A
    PROCEEDINGS
          OF THE
   First International
    Symposium on
Oil and Gas Exploration
          and
   Production Waste
 Management Practices
    September 10-13,1990
        Ce Meridian Hotel
    New Orleans, Louisiana, USA
          Sponsored by
    U.S. Environmental Protection Agency

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                     PROCEEDINGS OF
          THE FIRST INTERNATIONAL SYMPOSIUM ON
       OIL AND  GAS EXPLORATION
               AND  PRODUCTION
   WASTE  MANAGEMENT PRACTICES
                  SEPTEMBER 10 - 13, 1990
                 NEW ORLEANS, LOUISIANA
                        Sponsored by

               U.S. Environmental Protection Agency
                       Cosponsored by
American Association of Petroleum
Geologists
American Petroleum Institute
Canadian Petroleum Association
Energy Resources Conservation Board
of Alberta
Environment Canada
Governmental Refuse Collection and
Disposal Association
Independent Petroleum Association of
America
Interstate Oil Compact Commission
Louisiana Environmental Professionals
Association
U. S. Department of the Interior
U. S. Department of Energy
Underground Injection Practices
Council
United Nations Environment
Programme

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                           TABLE OF CONTENTS

TITLE                                                              PAGE

Alberta Drilling Waste Review Committee - A Cooperative
Approach to Development of Environmental Regulations, The
      Douglas A. Mead, Shell Canada Limited and Harry Lillo,
      Alberta Environment Protection Department  	          1
Alberta's Oil and Gas Reclamation Research Program
      C. B. Powter, Alberta Environment Land
      Reclamation Division  	
Alternative Processes for the Removal of Oil from
Oilfield Brines
      K. Simms, S. Kok, and A. Zaidi, Environment
      Canada  	         17

An Assessment of Produced Water Impacts to Low-Energy,
Brackish  Water  Systems in Southeast Louisiana:
A Project Summary
      Kerry M. St. Pe, LA Department of Environmental
      Quality, Jay Means and Charles Milan, LA State
      University, Matt Schlenker and Sherri Courtney,
      LA Dept. of Environmental Quality	         31

An Early Warning System to Prevent USDW Contamination
Environmental Underground Injection Equipment for
Hazardous  and Non-Hazardous Liquid Waste Disposal
Injection  Well and Monitoring Well in the Same Borehole
      W. W. Poimboeuf	         43

Application of the Continuous Annular Monitoring Concept
to Prevent Groundwater Contamination by Class II
Injection  Wells
      Len  G. Janson, Jr., Phillips Petroleum Company and
      Everett M. Wilson, Du Pont Environmental Remediation
      Services  	         73

Area Waste Management Plan for Drilling and Production
Operations
      C. T. Stilwell, ARCO Oil & Gas Company	         93

Attenuation of the Aquifer  Contamination in an Oil
Refinery  Stabilization Pond, The
      P.  M. Buchler, Sao Paulo Universtiy, Brazil  	        109

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BP Superwetter - An Off-Shore Solution to the Cuttings
Cleaning Problem
      Geraldine Shaw and Barry Slater, BP Chemicals	        117

Brine Impacts to a Texas Salt Marsh and Subsequent
Recovery
      W. Bozzo, M. Chatelain, J. Salinas and W. Wiatt,
      Boeing Petroleum Services, Inc.,  	        129

Brine Management Practices in Ohio
      Dennis R. Crist, Ohio Department of Natural
      Resources	        141

Characterization of Treatment Zone Soil Conditions at a
Commercial Nonhazardous Oilfield Waste Land  Treatment
Unit*
      W. Wayne Crawley and Robert T. Branch, K.W. Brown
      and Associates, Inc., 	        147
      (*presented as a poster session)

Clean-Up of Oil Contaminated Solids
      T. Ignasiak, D. Carson, K. Szymocha, W. Pawlak and
      B. Ignasiak, Alberta Research Council	        159

Common Misconceptions about the RCRA Subtitle C Exemption
for Wastes from Crude Oil and Natural Gas Exploration,
Development and Production
      Mike Fitzpatrick, U.S.  Environmental Protection
      Agency, Office of Solid Waste	        169

Comprehensive Environmental Training Program for  the
Production of Oil and Natural Gas Industry
      Forrest W. Frazier, Amoco Production Company  	        179

Contaminated Sulphur Recovery by Froth Flotation
      I. Adamache, Husky Oil Operations  Ltd	        185

Control of Waste Well Casing Vent  Gas from a Thermally
Enhanced Oil Recovery Operation
      Jack E. Braun and Mark A. Peavy, Oryx
      Energy Company  	      ,  199

Cost of Education, The
      Renee C. Taylor, True Companies	        211

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Determination of Soil Conditions that Adversely
Affect the Solubility of Barium in Nonhazardous
Oilfield Waste
      Robert T. Branch, Dr. Janic Artiola and
      Walter W. Crawley, K.W. Brown and Associates	       217

Development of a Waste Management System for the  Up-Stream,
On-Shore Oil and Gas Industry in Western Canada, The
      Ross D. Huddleston, Universtiy of Calgary and
      Jacques R. Benoit, Mobil Oil Canada  	       227

Development of an OEM Cutting Cleaner in the Netherlands, The
      L. R.  Henriquez, Ministry of Economic Affairs of the
      Netherlands  	       243

Disposal Practices for Waste Waters from Coalbed
Methane Extraction in the Black Warrior Basin, Alabama
      D. Troy Vickers, Amoco Production Company	       255

Drilling Waste Landspreading Field Trial in the Cold Lake
Heavy Oil Region, Alberta, Canada
      T. M. Macyk, F.  I. Nikiforuk, Alberta Research Council
      and D. K. Weiss, ESSO Resources Canada Ltd.,	       267

Drilling Wastes Management for Alaska's North Slope
      Bradley Fristoe, Alaska Department of Environmental
      Conservation 	       281

E & P Waste Management in the Complex California  Regulatory
Environment - An Oil and Gas Industry Perspective
      W. A. Brommelsiek, Chevron, USA  Inc., and
      J. P. Wiggin, Exxon Company  	       293

EPA Perspective on Current RCRA Enforcement Trends and
Their Application to Oil and Gas Production Wastes, An
      Charles W. Perry and Kenneth Gigliello, U. S.
      Environmental Protection Agency 	       307

Economic Impacts of Environmental Regulations on the Costs
of Finding and Developing Crude Oil Resources in the
United States, The
      M. L.  Codec  and K. Biglarbigi,  ICF Resources
      Incorporated	       319

Environmental Auditing at Prudhoe Bay: A Waste
Management Tool
      Pepsi  Nunes & Michael J. Frampton, ARCO
      Alaska, Inc	       339

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Environmental Compliance Audit of Four Oil and Gas
Facilities in Kenai, Alaska, An
      C. Reller, Entropy  	        345

Environmental Evaluation of Oil Drilling and Collection
System - A Case Study from India
      K. C. Baruah, Central Pollution Control  Board	        357

Environmental Protection Planning for Produced Brine
Disposal in Southwestern Saskatchewan Natural Gas Fields
      Graham R. P. Mutch, Saskatchewan Environment
      and Public Safety 	        375

Environmental Consequences of Mismanagement of Wastes
from Oil and  Gas Exploration, Development and
Production
      Robert Hall, US EPA	        387

Evaluation of Containerized Shrub Seedlings for
Bioremediation of Oilwell Reserve Pits
      Darrell N. Ueckert, Texas Agricultural Experiment
      Station, Steve Hartmann & Mark McFarland, The                     '
      University of Texas System  	        403

Evaluation of Limiting Constituents Suggested for
Land Disposal of Exploration and Production Wastes
      L. E. Deuel, Jr., Soil Analytical Services,
      Inc.,	        411

Evaluation of Leaching and Gypsum for Enhancing
Reclamation  and Revegetation of Oil Well Reserve Pits
in a Semiarid Area
      S. Hartmann, University of Texas Lands, D. N.
      Ueckert, Texas  Agricultural Experiment Station
      and M. L. McFarland, Texas A&M University  	        431

Evaluation of Oily Waste Injection Below the Permafrost
in Prudhoe Bay Field,  North Slope, Alaska
      D. E. Andrews, A S. Abou-Sayed, and I. M. Buhidma,
      ARCO Alaska,  Inc	        443

Evaluation of Selective-Placement Burial for Disposal
of Drilling Fluids in West Texas
      Mark L.  McFarland, Texas A&M University,
      Darrell N. Ueckert, Texas Agricultural Experiment
      Station and  Steve Hartmann, University of Texas
      Lands	        455

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Evaluation of the Area of Review Regulation for
Class II Injection Wells, An
      Geroge Korsun and Matthew Pierce, The
      Cadmus Group, Inc	        467

Evaluation of the Groundwater Contamination Potential
of Abondoned Wells by Numerical Modeling
      D. Warner and C. McConnell, University of
      Missouri - Rolla	        477

Evaluation of the Use of a Pit Management System
      Richard Spell,  Oryx Energy Company and
      Darrell Pontiff and John Sammons, SOLOCO Inc	        491

Fate and Effects of Produced Water Discharges in
Coastal Environments
      Nancy N. Rabalais, Louisiana Universities
      Marine Consortium, Jay Means and Donald
      Boesch, Louisiana State University	        503

Harmonized Procedure for Approval, Evaluation and Testing
of Offshore Chemicals and Drilling Muds within the Paris
Commission Area, A
      L. O. Reiersen, State  Pollution Control
      Authority (Norway)	        515

Hazardous Waste Treatment/Resource Recovery via
High Temperature Thermal  Distillation
      Tom F. Desormeaux and Brian Home,
      T.D.I. Services, Inc	        529

International Aspects of Waste Management, and the Role
of the United Nations Environment Program (UNEP)
      Fritz Balkau, United Nations  Environment
      Program	        543

Land Farming of Drilling Muds in Conjunction with
Pit-Site Reclamation:  A Case  History
      Dr. G. A. (Jim) Shirazi, Shirazi & Assoc.
      International Consultants, Inc.	        553

Landfarming Oil Based Drill Cuttings
      Peter K. Zimmerman and James D. Robert
      Amoco Canada Petroleum Company Ltd	        565

Management of Amine Process Sludges
      Carol A. Boyle, University of Calgary	        577

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Minimizing Environmental Problems from Petroleum Exploration
and Development in Tropical Forest Areas
      George Ledec, World Bank	        591

Mobil Waste Management Certification System
      Walter A. Steingraber, Mobil Exploration & Producing
      U.S. Inc., and Fred Schultz & Stephen Steimle,
      Steimle & Associates, Inc	        599

Modeling of Toluene Migration in Ground Water with the
Use of a Multiphase Simulation Programme
      G. Pusch and R. Weber, Technical University of
      Clausthal 	        611

Monitoring in the Vicinity of Oil and Gas Platforms:
Environmental Status in the  Norwegian Sector in
1987-1989
      T. Bakke, Norwegian  Institute for Water
      Research, J. S. Gray, University of Oslo and
      L.O. Reiersen, Norwegian State Pollution
      Control Authority	        623

Nature, Occurrence and Remediation of Groundwater
Contamination at Alberta Sour Gas Plants
      P. E. Hardisty, T. L. Dabrowski, L. S. Lyness,
      Piteau Engineering Ltd., R. Scroggins, Environment
      Canada, and P. Weeks, Husky Oil Ltd.,  	        635

New Pipeline Leak-Locating Technique Utilizing a Novel
Odourized Test-Fluid (Patent Pending) and Trained
Domestic Dogs, A
      L. R. Quaife and K. J. Moynihan, ESSO Resources
      Canada Limited  	        647

Oil Field Brines:  Another Problem for Louisiana's
Coastal Wetlands
      Virginia Van Sickle, Louisiana Department of
      Wildlife and Fisheries	        659

Oil Field Disposal Practices  in Western Kern
County, California*
      S. C. Kiser, M. J. Wilson, and L. M. Bazeley,
      WZI Inc.,	        677
      (*presented as a poster session)

Oil Waste Road Application Practices at the Esso
Resources Canada Ltd., Cold Lake Production Project
      Alan J. Kennedy, Lancecelot L. Holland,  and
      David H. Price, Esso  Resources Canada Ltd.,	        689

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Onshore Solid Waste Management in Exploration and
Production Operations
      Harold Yates, Exxon Corporation  	        703

Overview of Produced Brine Injection Practices in
Kentucky,  An
      W.  Mann and R. McLean, U.S. Environmental Protection
      Agency	        715

Overview of Treatment Technologies for Reduction of
Hydrocarbon Levels in Drill Cuttings Wastes, An
      Dennis Ruddy, U.S. Environmental Protection
      Agency and Dominick D. Ruggerio and Harold
      J. Kohlmann, Kohlmann Ruggiero Engineers  	        717

Pathway Exposure Analysis and the Identification of
Waste Disposal Options for Petroleum Production
Wastes Containing Naturally Occuring Radioactive
Materials
      H. T. Miller and E. D. Bruce, Chevron
      Environmental Health Center 	        731

Pilot Bioremediation of Petroleum Contaminated Soil*
      Julian M. Myers and Michael J. Barnhart,
      Waste Stream Technology	        745
      (*presented as a poster session)

Policy and Regulatory Implications of Coal-Bed Methane
Development in the San Juan Basin, New Mexico and Colorado
      Chris Shuey, Southwest  Research and Information
      Center	        757

Potential for Solar Detoxification of Hazardous Wastes
in the Petroleum Industry, The*
      Kenneth M. Green and Dinesh Kumar,
      Meridian Corporation	        771
      (*presented as a poster  session)

Practical Approach to Enforcement of Heavy Oily Waste
Disposal, A
      David Degagne and W.  (Bill) Remmer, Energy
      Resources Conservation Board   	        783

PRS Treatment and Reuse of Oilfield Wastewaters
      Ernst Schmidt and  Shirlee Jaeger, Preferred
      Reduction Services, Inc.,	        795

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Rapid Method for the Determination of the Radium
Content of Petroleum Production Wastes, A*
      H. T. Miller and E. D. Bruce, Chevron
      Environmental Health Center and L. M. Scott,
      Louisiana State Univeristy	       809
(*This paper was not presented orally at the Symposium.)

Regualtory History of Commercial Oilfield Waste Disposal
in the State  of Louisiana, A
      Carroll D. Wascom, Department of Natural
      Resources	       821

Regulation of Naturally-Occurring Radioactive Material
in Louisiana
      L. Hall Bohlinger, Louisiana Department
      of Environmental Quality  	       833

Regulations  and Policy Concerning Oil and Gas Waste
Management Practices in India
      G. D. Kalra, National Council of Applied Economic
      Research (NCAER)	 .	       841

Review of State Class II Underground Injection Control
Programs, A
      Jeffrey S. Lynn, Marathon Oil Company and
      Richard  L. Stamets, UIPC Consultant  	       853

Simple Injectivity Test and Monitoring Plan for Brine
Disposal Wells  Operating by Gravity Flow
      L. Meyer, US EPA, Region IV  	       865

Solidification of Residual Waste Pits as an Alternate
Disposal Practice in Pennsylvania
      S. J. Grimme  and J. E. Erb, Department of
      Environmental Resources  	       873

Statistical Assessment of Field Sampling Project Data
on Petroleum Exploration and Production Wastes
      Charles Winklehaus, George L. Clark,  and Robin
      Pomerantz, SRA Technologies, Inc	       883

State Oil and Gas Agency Environmental Regulatory
Programs - How Successful Can They Be?
      David G. Boyer, New Mexico Oil Conservation
      Division	       897

State Regulatory Programs for Drilling Fluids Reserve
Pit Closure: An Overview
      Fredrick V. Jones, M-I Drilling Fluids Company	       911

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States' Regulation of Exploration and Production Wastes, The
      Jerry R. Simmons, Interstate Oil Compact
      Commission	        925

Study of the Leachate Characteristics of Salt Contaminated
Drilling Wastes Treated with a Chemical Fixation
Solidification Process, A
      L. Roberts, Mobil Exploration & Producing US Inc.,
      and G. Johnson, Oklahoma State University	        933

Sulphur Block Basepad Reclamation  Programs Undertaken at
Three Facilities in Central Alberta
      S. A. Leggett, Jim Lore and Associates, Ltd., and
      S. L. England, Mobil Oil Canada	        945

TC Model Alternative for Production Waste
Scenarios, A
      H. S. Rifai and P. B. Bedient,  Rice University  	        955

The Application of Concentric Packers  to Achieve
Mechanical Integrity for Class II Wells  in Osage
County, Oklahoma
      Everett M. Wilson, DuPont (formerly with the US
      Environmental Protection Agency, Region Six  	        967

Theory, Design and Operation of An Environmentally
Managed Pit System
      Darrell Pontiff and John Sammons, SOLOCO, Inc.
      and Charles Hall and Richard Spell,  Oryx
      Energy Company  	        977

Toxicity and Radium 226 in Produced Water - Wyoming's
Regulatory  Approach
      John F. Wagner, Wyoming Department of Environmental
      Quality	        987

Unsuccessful Oilfield Waste Disposal Techniques in
Vermilion Parish, Louisiana
      Wilma A.  Subra, Subra Company, Inc	        995

Use of Hydrocyclones in  the Treatment of Oil Contaminated
Water Systems
      I. C.  Smyth,  M. T. Thew, University of
      Southampton 	       1001

Use of Minteq for Predicting Aqueous  Phase Trace Metal
Concentrations in Waste  Drilling Fluids
      George M; Deeley, Shell Development Company	       1013

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Using Oily Waste Sludge Disposal to Conserve and Improve
Sandy Cultivated Soils
      Volkmar O.  Biederbeck, Agriculture Canada  	       1025

Waste Minimization in E & P Operations
      N. E. Thurber, Amoco Corporation	       1039

Waste Management Guidelines for the Canadian
Petroleum Industry
      Paul D. Wotherspoon, Paul Wotherspoon & Associates,
      Inc., and Gary Webster and James Swiss, Canadian
      Petroleum Association	       1053

Waste Management Practices:  The Role of UNIDO
      W. Kamel, UNIDO	       1063

Waste Management Decision Making Procedure at
Prudhoe Bay, Alaska
      Michael J. Frampton, ARCO Alaska, Inc	       1071

Who is  Qui Tarn?  Privatizing Environmental Enforcement
      Philip M. Mocker, Mineral Policy Center 	       1081
 Author Index 	      1090

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THE ALBERTA DRILLING WASTE REVIEW COMMITTEE  - A COOPERATIVE  APPROACH TO
DEVELOPMENT OF ENVIRONMENTAL REGULATIONS
Douglas A. Mead, Ph.D., RPF
Senior Environmental Scientist
Shell Canada Limited
Calgary, Alberta, Canada
Harry Lillo
Manager, Environment Protection Department
Alberta Energy Resources  Conservation  Board
Calgary, Alberta, Canada
 Introduction

 The  Province  of Alberta  contains  the  bulk  of  the  producing  oil  and gas
 resources of Canada.   The  oil  industry is a major  factor in the economy of the
 Province and a significant contributor to the national economy.  An average of
 approximately  6000  wells per year have been drilled over  the past ten years.
 The  wells  have  been  drilled  in a  wide  variety of geological  formations at
 depths  ranging  from  500-5000 m  (1,650-16,500  feet).    Over  the  past decade
 drilling technology has become  more sophisticated and  the drilling muds and
 mud  additives used  for drilling  have become more diverse and  complex.  The end
 result  is  that the  wastes created by drilling have also  become more diverse
 and  complex.

 In   Alberta,   the   Energy  Resources   Conservation  Board   (ERCB)   has  the
 responsibility for  managing  the  Province's energy  resources and regulating the
 energy  industry.  This includes  the  establishment  of policies, regulations and
 guidelines  respecting the handling and  disposal  of energy  industry wastes,
 although  various   other  government  agencies  also   have  some  regulatory
 responsibility regarding waste transportation and disposal.   The disposal of
 drilling wastes  in Alberta  is currently regulated by  an  "interim" guideline
 developed in 1975.

 Existing Sump Regulations  Inadecruate

 During  the 1980s, as  environmental  concerns rose to  the top of the public and
 political  agenda,   governments  everywhere  have  been  scrambling to  develop
 and/or  update  environmental  regulations  to cope  with  public demands and to
 incorporate constantly expanding knowledge of environmental  problems and the
 technology  available  to deal with  ^hose problems.    Industry,   in  turn,  is

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scrambling to  keep up with  the  regulatory tide and to  deal effectively  with
environmental issues, including management of wastes.

In Alberta in 1987 there was a climate of dissatisfaction and criticism by all
parties  (government,  industry and  public)  when it  came to the  handling  and
disposal of drilling  sump  wastes.   A round-table meeting was organized by the
ERCB and  the  Canadian Petroleum Association  (CPA)  to  enable all participants
to discuss  their  concerns,  complaints and frustrations.   Representatives  of
numerous government agencies and oil  industry organizations were present.   The
group quickly  developed a  list of  issues and concerns.   The discussion which
followed made  it clear that the  root cause of  many of  the problems was  that
the  1975  guidelines  were  inadequate  to  deal  with  contemporary drilling
technology  and  environmental  concerns.    Different government  agencies  were
developing separate ad  hoc approaches that sometimes conflicted, with industry
caught  in the  middle.   Disposal   techniques favoured by  some  companies  and
regulators  were  unpopular with other companies  and  regulators.    There  was
substantial uncertainty and  confusion.

It was  apparent that  what  was  required were new regulations that would  reflect
current drilling  technology,   waste  treatment  technology  and environmental
concerns.

There   had  been  a history  in Alberta  of forming  joint  government-industry
committees  to  investigate  areas of common concern and to make  recommendations
on  government   policy  and  regulation.    In   fact,  the  1975  sump disposal
guidelines  had been  developed in  this  way.     In  August  of  1987,  senior
representatives of industry and government  approved the establishment of  the
Drilling  Waste  Review  Committee  (DWRC).   The  task  of the Committee  was  to
prepare a  new  comprehensive  guideline  for the management of  drilling  sump
wastes  for  Alberta.   The  new  guidelines  would  also provide the basis  for  new
regulations.   The Committee  would be  co-chaired by representatives  of the  ERCB
and  the CPA (the  authors  of this paper) .   There were also representatives  of
Alberta Environment,  Alberta  Department  of Forestry,  Lands  and Wildlife  and
the  Independent Petroleum  Association of  Canada (IPAC).

Cooperative Process  Taken

Within  a  short period of time  the Committee had agreed to the process which it
would   use  to  develop  the new sump  disposal  guidelines.    The objective  and
contents   of   the  guidelines   were  agreed   upon  and   twelve   technical
sub-committees  (one per guideline  chapter)  were created.   Each sub-committee
was  chaired by a DWRC member.   Each sub-committee  chairman  was  responsible for
filling his  sub-committee  with experienced  individuals  from industry   and
government.

Each sub-committee report (section of the guideline)  was  to  be  a  consensus
report  of the  technical sub-committee.   Cross   sub-committee appointments  and
the  circulation of draft  reports would help keep the effort coordinated.   The
DWRC would be  responsible for integrating the  sub-committee  reports  and  for
conducting  a broader  review  (including the public) of  a  draft guideline before
submitting  a  final draft to  the ERCB  for  implementation.

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 Progress is slow, but commitment remains

 The twelve sub-committees  were quickly formed  and draft  reports  began to
 appear by late 1987.  It quickly became  obvious,  however,  that there were two
 key areas that would take longer to  resolve.   One was the characterization of
 the wastes:   which characteristics  should be  measured and how  should it be
 done.   The characterization  of sump wastes should  be comprehensive enough to
 detect levels  of contaminants  that would  be  of  concern,  yet  the procedure
^should also  minimize  the time  and expense required.   The process should be
 effective and efficient.

 The  second,   and  perhaps  most difficult,   area  is   reaching   agreement  on
 criteria:   what levels  of  contaminants are  safe for  disposal.   This debate
 continues across our  society for a multitude of  wastes  -   liquid, solid and
 gaseous.   What levels  of  contamination will  or  might create  an undesirable
 environmental or health effect?  Drilling sumps contain waste drilling fluids,
 drilling muds and the rock cuttings  from the  drilling operation.   If they are
 allowed  to settle  or are  treated,  there  are liquid  and  solid  (sludge  and
 cuttings) phases to dispose of.  Some drilling muds are very salty.  Some have
 a  high  oil content.  Some  may contain heavy metals.   Wastes  containing high
 salt,  oil  and/or heavy  metal concentrations  are a  concern because improper
 disposal  can  result  in  undesirable impacts  to  ground  and  surface  waters,
 vegetation, wildlife, domestic animals and perhaps humans.

 Considerable  debate  within  and  between  the  Characterization   and Criteria
 sub-committees  led to  a  decision  to  commission  an  independent  review  of
 disposal criteria for drilling  wastes  in other jurisdictions,  a  review of the
 concentration  of  the  various waste  constituents  that could impact  vegetation
 and a recommendation as to what  soil loading  rates  would  be safe.   This study
 took approximately  six months to complete.

 The  criteria  suggested by  the  independent   report  were  considered by  all
 parties  to be  safe,  in that  the  concentrations  would not affect  plants or
 animals  if  sprayed  onto  or  worked  into the topsoil.    However, industry
 representatives  generally  felt that the proposed criteria  were unnecessarily
 strict and that  the broad suite of  analytical  procedures would  be  costly and
 time-consuming to conduct.

 The debate of these  issues  led to  the realization  to nobody knew what  the
 impact  of  adopting the  proposed  criteria  would be.   There  was no suitable
 database of sump chemical analyses to compare to  the proposed criteria.  Would
 10% of  the sumps fail the criteria  or  would  10%  pass?   It was  agreed that a
 sump characterization study was required to document the physical  and chemical
 nature of  drilling  sump wastes  in  Alberta.   This  study is currently underway.
 A  final report is expected early in  1991.

 End product will be effective and efficient

 The  cooperative  approach to development  of  environmental   regulations  has
 several distinct advantages  over alternate methods.

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• Industry  obtains  a  better  understanding of  the  political  driving forces
  which  are compelling  environmental agencies  to develop new environmental
  regulations.

• Government   agencies   gain  a   better  understanding   of  the   economic
  implications  of  potential regulatory  alternatives  before  new regulations
  are implemented.

• Government  agencies  obtain a better  understanding of the  problems  or even
  the feasibility  of compliance with  potential  regulatory  standards.

• More   experience  and   knowledge  is  available  to   evaluate  regulatory
  alternatives  and find  workable  and  effective  solutions.

• Any  policies, regulations  or  guidelines that result will  have widespread
  credibility  and  acceptance leading  to  quicker  implementation and  fewer
  legal  challenges.

The end of the  story

Unlike Paul Harvey,  we  do not yet have the  end of  this story.   The  sump
characterization study will provide very  valuable  data by  late this  year that
will assist us  in moving quickly to wrap up this project.  It has taken longer
than originally expected,  but  all parties remain committed and convinced that
the process  will  result  in drilling  waste  regulations  that  will  protect  the
environment  and  incorporate  analytical  and  disposal  procedures  that  are
effective and efficient.

The  cooperative   approach  to developing  environmental   regulations  being
utilized  in  this  situation may not be  appropriate for all new environmental
regulations,  but  it clearly reflects  and supports the trend  throughout  North
America to a consultative  approach to the resolution of environmental issues.

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DRILLING WASTES PAPER - SLIDES*









  1-4       Typical drilling scenes:   lakes, mountains,  plains,  drilling pads




  5-7       Drilling sumps




   8        Location slide  - Alberta




   9        Round-table discussion  scene  - DWRC




   10       "List of 20"




  11-12      Lab scenes -  analytical work




   13       List of DWRC  representation




   14       Sub-committee structure




   15       Examples of cooperation (E.P.M., noise,  soil monitoring)




   16       Small round-table  discussion  scene -  sub-committee




   17       Front page of ID-OG-75-2




   18       Photo of smiling,  contented bureaucrat




   19       Photo of smiling,  contented drilling  foreman




   20       Photo of smiling,  contented cow











 * Not necessarily in order.

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SUBCOMMITTEE CHAIRMEN AND MEMBERSHIP
1.   TERMS (CPA - MEAD)
           Loose  (FLW)


2.   SOURCES  (CPA - STUART)


3.   RESPONSIBILITIES  (ERCB -  LILLO)
           Wolff  (Suncor), Creasey (ERCB),  Fernandez (AE), Lloyd  (FLW)


4.   PREPLANNING  (FLW  -  LLOYD)
           Sitar  (Mobil),  Onciul  (AE).  Hartley (FLW),  Creasey  (ERCB),
           Wolff  (Suncor), Rattliff  (AFS)

5.   DESIGN  (CPA  -  STUART)
           Cartwright  (Shell),  Karasek  (FLW),  Hughes (Mobil), King  (AFS)

6.   CONTROL  (IPAC  -  LIKELY)
           Molnar (Amoco), Anderson  (Shell),  Stychyshyn  (North Canadian Oil)

7.   CHARACTERIZATION  (AE - FUJIKAWA)
           O'Leary  (Shell), Moynihan (Esso),  Roberts (ERCB),  Abboud  (ARC),
           Macyk  (ARC),  Korchinski (ERCB)

8.   CRITERIA (ERCB -  LILLO)
           Lesky  (Husky),  Birchard (Esso),  Takyi (FLW), Korchinski  (ERCB),
           Roos  (Amoco),  Ferderko (Gulf)

9.   TREATMENT  (CPA -  MEAD)
           MacDonald  (Esso), Van  de  Pypekamp (Shell),  Cole (FLW),
           Johnson  TAEC),  Wilson  (AEC),  Waisman (ERCB), Krassman  (AFS)

10.  CLOSURE  (FLW - LLOYD)
           Silkie (Esso),  Scott (Shell),  Pryce (BP), Kremeniuk  (FLW),
           Schneidmiller (AFS)

11.  MONITORING  (FLW  - LLOYD)
           McCoy  (Canterra), Kohlman (PC),  Ceroici  (AE), McFadden  (AFS)

12.  RECORDS  (CPA - STUART)

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ALBERTA'S OIL AND GAS RECLAMATION RESEARCH PROGRAM
C.B. Powter
Chairman, Reclamation Research Technical Advisory Committee
Alberta Environment, Land Reclamation Division
Edmonton, Alberta, Canada
Abstract

There are over 130,000 wellsites  and  200,000 km of pipelines in Alberta, which
have  disturbed  an estimated  2331 square  kilometres  of  land.    The Alberta
government,  through  the  Reclamation Research  Technical Advisory  Committee
(RRTAC),  has developed  a  research  program to  identify suitable methods of
reclaiming  these disturbances.  RRTAC is working  together with industry  (the
Canadian  Petroleum Association and  the Independent Petroleum  Association of
Canada) to develop environmentally-safe methods for disposal of drilling wastes,
and  to determine suitable  ways   to  return land  to  a  condition capable of
sustaining an approved land use.  Funding for the research comes  from the Alberta
Heritage Savings Trust Fund.

This paper  will  discuss  the nature and effectiveness of the joint government/
industry research approach and will highlight some of  the projects undertaken.

Drilling  waste  research  has  focused  on:  waste characterization, effects of
various waste rates and types on plant growth, sump siting criteria, evaluation
of burial as a disposal  option, and developing a manual to help select surface
disposal options.

Activated  charcoal has been evaluated for  effectiveness  in inactivating  soil
sterilants.

Soil compaction work has  looked at identifying how to  measure compaction, deter-
mining  if compaction problems exist on  oil  and gas  wellsites,  and relating
compaction  to plant growth.

Introduction

Exploration, development,  transport and  processing  of oil and gas  is  one of
Alberta's largest industries.  There  are  over 130,000  wellsites and 200,000 km
of pipelines in Alberta, which have disturbed an estimated 2331 square kilometres
of land (1) . Provincial regulations (2) require that all industrial developments
in the province which disturb the land surface meet established soil conservation
and  reclamation  criteria.   Larger surface disturbances,  including  oil sands
developments within a well defined region (3) and pipelines greater than 15 cm

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in diameter and 16 kilometres in length (4) ,  require more extensive planning and
prior approval by provincial regulatory authorities.

The  Alberta Land Conservation  and Reclamation  Council  is  responsible  for
approving the development and reclamation plans for all regulated disturbances
and  for the  certification of  all reclaimed  disturbed  sites.    The  Council
established the  Reclamation Research Technical Advisory  Committee (RRTAC)  to
provide relevant technical information necessary to carry out Council functions.
RRTAC's role is two-fold:  first, to coordinate provincial government reclamation
research, and  to act as a clearinghouse  for information  on other  reclamation
research activities  in  industry  and educational  institutions;  and, second,  to
fund  and manage  a  research program to  provide  information on  a variety  of
reclamation topics of interest to both government and industry.   RRTAC  and  the
Council have set up  five research program areas, one of which deals with  oil  and
gas issues.

The Oil and Gas Reclamation Research Program (OGRRP) is a joint effort between
the provincial government and Alberta's oil and gas industry whose  focus  is  on
reclamation of all types of oil and gas  facilities,  including wellsites,  on- and
off-site drilling waste sumps,  access roads, compressor  stations and batteries,
and pipelines.   Specific program objectives include:'developing environmentally-
safe methods for disposal of drilling wastes (fluids and solids); and, evaluating
methods for returning land to a condition capable of sustaining  an  approved land
use.

The program is  managed  by a committee  of reclamation specialists from  several
provincial  government  departments  and representatives of  industry  from the
Canadian  Petroleum  Association and  the  Independent Petroleum  Association  of
Canada.  These specialists work together to prioritize research needs, develop
research projects to address these priorities,  select contractors to undertake
the work, and evaluate progress and the final reports from  the studies.  Results
from  all studies  are  made available  to government,  industry and the public  to
ensure  that all  interested parties have access  to the most current  information
when  making development and reclamation decisions.

We have concentrated on  three issues  to date: drilling  waste disposal;  soil
sterilants; and, compaction.  Soil handling practices for pipeline construction
are also starting to be investigated.   The remainder of  this paper will discuss
the  nature  of  these problems  in  Alberta  and how the  research  program   is
attempting to address them.

Drilling Wastes

In 1984, RRTAC  sponsored a two-day workshop on drilling waste  disposal in Alberta
(5).   The workshop  was  designed  to promote  a  better understanding between
government regulators and industry about:
      (a)   the mud components used, their purposes and need;
      (b)   constraints  on  industry  with  drilling  and  industry  clean-up
            practices;
                                      8

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      (c)   environmental considerations such as soil, vegetation, groundwater
            and surface waters when disposing of wastes;
      (d)   government regulations, procedures and concerns; and,
      (e)   potentially toxic constituents within drilling wastes.
Our Oil and Gas research program has grown out of these initial discussions.

Siting

The physical location of drilling waste disposal pits must be carefully chosen
to  minimize the  potential  for  subsurface  spread  of  leachates  that may be
generated from the wastes (6).  Knowledge of site characteristics  such as:  the
distance between the disposal site and the nearest surface water body or ground-
water supply; the depth to  the watertable; the watertable gradient  away from the
site; and, the type and thickness of geologic material through which the contam-
inated water could migrate, is required to make decisions  on  the suitability of
a waste pit location.  Knowledge of proposed waste pit contents and their likely
effects on  the permeability  of pit liners is also important.

RRTAC funded a project to evaluate the potential for  developing an  expert system
that would allow these decision making steps to be computerized.  The consultant
reported that such a system could be produced, but that a considerable data base
would need  to be developed to allow for the system to be effective (7).

In  addition to the  computer  study, a literature review was conducted to assess
the  effectiveness  of geological containment of drilling  wastes  in  sumps (8).
Knowledge of material permeability makes for more informed sump siting decisions.

Characterization

Three  basic drilling  muds  and variations  thereof  are used for oil and gas
exploration in Alberta (9).   The freshwater gel bentonite is most commonly used,
followed by the salt water  systems which use sodium or potassium chlorides.  The
oil  invert  drilling mud is also used, particularly in the mountainous areas of
the  province,  and  is  gaining  in  popularity with some  companies.  Diammonium
phosphate  (DAP) mud is also  being used.

The  wastes  produced from drilling  operations contain many complex organic and
inorganic  compounds that  are added at various stages of the drilling process
(10).   The materials  that start  out as drilling mud are usually extensively
altered chemically  and physically by the time they enter a waste pit.  The muds
can be altered by heat and pressure  effects associated with drilling and by the
addition of drill cuttings brought up with the mud system.  The materials found
in the waste pit can also be  changed chemically and physically by other products
that are purposely  or  inadvertently added to the pit.  Caustic soda, rig wash,
diesel fuel, waste  oil from  machinery, metal and plastic  containers, and other
refuse often find their way  into a waste pit  (11).

A  thorough physical and chemical analysis  of the  liquid and  solid phases of
wastes generated by drilling  operations utilizing the different mud types  is one
of  the prerequisites  to assessing  the potential environmental hazard  of the

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disposal of these wastes.  RRTAC funded an initial project to provide a  scien-
tific basis for development of guidelines  for drilling mud solids disposal  that
optimizes environmental safety and cost effectiveness.   Drilling waste  fluids
and  solids  were collected  from sumps at wellsites in three regions  of  the
province.  Samples were collected at several depths in each of several locations
within a sump to determine spatial variability in the waste properties.  A suite
of chemical analyses was  performed to  characterize both  solids and fluids.   The
sump solids were mixed at various rates with a soil indigenous to the respective
region and planted to a grass species typically used in reclamation.  The results
of these greenhouse trials  provided preliminary  indications of how much of  each
waste type can be added to soil without seriously degrading soil capability (12).

Following up  on this  research,  and recognizing that only a  limited number of
sumps were sampled,  a broader sampling of sumps  is currently underway.  This new
study will provide  data  to  a joint government and industry  task force that is
currently updating  the  existing guidelines/criteria for disposal  of drilling
wastes  in  Alberta.   RRTAC  funded the  first  portion of this work which  was a
detailed sampling and analysis protocol for use in the field study (13).  Indus-
try  is  now  funding  the collection  and analysis  of wastes  from up to 100 sumps
through a special levy on well site owners.  Finally, RRTAC will pay for the  data
synthesis and  interpretation, and production of a final report.

Disposal

Drilling wastes are currently disposed of  in  Alberta  by burying,  trenching,
squeezing, or spreading.  Each of these disposal  methods  impacts the environment
in different ways.   For example, interactions of  waste constituents with ground-
water is much  more  likely to  occur if wastes are trenched or buried as opposed
to  surface  spread.   The reverse is true  for surface soils and plants.   When
considering these various waste disposal options, both industry and government
staff have the following objectives in mind (14):
      (a)   to minimize deteriorization of groundwater and surface water quality;
      (b)   to control  the changes in soil  and site characteristics  so  that
            productive use  of the  site may  occur after  waste disposal ceases;
            and,
      (c)   to minimize closure requirements and post-closure care.

Our first research in this  area focused on trying to  develop a manual that could
be used by  field staff to  determine whether  a waste could be safely spread on
a given soil surface (15).   The manual was prepared with  the assistance of field
staff,  however after  testing the system in the  field  it became apparent  that
changes were required.  A follow-up study  was designed to revise and update the
manual  (16), specifically by:
      (a)   developing a more definitive drilling waste disposal decision  flow
            chart;
      (b)   developing a glossary or simplifying terminology used in the manual;
      (c)   indicating what parameters could be tested  in  the field, why  they
            should  be tested, and the appropriate procedures to be used;
      (d)   redefining the  calculations to determine sump contents;
                                      10

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      (e)   providing critical levels  for  parameters so that calculations are
            completed;
      (f)   condensing and clarifying the checklist  for fieldmen;
      (g)   expanding on the  guidelines  for obtaining representative samples;
            and
      (h)   developing  a  computer  program that  will allow  users to  do the
            calculations prescribed in the manual.
The revised manual is expected to be released early  in 1991.

There has been a movement, within  some  sectors of  the  government,  away from
burying in sumps as  a disposal  option because of concerns about potential for
migration of contaminants into groundwater.  Therefore, a project was initiated
to review the  international  literature to  determine the environmental accept-
ability of burial of drilling waste solids.  One of  the most difficult tasks in
this study was to  come to some agreement regarding  the  terms to be used when
describing the various methods of burial (e.g., burial, containment, trapping,
landfilling,  etc.).    The  project was  completed and a  final report  will  be
available late in 1990.

Diesel fuel forms the liquid portion of invert drilling muds rather than water.
Therefore, the organics in the waste  may  be bio-degradable  in  the  soil, and
landfarming of this  type  of  drilling waste may be an environmentally sensible
option.   A  multi-year study  will:  characterize  an invert  waste,  determine
degradation  rates   in controlled  laboratory  and  greenhouse  conditions,  and
determine suitable waste  application rates  for field disposal through a field
study.  Petro-Canada has supplied the invert waste and a field location for the
research.
Residual Herbicides

Soil sterilants, residual herbicides that render the treated soil unfit for plant
growth  for relatively  long periods  of time,  have  been  used in  Alberta on
wellsites, rights-of-way and other industrial areas for total vegetation control.
Such  vegetation control measures  reduce  fire  hazards and  improve  aesthetic
appearance.   The  treated areas  can remain devoid of vegetation for many years
depending  upon the type and rate  of soil  sterilant  used,  and  the  soil and
climatic conditions.  Furthermore, in the past  it was not uncommon  to use more
than the recommended rates  of these chemicals for achieving long-term vegetation
control with  a single  application.   Bromacil and tebuthiuron are the commonly
used soil  sterilants in  Alberta.

Once a  sterilant-treated site is abandoned,  it may  take  several years before
the  site   is  restored  to  its original  capability.    The  site  also becomes  a
potential  source of contamination through surface runoff and  wind  dispersion of
soil sterilants onto adjoining  untreated land.   In Alberta,  the extent of the
soil sterilant problem is  becoming apparent  as  more depleted oil  and  gas lease
wells are  abandoned.   The seriousness  of the  problem  has been identified by
various provincial  organizations and  committees (17).
                                      11

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RRTAC recently completed a study addressing the emerging soil sterilant problem.
The approach was to identify methods for binding the herbicide, thus rendering
it ineffective.  A greenhouse study was conducted to investigate the efficiency
of activated charcoal for inactivation of bromacil and tebuthiuron residues  in
soil.   Oats was  used as a  bioassay species  to  assess the  phytotoxicity  of
bromacil and tebuthiuron residues.

Results of  this  greenhouse study  showed  that activated charcoal,  at ratios  of
1:200 or more  (herbicide active ingredient:activated charcoal), can be effect-
ively  used to  inactivate  bromacil  and tebuthiuron  residues  in soil.   The
efficiency  of  treatment depends on activated charcoal ratios, soil character-
istics (texture, organic matter content and moisture level) and the  time interval
between activated charcoal incorporation and plant establishment  (18).

Currently, a consultant is interviewing industry and government personnel to help
identify specific field problems that can be addressed through research.  Arising
from this process will be an  integrated research program that we can implement,
or direct to other suitable funding agencies.

Compaction

Mining, pipelining and the construction of oil and gas  leases all result in soil
compaction.  In fact, a  recent report by the United States Office of Technology
Assessment  found  that  soil  compaction was   the  single biggest problem  in
reclaiming cropland disturbed by mining (19).  A survey conducted by RRTAC found
that Reclamation Officers perceived soil compaction to be the prime concern in
reclaiming  oil and gas wellsites.

Repeated passage of heavy equipment during development and operating phases of
a wellsite or pipeline results in compaction of  the soil. Compacted soil retards
root development which can lead to  moisture and nutrient stress in plants.  This,
in turn, retards  shoot  development and  yield.   Freeze/thaw and wetting/drying
cycles were thought to loosen compacted soil,  but current evidence  suggests that
their benefits are rather limited.  In Alberta, moderately compacted soils can
have recovery  times measured in decades.

There is a paucity of useful  data  pertaining  to soil compaction in Alberta (and
elsewhere). largely because a fully satisfactory measurement technique has yet
to be  identified.   Crop yield is  the best measure  of compaction in addressing
agricultural  concerns.  However,  the effect of soil  compaction  on crop yield
varies with soil type, yearly meteorological conditions, and type of crop.  It
is hoped that a measurement  of compaction must be identified that has  a high
correlation with plant  response,  is  independent of soil type, is inexpensive,
and can be performed rapidly in the field.

Bulk  density is most commonly used to  determine  soil compaction,  but shows
considerable natural variation due to soil particle size distribution and organic
matter content, and has  no unique  value  at which root  growth is impeded.   Hydr-
aulic  conductivity,  porosity,  air permeability, infiltration,  and sorptivity
yield valuable information about the  effect of  compaction on physical processes

                                       12

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in soils.   But these are not suitable as operational field measurements  due  to
long measurement times, wide data variability, departure from normality,  and the
absence of an exact relationship between these properties and plant growth.

Our initial approach  to  the compaction problem was  to determine what charac-
teristics predispose a soil to compaction and to  identify the best field  method
for identifying and quantifying compaction.  This knowledge will  allow operators
to avoid compaction wherever possible and allow regulatory personnel to identify
compacted areas.   A cone  penetrometer,  developed at the Alberta Environmental
Centre, allows mechanical  impedance to be measured at various depths in the field
at extremely low cost.

Using the penetrometer, a detailed  survey of wellsites was  conducted in east-
central Alberta. It concentrated on establishing appropriate  sampling densities
and on evaluating various  techniques of measuring compaction.   At  five wellsites,
data were collected on soil strength (recording penetrometer), undisturbed cores
were  collected for measurement  of bulk  density  and  pore  size distribution,
disturbed  or  undisturbed cores were  collected  for  measurement of  moisture
content, texture and organic matter,  and soil profiles  (for classification) and
soil morphology were recorded.

The  second part of the  study involved an  assessment of soil  compaction on
20 wellsites using a recording penetrometer  to measure vertical and horizontal
soil compaction profiles.   Emphasis was  placed on  strength measurements because
they  can be taken  quickly,  no expensive and time consuming  laboratory work is
required, and  work at the Alberta Environmental  Centre and  elsewhere suggests
that  soil strength may be the  variable most  closely related  to plant growth in
compacted soils.

The  information generated by this research will  be published in 1990.  It has
helped determine the nature and scope of the  compaction problem, and establish
appropriate methods and sampling designs for future work concerning compaction.

Our Reclamation Officers are now equipped to measure compaction at any disturbed
site.  However, there  is little information relating mechanical impedance  or any
other measurement  to reductions in crop yield.  What is needed is a simple model
for routine applications that predicts plant yield with a minimum of data  input.

The  main objective of  the  third  phase  of  the   research is to  identify the
relationship between subsoil compaction, topsoil  depth, and  plant productivity
Binder a range of conditions (soils and years). The experiment is factorial and
arranged in a completely randomized design, with three compaction levels and four
topsoil depths.  Each treatment is replicated four times at  each of two  sites:
a  Chernozem soil,   which  was  constructed  in  1989; and  a Luvisol, which was
constructed in 1990.  Barley will be grown in each plot for three years, and the
growth response (measured by root biomass,  root length, shoot biomass, and crop
yield) will be related to  three measures of soil compaction (penetration  resis-
tance, bulk density, and  porosity).
                                     13

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The project is in its second year  of  data collection and is expected to  go  on
for at least two more years.  A final report is expected in 1994.

Conclusion

The oil and gas industry is an important facet of Alberta's diversified economy.
Government and industry in the  province have made a commitment  to ensuring that
this industry will continue to thrive while not harming the environment.  Through
the actions  of the Oil  and Gas Reclamation Research Program, we  are making
important strides toward this goal.

The cooperative  efforts between  government and industry are what  makes the
program  so  effective.   As  the  program becomes established,  and  the partners
become more comfortable with each other, we expect that we will be able to report
many more successes.

References

1.    D.L. Bratton, Planning for Soil  Conservation by the Oil and Gas Industry.
      IN: C.B. Powter, Compiler, Alberta Conservation & Reclamation Conference
       '88,  sponsored by  the Alberta Chapters of the  Canadian Land Reclamation
      Association and the Soil and Water Conservation Society, 1988, pp.  1-4.

2.    Government  of the  Province  of  Alberta,  Land  Surface  Conservation and
      Reclamation Act. Office Consolidation, 1984,  44 pp.

3.    Government  of the  Province  of  Alberta,  Land  Surface  Conservation and
      Reclamation Act.  Regulated Oil Sands  Surface Operations Regulations. Office
      Consolidation, 1978,  15 pp.

4.    Government  of the  Province  of  Alberta,  Land  Surface  Conservation and
      Reclamation  Act.  Regulated  Oil and  Gas Pipeline Surface  Operations
      Regulations. Office Consolidation,  1979,  6 pp.

5.    D.A. Lloyd (Compiler), Gel and Saline Drilling Wastes in Alberta: Workshop
      Proceedings. Alberta Land Conservation and Reclamation Council Report  RRTAC
      87-3, 1987, 218 pp.

6.    G.L.  McClymont,  M.R.  Trudell, S.R.  Moran, T.M.  Macyk,  An Expert System
      for  Siting Drilling  Waste  Sumps.  IN: Proceedings of  the  Symposium  on
      Ground-Water  Contamination,  June,   1989,  National Hydrology Research
      Institute and Canadian Water Resources Association  (in press).

7.    Reclamation Research  Technical  Advisory  Committee, Reclamation Research
      Annual  Report  -  1987. Alberta Land Conservation and Reclamation Council
      Report  RRTAC 88-6, 1988, pp.  36-37.

8.    D.R.  Pauls,  S.R.  Moran,  T.  Macyk,  Review of Literature Related to Clay
      Liners  for  Sump  Disposal of  Drilling Wastes.  Alberta Land Conservation
      and Reclamation Report RRTAC  88-10, 1988, 61 pp.
                                      14

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9.    S.A. Abboud, T.M. Macyk, D.A. Lloyd, Characterization of Drilling Wastes
      from Alberta. IN: Proceedings of the Conference  on Prevention & Treatment
      of Groundwater & Soil Contamination in Petroleum Exploration & Production,
      Calgary, Alberta, 1989, pp. 3.0-3.4.

10.   H.U. Ziedler, Alberta's Major Drilling Mud Systems and Their Composition.
      IN: D.A.  Lloyd  (Compiler), Gel  and Saline Drilling Wastes  in Alberta:
      Workshop Proceedings,  Alberta Land  Conservation and Reclamation Council
      Report RRTAC 87-3, 1987, pp.  24-36.

11.   R. Clark, Disposal of  Drilling Fluid. IN: D.A. Lloyd (Compiler), Gel and
      Saline  Drilling Wastes in  Alberta:  Workshop Proceedings,  Alberta Land
      Conservation and Reclamation  Council Report RRTAC 87-3, 1987, pp. 59-74.

12.   T.M. Macyk, F.I. Nikiforuk,  S.A.  Abboud,  Z.W. Widtman, Detailed Sampling.
      Characterization and Greenhouse Pot  Trials Relative  to Drilling Wastes in
      Alberta. Alberta Land Conservation and Reclamation Report RRTAC 89-6, 1989,
      228 pp.

13.   T.M. Macyk, Drilling Waste Sump Chemistry Study Design. Unpublished Report
      Prepared  for  the  Alberta  Land Conservation  and  Reclamation  Council,
      Reclamation Research Technical Advisory Committee, 1990, 33 pp.

14.   S.  Lupul,  Department  of Environment Requirements for  Land  Disposal of
      Industrial  Wastes.  IN: D.A.  Lloyd  (Compiler),  Gel and Saline  Drilling
      Wastes  in Alberta:  Workshop  Proceedings,  Alberta Land Conservation and
      Reclamation Council Report RRTAC 87-3, 1987, pp. 123-135.

15.   L.A. Leskiw, E. Reinl-Dwyer, T.L. Dabrowski, B.J. Rutherford, H. Hamilton,
      Disposal  of Drilling Wastes. Alberta  Land Conservation and Reclamation
      Council Report RRTAC 87-1, 1987, 210 pp.

16.   D.A. Lloyd, Drilling Waste Disposal  in Alberta  - A Field Manual. Paper
      presented at the First International Symposium on Oil and Gas Waste
      Management Practices,  New Orleans, Louisiana, September, 1990.

17.   C.B. Powter, S.  Fullerton, Proceedings -  Soil Sterilants Workshop.
      Alberta Environment, Edmonton, Alberta, 1986, 30 pp.

18.   M.P. Sharma, Efficiency of Activated Charcoal for Inactivation of Bromacil
      and Tebuthiuron Residues in Soil. Alberta Land Conservation and Reclamation
      Council Report RRTAC 89-3, 1989, 38 pp.

19.   U.S. Office  of Technology  Assessment,  Reclaiming of Prime Farmlands and
      Other High Quality Farmlands  After Surface Coal Mining. 1985.
                                      15

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ALTERNATIVE PROCESSES FOR THE REMOVAL OF OIL FROM OILFIELD BRINES
K. Simms, S. Kok, A. Zaidi
Environment Canada
Wastewater Technology Centre
Burlington, Ontario, CANADA
Introduction

Production  of  oil  from  both onshore  and offshore  oil  recovery  operations
generates substantial  volumes of oilfield brines which must  be  handled in an
environmentally  sound manner.  Removal of residual suspended oil is a critical
step in the handling and treatment of these brines prior to their-ultimate fate
which  may be  reinjection,  deep  well disposal,  recycle  or  discharge  to the
receiving aquatic environment.

Conventional treatment of oilfield brines for oil removal generally involves the
use of unit processes  designed  to  separate the  oil  by gravity  (or enhanced
gravity)  settling.   These  processes include  skim tanks  (ST),  parallel plate
separators  (PS)  and induced gas flotation units  (IGF).  In some instances, such
as in  onshore in-situ heavy oil  recovery  operations using steam,  a polishing
step,  consisting of  granular media  filtration  (GMF),  is used  for  fine oil
removal.  The use of these processes  is typical of both the offshore and onshore
oil production in all major oil producing regions of the world.  However, these
processes  have  certain  inherent  features which  make them  prone  to serious
operating difficulties.   Therefore,  at some locations they can  not be relied
upon to  consistently  provide the degree of oil removal necessary  to meet the
specifications for recycle or discharge.  Consequently, alternative oil removal
processes need  to be  considered  to treat the  oilfield  brines  more effectively
than is possible with the conventional processes.

Environment Canada's  Wastewater  Technology Centre  (WTC)  has  been evaluating
several  aspects of oil  removal  from oilfield brines  from both  offshore oil
production and from onshore in-situ heavy oil production using steam injection
methods.  This paper presents an overview of the status  of  conventional and
alternative oil  removal processes based on the results of the WTC work as well
as other published information.

Requirements for Oil Removal from Oilfield Brines

The requirements for the treatment of oilfield brine vary depending on whether
the brine is from offshore or onshore oil production and whether or not the brine

                                      17

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can be disposed of through deep-well injection.

Offshore Oil Production
Discharge of treated brine to  the  ocean is currently the most common approach
for handling the oilfield brines at offshore oil production facilities.   Before
treatment, the oil concentration in the brines at these facilities can be as high
as 400 mg/1 or more1.   On the other hand, present limits for oil concentration
in the  oilfield brine for marine  disposal range  from  as low as  30 mg/L  in
Australia to 48 mg/L1 in the United  States.  The discharge limit in the North Sea
is 40 mg/L1.  Proposed guidelines for Canadian offshore platforms also specify
a discharge limit of 40 mg/L2.   The regulations for the North Sea  will shortly
be revised,  and  lower discharge  limits may be  established for  offshore oil
production in this region.

Onshore In-Situ Heavy Oil Production
A significant portion of the  heavy  oil  in Alberta and Saskatchewan is recovered
using  steam injection methods.    These  methods  usually  generate  substantial
quantities  of  oilfield  brines.  One approach for handling these  brines is to
recycle them as feed to the once-through oilfield steam generators.  Since this
approach  is  considered  environmentally more attractive  than  the alternatives
(such as deep well injection),  the emphasis in the heavy oil industry is towards
recycling  as  much brine  as  the circumstances would allow. However,  certain
factors (e.g.  presence of other contaminants; experimental nature of the in-situ
recovery facilities, etc.)  currently mitigate against the recycle at most  of the
locations in Alberta and Saskatchewan, so that the oilfield brine is generally
disposed of by deep well injection in these areas.

Concentration of  oil in the  untreated  brines can be  as  high as 1 570 mg/L  or
more.    Recycling of the  oilfield brine to generate steam requires  that the
suspended  oil be  removed down  to non-detectable  levels (<  1  mg/L) .   The
specifications on the concentration of oil  in the oilfield brines for deep well
disposal  are  variable;  however, it La  generally acknowledged  that  minimizing
the oil concentration in the brine to low levels is desirable to prevent plugging
of the injection  formation.

WTC Study on Offshore Oilfield Brines

In  1987,  the  WTC  initiated  a  study  to  assess the  status  of oil  removal
technologies for  oilfield  brines from  offshore oil  production "and to identify
research needs related to the treatment of these  brines.  The study included a
survey of offshore oil platforms in  the  North Sea.  Questionnaires were forwarded
to all major offshore oil  platforms in  the  British and Norwegian sectors  of the
North Sea.  Information was requested on the volumes of oilfield brine generated,
disposal methods,  type  of oil removal processes used,  typical performance of
these processes and operational problems experienced with the oil removal process
equipment.

Scope of the Survey
Responses were received  from  all the 17 oil  companies  contacted. Information was

                                      18

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provided for  43  platforms; 18  in  the Norwegian sector and  25  in the British
sector.  Except  for 2 platforms  where reinjection of the  oilfield water was
carried out, all  the platforms discharged the treated oilfield brine to the sea.
The volume of oilfield brine generated at these platform ranged from  20 to
25 000 m3/d with an average of 5 000 m3/d.

Oil Removal Processes Identified
Table 1 shows the types of oil removal processes used and the number of  platforms
where  each process  was  used.   The most common  processes  used  for  both the
Norwegian  and British  Sectors were plate separators and induced gas  flotation
units.   Table 2  shows the most common process  treatment  trains used for each
sector of  the North Sea.  In the  Norwegian  sector,  the  most common  treatment
train  consisted  of a skim tank, followed by a  plate  separator  followed by an
induced gas flotation unit. In the British sector, the most common  process train
involved the  use of a plate separator alone  or in combination with an induced
gas  flotation unit.   The  survey  also  identified  (see  Table  1)  that  the
hydrocyclone, a  relatively newer  technology, was  being used on five  platforms
in the British sector  and was  scheduled  for  installation on four platforms in
the Norwegian sector.

Performance of Oil  Removal Processes
Table  3  summarizes  the  average oil  concentrations  in the  effluent  from the
various treatment processes.  The influent oil  levels  seen by the process units
were not determined by the survey.  Of most  interest is the effluent from the
final  process units prior  to marine discharge of the oilfield brine.

The  IGF  unit  was  used  as  the  final treatment   process on  21  offshore
installations.   The average effluent oil concentrations  ranged  from 15  to 100
mg/L.  However,  the overall average  oil concentration was  less than 40 mg/L.
In some cases (8 platforms), plate separators were used as the final  treatment
prior  to  discharge.    In these   cases,  the  overall  average  effluent  oil
concentrations was 15 mg/L with  a range of 2 to 35 mg/L. Hydrocyclones  typically
produced an effluent averaging  33 mg/L of oil with a range  of  13 to 75 mg/L.

Generally, the process units met the regulatory requirements; however, there were
some  instances of  excessive oil concentration in the effluent  as a result of
operating  problems  experienced  with the treatment process.

The  main  operating problems identified  from  the  WTC  survey  for  the plate
separator, the IGF unit and the hydrocyclone are summarized in Table 4.  The most
commonly cited problems for the IGF unit  were the  inability to handle  emulsions
and the inability to maintain good level  control.  These operating difficulties
caused very high concentrations of oil in the final  effluent; in several of the
responses, maximum oil concentrations over 2 000 mg/L were cited.  These problems
have also been identified at the oil production platforms operating in the U.S.  .
The  frequency of occurrence of these upsets was  not  identified in the survey
conducted by the Wastewater Technology Centre; however, other data6 suggest that
upsets could  occur  about 20-30% of the time.  Similar  problems were  experienced
with  the  operation  of  the  plate  separators.    For  the   hydrocyclone,  no

                                      19

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difficulties were cited with respect to  platform motion or high oil levels  in
the influent to the treatment train, but  problems were experienced with erosion
and sand buildup.  The offshore operators also indicated that effective on-line
oil-in-water monitoring of the  treatment processes would be helpful in achieving
a more consistent performance than is currently observed.

Conclusions from the WTC Study on Offshore Oilfield Brines
From the WTC study, it was concluded that although the plate separator and IGF
units were  the most common  processes  used on North Sea platforms,  there were
substantial operational problems associated with  these  units.   The relatively
newer hydrocyclone technology seemed promising because of lower sensitivity to
platform motion  and to variable influent oil concentration.   For the Canadian
situation,  where full  scale   offshore  oil production  is not  yet in  place,
hydrocyclones  would appear to  be the most  appropriate  technology for removing
suspended oil  from the produced brines.

WTC Study on Onshore In-Situ Heavy Oil Recovery Brines

In 1988, the WTC conducted a study to  evaluate  the performance of  oil removal
processes operating at  two in-situ heavy oil recovery operations (Sites A and
B) in Alberta.  Long term and intensive sampling campaigns were conducted at each
site.  During the long  term sampling campaign, samples were collected daily over
a one month period to monitor long term performance variations.  The intensive
sampling campaign, consisting  of 4 to  5  samples per day,  was  conducted over a
1 week period  to monitor  daily performance.  Grab  samples  of  process  feed and
effluent streams were taken for determining the  oil  concentration  in the sampled
streams.   The analytical method for determining  oil  was based  on  a  standard
partition/gravimetric method using Freon 113 .

Figures  1  and  2 schematically show the oil removal process  trains and  the
sampling  locations  for  the   oilfield  brines  generated  at   Sites  A  and  B
respectively.  At Site A, the oil removal  process train consisted of a skim tank,
an IGF unit and three anthracite/garnet filters.  The capacity of the IGF unit
was less than the volume of water produced so that up  to 20 % of the water
bypassed the unit and  was introduced directly to the filters.   The total flow
of produced water was 6 000 m /d at this  site, and the water was disposed of by
deep well injection.   At  Site  B, the oil removal  process train consisted of a
skim tank,  a surge tank, an IGF unit and  two sand filters.  In this case, 2 000
m /d of oilfield brine was being treated prior  to  deep well disposal.

Results from the In-Situ Onshore Study
Tables 5 and 6 present  a  summary of the  results of the  performance evaluation
study for Sites A and B respectively.

At Site A,  the effluent oil  concentration from the IGF unit averaged 47.9 mg/L
and 25.1 mg/L  during  the daily and intensive  sampling  programs  respectively.
Wide variations  in the long term performance of the IGF  unit were observed, as
indicated by the high standard deviation in the oil and grease concentration (see
Table 5 and Fig.l).  Considerable problems were experienced with the operation

                                      20

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of the anthracite/garnet filters at Site A.  The average oil concentration  for
the filter effluent during the intensive sampling campaign was 40.5 mg/L; this
corresponded to an oil removal efficiency of only 6.7%.  Main operating problems
experienced with  these filters included channelling,  and  "mudballing" of  the
filter media.   The filters were frequently out of  operation  because of these
difficulties.

At Site B, long term  performance for the IGF unit was worse than that observed
for the IGF unit  at Site A.   The average IGF effluent concentration for Site B
was 101.2 mg/L.   During the study period, the skim tank had been shut down  and
the surge tank was being used as a skimming vessel.  The loss of surge capacity
resulted in high  flow and oil level variations in the IGF feed.  As at Site A,
wide variations in IGF performance were observed as  shown in Fig.4.  During the
intensive campaign, the IGF performance at Site B was  comparable to that of the
IGF  unit at  Site  A.   For  the  sand  filters  at  Site B,  the effluent  oil
concentration averaged 51.4 mg/L  for  the  long term  sampling  campaign and 25.8
mg/L  for  the intensive sampling  campaign.   The  poor performance of  the sand
filters  over the long term  is  attributed to  frequent  oil  leakage due  to
channelling  in  the filter.   The average  oil removal efficiency of  the sand
filters at Site B over the long term was only 8.4%.

Conclusions from  the  In-Situ  Onshore Study
The study identified  substantial operational problems  with the conventional IGF
and GMF units.  These  problems result in wide variations in effluent quality and
oil removal efficiency over time;  effects  that would severely limit the ability
of the  heavy oil  operators to  recycle the oilfield  brine.   Therefore,it  was
concluded that alternative processes need to be evaluated in order to obtain the
consistently  high quality effluent that is required  for recycle to  the steam
generators.

Alternative Processes for the Removal of Oil

Since the completion of the WTC work described above,  there have been significant
developments  in  the  oil  removal  process  technologies for  the treatment  of
oilfield brines.  These developments relate to the increased use of hydrocyclone
processes and the field testing  of membrane technologies  (ultrafiltration and
microfiltration)  to alleviate some of the operational difficulties  previously
described. The following paragraphs detail these alternative processes  and their
status for both offshore and  on-shore in-situ heavy oil recovery situations.

Hvdrocvclone
Potential advantages of hydrocyclones over the conventional oil removal processes
for  the treatment  of oilfield  brines from  offshore oil  platforms  are   (i)
relatively low weight  and volume requirement, (ii) insensitivity to wave motion,
and (iii) reduced sensitivity to influent oil concentrations.

The operation of the hydrocyclone  is based on the use of a swirling flow pattern
to generate centrifugal forces which separate the oil and water based on their
density difference. There are two types of hydrocyclones which are distinguished


                                      21

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by the method used to generate the flow pattern.  In static hydrocyclones,  the
swirling flow pattern is established by high inlet flow and pressure;  in rotary
hydrocyclones, mechanical rotation provides the swirling  flow motion.   The main
advantage cited by the manufacturer of the rotary hydrocyclone is that  high inlet
velocity is not needed  and  high  turndown ratios are possible.   Both  units  are
subject to erosion by sand  usually  present in the oilfield brines.   Figures  5
and 6 show schematics of  the  static and rotary hydrocyclones  respectively.

Currently, hydrocyclone applications  are limited to the  treatment of  offshore
oilfield brines, and full scale static hydrocyclone  systems have been  installed
at more than  50 offshore  platforms8.   One  rotary hydrocyclone  system  is  being
installed offshore  in Holland9.   The  static hydrocyclone is  now marketed by
Conoco Special Products Inc. (CSPI)  in the  U.S.  The rotary hydrocyclone,  which
is a relatively newer technology,  is  being marketed by Serck  Baker U.K.  under
the name "Dynaclean".  Published data on the performance  of the Dynaclean unit
are limited.   However,  results of tests10  conducted  in 1989 at an independent
testing centre in  Northern Scotland indicate that, at an inlet oil concentration
of 150 mg/L, the Dynaclean can consistently  generate  an effluent containing less
than 40 mg/L  oil, and maintain this  performance at  flow  rates  ranging from 20
to 200  %  of the  nominal  design  flow rate.   In these tests,   the oil removal
efficiency of the rotary hydrocyclone remained near  90  % when the  inlet oil
concentration was increased from 20 to 1 800 mg/L.

The CSPI static hydrocyclone has  been tested for heavy oil field application in
Alberta   but  results of  these tests have  not  been released.   The  Dynaclean
rotary  hydrocyclone  has  not  been tested  in the  field  for  the  treatment  of
oilfield brines from in-situ operations in  Alberta or Saskatchewan.

Membrane Technology
Potential advantages for application of membrane processes (ultrafiltration and
microfiltration) to oilfield brines  for offshore platforms include  (i)  low size
and weight,   (ii)  insensitivity  to  platform motion,  (iii)  insensitivity  to
fluctuations  in influent  oil  concentration and (iv) more  consistent effluent
quality.  The  last two  factors are  also relevant to onshore in-situ  heavy oil
operations.

Figure 7 shows a schematic of  the principle  of operation of membrane filtration
processes  such as ultrafiltration  (UF) and microfiltration   (MF).    The oil
containing brine  flows  axially in a  porous tube while  the clean water flows
radially through the  tube  walls.  MF implies tube wall pores in  the range of 0.1
micron to a few microns.   UF, on the other hand,  implies much finer pores (<0.01
pirn).  Because  of the  positive  barrier  available for separating the oil  from the
water,  the  effluents generated  by  UF  and  MF  processes are  expected  to  be
virtually free of suspended oil.  The flux (flow rate per unit membrane area)
is generally higher for MF than for UF; however, MF  can be more susceptible to
particulate fouling than UF.  UF and MF membranes may be  made  from a  number of
organic polymers or inorganic materials. The commercial  organic membranes are
available in  a  wide  range of polymers  including cellulose acetate,  cellulose
triacetate, polysulphone, polypropylene and polyimide.   Similarly, commercial
                                      22

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inorganic membranes are available in many different materials including alumina,
zirconium oxide, titanium oxide, stainless steel and carbon.
                                                   ^
For MF  and UF  treatment of  oilfield brines,  several tubular  membranes are
generally placed in tubular modules to provide high surface area for filtration.
A system consists of many of these modules, a recirculation pump and  ancillary
tanks for feed, concentrate and product.  A schematic of a typical assembly is
provided in Fig. 8.

Microfiltration  has  been  tested  for  both  offshore  and  heavy  oil  field
applications.  One MF system for the treatment of oilfield brines is  currently
marketed by Alcoa  in the U.S.  The system uses  tubular  alumina  membranes and
employs a permeate  backflush  to maintain the  membrane  flux.   Discussions with
the supplier  indicate  that  pilot  tests  (up to several months  long)  have been
conducted in the North Sea and the Gulf of Mexico, and a full-scale Alcoa system
is  currently  being  installed  on  an  oil production platform  in the Gulf  of
Mexico  .  Published data on the performance of MF systems  and on the testing of
any  UF systems  for  offshore oilfield  brines   are  currently not  available.
However, both UF and MF have  been tested for  the treatment of oilfield brines
from in-situ heavy oil recovery operations in  Alberta at bench and pilot scale,
and some data are available for this application of UF and MF.

In 1981, the Alberta Oil Sands Technology and Research Authority (AOSTRA) funded
a study   on the evaluation  of UF  for removal  of oil from the oilfield brines.
However, the  results of this study are  not available  in  the open literature.
Later work  on UF   for  oil  removal  on oilfield  brines from  in-situ  heavy oil
recovery operations consisted of off-site and  on-site trials at bench  and pilot
scale.  These tests were conducted with a UF system and two different membranes
developed by  Zenon  Environmental Systems,  Burlington,  Ontario.   Initial trial
runs (several days to a few  weeks) indicated that an effluent flux ranging from
50 - 250 L/m /h could be  achieved with cleaning  intervals ranging from  1 to 7
days.   Longer term pilot tests   (total of  2  months/membrane)   conducted  in
1989/9Q indicated that under certain conditions substantially lower fluxes were
attained.  This flux decline  was attributed to  fouling due to the presence of
fine solids in the oilfield  brines.  The  presence of certain oil-well treatment
chemicals in the the brine also caused the leakage of suspended oil through the
membranes.  During most (approximately 80 %) of the test period, however, these
problems did not appear and a high quality effluent (negligible suspended oil)
was generated by UF.

MF work on oilfield brines from in-situ heavy  oil operations has been  conducted
at both bench and pilot scale at research facilities and in the field.  Most of
                               16
the tests have been short term   (a few days to 2 weeks).  In one widely tested
system, developed by Separ Systems and Research Ltd., Calgary, Alberta,  chemicals
(such  as  ferric chloride,  calcium oxide  and sodium  carbonate  solely  or  in
combination)  are  added to the  oilfield  brine and recirculated  through Alcoa
ceramic membranes.   Available data from one  of these tests  indicated  fluxes
ranging from  800 -  1 800 L/m /h  .   In  longer  term pilot tests15  (total of 5
months testing) conducted in parallel with the UF pilot test cited previously,
                                       23

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the flux was substantially less than what was observed in the short term trials.
No  substantial  difference in the flux rate  was  observed  between  trial  runs
conducted with  and without the  use  of chemical  addition.   One MF system  is
currently being installed at an onshore oilfield site in Alberta12.

Studies of membrane technology have identified several difficulties.   However,
it must be recognized that the work completed to date has been limited both  in
terms of  scope  and duration.  There  are many membrane  materials  and systems
currently available that  are  potentially  suitable for application to  oilfield
brines.    In addition,  longer  term  testing  is  required  to determine the
performance of membrane processes under the range of conditions seen over  time
at operating oilfield sites.

Overall Conclusions on Conventional and Alternative Oil Removal Processes

There is an increasing need for reliable and efficient technology for the removal
of  oil  from oilfield  brines generated  from the  onshore  and  offshore oil.
production.  Treatment requirements must address the prospect of more stringent
limits for marine discharge of the oilfield brines from offshore oil platforms,
and for the recycle of oilfield brines from heavy oil production.

The  survey  of  the  North Sea  offshore   oilfield  treatment  systems  and the
performance  evaluation  study of  conventional  processes  in Alberta  heavy oil
fields  indicated  serious  operating difficulties  with conventional  processes
(IGF, granular media filters,  etc.) which  led to inconsistent effluent quality.

Hydrocyclones  and  membrane  processes   have  certain   advantages   over  the
conventional oil removal technology.  These advantages include insensitivity to
platform motion,  low load requirements, reduced sensitivity to variable influent
oil concentration and consistent effluent quality.

The WTC  tests on  MF  and UF  at  a heavy  oil  field  site in  Alberta indicated
generally consistent performance  but did not generate sufficient long term data
to allow an evaluation of the cost effectiveness  of the membrane  processes.

Ongoing Research Activities at WTC

For Canadian offshore oilfield brines, studies to  evaluate  the performance of
both the static and rotary hydrocyclone are currently  in progress.  In addition,
evaluation  of  several oil-in-water monitors  and  analytical  methods  for oil
determination is currently ongoing.  Also, there  are plans to initiate, in the
Fall of  1990, a  systematic evaluation of up to 20 commercially  available and
experimental membranes for their  suitability  for  application to  the treatment
of oilfield brines from in-situ heavy oil recovery operations in  Alberta.

Acknowledgement

This work was supported, in part, by the Federal  Panel on Energy  R & D (PERD).
                                      24

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References

1.    Thomas,   D.J.,   et   al.,   Offshore  Oil   and  Gas   Production   Waste
      Characteristics.   Treatment  Methods.  Biological  Effects  and   Their
      Application  to  Canadian Regions, prepared  for  EPS,  Environment Canada,
      1983.

2.    Canada  Oil and Gas  Lands Administration,  Canada  Newfoundland Offshore
      Petroleum  Board, Offshore Waste Treatment Guidelines. Jan.  1989.

3.    Selwood,   P.,  UK  Offshore  Operators   Association   Ltd.,   personal
      communication,  1990.

4.    Wastewater Technology  Centre,  Environment  Canada, Characterization of
      Produced  water  from  Selected  In-Situ Heavy Oil Recovery Operations in
      Alberta and  Saskatchewan, unpublished report,. 1990.

5.    CH2M Hill, Generation of Steam using Low-Grade Fuels  and Field Produced
      Water for  In-Situ  Oil Recovery, prepared for Energy, Mines  and Resources
      Canada, Aug.  1982.

6.    Jackson, G.F., E. Hume, M.J. Wade,  and M. Kirsch, Oil Content in Produced
      Brine on Ten Louisiana Production Platforms,  prepared by Crest Engineering
      Inc. for U.S. EPA, Cincinnati, OH, 1981.

7.    APHA/AWWA/WPCF,  Standard  Methods  for  the Examination of  Water  and
      Wastewater (Method /503A1. Washington D.C.,  1980, pp.561-562.

8.    Conoco Special Products  Inc., manufacturer's data,  July  1990.

9.    Michaluk,  P., Serck Baker, U.K., personal communication,  1990.

10.   Triponey, G., and J. Woillez., "Recent Experience in Water Separation from
      Gas Condensate", 1990.

11.   Rubinstein,  I., Esso Resources, Calgary, personal communication, 1990.

12.   Gramms,  L.C.,  Separ  Systems  and  Research  Ltd.,  Calgary,  personal
      communication, 1990.

13.   Alberta Oil  Sands Technology and Research  Authority,  unpublished data,
      1981.

14.   Krug, T.A., Farnand, B., "Ultrafiltration of Oil Field Produced Water for
      Oil Removal", 37th Can.  Chem. Eng. Conf.,  Montreal, May  1987.

15.   Environment Canada, Wastewater Technology Centre, unpublished data, 1990.

                                     25

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16.   Separ Systems & Research Ltd., Crossflow Microfiltration of Produced Water.
      prepared for Environment Canada,  May 1988.
                                     26

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                          TABLE 1

       Oil Removal  Equipment on Korth Sea Platforms
Unit

Skim Tank
Norwegian
Sector
11
Plate Separator 12
Induced Gas Flotation 15
Hydrocyolone
Coalescer
Granular Media
Dissolved Air
Other
4*
1
Filter 0
Flotation 0
4
British
Sector
3
15
12
5
1
1
1
3
Overall

14
27
27
9
2
1"
1
7
   *  scheduled for  installation
                           TABLE  2

   Oil Removal Treatment Trains on North  Sea Platforms
Process Train

ST/PS/IGF
PS only
IGF only
HC only
PS/IGF
Norwegian
Sector
8
1
3
4*
1**
British
Sector
1
7
3
2
4
Overall

9
8
6
6
5
      installations not complete at  time of  survey
   ** combination skim tank and plate  separator
                         TABLE  3

Average Effluent Oil Levels from North Sea Platform Survey
Process Norwegian Sector
t Range Mean
ST
PS
PS*
IGF
IGF*
HC*
10 15-3000 882
11 20- 200 163
1 20
14 15-2000 174
13 15- 38 33

British Sector
t Range Mean /
2
13
7
11
8
5
200-3000
2-
2-
220
35
16-2000
16- 100
13-
75
1600
47
14
217
38
33
12
24
8
25
21
5
Overall
Range Mean
15-3000
2-
2-
220
35
15-2000
15- 100
13-
75
1001
51
15
193
35
33
                             27

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                        TABLE 4

    Main Operating Problems of  Oil  Removal  Equipment
                 On North  Sea Platforms
Plate Separator     Induced Gas Flotation    Hydrocyclone
Plugging of plates  Unable to handle
                    emulsions
                         Erosion and
                         corrosion
Unable to handle
emulsions

Platform motion

Oil slugs

Surge loads
Level control problems   Blockage due
                         to sand buildup

Platform motion

Oil slugs

Poor froth formation

Interference by
treatment chemicals

Poor mechanical
durability

Scale/sludge buildup

Operator/maintenance
intensive
Unit
IGF

GMT
Unit
IGF

GHF

TABLE 5
Performance of Oil Removal Units at Site A
Total Oil Concentration (mg/L)
Sampling Number of Influent Effluent
Campaign Samples Mean S.D. Mean S.D.
Long Term 25 85.9 39.1 47.9 18.2
Intensive 19 76.9 40.5 25.1 2.8
Intensive 21 45.1 16.3 40.5 25.1
TABLE 6
Perf.Qrma.nce of Oil Removal Units at Site B
Total Oil Concentration (mg/L)
Sampling Number of Influent Effluent
Campaign Samples Mean S.D. Mean S.D.
Long Term 20 112.3 97.6 101.2 87.3
Intensive 20 155.3 206.9 45.3 43.2
Long Term IB 129.2 108.5 51.4 34.0
Intensive 19 40.0 32.8 25. B 13.7
Oil Removal (%)
Mean S.D.
40.9 20.0
57.1 22.0
6.7 53.0
Oil Removal (%)
Mean S.D.
7.9 37.7
52.7 22.9
42.2 36.6
8.4 50.0
                            28

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    SHU
    TANK
                        BY PASS
9
SAMPLING PORT
                          TO DISPOSAL TANK
                                                   FILTERS
9


ffrfn3 O

>~^-
I



A





A


          Figure  1    Sit* A  ProceM Flow Schematic
                                                                                                    10        15
                                                                                                    Sample Number
                                                                                   Figure 3   Long Term IGF Performance at  Site A
SKDI
TANK


SURGE
TANK
9

.•rPWrP.
IGF UNIT ]
                                             L9J
   9
   SAMPLING PORT
                             TO DISPOSAL TANK
         Figure 2   Site B  Procen Flow Schematic
                                                        FILTERS
                                                       vv
                                                                                                         10
                                                                                                    Sample Number
                                                                                                                                  20
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-------
AN ASSESSMENT OF  PRODUCED  HATER  IMPACTS TO LOW-ENERGY, BRACKISH  HATER SYSTEMS
IN SOUTHEAST LOUISIANA: A PROJECT SUMMARY
Kerry M. St. Pe
Study Coordinator
Louisiana Department of Environmental Quality
Hater Pollution Control Division
Lockport, La. 70374
Jay Means, Charles Milan
Louisiana State Universtiy
Institute for Environmental Studies
Baton Rouge, La.
Matt Schlenker, Sherri Courtney
Louisiana Department of Environmental Quality
Baton Rouge, La.
Introduction

      Produced water is a by-product of the oil production process and is brought
to the surface along with petroleum from  subsurface  formations.  Also known  as
formation  water  or  oil field brine,  produced waters associated with Louisiana
oil reserves are usually highly saline with ranges reported by Hanor et al.  (1)
from  50  ppt to  150  ppt.  In comparison, the average open-ocean salinity  is  35
ppt (2).  Louisiana  inland water salinities vary considerably with distance from
the Gulf of Mexico,  but are  almost  always  much less than those found in  the open
sea.

      Produced waters  can  also contain various  radionuclide and  volatile  and
semivolatile organic hydrocarbon contaminants.  Boesch  et al. (3,4)  demonstrated
that  produced   waters  discharged   into  Louisiana  waters  contained   high
concentrations of petrogenic hydrocarbons.  Sediments near these  effluents were
also  highly contaminated with  semivolatile organic hydrocarbons.   Reid  (5)
surveyed several Louisiana produced water effluents and found radium 226  levels
ranging  from 131 ±  3 pCi/1  to 393  ± 1 pCi/1.

      The  recently  escalated research interest in the  environmental effects of
produced water discharges is largely  based on increased regulatory concerns by
various  federal, state,  and local  agencies.    These agencies  have  directed
research  efforts towards  obtaining  the  data  necessary  for  reassessing  and
updating current regulations dealing  with produced water  discharges.
                                       31

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      Within the State of Louisiana, the Louisiana Department of Environmental
Quality  (LDEQ),  Water Pollution  Control  Division, governs  all discharges  to
surface waters.  The current Louisiana regulations which specifically  apply  to
produced waters  date  back to 1953.  The  1953  rule basically allowed  produced
water effluents into any stream not used for drinking water purposes.   In  1968
an additional rule was promulgated which prohibited the discharge of oil field
brines into  freshwater areas, but allowed for  their release into "...normally
saline  waters,  tidally  affected  waters,  brackish  waters,  or other waters
unsuitable for human consumption or agricultural purposes"  (6).

      On November  20,  1985,  LDEQ adopted a water  discharge permitting system
which required all effluents, including those from  the oil and gas industry,  to
be permitted.  An agreement was made to allow the petroleum industry until May
20, 1986, to submit applications.

      Data  from the  applications submitted  by the  petroleum  industry  were
summarized in a study by Boesch and Rabalais  (3).   The total volume  of  produced
water  discharged to  Louisiana  waters  at  the  time  of  the study  was almost
2,000,000 barrels per day.

      Generally, the objectives of this study were derived to further  evaluate
past observations made by the LDEQ staff and other investigators or to add to
the available  data base  regarding produced water  discharges  to low-flow type
systems.  The specific study objectives are presented below.

      1.    To  evaluate the  hydraulic  behavior  of  produced  water effluents to
            poorly flushed brackish or saline systems.

      2.    To quantify the organic, inorganic, and radiological pollutants in
            selected produced water discharges  and in  proximate sediments  and
            to evaluate the spatial extent of effects.

      3.    To  evaluate  the  potential for  bio-concentration  of  polynuclear
            aromatic hydrocarbons  (PAH) from contaminated sediments by benthic
            biota.

      4.    To evaluate the biotoxicity of produced water effluents and proximate
            sediments.

      5.    To  assess the potential for the accumulation  of radionuclides  and
            organic pollutants by caged oysters  placed in proximity to  produced
            water discharges.

      Presented  in this  paper  is a general  summary of  study  results.   The
original study  report which  is  presented  in more  detail is available  from the
study coordinator.

Study Sites

      Four study sites in southeast Louisiana  were selected for study.  Study
sites consisted  of a  single  discharge and were located  in  the  Lirette (LRT),
                                      32

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Delta Farms (DF), Bully  Camp  (BC)  and Lake Washington (LW) Oil Fields.   Three
transects,  labeled "A",  "B",  and "C", radiated  from  each produced water  site
outfall.   Eight  sample points were  distributed  at varying distances  from the
outfall along  the transects.   An  unaffected reference  sample point was  selected
for each study site for comparison.

      The  types of samples collected were either sediments, effluents,  biota,
or water column.  Sediments and  water column samples were  collected from  each
transect sample point.  Biota were collected from caged oysters placed along  a
site transect.

      This study was meant to be a general assessment of  the extent and  nature
of  produced  water  impacts and  therefore  did  not  include  the   replications
necessary  for extensive statistical  analyses.

      Discharge volumes  varied from  462  barrels  per  day  (bpd)  at   the  LRT  site
to 13,458 bpd  at the DF site.  Effluent salinities were considerably higher  than
receiving  stream concentrations  and  ranged from  139 ppt at  the LRT site  to 193
ppt at the  LW site.   Receiving stream salinities ranged from  about 4.0 ppt at
the DF site to an average of  23  ppt  at the LH site.

Hydraulic  Behavior of Produced Water  Effluents

      Due  to their high salinities, Gulf Coast produced waters are generally  much
denser  than Louisiana inland waters.   Harper   (7) reviewed  literature  which
reported a bottom layer of higher salinities  near produced water effluents  into
poorly  flushed canals.   Boesch  and Rabalais (3)  concluded that produced water
effluents  can act as dense plumes after discharge to estuarine waters.  Studies
have also  shown high concentrations  of hydrocarbons in sediments  near  produced
water outfalls (3,4,8).  These observations, along with those made by  Baird et
al.  (9) provided the impetus for  this further investigation into the hydraulics
of produced water effluents.

      A  slotted  core tube was  used  to  collect  sediment  and  overlying  water
samples  from  each transect point for chlorides analyses.   Overlying water was
collected  from the core  tube  at  the sediment/water interface  (0  level)  and at
the  10 cm  (+10) and 20 cm  (+20)  levels.   Interstitial water was also collected
from 10 cm core sections (-10, -20, and -30 levels).   Water column measurements
were  also taken with  a  commonly-used CTD  (conductivity, temperature,  depth)
instrument.

      Results  from  all  4  study  sites  (Figs.  1, 2,  3  and 4)  indicated  that
produced water influences on chloride concentrations of the receiving water  body
were  considerably more  apparent in  bottom  sediments in  comparison  to those
effects measured in  the water  column.  At some stations highly elevated  sediment
chloride concentrations were  measured, while no  measurable impact in the water
column of  the same station was detected.   This suggests  that almost no  apparent
mixing of  these discharges is occurring  or that  any dilution which might occur
is insufficient to completely reduce the density differences between the  produced
water effluent and the receiving water column.
                                       33

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      Produced water was shown to penetrate to  a depth of at least 30 cm at some
stations and there was a strong positive correlation between depth increases and
interstitial chloride increases at the most impacted transect points.  The trend
of steadily increasing  sediment  chlorinities  suggests that  a produced  water
penetration to levels deeper than  30 cm is likely.

      The highest interstitial chlorinities were measured at the stations nearest
to the outfall (LRT-0, DF-0, BC-0, and LW-0) with progressively lessening effects
noted at more distant transect points.  The most heavily impacted sediments were
visibly contaminated with high concentrations of hydrocarbons.   Trend  analysis
of selected study site  stations indicated an exponential  rate of increase  in
sediment chloride concentrations  as the origin is approached.

      Study  results  also show  that conventional CTD  instruments may not  be
capable of consistently detecting produced water chloride impacts since much  of
the effect, at least  in poorly  flushed systems, may be below the position of the
conductivity sensor.  A strict reliance on water column salinity readings  near
produced water effluents might result in the erroneous  conclusion that  produced
waters are  completely mixed and quickly dispersed after discharge.

Radium 226  Activities in Produced Hater

      Produced waters from Louisiana and locations throughout the world have  been
shown  to  contain  environmentally  high  concentrations  of radium  (5) .   The
regulatory  control of naturally occurring radioactive materials  (NORM)  has not
received sufficient attention in the past  by federal and state agencies  because
of limited  jurisdictions and staff  (10).

      Current  Nuclear   Regulatory  Commission  regulations   set  a   maximum
radioactivity  level of 30 pCi/1 in  liquid discharges from nuclear power plants
to unrestricted access areas.  Standards for drinking water are set not to exceed
5 pCi/1.  EPA regulations proposed in response to the Resource Conservation and
Recovery Act of 1976 (RCRA)  would classify radioactivity levels of greater  than
50 pCi/1  as a hazardous waste.   The natural  radium  226 activity of Louisiana
surface waters is usually below 1.0 pCi/1  (10).

      The USEPA and the Conference  of Radiation Control Program  Directors  have
recommended remediation of radium-contaminated soils to 5 pCi/g above background.
The natural Ra 226 activity of Louisiana surface soils  ranges  from <1  pCi/g  to
about 7.0 pCi/g  (10).

      High radium 226 levels were detected in all study site effluents  and ranged
from a low  of  355 pCi/1 at the Delta Farms site to 567  pCi/1 at  the Bully  Camp
site.   The  variation  between  site effluent  activities  is  probably  due  to
differences  in the  mineral composition of  the geologic formations from which
petroleum is extracted (11).

      The top  10 cm  of  sediment  from each transect  sample point  were  analyzed
for radium  226.  The sediments from the station nearest to the  outfalls at the
Lirette  (Fig. 5), Bully Camp (Fig. 7),  and Lake Washington  (Fig.  8) study sites
contained very high concentrations  of radium 226 ranging from  182 pCi/g at the


                                     34

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Bully Camp transect origin to 533 pCi/g at the Lirette  site  transect  origin.

      Radium 226  levels in  LRT,  BC,  and  LH sediments located  away from  the
outfalls were lower than transect origin sediments but were still  elevated above
background levels  at »ost  of the transect sample points.  Stations indicating
radium activities  which were greater  than 5 pCi/g  above the site background
(reference) were up to 500 meters from the outfall  (Lirette  site, Fig.  5).

      Sediment accumulation  of radium 226 at the Delta  Farms site  (Fig.  6)  did
not follow the observed pattern of the other sites.  No accumulation  of  radium
was noted  in Delta Farms sediments.   This was attributed  to the predominantly
organic nature of  the sediments at this site.  Radium 226  has been shown to be
more effectively adsorbed by the fine-grained,  clay type soils which were noted
at the Lirette, Bully Camp,  and Lake Washington sites (12,13).

      Although only the top 10 cm of  sediments  were considered in this study
component, there was evidence which suggested that radium  226 contamination in
sediments near the produced water outfalls investigated  may increase with depth
as did the interstitial  chloride concentrations.  An excavated 50 meter station,
LW-B50,  at the Lake Washington site showed  higher radium 226 activities than
another,  undisturbed 50 meter  station (Fig. 8).   It  also  appeared  that the
excavation  may have allowed for the transport  of radium  contaminated sediment
to more  distant transect stations.

Biotoxicity

      Samples  of  each study site  effluent were tested for  acute  toxicity to
mysids and sheepshead minnows.  Sediments  from a station near  each site effluent
and a reference from each  study site were also tested for  acute toxicity using
an elutriate and a solid phase procedure.

      Each  effluent exhibited  96  hour acute  toxicities   to  mysids  which was
attributed to components other than salinity. The Lirette effluent was  the least
toxic to mysids with an LCgf  value of 5.8Z effluent.  The highest mysid effluent
toxicity was measured at 2.6Z effluent  in the Bully Camp discharge  sample. The
mean LCg>  for  all  effluents  was 4.31.

      Effluent toxicity patterns  using sheepshead minnows differed from mysid
test patterns and sheepshead minnows were  shown to be less  sensitive to produced
water effluents.   The 96  hour LCgt values  for sheepshead minnows ranged from
33.81 effluent (least toxic)  at the Bully Camp site to 7.21 effluent  (most  toxic)
at the Delta Farms site.  The mean 96 hour LCg>  value for all effluents  used in
sheepshead minnow  tests was  20.IX.

      Two methods were used to measure sediment toxicity.  The first method used
tested  the toxicity of a  sediment  elutriate to mysids.   The elutriate tests
failed to  show any significant acute toxicity.

      The  second sediment toxicity method used was a solid phase procedure which
measured the toxicity  of sediment  samples to the borrowing  amphipod, Eyalella
azteca.   Significant levels  of  acute  toxicity to Eyalella,  due to a  component


                                      35

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other than salinity, were measured using this solid phase procedure.   The mean
mortality rate  for all  treatment  sediments was  73.31 mortality.   One  study
reference sediment sample,  BC-R,  demonstrated  a significant  mortality  rate
(28.91).  The remaining reference sites showed no significant mortality.

Chemical Characterization of Produced Water Impacts

      The  chemical  composition  of   four  produced  water  discharges   were
characterized using gas chromatography/mass spectrometry for the identification
and  quantification  of  the  organics  and  inductively  coupled   plasma/mass
spectrometry for the quantification of  the trace metals.  The produced waters
were characterized  by  high concentrations of volatile,  including benzene  and
toluene,  and  semivolatile hydrocarbons such  as aliphatic  hydrocarbons and a
series of alkylated polycyclic aromatic hydrocarbons (primarily naphthalenes and
phenanthrenes).  The discharges also contained high concentrations  of  aromatic
acids and aliphatic fatty acids.  The trace metal content of  the  four discharges
was  very  variable,  however,  each was characterized by  high levels of barium,
ranging from 1,521 ppb in the Delta Farms produced water discharge to a maximum
of 4,644  ppb  in the Lirette field  discharge.   Vanadium, a trace metal often
associated with oil, was also found in each of the four discharges at variable
levels.   Some  discharges contained significant levels  of  arsenic and copper.
These levels of toxic metals and organics represent a significant  negative impact
upon receiving waters of natural bayous because of the high volumes of formation
waters discharged annually into confined waterways which are often poorly flushed
by freshwater flow or tidal exchange.  Because of the  hydrology of these systems
and  the  particle reactive  nature  of both  the  metals  and  organics  being
discharged,  we  would   anticipate  that  these  substances   would continue to
accumulate within the sediments  in the  region of the discharges  to high levels.

Assessment of Produced Water Chemical Impacts to Receiving Streams

      The impacts of produced water discharges o,n sediment quality varied in  each
of the areas studied (Fig. 9).   Major factors determining the degree of impact
were:  1) discharge rate; 2)  quantity and quality of the hydrocarbons and trace
metals  present  in  a particular  discharge;  3)   local hydrology;  4)  sediment
disturbances  (i.e. dredging  and boat traffic);  and 5) sediment   types  (organic
carbon content and texture).  Analyses  of sediments collected at the four sites
revealed that all four receiving water systems were measurably  impacted by  the
discharges  in the  region.   Concentrations of  both  aliphatic  and alkylated
aromatic hydrocarbons characteristic of  the discharges,  as well  as barium,  were
found  at  elevated levels  above  background in  the sediments, surrounding  the
discharges.    The areal extent  of  this  contamination expressed  in  terms  of a
Fossil Fuel  Pollution Index (14)  or Ba concentration was  found to extend to  the
farthest points sampled at each discharge site (about 300m).  The continuation
of these discharges into these receiving waters will likely result in  an increase
in both the level and extent of contamination at these sites.

      Investigations of  the  genotoxic potential of  the produced water carried
out in other studies  indicated  that chemicals in  produced  waters represent a
significant genetic risk to embryo and larval stages of fish (15).  In this study
a bioaccumulation  model applied  to the levels  of contamination found in  the


                                      36

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sediments  yielded  extremely   high  potential  tissue  burdens   for   benthic
invertebrates, including edible species.  Thus, these  chemicals  represent  both
a potential ecological and human health risk.

Accumulation of Organics and Radium 226 by Oysters

      The  use of bivalves  in bioaccumulation  studies has  been advocated  by
researchers from several scientific disciplines (16).  Oysters have  been shown
to accumulate hydrocarbons  from produced  water effluents  (17,18,19).   Jeffree
and Simpson (20) demonstrated that  freshwater mussels can accumulate  radium 226
from uranium mill effluents.  There have been  no known investigations into radium
226 accumulation potentials by the oyster, Crassostrea virginica.

      In this study component, caged oysters  were used to  assess the potential
for the uptake of organic contaminants and radium  226.  Oyster cages  containing
75 individuals each were placed at  the Lirette,  Bully Camp, and Lake  Washington
sites.  Lirette cages were 110 meters  from the outfall and Bully Camp and  Lake
Washington cages were placed  85 and 70 meters, respectively, from  produced water
outfalls.   A  control was deployed at  an  unaffected location in Caillou Lake.
All oysters remained in place for 30 or 33 days.

      All  of  the  oysters exposed  to produced  water impacts  in  this study
component accumulated volatile and  semivolatile organic compounds.  The  control
site  oysters  accumulated no  volatile organics and only  trace  quantities of
pyrogenic  semivolatlies.   Total tissue volatiles  among treatment site  oysters
ranged  from 3 ppb  at the Lake Washington site to  372  ppb  in tissues from  the
Lirette  site. Of  all volatiles  measured,  toluene  was  detected in the greatest
quantity.   Petrogenic  polynuclear  aromatic hydrocarbons  were detected  ranging
from  41 ppb at  the Lirette site to 319 ppb at the Lake Washington site.

      Radium  226 analysis of  caged oyster tissues indicated  that oysters  growing
near  produced water effluents may accumulate  petrogenic radionuclides.  Tissue
samples from oysters placed near the Lirette effluent accumulated 3.1 ± 0.3 pCi/g
of radium 226.  Oysters placed at the  Caillou Lake  reference  and  Bully Camp  and
Lake  Washington study sites accumulated no measurable  radium activities.

      Several  studies   have  shown  that  oysters  can  release  accumulated
hydrocarbons  after  exposure in  contaminant-free  water (17,18).   Oysters  are
usually harvested directly, however, and are not depurated before being consumed.
This  must  be  considered when assessing  the  potential for human health risks
associated  with chemically contaminated shellfish.

      Studies by  Jeffree and Simpson  (20) related  to  uptake of radium 226 by
freshwater  bivalves  show  that  these  organisms  can readily accumulate these
pollutants  in a linear manner from  water containing radium  at  levels  which  were
much  less than those  measured in the four outfalls studied.   A complete in-depth
study would be needed to assess  the full radiological impact of produced waters
on oysters. Such a study is recommended since many of these  discharges currently
exist near  commercial oyster harvesting areas.
                                      37

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       Fig. 1. Cl Results of Interstitial Water
   From Sectioned Cores and Overlying Water
          Strata at all LRT Site Stations
    Fig. 2. Cl Results of Interstitial  Water
From Sectioned Cores and Overlying Water
        Strata at all DF  Site Stations
       PirU P»r Thouiind (a/I)
    P»rt« Per Thouiind (a/I)
0   AIM  ASSO A800  B20  C80  C280 CJ2S  R.f.

              Transect Sample Points
                                    •••pi* *>pthl (on) «r* *i
                                    •bow (•> or k*Hnr (-) th*
                                    tattrfM* (0).
 AIM  AZOO A300 8,200  ^200 BjSOO  C78  R»t.

           Transect Sample Points
                                      d*pth> (em) «r«
                                 •bov* (•) or k«low (-) III* *»d/w*t*r
                                 Inttrlu* (0).
      Fig. 3. Cl Results of Interstitial Water
   From Sectioned Cores and Overlying Water
           Strata at all BC Site Stations
       Part* P«r Thouiind (a/I)
         B60  BWO  CSO   CWO  C,30O C,300  R«f.

              Transect  Sample Points
                                    S*«pl« tf*«t(i> (on) •'•
                                    tbm* (•> or b*low <-) th*
                                    InuiKo* 10).
   Fig. 4. Cl Results of Interstitial Water
From Sectioned Cores and Overlying Water
        Strata at all  LW Site Stations
                                                                                 Pirtt P«r Thoutind (a/I)
                                                                             A60
                                                                                   -1	'—1	'—t
                                                                                   B80   B15O  8380
                      C100  0,280 Cj300  R.f.

           Transect Sample Points
                                 Sinpl* tfapth* (om) •
                                 •bov* (•) or b«k>w (-) th* ••d/mur
                                 InUrlao* (0).

-------
                              Figure 5
             Llrette Sediment Radium-226 Activities
     Radlum-226 Activity In plco-CI/grsm
600 1
                                13-6   5.24   3.24   7.89   9.73
             B20   C50   A100   A260  C260  C326  C600   R
                        Transect Sample Points
                I mean plco-Ci/gram
! »/- 2 sigma error
                                           from origin.
                                                   ts srrsngod by dlstsnoo
                                                                 Figure 6
                                                         Delta Farms Sediment
                                                         Radium-226 Activities
                                                                              Rtdlum-228 Activity In plco-CI/gr»m
                                               C75   A100   A200  Bi200  B2200  Bz300  A300
                                                           Transect Sample Points
I mean pico-Ci/gram
i •»/- 2 aigma error
                                                                                                                       Banplo points srrsnood by dlstsno*
                                                                                                                       rrom origin.
                              Figure 7
                      Bully Camp Sediment
                      Radium-226 Activities
     Ridlum-228 Activity In plce-CI/gram
260-1
200
             A60   B50   C60   B100  C100  Ci300  Ca300   R
                        Transect Sample Points
                I mean plco-C!/gram
I »/- 2 sigma error
                                           Simplo point* arranged by dlstsnco
                                           ttcm origin.
                                                                  Figure  8
                                                        Lake Washington Sediment
                                                          Radium-226 Activities
                                                                                R«dium-228 Activity In plco-CI/gr«m
                                                                           350
                                                                                                                  0.02    4.12   5.87   3.91
                                                 A60   B50  C100  B150  Ci250  Cg300  B350    R
                                                            Transect Sample Points
 I mean pico-Ci/gram
 i»/- 2 sigma error
                                                                               Sainplo points srrsngsd by dlstwioo
                                                                               Iron origin.

-------
                    Total PAH Homologs  (ppb)
                100000      200000      300000
400000
LW-C^SO
LW-C2300
 LW-B350
   LRT-0
 LRT-B20
LRT-A100
 LRT-C50
LRT-C325
LRT-C250
LRT-A250
LRT-A500
      Figure 9.  Total  PAH  homologs  detected in  sediments
                 in  the  vicinity  of  four  produced  water
                 discharges.
                             40

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References

 1.    J.S. Manor, J.E.  Bailey,  M.C.  Rogers, L.R. Milner,  Regional  Variations
       in Physical and Chemical Properties of South Louisiana Oil Field  Brines,
       Trans, of Gulf Coast Association of Geological Societies.  36,  1986,  143-
       149.

 2.    G.K. Reid, Ecology of Inland Haters and Estuaries.  Van Nostrand Reinhold
       Company,  New  York,  N.Y.,  1961,  202-204.

 3.    D.F. Boesch, N.N. Rabalais, (eds.), Produced Waters in Sensitive  Coastal
       Habitats: An  Analysis  of  Impacts,  Central Coastal Gulf of Mexico,  U.S.
       Dept. of  the  Interior,  Minerals Management Service, Gulf of Mexico DCS
       Regional  Office,  New Orleans,  Louisiana,  1989,  157 pp.

 4.    D.F.  Boesch,  N.N.  Rabalais,  (eds.).  Environmental  Impact of Produced
       Kater Discharges  in Coastal Louisiana, Report to the  Louisiana Division
       of  the  Mid-Continent Oil  and Gas  Association,  Louisiana Universities
       Marine Consortium,  Chauvin, Louisiana, 1989,  287 pp.

 5.    D.F.  Reid,  Radium in Formation Waters:  How Much and Is  It of Concern?
       Naval Ocean Research and Development Activity, College of Oceanography,
       Oregon State  University,  1984,  202-204.

 6.    Louisiana Administrative   Code,   State   of Louisiana  Stream   Control
       Commission, Title 33, Part  IX,  Chapter 19,  1988.

 7.    D.E.  Harper,  Jr.,  A Review and  Synthesis of Unpublished  and  Obscure
       Published Literature Concerning Produced Water Fate and Effects, Prepared
       for Offshore Operators  Committee, Texas A&M Marine Laboratory. Galveston,
       Texas, 1986.

 8.    H.W. Armstrong, K. Fucik,  J.W. Anderson,  J.M. Neff, Effects of Oil Field
       Brine Effluent on Sediments and Benthic Organisms in Trinity Bay, Texas,
       Marine Environmental Research,  1979,  55-69.

 9.    B.H.  Baird, K.M.  St. Pe,  D.N.  Chisholm,  Internal  memorandum describing
       results of a produced water investigation in .afourche Parish, Louisiana
       Department of Environmental Quality,  Baton Rouge,  Louisiana,  1987.

 10.    Louisiana Department   of   Environmental   Quality,   Naturally-Occurring
       Radioactive  Materials  Associated  with  the Oil  and  Gas Industry, An
       Informational Brief, Office of  Air Quality  and  Nuclear Energy, Baton
       Rouge, La., 1989.

 11.    T.F.  Rraemer, D.F.  Reid,  The Occurrence  and  Behavior  of  Radium in
       Formation Waters of the  U.S. Gulf Coast Region, Isotope Geoscience, 1984,
       Volume 2.
                                      41

-------
12.     M.A. Hanan, Geochemistry and Mobility in Sediments of Radium from  Oil-
       Field Brines:   Grand  Bay,  Plaquemines Parish, Louisiana, University of
       New Orleans, New Orleans, Louisiana,  1981, 89 pp.

13.     E.R. Landa, D.F. Reid, Sorption of Radium-226 from Oil-Production Brine
       by Sediments and Soils, Environmental Geology, 1983,  26  pp.

14.     P.D. Boehm, J.W. Farrington, Aspects of Polycyclic Aromatic Hydrocarbon
       Geochemistry of  Recent  Sediments  in  the  Georges  Bank Region, Environ.
       Sci. Technol. 1984, Vol.18, 804-845.

15.     C.B. Daniels,  J.C. Means,  Assessment of the Genotoxicity  of Produced
       Water Discharges Associated  with Oil  and Gas Production Using  a  Fish
       Embryo and Lanval Test, Marine Environmental Research, Elsevier Science
       Publishers Ltd., England, 1989, 303-307.

16.     M.C. Mix,  Polynuclear Aromatic  Hydrocarbons  and  Cellular Proliferative
       Disorders  in Bivalve  Mollusks  from Oregon Estuaries, Project Summary,
       U.S. Environmental Protection Agency, Gulf Breeze, Florida, 1982, 1-3.

17.     H.J. Somerville, D.  Bennett,  J.N.  Davenport,  M.S.  Holt, A.  Lynes,  A.
       Mahieu, B. McCourt, J.G. Parker,  R.R. Stephenson, R.J.  Watkinson,  T.G.
       Wilkinson,  Environmental  Effect of Produced  Hater from North  Sea  Oil
       Operations, Marine Pollution Bulletin, 1987, Vol. 18, 549-558.

18.     J.M. Neff,  Bioaccumulation  and Biomagnification  of Chemicals  from  Oil
       Nell Drilling and  Production Wastes in  Marine Food  Webs:  A Review for
       the American Petroleum Institute,  Washington, D.C., 1988, 67 pp.

19.     D.F. Boesch, N.N.  Rabalais,  C.S.  Milan,  C.B.  Henry,  J.C.  Means,  R.P.
       Gambrell, E.B.  Overton,  Chapter 3, Field Assessments,  In D.F. Boesch and
       N.N. Rabalais (eds.),  Produced  Waters  in  Sensitive Coastal Habitats:  An
       Analysis of Impacts,  Central Coastal Gulf of Mexico, U.S. Department of
       the Interior, Minerals Management  Service, New Orleans, Louisiana, 1989,
       31-115.

20.     R.A. Jeffree, R. D. Simpson, An Experimental Study of the  Uptake and Loss
       of  Ra-226 by the  Tissue  of the  Tropical Freshwater Mussel  Velesunio
       angasi   (Sowerby)  Under  Varying  Ca  and  Mg   Water  Concentrations,
       Hydrobiologia,  1986, 59-80.
                                      42

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           AN  EARLY  WARNING SYSTEfl TO PREVENT USDU CONTAMINATION

               ENVIRONHENTAL UNDERGROUND INJECTION EQUIPRENT
                                    FOR
            HAZARDOUS AND NON-HAZARDOUS LIQUID WASTE DISPOSAL

          INJECTION  WELL AND HONITORING WELL IN THE SAPIE BOREHOLE
                              (PHYSICAL  PROOF)
                           U.U. POIHBOEUF, P.E.


                                 ABSTRACT

        COHBINATION INJECTION/MONITORING WELL  IN  A  SINGLE  BOREHOLE

 This  paper  deals  with  completion  of an injection well for any class well
 1 i  2,  3  or  5.   It deals  with the  direct monitoring of that injection well
 from  its  well  bore.   This type completion  gives positive proof of no con-
 tamination  of  ground  water from the injection  well.  At any time that
 there  is  potential danger of ground water  contamination, the monitoring
 system in the  injection  well shows this potential danger.  It shows the
 danger of contamination  in sufficient time so  that injection can be
'stopped  and remedial  well actions  taken so that there will be no contam-
 ination.  This method  of completion gives  absolute physical evidence of
 any  possible injection failure long before the injection well could con-
 taminate  ground water.  The  completion is  so designed that samples of
 fluid  can be taken from  one  or more formations above the formation being
 injected  into.  As long  as these  samples show  no contamination, it is
 impossible  for the injection well  to have  a  failure.  This particular
 type  of  completion is  especially  acceptable  to Class I injection wells.
 Considerable savings  can be  realized from  this type monitoring system in
 deep  wells.
                                    43

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  COHPLETING OBSERVATION WELLS AND INJECTION WELLS IN THE SANE UELLBORE

It is possible today to complete an injection well in such a manner  that
the operator will have proof positive at all times that his injection
well is not contaminating fresh water in the vicinity of that well.  At
the present time injection well integrity is proven by running a  series
of costly logs initially and the periodic workover of wells, by pulling
the injection tubing and again running the costly logs.  The process
here, as noted, eliminates the need for costly workovers.  This procedure
allows the operator to continually operate the well without interruption,
and at all times knowing that ground water is not being contaminated
from it.  The need for the costly workover is eliminated, therefore the
operator can continually operate these wells for 20 years or more,
depending upon the type of completion he selects from the variation
herein presented.

There is one basic method shown here, with various ramifications of that
method.  The basic method is to complete the well as shown in the "Com-
posite Completion Sketch", Figure 24.  The package or the casing design
is strictly contingent upon the depth to which the well is drilled and
the number of strings of 2 3/6" or smaller tubing to be used for moni-
toring.  The size of the injection string of tubing and the various
casing strings can be varied.  The design depends upon the volume of
fluid being injected and the depth of the well, but basically is contin-
gent upon cost and the physical location of the well to be drilled.

The geology used here is very simple.  Very complex geology is encount-
ered in some cases.  USDW zones sometimes are over 3DDD ft. deep.  The
simple geology is used to more easily explain the completion.  Refer to
Figure No. 1.  At the surface is a permeable zone containing USDU. This
is underlain by an impermeable zone which in turn is underlain by a
permeable zone.  This zone contains salt or fresh water, but contains
some fluid.  This in turn is underlain by a permeable zone and this in
turn is underlain by a permeable zone into which fluid is injected.
Zone one is the fresh water zone.  Zone two is the first impermeable
zone.  Zone three is the monitoring zone, and the second permeable zone,
Zone four, is an impermeable zone.  Zone five is a permeable zone into
which the injection will be made.  Zone six is an impermeable zone below
the zone to be injected into.

The well is started by driving or otherwise setting a string of conduc-
tor pipe, Figure 2.  It should be set deep enough in the ground to con-
tain unconsolidated sands.  Drilling is then accomplished through the
conductor pipe to a point into zone #2, Figure 3, at least 100 feet.   The
surface casing is set at this depth and cemented to the surface.  This
cases off the fresh water zone in order to protect it.  The will is then
drilled through zone #3 and seated in zone #4.  Monitoring casing is
cemented to the surface.  The will is then drilled to total depth through
the monitoring casing, Figure 4.
                                       44

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A retrievable bridge plug is set in the monitoring  casing  below  the  perm-
eable zone #3.  A section of monitoring casing is milled out  to  expose
the face of the permeable formation, Figure 5.  This milling  process  is
accomplished in a manner such that the face of the  formation  is  cleaned
off as much as possible in order that virgin formation  fluid  can  be
obtained therefrom.  The virgin formation fluid is  pumped  from this  form-
ation by lowering tubing and a pump into the monitoring casing.   The
fluid is pumped out and an on site chemical analysis is made  of  this  for-
mation fluid.  These are merely basic chemical analyses to determine  the
chemistry of the virgin fluid.  With the virgin fluid in the  wellbore,
the retrievable bridge plug is removed.

The completion string of injection casing is then run in the  hold, it mill
consist of a cement guide shoe, injection casing up to  a point below  the
exposed formation, a cement retaining element, it is a mistake to call
these packers, when they are actually cement retainers.  The  cement
retainer or packer is designed to have three connections, top and bottom
for 2 3/8" tubing and injection casing, Figure 15.  Both of the 2 3/B"
tubing sections are installed, one is perforated and one non-perforated
tubing.  Injection casing is also installed.  Approximately 60 feet above
the top of the lower packer a second packer is installed.  Monitjaring
tubing and injection casing will be run to the surface.  The  other 2 3/8"
tubing opening will be left as is, Figure 6.  This  is the channel for
cement to follow when cementing in the injection casing.

When the injection casing has been landed, setting  of the two packers
will be initiated.  The selected packer here is hydraulically set, the
packer can also be cup type or other.  The packer is set by pressuring
the injection casing, therefore, hydraulically extruding the  sealing
elements of the packer against the monitoring casing, Figures 14 and 15.

This straddle type arrangement isolates the monitoring  formation from the
surface and from the injection zone, Figure 13.

At this point, normal cementing procedures can be used  in the injection
casing and the 2 3/B" monitoring string.  Cement is pumped through the
injection casing inside down through the guide shoe, up around the out-
side of the injection casing until it reaches the bottom of the  lower
packer.  At this point it follows a path up through the 2 3/B" tubing
string to the top of the upper packer, then it follows  a path upward
around the monitoring tubing string and the injection casing  string to
the surface.  Centralizers are used to ensure that  there is coverage of
the monitoring tubing and injection casing, Figures 7, 13, 14 and 15.

At this point the well is perforated in the injection zone.   Another
variation for this type injection well is an open hole completion.

All drilling should be accomplished with fresh water in order that none
of the permeable formations will be contaminated with drilling fluid.
There is no need for expensive drilling fluid, since we do not antici-
pate any pressure problems in the well.
                                     45

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The injection tubing string with a packer on the bottom is now run in the
hold.  The packer is set and the tubing is landed in the wellhead assembly
Figures 17 and 19.  The type tubing to be used and the type packer to be
used will be based upon the type fluid to be injected.  If one uses a
corrosive fluid for injection, he should consider using fiberglass tubing
and an internal coated packer, Figure 8.

The wellhead assembly is now in place.  It is necessary to button up the
well, we do this by tightening down on the stud bolts through the rubber-
ized packing elements.  Tightening these bolts will seal off the casing
tubing annulus and seal off the injection casing.  There can be variations
in this type wellhead assembly equipment.  These variations depend on the
type completion, Figure 9.  The casing tubing annulus is filled with fluid
to enable monitoring for leaks, Figure 10.

There is an opening to the tubing casing annulus.  This is connected to a
monitoring pot, Figure 18.  The monitoring pot is a vessel constructed
such that a fluid level in the pot will give a positive indication of a
tubing/casing annulus leak.  Pressure is applied (50 to 100 psi) on the
monitoring pot.  The level of fluid in the monitoring pot can be observed
in the sight-glass on the side of the pot.  As long as the fluid is in
the monitoring pot, there is no leakage in the injection casing or the
injection tubing annulus, Figure 10.

Injection through the tubing can now safely be done, Figure 11.

There are many variations to this type completion.  These are contingent
upon the depths and fluids being injected.  One variation that should be
strongly considered is that by which the injection casing string and moni-
toring string are not cemented to the surface, Figure 23.  They are cem-
ented approximately to 100 feet above the upper-most packer.  This will
leave a second annulus which can be monitored.  This monitoring pot can be
connected to this annulus and it monitored in the same manner as the
tubing casing annulus.  As long as there is no pressure change or loss of
fluid from the injection/monitoring annulus, there cannot be any loss of
fluid through the injection casing wall.

It is possible also to place two or even three or even possibly four
monitoring strings of tubing in the annulus between the injection casing
and the monitoring casing.  Each monitored formation would need be iso-
lated with a straddle packer arrangement as is shown in the simple com-
pletion, Figures 16, 20 and 23.

The costs and savings of this type completion is of importance.  Attached
is a cost of a simple type completion.  In the simple case, the difference
in cost will be that of an additional string of casing, two packers,
milling, three days rig time, 2,000 feet of 2 3/8" tubing, tool rental,
logs and service.
                                     46

-------
At the end of five years, the cost of a "Present Day" completion method
is $226,000.  The cost of the Poimboeuf method is $203,000.  After ten
years, the cost of th "Present Day Method" is $276,000; in fifteen years,
$326,000.  The Poimboeuf method is a one time cost, Figure 25.

There is a risk of even a higher cost in a "Present Day Method."  The
costs above are based on trouble free well workover.  Well workov/er is
normally not trouble free.  When one is working underground many unfore-
seen minor details can become major costs.  A $50,000 workover can
easily become a $100,000 workover, one in twenty workov/ers go wrong and
cost more.  One in forty to fifty wells are lost due to unforeseen prob-
lems during workover.  This added risk is not necessary in the Poimboeuf
method.

The completion has been discussed with various state regulatory bodies
and with individuals in the Federal EPA.  The Federal EPA have not
turned it down nor have they actually accepted it.  Three state regu-
latory bodies were contacted and copies of the procedure given them.  In
all three cases, these regulatory bodies stated that they felt the pro-
cedure was good and that they would approve this type procedure for an
injection well.  On extremely shallow injection wells, it is probably
less expensive to drill a separate monitoring well near the injection
well.  There is no assurance that the monitoring well will not have
vertical fluid communication upward, around the outside of the moni-
toring string casing.  Improper grouting, and in many cases no grouting,
results  in this type external communication.  This possiblity is elim-
inated in the case being presented here.

There are many variations of completion equipment.  Any type cement
retainer (packer) which will satisfactorily straddle the monitored
formation will be acceptable for cementing.  Probably the lease expen-
sive is  a short section of injection casing and two short sections of
tubing and rubber cups imbedded in plastic or fiberglass.  The purpose
of this  packer is merely to hold cement in position until it hardens.
Fiberglass casing and tubing is available for this type completion.
Fiberglass packers can easily be built.  These give a better seal
against  leaks and eliminate corrosion.

Should one desire to monitor more than one formation in the borehold,
it can be done by adding straddle packers and monitoring tubing for each
monitored formation.

This method gives physical proof of no contamination of USDW.  One can-
not argue with physical proof.  All "Present Day" methods are theoreti-
cal .
                                    47

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                                   COMPOS IT
         INJECTION WELL  WITH MONITORING SYSTEM  INSTALLED
                   SAMPLE  - SIZES VARY -  SCHEMATIC
                        (POIMBOEUF  -  BUCK METHOD)
                                FIGURE NO.  1
                    VALVE
                                          INJECTION TUBING AND
                                          INJECTION FLUID
       MONITOR TUBING
FRESH WATER
FORMATIONS
VARIOUS
FDRflAirONS
MOSTLY
IMPERMEABLE

HILLED OUT
PIPE SECTION

PERFORATED
MONITORING
TUBING
ANNLLU5

CASING

CEMENT
INJECTED
FLUID

WELL
TOTAL
DEPTH
SURFACE
CASING
UPPER
MONITORING
PACKER
                          T-I-r-K ;L". • .7. • .7. •.'.'. •.' l-SSH
                             ŁŁ:& •*.*•: •"."•: •"•: •" '• fe^
     ANNULU5
     MONITORING
      POT
PERMEABLE
FORMATION
CONTAINING
FLUID
LOWER
MONITORING
PACKER

IMPERMEABLE
FORMATION
INJECTION
PACKER

PERMEABLE
INJECTION
FORMATION

PERFORATIONS

IMPERMEABLE
FORMATION

-------
         GEOLOGY  FOR  INJECTION
             AND MONITORING
                 FIGURE  NO.   2
                                                     FRESH
                                                     WATER
                                                     FORMATIONS
                                                     IMPERMEABLE
                                                     FORMATION
                                                     PERMEABLE
                                                     FORMATION
                                                     CONTAINING
                                                     FLUID
                                                     FORMATION
                                                     TO MONITOR
                                               7
                                                  /  IFPERfCABLE
                                              	 FORBATION
::::::::::::::::::::::::::::::::::.  INJECTION
:^:^::^:o^:^:^^^::a:^^.
.V.\V.V." A..".".".".*.".". V.V.V/.V.V.".*.".".".".'.".*'.'.'.'.'.'.'*.'.'.'.'.''.'.SV.'.'.
                                                  — DKWtABLE
                                                	« FORWTION
                          49

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                      STEP NO.  1
            INJECTION/MONITORING WELL
                     FIGURE NO.  3
DRIVE
PIPE
DRILL OUT AND SET

SURFACE CASING

/CEMENT TO SURFACE
            =•>
                        S
                           Ł:
                           2 =
                           e-
                         ;-'-'r.vb»>^-'o-'-/?-vav-^»6''
                            50

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                 STEP  NO. 2
           MONITORING CASING  THRU
            MONITORING  FORMATION
                 FIGURE  NO.  4
DRILL OUT AND
SET MONITORING
CASING ^---_

^==S#jJ




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X .t
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>


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7^ '
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j? •• = GROUND UATI
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• r
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;;.•.•.•.•.•.•.•.•.•.•.-.•.• MONITORING
•••.•.•.•.•.•.•.-.•.•.•.•.-. FORMATION
P 	

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/
X
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X
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.Y.vr/fjY.vr.Yo-.. .•.•o'-'-'-'/.'Q'.'.'.. .YO'-".YB$Y.Y.Y.QY. . .•.'O'-'-'-'
                        51

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               STEP NO. 3
  DRILL  OUT  FOR  INJECTION  CASING
     DRILL THRU  INJECTION ZONE
               FIGURE NO.  5
       •V
       '.•*?
:*.::.• :.v7: •


f.'.'.'.'.'.'A ..'.'.
d
5
                                ire
•^o-;.;-^-;.^;.;.;.;  INJECTION
V.Y!Y!-AY!Y!Y!  ForanATiON
                      52

-------
         STEP NO. 4
EXPOSE MONITORING FORMATION
BY MILLING OUT SECTION OF 16
MONITORING CASING AND CEMENT
         FIGURE NO. 6


	 r>f




s •'

X .t

~t
X "••
X
X .•
X
x'2






	 A

.-

	 7- 	 -fl
X" l^
X
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>
/
/
/
X
X
X
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->Q;-;S;-v&;ivX<




















rau. our

SECTION

1

BRIDGE PLUG j

1
^










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»
*




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to H
*™ y
>
X
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' y
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k'
> X
.'
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•V 	 . / 	 *
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fe
X

X
X
X
X

X
/
X
/
'

. .'.'G-'-'- • •'•(-^'•'.
            53

-------
                 STEP NO.  5
  RUN  INJECTION CASING STRING CONSISTING
  OF CASING,  STRADDLE PACKERS SYSTEM,
  MONITORING  TUBING (PERFORATED). CEMENT BYPASS
                FIGURE NO. 7
  /
        ^Z-S.
               8
•::~::^-::::^):.
                  J!
                     54

-------
                STEP NO.  6
 RUN INJECTION CASING STRING CONSISTING
       OF CASING, STRADDLE PACKERS
SYSTEM, MONITORING TUBING, CEMENT BY PASS,
            CEMENT TO SURFACE
               FIGURE  NO.  8
                      55

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            STEP NO. 7
    CONNECT MONITORING TUBING
RUN INJECTION TUBING WITH PACKER
           FIGURE NO. 9

	 13



X •_!

ft
si
;;
jr
*<
•i
/ •*•;
X J
X j
X f
J
x y
X
X
fe
w
i(
p
Jj
k*.
?
-------
                          STEP NO.  8
                      INSTALL WELLHEAD
                        FIGURE NO.  10
               VALUE
FORBATION
MONITORED
FLUID
VALUE
  MELQCAD
              ANNULUS
              nONITORING
                                57

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           STEP NO. 9
INSTALL ANNULUS MONITORING  FLUID
   AND ANNULUS MONITORING POT
          FIGURE  NO.  11
                          HDNITORING
                                          nONITORING
                                          FLUID
                  58

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  STEP  NO.  10
BEGIN  INJECTION
 FIGURE NO.  12
                 INJECTION FLUID

-------
                    EXPANDED PACKER ARRANGEMENT
                            FIGURE NO.   13
PORT FOR
INFLATING
PACKER
PERFORATED
TUBING
CUT OUT
CASING
SECTION
PACKER
BODY
                                                           PACKER
                                                           SEAL
                                                     CEFENTING
                                                     TUBING
                                                     INJECTION
                                                     TUBING
                                60

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nDNITORING TUBING
                    CUP TYPE  PACKERS ARRANGEMENT
                              FIGURE  NO.  14
INJECTION CASING

COOT

nDNITORING
CASING
                                                           UPPER PACKER
                                                           CUP TYPE
                                                           CUPS
                                                           nil I FT) OUT
                                                           CASING SECTION
                                                           20 FEET + -


                                                           PACKERS
                                                           40 FEET + -
                                                           APART
                                                           LONER PACKER
                                                            CEffiWT TUBING
                                      61

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                FIGURE NO.  15
                           PRESSURE GAUGE 50PSIG
1
N 1 TROGEN
• . • ««»«»«* /,* •",%*• * *

,*« , t , > , , , * ,»« ..,»»«
«•«.•»*. JU Kb •«••• * *
'*«"• /»»"!• "'/'•.'•' v «



•••^^H


if * *



_J


* * 1


                                      SIGHT GLASS
                                      5  TO 10
                                      GALLON SIZE
TO
ANNULUS
OBSERVATION
PORT
          ANNULUS MONITORING POT
                      62

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         CROSS SECTION THRU GROUND  LEVEL CASING  ARRANGEMENT  - CASE  I
                                   FIGURE  NO.  16
nONITORING
TUBING
                                                                      CONDUCTOR
                                                                      CASING
                                                                           SURFACE
                                                                           CASING
                                                                               nONITORING
                                                                               CASING
                                                                                 INJECTION
                                                                                 CASING
                                                                              CASING/TUBING
                                                                              ANNULUS
        CEPENT
                                                                          INJECTION
                                                                          TUBING
                                                                                               s

-------
            CROSS SECTION THRU GROUND LEVEL  CASING ARRANGEMENT
                             MULTIPLE ZONE MONITORING
                                  FIGURE  NO.  17
     USOU ZONE I
     MONITORING
     TUBING
                                                                      CONDUCTOR CASING
SURFACE CASING
                                                                               nONITORING
                                                                               CASING
USOU
ZONE II
MONITORING
TUBING
 SALT HATER
 ZONE
 MONITORING
 TUBING
        CEMENT
                                                                                 INJECTION
                                                                                 CASING
   CASING/TUBING
   ANMULUS
                                                                          INJECTION TUBING
                   s

-------
                              CROSS SECTION THRU PACKER
                                    EXAMPLE  SHOWN
   PACKER RUBBER
   DEFLATED
PACKER
INFLATING
VALUE
                                                                                     MONITORING
                                                                                     TUBING
                                                                                     CONNECTION
TUBING
CONNECTION
FOR
CEMENTING
           CASING
                                        FIGURE NO.  18

-------
                         PACKER CROSS SECTION  FOR  MONITORING
                                 THREE SEPARATE ZONES
          PACKER
PACKER
INFLATION
VALUE
                                                                                      CEMENTING
                                                                                      TUBING
                                                                                      ZONE III
                                                                                      MONITORING
                                                                                      TUBING
                                                                                     ZONE II
                                                                                     MONITORING
                                                                                     TUBING
                                                                                     ZONE I
                                                                                     MONITORING
                                                                                     TUBING
        MONITORING
        CASING
                                      FIGURE NO.  19

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                                 WELLHEAD  EQUIPMENT EXPANDED
                           SCHEMATIC  - VERTICAL  SECTION -  CASE
                                         FIGURE  NO.  20
MONITORING
TUBING
TUBING
HANGER
      INJECTION TUBING

      TUBING HANGER STUD BOLT
                                                                                CASING
                                                                                HANGER
                                                                                STUD BOLT

                                                                                ANMJLUS
                                                                                OBSERVATION
                                                                                PORT
                                                                                CASING HANGER
                                                                            Jjjj-—•  SET SCREW
                                                                                         CASING
                                                                                         HANGER
                                                                                      — SUBP
     HWITORING CASING
     CERENT
INJECTION CASING

-------
                           STEP NO.
                 INSTALL WELLHEAD EQUIPMENT
                         FIGURE NO.  21
               VALUE
                                        VALVE
nONIIUNDC
FORPWTION
FLUID
ANNULUS PDNTTDRING
OPENING
                                68

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                             PRESENT  DAY COMPLETION
                               CLASS  I  OR  I I  WELL
                                  FIGURE NO. 22
                                     INJECTATE
fiDNITQRING
POT
                  INJECTION
                  TUBING
COMXJCTOR
CASING


SURFACE
CASING

ANNULAR
FLUID


INTERMEDIATE
CASING
CEMENT
INFECTION
CASING
PACKER
PERFORATIONS
           DTOWEABLE
           FORHATION
                                                                     PERPEABLE
                                                                     FORfWTION
           irVERTCABLE
           FORMATION
                                                                     PERPEABLE
                                                                     FORMATION
                                        69

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                                  COMPOS IT
         INJECTION WELL  WITH  MONITORING SYSTEM  INSTALLED
                   SAMPLE  -  SIZES VARY -  SCHEMATIC
                       (POIMBOEUF -  BUCK METHOD)
                              FIGURE NO.  23
                            IIFI i \r nn
                   VALUE
                                         INJECTION TUBING AND
                                         INJECTION FLUID
       PDNITOR TUBING
FRESH WATER
FORPIATIONS
VARIOUS
FORPIATIDNS
PDSTLY
IPPERPEABLE

PULLED OUT
PIPE SECTION

PERFORATED
PDNITOR
TUBING
ANNULUS

CASING


CEPENT
INJECTED
FLUID

WELL
TOTAL
DEPTH
SURFACE
CASING
UPPER
PDNITORING
PACKER
                                                                        ANNULUS
                                                                        PDNITORING
                                                                         POT
PERPEABLE
FORPIATION
CONTAINING
FLUID
LOWER
PDNITORING
PACKER

IPPERPEABLE
FORPIATION
INJECTION
PACKER

PERMEABLE
INJECTION
FORPIATION

PERFORATIONS

IPPERPEABLE
FORPIATION
                                        70

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INJECTION WELL WITH MONITORING SYSTEM
     FOR MONITORING TWO ANNUL I
          FIGURE NO. 24
                  71

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                                  COMPOS IT
         INJECTION WELL  WITH MONITORING SYSTEM  INSTALLED
                   SAMPLE  -  SIZES VARY -  SCHEMATIC
                       (POIMBOEUF -  BUCK METHOD)
                              FIGURE NO.  25
                            WELLHEAD
                   VALVE
INJECTION TUBING AND
INJECTION FLUID
       nONITOR TUBING
FRESH WATER
FORMATIONS
VARIOUS
FORMATIONS
MOSTLY
IMPERMEABLE

MILLED OUT
PIPE SECTION

PERFORATED
MONITORING
TUBING
ANNULUS

CASING

CERENT
INJECTED
FLUID

WELL
TOTAL
DEPTH
                          SURFACE
                          CASING
                          UPPER
                          PDNITORING
                          PACKER
                                                                        ANNULUS
                                                                        nONITORING
                                                                         POT
                          PERMEABLE
                          FORMATION
                          CONTAINING
                          FLUID
                          LOWER
                          MONITORING
                          PACKER

                          IMPERMEABLE
                          FORMATION
                          INJECTION
                          PACKER

                          PERMEABLE
                          INJECTION
                          FORMATION

                          PERFORATIONS

                          IMPERMEABLE
                          FORMATION —
                                        72

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            APPLICATION  OF THE CONTINUOUS ANNULAR
          MONITORING CONCEPT TO PREVENT GROUNDWATER
          CONTAMINATION BY CLASS II INJECTION WELLS
By Len G. Janson, Jr*.
Sr. Production Engineer
Phillips Petroleum Company
Shidler, Oklahoma
Everett M. Wilson*
Consulting Engineer
Du Pont Environmental Remediation Services
Houston, Texas

* SPE Member

Copyright 1990, Society of Petroleum Engineers Inc.

This  paper was prepared for presentation at the 65th Annual
Technical  Conference  and  Exhibition  of  the  Society  of
Petroleum  Engineers  held  In  New  Orleans,  LA, September
23-26, 1990.

This  paper  was selected for presentation by an SPE Program
Committee  following  review  of information contained in an
abstract  submitted  by  the  author(s).    Contents  of the
paper,  as  presented,  have been reviewed by the Society of
Petroleum  Engineers  and  are  subject to correction by the
author(s).      The   material,   as   presented,  does  not
necessarily   reflect   any   position  of  the  Society  of
Petroleum  Engineers,  its officers, or its members.  Papers
presented  at SPE meetings are subject to publication review
by   Editorial   Committees  of  the  Society  of  Petroleum
Engineers.   Permission to copy is restricted to an abstract
of  not  more  than  300  words.    Illustrations may not be
copied.      The   abstract   should   contain   conspicuous
acknowledgement   of   where   and  by  whom  the  paper  is
presented.    Write  publications  Manager,  SPE,  P. 0. Box
833836, Richardson, TX 75083-3836.  Telex, 730989 SPEDAL.

ABSTRACT

This  paper  will  present  a  continuous annular monitoring
concept  that  allows  Class  II  injection  wells that have
insignificant  leaks in the casing to demonstrate mechanical
integrity.    Inherent  in this concept  is the premise that
an  insignificant  leak  in  the casing is any leakthat will
not  endanger  a USDW and that this test will therefore meet
the  regulatory requirements under 40 CFR 146.8  (a) and  (b).
A case history will be presented to demonstrate the


                             73

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viability  of  this  concept  as  an  alternative mechanical
integrity  test.    This  concept  has  been  approved  as an
alternate   mechanical   integrity   test   by  the  Reginal
Administrator  of  USEPA  Region  6  for  use  in  the  Osage
Mineral Reserve under 40 CFR 147.2912 (a) (1)(v).

INTRODUCTION

There  are  a significant number of Class II wells that have
been  in  existence for many decades.  The casing leaks that
have  developed  in  these  wells  have  proven expensive to
correct  in  order  to meet the strict interpretation of  the
applicable  UIC  regulations on the federal and state level.
Accordingly,  in  order  to  allow the continued use of this
type  of well without remedial action being performed on  the
casing  until such time as the USDW is endangered, a concept
that  incorporates  a pressure test on the tubing and packer
along  with  continuous  annular  monitoring  was developed.
This  concept  has  been successfully implemented on a  field
operated  by  Phillips  Petroleum  Company  in Osage County,
Oklahoma under agreement with USEPA Region 6.

REGULATORY OVERVIEW

The  Environmental  Protection  Agency  Regulations covering
the  underground injection control program are defined  in 40
CFR  Part 146.  Specifically, the regulations concerning  the
demonstration  of  mechanical  integrity are put forth  in 40
CFR  146.8  and  in  the  applicable  sections of 40 CFR  147
which  covers  the  primacy  states and Indian Lands and  has
basically the same requirements as those outlined in 146.8.

40   CFR  146.8  (a)  states  that  an  injection  well  has
mechanical  integrity if:  "(l) There is no significant leak
in  the  casing,  tubing  or  packer;  and  (2)  There  is no
significant  fluid  movement  into  an underground source of
drinking  water  through  vertical  channels adjacent to  the
injection wellbore."

All  existing  wells  undergo  a  technical  review  to show
compliance  with  40  CFR 146.8 (a)  (2) and this part of  the
regulation will not be addressed further.

Compliance  with  146.8  (a)   (1)  can be demonstrated  under
146.8  (b)  which  states that "one of the following methods
must  be  used  to evaluate the absence of significant  leaks
under  paragraph (a)(1) of this section:  (1)  Monitoring of
annulus  pressure:  or (2) Pressure test with liquid or gas:
or (3) Records of monitoring showing the pressure
                              74

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and  injection  flow  rate  for  the  following  Class  II
enhanced  recovery  wells:"  etc.  Subparagraph  (3) is not
considered  relevant  to the continuous annular monitoring
concept and will not be addressed further.

THE CONCEPT OF CONTINUOUS ANNULAR MONITORING

The  continuous  annular  monitoring concept that is being
proposed  as  an  alternate mechanical integrity test is a
combination  of  pressure test on the tubing and packer as
well   as   a   monitoring  system  on  the  tubing-casing
annulus.    This  concept  will  ensure that a USDW is not
endangered  when  a  well  is  allowed  to operate without
demonstrating that the casing will hold pressure.

To  qualify  for  the  continuous annular monitoring test,
the well must:

     1. Demonstrate compliance with 40 CFR 146.8 (a)(2).

     2.  Have  a  fluid  level    greater   that  100 feet
        (30.48m) below the base of the lowermost USDW.

     3.  Demonstrate  mechanical integrity of  the  tubing
        and  packer  using  the  "ADA  Pressure Test" or a
        radioactive  tracer  survey  if  applicable  under
        state regulations.

The test procedures would be:

     1.  Install  a  continuous  monitoring  system  which
        would  immediately  detect  and  warn  of  a fluid
        level  in  the  casing  or  tubing-casing  annulus
        within  100  feet  of  the  base  of the lowermost
        USDW.

     2.  If  the  fluid  level  rises to  within  100 feet
        (30.48m)  of  the  lowermost  USDW.   The operator
        shall   report   this  situation  to  the  EPA  or
        appropriate   regulatory  agency  with  48  hours.
        Within  five  days  the  operator  shall reset the
        monitoring   device  to  detect  the  fluid  level
        within  75  feet   (22.86m)  of  the  base  of  the
        lowermost USDW.

     3.  If  the  fluid  level  rises   to  within 75 feet
        (22.86m)  of  the  lowermost  USDW,  the  operator
        shall  report  this situation, including change in
        fluid  level  in   feet  per  day,  to  the  EPA or
        appropriate  regulatory  agency  within  48 hours.
        Within  five  days  the  operator  shall reset the
        monitoring device to detect the fluid level
                             75

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        within  50  feet  (15.24m)  of  the  base  of  the
        lowermost USDW.

     4.  If  the  fluid  level  rises  to  within  50 feet
        (15.24m)  of  the  lowermost  USDW,  the  operator
        shall  immediately  shut-in  the  well  (if active)
        and  report this siutation including the change in
        fluid  level  in  feet  per  day,  to  the  EPA or
        appropriate regulatory agency within 48 hours.

If  the  fluid  level  does  not  remain more that 50 feet
(15.24m)  below  the  base of the lowermost USDW, the well
would   fail   the   mechanical  integrity  test  and  the
operator   shall   submit   to   EPA  or  the  appropriate
regulatory  agency,  within  15  days: (1) A plan to lower
the  fluid  level  in the annulus, or (2) A plan to repair
the  well,  or  (3) A plan to properly plug and abandon the
well.    The  plan shall include a schedule for completing
the  required  work  as  long  as  the well is passing the
continuous  annular monitoring test the actual fluid level
in  the  tubing-casing  annulus shall be measured at least
twice  a  year  and  reported  to the USEPA or appropriate
regulatory  agency with the annual report.  The tubing and
packer  must  be  pressure  tested  every  five  years  or
whenever the packer is unseated for any reason.   ~

The  rationale behind the development of this test is that
regardless  of  the condition of the casing, a USDW cannot
be  endangered  if  the formation pressures below the USDW
are  not  great enough to support a column of fluid at the
same  level  as the USDW.  Since the static fluid level in
the  annulus is directly related to the reservoir pressure
existing  at  the  time  the  packer  was  set,  it can be
assumed  that  any  change  in the formation pressure that
would  endanger  the  USDW  would  be  picked  up  by  the
monitoring  device  when  the  static fluid level changed.
Any  change  in the static fluid level would indicate that
there  was  a tubing-packer failure or there was migration
of   fluids  behind  the  casing  that  was  communicating
through  the  casing  leaks,  therefore,  causing  a fluid
level rise in the annulus.

The  theory  and  operation  of the continuous fluid level
monitoring  device  was  tested  by Jerry Thornhill of the
USEPA  Robert S. Kerr Environmental Laboratory in Ada, OK,
on January 22, 1990.

The   device   was  successfully  tested  on  the  ECU/EPA
Research  well  by  detecting  a rise in the annulus fluid
level  and  activating the alarm with the fluid raising to
no  greater  than  one  foot   (30.5  cm) above the trigger
depth.  These depths and conditions were verified by two
                            76

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acoustic  fluid  level  measuring  devices  and a manually
operated cable type fluid level measuring device.

ADVANTAGES
This  concept  has  several  inherent  advantages over the
standard  pressure  test  that is required to be performed
every five years.

A  major  advantage  is  that  the  well  is,  in  effect,
continuously  tested  for physical integrity of the tubing
and  packer as well as for any vertical migration that may
be  occurring  through  vertical  channels adjacent to the
well  bore.   This migration would be communicated through
any  leaks  in  the casing and manifest itself as a change
in  the  static  fluid level in the tubing-casing annulus.
Although  a  well  may pass the pressure test, there is no
guarantee  that  the  well would pass the same test at any
time  in  the future.  Should the casing, tubing or packer
fail,  and  industry  experience  indicates that a failure
can  be expected before the five year retest, the well may
operate  for  a  considerable  period  of  time before the
failure  is  discovered.    With  the  continuous  annular
monitoring,  once  there  is  a  rise in the tubing-casing
annulus  fluid  level,  the  device  would immediately and
visibly  report  the situation, therefore, allowing either
the  operating  personnel  or the regulatory inspectors to
easily notice the problem.

The   application   of  this  concept  as  an  alternative
mechanical  integrity  test  also  allows  an  operator an
economic  savings  as  long as the well remains within the
contraints   of   the   test   procedures.     It  can  be
conservatively  stated  that  under  the  vast majority of
cases,  an  operator could be expected to expend a minimum
of  USD  3000  to  repair  a  casing  leak.    The cost of
plugging  and  abandoning  a  well,  should  the  leak  be
unrepairable,  would  range  from USD 1500 up depending on
well  construction and problems encountered.  The operator
would  also incur a significant cost in replacing the well
that  was  plugged or, in the worst case, have to plug out
the  entire  lease if production revenue would not support
the  construction  of another well for injection purposes.
This   probblem  could  be  effectively  resolved  by  the
application  of  the  continuous  monitoring concept as an
alternative mechanical integrity test.

CASE HISTORY

The   North   Burbank  Field,  located  in  Osage  County,
Oklahoma,  was  discovered  by Marland Oil Company in May,
1920.    The  producing  formation  is approximately 3,000
feet (915m) deep and extends 12 miles  (19.3km) north to


                            77

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south  and  4-1/2  miles  (7.25km) east to west.  Original
oil-in-place  was  671,000,000  STB (107,000,000m3).  The
field  was  unitized  in  1950  with Phillips Petroleum  as
operator.    Today,  the  field is under waterflood with a
total  of  721  producing wells and 561 Class II injection
wells.    Currently, only 165 producing wells and 73 Class
II  injection wells are active.  Cummulative production  to
date is 310,000,000 STB (49,300,000 m3) .

The  wells,  drilled  from  the 1920's through the 1960's,
were  completed  with  large  surface  casing  set  to   an
average  depth  of  120  feet  and  cemented  to  surface.
Production  casing  was  set  to  a depth of approximately
2900  feet (884m) and cemented with an average of 75 sacks
of  cement.   The well was then cable tool drilled through
the  producing  zone  and completed openhole.  (See Figure
1.)

In  1984  the  Osage  County Underground Injection Control
(UIC)  regulations  became final (See Figure 2.)  Early  in
1985  they went into effect requiring that owner/operators
of  Class  II  injection wells demonstrate well mechanical
integrity   according   to  40  CFR  147.2912  (a),  which
included:

     1.  A  review  of  casing  and  cementing  records  to
        demonstrate  that  there  is  no significant fluid
        movement  into  a  USDW  through vertical channels
        adjacent  to the wellbore (40 CFR 147.2912 (a)(2),
        and

     2.  A  field  test  of  the  well to demonstrate that
        there  are  no  significant  leaks  in the casing,
        tubing, or packer (40 CFR 147.2912 (a)(1).

According  to the UIC regulations, if a Class II injection
well  failed  to  demonstrate  mechanical  integrity,  the
owner/operator  was  required  to  remove  the  well  from
service.    At  that  point  the  well had to be repaired,
converted to a producer, or plugged and abandoned.

During  1987,  all  Class  II  injection wells operated  by
Phillips  Petroleum  in  Osage  County  were submitted for
technical  review.   During 1988, following that technical
review,  all  Phillips  operated  Class II injection wells
were   either  tested  for  mechanical  integrity  of  the
casing,  tubing,  and  packer  with  a  200  psi (1380kpa)
pressure  test,  or  submitted  as  verbal failures of the
mechanical  integrity  test.    At  that  time  the  field
contained  561  Class  II  injection wells.  A total of  45
wells  passed  the  casing,  tubing,  and packer integrity
test and 516 wells failed.


                             78

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Due  to  the magnitude of the number of wells that failed,
and  the  resulting  operational impact that casing repair
of  plug  and  abandonment  would  have  on  the  economic
viability  of  the  field,  Phillips,  as  operator of the
North  Burbank  Field,  requested  the opportunity to test
the  continuous  annular monitoring concept.  That request
was  granted  by the USEPA Region 6 Regional Administrator
in October, 1988.

In  approving  the  test  of the concept, the USEPA placed
the following general requirements:

     1.  If  mechanical integrity tests demonstrate casing
        leaks,  or  if  Phillips  admits  the  presence of
        casing  leaks,  then  Phillips  will implement the
        monitoring  program  for  active  wells  with such
        leaks  and for all inactive wells that do not have
        mechanical integrity.

     2.  Phillips  would  test the mechanical integrity of
        the  tubing  and packer of all active wells in the
        North Burbank Unit.  Pursuant to 40 CFR 147.2912.

     3.   Phillips   would  install  on  each  active  and
        inactive   well   described  above,  a  continuous
        monitoring  system  which would immediately detect
        and  warn  of  fluid  level  in  the casing-tubing
        annulus  within  100  feet   (30.48) of the base of
        the  lowest USDW.  Beginning upon signature of the
        Agreement,  the  systems  would  be installed at a
        rate  of  forty-five  (45)  per month, with active
        wells  given  priority.    All required monitoring
        systems to be installed by December 31, 1989.

Based   on  the  requirements  outlined  above  under  the
concept   of   continuous   annular  monitoring,  Phillips
developed  corrective  action  plans  for certain Class II
injection  wells  that  failed  to  demonstrate mechanical
integrity,  but  that  would  continue  to  be operated as
injection  wells.     (See  Figure 3.)  In all wells have a
tubing-casing   annulus   fluid   level  above  the  USEPA
specified  base  of  the  USDW  and  a  fluid level in the
tubing  below  the base of the USDW, the fluid level would
be  lowered  below  the  base of the USDW by releasing the
packer.   This action will allow the tubing-casing annulus
fluid  to  equalize  with the fluid  level supported by the
producing  formation  is  evidenced  by  the  tubing fluid
level.    Since the fluid level in the tubing is below the
base  of  the  USDW,  the  resulting  fluid  level  in the
annulus would likewise be below the base of the USDW.
                             79

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In  all  wells  having a tubing-casing annulus fluid  level
and  tubing  fluid level above the USEPA specified base  of
the  USDW, the fluid level would be lowered below the base
of  the USDW by removing the tubing and packer and placing
a  blanking  plug  in  the  well above the injection  zone.
The  fluid  level  would  then  be swabbed down to a  point
below the base of the USDW.

Following  both  of  these corrective action plans, a FLMD
is installed on the well.

Similar  corrective  action plans were developed for  those
Class   II  injection  wells  that  would  be  temporarily
abandoned.  (See Figure 4.)

DESIGN

The  continuous  monitoring system as proposed by Phillips
utilizes  a  fluid level monitoring device (FLMD) that was
designed  by  a group of Phillips engineers lead by Mr.  C.
D.  Fryer.   This monitoring device ensured that any  fluid
level  which rose to near the base of fresh water would  be
readily detected.

The  FLMD  contains  two  separate  sections; a monitoring
side  and  an  alarm  side (See Figure 5.)  The monitoring
side  is  based  on  the  ideal  gas law and consists of a
diaphragm  and  1/4  inch  (6.35mm) stainless steel tubing.
The  stainless steel tubing is placed .in the tubing-casing
annulus  to  a pre-calculated depth.  The setting depth  is
based  on  the  depth  of  the USDW and the warning margin
desired, and calculated by the following formula:

Lt=(((Pd(Vd2+VtLw))/Pa)-Vd)/Vt	(1)

Where   Lt = Length of stainless steel tubing, feet
        Lw  =  Warning  level  (USDW  +  warning  margin),
             feet (m)
        Pa = Atmospheric pressure, psia (Pa)
        Pd = Diaphragm trigger pressure, PSIA  (Pa)
        Vd   =   Volume  above  diaphragm  at  atmospheric
             pressure, 1.83 cu. in.  (3 x 10 ~5 m3)
        Vd2  = Volume above diaphragm at trigger pressure,
             3.66 cu. in.  (6 x 10 ~5 m3)
        Vt   =  Internal  volume  per  foot  of  1/4  inch
             (6.35mm)      stainless     steel     tubing,
             0.3054 cu. in./ft (1.64 x 10 ~5 m3/m)
        Lw  =  Warning level  (USDW + warning margin), feet
             (m)
        Pa = Atmospheric pressure, psia (Pa)


                            80

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Example:  USDW = 100 FT (30.48m)
          Warning margin = 100 ft  (30.48m)
          Trigger pressure = 2.5 psig  (17.24 kPa)
          Atmospheric pressure =14.4 psi  (99.28 kPa)

          Lt = (((Pd(Vd2+VtLw))/Pa)-Vd)/Vt

          Lt  =  243  feet  (74m)  of  1/4  inch   (6.35mm)
               stainless steel tubing

In  this  example,  the  stainless  steel  tubing would be
placed  in  the  tubing-casing  annulus  to a depth of 243
feet  (74m).  Once attached to the diaphragm the diaphragm
would  trigger  if the annulus fluid level rose to a depth
of  200  feet  (60.96m)  from  surface.  This would be 100
feet    (30.48m)   below  the  base  of  the  USDW.    This
"triggering"  is  accomplished  by  the compression of the
air  in the stainless steel tubing and above the diaphragm
as  the  fluid level in the annulus raises from the end of
the  stainless  steel  tubing  at  243  feet  (74m) to the
warning  level  of  200  feet (60.96m)  (USDW plus warning
margin).

Once  the monitoring side of the FLMD has sensed a rise in
the  tubing-casing  annulus,  the  alarm  side  goes  into
action.   The alarm side consists of a pressurized tank, a
valve,  and  a  warning  flag mounted on an air ram.  When
the  diaphragm  is triggered, it opens a valve.  The valve
then  allows  pressure from the pressurized tank to charge
the  air ram.  The charged air ram then raises the warning
flag  in  the  air  to  signal  a  high fluid level in the
tubing-casing annulus.

The physical environment that the FLMD  would  be required
to  operate  in  necessitated  that the device be compact,
unobtrusive  and  attach  to  existing  wellhead equipment
with  minimal  modification  (See  Figure  6.)  Due to the
number  of  FLMD's  to be installed, total installed price
per  unit  had  to  be maintained as low as possible.  The
time  frame  for  installation  set  by the USEPA demanded
that  the FLMD's be built from equipment available off the
shelf and easily serviced.

INSTALLATION

Installation  of  the  FLMD  is identical for an active or
inactive  Class  II  injection  well.   However, to remain
active  a Class II injection well must first pass a tubing
and  packer  integrity  test.    The  nitrogen  method  of
integrity  testing  was  utilized  at  North Burbank.  The
method  required  that  the  tubing and wellbore below the
packer be filled with nitrogen and the surface pressue on


                             81

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the  tubing-casing  annulus  as  well  as  the  tubing   be
monitored  for  pressure  changes resulting from tubing or
packer leaks.

The installation procedure for the FLMD is as follows:

    1.    Modify  the rubber seal ring of the wellhead  and
        adjust   the   tubing   slips  to  facilitate   the
        monitoring tube.
           NOTE:  Some types of slips will require removal
        and modification.

    2.     Install  stainless  steel  monitoring  tube   to
        predetermined depth.

    3.    Modify  wellhead to accept FLMD.  Attach FLMD to
        wellhead.

    4.   Test stainless steel monitoring tube to ensure it
        is not blocked.  Clear if required.

    5.    Complete  installation  by attaching the FLMD to
        the    stainless   steel   monitoring   tube    and
        pressurize the FLMD's air tank.

To  date  a  total  of  487  FLMD's have been installed in
Class  II  injection  wells  in  the  North Burbank Field.
During  1989,  a total of 45 monitoring devices detected a
high  tubing-casing  annulus fluid level.   Twenty-four of
the  signals  resulted  in corrective action to the wells.
Twenty-one  of  the  signals  were either false signals or
premature signals.

Total  compliance with USEPA MIT requirements for Class II
injection  wells in the North Burbank Field without use of
the  approval  of  the  continuous  monitoring concept  was
estimated  at  USD  7.2  MM.   By utilizing the continuous
monitoring  concept compliance for the North Burbank Field
totaled USD 600,000.

On  December  20,  1989,  USEPA  Region  6  made  this   an
alternate  mechanical  integrity  test as per the Regional
Administrator Authority under 40 CFR 147.2912 (a)(1)(V).

This  approval  applies  only to the Osage Mineral Reserve
and  allows  an  operator  to  choose between the positive
pressure  test  of  casing  or  the  continuous monitoring
concept.  (See Figure 7=)

PROBLEMS

Two areas of problems have been encountered during the


                            82

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installation  program of the FLMD.  The first problem  area
is  system  air  leaks  on  the  alarm side of the device.
These  are  being  addressed  and steps are being taken to
eliminate  as many potential leak points as possible.  The
second  area  is  plugging  of  the  monitor tubing during
installation.    This problem has been solved with the use
of  a  low  volume high pressure pump to clear the monitor
tubing after installation.

Alternate   methods   of  warning  have  been  tested  and
reviewed.    Electrical signals such as flashing lights or
sirens,  as  well  as the mechanical flag signal have  been
tested.    Due  to  the  operating parameters in the North
Burbank  Field,  the  mechanical  flag  warning signal was
chosen.

PROGRAM MAINTENANCE

The  continuous  monitoring  system  as installed at North
Burbank  requires  cooperation  of all persons involved in
the  field.    Everyone has been trained to look for flags
as  they  travel  the  lease  roads.   The air pressure is
checked  on the monitor devices by the field pumpers twice
a  month.   Twice a year the monitoring device is function
tested  and  preventive  maintenance  done  on the device.
During  this  function test, the tubing-casing fluid level
is  determined by an acoustic fluid level measuring device
to confirm the fluid level is below the base of the USDW.

SUMMARY

The  application  of  the  continuous  annular  monitoring
concept  as  an  alternative  mechanical integrity test on
Class  II  wells with insignificant leaks in the casing is
a   practical  means  of  achieving  compliance  with  UIC
regulations.   Oil and gas producing companies can realize
significant  economic  savings  since  expensive  remedial
operations  would  not  have to be performed on every  well
that  could  not  pass  a  standard  pressure  test on the
tubing-casing  annulus.    In addition, this concept would
allow  for regulatory agencies to quickly and easily check
for   well   problems  that  might  go  undetected  for   a
considerable  length  of  time  under the normal five  year
test schedule.

REFERENCES

Wilson,   Everett   M.:    "EPA  Develops  Injection   Well
Pressure Test"

Petroleum  Engineer  International  March 1988  (Pg. 34-39)
and April 1988  (Pg. 40-47).


                             83

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The   authors   thank  C.  D.  Fryer,  Phillips  Petroleum
Company,   who   designed   and  patented  the  monitoring
device.    His efforts as well as the efforts of the staff
of  USEPA  6W-SE  were instrumental in obtaining the USEPA
Region   6   Regional   Administrators   approval  of  the
continuous  monitoring  test  program.  Without their work
this article would not have been possible.

ABOUT THE AUTHORS

Len  G.  Janson,  Jr., is employed with Phillips Petroleum
Company  as  the  Senior Production Engineering Supervisor
in  the  Shidler,  Oklahoma  Office.    He holds a B.S. in
Petroleum Engineering from Montana Tech.

Everett  M.  Wilson is employed with Du Pont Environmental
Remediation  Services  in  Houston,   Texas  as  a  project
engineer  specializing  in UIC and underground issues.   He
was  previously  employed  by  USEPA Region 6 in the water
Management Division.
                             84

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                                              INJECTED
                                              FLUID
           WELLHEAD
                                      BOTTOM OF SURFACE CASING
                 BASE OF
       PROTECTED WATER
Figure 1. Typical Class II Injection
Well Completion in North Burbank Field
     DRILLING MUD
                                     ANNULAR SPACE
                                      PACKER
                                      BOTTOM OF CASING
INJECTION ZONE

-------
                                         CASING MIT PER
                                         40CFR 147.2912
                               FAIL
                          PASS

I
PLUG AND
ABANDON



I
REPAIR
WELL


CONVERT TO
PRODUCER




INJECT
OR
TA
                        CASING
                           MIT
                             RETEST
                             IN 5YRS.
             FAIL
              PLUG AND
              ABANDON
    PASS
INJECT
OR TA
Figure 2.  Original Osage County
Underground Injection Control
(UIC) Regulation.
                                  RETEST
                                 IN 5YRS.

-------
                                      INJECT
                                 i
                             ANNULUS FL
                               ABOVE
                               USDW
            I
       ANNULUS FL
          BELOW
          USDW
                       TUBING FL
                         ABOVE
                         USDW
TUBING FL
  BELOW
  USDW
                        BRIDGE
                       PLUG AND
                         SWAB
                                       J-
 RELEASE
 PACKER
AND RESET
                                        L
REPAIR
CASING
 AND
RETEST
                                 c-
                                 00
                                            NITROGEN
                                              TEST
                                             TUBING
                                           AND PACKER
                                      INSTALL
                                       FLMD
                REPAIR
                 AND
                RETEST
                OR TA
Figure 3.   Corrective Action Plans Under Test
Program for Active Class II Injection Wells.

-------
                                    TA
                     ANNULUS FL
                       BELOW
                        USDW
                       INSTALL
                        FLMD
      ANNULUS PL
        ABOVE
         USDW
TUBING FL
 BELOW
  USDW
                                        I
                                     RELEASE
                                     PACKER
                                        _L
                                     INSTALL
                                      FLMD
TUBING FL
  ABOVE
  USDW
               BRIDGE
              PLUG AND
               SWAB
                 J.
               INSTALL
                FLMD
Figure 4.  Corrective Action Plans Under Test Program
for Temporarily Abandoned Class II Injection Wells.

-------
                             FLAG
                      AIR TANK
                  MONITORING
                  SIDE
                      STAINLESS
                   STEEL TUBING
                   MICRO VALVE
                                                ALARM
                                                   SIDE
                                              AIR
                                              CYLINDER
Figure 5.  Fluid Level Monitoring Device.

-------
               FLMD <
          WELLHEAD
••^•••••••••B
cm
            BASE OF
  PROTECTED WATER
              ^^  ^^   ^  ^«^^  ^
Figure 6. A Completed Installation of Fluid Level

Monitoring Device on Class II Injection Well.
           BOTTOM OF
           SURFACE CASING

-------
                                SELECT
                                 MIT
        I
                                   1
 200 PSI POSITIVE
 PRESSURE TEST
                                  1
                            CONTINUOUS
                              ANNULUS
                            MONITORING
   PASS
                         FAIL
                   FAIL
                                                           I
                                                     NITROGEN TEST
                                                      TUBING AND
                                                        PACKER
      INJECT
      OR TA
     RETEST
    IN 5YRS.
I
                                                             PASS
                                               o>
                               INSTALL
                                FLMD
                      PLUG AND
                      ABANDON
              REPAIR
               WELL
Figure 7. Revised Osage County Underground
Injection Control (UIC) Regulations Following Test Program.
     1
CONVERT TO
 PRODUCER

-------
                         AREA WASTE MANAGEMENT  PLAN
                                     FOR
                      DRILLING AND PRODUCTION OPERATIONS
C.  T.  Stilwell
ARCO Oil &  Gas Company
Midland,  Texas,  USA
INTRODUCTION

One environmental issue receiving significant attention in  recent  years  within
the oil and gas exploration and production industry is the handling and disposal
of  wastes  generated  by  the  various   drilling  and production   operations.
Heightened  interest   within  the  public   and  regulatory  agencies   toward
environmental issues  has been an  impetus  for the  industry to scrutinize  its
wastes and how they are managed.

From a private company's  perspective,  proper waste management is  an  important
part  of  doing business.   A company must  be concerned  with compliance  with
applicable waste regulations, minimizing the impact of  wastes on the environment,
and the  reduction of potential  liability  associated with improperly  disposed
waste.  This must be  accomplished all within the certain economic bounds.   Also,
eliminating or minimizing the generation of waste is becoming more critical  -
both environmentally and economically - as  a means of reducing  waste-related
liabilities and  costs.

This paper reviews  the concept  of the Area  Waste Management Plan  (Plan)  as  a
means of improving the management of wastes generated by a company's drilling and
production operations.  The  development and use of Area  Waste Management  Plans,
as  described  in this  paper,  allow a  company  to  effectively  identify  and
communicate sound waste management  strategies.  These strategies are based on the
 regulatory,  environmental,   technical, and economic  criteria applicable  to  a
specific  geographic  area's operations.   The development, content,  format,  and
possible  alternative applications  of  the Plan are presented.


WASTE  MANAGEMENT CONCERNS

Upon  a cursory  review of the  Company's drilling and production operations,
 several concerns were identified regarding the handling and disposal of certain
 wastes generated by  its operations.  Production operations reviewed were from a
 broad  scope of operating  facilities, including oil production (both primary and
 secondary),  gas production,  and gas processing  plants.    Drilling operations
 observed  included drilling,  workover, and completion operations.   These field
 operations were  situated  in  a variety of environmental and regulatory settings.

 Waste  management  concerns  generally manifested  themselves in  inconsistent
 minimization,  handling and  disposal practices.   In reviewing  the operations
 themselves and interviewing  operations personnel, specific reasons these waste
 management concerns  became evident.

 The primary reason for the waste management concerns was a lack of understanding
 of the  wastes   and  the management  options  available  for  their  handling and
 disposal.  This  was  due  to  several factors, including a  complex and changing
 regulatory climate,  lack  of  clear guidance on the environmental aspects of field



                                      93

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operations, and the perception of competing environmental and economic goals.

                              Regulatory Climate

Most  state oil  and gas  agencies  began  regulating  waste  from drilling and
production operations before the inception of many of the federal environmental
statutes passed in the early 1970s.  Historically,  regulation of wastes in the
oil field focused on drilling fluids and produced water.

Since  the  early 1970's, a  number of the federal environmental  statutes, and
subsequent  state  statutes  and regulations,  have  been passed which  affect the
management of oil and gas waste. -Each state has developed regulations to control
these wastes as specified in the federal laws,  and  as specified in the individual
state's  environmental  statutes.   For operations on federally  controlled land,
separate and overlapping  regulations  administered by  the  respective  federal
agencies (e.g. BLM, Forest Service)  must be  complied with, in addition to state
requirements.

Though adequate, individual states'  requirements for oil  and gas waste management
vary  significantly.   This  variability reflects  the  diverse  geological  and
environmental  conditions in each state.   Often  attributed to  the  historical
emphasis on drilling fluid and produced water,  the regulations  are  often not
specific on a waste by waste basis.  Additionally, most environmental regulations
have  been  amended frequently over the  last ten  years.

This  complex regulatory climate, which changes with time and with geo-political
boundaries, contributes significantly to the lack of understanding of compliance
 requirements  affecting waste management in the  oil field.

                       Management Options  Not Understood

 In the operations  reviewed, many viable waste management options allowed by the
 applicable regulation were not being utilized.  This was primarily due to a lack
 of understanding of the available options which met the  appropriate regulatory,
 environmental,  company policy and  economical criteria.   Operations  personnel
 responsible for  waste  management  at  each  facility  had  inadequate  resources
 available  for  determining  and  choosing among  the  feasible options.

 Adequate guidance from regulatory agencies was generally not available.   Copies
 of the  ^ applicable  regulations  were  readily  available,  but  commonly  these
 regulations were not clearly written for individuals not  familiar with regulatory
 documents.   Internal  guidance  from  the  company  was  often  unavailable  or
 inadequate.  Several reasons  for  this  were:

 •     Relevant company policies  on  waste management were too general;
 •     Environmental personnel  (staff) who were knowledgeable on the regulatory,
       environmental,  and   technical  aspects  of  waste  management  were  not
       knowledgeable in field operations; and
 •     The 1980's business  climate - profit margins and support staffs have been
       reduced at the same  time concern for  the  environment has increased.

 With  no  usable  guidance,   field   operations   personnel  frequently  decided
 unilaterally on methods of handling  and disposing of wastes.  This often resulted
 in wastes  being  managed in ways which,  though historically  acceptable,  were
 without full consideration of the  regulatory and environmental criteria which
 possibly applied.  Conversely,  some  operations were using over-conservative waste
 management practices,  when equivalently compliant  and  protective methods were
 available that were less costly.

                                Needs Assessment

 The following is the needs assessment  resulting from the identification of the
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waste  management problems and their root causes :

1.     Improve Understanding  of Wastes  and Waste .Management Requirements  and
      Options
2.     Establish Waste Management Goals and Performance  Standards
3.     Improve Communication and Implementation  of Goals  and Standards


AREA WASTE MANAGEMENT PLAN

The concept of the Area Waste Management Plan,  as described below,  is intended
to address the stated needs in the following manner:

1.    Provides  a  process to identify  appropriate  management strategies  (i.e.
      minimization, handling,  and  disposal practices)  for  wastes generated by
      production or drilling operations; and
2.    Provides an effective means of communicating those strategies so they may
      be implemented effectively.

In identifying appropriate waste management strategies, all relevant criteria are
considered, including regulatory, environmental, company policy, practical,  and
economical.   As  important as identifying sound waste management practices,  is
ensuring they are properly implemented.  The second component of the Plan is the
development and use of a user-friendly document which provides effective guidance
to  field operations personnel  requiring  the information.

Much  of the regulatory and technical information required to identify acceptable
management  options for  specific  drilling and  production  waste was  addressed
generally  by  the  American  Petroleum  Institute  in  its  document  entitled
Environmental Guidance Document for Onshore Solid Haste Management in Exploration
 and  Production  Operations  (API/EGD)1.    The  development  of   the  Area  Waste
Management  Plan uses  and builds upon the  regulatory and technical  information
contained  in  the  API/EGD.

                              Development of Plan

 The first  phase of the  Plan process  consists  of identification of  wastes  and
 guidance on the management of those wastes.  A Plan is developed using a rigorous
 step-wise  process  of  identifying  wastes,  then  selecting  and  prioritizing
 management options (i.e. minimization, handling,  and disposal practices for each
 waste) .

 Throughout the  development process, the involvement of field personnel (several
 levels  are preferred - supervisors to roustabouts)  is critical to:   a. identify
 all waste  streams  and management options; and b. to ensure their support of the
 Plan when  published.

 Each step in this waste management  practices  selection exercise  is described
 below.  With  each step, examples are given from the development of an actual Plan
 for the Company's Southeast New Mexico Production Operation2.   A brief summary
 of this six-step process is found  in  Table 1.

 Step 1:  Identify Area of Coverage
   ^        scope for the Plan must be defined by selecting the area which the Plan
 will cover.   Developing one cohesive  Plan  to cover  all  the operations  in a
 company  is  generally  not  possible   unless  the   operations   are  limited
 geographically or operationally.   It  is assumed,  therefore,  that  initially a
 ^company's operations must  be divided  into several "areas"  for the purpose of
 developing the Plan  for  each.  On the other hand, a company's operations should
 not be divided into so many Areas that  there  are  too  many individual Plans to
 practically develop  and  maintain.  In defining an Area  of Coverage for the Plan,
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the primary goal is to define areas with common  aspects  which may affect waste
management strategies.   An Area should be  defined by operational,  as well as
geographic or areal, boundaries.

Defining an area geographically should be based  primarily on common regulatory
requirements, environmental, and geological  characteristics.   Areas based on the
applicable waste regulations usually follow  state  (or other geo-political) lines
which  define   regulatory  jurisdiction.     An   Area  may   also   be  defined
geographically, based  on common environmental and/or geological  aspects.   The
surface  environment where  an operation exists  often  influences the various
management options available.  The  geological (i.e., reservoir) aspects influence
the nature of production and  drilling wastes generated.

A geographically-based Area can be  further  refined by determining the relative
benefit of defining the Area based on common operations.   It may be effective to
develop  separate  Plans  for  each  of  the  major  types  of operation  -  namely
drilling, production,  or gas processing plant.  Another  method to  consider in
defining  an  Area  is to have separate  Plans for each  operational  organization.
In  some cases,  an  Area defined  by organization (e.g., Area Plan for Production
Dept.) allows more customizing  with respect to the ultimate  user  of the Plan.

       Example  of defining an  Area:  In defining  the Area  for the  Southeast  New
       Mexico Production  Operations' Plan, the  following  rationale was used:

       •      Regulatory:   Oil and gas  wastes are primarily regulated by the  New
             Mexico Oil Conservation Division (NMOCD),  therefore the initial area
             definition was by state. The two primary oil and gas  regions in  New
             Mexico are  in the Northwest  (NW) and Southeast (SE) corners of  the
             state.  One  reason  for  dividing the  state in  two is the regulatory
             agency jurisdiction—the  NW has a large  percentage of  federal  and
             Indian land  and the SE  is predominately privately owned.

       •      Environmental:      The two  regions  are also  distinct   in  their
             environment.  The NW  is a high  plateau region crossed with several
             large  river  basins.  The SE is very much like West Texas,  flat with
             little surface water.

       •      Geological:   Gas  is the primary product from the San  Juan Basin  in
             the NW.  The SE  is an  extension  of  the Permian  Basin, which is a
             mature oil and gas producing region.   The  difference in the resource
             products also causes  a  difference  in the  nature  of the wastes.

       •      Operational:   Three   operational  considerations  influenced  the
             definition of the Area:

             1.     Waste  management options   vary  between  the  two  regions,
                   partially due to the differences in  the  service industry which
                   has evolved in  each region.
             2.     Separate production offices  manage  the NW  and  SE operations,
                   giving another  reason for dividing  the state's  operations in
                   two.
             3.     Separate Plans were  developed  for Drilling and  Production
                   Operations because the two are  managed by separate departments
                   within the Company.

 Step 2:   Identify Wastes in Area's  Operations

 Once  an  Area  is  defined,  all  wastes  generated  by the  operations need  to  be
 identified.    This is best done  on a  process by process basis.    The primary
 processes  associated with   drilling and   production operations,  and  wastes
 generated from those processes, are summarized in the API/EGD.  In addition to
 wastes generated directly from  the  drilling or production process,  many wastes


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are generated through indirect activities.   These include wastes from vehicles,
maintenance activities,  office  or  living  quarters in  remote  locations,  and
infrequent or unexpected activities.   An  example  of  a  waste generated by an
infrequent activity is residue  from a well treatment with  a  special chemical.
Unexpected activities may include product  or chemical  spills,  or the discovery
of friable asbestos in an insulated vessel  or building.

      Example  of  Area's Waste:    Waste  identified  as  being  generated,  or
      potentially being generated in the SE New Mexico area are listed in Table
      2.

Step 3.  Categorize Wastes

Once  an  Area's  wastes  have  been  identified,  they  must  be  categorized.
Categorizing  the wastes  as they are  defined by the applicable  regulations is
necessary to ensure they are managed in compliance with those regulations.  Even
though  oil  and  gas  wastes  are regulated  under varying  state programs,  all
programs  must adhere to  several basic  waste definition  principles established
under  the  federal Resource  Conservation and Recovery Act (RCRA)3.   RCRA is the
 federal statute  which regulates solid waste ("solid waste"  can be solid, semi-
 solid,  or  liquid wastes).   In developing the RCRA statute,  Congress recognized
 the special nature of oil and gas exploration and production  wastes, and exempted
 them   from  hazardous  waste  regulations.    This  "exemption"  is   the   key  to
 categorizing oil and gas wastes in  order to facilitate their proper management
 under  the various regulatory scenarios found nationally.

 The Environmental Protection  Agency (EPA)  listed specific oil and gas wastes as
 "exempt"  or  "nonexempt" in its Regulatory Determination submitted to Congress in
 June 1988.  Using this Determination as a basis,  all oil and  gas wastes generated
 in an  Area may be divided into the  following major categories:

 •     Exempt Waste - Wastes generally coming from an activity directly associated
 with  the  drilling of an oil or  gas  well or the production  and processing of a
 hydrocarbon product.  These wastes are considered non-hazardous  industrial wastes
 under  RCRA and under  state statutes following RCRA.   Some states  have a narrower
 interpretation of Exempt Waste, which should be considered in categoring specific
 wastes in those states.

       Example of Exempt  Haste:  Bottom Sediment  and Water (BS&W or tank bottoms)
       is  the non-saleable fraction  of the production stream which settles in the
       bottom of  storage tanks  and  process vessel.  Since  BS&W  comes  from the
       vessels directly  associated  with production, this  waste  is categorized
       Exempt.

  •     Nonexempt  Waste  - Waste  coming from the maintenance  of  production or
 drilling equipment, or otherwise not unique to the oil and gas exploration and
 production  industry.   Though  nonexempt,   these  wastes  are not  necessarily
 hazardous.

 Because  Nonexempt Wastes  are  potentially  subject  to RCRA's  hazardous waste
  regulations  (RCRA  Subtitle  C) ,  they  must be  subdivided  to  ensure  proper
 management:

        Nonexempt   Non-Hazardous  Waste:     Wastes   which  are  neither   listed
  characteristically hazardous as defined by the RCRA regulations.   These wastes
  can generally be managed as  non-hazardous industrial  waste, similar to exempt
  wastes, under most state regulations.

        Nonexempt   Hazardous   Waste:    Wastes   which  are   either  listed  or
  characteristically hazardous as defined by RCRA regulations.   These wastes must
  be managed  as  hazardous  wastes   under   the   respective   state   and   federal
  regulations.


                                       97

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      Example of Nonexempt Waste:   Waste  hydrocarbon based solvents  generated
      from cleaning production equipment are classified Nonexempt  because they
      are associated with a maintenance activity not necessarily unique to the
      oil  and  gas  industry.    Some waste  solvents are  classified  Nonexempt
      Hazardous due to being characteristically hazardous for  failing the RCRA
      ignitability test4.  Others exhibit no hazardous characteristics under the
      RCRA criteria, thus are Nonexempt Non-Hazardous.

      Nonexempt  Special  Waste:  Wastes  which are  specifically identified  and
controlled under separate statutes and regulations—either on a state or federal
basis.  These wastes are  usually handled separately under  the  federal and state
regulatory programs due to their uniquely unsafe nature.

      Example  of Nonexempt  Special  Waste:   Both PCBs  and asbestos are  unique
      wastes which  warrant  special  handling and disposal dictated  by separate
      statutes and  regulation, thus are Nonexempt  Special Wastes.

The API/EGD  fully describes  the regulatory basis for the above classification
system as  well as  lists  specific wasted defined as Exempt or Nonexempt  by EPA.

Step  4.      Identify All Management Options  for Specific Waste

For each waste  identified and  categorized,  all  possible  management  practices
potentially  available for that waste should be listed.  Within the context of  the
Plan, "waste management"  includes:

      Minimization:      Methods which minimize or  reduce waste's volume  and/or
                         risk  of doing harm  to people or the environment.
      Handling:    Practices associated with  waste  from the point of generation
                   to  the  point  of  disposal.     Handling  includes   storage,
                   transportation, recordkeeping, waste  sampling and  analysis,
                   and use of  contracted waste handlers.
      Disposal:    Methods  and locations associated  with  on-site and  off-site
                   disposal or recycling of the waste, including use of public or
                   private disposal  locations.

Derive  the list  of management options from  the following:

      Practices  used  for the  waste  in the Area
      Practices  used  for the  waste  in other Areas
      Practices  used  for other  types of wastes
      Practices  used  by  other companies or  industries for similar  wastes


The practices  listed for the waste must be consistent with the  waste's category.
This  means only practices which comply  with the  various regulations applicable
to the   waste's  category  in  the Area should be  listed.   Waste categories  are
particularly important  when  considering  mixing of  several  waste  streams  for
 storage, handling or  disposal.

This  step is a brainstorming exercise meant  to identify potential practices.  In
 this  step, the listing of a particular practice or  idea should not  be biased by
 its  practicality, availability or  lack of  historical  use  in  the Area.   It is
 important for  the environmental engineer  to identify possible  new  practices by
 transferring ideas and technology from  other industries or geographic areas.

       Example  of "brainstorming" options  - for  BS&W in  SE New Mexico:

                                 Minimization
       1.    Change oil treatment process to  reduce or change character of BS&W.
       2.    Allow more BS&W to  be sold in production stream by lowering quality
             standard of  product.


                                      98

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                                  Handling
     1.     Drain BS&W from vessels into temporary earthen  pits.
     2.     Use a vacuum truck to pump BS&W out  of vessels.
     3.     Use liners,  drip pans or catchment basins to minimize BS&W spillage.
     4.     Use contracted labor specialized in  BS&W  clean  out of vessels.
     5.     Use company employees for BS&W clean out.
     6.     Use rigid containers with no leaks to store  BS&W during handling.

                                  Disposal
     1.     Spread/Disk in on lease road  (with agency approval).
     2.     Haul by  commercial  oil  reclaimer,  who reclaims  BS&W  partially and
           disposes remainder in industrial landfill.
     3.     Landfarm  (with agency approval)
     4.    Bury onsite  (with agency approval)
     5.    Haul to centralized treatment disposal facility operated by company.
     6.    Keep records  related to the disposal of BS&W.

Step  5:     Select Acceptable Management Practices

From  those listed in  Step 4, practices deemed acceptable by applicable regulatory
and company standards in the specific Area are chosen.   The criteria used to deem
a practice  acceptable are:
•    Acceptable under  applicable waste  regulation  for the  Area
4    Acceptable under  company  environmental policy

Company  policy dictates that  besides being in  regulatory compliance,  practices
must  minimize  the environmental impact and/or potential long-term environmental
liability where possible.

      Example:  Of the  management options listed in Step 4.  for BS&W associated
      with Southeast New Mexico Operations,  only the  following were selected:

      Minimization:     None  acceptable.   No  other  treatment  processes  are
      available to  reduce volume or nature of BS&W.  Neither Company policy nor
      the state oil  and gas regulations will  allow product  quality standard
      lower than the one currently  used in the area.

      Handling:  All handling methods listed in Step 4.  are acceptable  except
      Option 1. Company policy calls for minimizing the  use  of earthen pits for
      wastes,  even when allowed by  regulation.

      Disposal:  Hauling to a commercial reclaimer or  disposing  at a Company-
      operated site (Options 2 and  5)  are allowed by the agency.

 Step 6:      Prioritize Selected Management  Practices

 In most  cases, more than  one option will remain available  after  the selection
 process  in  Step  5.   Three factors to  consider  in prioritizing  the remaining
 minimization,   handling, and disposal practices  are practicality  for the field
 operations, availability  of  options  with specific area, and cost  of options.
 Some acceptable options may even be eliminated from further  consideration due to
 availability,   practicality,  or cost.    A simple  scheme of  deeming  the first
 priority option as "Preferred" and all others "Acceptable"  is utilized.

      Example:  The  options  selected  in Step 5  for  BS&W  in the  Southeast New
      Mexico  Plan were prioritized as  below:

                             Minimization - None

                                  Handling
      Preferred Option  -  Use  contracted  labor  specialized in BS&W clean-outs.
      Vacuum  trucks to pump BS&W and appropriate use  of  drip catching liners to
                                     99

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      minimize BS&W spillage is also specified for use by the  contractor.
      Acceptable  Option -  Use  company  employees  for  BS&W  clean-out  when
      contractor not available.

                                  Disposal
      Preferred Option - Haul to commercial oil reclaimer.
      Acceptable Option - None.  Use of a  Company  operated oil  reclaimer is not
      currently available,  nor practical or economical to operate.

The majority of an Area's Waste Management Plan is  complete upon performing this
six-step management  selection  exercise for each  waste  generated in  the  area.
Though this process  may appear protracted as presented here, it may be completed
quickly  with  environmental  and   operations   personnel   working   closely.
Additionally,  similar  wastes  occurring  across   Areas   make   development  of
subsequent Areas' Plans easier.

                         Writing the Plan's  Document

For  the  collection  of management guidelines  for  an Area's  wastes to be  most
useful, communicating them effectively to the Operations personnel generating the
wastes is essential.  Attention must be given not only to the  content of  those
guidelines but  also the format in which those guidelines are presented.

1.   Target Plan  Toward  Field Supervisor

With Operations personnel providing  input to the  six-step management option
selection  exercise,  the Plan's document should be substantively  practical and
useful to Operations.  Yet, for the document to be accepted and truly functional,
it  must  be  written  in a style and format  which is desired by  the primary  user
group --field operations personnel.

More specifically,  the primary users of the  document are the  first  and second
line production and drilling supervisors.   These supervisors are often the  focal
point for implementing new policies  and requirements generated by management and
engineering  personnel in  the Company.   It is important that they are provided
clear, concise directives on what is required of their operation.  This includes
appropriate  background and  details  without diluting the primary  intent of the
guidance.    Other  users of  the   Plan  document   are engineers,   management,
environmental professionals,  and field personnel.

2.   Plan's  Format

To provide a  concise,  straight  forward directive,  as  well as an  appropriate
amount  of detail  in the Plan document,  a two-tiered format  was used.    This
entailed having an encapsulated version of the Plan—called the  One Page Summary,
backed up  by the full document.

The One  Page  Summary serves  several  purposes.  It acts as a quick reference  guide
for all  users.  More importantly, it provides  a comprehensive summary of the Plan
on one page,  which  makes waste management  guidance  directly available to  field
personnel  who normally  would not read a technical  manual.  This One Page Summary
may be  incorporated in  a plant operator's or pumper's field book or posted on a
plant or field office bulletin board..

 Appendix A  shows the  One  Page Summary  for Southeast  New Mexico  Production
 Operations.    Appendix B describes the  full document's  basic  structure and
 content.   Appendix  C gives an  example of one waste's  Handling and Disposal
 guidelines from the Plan.

 3.  Document Production Details

 Many documents or manuals produced  by  a company to relay details on a technical



                                     100

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subject to its employees are ineffective because they are written and maintained
by a detached  staff group within  the company.   Often  these  manuals  are  not
presented in a  "user-friendly" format.   To avoid  some of  the pitfalls of a
Company  Manual, the  following were employed in  producing and  maintaining  the
Plan:
•     Written and maintained by an environmental engineer  who  is  familiar with
      and works with field operations routine.
•     Significant opportunity  for  Operations  to  provide input  into  the Plan's
      publication and maintenance by the use of frequent and sometimes informal
      update/revisions.
•     Use  full power,  personal computer-based  word  processor  to  write  and
      maintain the Plan.   This affords  a high quality  document while allowing
      quick revisions of the Plan.

                     Implementation and Maintenance  of  Plan

Once written,  several critical  steps  remain for the Area Waste  Management Plan
 to be implemented for use by Operations.  Final approval and endorsement of  the
 Plan must be received to ensure its use  by  the line personnel  including:

 1.    Final  review  and comment from specific operations supervisory personnel
      who will use  the  Plan;
 2.    Review and  approval  by  Legal Counsel; and
 3.    Review and  endorsement  by management

 In maintaining the  Plan, the  local environmental engineer  or staff  (i.e.  group
 working  directly with  Operations)  should maintain control.    Informal,  minor
 revisions  requested by Operations  should be incorporated  to allow the  Plan to
 remain  practical  and dynamic.  Revisions should also be made as  regulatory or
 policy  changes occur.

 Formal  reviews should occur periodically (biannually is  suggested) to ensure  all
 guidelines   remain  consistent  with  current  regulations,   technology  and
 environmental  science.  The intent of the subsequent  periodic  reviews and updates
 is more  than ensuring compliance.   New and innovative minimization, handling and
 disposal strategies  should be formally reviewed through the  six-step process used
 to enhance the original Plan.

 Although the examples presented in this paper are  for Production  operations only,
 the Plan's  concepts have been similarly  applied  to  Drilling and  Gas  Plant
 operations.


 CONCLUSIONS

 The development,  implementation,  and maintenance of  the Area  Waste  Management
 Plan concept improves the Company's  waste management  by satisfying  the stated
 needs as follows:

  1.    Improved understanding  of wastes  and waste  management  requirements  and
       options was  accomplished by  listing and categorizing  an Area's wastes,
       then listing available management options  based on those categories.

  2.    Waste management goals and performance standards were established by use
       of  the  Plan's  six-step development  process  to select and  prioritize
       appropriate management options.

  3.    Communication and implementation of the established waste  management goals
       and standards were  improved by the  writing and implementing of the Area
       Waste Management Plan document, as described, for the field operations.
                                     101

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ALTERNATIVE APPLICATIONS OF PLAN CONCEPT

This Area Waste Management Plan concept employs basic principles in identifying
wastes  and appropriate  waste  management  practices  based on  an  individual
company's needs.  The same concept can easily  be applied on a  broader scale.

                            Multiple Company Plans

One application  is  a  collection of  oil and gas companies combining  efforts to
develop and use  a Waste  Management  Plan for all their operations  in a  defined
area.  The Plan's development process would not  have to be altered significantly.
There may also be added benefit  in having the companies identify common problems
and  assist  one  another  in  solving1  those  problems,  either  individual  or
collectively.   One  example extending from a multiple company Plan is possible
establishing  waste  disposal  sites  cooperatively used and  maintained  by  the
companies  involved.

                           Industry/Government Plan

A  second  possible application to  the Area Waste Management Plan concept would
involve a cooperative effort between private industry and the regulatory  agency.
Having the two entities working  together would facilitate an  increased awareness
of the respective group's  needs and goals.  Using the Plan  concept could avoid
certain pitfalls in the  regulatory process, and halt the trend of increasingly
specific  waste  regulation.


ACKNOWLEDGEMENT S

Copyright  1990  Society of  Petroleum Engineers.  Paper first printed  in  the SPE
65th Annual Technical Conference and Exihibition, Sept.  1990 proceedings.

Thanks is  extended to Mr. Steve Smith and  his organization,  and Mr. Jim  Collins
and  others in  API's  Production Waste  Issues Group  for their  assistance in
developing the  Plan's process and the pilot Plan.
                                     102

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REFERENCES

1.    American Petroleum  Institute:    APJ Environmental  Guidance  Document  -
      Onshore Solid Waste Management in Exploration and Production Operations,
      First edition,  (January,  1989) .

2.    ARCO  Oil & Gas  Company,  Central District:   Area  Waste Management Plan,
      Southeast New Mexico Production  Operations,  ARCO Oil  &  Gas Company, First
      edition, (April 1990) .

3.    United  States  Congress:  "Hazardous  Waste  Identification",    Resource
      Conservation and Recovery Act of 1976 (passed Oct. 31,  1976), Subtitle C,
      Section 3001.

4.    Environmental Protection  Agency:   "Regulation for Identifying Hazardous
      Waste", Code  of Federal  Regulations (original publication,  45 FR 33119,
      May  19, 1980),  40 CFR 261.

5.    New  Mexico  Oil  Conservation Division: Rules  and  Regulations,  (March 1,
      1987),  Sections B, C, and Appendices.
                                     103

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                                        TABLE 1
                Process for Development  of  Waste  Management Strategies
STEP 1:  Identify Area of Coverage

             Define Areas  similar  in:
             • Regulations        •  Environment
             • Geology            •  Operations

STEP 2:  Identify Wastes in Area's  Operations

             List all solid, semi-solid, & liquid wastes generated from the processes in
             Area's operation
STEP 3:  Categorize Each Waste

              Categories:   •
                                Exempt
                                Nonexempt Non-Hazardous
                                Nonexempt Hazardous
                                Nonexempt Special
 STEP  4:   Identify All Minimization, Handling, Disposal  Options  for Each Waste

              "Brainstorm" to  list  all possible  options for minimizing,  handling  and
              disposing  each waste.   Include management practices  used  for the  waste in
              other  Areas of Company and  in  other  Companies  or industries,  and practices
              used for other wastes, as well as  practices currently used in the Area.

 STEP  5:   Select  Acceptable  Management  Practices

              All options selected  must  be  acceptable under applicable  regulations  and
              Comoany policies
              - i.e., must be environmentally sound by Company and government standards

 STEP  6:   Prioritize Remaining Options

              •      Prioritize as  "Preferred" or  "Acceptable".
                     Base priority  on  policy,  practicality,  and  cost.
                     Practice may also be eliminated based on practicality or cost.
                                        TABU:  2
               Wastes generated by production operations in SE New Mexico


 Production Wastes
                                  Contaminated Soil
                                  Solvents
                                  Empty Drums
                                  Methanol
      Refuse
      Produced Water
      Used Lube Oil
      Tank Bottoms, BSiW
      Oil and Water Filters

lompletion  &  Workover  Wastes
        Well Completion,  Treatment  &  Workover  Fluids
        Miscellaneous Rig Wastes
Slop Oil
Paraffin
Surplus Chemicals
Used Acid Batteries
 Special Wastes
        Asbestos
        Pesticide Waste
                                 Pesticide Waste
                                 Trichloroethylene
PCBs
 Copyright 1990 SPE
                                             104

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                                   APPENDIX


APPENDIX A               One  Page Summary
                        of Area Waste Management Plan for
                        Southeast New Mexico Production Operations

APPENDIX B               Basic Format and Content of Full
                        Area Waste Management Plan

APPENDIX C               Example of Handling and Disposal Guideline for One Waste
                                         105

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                             WASTE MANAGEMENT PLAN
        One Page Summary
           4/90
                                        Southeast New Mexico
                                        AKCO Oil & Gas Company
   WASTE
SEC.
REFUSE,PAPER,TRASH   2.1.1

PRODUCED WATER     2.1.2

USED OIL               2.1.3
OIL & WATER FILTERS  2.1.4

TANK BOTTOMS, BS&W 2.1.5
SLOP OIL               2.1.6
"HOT OIL" PARAFFIN   2.1.7
CONTAMINATED SOIL  2.1.8
 SOLVENTS
 EMPTY DRUMS
2.1.9
2.1.10
 SURPLUS CHEMICAL    2.1.11

 METHANOL             2.1.12
 USED ACID BATTERIES  2.1.13
 WORKOVER & WELL
 TREATMENT FLUIDS
 2.2.1
 MISCELL RIG WASTES   2.2.2
 buckets, empty
 sacks, used filters,
 quarters trash
                HANDLING & DISPOSAL GUIDELINES

       PRODUCTION WASTES

     Use trash containers, no pits.  Dispose using local trash contractor or
     directly with municipal landfill
     Reinject into ARCO wells or dispose using a water hauler listed on the
     Hobbs office's approved bid list
     Recycle to production stream, or sell to approved oil relaimer*.
     Drain  fluids back to production.   Dispose dry filter with trash at
     approved municipal landfill
     Reclaim using approved tank cleaner*.
     Reclaim* or add to crude production
     Circulate hot fluid/paraffin back to production stream
     For oil or water spills, remove free liquids, disk in or bury, stained soil.
     For spills of certain chemicals or if required by the agency, remove soil
     and haul to an approved disposer*.
     Use approved solvent recycler*, or call Env. Rep.
     Be sure drum is empty of all free liquids. Through Materials Rep.: 1.
     be sure bungs are in; 2. return to vendor; 3. use approved commercial
     drum disposer.
     Through Materials Rep.: 1. find a use for it at another ARCO facility;
     2. return to vendor;  or 3. call Environmental Rep.
     For de-icing or testing lines, circulate back  to production stream.
     When buying new battery, have dealer retain battery when changed
     out. Store  or transport no more than 3 used batteries at a time.
COMPLETION b WORKOVER WASTES

    •  Use  lined pits.   Vacuum  fluids  out and dispose at approved
      commercial facility*, or circulate back to production with Production's
      approval.

    •  Do not store or dispose in reserve or other pit. Use all material dope
      before disposing of empty containers. Store in a dumpster and dispose
      at authorized landfill.
 SPECIAL WASTES: PCBs, ASBESTOS, PESTICIDES, NORM, TRICHLOROETHYLENE (Sec. 2.3)
 If these wastes, or material suspected to contain these wastes, are found, notify your Supervisor or Environmental
 Rep. for handling and disposal.
                                         GENERAL NOTES
 1.   * Reclaim oily wastes using contractors and disposal locations listed on the back of this Summary or in Section
      3.2 (Waste Handlers and Disposal Sites) of the full Area Waste  Management Plan.
 2.   SEC column shows the Section of the complete Waste Management Plan. For more detail on these and other
     waste guidelines, refer to the complete Plan or call the Environmental Department (915-688-5560).
 3.   If unidentified material or waste is found at an ARCO facility, contact your Supervisor or Environmental Rep-
     for assistance in identifying and handling.
 4.   If illegal disposal by a contractor is seen or suspected, contact your supervisor.
 5.   Waste disposal into pits is no longer acceptable. All pits are permitted for only specific uses; know these uses.
                                               106

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                                      APPENDIX B

                          Basic Format and Content  of  Full
                              Area Waate Management Plan


Inside Cover   One Page Summary

Section  I      Introduction

      •       Brief  background  and description  of  Plan including definition  of waste
              categories

Section  II     Handling and  Disposal  Guidelines - By Waste

      •       Guidelines  presented   on  a  waste-by-waste  basis,  including  a  brief
              description of  the waste and its source,  its waste category, and a listing
              of "Acceptable" and "Preferred" management practices;

              Handling    practices   cover    waste    minimization,    waste    storage,
              testing/analysis  and requirement where appropriate.

       •      Disposal  practices include  waste  transportation,  types  of  disposal
              methods,  appropriate record to  keep,  and specific  disposal locations and
              companies  to  use.

       •      To facilitate  locating wastes   in  the plan, wastes  are grouped  by  the
              operation  from which they are generated:

               1.   Production Operations - Wastes are grouped as follows:

                    Production Wastes - wastes from routine field production  operations
                    Workover/Completion Wastes - wastes from well work handled by the
                                                 Production Department
                    Special Wastes - for non-routine or unexpected wastes, such as PCS's
                                      or  asbestos).

               2.   Drilling  Operations - Wastes are grouped as follows:

                    Drilling  Wastes -   for waste generated  from operations  associated
                                        with  a drilling rig
                    Workover/Completion Wastes -  for waste generated  from operations
                                        associated with a pulling unit or completion rig
                     Non-Rig Operations Wastes  - for  wastes from operations not requiring
                                        a rig such  as  wireline work
                     Special Wastes -    as addressed in the Production section above

               3.    Gas Plant Operations  -  Wastes are  grouped  only as Gas Plant Wastes
                     and Special Wastes.

 Section III:   District/Company Waste Management Policies and Practices

               Relevant  Company  or  District  policies   or  guidelines  related  to waste
               management are included.

        •       Such general policies  or guidelines may include:  Hazardous Waste Handling
               and Disposal,  Identification and Handling of Unidentified Materials, and
               Selection  of Waste  Contractors.

 Appendix:      Summary of APE Guidance or Onshore Solid Waste Management in Exploration
               and Production Operations

               This  is included  for  the  plan's users and reviewers because the plan is
               heavily reliant on the API/EGD as a  reference for regulatory, technical
               "and environmental  information  regarding  oil field  waste management.
                                         107

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                                                                   Environmental Manual
Section
      Waste Management Plan
      Southeast New Mexico
Subject
       TANK BOTTOMS & BS&W
2.1.5  TANK BOTTOMS AND BS&W

Tank bottoms or BS&W (basic sediment and water) is an oil field term referring to solid and
emulsified waste that settle out of crude oil into tanks and process vessels. BS&W is normally
a liquid heavily laden with solids and often entrained with produced water.

Category: Exempt Waste
 Handling and Disposal

 1.   Preferred Handling and Disposal - An approved tank cleaner or hauler* should be used to
     remove and transport BS&W. Contractors handling BS&W should be disposing of the non-
     saleable  fractions  at a facility  approved to accept such material*  (i.e.,  permitted by
     NMOCD).

 2.   Acceptable  Handling - If/when an approved tank cleaner is not available,  company
     personnel may be used to remove and store the BS&W. Disposal at an approved disposer*
     is still required.

 3.   Removal of BS&W from the vessels should be done in a manner where no spillage occurs.
     Use of drip pans, plastic liners or catchment vessels are recommended to ensure this.

 4.   If BS&W has to be stored, rigid containers are preferred.  BS&W should never be stored in
     (even temporarily) in lined pits.

 5.   Records related to the disposal of BS&W should  be retained for at least three  years,
     including:
         Date of shipment
         Hauler's name and approval number
         Disposer's name and approval number
      Source/location of origin
      Volume of load
          See Section 3.2 for a list of currently approved waste disposers and the process of
          selecting waste contractor. If a list is not available, check with the Area Production
          Superintendent.
  Date
               12/89
Page
                   2.1.5.1
                                        108

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THE ATTENUATION OF THE AQUIFER CONTAMINATION  IN AN OIL
REFINERY STABILIZATION POND
P.M. Buchler
Sao Paulo University
Chemical Engineering Department
Box 8174, Sao Paulo, SP, 01000, Brazil
Abstract

The infiltration of oil  derivative  organic compounds  in  the
underground water  in  a refinery  stabilization pond can be
reduced by lining  it  with  a  sodium  bentonite modified by the
tetramethylammonium cation.  Wyoming bentonite as well as a
Brazilian bentonite were tested  in  the pre.sent study. The
hydrophobic nature of this ammonium quaternary cation makes
yhe silica-alumina surface of  the clay more receptive to
organic molecules  and, above all, to polar organic molecules,
Some organic compounds typical of the oil industry waste
waters were tested at temperatures  close to the ambient.
Isotherms were plotted and their shapes were compared with
Freundlich isotherms. The  correlation coefficients found for
all isotherms were close to  0.9  showing that the Freudlich
isotherm is in good agreement with  the results of this
adsorption study. Adsorption is  higher at lower temperatures
meaning that in the winter underground contamination  tends
to be smaller.The  adsorption of  phenol at 1,000 ppm and  20 C
has shown a removal effectiveness of 85%. For lower
concentrations and higher  temperatures the adsorption was
less effective. The linear nonpolar organic molecules had
shown a lower adsorption pattern.
                            109

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Introduction

Stabilization ponds are economical devices to treat  liquid
effluents of the oil industry. If the soil where the pond is
built is a sandy one then the infiltration of the waste water
in the aquifer may poison the underground water.

The objective of this paper is to propose a lining mixture of
regular soil and clay for oil refinery stabilization ponds
which impermeabilize the pond and, at the same time, adsorb
the organic pollutants present in the waste water. Strong
attention will be devoted to phenol because of its high
toxicity (40 mg/1) as compared with the other  pollutants
present in the waste and because of its polar nature which
makes it likely to be easily adsorbed by organophilic
bentonites. These bentonites are clays modified by the
substitution of the interlayer sodium cation by a quaternary
ammonium cation. Sodium bentonites are very impermeable. The
quaternary ammonium cation derivatives are organophilic but
not impermeable. Therefore the lining of the pond must be
prepared with a mixture of regular soil (as filling), sodium
bentonite and the organo clay. Several quaternary ammonium
cations are available for purchase. The tetramethylammonium
cation is very effective to adsorb most organic molecules.
But because of its high cost the preference is towards the
tallow oil derivatives. This is the so called fatty ammonium
quaternary cation. The resulting cation has three nytrogen
bonds replaced by methyl groups and the remaining fourth
bond is replaced alternatively by linear saturated radicals
with 12, 16 and 18 carbon atoms. These are radicals derived
from the palmitic, oleic and fumaric fatty acids.
                             110

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Literature Review

The hydrophilic nature of sodium bentonites makes  them a poor
adsorbant for organic molecules (4). Therefore other cations
besides sodium were tested to improve the organophilic
properties of these clays. The first trial was to  replace
sodium by the most simple ammonium cation, i. e.,  tetramethyl^
ammonium cation (1). Sodium bentonites swell very  easily in
water and it can expand up to 15 times its original volume.
This means that the small clay particles (2 |im in  size) tend
to defloculate in water and these swelling and defloculating
properties make them a powerful impermeabilizing agent to be
used in dams and reservoirs (2).

The bentonite modified by a quaternary ammonium cation can
become a better adsorbant for organic molecules (5). The
proposed explanation is that the hydrophobic nature of the
cation makes the clay surface more receptive to organic
molecules. The presence of organic groups bonded to the
nitrogen atom in the space between the layers of silica and
alumina in the structure of the clay is responsible for the
solubilization of the organics and its later adsorption.  The
tetramethylammonium bentonite is very effective in the
adsorption of organics but other quaternary ammonium cations,
in spite of being less effective, can also be used (3).
Materials and Methods

Four different organo clays were used in this series of
experiments: two derived from Wyoming bentonite and two
derived from a Brazilian bentonite.The quaternary ammonium
cations used were tetramethylammonium and a cation derived
from hydrogenated fatty acids.

The Brazilian bentonite has originally calcium cations
between the layers of silica and alumina of the clay mineral
structure. Therefore it has to be modified with sodium
carbonate in order to become a sodium bentonite.
                              Ill

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The Wyoming bentonite is a sodium bentonite with  a high
content of the clay mineral smectite (90%). The purity
of the Brazilian bentonite is lower than that  (70%).
Method to Modify the Sodium Bentonite

The sodium bentonite is suspended in an aqueous solution of
the quaternary ammonium chloride for 24 hours under agitation,
After centrifugation the bentonite is washed with water until
no free chloride is present (test with silver nitrate). The
modified bentonite is then dried at 60 C and after that
ground into a fine powder.
Method to Measure the Adsorption of Organics on the Surface
of the Clay

The concentration of the organics in solution is measured by
the TOG (Total Organic Carbon) method using sodium
persulphate as an oxidizing agent.  The carbonic gas
concentration generated by the oxidation of the organic
matter is measured through infrared spectrometry.
Results and Discussion

Results are shown on Figures 1 and 2.  The adsorption of
phenol on Wyoming bentonite exchanged with tetramethyl-
ammonium cation is the most effective. Evidence of this
fact was already shown in the literature (5) when several
adsorbants were tested with an aqueous solution of phenol.
The present experiments show that the isotherms at 20°C are
in good agreement with the Freudlich isotherm. The
correlation coefficients are in the vicinity of 0.9. The
polar nature of the phenol molecule makes its adsorption
more effective than that of the hydrocarbons tested. The
tetramethylammonium derivative is better than the fatty
acids derivative used but the cost makes this last one more
competitive.
                            112

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Wyoming bentonite derivatives give better results  than  the
Brazilian bentonite because of its higher content  of  the
clay mineral smectite.
Conclusions

A mixture of regular soil, sodium bentonite and a bentonite
modified by a quaternary ammonium cation derived from
hydrogenated fatty acids can be used as a liner in a refinery
stabilization pond both as a sealing agent and also to
attenuate the infiltration of organic pollutants in the
aquifer.
 Acknowledgements

 This work was made possible, in part, thanks to a grant from
 the Sao Paulo State Foundation for the Support of Research
 (FAPESP - Process no. 86/0650-6).
 References

 1.    R.M. Barrer, D.M. MacLeod, Activation of
      montmorillonites by ion exchange and sorption
      complexes of tetra-alquil ammonium montmorillonites,
      Transactions of the Faraday Society, 51, 1955, 1290-
      1300.

 2.    P.M. Buchler, D. Warren, A.I. Clark, R. Perry, The use
      of clay liners in the attenuation of the organic load
      of vinasse in developing countries, Proceedings of the
      International Conference on Chemicals in the
      Environment, Lisbon, 1986, 715-724.
                            113

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3.    P.M. Buchler,  The effect of exchangeable cations on the
      permeability of a bentonite to be used in a stabilization
      pond          liner, presented at the International
      Symposium on Processes Governing the Movement and Fate
      of Contaminants in the Subsurface Environment, Stanford,
      1989, to be published in Water Sciences and Technology,
      July, 1990.

4.    R.E. Grim, Clay Mineralogy, McGraw-Hill Book Company,
      New York, 1953.

5.    M.B. McBride,  T.J. Pinnavaia,  M.M.  Mortland,
      Adsorption of aromatic molecules by clays in aqueous
      suspensions, Advances in Environmental  Sciences  and
      Technology, 8(1), 1985,  145-154.
                            114

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30
20
10
  TMA-tetramethy1ammonium
  FDA-fatty acids derivative
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                                         phenol on FDA
                                      C  on TMA
                                       8
                                      C  on FDA
                                       o
                                          on TMA
                                         C   on FDA
      200    400     600    800     1000
      Equilibrium concentration (ppm)
Figure 1  Adsorption of some pollutants from
         oil refineries waste waters on
         Wyoming bentonite modified by
         quaternary ammonium cations.
                       115

-------
    20
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                                               phenol  on FDA
                                      C0  on  TMA
                                        8

                                      C   on  FAD
                                        8

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                                      C    on FDA
     200     400     600    800      1000

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Figure 2 Adsorption of some pollutants  from

         oil refineries waste waters on a

         Brazilian bentonite modified by

         quaternary ammonium cations.
                         116

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BP SUPERWETTER - AN OFF-SHORE SOLUTION
TO THE CUTTINGS CLEANING PROBLEM
Geraldine Shaw
Business Development Manager
BP Chemicals, London, England
Barry Slater
Chemist
BP Chemicals, Hull, England
 INTRODUCTION.

 Drilling  with oil  based mud  (OBM)  provides  many technical  and economic
 advantages, and can be virtually  essential for some geological formations.
 However extensive studies,  especially  in and around Europe have shown that
 areas  of  the sea  bed,   where oily  cuttings  have,  accumulated  from  OBM
 drilling  operations,  suffer  marked  physical,  chemical  and  biological
 changes.

 A ban  on  the  discharge of oil contaminated  cuttings  has  been in operation
 in the USA  for  several  years.  However  existing  legislation  in  Europe
 affecting operations  in  the  North Sea  permits a controlled  discharge  of
 oily  cuttings waste.   In  Norway  and Holland the level of  discharged oil,
 averaged  over the well sections drilled with OBM,  must not exceed lOOg for
 every  kg  of  dry  cuttings residue, (10%w/w).  In the United  Kingdom North
 Sea the allowable discharge  limit  is 150g/kg,  (15%w/w).

 Cuttings  cleaning procedures  generally  follow one  of  two  main regimes.

 i) Base Oil Wash:
 Oily  cuttings are  slurried into low toxicity  base  oil before being pumped
 through  a  combination of low and high speed  decanting  centrifuges which
 achieve the solid-liquid  separation. Cuttings discharges  from the
 centrifuges are flushed  into  the  sea and the recovered fluids are recycled
 around the  cleaning system.

 ii) Surfactant Wash:
 Oily  cuttings are  mixed  into an aqueous surfactant solution  by means of a
 rotating  washdrum where  the majority of the  cuttings are removed from the
 cleaning   solution  by   feeding   the   mixture  over  a  shaker.   Cuttings
 separated by   the shaker  are  discharged  overboard and the fines / oil /
 surfactant  solution,  are  further  processed  through  a  combination  of
 decanting and disc-stack centrifuges   to  effect separation.   The cleaning
 solution  is recycled  around the hardware.
                              117

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Each of these systems is shown diagrammatically in Figs.  1 and 2.

In  the  near  future  oil  on  cuttings  discharge  limits  are  going  to  be
reduced.  Whereas   the  systems   available  now   can  meet   the   10%w/w
requirement, they are  not  capable of meeting   any limit  set significantly
lower than this. Over the next year  new legislation will  be implemented  in
Norway  and  within  2-3 years is  is  almost inevitable  that  Holland and the
UK will also reduce the allowable discharge of  OBM.
A research project within British Petroleum has looked at this problem and
developed a novel  type of  cleaner,  which  is  operational  in  an off-shore
environment, to  substantially  reduce the  retained oil on  drill cuttings.
It  is the development and testing of this cleaner  that is  described below.

Novel Cleaner Concept.

The  cleaning fluid works  neither as a solvent nor  an emulsifier  but by
displacement.  The  cleaner  preferentially wets  the   surface  of  an  oil
contaminated cutting, displaces  the  oil  and since  the  cleaner  does not mix
with or emulsify oil  the two liquid  phases  separate.  Oil,  having the lower
density,  forms  the  upper phase which can  be  'decanted' off and  the lower
phase cleaning  fluid  is recovered and recycled.

EXPERIMENTAL.

The test  results  of  two   cleaning formulations,  coded  K5T  and  CJD40
respectively are described here. The test work  is  in three  stages;

          i) Laboratory evaluation
          ii) Pilot  scale studies
        iii) Full scale off-shore tests

i)  Laboratory Evaluation.
The  evaluation  technique  used   in   the  laboratory  utilised   simple
controlled  mixing  of  cuttings  and cleaner followed by filtration.  Several
types   of  oily  cuttings  were  used  in  the  laboratory tests  ranging  in
geology,  type  of drilling mud and  degree  of  contamination. In all  cases,
the mud  oil component  was BP   83HF  as  supplied by BP  Chemicals.  The
cuttings  samples  were  from  a  number of BP  North Sea and UK land  based
operations. The cuttings tended  to be small (from  the  8.5"  and 6" well
sections),  and were therefore, ca.<5mm  in size.

Cuttings  were mixed with the cleaner in  ratios  of  1:5  to 1:2
prior  to  filtration,  and in some  instances a further  washing stage  using
sea-water.  The  cleaned cuttings were collected and measured  for residual
oil content.  The  collected recovered  fluids  separated  into  two  phases,
cleaner and oil.  The  cleaner  could then  be  used  again  to treat  further
oily cuttings and the composition of both phases could be analysed.
Comparison  cleaning experiments were carried out using a 5%v/v solution
of  a commercial  surfactant  ('By-Prox',ex BP)  and low toxicity base  oil
(BP83HF,  ex BP) as  cleaning media.
                              118

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A number  of  drying  experiments  were  carried out  on  some of  the cleaned
cuttings to  assess the  efficiency of  low temperature  thermal techniques
for removing residual  cleaner  from  the  treated  rock  cuttings.  Several
samples of   cuttings  were  simultaneously  weighed  into  glass  laboratory
petri-dishes and  placed  in an  oven at  either  140 C  or  180  C (  284 or
356 F ). After 1,  6,  and 16 hours of being  in  the oven individual samples
were  removed  and  their  oil,   cleaner  and   total   moisture  contents
determined.

The analytical techniques used are described at  the end of this  section.

ii1) Pilot Scale Studies.
Two different  types of hardware  were used  in  the pilot  scale  test  work.
The first was  based around a decanting centrifuge  performing the  majority
of  the  solid-liquid separation and  in the second,  the  largest  proportion
of  the  cuttings were separated from the cleaner  on a  shaker  screen.  These
are shown schematically in Figs.  3  and 4.  The  hardware  was  supplied and
set up  on behalf of  BP by Thomas Broadbent  and Sons  Ltd  (TB&S)  at  their
laboratory facilities in Huddersfield,  England.

The  cuttings used  in these  studies  were obtained from  several  drilling
locations  and as  such  provided a  variety  of  geologies  and  mud  types.
Pipework  restrictions meant that  the cuttings  needed  to be  10mm or  less
and  were  therefore  sourced  from  the  8.5",   6"  or  lower  12.25"   well
sections.

Using  the decanting centrifuge apparatus  (Fig.3),  cuttings were  mixed with
the  cleaner to a  slurry concentration of  30%v/v  and kept  in  suspension
using  a mechanical stirrer.  After mixing for 3  mins.the  slurry  was  pumped
to  the  laboratory  decanting centrifuge.This  centrifuge  was a  150mm x  300mm
heavy  duty  horizontal  solid bowl  decanter centrifuge, working  at  2450rpm
 (510G). The  slurry  was  pumped at  a  flow rate of  11-12  1/min and samples of
produced  cake  and  recovered fluids were taken for  analysis.

Experiments  using  the shaker  screen  apparatus (Fig.4).  cuttings  were  mixed
with  the  cleaner  to a concentration of 30-40%w/w and the  cuttings  were
held  in  suspension in a  specially  designed mix  tank with  a  low  shear
agitator. This mix  tank was located  directly above the  leading edge  of the
shaker  screen. The screen itself was a modified  full  size oil-field  shale
 shaker.  The majority of  the  shaker  was blanked off  to leave a  channel
 300mm  wide   running  the full length  of the  shaker.  The  cuttings,  having
been contacted with the cleaner  for a fixed  time  (usually 2mins)  were fed
directly  from the  mix  tank onto  the shaker where they  were  transported
 down the  channe1.
 Samples  of  cuttings  were  taken  from  the  shaker  for  oil-on-cuttings
 analysis. The  underflow from  the  shaker,  which  consisted of fines,  cleaner
 and oil was further separated  through  decanter  (4000rpm, 1350 x g)  and
 disc  bowl  (10,500rpm,  4000  x  g)  centrifuges.  Samples  of  the  separated
 fines  and each of  the liquid phases were collected.
                              119

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ill) Full Scale Off-Shore Tests.
A limited amount  of  test work has been completed  on two BP drilling  sites
in the Norwegian  sector of the North  Sea.  This test work used both  types
of existing cuttings cleaning hardware ie;

     - a combination of  decanting centrifuges
     - a washdrum type system

(see Figs. 1 and 2 for schematics of these  types of  systems).

These  tests  were  carried out  with permission from  the Norwegian State
Pollution  Control  Authority  and  cooperatively   with   BP  Norway,  Thomas
Broadbent and Sons Ltd.  and Swaco Geolograph (Aberdeen,  Scotland).

In  each  case the cleaner  was used  in the existing  hardware  as  a  direct
substitute  for  either  low  toxicity base  oil   or  surfactant solution,  no
modifications were made  to optimise the cleaner/hardware combination.
Throughout several  short trials oily cuttings  from  the 12.25, 8.5  and  6"
well sections were  treated.  Cuttings  were  processed through  the  hardware
and samples were  taken for analysis at each solids discharge point.  In the
decanting centrifuge set-up this meant collecting  samples from the primary
and  secondary decanters.  From the wash-drum   system,  samples of  cleaned
cuttings  and fine   solids  were  collected from   the  shaker  screen,   the
decanting centrifuge and the  disc stack centrifuge.  Recovered  fluids  were
also collected for analysis, ie. both cleaner and  separated  oil.

ANALYTICAL TECHNIQUES.

Oil-on-Cuttings analyses were carried out using a  standard mud  retort. The
volume of oil collected  is  converted to  weight and results  were  expressed '
as  %w/w  oil  on  dry  cuttings  residue.  Levels of residual  cleaner  and total
moisture  of  the  cuttings  were measured by converting  each of the fluid
phases condensed  by  the retort to  weights  and totalling these weights  to
express  the  results  as  %w/w  on cutting as discharged. The mass balance  on
each of  the mud retort experiments  was checked  and agreement within  2% was
considered acceptable for the data  to be used.

Chemical  Analysis  of  the  recovered  oil  and cleaner  phases  from  the
cuttings  cleaning  experiments  was  conducted using   a laboratory  gas
chromatograph.

RESULTS.

i) Laboratory Experiments.
Table  1  sets  out  cuttings cleaning data  obtained  in the laboratory using
both the  K5T  and  CJD40 cleaners.  In Table  la  the  results show that a low
toxicity  base oil wash and a  surfactant  wash   reduce oil-on-cuttings  from
18.7%w/w  to  12.6%  and  13.2%  respectively. Under  the  same  experimental
conditions, K5T reduced  the oil-on-cuttings to  2.3%w/w.
                              120

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Removing the  water  wash stage  from  the laboratory  experiments  did  not
significantly affect the de-oiling efficiency  of K5T.  Table  Ib  shows  a
reduction in oil content of cuttings  contaminated with  'all-oil'  drilling
mud from 27%w/w  to 7.5-10%w/w.  K5T performed slightly  better on  cuttings
contaminated with  an  80:20  drilling mud,  reducing  oil-on-cuttings  from
21.1% to 3.3-5.8%w/w.
Cleaner  CJD40  reduced  the  level  of oil-on-cuttings in  lab  tests  from
14.3%w/w to 5.1-6.1%w/w. These results are shown in Table Ic.

Cuttings which had been treated  in deoiling experiments by  either K5T or
CJD40, were  dried'  at  140  or 180°C.  As  the  results in Table  2 show
show,  significant   reductions   in  cuttings  moisture  content  could  be
achieved in  relatively  short times using these  low temperatures.  At 140 c
cuttings treated using  K5T reduced from  29.1%w/w total moisture  to just
5.4%.  Concurrently the  level of  oil  on  the  cuttings  reduced  from  9.8% to
2.0%w/w. Total moisture includes residual oil,  cleaner  and water.  After 3
and  6 hours total moisture levels stood  at 3-4%w/w  and the  residual oil
remained constant  at l-2%w/w.
At 180 C,  as expected,  the  cuttings dried more  quickly  and after  1 hour a
total moisture  content of  26.9%w/w  had  been  reduced  to  2.2%w/w.  Again
there was  an associated reduction in the oil content of the cuttings, from
9.6%  to 1.0%w/w.  After 6  hours  in  an  oven test  at  180 C,   the  residual
oil-on-cuttings  had fallen  to   a  level   which  was  so  low  as  to  be
undetectable by  retort  analysis.
A similar  phenomenon was observed from drying cuttings treated by CJD40 in
an laboratory oven  at  140 C.  An initial  moisture   level  of  23%w/w  was
reduced in  1  hour  to  3.6%w/w.   The oil-on-cuttings  of  the  sample  was
relatively  low  prior   to  the   'drying'  experiment  at  3.4%w/w  (sample
collected  from pilot scale  studies),  however this  reduced  further  to 2.4%
after a 1  hour thermal test  and  to 0.5-l%w/w after periods of >3  hours at
 140°C.

 ii)  Pilot  Scale  Tests.
As stated  earlier in the text,  these tests  were carried out  on two types
of hardware  each of which  carried  out the primary solid/liquid separation
 stage  in  a  fundamentally  different way.   The  first   used  a  decanting
 centrifuge to perform  the  separation  (Fig.3)  and the  results of  these
 experiments  are  shown in Table 3a. During these  tests K5T  was used as the
 cleaning medium. K5T reduced the  residual oil level of cuttings having oil
 contents   of  39%,  45%,   and   18.6%w/w,   to   4.2%,   5.2%,   and  3.7%w/w
 respectively. Under  identical experimental conditions, a low toxicity base
 oil wash reduced the oil content of  these same  cuttings to 12.5-14.4%w/w.
 The  K5T cleaner.therefore  removed  80-90%   of  the oil  from  the  cuttings
 compared to  an efficiency of  63-72% for  base oil.

 The second type  of hardware used a shaker screen as  the main solid/liquid
 separating method  (Fig.4).  Cuttings cleaning experiments were carried out
 using both the K5T and  CJD40  cleaners. The detailed results of these tests
 are shown  in Table 3b.  After cleaning in K5T, oily cuttings  from a 12.25"
 well section,  with an initial oil  content of 7.5%w/w,  were reduced in oil
 content to  1.3-3.6%w/w.  Similarly,  cuttings  from  a  12.25"  well  section
                              121

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with  an initial  oil content  of  8.45% were  cleaned  with CJD40  to  give
cuttings containing only  1.4-3.0%w/w  oil.

In both sets of experiments once  the majority of  the  solids were  removed
from  the system.  The large  solids are  removed by  the  primary separation
stage  and the  fine solids  are  flocculated by  the cleaner so  that  the
majority are removed by the  secondary separation hardware. The cleaner  and
oil split into  two separate  layers  allowing  recovery of both.

iii)  Full Scale Off-Shore Tests.
The initial  off-shore test  work reported here utilised  the K5T cleaner in
both  types  of existing  cuttings  cleaning  hardware  (ie.  the  decanting
centrifuge system and the washdrum  system  shown  in  Figs.1  and 2).
In  the  decanting centrifuge system K5T reduced  the oil-on-cuttings  of a
relatively contaminated feed containing 17.3%w/w  oil to ca. 6.8%w/w (Table
4). This represents  a cleaning efficiency of 61%.  By comparison  when the
system was  switched back to low toxicity base  oil, the  level of  oil on
cuttings was 13%w/w, representing a cleaning efficiency  of 25%.
The same cleaning  formulation  was used in a  wash-drum  system.  The results
of  this test are  shown  in Fig 5.  Over an  800m section  of  a section of the
12.25"  well K5T  reduced  the  oil-on-cuttings to an average of  3-3.5%w/w
with  a best result of 2.5%. Throughout the  trial the well  was  drilled at
full  rate  (ie. 40-60m/hr)  and  all   the  cuttings  were  fed  through  the
cleaning system. Oil and  cleaner  separation  was  achieved in the disc stack
centrifuge  so that the cleaner  could be  recycled  to the  cleaning  system
and  the purity  of the  recovered oil  was  measured   at >98%.  The  oil
therefore  was  more  than suitable  for recycle  back  to   the  active  mud
system.

DISCUSSION

In  laboratory,  pilot  and  full   scale experiments  both  K5T  and  CJD40
cleaners have been shown to provide  superior deoiling of  drill  cuttings,
to  levels  substantially below what is  achievable with  current  technology.
The   full  scale tests  confirmed  that,  because  of  the  enhanced  surface
activity of  this type of  cleaner,  a less attritive  hardware arrangement is
preferable.  The washdrum  /  shaker system  (Fig 2) caused less breakdown of
the  cuttings  than  the decanting  centrifuge  system (Fig  1)  and  thereby
reduced the  level  of fines  which had  to be  separated,  keeping  the cleaner
in  better condition.  In  the light of  these  findings the project work is
continuing  to  further  optimise  a  hardware  combination for this type  of
cleaner.
Residual cleaner on  the cuttings  can  be efficiently  removed using  low
temperature  drying.  It  should be  noted that the drying process  described
in  this paper  provides  relatively  inefficient  heat  transfer  to  the
cuttings.  In correctly  engineered  drying  hardware  it is  anticipated  that
cuttings from the  cleaning  hardware  could be dried on a  continuous basis
using  steam  as a  heating  medium for the  process. This  would  provide
cuttings for   subsequent  disposal  containing  <2-3%w/w  oil  and  <5%w/w
cleaner.
                              122

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A small degree  of cross  contamination of  cleaner  into the  recovered oil
was noted during gas  chromatography analysis. The  levels  of contamination
were <10%,typically 2%w/w. Mud compatibility  experiments in the laboratory
where fresh and used muds were  deliberately  contaminated with up  to 20%
cleaner showed  that  even at  this improbably  high  level  of contamination
the rheological properties of the mud were  unaffected.
The K5T / CJD40 cleaned cuttings behaved  differently  to oily cuttings. The
cleaning process  left  the cuttings  'water  wet .  When  these  cuttings were
dropped into water they broke  up and dispersed easily.  It is anticipated,
therefore,  that  when the cuttings  are discharged  directly  into  the sea,
they would disperse  in a  similar way to  cuttings discharged from drilling
operations using water based mud and would  not form the localised cuttings
pile observed  as  a result of  oily  cuttings discharge.  Additionally, both
these cleaners  are water  dispersible and any cleaner  left on the  cuttings
when they  were  discharged  would disperse  into  the  upper  layers  of the
water column where it would be available  for aerobic biodegradation.
In  terms of  their  physical   properties,  both  cleaners  are water  white
liquids. The flash point  of K5T is 66°C_(by ASTM D93)  and  CJD40  is >100°C.
The density of  these fluids is 0.96g/cm  .

CONCLUSIONS

In  order  to  reduce the environmental  impact  of oily cuttings and  support
the continued  use  of oil  based mud in drilling operations,  novel  cleaning
fluids  have  been  developed  which can  substantially   reduce  the level  of
residual oil on cuttings.
The  cleaners  have been tested in laboratory, pilot  scale and  full  scale
equipment and  the results show that cuttings  can be  reduced  from  >20%w/w
to  <2%w/w oil.  A low temperature  drying process  can quickly  reduce the
total  moisture hold-up  of the cuttings  (ie.  oil,  cleaner and water) from
>20%w/w to less  than 5%.
The  cleaners  have been formulated for  off-shore  use  and  produce  cuttings
which  are  'water wet' and easily break up and  disperse  in  a water column.
The  development  of  a  fully   optimised  hardware / fluid combination  is
continuing  with  the  aim of  producing  cuttings for  disposal  containing
<2-3%w/w oil  and <5%  cleaner.  It is anticipated that  the  development will
be  complete by  the end of 1990.

ACKNOWLEDGEMENTS

The  authors  would  like   to  give special acknowledgement  to Dr.  Charles
Jeffrey and  Miss Tracey Smethills  of  BP  Research,  Sunbury-on-Thames,
England, and to  Mr.  Charlie Dye of BP Chemicals,  Hull,  England.  Thanks are
also due to BP  Norway for their assistance  during the  off-shore  trials.
We  would like to acknowledge  the staff  at  Thomas Broadbent  and Sons Ltd,
 especially  John  Wright  and  Steven  Howe  and  also  staff  from  Swaco
Geolograph, particularly  Dave  Simpson and Jim  Hamill.
                              123

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                                  TABLE 1

               LABORATORY CUTTINGS CLEANING EXPERIMENTS
a) Cleaning --> Water Wash --> Filtration

            Cleaning Solution                   %w/w oil on  dry
                                               cuttings residue

             * None                                    18.7
             * None                                    17.6
        5% Surfactant in Water                         13.2
             Base Oil                                  12.6
              K5T                                       2.3
              K5T                                       2.4
b) Cleaning --> Filtration

Cuttings Type         Cleaning Solution         %w/w oil on dry
                                                cuttings residue

  (i)                  * None                          27.0
'all-oil'                K5T                            7.5
  mud                    K5T                            8.5
                         K5T                           10.0
 (ii)                 * None                           21.1
80:20 mud               K5T                             3.3
                        K5T                             3.3
                        K5T                             5.8
                        K5T                             4.2
                        K5T                             5.2
                        K5T                             3.6
   Cleaning --> Filtration

         Cleaning Solution                       %w/w oil on dry
                                                cuttings residue

             * None                                    14 _ 3
               CJD40                                    5[ i
               CJD40                                    5' 9
               CJDAO                                    5.' 5
               CJD40                                    6'. 1
                             124

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                                 TABLE 2

                LABORATORY CUTTINGS DRYING EXPERIMENTS
a") Cuttings Cleaned Using K5T Cleaner
Oven Temperature
    Tc)
  140
  180
     Time
    (hrs.)
     0
     1
     3
     6

     0
     1
     6
    16
     Cuttings Analysis
(%w/w oil)           (%w/w total
                      moisture)
   9.8
   2.0
   1.0
   2.0

   9.6
   1.0
   (0)
   (0)
29.1
 5.4
 3.4
 4.1

26.9
 2.2
 2.4
 1.2
b) Cuttines Cleaned Using CJD40 Cleaner
 Temperature
  140
 Time
(hrs.)
 0
0.5
 1
 3
16
24
       Cuttings  Analysis
   (%w/w oil)       (%w/w  total
                    moisture)
    3.4
    2.6
    2.4
    0.7
    0.5
                                           0.5
23
4.0
3.6
2.2
1.8
1.8
                              125

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                                 TABLE 3

                 PILOT SCALE CUTTINGS CLEANING TRIALS
a) Decantine Centrifuge Apparatus
 Initial Oil on
 Cuttines %w/w
  39.0
  45.0
  18.6
     Base Oil Wash
 Residual OOC    % oil
    %w/w        removed
    14.4
    12.5
 63
 72
                     K5T Wash
              Residual OOC     %  oil
                %w/w         removed
 4.2
 5.2
 3.7
89
88
80
b) Shaker Screen Apparatus
 Initial Oil on
 Cuttings %w/w
 7.5
    Base Oil Wash
Residual OOC    % oil
   %w/w        removed
   3.9
 48
 Initial Oil on
 Cuttines %w/w
 8.45
    Base Oil Wash
Residual OOC    % oil
   %w/w        removed
                    K5T Wash
             Residual OOC    % oil
               %w/w         removed
2.6
1.3
2.3
1.6
1.8
3.6
65
82
69
77
76
52
                  CJD40 Wash
              Residual OOC   % oil
                %w/w        removed
                               3.02
                               1.39
                               2.47
                               1.96
                               2.67
                               64
                               84
                               71
                               77
                               68
                                 TABLE 4

              FULL SCALE OFF-SHORE CUTTINGS CLEANING TESTS
 Initial Oil on
 Cuttings %w/w
    Base Oil Wash
Residual OOC    % oil
   %w/w        removed
                    K5T Wash
              Residual OOC   % oil
                %w/w        removed
   17.3
  13.0
24.8
                                                     6.8
               61
                               126

-------
FIGURE 1
A BASE OIL WASH IN A CENTRIFUGE-CUTTINGS CLEANING SYSTEM.
            CUTTINGS &
             BASE OIL
                                               CLEANED
                                               CUTTINGS
            CLEAN OIL TO ACTIVE MUD PIT
                                               CLEANED
                                                 FINES
 FIGURE 2
A SURFACTANT SOLUTION USED IN A WASH DRUM SYSTEM.
         OILY CUTTINGS
                                  DRYING SCREEN
                                         CLEAN CUTTINGS
       WASH SOLUTION
       RECYCLED TO
       WASH DRUM
            J^LS\
            	•  3 PHASE   •—x-«  DECANTING  I
        CLEAN
         FINES
CLEAN
FINES
                      127

-------
            AGITATOR
                                            DISCHARGED
                                              CLEAN
                                              SOLIDS
         RECOVERED
           FLUIDS
         (CENTRATE)
             CUTTINGS/CLEANER
             MIX TANK
              FIG  3   SCHEMATIC OF DECANTING CENTRIFUGE APPARATUS
                      USED FOR PILOT SCALE CUTTINGS CLEANING STUDY.
                AGITATOR
                        CUTTINGS/CLEANER
                           MIX TANK
                                               DISCHARGED
                                               CLEAN CUTTINGS
                 FIG.  4.  SCHEMATIC OF SECOND STAGE APPARATUS USFD

                 	FOR PILOT SCALE CUTTINGS CLEANING STUDY.
FIGURE  5
              OIL RETENTION ON CUTTINGS - OFFSHORE DATA
                    1600
                            2000
                                    2200
                                             2400
                                                      2600
                       I RIG SHAKER  DEPTH (M)
— CUTTINGS CLEANING
"SHAKER
                                128

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BRINE  IMPACTS  TO  A TEXAS SALT MARSH AND SUBSEQUENT  RECOVERY
W. Bozzo,  M.  Chatelain,  J. Salinas, and W. Wiatt
Boeing Petroleum Services, Inc.
850 South  Clearview Parkway
New Orleans,  Louisiana  70123
Introduction

Salt water production is commonly associated with  oil  field activities.   Crea-
tion of hydrocarbon storage facilities  in salt domes produces  large quantities
of concentrated salt water (brine).  Common disposal methods include deep well
injection to salt water sands and dispersion via pipeline  into surface waters.
These  activities  are regulated  by  both  state  and federal  provisions of  the
Clean Water Act.

Regulatory reporting requirements for spills of salt water are not  as rigorous
as for spills of oil and hazardous substances.  These  salt water  spill report-
ing  requirements  are  described  in  terms  of a   general  prohibition  against
polluting waters of  the  state,  and are  entirely  absent from  the quantitative
spill  reporting requirements  of  the  Clean Water Act and the Comprehensive  En-
vironmental  Response  Compensation and  Liability  Act.   In  this  context  salt
water  spills may be perceived as producing less ecological  impact  than oil or
hazardous substance spills.

On  June  22,  1989.  approximately 8.3  acres  of  coastal  marsh  and the  Gulf
Intracoastal  Waterway  (ICW)  were  impacted by  a  major  failure  of a  brine
disposal pipeline.  An  estimated 35  million gallons of waste  water ranging in
salinity (as  sodium  chloride) from  zero to 274 parts  per thousand  (ppt)  was
estimated  to have  discharged over  an  eight  week  period  at two  locations.
Nearly 17 million gallons of  this water  (brine) had a  salinity of over 220 ppt
and  was  discharged  during the first 7  weeks.   Another  17 million  gallons of
brackish water  (less  than 25  ppt salinity) was used  to perform  the  flow test
which  identified the  failure.  About 24 million  gallons of salt water from a
cluster of pipeline leaks  severely  impacted about 8.3 acres of coastal marsh.
The  remaining  11  million gallons  of  salt  water  was  released  from  another
 cluster of leaks to the bottom  of the  Gulf Intracoastal Waterway where  it was
 dispersed  through  the  mixing   effects  of  currents   and  commercial  marine
 traffic.

 On discovery of the spill an  environmental assessment  was  initiated to quanti-
 fy  the extent  of  damage.   This  assessment  facilitated a  marsh recovery  study
which  was conducted over  the  following  ten months.  The study evaluated  vege-
 tative damage  and  recovery,   temporal changes  to  surface  water physicochemis-
                                 129

-------
try, groundwater impacts, and  soil  salinity impacts and recovery.   Review and
analysis of  the  resultant data produced  an excellent opportunity  to evaluate
the impact of highly  saline water to a brackish marsh,  and the  resiliency of
that marsh.
Methodology

The marsh recovery study incorporated three approaches.   Vegetation was evalu-
ated for  damage  and subsequently monitored for  recovery throughout  the  study
period.  Surface water and soil salinities were monitored to  assess and relate
physicochemical  conditions  to vegetation recovery.   Groundwater seepage  from
unconsolidated fill in the pipeline right-of-way was monitored  for  evidence  of
salt contamination.   Figure  1 is a map of the  study area showing  the  station
locations used in this monitoring program.
 Figure  1.   Salt Marsh Brine Impact Study Area.

 The  vegetation assessment consisted of quarterly  ground level evaluations of
 four vegetation  plots  (VP1 to VP3 and VPS)  established in heavily to lightly
 impacted  areas.   A  fifth  plot  (VP4)  was established  outside  of the impacted
 area as a  control.   Each plot consisted of a 10 meter  radius around an identi-
 fication  stake.    Species dominance,  as  percent  foliage cover,  and percent
 mortality  were identified  for  each  plot  area in the field by three biologists
                                    130

-------
using  the  Daubenmire method  (1).   Changes  in  species diversity  and mortality
between  assessments  were  determined.    These  assessments were  augmented  by
aerial photographs   (visible  and  infrared)  of  the  area  immediately  after
detecting  the spill,  to  help establish  the study  area  and sample  locations,
and one year  later.   Aerial and ground level photography  were  used to document
changes in marsh appearance over time.

Surface  and  soil  salinities were  monitored periodically at  twenty-six  loca-
tions  throughout the  study area.   Each monitoring  station was  identified  in
the field by numbered  stakes  recorded on a master  map (Figure 1).   Two  addi-
tional stations  in  the ICW were  monitored for  soil and  water salinity  on  a
single occasion  to  assess the  impact  of released brine  from that  portion  of
the brine line.

Surface water salinities  were  determined by in situ electronic analysis.   Sa-
linities  were analyzed at the base of the water column since  the  relative den-
sity of salt causes more  saline waters to accumulate  there.  Temperature,  dis-
solved oxygen, pH, and electrical  conductivity were also  monitored  to  supple-
ment the study data.

Routine monitoring stations were  established  in four marsh ponds  (MP-1 to 4),
three locations  in  tidal ditches  (MS-1  to  3),  and  in Mud Lake  (J) .   Control
stations were identified  as MP-4  in the  marsh ponds, MS-1 in  the  ditches, and
J  in Mud Lake which  ties  this  monitoring data to over ten years  of  historical
water quality data  there.  Two stations were  also  sampled on one occasion  in
the ICW.    Monitoring  frequency was biweekly for the first quarter followed by
monthly thereafter.

Soil  salinities were  determined  by laboratory  extraction  of  salt  using  a
deionized water wash followed by a chloride titration  of  the extract by method
4500-C1~B  (2).  Soil salinities were reported as parts per thousand  (ppt)  on  a
weight per weight basis.   Soil samples  were taken with a  polypropylene coring
 device.    Cores  were   taken  in  close  proximity  to   each field  station
 identification stake from relatively undisturbed substrate.  One  approximately
 three-inch long  surface  core  was extracted and  collected at  each station for
 laboratory analysis.

 Routine monitoring  and control stations were  the  same as those  described for
 the surface  water salinity monitoring, plus six additional stations  in  each  of
 three marsh  zones  (A-l to 6,  B-l  to 6,  and C-l to 6) in  the 8.3  acre impacted
 area.   Two  stations  (ICW-1  and 2) were  also  sampled on one  occasion in the
 ICU.   Monitoring  frequency  was  biweekly  (twice  per month) for  the  first
 quarter,  to  detect rapid  initial changes, followed by  monthly  there-after.

 Groundwater  was  monitored periodically  in three excavations (BL-1 to 3)  along
 the brine  disposal pipeline.   Water in  the bottom of  the  excavations was  ana-
 lyzed _in  situ during periods  of high water when the excavations  were flooded.
 During low water,  when the excavations  could  be  de-watered,   samples of  water
 draining  directly from  unconsolidated   right-of-way fill  were collected and
 analyzed.  Location  BL-1  is  at the pipeline break in  the  impacted marsh  area,
 BL-2  is  just north of the  ICW,  and BL-3 is at  the  beach, where  the pipeline
                                     131

-------
was excavated  for  inspection purposes immediately  prior to its entry  into the
Gulf of Mexico.  These locations  are  distributed over a distance of  nearly two
miles.  Monitoring frequency was approximately  biweekly for the first quarter
and monthly thereafter, tidal  and construction activities permitting.
Results

Vegetation assessments  were conducted on June 26,  27,  and 28; July 5;  Septem-
ber 20,  1989;  February  1;  and April 24 and 25,  1990.   The July and April sur-
veys were  supplemented  and validated by a third party marsh vegetation expert
(3 and 4).

Table 1  describes the common plant species observed  in the impacted area, and
their relative abundance.   This  species  distribution  is  typical  for a saline
marsh as recognized by  the U.S.  Army  Corps  of Engineers (5).

                                    TABLE 1
      Relative Abundance of Common Plants  in  the Study Area
        Common Name
Scientific Name            Abundance
       Saltgrass                 Distichlis  spicata            VA
       Oystergrass               Spartina  alterniflora,         VA
       Carolina wolfberry       Lycium carolinianum           VA
       Sea-oxeye                 BorrLchLa frutescens           A_
       Leafy threesquare         Scirpus robustus                A
       Wiregrass                 Spartina  patens                 A
       Glasswort                 Salicornia  sp.                  A
       Gulf cordgrass            Spartina  spartinae            LA
       Seacoast sumpweed         Iva  annua                     LA
       Narrowleaf sumpweed      Iva  augustifolia               LA
       Saltmarsh  pluchea         Pluchea purpurascens      .     R
       Seaside heliotrope       Heliotropium curassavicum      R

             A: VA «= very abundant, A » abundant, LA "= less abundant, R •= rare

 Brine  injured vegetation appeared confined to an 8.3 acre plot surrounding the
 brine  line break.   This area  was  subdivided  into  three zones,  based  on the
 severity of vegetation damage,  as described by Figure  1 and below.

    A.  Zone A is  2.5  acres extending 120  yards along the east side  of the brine
       line break area and bounded to the north by  an access  road.   The eleva-
       tion of zone  A is  low  near  the  access  road rising  in a westerly and
       southerly  direction.  Zone A is poorly drained,  allowing water  to ac-
       cumulate near  the   road.   Nearly all vegetation  in zone A was  dead and
       severely decomposed in June 1989.

    B.  Zone B is  4.6  acres located  south of zone  A  and  east  of the  brine line.
       The zone  is slightly  higher  in elevation than  zone  A, so  predominant
       drainage from  zone  B  is northerly  (towards  zone  A).   Some  water  does
                                    132

-------
     drain to  the  east  from zone B  following high  water conditions.   Some
     brine flowed easterly from zone  B  as  evidenced by an alluvial pattern of
     dead vegetation in the  eastern  part of  the  zone.   Several  shallow
     ditches  that drain  towards Mud  Lake serve zone  B.   Vegetation injury in
     zone B ranged from  completely dead to healthy in June  1989.   Injury was
     most severe in the western portion of zone  B.

  C. Zone C is  1.2 acres paralleling zone A on  the western  side of the brine
     line.  Drainage  from zone A  to  zone  C is blocked by a  low linear mound
     of fill  remaining  on the right-of-way from the original  line installa-
     tion.  Drainage  from zone A  into  zone C  occurs through low  portions  of
     the mounded right-of-way  during  high  water  conditions in the area.   Most
     drainage  in zone C occurs  in  a  westerly  direction via  a  slough  that
     transects  the zone.  Injury  in  zone  C also ranged  from completely  dead
     to unaffected vegetation  in  June 1989.  The more severely injured  vege-
     tation was confined to the  slough and low areas where brine apparently
     flowed from zone A.

Five circular  plots in zones  B  and C  were established in  areas  having  no,  and
light to heavy plant mortality.  The percent foliage  cover for  living and  dead
plants  and the percent plant mortality  by  species  in June, September,  Febru-
ary, and April are described  in Table  2.

Typical signs  of salt  injury  observed  during the  June  assessment were found  on
many plants in the vicinity of  the break.   These  signs included  complete plant
death,  and chlorosis or apical  necrosis  of  plant  leaves and stems.   Severe  de-
terioration of woody stem and root tissue was evident  on many plants,  particu-
larly those within  zone  A.   Necrotic  or abscised leaves  were not  found on  or
around  severely  deteriorated plants,  indicating that  complete leaf decomposi-
tion had  occurred.  New  growth  was found on some recovering plants within  the
alluvial  area  of zone  B  and along  the edges of the slough within zone  C.  The
amount  of decomposition  found,  coupled with the appearance of new  growth,  in-
dicates that   large quantities  of  brine  were  spilled within  the area one  to
three months prior to  identification of  the leak, and  that sufficient flushing
(see discussion) had occurred to facilitate new growth.

During  the September  assessment substantial  new  growth was observed  for  sev-
eral  predominant  species  within  certain  plots.     Salt  tolerant   Lycium
carolinianum  exhibited new  growth in  several  of  the impacted areas.   Most
striking  was   the appearance  of a   pioneer  species,  Spartina alterniflora,  in
VP5-a and b.   This salt  tolerant  plant, initially  not  present in  plot VP5-a
and b,  appeared  to have taken advantage  of  the  available niche  left by damaged
Scirpus robustus (90% mortality).   Zone  A,  which  has  no vegetation plots,  con-
tinued  to exhibit little  discernible vegetative  recovery.

An  unseasonably severe freeze  occurred  from December 21  through  25,  damaging
most of   the  remaining   vegetation.     The  vegetation  survey  scheduled  for
December  1989  was delayed until early 1990  to provide an  opportunity for  some
recovery   from  the  freeze  damage.   The high  mortality  figures  observed  in
February  are   in  large part  attributed to this  atypical meteorological event.
Jiscichlis spicata  (65% mortality) and S. alterniflora (25% mortality)
                                    133

-------
                                     TABLE 2
Percent Foliage Cover and Mortality (Death)  for Predominant Species by Plot
June
PlotA
VP1

VP2

VP3

VP4


VP5-a



VP5-b



Species CovB
Lycium carolinianum
Distichlis spLcata
Lycium carolinianum
Distichlis spicata
Lycium carolinianum
Distichlis spicata
Lycium carolinianum
Distichlis spicata
Scirpus robustus
Lycium carolinianum
Distichlis spicata
Scirpus robustus
Spartina alterniflora
Lycium carolinianum
Distichlis spicata
Scirpus robustus
Spartina alterniflora
70
30
80
20
25
80
30
60
5
30
60
10
0
10
50
75
0
1989
Death
97
100
70
85
30
25
15
5
2
10
15
15
0
95
90
95
0
Sept
1989
CovB Death
70
5
75
65
25
85
40
75
5
10
70
2
20
5
60
25
5
80
50
45
30
10
15
3
4
2
1
5
98
2
0
15
80
40
Feb
CovB
70
5
65
60
25
85
15
80
5
0
70
15
30
5
60
15
10
1990
Death
95
60
80
80
95
60
95
70
57
-
60
100
10
100
60
100
40
Apr
1989
CovB Death
65
15
45
65
15
90
10
90
5
0
75
45
50
0
85
45
25
85
10
80
15
95
15
90
10
5

5
5
5

5
5
5
     A:  VP5-a and VP5-b each represent one half of a 10 meter radius plot.
     B:  Percent cover based on estimate for both dead and living plants.

 appeared  to  be  less  adversely  affected   by  the  cold   weather  than  L.
 carolinianum (93%  mortality)  and S.  robustus  (87%  mortality).   Considerable
 new  growth and  few effects of  the  severe winter  freeze were  observed during
 the  April survey.

 Three  marsh  ponds  (MP-1, 2, and 3) were the  only surface water bodies to show
 elevated salinities as  a result of  the brine release  (Table 3).   These ponds
 are  low areas in the marsh which act as sinks,  retaining the dense brines that
 flowed into  them during the release.   Ponds  MP-2 and MP-3 returned to ambient
 salinity conditions by  August 8,  with  MP-1, the  most  severely  impacted pond
 (located in  zone   A),  returning  to  and  remaining  at   ambient conditions  on
 August 23.   Depressed dissolved oxygen,  observed in this pond  through October
 (Table 4),  was  attributed  to  decaying biomass  and high  temperatures.   All
 other  surface water  stations  were consistent with their control  stations and
 ambient conditions throughout this report period.

 Abundant fauna was  observed  in  and  around all  surface  water bodies by August
 1989.   Observed  fauna included stripped hermit  crab, Clibanarius vittatus;
                                     134

-------
                                     TABLE 3
Water, Mud,  and Interstitial  Soil Salinities  (as ppt)
Area
Marsh
Pond
Water

Ditch
and
Open
Water





Marsh
Pond
Mud

Ditch
and
Open
Water
Muds

Inter-
Station
MP-1
MP-2
MP-3
MP-4B
MS-1B
MS-2
MS-3
JB
ICW-1
ICW-2
BL-1
BL-2
BL-3
MP-1
MP-2
MP-3
MP-4B
MS-1B
MS-2
MS-3
JB
ICW-1
ICW-2
A-l
stitial A-2
Soil
Water















A-3
A-4
A-5
A-6
B-l
B-2
B-3
B-4
B-5
B-6
C-l
C-2
C-3
C-4
C-5
C-6
A: Data rei
JunA JulA
152
2
2
2
2
1
2
2





110
24
69
7
3
6
39
6


94
23
40
48
24
20
10
34
20
12
10
10
6
6
8
6
8
6
presents
33
20
24
12
14
16
16
16
11
12
20
21

50
25
76
6
5
5
6
6
5
6
50
36
29
46
26
25
20
25
22
26
12
14
7
6
14
5
8
5
AugA SeptA Oct Nov
24
18
20
18
16
18
18
16


35
10
8
46
29
34
17
14
18
16
17


44
36
23
42
22
24
28
24
28
30
20
21
22
19
22
17
22
17
an average of
30
30
28
29
30
30
30
16


102
24
14
20
21
32
10
5
6
7
6


14
12
26
18
14
12
15
14
16
29
16
16
9
9
14
14
18
13
up to
21
22
22
21
21
22
21






15
22
23
16
9
15
22



22
14
15
21
18
14
19
26
10
15
12
18
11
15
26
13
27
14
four data
24
24
23
24
22
22
22



29


10
17
16
12
13
11
16



6
14
13
19
16
15
18
16
17
19
19
16
18
20
20
14
16
14
poim
Dec Jan
26 14
28 12
27 20
25 23
25 13
26 12
26 15






13
19
18
14
9
11
19



12
10
8
20
14
12
47
19
20
25
14
21
13
11
26
14
17
10
:s these months.
Feb
18
15
16
19
10
13
14
11





7
11
9
8
3
9
4
14


13
15
11
11
10
11
30
11
11
26
13
16
16
11
13
10
16
7

Mar
8
8
8
8
7
7
8






6
7
7
8
6
7
6



7
12
6
6
7
6
16
7
5
11
6
6
20
9
21
10
8
6

Apr
8
7
5
7
3
3
4
8


23


9
9
9
10
11
9
9



11
6
6
7
7
6
4
8
5
11
4
3
11
7
14
8
10
6

       B:  Control stations.
                                       J35

-------
                                    TABLE 4
Additional Surface Water  Physicochemical Parameters

Parameter
Temper-
ature
(°C)




PH
(SU)





Dissolved
Oxygen
(mg/1)




Conduc-
tivity
(umho)





Station
MP-1
MP-2
MP-3
MP-4B
MS-1B
MS -2
MS-3
MP-1
MP-2
MP-3
MP-4B
MS-1B
MS -2
MS-3
MP-1
MP-2
MP-3
MP-4B
MS-1B
MS -2
MS-3
MP-1
MP-2
MP-3
MP-4B
MS-1B
MS -2
MS-3

JunA
29
28
28
28
30
27
28
7.0
7.6
7.6
7.8
7.1
7.4
7.6
2.0
5.9
6.4
6.4
3.5
4.4
5.9
182
5
5
5
3
4
5

JulA
28
28
28
28
31
31
27
8.4
8.4
8.6
8.0
8.5
8.1
7.8
5.8
3.5
6.9
4.0
6.4
4.9
4.6
50
31
39
20
29
26
27
A: Data represents an average

AugA
27
27
28
28
28
27
30
7.8
7.9
8.0
8.0
7.8
7.5
7.4
2.6
7.0
7.6
6.8
7.0
4.4
6.5
41
30
33
30
27
30
30
of up
1989
SeptA
29
30
30
30
29
29
31
7.8
7.7
7.8
7.8
7.3
7.4
7.6
3.2
8.6
10.0
7.2
2.4
4.5
6.1
28
29





to four

Oct
24
24
24
25
25
25
24
6.9
7.2
7.3
7.3
6.7
6.8
7.2
1.1
5.0
6.2
4.5
0.7
0.9
5.2
35
35
35
37
35
35
3
data p

NovA
21
20
20
21
21
21
21
7.3
7.2
7.2
7.7
7.0
7.0
7.0
1.0
2.4
2.2
4.8
1.9
2.2

Dec
5
5
6
6
4
3
9
7.7
7.6
7.8
7.7
7.3
7.6
7.6
8.3
8.1
8.5
7.5
9.2
8.7
2.3 11.0
38
37
37
38
35
35
34
42
43
42
40
39
40
40

Jan
12
13
14
14
13
16
14
8.0
8.1
7.9
8.0
7.0
7.3
7.7
10.2
10.5
7.7
8.1
5.1
6.3
10.6







1990
Feb Mar
16
17
17
18
16
16
16
8.1 7.7
4.0 8.0
3.5 7.8
4.4 8.0
6.3 7.4
7.4 7.4
6.0 7.5
6.2
7.4
6.5
7.9
6.1
7.4
6.0








Apr
28
28
30
27
29
28
30
7.6
7.7
7.8
7.7
7.7
7.6
7.8
5.1
5.9
7.4
6.1
6.8
6.3
7.4







loints these months.
      B:  Control stations.

fiddler  crabs,  Uca  sp. ;  blue  crab,  CallLnectes  sapidus;  periwinkle  snails,
Littorina   sp.;   sailfin   molly,   Poecilia   latipinna;   sheepshead   minnow,
CyprLnodon  variegatus;   broad-banded water  snake,  Nerodia  fascLata,  common
egret, Casmerodius albus; green heron, Butorides virescens;  roseate spoonbill,
Ajaia ajaja;  osprey, Pandion  haliaetus;  and coyote, Canis latrans.   There was
no  attempt  to quantify  these organisms.   Cooler  temperatures  at the  end  of
1989 and in early 1990 may  have tempered the observed  activity of this fauna.
                                     136

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;Eleva,ted soil and  mud salinities  were more persistent in  the  impacted  areas
 (Table 3).   Marsh  ponds MP-1  through 3 and Zone  A were  most persistent with
 elevated soil  salinities.    These  marsh  ponds,   as  a  group,   reached soil
 salinities  tolerable  for  the more hearty  vegetation (about  50  ppt)  by  August
 1989.  The soil  salinity  in marsh pond  MP-3  remained about  twice that of  the
 control station on September 20,  while marsh ponds MP-1 and 2 were consistent
 with the control station.   By November  21 variation of  the  marsh ponds  rela-
 tive to the  control  station had  declined  to and  remained at only 5  ppt.  No
 evidence that rooted bottom vegetation existed  in  the marsh ponds prior  to  the
 brine release was observed.

 One  zone A and one zone B soil salinity  also remained'elevated as of September
 20.   By October  17   all  marsh soil  salinities had  recovered  to essentially
 ambient conditions, although some  individual stations exhibited minor periodic
 swings in salinity attributed  to  sample  heterogeneity.

 Neither soil nor water samples indicated any observable salinity impact in the
 ICW  (Table 3).  This  is attributed to the  shallow  morphology of the canal, se-
 vere mixing  turbulence imposed by barge traffic,  and  the  close communication
 of this area with  the Gulf  of Mexico.   Monitoring of this  station was there-
 fore discontinued  in  July.

 No producing  aquifers were  identified during excavation  of  the  brine  pipeline
 to expose pipe  failures  for repair.   This observation was  substantiated by  an
 independent  hydrogeologist   (6).    Some small amounts  of groundwater were  ob-
 served draining  into  the  excavations.  This  groundwater seepage  into  the three
 brine  line  excavations was  monitored as  construction activities and  weather
 allowed (Table  3).   Excavations  at the ICW (BL-2)  and  the beach (BL-3) showed
 no indication of measurable  salt contamination.   All  samples at these  loca-
 tions  were similar in salinity to nearby surface waters.  The salinity at the
 initial  leak location  (BL-1)  was observed  at  significant  levels (85  to  110
 ppt) from September  1 through  18.  By November,  groundwater  salinities  at BL-1
 declined  to  within ambient  marsh conditions.    This  groundwater  was  observed
 seeping from unconsolidated fill  in  the original  pipeline  excavation,  rather
 than a producing sand or  aquifer.

 Discussion

 The  study  area  was frequently inundated with heavy  rains and or  tides during
 the  early portion  of  this study.   Tropical storm Allison (landfall on June 26,
 1989)  and hurricanes Chantal (landfall July  31,  1989)  and Jerry  (landfall
 October 15,  1989)  made  significant  contributions  to  flushing brine and  salt
 laden waters from the  impact area,  and  its soils.    Severe cold weather  in
 December  1989  (see  Table 4)  resulted  in  extensive  necrosis  of the  exposed
 vegetation.   Significant  recovery from this  freeze damage was evident by April
 1990.

 The  more salt tolerant plants  such as L. carolinianum and D.  spicata  recovered
 significantly  in all but the  most severely impacted  areas.   D.  spicata  also
 exhibited  tolerance  to the  cold  weather.   S.  robustus,  a somewhat  less  salt
 tolerant species,  has been  significantly affected  in some areas,  declining  in
                                     137

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distribution and density.  S. alterniflora has  moved into some of the impacted
areas as a pioneer species filling the niche vacated by S.  robustus in zone C.
S. alterniflora  also exhibited  some tolerance to  the cold  weather.    As of
April 1990 vegetation  in all but about two and a half acres  of impacted area
showed at least partial  recovery.

Water and soil salinities  were  consistent with the  early recovery observed in
most of  the marsh  vegetation.   The salinity of surface water  stations  quickly
declined to ambient conditions.  Recovery of soils was  slower  than water qual-
ity, as  might be  expected,  due  to the more  limited mobility  of  interstitial
waters  and salts.    Frequent natural  flushing  throughout the study  period
appeared to augment flushing of  salt and  nutrient exchange.

The  elevated  groundwater salinities  in BL-1 were believed  to  represent  a  re-
turn of brine lost to  unconsolidated  fill  around the  brine pipeline.    These
salinities  eventually  returned  to typical marsh salinities  suggesting  measur-
able release  of  brine from unconsolidated fill is  complete.   This  contamina-
tion was of  minimal  ecological impact.  No  aquifer  or  sand  was  cut  by  the
brine  line  excavation suggesting  extensive groundwater contamination did  not
occur.   Monitoring  of  this  fluid will  continue  as precipitation and  tidal
conditions  permit.
 Conclusion

 Measurable surface water  and soil  impacts were  relatively  short  lived due  to a
 variety of factors.  Frequent and  severe  tidal and precipitation events  pro-
 vided excellent natural flushing to the marsh.   The shallow morphology, heavy
 commercial barge traffic, and close communication with the Gulf of Mexico fa-
 cilitated rapid dispersion  in  the ICW.  This  rapid physicochemical  recovery
 facilitated a corresponding  response  in the  local  flora.

 Vegetation in  study  zones B and  C exhibited  pronounced  recovery during the
 first quarter,  and continued recovering throughout the study period.  Most of
 the vegetative  damage in  these zones  was confined  to leaves and  stems allowing
 recovery  to  be initiated by the  relatively  unimpacted  roots  and  rhizomes.
 This limited damage  is attributed to  the slightly  higher elevation  of these
 zones preventing  prolonged  penetration of  the  brine  into the substrate,  and
 the frequent flushing by  tides and precipitation.   Recovery was  interrupted by
 freeze damage,  but continued once  this  meteorological  anomaly  passed.

 Study zone A showed little vegetative recovery  during  the  study.   Coupled  with
 high  initial  soil  salinities,  this suggests  more  extensive damage to  the
 vegetation in zone A.  The  low relief of this  area  and its proximity to the
 brine  source  lengthened  and intensified  the  brine  exposure,  producing  deep
 root damage and a more  prolonged soil  impact.   Return of  the  soil  salinity to
 ambient conditions suggests  that at least some natural  revegetation  may occur
 by runners on the perimeter, and by seeds if adequate transport into the  area
 is achieved.   Periodic long term  monitoring  of  the  vegetation  in  this  area
 will continue  in  order  to  track  recovery.    Enhancement of  circulation and
                                     138

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'scattered planting  of  S.  alterniflora  are  under consideration  as  feasible
 actions to provide a seed source to the area.

 Spring growth produced significant recovery and some  species  redistribution in
 all but the most severely impacted area.  The shift in  species  dominance is an
 expected phenomenon in an area,  such  as this, where  the primary physicochemi-
 cal conditions were significantly altered.  Return of the  physicochemical par-
 ameters to suitable conditions  facilitated initial revegetation by  the  heart-
 ier species.  This phenomena allowed  these species to  establish themselves in
 several new  areas, and  provided an opportunity  for  them to expand  their dis-
 tribution in these areas.
 References

 1.    R.  Daubenmire  and  J.  B.  Daubenmire,   Forest  Vegetation  of Eastern
      Washington  and  Northern  Idaho,  Washington   Agriculture   Experimental
      Station, Technical Bullitin  60,  1976.

 2.    Standard Methods for the Examination of Water and Wastewater,  17th  Ed.,
      American Public Health Association,  Washington, D.C.,  1989.

 3.    D.  L.  Wilkinson,  Biological  Assessment  of  the  Bryan  Mound  Strategic
      Petroleum  Reserve  Brine Disposal Pipeline  Leak, Report  by Biological
      Consulting Services  for  the  U.  S. Department of Energy, August  1989.

 A.    D.  L.  Wilkinson, Wine Month Review of  the State  of the  Marsh  at the
      Bryan  Mound  Strategic Petroleum Reserve Brine Disposal  Pipeline Leak,
      Report  by Biological  Consulting Services  for  the  U.  S.  Department of
      Energy, May 1990.

 5.    Army  Corps  of Engineers,  Wetland Plants of the  Eastern United States,
      North Atlantic Division,  90  Church Street,  New  York,  NY, February 1977.

 6.    D.  Jeffery, Brine Leak Groundwater and Soil Inspection, Letter  Report by
      Parsons Brinckerhoff and KBB,  Inc.,  for the U.  S. Department of Energy,
      July  1989.
                                     139

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BRINE MANAGEMENT  PRACTICES IN OHIO
Dennis R. Crist
UIC Program Administrator
Ohio Department of Natural Resources
Division of Oil and Gas
Columbus, Ohio, U.S.A.
The Division of Oil and Gas was created as the primary agency with authority to
regulate Ohio's  oil and  gas industry by conservation  legislation enacted  in
1965. Serving a dual mission,  the Division protects the public health,  safety
and environment during the course of oil and gas operations  while allowing the
development of Ohio's  non-renewable energy  resources.  Today,  the Division  is
responsible for  an industry which has  grown to  over  64,000  wells and  3,500
registered well owners.

Ohio's UIC Class II well program  was  granted  primacy by U.S. EPA,  effective  in
September, 1983. The program has acquired a  broad range of  regulatory respon-
sibilities which assists the State in tracking of oilfield brine and associated
wastes. To protect underground sources of drinking water, the Class II program
enforces regulations concerning:  transportation of  brine;  tracking of wastes;
inspection of  injection  well surface  facilities and pipelines;  and approving
resolutions for dust and ice control. However,  the primary focus  of the  Class
II program is centered on the four methods of brine disposal allowed by  State
law.  These  methods include; conventional  injection wells,  enhanced recovery
projects, road-spreading for dust and ice control, and annular disposal.

Wells  constructed  for  deep  injection,   or  conventional injection  wells are
typically designed with multiple  layers  of sealed casing to  protect freshwater
aquifers. The surface casing is set at least  50  feet below the lowest U.S.D.W.
and cemented to  the surface. The production  casing must be  cemented a minimum
of 300 feet above  the  top of the injection zone and tubing  is  set on a packer
creating a monitored annulus.  At current staff  levels,  UIC  inspectors witness
100 percent of all critical well construction phases including  installation and
cementing of casing and installation of tubing and packer.

Before granting a permit  for injection,  an "area of review"  must be evaluated,
a legal notice is published  in a newspaper of general  circulation in the  area
where the proposed well  is located,  and  a public hearing may be held depending
upon the validity of objections raised.

After ^an initial mechanical  integrity  test  is performed on the injection  well,
continuous monitoring  of the annulus is an acceptable means  of  determining
ongoing mechanical  integrity as  long  as sufficient  pressure is maintained  to
detect leaks.  If  positive pressure  cannot be maintained on the annulus  for a
prolonged  period  of  time,   a monthly mini-test  is  required  and mechanical
integrity must be demonstrated once  every five years. At current staff levels,
                                     141

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UIC  inspectors  witness  100  percent  of  all mechanical  integrity  tests and
inspect annular  pressure readings once every six weeks,  on average.  If annular
and  injection tubing pressures equalize,  injection operations are immediately
suspended by order of  the chief until corrective  action is  taken and the UIC
inspector witnesses a successful mechanical  integrity test.

Most of the 186  conventional injection wells in Ohio are converted production
wells  geographically distributed in  36  counties  and known  producing fields.
Since the majority of the wells are  commercial,  the associated production costs
are  greatly  increased  with brine disposal  rates  averaging between  $1.50 and
$2.50/BBL depending  upon transportation distances.  Over 92% of  reported brine
production  of 8.9 MM/BBLs was  injected  in conventional wells during 1988.  A
relatively  small percentage was disposed of  by annular disposal or road-spread-
ing  for dust and ice control.

Concerns  that are frequently raised over  deep  injection wells vary greatly in
Ohio.  .One area of interest is the ongoing research by Columbia University, the
United! States Geological Survey and others on the possibility that these wells
are  triggering  earthquakes in the  northeast portion of the  State.  Addition-
ally,  the Division has  developed mini-task  force groups composed  of  qualified
personnel,  industry representatives, and constituents to establish recommenda-
tions  on "Parameters for  Maximum Injection  Pressure's" and  "Guidelines  for the
Construction of  Surface Facilities"  in an  effort to resolve complicated techni-
cal  and economic issues. The Division  also encounters  regular objections at
public hearings concerning problems with  aesthetics of  the proposed  facility,
transportation restrictions,  zoning regulations, and the possibility  of  fresh-
water  or  other environmental damage.

Wells  constructed for injection in Ohio's enhanced  recovery projects  must  meet
the  same construction,  testing  and monitoring  requirements as deep  injection
wells.  Enhanced  recovery projects operate  in  16 counties  statewide with  171
injection wells  and 302 withdrawal  wells. The  total volume of  fluid injected
during 1988 was  approximately  1.2 MM/BBLS.

Because  of  its favorable reservoir characteristics  (high permeability,  lentic-
ular channel  deposits,  shallow  depth and  estimated oil  reserves)  the Berea
Sandstone  is  effectively  the only  reservoir in Ohio successfully supporting
secondary  recovery.  However,   the  Berea  has  been historically  drilled  and
accurate well records  are often non-existent or less than adequate  to demon-
strate that  well construction  and  plugging methods meet  today's  standards.
Therefore,  several  producing  fields  are  currently static since  the area of
review typically contains 100  to  200  wells  and  economic conditions  cannot
 support the  up-front  costs of rejuvenating these  potential  enhanced recovery
projects.  However, the  UIC Program has been creative in evaluating  proposals
 for such projects by:   issuing  permits  contingent  upon conpleting corrective
action requirements  in  the area  of review, or allowing the use of monitor wells
 to ensure that reservoir static fluid levels do not rise as a result of injec-
 tion potentially resulting in  contamination  of U.S.D.W.'S.
                                     142

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The UIC Class II Program maintains strict standards over road-spreading resolu-
tions,  which are  passed by local  government authorities.  Presently,  10  coun-
ties, 171 townships, and 15 municipalities statewide have passed valid resolu-
tions to allow brine spreading  for dust and ice control. Approximately 362,000
BBLs or 3.8% of brine produced was reportedly spread on  Ohio's roads in 1988.

Surface application of brine remains an environmentally  controversial method of
disposal. While injection  of  brine into conventional  Class II wells is recog-
nized as the preferred method of disposal  in Ohio,' the General Assembly deter-
mined  that  insufficient  evidence of  environmental  harm existed  to  prohibit
alternate, less expensive  disposal options.  However,  in response  to  environ-
mental  concerns,  the legislature  created a Brine Management Research Special
Account to fund research concerning alternate brine disposal methods.

To date,  four  research projects have been  funded at a  total  cost of  approxi-
mately  $107,000.  This research has answered many of  the questions  concerning
 the environmental  acceptability  of  the  surface  application method.  Funded
research projects include:

     •    A preliminary study of  aromatic hydrocarbon  concentrations in Ohio
          oilfield brines;

     •    A study of trace metal concentrations in Ohio brines;

     •    A field study to monitor soils and groundwater quality  changes caused
          by surface  application of brine under worst case aquifer conditions;
          and

     •    A  study of  volitalization  of  aromatic hydrocarbons  in  brine from
          wellhead to road surface.

 Findings  from the study on brine  application under worst  case  aquifer condi-
 tions  showed  that  localized  saline  contamination  of  ground water  occurred
 torporarily  following  both  winter  and  summer  spreading  episodes.  However,
 there  was no evidence  of  aromatic hydrocarbons  or  increases  in heavy metals
 concentration  in the aquifer.  Copies  of  this study,  conducted by the Ohio
-State University, are available at cost through the Division's  Public Inquiries
 Assistant.

 Annular disposal of brine  is  under Class II jurisdiction even  though construc-
 tion standards and the disposal method differs considerably from conventional
 injection wells. New rules,  enacted  in July 1989,  have  strengthened well
 construction  requirements  and  mandate demonstration  of mechanical  integrity
 prior   to disposal   authorization.  However,  the  following  major  differences
 between annular disposal and conventional injection retrain:

     •    There  is  only one layer of casing  that protects freshwater  aquifers
          in an annular disposal well.  Surface casing must  be set  at  least  50
          feet below  the lowest U.S.D.W.
                                    143

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     •     Average daily volumes injected are limited to a maxiirum daily average
          of 10 BBLS.

     •     The injection zone is not defined in an annular disposal well.

     •     An Inspector  must witness setting  the surface  casing. Upon  inspec-
          tion of  the liquid  tight  piped system,  the well owner  is  granted
          authority to dispose of  on-lease  brine  by  the annular disposal
          method.

     •     There is no area of review established for annular disposal wells.

     •     On all annular disposal  wells,  brine is gravity-fed  into the injec-
          tion zone.

     •     Most  annular  disposal wells  are located  in a  five-county  area of
          east-central  Ohio and are  drilled by  cable-tool  rigs.  It  is  sus-
          pected  that the  Berea  Sandstone and  the Nevfourg Dolomite  are the
          major inherent injection zones since annular disposal is only practi-
          cal when drilling problems created by  brine production  are encoun-
          tered in those zones.

     •     Most annular  disposal wells meet the  stripper classification and are
          marginally  econonical utilizing this practice.  Any  further produc-
          tion costs may considerably shorten the economic life of the well.

     •     Only 3.6% of  350,000 BBLS of brine produced was reportedly injected
          using the annular disposal method in 1988.

Annular disposal  has  long  been suspected as a  cause of damage  to U.S.D.W's;
however,  there  is relatively little  documentation that this  has  actually
occurred.  Much  of the  controversy surrounding  annular  disposal  centers  on
unanswered questions regarding the practice.

The  UIC Section  has  been  successful  in answering  many  questions  concerning
annular  disposal  by  performing  in-depth  research  on  the  practice.  This
research, funded by both the U.S. EPA and Division  of  Oil and Gas,  evaluated
actual  casing and sealant  conditions  in the  field on one-hundred  wells  per-
mitted  to use annular disposal. In summary,  this study demonstrated that the
practice  of sealing  surface  casings  with prepared  clay was not effective in
isolating or protecting underground sources of  drinking water.  Ninety-seven of
one-hundred wells  evaluated were  determined  to be  inadequately sealed.  As a
direct  result of  this research,   strengthened  regulations were  adopted which
require annular disposal wells to  have  surface  casing sealed with cement under
an inspector's supervision and an initial mechanical integrity  test of the well
prior to conmencement of disposal  operations.
                                    144

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In 1988, the UIC Section initiated the mechanical integrity testing requirement
addressing  all annular  disposal wells permitted prior to September  of  1983.
This effort was mandated by the once  every five year testing  requirement con-
tained in Ohio's regulations.

'To date, 6,334  wells have had authorization to use annular disposal  revoked by
[Chief's order for  failure to perform the required  mechanical integrity  test.
•With assistance from the Division of Oil  and Gas  field  staff,  in excess of
5,400 of these wells  have been field-checked for compliance with the orders.
Only 135 wells have been tested by operators to date.  Out of  this number,  104
wells successfully demonstrated mechanical integrity and have had authorization
to  use  annular disposal extended  for five years.  Currently,  there are  only
11,560 wells authorized to use annular disposal in Ohio. This number  is antici-
pated  to  continue  the  dramatic   decline that  began  in  1988 as  mechanical
integrity testing requirements continue to be enforced.

Sane  other areas  of  interest  regarding brine  disposal in Ohio relate to  the
U.S. EPA mid-course evaluation of Class II Programs, and the Underground Injec-
tion Practices Council (UIPC) Peer Review process.

Ohio was one of five states  selected  to  participate in' the national  mid-course
evaluation effort for Class II wells. This  evaluation  looked primarily at  the
Eadequacy of  existing  regulations  for  Class  II wells  nationwide.  Findings
^indicated that overall,  current regulations are for  the most part adequate.

The UIPC Peer Review of Ohio's Program was  conducted  in February,  1989. This
process consisted  of  a review  team composed of  State  UIC Directors fron  two
primacy states, a previous  State Director and the UIPC Technical Director.  The
week  long  review  critically examined all  aspects of  Ohio's brine  disposal
program. The findings,  which were published  and   are available  through  the
UIPC, demonstrate  that  Ohio is very  much in the forefront  nationally with a
progressive  UIC   Program.   Additionally,   the   Peer  Review  Report   closely
parallels bi-annual U.S. EPA evaluations of the program. In  fact.  Region 5  of
 the U.S. EPA has  consistently used Ohio's program  as a model for other states
 to utilize.

Currently,  a  major area of  concern centers  on federal  funding  available  for
Ohio's  UIC Program.  Since  receiving  primacy in 1983, annual  federal grants
 have-only  funded  approximately 25 percent of  the total  program's  cost.  The
 State's dedication to the program  and willingness to pick  up the lion's  share
 of program funding has enabled a model Class II UIC  program to  develop  in  Ohio.
 It is critical,  however,  that both  U.S. EPA  and  Congress  recognize  that  in
 order to maintain quality programs in Ohio and other states,  it is necessary to
 provide adequate funding.

 Over  the last 24 years,  the Division has grown with  Ohio's  oil  and gas  activity
 and has responded progressively to issues and concerns from industry, local  and
 state officials,  special interest groups  and the  general public.  The  Divi-
 sion's UIC Class  II program shares this same progressive  attitude by acknow-
 ledging broad responsibilities and high expectations for the  future.
                                     145

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CHARACTERIZATION OF TREATMENT ZONE SOIL CONDITIONS AT A
COMMERCIAL NONHAZARDOUS OILFIELD WASTE LAND TREATMENT
UNIT
W. Wayne Crawley, Robert T. Branch
K. W. Brown & Associates. Inc.
Introduction

Campbell Wells Corporation (CWC) operates two commercial land treatment facilities in the
State of Louisiana; the Jennings Facility (Jeff Davis Parish) and the Bossier Parish Facility.
Both are permitted through the Louisiana Department of Natural Resources for the treatment
and disposal of nonhazardous oilfield waste (NOW), as defined in Statewide Order 29-B.

Land treatment has proven to be a successful treatment method for organic wastes, as well as
conservative pollutant species (heavy metals).  However, a primary concern for land treatment
of oilfield wastes is the high soluble salt concentrations  and  the potential  for these  soluble
salts to move vertically out of the treatment zone. The objective for soluble salts management
is to limit vertical mobility and impacts to groundwater.  CWC removes soluble salts from its
treatment cells primarily via the surface water runoff pathway.

Routine treatment cell monitoring at both CWC facilities includes quarterly soil core and soU-
pore water  samples.  The soil-pore water samples, collected from lysimeters. are  designed to
provide chemical data  for water moving through the  treatment zone.  The Jennings  facility.
which began operation in December 1983, has been unable to collect consistent water samples
in their lysimeters. even though the lysimeters are functional. Since migration of soluble salts
into the subsoil represents a potential offsite impact, and thus may influence the operating life
of the facility, CWC decided to  conduct a subsoil  study in one of their older treatment cells to
better define the potential movement of soluble salts.

Study Objectives

This field investigation was conducted to characterize the subsoil conditions of one of the older
treatment cells at the CWC facility.  The specific objectives of the field investigation were:

       1.  to determine the effect of land treatment operations on the physical and chemical
          properties of the subsoil;
       2.  to quantify flow rate of soil-pore liquid  through  the subsoil;
       3.  to develop  site-specific data  to determine if  barium is being  attenuated or is
          otherwise unavailable for migration; and
       4.  to further document the impacts or lack of Impacts of land treatment  of NOW at the
          CWC facility.
                                    147

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Investigative Approach

The Investigation was divided Into the following tasks: 1) field infiltrometer tests, and 2) soil
sampling and description activities.  A treatment cell (Cell 2) and a background location were
chosen for this study. Cell 2 was one of the original treatment cells permitted in 1983. This
cell is typical of the treatment cells at CWC. both in construction and management. Cell 2 had
recently concluded a treatment cycle and the treated NOW had been excavated. Therefore, the
surface of the subsoil was exposed and available as the "surface" for this study.

Field Infiltration Study

An infiltration study was undertaken to determine the rate at which water infiltrates the
treatment zone soil. Four separate infiltrometer test sets were conducted for this study. The
first set of three infiltrometer tests were conducted in Cell 2 at the subsoil surface.  The second
set of three were conducted adjacent to the first set, at a depth of 18 inches below the subsoil
surface.  Sets three and four of the infiltration runs were conducted at the background location.
at corresponding depths within the soil profile.

Double-ring infiltrometers were used to determine  the infiltration rate of the treatment zone
materials. This equipment consisted of three pair of 12-inch  high steel cylinders.  The inner
cylinder or ring of each pair was 12 inches In diameter, while the outer cylinder was 30 inches
in diameter. The purpose of the inner ring or cylinder was to allow a measure of flow rate into
the soil, while the outer ring wetted the surrounding soil to ensure that flow from the inner ring
was vertical.  The cylinders were open at both the top and bottom, and the bottom edge was
beveled for ease of insertion Into the soil.  A 50-gallon barrel was used to supply water to each
outer ring and a 3-foot high. 6-inch diameter cylinder was used  as the supply for the inner ring.

Depth of water in both cylinders was maintained at approximately 2 Inches above the soil sur-
face with automatic float valves.  A Stevens Hydromark water level chart recorder was used to
continuously record the water level in the Inner ring water supply cylinder.  Sufficient time
was allowed during the test for the wetting front to advance at least 6 inches into the soil. This
ensured a 6-inch  depth of saturated soil with an infiltration rate approaching a steady state
value.

Soil samples were collected to measure the native field water content of the soil before the tests
were started and  immediately after the infiltration test to indicate the percent saturation of
the soil below the test ring.

Subsoil Characterization Procedures

Procedures to define subsoil conditions were divided into two phases:   soil chemical and soil
physical properties, both of which were accomplished by means  of soil pits  excavated in the
soil. Three soil pits were excavated in Cell 2 to a depth of 5 feet, measured from the undisturbed
soil  horizon directly beneath the waste treatment zone.  In addition, one background pit was
excavated for comparison.  Each soil pit was described and sampled in accordance with the
procedures outlined below. A track hoe was used to excavate the pits, with the  operator creating
a vertical pit wall used for soil descriptions and sample collection.

Soil Description - Detailed  descriptions of the profiles were  made  and compared with data
collected from similar adjacent background areas.  The soils were described and classified
according to standard soil survey procedures.
                                      148

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Soil Sampling -- Soil samples were collected at continuous 3-lnch Intervals from the lower
boundary of the \vaste treatment zone to a maximum depth of 5 feet.  Selected samples were
analyzed In order to define concentration gradients.  Chemical properties analyzed included
soluble cations, soluble anlons, pH. electrical conductivity, and  selected metals (e.g., total
barium and zinc). Physical properties included  soil moisture percentage, water retention
capacity, bulk density and particle density.
Treatment Cell 2 was chosen for this study. The field investigation was conducted during the
last week of September and  the first week of October 1988.  Three soil pits were located
randomly and excavated  in  Cell 2, with a background soil pit excavated  at the  nearest
accessible native soil location (Fig. 1).  Infiltration runs were conducted In Cell 2  and at the
background site, as noted in Figure 1.

Historical Use Of Treatment Cell 2

The treatment cycle for each treatment cell consists of an application, a dewatering. and a
treatment cycle.  Once the treatment cycle is completed, and the treated NOW meets specified
criteria established by the DNR. the treated NOW can be removed  from the  treatment  cell.
During treatment cell construction, the topsoll is removed, therefore,  applications are made to
the surface of the subsoil. The treatment zone consists of the Waste Treatment Zone (applied
NOW), the Upper Treatment Zone (subsoil surface to 12 inches), and  the lower  treatment zone
(12 to 54 inches).

At the time of the study. Cell  2 has undergone three application cycles since the initial facility
start-up in 1983 (Table 1).  NOW applications ranged  between 16.000  and 26.000 barrels/acre.
with the average treatment time being about 18 months. Gypsum (26 tons/acre) was applied
during the third cycle.

Table 1.  Application History of Cell  2.
Beginning
Application Date
IstQ., 1984
Sept. 30. 1985
Nov. 25. 1987
Barrels/Acre
•
26.000
16.123
End of
Treatment
8/85
11/1/85
9/15/88
Total Treatment
Months
-20.0
23.6
10.0
Gypsum App.
(tons/acre)
0
0
26
    CWC opened in Dec. 1983. No records were kept relating barrels applied per acre for early
    applications.  It  is assumed that Cell 2 received applications in early 1984.  The first
    excavation for Cell 2 occurred in mid-1985.

 Soil Description

 The Soil Conservation Service (SCS) has mapped this area as Crowley/Vidrine Complex, with a
 small  area of Mowata Series mapped  for Cell 2  (Fig.  1).   According to the  SCS. the
 Crowley/Vidrine and  the  Mowata series are geographically  competing series.   Primary
 differences between these soil series are:

       1.   Mowata soils have tongues of A2 extending into a B horizon; and
       2.   the  Crowley/Vidrine  soils  are  on  slightly higher  convex  shaped surfaces
           surrounding Mowata soils.
                                     149

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                 LOUISIANA
                         Y-VIDRINE ASSOCIATION
                                                 BACKGROUND
                                                    AREA
                                                      NTRANCE

                                                       OFFICE
 Scale  in  feet
     iZ
     250
              Soil characterization  pit locations
              Infiltration
Figure 1.   Selected Area for Subsoil Study.
                           150

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Thus the surface horizons and the location within the landscape are the reason these soils are
mapped separately.  The subsoils for the series are very similar.  Therefore, while there may be
minor differences with the surface soils for the soil pit and background locations, it was
determined that the subsoils were  similar, and  comparisons between these four pits  is
appropriate for this study.

The subsoil for both the Crowley and the Mowata soil series have silty clay and silty clay loam
horizons. Calcium carbonate concretions were visible in all  soil pits, with the exception of soil
pit 3.  Both the Crowley and the Mowata soil series have calcium carbonate concretions in their
subsoil (36 to 60 inches).

As a result of  cell  construction and operations,  the existing subsoil surface in Cell  2  is
equivalent to an approximate 18-inch depth in the background area.  Therefore, sampling and
data interpretation accounted for this effect to compare data for equivalent soil depths.  For
comparison to Cell 2 data, except where noted, the background data is presented as 18-inch
being 0-inch (subsoil surface).

Infiltration Tests

Infiltration tests were conducted at the surface of the cell (surface) and  18 inches below the
surface (subsurface).  For the background location, tests were conducted at 18- and 36-inch
depths, corresponding to the same soil horizons.

The infiltration data indicate that water movement through these soils is very slow.   The
infiltration rates for the surface and subsurface were 1.7 x 10"6 cm/sec (0.002 in/hr) and 5.54 x
 1(T6 cm/sec (0.008 in/hr) (Table 2) (Fig. 2a and 2b).  The infiltration rates for the background
soils were 7.7 x lO'7 cm/sec (0.001 in/hr) and 1.43 x 10'6 cm/sec (0.003 in/hr) (Fig. 3a and 3b).
Given the data  scatter, however, the background subsoils' hydraulic conductivities were about
the same as the subsoils within Cell 2.  It should be noted that the measurement limit for the
double-ring infiltrometer  is usually  around  1 x  10"^  cm/sec.  Therefore, all of the
measurements in this study were near the  limit of detection for this instrumentation.   It is
possible that the final infiltration rates (saturated hydraulic conductivities)  are  lower  than
those reported.

Table 2. Hydraulic Conductivity and Permeability Classes.
Infiltration Test
Location
Cell 2
Surface
Subsurface
Background
18" Depth
36" Depth
Hydraulic Conductivity
(in/hr) (cm/sec)
0.0023
0.0025
0.0011
0.0027
1.72x 10"6
5.54 x lO"6
7.74 x 10'7
1.43 x KT6
Permeability
Class
Very Slow
Very Slow
 The average pre-infiltratlon  soil moisture for  Cell  2 surface and subsurface and  the
 background 18- and 36-inch depths were similar, ranging from 21.5 to 26.3% (Table 3). The
 post-infiltration soil moistures were different,  with  the Cell 2 moisture only increasing by
 about 28%. The background 18- and 36-inch depths had a 50% change in soil moisture.
                                      151

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                                   	REP  1
                                   000.00 REP  2
                                   .««»» REP  3
   10
     -7  I I I I I I I I I 1 I I I I 1  I I I I 1 I I
      0.0
                               I I I I I I I  I I
                500.0      1000.0     1500.0
                ELAPSED TIME (mins)
   FIGURE  2o.  INFILTRATION  RATE AT
   SOIL SURFACE  IN  CELL 2.
                                                                                   •-"» REP 1
                                                                                   0.0000 REP 2
                                                                                    «•"•« REP 3
                                                  10
                                                    -1  I I 111 I I I I illlllillllllllllllll
  0.0       500.0      1000.0
            ELAPSED TIME (mins)
                                                                                    1500.0
                                                  FIGURE  2b.  INFILTRATION  RATE  AT
                                                  SUBSURFACE IN CELL 2.
  '0 ~'-a
  10 ~'-S
2
O
  10 "•=
o
<
  10 "-=
- 10"-=
                 I I
                                        REP 1
                                        REP 2
                                        REP 3
      0.0       500.0      1000.0     1500.0
               ELAPSED TIME (mins)

  FIGURE  3a. INFILTRATION RATE  AT
  18 INCHES DEPTH IN BACKGROUND AREA.
                                 •^ii_- RE?  1
                                 e.ooop RFp  2
                                 -..»»REP  3
                                                       0.0
                                                                                     1500.0
             500.0      1000.0
             ELAPSED TIME (mini)

FIGURE  3b.  INFILTRATION  RATE  AT
36  INCHES  DEPTH  IN  BACKGROUND AREA.
                                              152

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Table 3.  Soil Moisture Before and After Infiltration Tests.
Location
~CelT2 - Surface
Cell 2 - Surface
Cell 2 - Surface
Cell 2 - Subsurface
Cell 2 - Subsurface
Cell 2 - Subsurface
Background - Surface
Background - Surface
Background - Surface
Background - Subsurface
Background - Subsurface
Background - Subsurface


Repl
Rep2
Rep3
| Average
Repl
Rep2
Rep3
I Average
Rep 1
Rep2
Rep3
| Average

j Average
Before
23.8
22.1
21.5
22.5
22.0
21.4
21.1
21.5
22.7
24.9
30.7
26.1
24.9
29.2
24.6
26.3
After
30.3
29.2
27.2
28.9
28.8
27.8
25.9
27.5
39.9
43.4
50.9
44.7
43.6
44.0
38.3
42.0
 Soil Analytical Data

 The soil textures ranged between silty clay and silty clay loam.  While the horizons varied
 somewhat with depth, the soils were fairly consistent for the depths studied. Based on this
 observation, this discussion will not attempt to discuss the chemical data in accordance with
 the natural variations within the soil profiles.  It is felt that this would greatly complicate the
 discussion on the soil chemical data, and would only have limited utility.  It is realized that
 some of the variations within the four soil pits on a depth basis may be affected by the different
 horizons.

 Chemical Data — Soluble salts,  as measured by electrical conductivity (EC), were elevated for
 all three pits for the surface 18 inches, with the greatest increase in the surface 3 inches (Fig. 4).
 Below 18 inches, soil  EC values were below  1 mmhos/cm. and generally at or near background
 soil EC. A slightly higher soil EC was noted at 48 and 60 inches in Pits 1 and 2. This higher EC
 is  primarily due to naturally occurring soluble salts, primarily sodium bicarbonate.  The
 soluble sodium concentrations  are higher  (4.74 meq/L) at 48  and 60 inches than  the soils
 between 9 and 45  inches, therefore, it is concluded that the increased sodium is a natural
 occurrence. Bicarbonates are generally low  in all four soil profiles above 3 feet.

 The soil pH values also reflect the Impact of the  soluble salts in the first  18  inches.  The
 background soil pH reflects a well leached surface soil, with a pH of 5.4 to 5.8 for the first 18
 inches, which grades into an alkaline system near 3 feet (Fig. 5). Pit 1 (0 to 6 inches) and Pit 3 (3
 to 9 Inches) both have a zone of lower pHs. which reflect some of the natural pH values. Soils in
 Pit 2 have pH values above 6.7 throughout the pedon.

 The primary soluble  ions of concern with  oilfield wastes are sodium  and chloride.  Chloride
 concentrations were elevated in the first 18 inchgs of the soil profile, but were generally near
 background  concentrations below 18  inches  (Fig.  6).   At 6 feet, the  average  chloride
 concentration for the  three pits was approximately 14 mg/kg above the background value.  No
 significance is placed on this minor Increase.   Sulfates at 4  and 5 feet reflected no increase
 above background concentrations.
                                      153

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                    EC
                                                                           pH
                                                           „() 1  2 3 4  S  6  7  6 9 10 It 12 13 14
0
10

2 "
(—
O 30
m
TD
^ 40
•^
D
•C— so
60
70
1 __/_J=_-l 	 — '
' ^j^'""''^*'--
\ jf/'
\ 	 PIT 1
S 	 PIT 2
- r> 	 — PIT 3
ill • — — BACKGROUND
-\
\
11
u
10

g »
r~
O 30
m
T3
X 40
-^>
D
O 50
60
70
' ' ' 'A-^/ ' '
v\ v
v\ \
M i
, 1 v
*\ I
i t
\ I 1
\ / '
i i


	 PIT i
	 PIT 2
• PIT 3
• — — BACKGROUND



FIGURE <  ELECTRICAL  CONDUCTIVE
(mmhos/cm)  FOR SOIL PROFILES
FIGURE  5. pH FOR SOIL  PROFILES
          CHLORIDE  CONC.  (meq/l)

                    7Q
                            — — BACKGROUND
 FIGURE 6  CHLORIDE CONCENTRATIONS
 (meq/l) FOR SOIL  PROFILES
      SODIUM CONC.  (meq/l)

       i    10    15    20    75    M
                                                                                 — — BACKGROUND
                                                     FIGURE  7 SODIUM CONCENTRATIONS
                                                     (meq/l)  FOR SOIL PROFILES
                                             154

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Soluble sodium concentrations varied between the profiles.  The increased soluble sodium in
Pits 1 and 2 is partially due to the higher natural sodium bicarbonates in these soils from 30
inches downward. Therefore, elevated sodium ions have occurred to an approximate depth of
18 to 24 Inches (Fig. 7). These data indicate an increase of approximately 30 mg/kg at 2 feet.
Pits 1 and 2 had increased sodium concentrations below 4.0.  Calcium  and magnesium have
also experienced increased concentrations in the surface  12 to  18 inches.  There  is little
environmental concern for these two ions, as they will offset the detrimental impacts from
sodium.

Background barium concentrations ranged between 91 and 396 mg/kg, with a general increase
in concentration with depth (Table 4).  Barium concentrations for the three  cell pits were
elevated for  the surface  3 inches. This impact is  expected because  of the high barium
concentrations in the wastes.  Pits 2 and 3 generally had background barium concentrations
below the 3-inch layer.

Zinc concentrations  show no movement  past  the surface  3  inches (Table 4); zinc
concentrations do increase with depth for all four profiles.  This Increase appears to be based
on natural effects and is not related to the treatment cell operation.  Mobility of zinc in soils is
pH-dependent. It appears zinc has moved from the native surface soils, which are well leached
and have pH values between 4.5 and 5.5 su.  Zinc accumulated  in the higher pH zones below 40
inches.

Table 4. Soil Barium and Zinc Concentrations.
Depth
0-3
3-6
9-12
21-24
33-36
45^8
57-60
Pit 1
695
449
545
393
254
ND
171
Barium
Pit 2
660
258
310
314
356
213
171
(mg/L)
Pit3
5.170
286
156
233
381
222
208
Bkgd
91
110
106
180
222
289
396
Pit 1
38
39
27
33
40
96
98
Zinc
Pit 2
52
47
51
41
37
50
65
(mg/L)
Pit3
122
35
31
36
33
50
59
Bkgd
27
50
37
22
31
31
80
 ND  No Data

 Physical Data — Six soil samples, three each from Pit 2 and the background pit, were selected
 for physical analyses (Table 5). These six samples represented three separate depths for each
 pit. All six of these soils are classified as a silty clay.

 The surface of the treatment cell (denoted as 18 to 24 inches in Table 5) has a bulk density of
 1.82 g/cc,  which reflects the compaction from the heavy equipment.  Porosity for the Pit 2
 samples ranged from 26.3% at the surface to 34.1% at 42 inches.  The background porosity was
 fairly consistent, and ranged from 36.4 to 43.8%.

 Characteristic moisture retentions were determined for these six soil samples (Table 5). The
 1/3 bar retention moisture percent is Important, as  it generally represents the  field capacity.
 Field capacity is defined as the percentage of water  remaining after free  drainage has
 practically  ceased.  Field moisture content the day of sampling for Pit 2 was  between 22 and
 26%. Increasing with depth.  The field moisture contents for Pit 2 were below the -1 /3 bar
 moisture contents, indicating that no free drainage was occurring. (No moisture samples were
 collected in the background pit).
                                      155

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Table 5.  Selected Soil Physical Properties.
Depth
Soil Pit 2'
18-24"
24-42"
42-64"
Background
18-36"
36-62"
62-72"
Field

22.3
25.0
26.1
ND
ND
ND
1/3 bar
	 °

49.0
33.5
35.1
45.4
32.2
40.0
Ibar
fa Moisture-

37.0
26.6
27.4
34.0
25.0
32.4
5 bar

28.4
20.0
20.9
25.7
19.2
24.8
15 bar

23.0
17.4
19.3
22.9
16.5
20.0
Bulk
Density
g/cc

1.82
1.67
1.66
1.55
1.44
1.59
Particle
Density
g/cc

2.47
2.53
2.52
2.48
2.53
2.50
Porosity

26.3
34.0
34.1
37.5
43.0
36.4
*  0-18" for Soil Pit 2 has been removed.

Characteristic moisture curves for each sample are presented In Figure 10.  These curves are
representative of clayey soils, with moisture contents ranging from 32 to 59% at field capacity
to 16 to 23% for the wilting point (-15 bar). The surface soil in Cell 2 had a moisture content
equivalent to -15 bar, while the two lower depth samples were between -1 and -5 bars. Since the
treated NOW had been removed from Cell 2. the surface soil had dried due to exposure to sun and
wind.

Discussion

The potential for environmental problems relating to  land based treatment and disposal of
wastes Is based on environmental mobility of contaminants.  Therefore,  In evaluating a
particular treatment and disposal operation, it is Important to evaluate the water movement
within that system.  The results of this study indicate that the site specific soil conditions serve
as barrier for contaminant migration. The saturated hydraulic conductivity (K^ai) for the Cell
2 subsoil averages 3 x 10'6 cm/sec.  Since the field moisture for Cell 2 was below the -1/3 bar
moisture content after the  Infiltration tests, the soils were not saturated.   The background
post-infiltration soil moistures averaged 44.7 and 42.0%, with the -1/3 bar moisture being
45.4%. Therefore, the background infiltration tests reached field capacity.

The infiltration tests for Cell 2 were actually evaluating unsaturated flow. The duration of the
infiltration tests for Cell 2 were not sufficient to reach  saturation and steady state.  The
appearance in the field of steady state K conditions was actually caused by reaching the lower
limit of the instruments measurement capacity.  Therefore, the K of Cell 2 would probably
measure somewhat lower than the background, given long enough  test using the sealed double-
ring infiltrometer equipment.  The unsaturated  hydraulic conductivity is  generally much
lower than the saturated.

The low estimated water movement is supported by the soil chemical data.  Chlorides, which
are frequently used as a tracer for offslte contaminant movement, have moved vertically only
about 18 inches in 5 years of operation.

Based on the current treatment cycle, which includes an application and dewatering cycle,
these cells remain  in a flooded or saturated condition  for a minimum of 6 months out of the
year. Thus, through 5 years of operation. Cell 2 has had a mixture of saturated and unsaturated
conditions.  Over this  5-year period, the impact of chlorides has reached approximately 18
inches. This equates to an annual saturated and unsaturated hydraulic conductivity of 3 x 10"7
cm/sec.  This rate  is near the hydraulic conductivity standard  for soil liners at hazardous
waste facilities (1 x 10'7 cm/sec). This is a very significant detail with regard to the potential
                                      156

-------
          BACKGROUND RETENTION CURVE
         0.50
                                     18-36"
                                     36-62"
                              •tHf-tHHs 62-72"
         0.10
                 2   4    6    8   10   12
                   Metric  Potential (bars)
                                           i«
               PIT 2 RETENTION  CURVE
         0.50
        > 0.40 -
       c
       o
       o
         0.20 H
         0.10
	 18-2^"
*^^ 24-42"
*-*.*-*.* 42-62"
                 2   4    6    8   10   12
                   Matric  Potential (bars)
                                               16
Figure  10.  Characteristic Mositure Retention Curves  for Pit 2 and Background
         Pit.
                            157

-------
for migration to the shallow groundwater, as it also indicates that the actual water movement
is much less than the measured saturated hydraulic conductivity.

The hydraulic conductivity measurements and the estimates of real water movement in this
study support the low volume of soil-pore water collected from the treatment cells.  At this site
location,  lysimeters may not be  effective or needed for estimating the  potential for
contaminant movement; soil sampling should suffice.

Conclusions

The data  collected from this study provides strong support for the current land treatment
operations at CWC.  The movement of water through and from the treatment zone in Cell 2,
supported with data for the background soils. Is very slow. This low water percolation through
the treatment zone has resulted in very limited soluble salt migration.  Based on this study, the
environmental impacts  resulting  from  5  years  of commercial land treatment of non-
hazardous oilfield wastes have been minimal. From this study the following conclusions can
be drawn:

       •  The impact of a dedicated, commercial facility must  be weighed against the
          environmental Impacts of scattered, unsupervised disposal.

       •  Site selection is a very important factor for a  successful, dedicated, land treatment
          facility.  Careful consideration must be  given to both the soil/subsoil conditions
          and the local groundwater situation.  This study demonstrates the benefits of a
          facility which was suitably located.

       •  This study  also provides data which support the facility management strategy
          regarding barium. Even with the high concentrations which are managed at CWC,
          and with flooded conditions for up to 6 months at a time, barium has not migrated
          into the subsoil to any significant degree.

       •  Zinc, which  is the second most prevalent heavy metal in the NOW managed at CWC,
          also has had limited vertical mobility. These two metals do not pose a threat to the
          environment as a  result of the CWC Jennings operation.

       •  Based on this study, no  changes to the current management at CWC  were
          recommended.  It is recommended that CWC  periodically evaluate the  subsoil
          conditions for soluble salt migration.
                                     158

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CLEAN-UP OF OIL  CONTAMINATED SOLIDS
T.  Ignasiak,  D.  Carson,  K.  Szymocha, W. Pawlak, B. Ignasiak
Alberta  Research Council
Coal  & Hydrocarbon Processing Department
Devon, Alberta,   Canada
Introduction

Oily   waste,    originating   from  a  variety  of  coal/petroleum   based
industries,   tailings  produced during heavy oil recovery, or  spills  that
may  occur  during  oil production and transportation, presents  a serious
environmental  problem.

To  control   the  problem,  various  remediation  technologies   based   on
physical,  chemical  as well as biological principles have been  developed
and  assessed.    Application  of  any  particular  procedure  has   to  be
evaluated  on  an  individual  basis  depending on the type  and  degree  of
contamination, its accessibility and cost-effectiveness.

The  present paper describes an attractive novel process for treatment  of
oily  waste  materials, jointly developed by the Alberta Research Council
(ARC)  and  the  United  States  Electric Power Research Institute  (EPRI)
(1-4).    The  process  utilizes  coal as a contaminant collector,  and  is
based on an agglomeration principle, with oily contaminants  acting  as the
bridging liquid between coal particles.  The effectiveness of  the process
depends on the ease with which the soil will release the contaminants and
also  on  the  contaminant  affinity  towards  coal.  In the process, the
contaminated  soil  is  mixed with a coal-water slurry.  The products,  in
the  form  of  contaminant  wetted coal and cleaned soil are separated  by
flotation.  Both attrition, which takes place during mixing, and sorption
capacity of the coal are very important to process performance.

The  potential  of  this  process has been demonstrated through  extensive
batch,  experimental  programs  followed  by  verification  in 6T/day pilot
plant  tests.    A  wide  variety  of  oil  contaminated   soils  have been
evaluated  with  particular  emphasis placed on remediation  of soils  from
manufactured gas plant sites.
                                  159

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Description of Contaminated Samples

A number of contaminated soil samples were used  in  the  evaluation studies
of  the  clean-up process.  A contaminant has  been  defined  as  any organic
matter  (solubles) which can be extracted with toluene  'or dichoromethane.
On the basis of the origin of contaminant, the samples  received represent
soils contaminated with:

    - tars produced by manufactured gas plants,  "MGP"
    - heavy oils, "HO"
    - gasoline, diesel and residual fuel (oil  spills),  "OS"
    - petrochemicals, "PC"

The  composition of samples varied within a wide margin, with  contaminant
concentration  ranging  from  less  than  1 to 602, Table 1.   The  toluene
soluble contaminants displayed distinct variations- in volatility.   It  can
be  seen  that  the  contaminating  species ranged  from very light, fully
distillable  components  (e.g.  gasoline) to much heavier ones^with about
60Ł non-distillable residue (e.g. heavy oil), Fig.  1.   Volatility  effects
the  viscosity  which  is  an  important  factor  in coal-bridging  liquid
interactions.  Also there were differences in the chemical composition of
contaminants.    According  to  its  thermal  history,  the tarry material
extracted  from  MGP  wastes  was  characterized  by  a  high   degree  of
unsaturation  as  indicated  by  the  low atomic hydrogen to carbon (H/C)
ratio  of  0.85  vs.  1.46  of  the heavy oil.  In  general, the  lower H/C
ratio,  the higher concentration of aromatic hydrocarbons.  The  solids in
contaminated  samples  varied  from  homogeneous,   clay-like materials to
heterogeneous  materials  with  a  wide  particle   size distribution that
included pebbles, rocks and molten minerals, Table  2.  Although  the basic
components of solids were silt and sand, some samples,  MGP tar  refuses in
particular,  contained  considerable quantities of  cokes and chars  (up to
40«).

Process Description

The  scheme  of the ARC/EPRI process for clean-up of tar/oil contaminated
soil  is  presented  in  Fig. 2.  The process consists  of two  stages.  In
stage I, a suspension of contaminated soil and coal in water is  subjected
to  tumbling  in a specially designed drum at an elevated temperature and
optimal  solids concentration.  The mixture is subsequently screened into
two  fractions:    -1mm  and  +lmm.    The  -1mm fraction is subjected to
conditioning   and   agloflotation   which   separates   the   coal  floes
(microagglomerates)  in  the  form of "froth 1" from clean (tar/oil free)
tailings.    Stage  II is optional and depends on the initial  response of
the treated waste to the cleaning.
                                 160

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In  stage   II,   the  tailings from agloflotation  are  combined with a -1mm
reject   derived   from  selective grinding of  +lmm fraction.   The combined
material  is subjected to reprocessing  in the  presence of  small  quantities
of coal  and a suitable collector and again  is  subjected to  agloflotation,
thus  giving  rise  to  "froth 2" which, together with "froth 1",  forms  a
combustible  product.    The tailings  from  reprocessing yield clean  soil.
During  agloflotation, some feedstocks can  produce middlings  (solids with
poor  settling  properties).    Depending   on   the characteristics of the
treated  soil,  the  "middlings"  are  combined   either   with combustible
product or clean soi1.

Processing

The  coal used in the experiments was  pulverized  to a top size  of  0.6 mm.
The quality of the product  streams,  in terms  of contaminant concentration
and  ash  content,  was  determined  by  extraction with  dichloromethane,
followed by proximate analysis of non-soluble  solids.

The  parameters  investigated  were  temperature,  contaminant/coal ratio,
solids  concentration,  agitation  and  residence time.    The effect of
temperature  on the  clean-up of tar  contaminated  soil  is  shown  in  Fig. 3.
The  amount  of  coal  required  in  the process depends on  the  origin and
concentration  of  contaminant, and  is higher  in  the  case of  oils  than in
tars,  Table  3.     The  results  of   processing  a number of  contaminated
samples,   in  terms  of the  residual  contaminant retained  in the soil,  are
shown  in  Table 4.  Overall the contaminated  soils responded well to the
cleaning  procedure with coal.  Most samples  were cleaned to  satisfactory
levels using the Stage I approach.

However, the ease with which the various samples  can  be processed  depends
to  a  large  extent  on  the chemical and  physical nature  of the  sample.
Samples, MGP-7 and MGP-8, represent  an extreme case of contaminated  soils
that  were  difficult to process.  The tarry  contaminant  in these  samples
had  a  deleterious  effect  on  the   flotation of coal resulting  in poor
product  separation.    Moreover,  the porous  sintered material,  char and
coke  present  in the soil  tended to retain the unacceptable  high  amounts
of  tar.   In these  cases,  the separation process was greatly improved by
addition  of an appropriate froth collector in amounts of up  to 2%,  based
on  weight of coal matter.  Increasing the  addition of froth  collector to
81  was  needed  to  float  the  indigeneous   tar loaded  char/coke with  a
particle  size  up   to  1.0  mm.     To better  clean the solids  containing
slag/char/coke   with   a   particle  size   above   1.0 mm,  grinding  and
reprocessing (Stage  II) was required,  Table 5.
                                 161

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In   some   instances,   the  presence  of   char/coke  materials  in  the
contaminated  soil  can  be very advantageous  to  the clean-up process, as
was  the  case  of  OS-1  sample.    This   soil was  processed without any
addition  of  coal  by utilizing the carboniceous  materials contaminating
the  sample.   The sample responded very well  to  processing,  yielding the
soil with less than 0.1% residual oil at 81% soil  recovery.

Essentially  there  is  no  upper  limit for concentration  of coal  and/or
petroleum  derived  pollutants   in  contaminated   soil   in   terms   of the
efficiency  of  the  clean-up  process.  A  soil sample  containing  502 (by
weight)  of a contaminant can be cleaned as efficiently as  a  sample  which
contains  only  0.5-5%  of contaminant concentration.   Since  however, the
treatment  requires  the  use  of  coal as  an  adsorbent in  quantities 2-4
times   greater as compared to contaminant concentration,  it appears  to be
economically advantageous to treat samples  characterized  by rather  low or
intermediate  (up  to  10-12% by weight) contaminant  concentrations.   Low
concentration  of  contaminants  (0.5-5%) offers particular opportunities
due  to  limited  application  of pyrolytic and combustion  techniques for
treatment of such samples.

The  concentration  of PAH in processed soil samples  originating from MGP
sites varied from about a few ppm to about  200 ppm.   The  concentration of
PAH  in  clean samples from oil spills was below the detectivity  level.

An   interesting   approach  to  the  utilization  of  the ARC/EPRI clean-up
technology   is  in the area of Alberta and  Saskatchewan heavy oil/bitumen
industry.   Economics of these two provinces rely  to  some extent on  their
enormously  rich,  but  low  quality oiI/bitumen deposits.  Currently the
recovery  of oil/bitumen is being achieved  by either  mining and hot  water
separation  or  in-situ steam flooding, using natural gas for steam/power
generation.    It  is  apparent  that  these  methods   present  a  serious
environmental  hazard reflected  in the vast accumulation  of tailing  ponds
and  oil  spills.  The adaptation of ARC/EPRI technology  for  the clean-up
of  contaminated ponds and spills using low  cost,  low  quality  coal  and the
utilization  of this oil laden coal, instead of expensive natural  gas for
steam   generation,  offers  a  vary  interesting route.   Furthermore,  the
combustible  product  (oil  adsorbed  on  coal) generated in  the clean-up
process can  be  either  combusted or thermally treated, releasing  light
oil, which  in turn can be used as diluent for pipelining  heavy  oil.

Conclus ions

The  process  that  utilizes coal for clean-up of  oily/tarry  contaminated
soil  can be applied to a variety of waste  materials  with a wide range of
contaminant  concentrations.  The effectiveness of the  process  depends  on
the  nature of both the contaminant and the  solids.
                                162

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Subject    to    state/provincial    regulations   and  laws  regarding  the
cleanliness   of  the   product,   the  processed  solids can be land filled
either   directly   or   after   some  additional treatment (ozone treatment,
bio-treatment).    The contaminant enriched coal can be used as a fuel in
conventional  coal  fired power plants.

Based  on   the   results  obtained  in  the  batch tests and in the 6T/day
continuous  unit,   the conceptual engineering design of the lOOT/day soil
clean-up mobile unit  has been prepared.
References

1.  W.  Pawlak,  A.   Turak,  Y.  Briker,  B.  Ignasiak,  Novel Applications of
    Oil   Agglomeration   Technology.    Proc.:     • Twelfth  Annual  EPRI
    Contractor's Conference  on  Fuel  Science and Conversion, 1988, 5:1-23.

2.  W.  Pawlak,  T.   Ignasiak,   Y.   Briker,  D. Carson, B. Ignasiak, Coal
    Upgrading  bv Selective  Agglomeration.  Proc.:   Thirteenth Annual EPRI
    Conference on Fuel Science  and  Conversion,  1989, 6:3-33.

3.  T.  Ignasiak,  D. Carson, W. Pawlak, B. Ignasiak, Application of Coal
    Agglomeration  for  Clean-up of  Hydrocarbon Contaminated  Soil. Proc.:
    1989  International  Conference   on  Coal  Science,  1989,  vol.  II,
    1019-1022.

4.  T. Ignasiak, K.  Szymocha, W. Pawlak, D. Carson,  B. Ignasiak, Clean-up
    of  Soil  Contaminated  with  Tarrv/Oilv  Qrganics. Proc.: Fourteenth
    Annual EPRI Conference on Fuel  Science, 1990,  13:1-10.
                                 163

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                             TABLE  1
                Composition of Contaminated  Soil

Type of
Contaminant
Tar
Oil

Petrochemicals
C ,__ 1 «.
iamp le
Tar Refuse3
Oil Spills
Heavy Oil Sands
Industrial Waste

Toluene
Solubles
1-60
2-40
8-16
2-36
wtX
Solids
20-93
52-96
83-90
9-95

Water
4-54
2-4
2
0-54
dM6P
                          TABLE 2
      Particle  Size Distribution of Selected  Solids  (Z)
Particle size.
nro
0.000-0.125
0.125-0.250
0.250-0.500
0.500-1.000
*1.000
Sample
Description
clay/silt
fine sand

medium sand
coarse sand & gravel
MGP-6
49.0
51.0
_
—
-
MGP-7
6.0
15.3
20.1
22.3
36.3
HO-2
14.0
83.4
1.6
1.0
-
OS-1
13.0
11.5
14.2
10.3
51.0
OS-2
52.0
20.0
10.0
5.0
13.0
                                  164

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                    TABLE  3
            Contaminant/Coal  Ratio
Contaminant Type
Tar
Oil
Ratio max
1:2.5
1:4
                    TABLE  4
         Clean-up of Contaminated  Soil
         -  Tar/Oil  Concentration,
Sample
MGP-la
MGP-2
MGP-3
MGP-4
MGP-5
MGP-6
MGP-7*'D
MGP-8D
HO-1
HO-2
OS-1C
OS(light)-!
OS(1ight)-2
OS-gasoline
OS-diesel
OS(heavy)-!
OS(heavy)-2
PC-1
Feed
8.6
1.2
5.4
1.6
66.9
0.7
5.6
10.6
8.7
15.2
0.5
2.0
0.5
3.1
30.7
43.0
0.2
34.3
Processed Soil
0.07
0.00
0.29
0.20
0.10
0.10
0.07
0.17
0.25
0.04
0.04
0.17
0.03
0.06
0.25
0.08
0.00
0.01
.II stage processing
 froth collector  required
 no coal  required
                         165

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                               TABLE 5
                     Clean-up  of  MGP-7 Sample
                   - Tar/Coke  Concentration,
Sample
as received
processed -
processed -
processed -


Stage Ia
Stage Ib
Stage IIb
Tar
5.50
0.60
0.16
0.07
Coke
12.0
5.0
1.6
0.7
           froth collector,  2%  of coal
           froth collector,  B%  of coal
       100
                                         Diesel
                                                   LJghl Oil I
                                                         Light Oil II
                                                     Heavy Oil
Fig. 1.  Simulated Distillation Profile of Selected Contaminants
                                   166

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               CONTAMINATED SOIL/COAL/WATER
        I Stage
II Stage
I .Omm
            Grinding
                                          -1.0 mm
                     I
                  -1.0mm
                   Reject
                 Tailings
         REJECT
                                Froth 1
                          Middlings    Froth 2 —
                           ,/'^

            CLEAN soil'''          ""COMBUSTIBLEPRODUCT


 Fig.  2.   Scheme  of Processing Tar/Oil Contaminated  Soil
     ft
     "6
             8.6
            Feed
               Temperature °C
1
25
1
4.8
60
70
I
80
                 Tailings
         Fig.  3.   Effect of Temperature on Clean-up
                         167

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COMMON  MISCONCEPTIONS  ABOUT THE  RCRA  SUBTITLE C  EXEMPTION  FOR
WASTES FROM CRUDE OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION


Mike Fitzpatrick  *
Environmental  Scientist
Office  of Solid Waste
U.S. EPA
Washington,  D.C.,  USA
Abstract

Certain  wastes  unique  to   the   exploration,  development   and
production of crude oil  and  natural gas have  been exempted  from
federal regulation as  hazardous wastes  under Subtitle  C of  the
Resource Conservation and Recovery Act (RCRA) in the United States.
This  regulatory  exemption  has  been variously  interpreted  and
sometimes  mistakenly   applied  to  wastes  not  covered  by   the
exemption.   This paper will  explore the legal background of  the
RCRA exemption and clarify the Agency's interpretation of the  scope
of the exemption.  It will also  clarify  the relationship of  RCRA
exempt wastes to CERCLA, as well as the differences among hazardous
materials,  hazardous wastes,  solid wastes (non-hazardous  wastes),
and exempt wastes.  Examples of common misconceptions  of the  scope
of  the  exemption will  be given.    Recommendations   and  a  brief
overview of the legal requirements  for the proper  handling of both
exempt and non-exempt  wastes  will also be touched upon.

Background

The Resource Conservation and Recovery Act  (RCRA) was enacted by
the United States Congress in 1976  and amended in 1980 and  1984.
The objectives  of this Act are to promote the  protection  of  human
health and the environment and to  conserve  valuable  material  and
energy resources.  To meet these objectives, RCRA  provides for the
promulgation of  regulations/guidelines  that  assure  wastes  are
managed in a manner that protects human health  and  the  environment.
RCRA also includes definitions of important terms,  including "solid
waste"; "hazardous waste";  and "disposal."
     Opinions expressed in this  paper are  solely those of the
     author and do not necessarily represent those of the U.S.
     Environmental  Protection Agency


                               169

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The term  "solid waste"  as defined  in RCRA,  means  any garbage,
refuse, sludge from a waste treatment plant, water treatment plant,
or air pollution control facility and  other discarded material,
including solid, liquid, semisolid, or contained gaseous material
resulting  from industrial, commercial,  mining, and  agricultural
operations, and  from  community activities,  but does  not include
solid  or  dissolved material  in  domestic  sewage,   or  solid  or
dissolved  materials  in irrigation  return  flows  or  industrial
discharges which are point  sources subject to permits under section
402 of the Federal  Water Pollution Control  Act.

The term "hazardous waste" as defined by RCRA means a solid waste,
or  combination of  solid wastes,  which because of its  quantity,
concentration, or physical, chemical, or infectious characteristics
may -
      (A) cause, or significantly contribute to an increase in
     mortality or  an  increase in serious  irreversible,  or
      incapacitating reversible, illness; or

      (B)  pose a substantial present  or potential hazard  to
     human health or the environment  when improperly treated,
     stored, transported or disposed of, or otherwise managed.

The  term  "disposal"   means  the  discharge,  deposit, injection,
dumping,  spilling, leaking,  or placing  of  any  solid  waste  or
hazardous  waste  into  or on any land  or water so that such  solid
waste  or hazardous  waste or any constituent  thereof may  enter the
environment  or be  emitted into the  air  or  discharged  into any
waters,  including  ground waters.

Subtitle D of RCRA provides EPA the statutory authority to regulate
the disposal  of  any solid  waste.   The regulations that  have been
promulgated   under  Subtitle   D   to  date   provide  for   state
implementation and  enforcement of state regulations that  have been
developed  based upon certain minimum standards  set by the federal
government  in Parts 256 and 257 of Title  40 of the U.S.  Code  of
Federal  Regulations (40 CFR).   Although  Subtitle D  regulations
specific  to the oil and gas  exploration  and production industry
have not yet been developed,  RCRA does provide the clear  statutory
authority  to  do so.

Those  solid wastes that are "hazardous wastes" are regulated under
Subtitle  C of RCRA.  Subtitle C provides the statutory  authority
for  federal  regulations and  their enforcement  for  the treatment,
storage,   and  disposal  of  hazardous  wastes.     States  may   be
authorized by EPA to  operate their  hazardous waste management
programs  in lieu of the Federal program if  they  demonstrate,  among
other  things,  that their programs  are equivalent to,  and  no less
stringent   than,   the  federal  regulatory  program.     Further


                               170

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information  about  hazardous waste permits  and state approval  can
be found in  40 CFR Parts  270 through 272.

In the  RCRA  amendments of 1980,  Congress exempted certain wastes
from regulation  as hazardous wastes pending study by EPA, but  the
exemption  did not  change the  statutory definition  of hazardous
waste.   The  Subtitle C regulations  promulgated by the Agency,  on
the other hand, provide a second definition of  hazardous wastes  for
the purposes of identifying which  wastes are to be  managed  in
accordance with the regulations.  This regulatory definition, found
in 40  CFR Part  261,  is  based upon  the intent of  the statutory
definition and lists some specific wastes as hazardous, as well as
identifies  those  parameters  or  "characteristics"  that can   be
measured for the purpose of identifying a hazardous  waste.    The
regulatory definition excludes those wastes  identified as exempt
from Subtitle C regulation.   Specific regulatory requirements under
Subtitle  C  include  provisions  for tracking  the  transport   of
hazardous  wastes   through   the  use of  manifests,  as  well   as
requirements for ground water  monitoring,  corrective action,   and
the storage, treatment, and disposal of hazardous wastes (40  CFR
Parts 260  -  268) .   For reasons discussed later in this paper,   it
is  important  to  distinguish  among the  various  definitions   of
"hazardous"  wastes, materials and substances.

RCRA Exemption for Crude Oil and Natural Gas Wastes

One group of wastes exempted  from  regulation  as hazardous wastes
pending study  by   EPA  (and a  Report to Congress)   are  drilling
fluids, produced water and  other wastes associated with crude  oil
and natural  gas and geothermal energy exploration, development,  and
production  (see Section  3001(b)(2)(A)  of  RCRA).   The Report   to
Congress was to be  followed within  six  months by  a determination
by the Agency on whether regulation of  these  exempt wastes under
Subtitle C was warranted.  In preparing  the Report to Congress,  EPA
was to evaluate  seven  study  factors  required in Section 8002(m)   of
RCRA.  These study factors  were:

     (A) the sources and volume of such wastes
     (B) present disposal practices
     (C) potential danger to human health and the environment
     (D) documented damage  cases
     (E) alternatives to current disposal methods
     (F) the cost  of such alternatives
     (G) the impact of those alternatives on the industry.

In  addition, the  Agency  was to study "the adequacy  of means  and
measures currently  employed by  the oil  and  gas and  geothermal
drilling and production industry, Government agencies, and others
to  dispose   of and  utilize  such  wastes  and  to  prevent   or


                              171

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substantially mitigate such adverse effects."  The Agency took this
study directive to mean that the Report to Congress should include
an evaluation of the effectiveness of state and federal regulatory
programs  for  the purposes  of managing  these wastes  in lieu  of
Subtitle C regulation.

Following completion of the  Report  to Congress  (1)   in  December
1987, the Agency held  a  series of  public hearings and  received
public  comment on the  report.    Based upon the  findings in  the
Report  to Congress and subsequent public comment, EPA  published
its  regulatory determination in the  Federal  Register on July  6,
1988  (2),  announcing  that  regulation  under  Subtitle  C was  not
warranted  for  exempt wastes  from  crude  oil,  natural  gas  and
geothermal   energy  exploration,  development  and   production.
However, the Agency  did note that some regulatory gaps did exist,
and  committed  to:   (A) work with  the states to  improve  their
regulatory programs,  (B) promulgate regulations under  its Subtitle
D  authority  specifically tailored to exploration and production
waste management activities, and (C)  work  with  Congress to develop
any  additional  authorities that may be needed.

The  Subtitle C  exemption for these oil and  gas wastes  is  directed
at "drilling fluids,  produced waters, and  other wastes associated
with the  exploration,  development,  or production of crude oil  05
natural  gas."    Included  in  the Report  to Congress  were  EPA's
tentative definition of the scope of  the exemption based  upon the
statutory language and legislative history, and three criteria that
EPA  believes  should be  used to  determine whether  a  waste   is
included within the exemption.  Briefly, exempt wastes  must be:  1)
intrinsic to exploration,  development or production  activities;  2)
uniquely  associated with exploration,  development  or production
activities;  and 3)  not generated as  part  of  a transportation  or
manufacturing  operation.  These three criteria are spelled out  in
more detail on page 11-18 of the Report to Congress.  Also, in the
regulatory  determination,  EPA presented  a list  (based  upon the
Report to Congress and public comment) of common examples  of exempt
and  nonexempt  wastes.   For wastes not specifically identified  in
the  regulatory  determination, reference must be made to the  three
criteria  in  the Report to Congress  to  determine  the  status of a
specific  waste stream.   Table 1  presents  examples of exempt and
nonexempt wastes  listed in the regulatory  determination.

Other Regulatory  Programs

In addition to RCRA,  other federal and state environmental statutes
and  regulations apply to oil and gas exploration and production
wastes.  The Subtitle C exemption does not negate  the authority  of
these other statutes, but it may  influence  the way  in  which  other
statutes  are applied towards the  management of wastes  from the


                              172

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                             TABLE 1
Examples of RCRA Exempt  and  Non Exempt Oil and Gas Wastes   *
EXEMPT WASTES
Produced Water
Drilling Fluids
Drill Cuttings
Rigwash
Well Completion Fluids
Workover Wastes
Gas Plant Dehydration Wastes
Gas Plant Sweetening Wastes
Spent Filters and Backwash
Packing Fluids
Produced Sand
Production Tank Bottoms
Gathering Line Pigging Wastes
Hydrocarbon-Bearing Soil
Waste Crude Oil From Primary
Field Sites
NON EXEMPT WASTES
Unused Fracturing Fluid/Acid
Painting Waste
Service Company Wastes
Refinery Wastes
Used Equipment Lubrication Oil
Used Hydraulic Oil
Waste Solvents
Waste Compressor Oil
Sanitary Wastes
Boiler Cleaning Wastes
Incinerator Ash
Laboratory Wastes
Transportation Pipeline Wastes
Pesticide Wastes
Drums, Insulation, and
Miscellaneous Solids
* Excerpted from the EPA Reaulatorv Determination
                               173

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exploration, development,  or production  of crude oil  or natural
gas.   These other authorities  include the Underground Injection
Control  (UIC) regulations  under the Safe Drinking Water Act, the
National  Pollutant Discharge  Elimination  System (NPDES)  permit
requirements  under  the  Clean  Water Act,   the  Department  of
Transportation   regulations  governing   the  transportation  of
"hazardous  materials"  (which may include products in  addition to
wastes), and various state  statutes and regulations.

In  addition, certain oil and gas wastes are also controlled under
the  Comprehensive  Environmental   Response,  Compensation,   and
Liability  Act  (CERCLA) known  as "Superfund."   Because  RCRA and
CERCLA are  closely related,  it  is important to remember that they
are separate  and  distinct.   While  they  may  contain  similar
definitions and provisions,  CERCLA is  designed to  mandate  the
clean-up of "hazardous substances"  (which  includes more  than the
universe of "hazardous wastes")  by the  parties responsible  for
their  release.  It should also be pointed  out that, although there
is  a petroleum exemption under  CERCLA, it  is different  than the
RCRA exemption for exploration, development and production wastes.
In  particular,  CERCLA  Section  104  (a) (2)  states that the  terms
"pollutant" or  "contaminant" do  "not include petroleum,  including
crude   oil   or   any  fraction   thereof which  is not   otherwise
specifically listed or designated  as  hazardous   substances  under
section 101(14)(A) through  (F)  of this title,  nor does  it include
natural gas,  liquefied natural gas, or synthetic gas of  pipeline
quality."    Section  101(14)  of CERCLA  also  states  "the  term
 [hazardous  substance]  does  not  include petroleum, including crude
oil or any  fraction thereof which  is  not  otherwise  specifically
listed or designated as a hazardous substance...  and the term does
not include natural gas,  natural gas  liquids,  liquefied natural
gas,  or synthetic gas  usable for fuel."  The  legislative history,
regarding the petroleum exclusion in CERCLA indicates that although
petroleum   and   any  fractions  thereof  are  exempt,   hazardous
substances  that  may  have been  added to the  oil,  but which are not
normally found  in petroleum at the levels  added, are not exempt.
The source of  the contamination, whether intentional addition of
hazardous  substances  to the petroleum or  addition of  hazardous
substances  by  the use of  the petroleum,  is  not relevant  to the
applicability  of  the  petroleum exclusion.    Therefore,  EPA  may
respond under  CERCLA  to releases  of  added hazardous  substances.
EPA may also respond  under CERCLA to releases  of  non-petroleum
hazardous substances (as defined under  CERCLA) from exploration and
production wastes.  In fact, several oilfield waste disposal sites
that accepted RCRA Subtitle C exempt wastes  are now Superfund sites
because these wastes  were not managed  in  a  way to prevent  the
 release of hazardous substances, and the RCRA exemption  does not
 relieve the operator  of liability  under  CERCLA.  Similarly,  any
                                174

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state requirements  that oil field wastes  be treated as  hazardous
wastes are independent of the RCRA exemption.

rommon Misconceptions

Since the inception of the exemption for oil and gas exploration,
development  and  production wastes under Subtitle C of RCRA,  there
has been  confusion  by  both  operators  and  state  and  federal
regulators.   Most of the misconceptions relative to the  exemption
can be divided into two groups: the first concerns the scope of the
exemption,  and  the second  concerns the  inherent hazard of  the
wastes.

The first group  of misconceptions  relative to the  scope of  the
exemption include the following:  (A) All wastes onsite are exempt;
(B) All service  company wastes  are exempt;  (C)  Unused  products
originally  intended  for  oilfield use are exempt;  and  (D) Exempt
wastes are CERCLA exempt.  These  misconceptions result from a lack
of understanding of the intent and legal basis for the exemption.
Congress intended  to exempt from the  burden of  full  Subtitle  C
regulation   those  wastes  that  are  intrinsic  to  exploration,
development,  or  production  processes  and  that are  generated at
facilities  employing  these  processes.   The exemption  was  never
intended to  free operators from all  forms of waste regulation,  nor
to exempt operators from liability in cases of mismanagement of the
waste.

Not all  wastes generated at an oilfield site are intrinsic to, or
uniquely associated with, oil and gas exploration, development or
production.   The EPA Report to  Congress provides three  criteria
that must be met in order for a waste to be  considered exempt.  It
is  important  that  a  waste be both  intrinsic  to,  and  uniquely
associated with,  efforts  to extract oil or natural gas.   If a  waste
generated  at  an exploration  or  production site  (other  than  a
substance that has been used "down-hole" or produced from the  well)
is the same  as  a waste generated by a  nonexempt industry (e.g. ,
oil refining), then that particular waste is not unique  to oil or
gas exploration,  development or production,  and is, therefore,  not
exempt.   Examples would be waste solvents used to clean  tools  and
equipment,  and waste crankcase and  lubricating oils.  Similarly,
unused products that  are to be discarded are  not exempt because
they  were   never  intrinsically  derived  from  the  exploration,
development  or production of oil or gas within the meaning of  the
statute, regardless  of  the  intent  in preparing the   product.
Examples would include spilled chemicals,  truck clean out wastes,
and unused excess or  off-specification products such as improperly
formulated   completion fluids.    Finally.-   the  RCRA Subtitle  C
exemption has limited  bearing  on the  jurisdictional  coverage of
CERCLA,   since   these   are   two  separate   and   distinct   legal
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authorities.  Non  exempt RCRA hazardous wastes  are automatically
hazardous  substances  under  CERCLA,  but   some  substances  are
hazardous under  CERCLA for reasons  other  than being  a hazardous
waste.  Some RCRA  exempt wastes can be (and in  fact already have
been)  contributing factors  in  the identification of  Superfund
sites.  Therefore,  improper  management of RCRA  exempt wastes may
subject the operator to  CERCLA.

The  second  group of misconceptions concerns the hazardousness of
the exempt wastes.  There are basically two common errors: (A) all
exempt  wastes are  nonhazardous,  and;  (B)  if  small  amounts  of
nonexempt  hazardous  wastes  (by   implication  both  listed  and
characteristic hazardous wastes) find their way into a large volume
of exempt waste,  the entire volume  is designated as hazardous.  The
first misconception in  this  group arises from confusion  over the
intent  and  meaning  of  the exemption, while the second comes from
the  blanket application of the  so-called mixture rule for listed
hazardous wastes to characteristic hazardous wastes as well.

The  regulatory  definition of  hazardous  waste  found  in 40  CFR
Sedtions  261.3  and 261.4 excludes  "drilling  fluids,  produced
waters,  and   other wastes   associated  with  the  exploration,
development, or  production of crude oil, natural  gas or geothermal
energy," but it  does not change  the wastes'  basic nature,  nor does
it alter or change the  statutory definitions of hazardous  waste or
hazardous substance found in RCRA and CERCLA.   It would  be  more
accurate  to refer  to  these  wastes  as "RCRA  exempt"  instead  of
"nonhazardous" since an exempt  waste may still exhibit hazardous
characteristics  even though it is not regulated as such under RCRA.
The  terms "hazardous waste,"  "hazardous substance"  and "hazardous
materials"  are terms of  art that have very specific  statutory and
regulatory definitions that may  differ in the various authorities.
The  improper  use   of  the terms  "hazardous"  and  "nonhazardous"
without clear reference to a specific  statute or regulation  can
cause confusion  over the status  of a waste.  This is an important
concept since an exempt waste  may still  be considered hazardous
under  state hazardous  waste  laws,  Department of  Transportation
regulations,  or  for the  purpose  of application of Superfund.

The  so  called  "mixture  rule," although not specifically an exempt
waste  issue,  is  also a  source  of confusion on  the part  of  some
operators.   There  are  two types  of nonexempt  hazardous  waste;
listed  and  characteristic hazardous wastes.   A listed hazardous
waste is one from specific or non-specific sources which the Agency
specifically listed in  the RCRA  regulations as hazardous.  A listed
hazardous waste  is considered hazardous wherever it is generated
and  managed unless it  has been specifically  delisted by EPA; a
characteristic hazardous waste  is  only hazardous when  it  exhibits
one   or more  of   the   hazardous  characteristics   of toxicity,
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reactivity,  ignitability,  and  corrosivity  as defined  in 40  CFR
sections 261.20  through 261.24.   A non-listed waste stream may be
either    hazardous   or    nonhazardous   depending    upon    its
characteristics, as determined on a site-specific and time-specific
basis.   The  mixture rule  is applied  differently to  listed  and
characteristic   hazardous  wastes.    Listed  wastes  are always
hazardous  (unless  specifically delisted by EPA)  and any  mixture of
a listed hazardous wastes  and  a nonhazardous  or exempt  waste  is
itself  a hazardous waste  regardless of  the relative volumes of  the
wastes  prior to  mixing.

A mixture of a  characteristic  hazardous  waste  (other  than  by a
small quantity  generator  as defined  in  the regulations)  and a
nonhazardous waste  is  only  a  hazardous  waste  if the  resultant
mixture also exhibits a hazardous characteristic.  However, the  act
of mixing a  characteristic hazardous waste with a nonhazardous  or
exempt  waste to  create  a nonhazardous waste mixture is considered
to be treatment  of a hazardous waste and must be  done in accordance
with the  appropriate RCRA requirements,  including any  necessary
permits.

It can  be  seen that, although not  every case  of mixing a hazardous
waste with exempt or nonhazardous wastes results in  a  hazardous
waste mixture, significant legal and logistical problems can arise
from co-disposal of  exempt and nonexempt wastes.

Responsible  Waste Management

The question may come to mind that, if some exempt wastes may still
be inherently hazardous,  then what does the exemption really do  for
the operator?  The answer is simple: it frees the operator  from the
prescriptive measures  of  the  federal Subtitle  C  regulations;
rather, the  operator is  subject to Subtitle D and other  existing
federal and  state authorities.   While the standard for Subtitle D
protection is the  avoidance of a reasonable probability  of adverse
effects on  health,  this  together  with  other  laws and  prudent
management to avoid  CERCLA liability suggest that there are still
incentives  for  responsible waste  management practices  that are
protective  of   human  health  and  the  environment.     While  the
exemption lifts  many of the burdens of  Subtitle C requirements,  it
remains the operators' responsibility to assure adequate protection
through proper waste management practices.

Responsible  waste management practices  may include such activities
as waste  segregation,  waste minimization,  recycling,  compliance
with applicable  regulations and  industry standards,  prevention,
mitigation and remediation of adverse impacts upon human health  or
the environment, and advance planning to identify and avoid actual
or potential adverse impacts.  In the United States,  the  American


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Petroleum Institute  (API)  has taken  the initiative  in assisting
operators in managing their wastes by issuing an API Environmental
Guidance Document that outlines applicable regulations and industry
standards for various waste management  practices (3).   This first
edition is now in the process of being  revised and updated.

Conclusion

The RCRA exemption for certain oilfield wastes  is a legal statement
(in  the  RCRA Amendments  of 1980)  that  excludes certain  defined
wastes from the  requirements of RCRA  Subtitle  C.   This exclusion,
in and of itself, does not make any judgment on the inherent hazard
of the wastes in question.   It does not change the chemistry of the
wastes, nor does it  relieve the waste generator or disposer from
the  responsibility  of handling and disposing  of the wastes  in a
prudent manner.  The exemption only gives the operator the  ability
to select a disposal  option other than full Subtitle C  requirements
for  what might otherwise be a hazardous  waste;  however,  it should
be noted that the selected option must still be in  compliance with
other existing authorities.  Prudent managers of some exempt wastes
often elect to go beyond the minimum  legal  requirements.

As mentioned  above,  the exemption makes no legal  finding  on  the
inherent hazardousness of the wastes,  and the RCRA-exempted wastes
are  not  automatically  exempt  from  Superfund or  other  legal
authorities.  An operator may elect to dispose of his  wastes at a
Subtitle  C permitted facility  if  he believes that the inherent
hazard  of the waste requires that  level of  protection for  the
environment.  However, if the operator believes that another waste
disposal option provides sufficient protection for the  environment,
he is  free  to use that  option.   But in  either  case, the operator
may  be held liable for his action if damages occur.  Prudent waste
management  makes good sense for several reasons: to avoid future
liability  costs, to  promote good public relations, and to lessen
the  need  for  more prescriptive state  and federal regulations.

References

1.   U.S.  EPA,  Report to Congress Management  of Wastes from  the
     Exploration, Development, and Production of Crude Oil,  Natural
     Gas  and  Geothermal Energy, EPA/530-SW-88-003  (NTIS order No.
     PB88-146212), December 1987

2.   U.S.  EPA,  Regulatory  Determination  for Oil  and  Gas  and
     Geothermal  Exploration,  Development  and   Production  Wastes,
     Federal  Register. Vol. 53, No.  129, July  6, 1988,  p.  25446

3.   API   Environmental  Guidance  Document,   American  Petroleum
     Institute,  Washington, D.C., January 15,  1989


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COMPREHENSIVE ENVIRONMENTAL TRAINING PROGRAM
FOR THE PRODUCTION OF OIL AND NATURAL GAS INDUSTRY
Forrest W. Frazier
Regional Environmental Affairs & Safety Coordinator
Europe, Latin America and Far East Region
Amoco Production  Company
P.O. Box 3092
Houston, Texas 77253
Abstract

Environmental rules and regulations are on the increase worldwide. The United States, the
apparent leader in environmental requirements, have increase the number of requirements
imposed on industry, increased the enforcement of these requirements, and have increased the
personal liabilities of employees.  Not only the United States but such international countries,
as Norway, Saudi Arabia, U.K., and New Zealand all are requiring more and more attention be
given to environmental concerns.

Because of this concern it is imperative Amoco employees are properly trained in the field of
environmental protection.  Not only because it's  the  law,  but  Amoco's own  internal
requirements  specify that we operate with a  "standard of care"  throughout our worldwide
endeavors.

Amoco Production Company has  made  a commitment to developing a comprehensive
environmental training program that gives the employees the tools needed to make intelligent
decisions.

We divided the training program into three phases corresponding to  the three levels of
employees within Amoco Production, (i.e.  Managers, Engineers,  and Field  Personnel). Each
phase requires its own unique level of understanding of the environmental requirements.  For
example, on one end  of the spectrum the managers need  a  broad understanding of the
regulations.   Where as on the other end the field personnel  would need a more detailed
comprehension of the law. In order to develop a  strong foundation within Amoco, we have
directed our phase I at the field personnel followed by the engineers for phase II and finishing
with management as phase III.

The program will stress the legal requirements as  will as potential environmental impacts to
oil and gas operations. The key is to recognize when a  requirement  is applicable to your
operations. The training will be in a modular form  consisting of a video tape, student manual,
and a teachers manual. There will be approximately 10 modules for phase I.  Each module will
range from 2-4 hours to complete. They will include pre-testlng,  problem solving associated
with the video, and a review. Each module is self contained and could be  sent to any location
for training.

We expect this  program to  result in  developing a higher level of understanding of
environmental rules and regulations by our field  employees throughout Amoco Production
Company, and standardizing,  if you will, the training employees receive for environmental
concerns.  It will create  an atmosphere  of compliance  among  the employees as well as
demonstrate Amoco's commitment to the protection of the environment.  Finally it has the
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potential to be used In the development of a standard of care and good operation practices
worldwide.
Objective

The objective  of this  project  was  to develop  a comprehensive  training program on
Environmental requirements, including both the legal obligations as well as Amoco's own
environmental policy and procedural requirements.

Within the last 20 years, the United States has increased its legislation for  environmental
protection. These legislative  acts require certain governmental agencies to develop extensive
rules and regulations which in turns creates  an ever increasing burden on  industry to
understand and comply with the law. These rules are usually very comprehensive and difficult
to read. Normal practice is to "weed-through" volumes of regulations to find that one section
or part of a section that directly applies to our industry.  This can be a monumental task
involving regulations dealing with issues such as clean air, clean water, or hazardous waste.

For each  one of these statutes the government has established penalties for violation of the
law. In the past, these fines and  penalties constituted nothing more than a "slap on the hand".
However,  as these laws become amended, the government has increased the penalties to include
substantial fines for companies as well as criminal penalties for individuals.  These penalties
place heavy emphasis on the fact  that our employees must be well trained in their legal
obligation to protect the environment.  With this  increase in penalties,  agencies have also
increased the enforcement of these requirements.  For example, from the time the United
States enacted its first pollution control statute in 1899 until 1980, only 15 environmental
crimes were prosecuted, averaging  fewer than  2 per decade.  Plus, all of these cases were
misdemeanors resulting in average fines of only $50 to $100. On the other hand, over the last
nine years, there has been a dramatic increase in federal enforcement. Since 1982, the courts
have handed down more than 400 convictions.  As of May, of 1988, judges have  imposed more
than  $23 million dollars in fines and  sentenced individuals to a cumulative  imprisonment
time of more than 250 years.

Therefore, compliance is critical for a company to operate in todays environment.  It's vital for
the person in the field to be adequately trained to understand his/her obligation to protect the
environment they live and work  in.


Training  Requirements

In order to establish the training  requirements two questions had to first be answered: 1) Who
are the recipients of this training and 2) what is the  information the employees have to know?

The recipients for environmental training can be divided into
three categories:

       1.      Management
       2.      Engineers
       3.      Field Foremen  & Field Environmental Specialist
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Management

Management officials have the authority over various operations within the company.
The ultimate responsibility for these  operations lies  on his/her shoulders.  If a
violation of an environmental law  occurs at a facility under his/her control,  he
personally can be held liable  for the crime.  Even though he was not personally
involved in the violation and was unaware of  what was going on, he should have
known and was in a position to stop the action.  This is the way U.S. Environmental
law is interpreted.

Therefore, management needs some form of basic or generalized environmental
training. An overview covering the key elements of the law and a reminder of Amoco's
Environmental Policies should be sufficient.

Engineers

The key role  of  an engineer  is  in the  design of  new operations, facilities,  and
experimental functions, (i.e. research and development).  In designing a brand  new
facility or revamping  an old  one. the  engineer  must  be constantly  aware  of
environmental concerns.  For example, air emissions from stacks, water  discharges
from pipes, or hazardous waste by-products from various process. Even something as
simple as moving locations could make a difference.  The engineer needs  a more in-
depth understanding of the impact industry has on the environment and how simple
considerations up front in the planning stages can prove to  benefit the company
economically, while providing environmentally sound result.  The engineer also needs
to know that certain actions may require extensive permitting by the government,  and
planning for these must be done early in the program.

In the area of research  and development, newer and better chemicals are constantly
being  developed to help In the production of crude  oil.  Because of these  exotic
chemicals, there are potentials  for harm to human health and the environment. Even
though they may work better, the potential liability may be to great for the company.
As a result,  the  training  for engineers should provide  a more comprehensive
understanding of environmental  requirements and the effects of pollution on the
environment.

Field Foremen & Field Environmental Specialists

Field foremen  and field environmental specialists are the people "in the trenches." The
daily compliance of environmental laws and Amoco Policies is entirely in their hands.
They must complete permit applications, perform monitoring and sampling, and be
constantly on the  alert for potential problems. They also have a more direct contact
with government agencies. The first line of compliance is in the field.  These people
 need to have the best understanding of all on environmental requirements that affect
 their operations.  Therefore, an in-depth, comprehensive training program is vital for
 field personnel.

Amoco has never before  embarked on an environmental training program of  this
 magnitude.  Because of this, Amoco has decided to use a phased-in approach. The  first
 group to receive this extensive training will be the field personnel.  This will start the
 development of a strong foundation for Amoco's compliance. The second phase will
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      concentrate on training for the engineers and finally the third phase on managers. As
      Amoco develops It's standard of care worldwide training on environmental concerns
      will reach to every Amoco operations.


Evaluation of Existing Courses

First, a review of existing environmental training course was made. Amoco consulted various
publications,  Interviewed other major oil companies and  contacted various educational
institutions. All available courses were eliminated for various reasons.  Most were too general
in scope or not specific enough to the oil industry.  Others were screened out because of
excessive emphasis on academic  training methods with  minimal trainee participation, or
excessive emphasis on promotion of company products and services throughout the training.
Overall, none of the courses reviewed fit the specific needs of Amoco.  It was decided at this
point to develop a  course to fit our own needs.


Designing of Training Curriculum and Courses

Since our own environmental training program would be Initially directed toward Amoco's
field personnel, we had to first determine exactly what the field personnel needed to know. The
production of crude oil and natural gas encompasses a portion of every environmental law on
the books today.  Each law covers the spectrum  of environmental protection and pollution
control.  Each law has specific areas of compliance for  the oil production industry.  Collecting
this Information and applying it in a manner understandable to field personnel was quite a
Job. It was decided to take each statute and break it down to the basics so that field personnel
could answer the simple questions of who, what, when, where, and how.

       1.     Who is responsible for compliance?
       2.     When do the requirements apply to me?
       3.     What are the requirements I  have to comply?
       4.     Where do I go for help?
       5.     How do these regulation affect me personally?

If a trainee can answer these basic questions regarding each statute, he will satisfy the course
objectives. It was decided to divide the requirements up into individual training modules. Ten
training topics have been identified for the field personnel.   Each module will consist of a
video, student workbook, and an instructor's manual.

       Video

       The  video will  be divided  Into  three segments,  1) a  general overview. 2) report or
       permitting completion,  and 3) a  review. Each segment will run five to ten minutes on
       the average.  The general overview will Introduce the topic and will be presented In one
       of several formats. For example, one format might use dialog between two individuals
       to establish a particular topic, while another format may use a narrator to walk the
       student through a topic.

       The  second segment would walk the  students through any paperwork requirement
       associated with that particular topic.  For example the module on water discharge
       would include how to complete a discharge monitoring report.
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Finally the third segment would be a brief review of what the student has learned In the
previous two segments and the class.

fitudent Workbook

Each workbook will consist of:

       1.     Pre-Questionnaire
       2.     Requirements of the topic as it applies to production operations.
       3.     Copies of all forms and/or permits
       4.     Post-questionnaire

The pre-questionnaire acts  as a benchmark for the instructor to identify the extent of
knowledge the trainee has for the subject prior to the video.  This is not designed to
embarrass the student, but merely to help the instructor design the course to fit the
needs of the class. The workbook also will have the specific requirements for the topic
as it relates to the production of crude oil and natural gas.  This eliminates the trainee
from having to review volumes of regulations looking for that one section that applies
to him. All of this has been done for the student making a quick and easy reference for
future work.

All forms  or permits associated with the topic will also be included. One set will be
completed as an example with an explanation for each blank on the opposite page. Also
a blank copy will be included  that can be  copied for future work. Finally a post-
questionnaire will be included as a means for the instructor to compare questionnaires
and determine if the message is getting across so he can adjust the training accordingly.
The following is a brief description of the  14 modules:

 1.     Department of Transportation (DOT) - Describes the  requirements of shipping
       hazardous materials to and from  our field locations.  Also discusses the proper
       paper work involved in transporting hazardous materials.

2.     Spill Prevention Control and Countermeasures fSPCC) for On-shore - Describes
       the specific requirements of preemptive  measures to reduce the likelihood of an
       oil spill. This also includes the recommended forms to help standardize Amoco
       operations.

3.     404 Permitting - Refers to section 404 of the Clean Water Act requiring
       permitting for dredge or fill work.  For example, permitting is required if you
       place a drilling platform in wetlands.

4.     Groundwater  Presents specific  requirements that must be followed to insure
       protection of underground  aquifers.  Also includes groundwater monitoring
       and cleanup.

 5.     Prevention of Significant Deterioration (PSD1 - Focus on air emissions.  The
       concerns, for example would be what can you emit, how much, and when does it
       apply.
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      6.     Hazardous Waste - Describes the characteristics of hazardous waste, and the
             handling of waste from generation to ultimate disposal.

      7.     Comprehensive Environmental Response Compensation Liability Act (CERCLA)
             - Identifies chemicals considered to be hazardous in your operation and advises
             how to properly report any spillage of these chemicals.

      8.     Superfund Amendment Reauthorlzation Act (SARA) - Applies to the general
             public's right to access information dealing with hazardous chemicals on your
             facility.  There is a considerable amount of paperwork associated with  SARA
             and failure to report properly carries significant  penalties.

      9.     National Pollution Discharge  Elimination  System fNPDESl for on-shore -
             Describes the permitting and regular testing for process water discharged into
             waters of the U.S.  Also includes an introduction to bio-monitoring. As well as
             extensive permitting and recordkeeping.

       10.    National Pollution  Discharge  Elimination  System fNPDES) for off-shore   Is
             the same as onshore however bio-monitoring is the key  element for offshore
             compliance.


Program Implementation

The following methods were considered for the implementation of this  program:  central
training facility,  traveling instructor, correspondence  training, or audio-visual training
packages.

In choosing the most appropriate approach, consideration was given to time, group size, and
audience. For example it would be difficult to bring all field personnel into a central training
facility.  Therefore, each  module was designed  to be self- sufficient.  The video, student
workbook, and instructor guide can be sent to a field location and taught to a small group by
either a person in the field  or a  traveling instructor.  As the  training  program expands to
include engineers and managers, other approaches may prove to be more appropriate.

Each module will be designed to create as much active participation as possible, by developing
small work groups within the class for common problem solving.


Results of Training

If this program is developed as planned. I see it having a very positive impact an Amoco. It will
formalize Amoco's training  while increasing the knowledge  and awareness of all Amoco
employees.   By providing a better understanding of pollution control, it will create an
atmosphere of compliance from  top management down to the field personnel.  It will also
demonstrate the commitment Amoco is taking to protect the environment and its employees.

Finally it will develop a  standard of care  and operating practices that  can be  utilized
throughout Amoco's world  wide operations.  Even in areas that may not have as extensive legal
requirements as In the United States we  can still operate in a method that will give high
priority to the protection of our environment as well as our employees.
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CONTAMINATED SULPHUR RECOVERY BY FROTH FLOTATION
I.  Adamache
Husky Oil Operations  Ltd.
Calgary, Alberta, Canada
INTRODUCTION

In order  to recover  the sulphur from contaminated sulphur  base  pad,  Husky Oil
Operations Ltd.  utilizes a froth flotation process at the  Ram River  gas plant
located in West  Central Alberta, approximately  250  Km from Calgary  [Fig.  1  -
Alberta map].   Ram River is one  of  the largest gas processing  plant  in North
America for the  production of  sulphur  from  sour gas.   The sour gas  plant
capacity is  17,700,000 m3/day with  a  hydrogen sulphide content  of between 10
- 35%.   The maximum  sulphur plant production is 4,600 metric tonnes  [tj/day.
 SULPHUR BASE PAD DESCRIPTION

 Background and History

 The froth  flotation  process in this  case  was conceived  to reclaim  the  base
 pads of sulphur  blocks  scattered  throughout  the  sulphur industry in  Alberta
 and in similar conditions worId-wide(1,2).   These sulphur blocks were formed
 during the  1950" s, 60"s  and 70's  when sulphur markets  were poor and  sulphur
 was generally regarded  as  an unwanted by-product  of oil and gas processing.
 As  a  result,  the sulphur was  poured directly  onto the  ground,  forming  the
 foundation or "base pad" for large  storage blocks. A schematic cross-section
 of  a  typical  base pad/sulphur  block  is shown  in Fig.  2.   The  contaminated
 area of  interface between  the  high grade elemental  sulphur product  and  the
 underlying  gravel  and  soil  contains  a  substantial   amount   of   valuable
 elemental sulphur.

 During the  1980's with  the improvement of  sulphur markets,  the high  grade
 elemental sulphur product overlying the  base  pads has been  re-melted  to  meet
 market  demands.   However,  the  sulphur  base  pads  and  other   contaminated
 elemental sulphur rejects  from industrial handling  have proven  difficult  to
 reclaim,   leaving hundreds  of   thousands  of  tonnes  of  contaminated  sulphur
 throughout  Alberta which are  environmentally undesirable.  Currently, it  is
 estimated that between 600,000  and  1,000,000  t  of contaminated sulphur  exist
 in Alberta with about 300,000 t being located at Husky's  Ram River Gas Plant.
 Not only are the  base pads  themselves an environmental problem,  but  moisture
 precipitation  on the  sulphur  blocks  and base  pads  forms an  acidic  water
 run-off  that  must be  collected,   treated and  disposed  of in  a controlled
 manner to  protect the  environment.  Although contaminated sulphur base  pads
 were  the  primary  reclamation  target  of  the   froth   flotation   facility,
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additional material  containing valuable elemental  sulphur has accumulated  at
other locations throughout Alberta  and  is  also targeted for processing.

Typical Composition

When  the  sulphur was  poured directly  onto the  ground the  molten elemental
sulphur intermingled  and  solidified in the soil, creating physical bonds and
contaminating the sulphur with  organic  impurities such as humus, wood, leaves
and  other vegetation  and with inorganic  impurities  including  fine .clays,
sand, pebbles and gravel.

At Ram River gas plant the base  pad contains  sulphur in the range of 807,,  In
other sulphur base pads in Alberta,  the  sulphur content could vary from 30 to
90% plus.


RESEARCH  AND  DEVELOPMENT (R&D)  OF  THE SULPHUR  BASE PAD RECOVERY  PROCESS  BY
FROTH FLOTATION

The  process  of sulphur recovery from  contaminated  sulphur products has  been
investigated by  the  industry  for a  number  of  years.   Primarily,  hot processes
have  been applied  to melt the contaminated sulphur  followed  by  filtration  or
separation by  gravity  for contaminant  removal.   The  hot remelt and filtration
processes have drawbacks related mainly to filter  plugging.   Due  to  fouling
of  the heat  transfer  surfaces by  the contaminants  the  efficiency  of  the
process is decreased.   In addition, a waste product  commonly  called "sulphur
cre«-e", containing  up to 80% sulphur, is produced.   These  hot processes  have
difficulties in  handling  sulphur base  pad  where the  contamination exceeds 10%
and  because  of rapid  fouling  of heat  transfer surfaces and  filter plugging,
efficiency could be  reduced when  the  contamination  is  as low  as 5%.   For
processing of  an average  sulphur  base pad  containing 20% contaminants,  the
hot  remelt and filtration method would only recover approximately  75%  of  the
sulphur   base  pad  feed.   "Sulphur   crete"  tailings  would  typically  contain
about  50% sulphur by weight  and  would  require  treatment and disposal which  is
both  expensive  and  a  potential  environmental  hazard.    Current practice
involves   hauling  tailings  to  a   landfill and  treating  with  three parts
limestone for  each  part  sulphur  to  neutralize  acidity.

A number  of   institutions,  including  Alberta  Sulphur Research   (ASR)  from
Calgary,  have  studied  sulphur  base  pad  recovery processes.  According  to  ASR,
elements  of  their sulphur base  pad recovery  processes  have  been  applied  to
sulphur clean-up in  Western  Canada.

At  the  Ram River gas plant,  a hot   contaminated  sulphur  recovery  pilot system
was  studied, constructed, operated,  evaluated  and shut down.   This system had
operational  problems  due to  fouling  of   the  heat  transfer  surfaces.   The
maximum  remelt rate  achieved  was   2.8  t/h  over a period  of   two  hours.   The
filter   screens   required  frequent   cleaning.    The  system  produced   the
unprocessable  by-product  "sulphur  crete".   The  sulphur  content  of  this
by-product was analyzed and found  to  contain  40 -  60% sulphur.   The  process
                                      186

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was discontinued when  operating costs could not be lowered  below the economic
threshold.

Hot processes have  the  disadvantage  of producing  organic  combinations  with
sulphur  which  are  objectionable  and  difficult  to  minimize  or  eliminate.
Carsul, which can  result from  the  reaction of sulphur and  hydrocarbons poses
problems  in  sulphur  discolouration and  in  deposition phenomena  which  can
result  in plugging of filtration  elements or of  other restricted  flow areas
such as,  orifices  and  spray nozzles(3).

Additionally, non-hot remelting  processes  have  been  investigated  by  the
industry,  such as:
- solvent extraction in  which elemental sulphur is taken into solution with a
  solvent;
- burning the contaminated elemental sulphur  to  SO   for injection  to  a Glaus
  recovery  plant;  however,   the  contaminant   combustion  products   could
 'adversely affect the recovery plant catalyst;
- use of two  immiscible  liquids which  differentiate  between  sulphur  and  its
  contaminants by  differences in density and wettability.
The above-mentioned "cold"  processes  have not yet  been commercially  applied
in the  oil and gas industry.

Due to  the problems associated  with the above mentioned contaminated  sulphur
recovery  processes,   alternative  methods,  including  froth flotation, were
deemed  necessary to be researched.

The froth flotation process was originally developed in the mining industry.
This process  has  not  been applied  commercially  in  the oil and gas industry
for the sulphur base pad contaminated sulphur recovery prior to  1984 when our
main froth flotation R and D activities started.

Following laboratory  testing and  experimentation, a  process flow sheet for a
froth  flotation  plant  was prepared.   The following phases illustrate the
evolution of the process:

- R and D studies  and froth flotation laboratory tests: December 1984  -
  December 1985

- Design by  Wright Engineers  Ltd.  Vancouver, British Columbia,  Canada and
  construction of  the froth flotation  plant  based  on  R  and  D  data:   1986 -
   1987; plant start-up:  May 1987.

- Patent granted in Canada in June 1987(1)

- Patent granted in United States in October 1989(2)

Froth Flotation Laboratory Tests Overview

Numerous froth flotation laboratory tests  were planned and conducted  varying
parameters,  such   as:   particle  size,  flotation  time,  reagent   types  and
quantities,  conditioning,   slurry  dilution,   pH  and  temperature  control.
                                    187

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Typical  laboratory results,  using Ram  River sulphur  base pad  samples, are
shown in Table 1.

The  feed to flotation  laboratory tests was prepared  by  size  reduction and
screening to -10 mesh, followed by conditioning  with reagents.  Typically the
following reagents were used:

- Frother:  methyl  isobutyl carbinol  [MIBC]:  in the  order of 0.08  to  0.5 Ib
  per short ton of dry raw material  treated;

- Promoter/collector: kerosene  or fuel  oil  in the  order of 0.05  to  0.5 Ibs
  per short ton of dry raw material  treated.

In  general,  three  stages  of flotation were  used:   a first  rougher  stage and
two  stages  of  cleaning with  a  duration of  approximately 15 minutes for the
first  stage and  approximately  7.5  minutes  for  each  cleaning  stage.   The
reagents were used in the conditioning and rougher  stage.

Comparison  of Froth Flotation with Other Alternatives Applied  by  the Industry

Figure  3 provides an  comparison example  of the froth flotation versus  hot
remelt  and  landfill  disposal for Ram River  conditions.  The  froth  flotation
process  compared  with  hot  remelting  appears  to  be superior both from an
environmental and  economic standpoint, primarily due to its higher  recoveries
 [98% vs 75%] and  lower  sulphur  content tailings   [7.5%  vs 50.1%].  As  men-
tioned  previously,  the  hot remelt tailings normally would have to  be  hauled
to  a landfill  and  neutralized with limestone.  Due  to  the  much lower sulphur
content  of  the froth  flotation tailings, research  is ongoing  to   place  the
tailings on the  reclaimed  base  pad area,   treat  them  with  an appropriate
amount  of  limestone  and  mix with  the  top soil  for  revegetation.   Also,
research is currently  being conducted  on  the  reclamation of  sulphur  rich
tailings through test plot and greenhouse experimentation.

The Ram  River example presented in Fig.  3 is  a base  pad containing  in average
20% contaminants  which  could  be considered a  typical  value.   It  is   not
uncommon,   however,   to   encounter  base    pads   with   higher   levels   of
contamination.   This  can cause  problems  with the hot remelt  system, as
mentioned  previously,  due  to fouling of  heat transfer  surfaces and  filter
plugging resulting in  large  reductions  in overall efficiency  and hence lower
sulphur   recoveries  and  higher   sulphur  losses   in  tailings.    The  froth
flotation  process,  on  the  other hand, is  capable of  coping  with  higher
quantities  of contaminants in the  feed material.

A  possible  third alternative as  shown  in  Fig.  3,  is simple disposal of  the
sulphur  base pad  in  landfills.   Although this does  not result  in any sulphur
recovery,  it may  be necessary  in cases where  the  application  of  recovery
processes  is  not possible due to  small  base pad quantities,  remote location
or   the   presence  of  unprocessable  contaminants.   Disposal  involves,  as
mentioned   previously,  treating  the sulphur with  limestone  to  neutralize
acidity  and disposing  at  a landfill   site.   This  is  the  least   desirable
 option,   both   environmentally  and  economically,   but  may  be   the   only
                                    168

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'alternative in difficult situations.
 RAM RIVER FROTH FLOTATION SULPHUR  RECOVERY PLANT DESCRIPTION

 The simplified process  flowsheets presented  in Figs.  4  and 5 illustrate  the
 overall process  utilized at  the  Ram River froth flotation  plant.   Figure  4
 shows  the  front-end size reduction  and  classification circuit  while Fig.  5
 presents the sulphur  flotation circuits  resulting in  the  final sulphur  cake
 product.   Each  of  the  major  components  of  the  process  will be  briefly
 described with reference to Figs.  4  and  5.

 Size Reduction and  Classification  [Fig.  4]

 The  contaminated sulphur  base  pad  material  is  reclaimed  by  a  scraper in
 combination  with a front-end loader and placed  into  a  large  hopper with  6
 inch  openings  for a preliminary  screening.   Large elemental sulphur  chunks,
 being  very  friable  in  nature,  can  be  broken  through the  hopper   openings.
 Pieces of  stone  and other non-sulphur material,  such as metal or large pieces
 of wood, will  remain on  the hopper and be removed to waste.  Hopper  undersize
 is collected and passed  to  a  feeder  belt, which  discharges the material onto
 the feed conveyor.  The  feed  rate  is monitored by a weigh-scale located under
 the feed conveyor.

 Raw feed less  than 6 inches  in size is  conveyed to a rotary  scrubber where
 elemental  sulphur and  contaminants  are  tumbled  with water  to  break down the
 more  friable sulphur  lumps.   The  rotary  scrubber  product  is screened  through
 a 1/2 inch trommel screen on  the  rotary scrub.ber  discharge.   Oversize waste
 material containing particles larger than 1/2 inch  is  discharged to a debris
 pile,  while  undersize particles  less than 1/2  inch flow into a spiral  classi-
 fier  for classification  and densification.

 As feed enters the  spiral classifier,  the coarse particles begin to  settle to
 the bottom of  the inclined  vessel.  The  fine  particles,  less than 10 mesh in
 size,  are  contained in  the overflow which  is  discharged at  the  lower-end of
 the classifier.   The  coarse  particles  that have  settled  in the tank settling
 zone  are  conveyed to  the upper-end  of  the  vessel by a rotating spiral screw
 at a  rate  slow  enough  to  allow  liquid  drainage  down to  the  lower-end and
 prevent excessive slurry agitation.  The coarse  particles are then fed to the
 attrition  scrubber.

 Attrition  scrubbing is  the process  of  forcing  particles  within a  slurry to
 impact and abrade against  each other.    It is  used to remove film or coatings
 from  particles to  increase the  efficiency of  the next step  in the circuit,
 the flotation  process.   This cleaning or polishing  of the sulphur  particles
 increases   the   likelihood  that   the  air  bubbles  will   float  the   sulphur
 particles.   The   particles  are  given  momentum  by two  propellers  driven at
 opposing  pitch,  which force  the  particles against  each  other  at  a velocity
 that  causes abrasion.   Some  particle size  reduction occurs  but  this is less
 significant  than the actual particle cleaning.
                                     189

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The'  discharge  from  the  attrition scrubber  and  the  fines  overflow  of  the
spiral classifier  are combined  and pumped  to  the 10  mesh vibrating  screen.
The  undersize  of the  10  mesh screen is  circulated  to  the conditioning  tank
ahead  of  the  flotation  circuit.  The  oversize, of  the  10  mesh  screen is
normally directed to  the  spiral  classifier feed.

Conditioning and Flotation Circuits [Fig.  5]

The  undersize  of the  vibrating  screen  flows by  gravity  to  the conditioner
tank  where  the flotation reagents MIBC  and  kerosene or fuel  oil are added,
to  aid in  the  flotation of  the  sulphur particles.   After  mixing  in  the
conditioning tank the  slurry  flows to  the  rougher flotation cells.  The froth
flotation circuit is  composed of three stages:  the 6 cell  rougher stage,  the
3 cell cleaner stage,  and the  3  cell recleaner  stage.

A  typical  flotation  cell process  is illustrated  in a schematic cross-section
presented in Fig. 6.   The cage-like rotor  draws air through the annular space
between  the standpipe and the  shaft.   The  air  is  mixed  with  the  slurry,
forming  air bubbles.   MIBC, which is  a  frother,  reduces the  surface tension
of  the water  enhancing the  formation  of  finely divided  air bubbles.   In  this
manner,  the sulphur particles collide with and attach  themselves  to  the  air
bubbles  and float to  the surface.  The  sulphur  flotation  is also  aided  by
kerosene  or fuel oil  which  is a  promoter/collector  that coats  or  films  the
coarse  sulphur particles making their  surfaces more  non-wettable which helps
them float.

As  the  slurry  flows  through the  6 cell rougher  flotation circuit, the sulphur
particles  floated by the air bubbles  form  a  froth at the  surface  of  the
flotation  cells which  is skimmed  off and pumped to  the  first  stage  3  cell
cleaner.   The  impurities and  contaminants are carried  through  the lower  zone
of  the  rougher cells  and are  pumped to the tailings circuit.

The sulphur product flows through the  3  cell cleaner  and  additional  sulphur
is  floated, skimmed  and pumped  to the  3  cell recleaner.   The  slurry which
remains   in  the  cleaner  cells  still   contains  valuable  sulphur  and   is
recirculated  back  to  the conditioner  tank  [referred  to  as  middlings  or midds
No.  1]  for  reprocessing through  the  rougher  flotation circuit.  The final
flotation  product  that is skimmed off  from the 3 cell  recleaner  is  pumped  to
the vacuum  belt  filter for  de-watering.

The flotation froth  coming from the  3 cell  recleaner  contains approximately
40% solids [60% water].  The  resulting  sulphur cake is  the final product  of
the froth  flotation  plant.  This product is de-watered in a ho.rizontal vacuum
belt filter down to  15% moisture  or less.   The  filtrate  water  recovered  by
vacuum filtration  is  recycled back to  the water circuit for re-use.

The tailings  from  the 6 cell  rougher flotation  stage  are sent  to a de-aerator
 tank followed  by  a  thickener  tank for  densifying  before filtration.   The
water recovered  in  the  thickener tank  overflow is  collected  in a  reclaim
water tank  and recycled to  the front-end of the plant.   Actually, over 95% of
 the  process water  is re-cycled  with  only minimal  amounts of make-up water
                                      190

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required  to  compensate  for the  water  lost  in  the  sulphur  concentrate  and
tailings  filter  cake.   As  a  result, environmental  water  disposal  problems
typically associated  with a large  water make-up are  virtually eliminated  in
Ram River froth flotation plant.

The  tailings  thickener  tank  underflow,  which  is  made-up  of  settled  and
flocculated  solids  with  approximately  60%  water  content,  is  pumped to  the
squeeze belt filter for  further water removal down to 25 - 30%  or less.
RAM RIVER FROTH FLOTATION  CONTAMINATED SULPHUR RECOVERY PLANT PERFORMANCE

Since the plant's start-up in May 1987. ongoing efforts have been directed at
optimizing  the  plant performance in  order  to reach  the design  capacity of
18.8 [t/h]  with  maximum   recoveries   and  purities  and  minimum amounts  of
sulphur  in the tailings.   It  should  be  noted that  the froth  flotation of
contaminated  sulphur' represented a new application  of  this  technology and
that previous operating experience was  not  available to  use  as a guideline.
Therefore,  initial energies were  concentrated on achieving satisfactory plant
operating   characteristics.   After   the   initial  start-up   period,  plant
operations  staff  began  to  rectify  many  of  the  mechanical  problems  and
production  rates  of  6-8 t/h were achieved with sulphur  purities  of approxi-
mately  98.5 -  99%S, sulphur  recoveries  of about  95%  and  tailings sulphur
contents in the 15-20%  range.   These values  were better than those of the hot
remelting  process,   but additional  improvements  were  possible.    Through  a
series of  plant enhancements,  mechanical process  problems were  corrected and
performance has improved.   Currently,  the  froth flotation plant is capable of
processing  approximately  18 t/h  of  plant feed  with a  typical  final product
purity of  98.5  -  99%S with potential  to be increased up to  99.6%S.  Sulphur
recoveries  of  approximately 98%  and higher  and tailings  sulphur  contents in
the order  of 10%  or  less have been achieved.  Additional process enhancements
are still  being  implemented  and  fine-tuned and  it  is  anticipated  that  the
plant performance can be further  optimized and improved in the near future.


POSSIBLE FROTH FLOTATION PLANT  EXPANSION

In  addition  to  sulphur   base   pad  recovery  by  froth  flotation,  another
processing  scheme is patented.   This  scheme  is  related to the  treatment of
"sulphur crete",  the waste residue formed through hot  remelting which, until
now has  been considered unprocessable.  The processing  of "sulphur  crete" is
a combined  method using the present  plant  along with a fine grinding stage in
which  5% "sulphur crete"  is blended with 95%  base  pad material  as  shown in
Fig. 7.    This  process  has  the   advantage  of  using  all  the  present  froth
flotation  plant equipment  plus  the addition of a  small  fine  grinding circuit
[less  than 1 t/h] for the  "sulphur crete"  material and an additional stage of
flotation  cleaning  which  could produce sulphur  concentrates with  purity of
98%+ having  a  recovery over  95%.   This  combined  flotation  process  could
result  in  a marketable sulphur   product  which  otherwise would  have  to  be
disposed  in a  landfill  at   great  expense and become  a  long term environmental
liability.
                                    191

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The' laboratory  research of  this  new process  is ongoing.   It  is  hoped that
enhancement of  the froth flotation  plant will  be  possible in  the future to
allow for processing of over 20,000  t of  "sulphur crete" presently on site at
the  Ram  River  plant  and  other  "sulphur  crete"  stock  piles existing  in
landfill waste disposal sites and at other  gas  plants.
                                     *  *  *
By  using the  froth  flotation  process  not  only for  the  sulphur base  pad
existing  at  Ram River  gas plant,  but also  for  processing  the  contaminated
sulphur  base  pads  existing at  other  sulphur  gas plants  in Alberta,  we  can
contribute  to  the  protection  of  the environment  in  the  Canadian  sulphur
industry, which is of concern to  all of us.
CONCLUSIONS

- The  Ram  River froth flotation process  is  designed to separate  high  purity
  sulphur  from inorganic  and  organic  materials   such   as   gravel,   soil,
  vegetation  and other  contaminants  existing  in  the  sulphur  base pad.   In
  this manner  the sulphur base pad, a former waste product,  is  converted to a
  saleable  commodity  which reduces  a major   environmental  problem  in  the
  Canadian sulphur  industry and could provide  revenue.

- Based on R and D  studies  and laboratory experiments using  Ram River sulphur
  base  pad  samples, it was found  that  a  froth flotation process,  consisting
  of  size  reduction and screening to -10 mesh followed by conditioning  with
  reagents and several  stages of flotation, can provide a high  sulphur  purity
  product  [typical  98.5  - 99%S with potential  to increase up to 99.6%S],  high
  recovery  [98%S and higher] and tailings with  a low sulphur content  [ 10%S  or
  less].

- Froth  flotation  process  is characterized by  a  superior  performance  due  to
  its  higher  recovery  and  lower  sulphur content  tailings, compared  to hot
  remelting  and  landfill   disposal,  contributing   greatly  to  reducing the
  environmental hazards  faced by the Canadian  sulphur industry.

- Further  environmental protection is  envisioned by processing the "sulphur
  crete" waste product  resulting  from  hot remelting  by a combined  coarse and
  fine  flotation   process.   The  "sulphur  crete"   is  currently   considered
  unprocessable commercially and is costly to  dispose of in  landfills.


ACKNOWLEDGEMENTS

The  author would like  to  thank  Husky  Oil Operations Ltd.  for  permission  to
publish  this work  and  all  those Husky staff  from  the  Petroleum  Engineering
Professional  Pool   - R  and D Section,  Deep  Gas Production Engineering, Ram
River  District - Froth  Flotation Plant  personnel, Engineering - Environmental
Affairs, and  consultant  H.  Gisler.  Also, the  author would like to thank the
Alberta  Energy Resource Conservation Board  and personally Mr.   G.  deSorcy and
                                     192

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 Mr. G'. Warne for  their  support in the  implementation of the  froth flotation
| technology.


 REFERENCES

 1.   I. Adamache,  Recovery of Elemental Sulphur  from  Products  Containing
     Contaminated  Elemental Sulphur by Froth Flotation,  Canadian Patent,
     1 223  373,  June 23, 1987.

 2.   I. Adamache,  Recovery of Elemental Sulphur  from  Products  Containing
     Contaminated  Elemental Sulphur by Froth Flotation,  USA  Patent,
     4 871  447,  October 3, 1989.

 3.   J.B. Hyne,  Don't Produce Carsul, Hydrocarbon Processing,  September  1982,
      241-244.
                                     193

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Husky Oil Operations Ltd.
                          TABLE 1
Typical Laboratory Froth Flotation  Test Results

for Ram River Sulphur Base Pad
PRODUCTS
FEED TO
FLOTATION

FLOTATION
SULPHUR
CONCENTRATE

TAILINGS
WEIGHT
  (%)
100.00   18.8




 80.79    0.80

 19.21   94.48
   ANALYSIS
ASH    SULPHUR
         81.2




         99.2

          5.52
SULPHUR  SULPHUR
 UNITS    RECOVERY
                           81.2
          100.00
                           80.14     98.7

                            1.06      1.3
Husky Oil Operations Ltd.
                         FIGURE 1
Ram River Gas Plant  Area Location
 100 Miles


 100 Kilometres
                            -,	
                     B*ITISH  \  Edmonton
                                     RAM RIVER
                                      PLANT
                        194

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      iilusky Oil Operations Ltd.
                                               FIGURE  2
      Sulphur Base Pad/Sulphur Block at Ram  River
       40ft
J
                        99.95% PURE HIGH GRADE SULPHUR
      2-4ft-
                    REMAINING SULPHUR BLOCK AFTER REMELT
k^r^^.^^^^
             ,J80% SULPHUR WITH SOIL, "GRAVEL, SAND AND VEGETATION _
             ttX:-:$vS&yJ^j#i&&^:*.----W
      *THE RECLAIMED MATERIAL INCLUDES 1 TO 2ft ABOVE AND BELOW GROUND LEVEL
      Husky Oil Operations Ltd.
                                              FIGURE 3
      Contaminated  Sulphur Base Pad Alternatives
      (Comparison Example )
      FEED

        QUANTITY
        SULPHUR CONTENT
        CONTAMINANT CONTENT

      RECOVERY
      SULPHUR PRODUCT
        QUANTITY (SULPHUR PURITY)
        SULPHUR CONTENT
        CONTAMINANT CONTENT

      TAILINGS
        QUANTITY
        SULPHUR CONTENT
        CONTAMINANT CONTENT

      TAILINGS DISPOSAL
        LIMESTONE REQUIRED
        FOR NEUTRALIZATION
SULPHUR FEED (20% CONTAMINANTS)
i
T
10001
BOOt (80%)
200t (20%) }
T
FROTH FLOTATION
(98% RECOVERY)
787.21 (99.6%)
784.01
3.2t (0.4%)
HOT REMELT
(75% RECOVERY)
602.4t (99.6%)
eoo.ot
2.4t (0.4%)

T T
212.81 397.6t
16.01 (7.5%) 200.0t (50.3%)
196.81 (92.5%) 197.61 (49.7%)
r 	 T
DISPOSAL
(NO RECOVERY)
0
T
1000t
SOOt (80%)
20Ot (20%)
                   48.0t
600.01
24001
                                  195

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Huskv Oil Operations Ltd.
                                      FIGURE I
Size  Reduction and Classification Simplified
Process Flowsheet
PATENTS: CANADIAN No. 1223373, U.S.A. No.4871447
     FRONT END LOADER -yj/n1
                  «SWo
                                WASTE OVERSIZE (*6')
                                                CONVEYOR
       VIBRATING SCREEN

     WATER SPRAY Ł
       +10 MESH
    OVERSIZE
    CRUSHER
            -10 MESH
        15-30% SOLIDS
                     APRON OR BELT FEEDER
              WATER

WATER SPRAYS ROTARY

 *1/2-TRAMP^CRUBBER
   .OVERSIZE
    WASTE

0 MESH SLURRY
                                            LIME
                                COARSE PRODUCT: / /-r-r~>->
                          ADD WATER __ p%SOLIDSLLU_//j' /
                          70% SOLIDS  V '—i   spio7r~rr~—
                             ATTRITION
                             SCRUBBER
                    REMOVABLE TRASH
                   SCREENS TO REMOVE
                   WOOD CHIPS & DEBRIS
                          TO WASTE

                 ADD WATER AS NEEDED
                                    CLASSIFIER
                                    OVERFLOW
                                    25% SOLIDS
                                                      •\
                                                     -a
             TO CONDITIONER
                                PUMP.
                                                      PUMP SUMP
Husky Oil Operations Ltd.
                                     FIGURE 5
Flotation  Circuits  Simplified  Process  Flowsheet

PATENTS: CANADIAN No.1223373, U.S.A.  No.4871447

           1-10 MESH

REAGENTS
           JMCONDITIONER
              ROUGHER FLOTATION (FIRST STAGE)

       ,       REAGENTS   (SCAVENGER STAGE
       T  T  T   T ]            OPTIONAL)
                  1 T
        CLEANER
    (SECOND STAGE)
 PUMP
MIDDS
No. 1
                                    FROTH   I
                                 FINAL TAILING
                                   TO WASTE
 RECLEANER
(THIRD STAGE)
    T	T
                     MIDDSL
                     No. 2
              PUMP
                        FROTH
               FROTH
                         FILTER eg. BELT TYPE
                                        FILTRATE
                                         RE-USE
                                                         SULPHUR  ,.
                                                       "FILTER CAKE
                               196

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                                                            FIGURE 6
w:^~^s===^=                              	
 Schematic Cross  Section of a  Flotation Cell
 Husky Oil Operations Ltd.
                              DRIVE

                              UPPER PORTION OF THE ROTOR
                              DRAWS AIR DOWN THE STANDPIPE

                              STANDPIPE

                              SULPHUR FROTH

                              SULPHUR PARTICLES ATTACHED
                              TO AIR BUBBLES

                              SULPHUR PARTICLES AND AIR
                              BUBBLES PASS THROUGH DOUBLE
                              DISPERSER
                              LOWER PORTION OF THE ROTOR
                              DRAWS THE SLURRY UPWARD
                              WASTE MATERIAL NOT ATTACHED
                              TO AIR BUBBLES

                                                   FIGURE 7
 Combined Coarse  and  Fine Flotation Simplified
 Process  Flowsheet
 PATENTS: CANADIAN No.1223373, U.S.A. No.4871447
 EXAMPLE FOR A COMBINED PLANT FEED WITH:
      (5% COMPLEX SULPHUR AGGLOMERATE/REJECT  BY-PRODUCT
      \ RESULTING FROM HOT MELTING-SULPHUR CRETE MELT RESIDUE *
      195
°o CONTAMINATED ELEMENTAL SULPHUR FROM BASE PAD
      CONTAMINATED ELEMENTAL
       SULPHUR FROM BASE PAD
       95% OF THE PLANT FEED
       SCHEMATIC FLOWSHEET
           FIGURE 5
         ROTARY SCRUBBER
         SPIRAL CLASSIFIER
        ATTRITION SCRUBBER
           SCREENING
    +1/2* WASTE
                            COMPLEX SULPHUR AGGLOMERATE/REJECT
                               BY-PRODUCT RESULTING FROM HOT
                              MELTING-SULPHUR CRETE MELT RESIDUE
                                   5% OF THE PLANT FEED


                                              GRIZZLY



                                             FEEDER

                                           o) JAW CRUSHER

                                          , -3/4'
               -10 MESH FEED
               15-30% SOLIDS
                           OVERFLOW
                98%-200 MESH 15-20% SOLIDS
         COMBINED FEED
       SCHEMATIC FLOWSHEET
           FIGURE 6
          CONDITIONING
           FLOTATION*
           FILTERING
                                PUMP
   TAILING
   WASTE
 »98% PURITY OF THE ELEMENTAL
     SULPHUR FILTERCAKE
                                                      FEEDER
                                                    -3/4"
                                          rx ACID RESISTANT
                                          . BALL MILL WITH
                                          a/ CERAMIC BALLS
                                      *1/4'TRAMP
                                     OVERSIZE WASTE
  *THE FLOTATION WILL INCLUDE A ROUGHER FLOTATION STAGE AND
   THREE ADDITIONAL CLEANING STAGES.
                                 197

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CONTROL OF WASTE WELL CASING VENT GAS FROM A THERMALLY ENHANCED OIL RECOVERY
OPERATION
Jack E. Braun, Environmental Coordinator
Oryx Energy Company
Valencia, California   U.S.A.
Mark A. Peavy, Operations Engineer
Oryx Energy Company
Valencia, California  U.S.A.
I.   Introduction

The purpose of this  paper is to present a case study regarding the construc-
tion and operation of a wellbore  vapor recovery  system.  Thermally enhanced
oil  recovery  (TEOR)   operations that  use  steam  injection  in  the  reservoir
generate return  vapors.    Controlling  these vapors  offers environmental  and
operational benefits.

II.  Field History

The Midway-Sunset (MWSS)  Field  is in the  southwest corner of the  San Joaquin
Valley, Kern County,  California (Figure 1).   The  field extends  from the town
of McKittrick  southeasterly  along the  Temblor Range  foothills  for over  25
miles to the town of Maricopa.  The field has an average width of 3j miles and
encompasses over  50,000  acres.   This  field is the 2nd largest  oil producing
field in the State of California  and  is  one  of the largest fields,  in terms
of reserves, within  the continental United  States.  Production from this field
is approximately  155,000  barrels of oil per day  which is produced from 9200
wells.

The  arid topography  varies  from  gently  sloping  alluvial  fans to  smoothly
rounded  hills,  occasionally  dissected  by gullies  (1).   Surface  elevations
range  from 500  ft.   to  over 1700 ft.  above  sea level  with  the  productive
interval occurring from  just below the surface to depths below 2000  ft.  The
primary  producing zone within  the MWSS  field is  the  Potter formation which
is  a heavy oil reservoir with oil gravities ranging  from 9-12°  API.

The  first  recorded  oil well  was  drilled prior to 1890,  with the  first spec-
tacular  gusher  recorded  in 1909.    This well  was  located  near  Fellows,
California, and  flowed in excess  of  3,000 barrels  of oil per  day.   By 1916
over  100 gushers flowing  over  1000 barrels of oil  per  day had been  placed
                                     199

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on production.  Since this time reservoir pressures have declined.  Artificial
lift is required to assist the fluids  to the surface.

Development of the field increased drastically around 1960 with greater demand
for low gravity crude and the development and refinement of thermal recovery
techniques, such as fire floods, cyclic steaming, and more recently continuous
steam injection.   Thermal recovery  can be defined as  a process in which heat
is  introduced intentionally  into a subsurface  accumulation of  organic con-
pounds for the purpose  of recovering fuels through wells  (2).   The primary
means of  thermal enhancement initiated  within the MWSS field in the 1960's
utilized  the injection  of steam  into  wellbores.   Generally,  one  barrel  of
crude oil or its equivalent  is  fired in a steam  generator and  the steam is
injected  into the  reservoir to  produce  approximately  10  barrels  of  crude.
Heat derived from the steam  is used to improve  the displacement  and recovery
efficiency  of the reservoir.   The  major benefit of heat is to  reduce  crude
oil viscosity due  to  the higher  temperature which allows the oil  to flow more
freely into  the wellbores.

Cyclic steaming and continuous steam injection are two  widely used methods  of
steam stimulation.  Cyclic  steam injection consists of  injecting  steam into a
wellbore  for  a period  of days  or weeks which is  normally  followed  by a
"soaking" period and  subsequent  return of the same well to production.   Steam
cycles are  normally repeated  over time.  Higher  fluid production  is typically
observed  during the immediate return to production of the cyclic well.  As the
reservoir near  the wellbore  cools,  production declines due to the  increased
viscosity of the crude  oil.   Cyclic well vent emissions tend to  follow  this
same pattern.

Continuous  steam  injection involves the injection of  steam down  a  dedicated
injection wellbore on a continuous  basis.  The  intent  of  the  process is  to
create a  steam front that moves radially away from the  injector  to  producing
wells  located  around it.    Higher  well vent  emissions  are associated with
continuous  steam  injection,  particularly  on wells immediately offsetting the
injector.

Oryx  Energy Company  currently operates  approximately  934 thermally enhanced
oil wells located on seven leases using casing vapor recovery  systems  (CVRS)
and utilizes both  cyclic and  continuous steam injection  techniques to enhance
oil production  (Figure 2).

III. Need for the System

A  system  to  control  emissions from well casings is  often required to conply
with  environmental rules  and  regulations  and  can  contribute  to  increased
production  by  the  lowering  of  near  wellbore  pressure.   These  areas are
reviewed  as  follows:

     A.   Environmental

     Regulation  of air  emissions within  Kern County,  California was accel-
     erated  in  1979 due to  the  passage  of  the Clean Air Act by  the Federal
     Government.   The  Kern  County Air Pollution Control  District  (KCAPCD)
                                     200

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passed rules as a result of this legislation that  impacted air emissions
and pollution  control  equipment within the  MWSS  field.    Two  rules
resulting  from this legislation  led  to the requirements  of a CVRS:  a) a
"ledger system"  for the emissions of air  contaminants  was  established,
and b)  a  rule requiring  the  control  of  casing  vents  of steam drive
recovery wells.  The "ledger  system" basically consisted of keeping all
emissions  at a 1979 level and limiting new emissions within  areas desig-
nated as non-attainment under the Clean Air Act.  New emissions above the
set limits were required to be offset by a corresponding decrease in old
emissions  and require the use of the best available control technologies.
The control of steam drive  well vent emissions  was strongly  influenced
by a  1981  Environmental Protection  Agency  study performed on well  vent
emissions  within Kern County,  California (3).   This study concluded  that
air emissions  from cyclic wells  ranged from 0.0  to 106  Ibs/day/well  of
hydrocarbons and air  emissions from steam drive  wells  ranged  from 35  to
842 Ibs/day/well of hydrocarbons.   Sulfur  emissions were not  quantified
in the Environmental Protection Agency report.

Prior  to  1979  steam operated  wellbores were  produced  with  their  well
vents  open  to the  atmosphere, discharging  large volumes  of sulfur and
hydrocarbons containing gas.

Shortly after  passage of   these  new  regulations, designed  to  control
emissions  from  steam drive wells,  Oryx  Energy  began  permitting  and
installing  casing  vapor  recovery systems on both  steam drive and  cyclic
veils  to  satisfy three needs:   1) to control emissions  from steam drive
operations, 2) to control old emissions to offset new projects, and 3)  to
improve production by the lowering of near wellbore pressure.

B.   Improved Reservoir Management

Historically,  cyclic  wellbores were produced with  the  well casing vents
open which released large quantities of steam laden with  hydrocarbons and
hydrogen  sulfide to the  atmosphere   (Figure  3).    Casing vent emissions
were generally visible upon the  immediate return to production of cyclic
wells  but would diminish after the  steam  would condense and pressures
eguilibriate  within the  reservoir.    Casing vents were generally  left
open in order to enhance oil production.  Two alternatives were evaluated
to control air emissions from TEOR wellbores.  These were:  1) closing the
well  vent,  and 2)   installing  a casing collection  and  treatment  system.
Closure of casing vents was determined to be an unacceptable solution for
the vast  majority  of  wellbores operated within  the MWSS field.  Losses
in  oil production  could  occur  with the buildup of significant casing
pressures associated  with  steaming  operations  if  not  released from the
wellbore.

Fluid  flow  into  a wellbore  occurs when existing fluid  (liquid  and vapor)
in  the wellbore  is  removed  resulting  in  reduced wellbore  pressure.
Higher  pressured fluid from the reservoir  surrounding  the wellbore then
flows  into the  lower pressured wellbore  (4).   Closing the  well vent
increases pressure  in the wellbore to an unacceptable level and prevents
oil from flowing from the reservoir into the wellbore.  A vapor recovery
                               201

-------
     system for  the  control  of well vent  casing  emissions  was  therefore
     advantageous to oil production because the pressure in the wellbore could
     be controlled.

     The effect  of  casing vacuum on drawdown is  straight-forward in that as
     vacuum is increased a higher pressure differential between the  formation
     and wellbore is created thus leading to more oil production.   Oil produc-
     tion  can therefore  be  optimized empirically by adjusting the  casing
     pressure or vacuum on wellbores that yields the most  fluid recovery.   As
     viscosity  and  differential pressure  influences  within  wellbores  are
     optimized  so  follows  production.    Thus  the  CVRS  can be  utilized  to
     maintain and improve oil production.

     Another benefit of the CVRS was the capturing of condensible  hydrocarbons
     from the well  casing vents.  Approximately 558  barrels per  day  of light
     gravity  oil (38° -  42°  API)  is  captured,  processed,  and  sold  from  the
     CVRS skids within the field.  These hydrocarbons were  previously  released
     to the atmosphere.

IV.  Major System Components and Process Flows

This section  of  the paper will describe  the major  components of  the  CVRS and
summarize  its operation.   There  are  three  primary  components  of  the CVRS
operated by  Oryx Energy within the  MWSS  field.   These  are:   1)  the  wellhead
and  gathering system,  2)   the CVRS  condenser and compressor skid, and  3) the
waste gas incinerator/scrubber system.  Each are discussed  as follows:

     A.   Overview

     Currently Oryx Energy operates  28  casing vapor recovery skids located on
     seven leases within the MWSS field that have CVRS in  place.  The CVRS is
     an integral part of the complete lease operations.  Each CVRS is  composed
     of several individual CVRS compressor skids and gathering network piping.
     Typically,  one  waste  gas  incinerator is  utilized   for  each lease  to
     dispose  of  the non-condensible gases produced through each CVRS network
     on the  lease.   The average number of wells placed within a CVRS skid is
     33.

     B.   Wellhead and Gathering System

     There were  two primary objectives  associated with the design of  the CVRS
     gathering network.  These were:  1) the ability to handle a 10" Hg  vacuum
     at  the  CVRS skid inlet continuously and  a 6-10" Hg  vacuum at each well
     casing,  and 2)  utilization of existing topography  in  order to allow
     fluid drainage to each CVRS skid.

     The typical wellhead connection to  the  CVRS gathering system is  illus-
     trated in Figure  4.  Threaded  connections are  used near the  wellhead for
     ease  of  removal.  Welded connections are used for the remainder  of the
     system due  to  strength,  longevity, and reduced  fugitive emissions.  Two
     threadolets  are  placed on each casing line in order  to monitor  pressure
     and temperature if needed.
                                     202

-------
In general,  CVRS skids  were  located at  the lowest point  of elevation
within the gathering  system in order  to utilize gravity  drainage of the
fluids.    The gathering  system  lines utilized  existing  production line
supports  as much as  possible.  All  main gathering  lines  were fabricated
with a slight slope  toward each  skid  to  prevent  low spots  within the
gathering  system in  order  to  minimize  fluid accumulation within the
piping.    This fluid  could  restrict  vapor flow and increase  the back-
pressure  against the reservoir.

C.   CVRS Skid

Each CVRS consists of a  large  air-cooled heat exchanger,  compressors,
liquid scrubbers, and pumps as  illustrated in  Figure 5.  Casing vapors
enter an  inlet surge  scrubber, VI, where free condensate  is  removed from
the non-condensible  gas  stream.    This vapor  stream then enters  the air
cooled heat exchanger for preliminary  condensation.   Condensed fluids are
separated  from  the non-condensible  gas within  a  vertical scrubber,  V2,
prior  to  first  stage compression.    Non-condensibles   then  enter  the
interstage condenser  within the  air  cooled heat  exchanger.    Additional
condensed  fluids are  then removed within  a vertical scrubber,  V3,  prior
to  second stage  compression.  The vapor  stream passes through one last
vertical  separator,  V4,  for  scrubbing   prior to  entering  the  non-
condensible  gas  gathering  system.   All  free and  condensed fluids  are
pumped to a  liquid  collection tank,  V5.   The  fluids are then gathered
from  all  skids  within  each  lease and are  pumped to  each  respective
dehydration  treating  facility.    Typical  CVRS  skid  design  criteria  is
found in Figure 6.

D.   Waste Product Processing

Two waste product streams are associated with the CVRS operations within
the MWSS field.    These  have  been mentioned  previously  and  are:   1)  a
non-condensible  gas  stream,  and  2)   a  condensible  fluid stream.    All
non-condensibles are currently  gathered from each  CVRS  skid within  the
leases and are  transported at  30 psig to a waste  gas   incinerator  for
sulfur removal,  treatment,  and discharge.   Condensed produced  fluids are
sent  to   the  oil treating  facilities where  hydrocarbons are  separated
frcm  produced water.   The  oil is sold  with lease  oil and the water is
combined  with other produced water  and then  softened at a water plant.
The water then  returns  to  the  Cogeneration  plant  to  be reheated into
steam  (Figure 2).   Non-condensible  gases  are  routed to the waste  gas
incinerator and scrubber.

E.   Incinerator

The typical waste  gas incinerator  is  comprised  of  two components:  1)
the incinerator, and  2)  a S02 scrubber  (Figure  7).   The  incinerator is a
cylindrical,  horizontal,  saddle  mounted unit  designed for forced draft.
NOn-condensible  gas is regulated  down  to  an  acceptable  burner pressure
and is introduced  into the burner of the  incinerator.  Burner operating
temperature  is normally  1625°F.    This temperature  is necessary in order
to  completely burn  the hydrocarbon and hydrogen sulfide in the waste gas
                                 203

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     stream.  Pipeline  utility gas must  be added to the waste gas for proper
     combustion.  If the  incinerator temperature drops below 1500°F the waste
     gas supply is shut  off.   This ensures  complete oxidation of  the non-
     condensible gas.

     The Incinerator  scrubber contains  a quench  section,  an  integral liquid
     recirculation tank,  a packed tower,  and a mist eliminator.   The scrubber
     is necessary in  order to remove S02 resulting from the oxidation of H2S
     within the  incinerator.   S02  removal is  accomplished by  saturating the
     exhaust  gas with  caustic in  the  scrubber  quench section.   The packed
     section consists of  a stack of saddles which increases  the  contact area
     between  the upward  flowing  gas  and  the downward  flowing  recirculated
     caustic.  The gas  passes through a mist eliminator for  final particulate
     removal  prior  to  exiting into the  atmosphere  via the  stack.   The  CVRS
     accomplishes  99%  removal of  hydrocarbons and  95% reduction of  sulfur
     emissions.

V.   Environmental Benefits

Control  of  sulfur and  hydrocarbon  emissions  are  two major environmental
benefits  that result  from operating  a  CVRS.    Total hydrocarbon emissions
controlled by the CVRS  operation  are estimated at 160,743 Ibs/day (Figure 8).
This was derived using  source test data  on cyclic wells and KCAPCD emissions
factors  for steam drive  wells.    In January,  1988,  Oryx Energy  conducted a
source  test  of 5 CVRS  skids  to quantify the hydrocarbon  emissions from Oryx
operated cyclic wells  (5).    The test results showed emissions  from cyclic
wells averaging  98.45 Ibs/day/well.  Using this emission factor,  total cyclic
well hydrocarbon emissions for  the field were  60,547  Ibs/day.   In  order to
quantify the emissions  from steam drive wells  the accepted KCAPCD hydrocarbon
emissions factor was  used (314 Ibs/day/well).  Total  steam drive well hydro-
carbon  emissions  for  the  field were  100,166  Ibs/day.    Steam  drive wells
account  for  only 34%  of  the  total well count yet contribute 62% of the total
estimated hydrocarbon emissions.

Hydrogen sulfide in the casing gas is oxidized in the  incinerator to S02 and
removed  in  the scrubber.    Using a mass  balance  equation based upon the
concentration of hydrogen sulfide in the waste gas  and the quantity of waste
gas,  the amount of  sulfur  dioxide that is controlled  by  the  CVRS  can be
quantified.    Assuming  a  95%   removal   efficiency,   Oryx  Energy  controls
approximately 3,558 Ibs/day  of S02  from  entering the  atmosphere  (Figure 9).

VI.  Economic Benefits

The  installation of  the  CVRS resulted  from the need to  control well vent
emissions for the majority of wells within the field.  The approximate cost
to install the CVRS fieldwide was $10,308,145.

The  dynamics within  heavy  oil  operations make  it difficult to  associate
incremental  oil  production  directly   to  the  CVRS  operation.    Since  the
implementation of  these systems  field production  has continued  to increase
due  to many  improvements within the  field.    It is  therefore  possible to
assume  that  CVRS operations  can  contribute to higher  oil  production  if used
                                      204

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'properly.  The CVRS also prevents excessive pressure buildup in  the wellbore
'which can occur with the closure of casing well vents.  Significant short term
production losses have been documented when well casing pressure increases due
to CVRS skid downtime.   Simple  payout for  the CVRS can  be calculated  using
only recovered condensate  volumes.   Assuming  a  $10.00 barrel  oil price and
•recovery  of  558 barrels  of  oil condensate  per day project payout occurs  in
slightly over 5 years.

VI. Conclusion

1,  CVRS  plays an important  role in  pollution  control  and  optimizing oil
     field production.

2.   Successful  control of hydrocarbon and  sulfur emissions  can  be  achieved
    with a  CVRS.
 3.
WJ.U1 a v_vrto.

Improved wellbore pressure  control is  possible with a  CVRS if operated
properly.
                                     205

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References

1.   Summary of  Operations, California  Oil Fields, Fifty-first Annual Report
     of  the State  Oil and  Gas Supervisor,  Volume  51,  No.  2, 1965, Pg.  21

2.   M. Prats, Thermal Recovery, SPE Monograph,  Copyright 1986

3.   Report No.  EPA 90919-81-003,  Assessment of VOC Emissions  from Well  Vents
     Associated   with  Thermally   Enhanced   Oil  Recovery,   United  States
     Environmental Protection Agency Region IX,  September,  1981

4.   R.N. Marshall,  Application of a  Vacuum to Casing Vapor Recovery  Systems,
     Oryx Energy (formerly Sun Exploration and Production Company), Presented
     at the 1986 API California Regional Conference

5.   Report No.  89-267-044-02,  Cyclic Well Hydrocarbon Emissions Sampling and
     Analysis  Program Results for Sun Exploration  and  Production Company,
     Radian Corporation, January,  1989
                                     206

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         C ALJ F O R NT IA
                                     MIDWAY-

                                     SUNSET

                                      FIELD
   FIGURE  1. MIDWAY-SUNSET OIL FIELD  LOCATION
              9 UWSS FIELD   °
               BOUNDARYV
                SAN LUIS OBISPO CO.
            FIGURE  2.  MIDWAY-SUNSET FIELD
ORYX ENERGY PROPERTIES WITH  CASING VAPOR  CONTROL
                      207

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        /v<
        ( /? CUISSOHS ..
                       -PRODUCTION LINER FROM 470' TO 1100'



                       -PRODUCTION TUBING SETT AT 1080'

                       -DOWNHOLE ROD STRING

                       -DOWNHOLE ROD PUMP
FIGURE  3.  TYPICAL MIDWAY-SUNSET  PRODUCER
      ILOI
                                 GATHERING LINE

1
IB"
~r
4
y

- o-
- o-


SADDLED STUG-IK
CONNECTION
- (FACING UP)
3/4 TORtAD-0-lCT
- (FACING UP)

	 T SCM to LONC
                             !  is
                             T   T   i
                                     Ii
FIGURE  4.  CVRS GATHERING  SYSTEM  WELLHEAD
             FLOWLINE SCHEMATIC
                     208

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    CASING
   VAPORS
  LIQUIDS TO
 DEHYDRATION
    TREATING
    FACILITIES
                                      TWO-STAGE
                                      COMPRESSOR
                                 TO
                              INCINERATOR
                       OUTLET
                      SCRUBBER
     FIGURE 5.  TYPICAL  MIDWAY-SUNSET  CVRS
                 SKID  FLOW  DIAGRAM
   (1)   Ambient Temperature Range  20'  to  1 15'F

   (2)   Atmospheric  Pressure  13.86  P5IA

   (3)   Non-Condensible Gas  146 MSCFPD
        Condensible  30 GPM

   (4)   Design Slug  Catcher  Inlet  Pressure 9  P5IA
         a)  maximum pressure 10  PSIG  (at start-up)
         b)  minimum  pressure  8  PSIA

   (5)   Design Skid  Discharge  Pressure  35  PSIG
          a)  maximum pressure 50 PSIG
          b)  minimum pressure 30  PSIG
FIGURE  6. TYPICAL CVRS SKID  DESIGN  CRITERIA
                       209

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                                                        EXHAUST
                                                          GAS
                                                          O
CVRS GAS—+

PILOT GAS—••

  COMBUSTION
       AIR
 BURNER
J
INCINERATOR
 (1625-  F)
                                                                     BLOW
                                                                     DOWN
                                                            CAUSTIC MAKE-UP
                                                          •—WATER MAKE-UP
                  FIGURE  7.  WASTE  GAS  INCINERATOR
LEASE
W k S
MAXWELL
ANDERSON/
GOODWIN
NEELY
EXETER
DICKINSON
TRUST
TOTAL
ACYCLIC 0STEAM-
WELLS DRIVE WELLS
126
93
229
167
0
0
615
14
121
20
22
122
20
319
EMISSION FACTOR
CYCLIC/DRIVE
LB/DAY/WELL
98 45/314
9845/314
98.45/314
9845/314
9845/314
9845/314
TOTAL
HC EMISSIONS
CONTROLLED
IBS/DAY
16,807
47,154
28,836
23.358
38,308
6,280
160.743
TOTAL
WASTE GAS
LEASE (MCFPD)
W & S
MAXWELL
NEELY
ANDERSON/
GOODWIN
EXETER
TOTAL
415
700
315
312
340
2.082
H2S S02
CONTENT CONTROLLED
(PPM) (IBS/DAY)
4.700 313
19.786 2.220
5,730 289
5.800 290
8,195 446
3558
                 FIGURE  8.                                  FIGURE 9.
  HYDROCARBON EMISSIONS  CONTROLLED BY CVRS       SULFUR  DIOXIDE CONTROLLED BY CVRS
                     ORYX ENERGY  OPERATIONS,  MIDWAY-SUNSET FIELD
                                    210

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THE COST OF EDUCATION
Renee C.  Taylor
Environmental Coordinator
True Companies
Casper,  Wyoming
USA
Basic Philosophy

Education within the workplace  can be a major expense,  just
as quality  education in the  private or  public  schools  can
be.  The  lack of quality  education can be  an even greater
expense.  Just as we can lose an educated generation to  poor
schools, your  company  can lose its  profitability to a  poor
regulatory  compliance  training program.   Waste management
roust  be a  major  component of any  industrial  educational
system.

There  are  numerous similies  between the  "formal"  years  of
education  and  those that must  follow  in  the workplace.
Education starts with the  basics in  kindergarten and becomes
increasingly  more  complex each  year.   This  is  also   how
education should  be handled in the work force.     Diversity
or  complexity  is  not  divided by  age  or  grade, but  by
position of responsibilty.

Remember  also that education can  never stop.   Not only is
there  not  a finite amount of knowledge to be taught but in
the   regulatory   scheme    of   things   the   rules  change
continually,  causing the need to periodically re-educate.

So much for my basic  philosophy of  education.   I work for
True   Companies  which   is  a  diversified,   family-owned
business.   Originally intended  to  be self supporting, we now
 serve  the needs of  the  oil and gas industry.  The company
 structure  includes  exploration and production,  crude  oil
pipeline  and truck  transportation, crude  oil  marketing,  a
gas  plant,  gathering systems,  drilling  rigs,  and a supply
 company.  Each of  these  components is  an  individual company
with  its own  management  structure.  This  type  of  internal
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structure  and  diversity  raises  many  complications  and
challenges when  creating a waste handling program.   Wastes
specifically exempted as  "associated wastes"  for exploration
and  production may be   regulated  wastes  for  pipeline  or
trucking.  Wastes  with minimal regulation  for  trucking  are
more cumbersome  when associated  with  the drilling  company.
In a  small company, because  there is  a  lot of  interaction
among  employees,   it   becomes  necessary  to   explain  the
idiosycracies  of  regulation as well  as compliance  strategy
when providing training.

Determination of Educational Needs

Ours  is  a fledgling  program,  so a  tremendous  amount  of
groundwork goes  into the educational  process.   This,  in  my
view, however is how the  continuing education process should
be  carried  out  for  programs  that  are  more  mature.   Our
training  program  begins by conducting  a  site review  of  key
facilities   for   each  company.   Periodic  informal  walk
throughs  and  discussions with  supervisors  keep the  process
fresh and compliance moving in  the right direction.

During the initial site review, potential waste streams  are
identified.   Staff interviews  provide  basic information  as
to  the  content  and  volume  of  these  streams  as  well   as
current   handling   of  disposal   methods.   As   with  formal
compliance audits  staff  interviews  are a  critical  part  of
this  process.   These  interviews should  be  part   of the
continuing education of the person conducting the  interview,
the  trainer.   Arrogance or a  "know-it-all"  attitude  on the
part  of  the  interviewer can stall a program before  it gets
started.   The  interviewer must  keep an  open mind and listen.
Listening could  eliminate the  chances  of asking  operations
to do  something  they've already tried but didn't  work.  The
other  great  opportunity  provided by  listening  is  to hear
ideas  that have  been building  in the minds of  operations
personnel, ideas  that could solve compliance problems.  Ask
the  operations staff or managers  if they are  concerned about
any  particular operation.  Asking supervisors questions will
provide  information as to the  depth  of their  understanding
of applicable  regulations.

Another  good source of  information as to educational needs
are  the  facility  files.   Review the compliance file  for
specific  regulatory   programs   identified   during  walk
throughs.  Look   also  at  previously  conducted  compliance
audits  and  their  action  plan responses.   Compliance with
other  enivronmental  regulatory programs must  be reviewed,
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for as we  know, many federal,  state and  local  regulatory
programs  are  interrelated.   Overlooked  compliance  in  one
program is  often  an  indicator of  compliance  problems  in
another program and a need for more training.

Education

Education  at   its   most   fundamental   point  begins  with  a
management commitment to  operate   within  the  regulations.
Upper management must communicate  this  commitment for  the
rest  of   the  educational   or  training   process  to   be
successful.   Without  this  the regulatory  compliance  and
training personnel  will  run up against  a  brick wall  from
both management and operations.

As mentioned earlier, the complexity of information provided
varies depending on  the position  of  responsibility  held.
For  example  I have  the  luxury  of  meeting  each manager
individually  to discuss  items  identified   as  problems  and
what  is  needed to  correct the  situation.   This  discussion
includes   the  compelling   regulation,   why  the   current
practice  is  not  appropriate,   the  cost  of  changing  the
operation  and  the   potential   cost   of  not  changing  the
operation.  This discussion  often includes  the  civil penalty
structure  and potential  criminal penalties but not always.
These  discussions   can  get  quite  complex  depending  on  the
managers  interest   in the subject  or his  or  her level  of
confusion about inequities within the  regulatory structure.

Once   management   has   "signed-off"   on   a   program   the
supervisors of the affected  facilites must learn about  the
situation.  This can  come down  in  one of two ways, an  edict
from  management or  a more  casual  group discussion  of  the
problem.   I  prefer  the  more  casual  approach,  saving  the
edict  for resistant supervisors.  The  casual approach  should
be a  give and  take  session  discussing the  problem,  the
regulatory  program  (and  its intent)  that  facilitates  the
need  for change and  possible solutions.    Give and take  is
important  because  a  solution  that  at  face   value   looks
perfect  to me may  be a  potential  operational  nightmare.
Once  a solution is worked  out  the next  phase of  education
can begin.

To facilitate  change  and compliance at the  operations  level,
a policy or  procedure  should be written which details,  in
 easily understood  language,   exactly  how  a   particular  waste
 stream is  to  be handled.  This should include  a  discussion
 of the  compelling  regulation, the  waste  to  be handled,
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personnel protective equipment  needed,  equipment  required,
sampling  and analytical  communications  with  environmental
staff,  record  keeping, transportation,  disposal,  etc.   The
procedure should  detail who has the responsibility  for the
different aspects of  the  program.   In  a  small  company one
person  can wear may  hats so  it  is imperative that the duties
for   complicated   waste  handling  situations   are  clearly
spelled out.  Not all waste handling scenarios  require this
level   of  detail.    Caustic neutralization  requires  more
detail  than  empty paint cans,  but  handling procedures  must
be    in  black    and  white    to   avoid   confusion   and
misunderstanding.

One  of  the intriguing aspects of creating  a waste management
program for this group of  related companies  is  cause  and
effect.  An  error  in judgement  on the  part  of  trucking
company  could  cause a  waste  clean  up  problem  for  the
production  company.    Well planned  coordination  between  the
companies can  significantly reduce the  overall  costs  of
compliance with  waste management regulations.

A second aspect of education  is  the  overall  scope  of
applicable regulations.    The same  people  from management to
operations must  have an appreciation for the tremendous body
of regulation that  governs  them.   They  do not  necessarily
need to know the detail but  must have a  basic knowledge from
which to operate and ask appropriate questions.   Appropriate
 forums for  this  kind of  education can be  for managers  at
 annual or bi-annual  staff meetings, supervisors meetings and
 for  operations   piggy-backed  onto  safety  meetings.    Two
 examples    of     "overall    scope"   meetings    are    the
 interrelationships  of  RCRA,    CERCLA,   SARA,   HAZCOM,   and
HAZWOPER or  Benzene  and  how  it is regulated  under  OSHA,
HAZWOPER, RCRA,   and CERCLA.  These are  complex issues  but
 someone other than  the  enivronmental  staff must understand
how non-compliance in one program can promote non-compliance
 in another.   The "big picture" must be  known maybe not  in
 excrutiating detail  but enough  that "Is it okay if  ..?"  is
 asked of the environmental staff.

An  environmental compliance  manual providing  information
 about  applicable  regulations  and  company policies  for  the
 consistent  implementation of  these regulations is  a  must.
 This volume can  be   used  by field  supervisors  for tailgate
 staff  meetings;  it  should   be  a  basic   reference   for
 engineering   and  planning  staff.    The  compliance  manual
 should be used   as  training modules for  new or reassigned
                             214

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employees.   Not  all  employees would  be required  to do  all
modules  only those which apply to their work group.

Record Keeping

While you are  teaching the importance  of  record keeping  to
the  operations  staff,  don't  forget  to   do   it  yourself.
Maintain detailed notes  or  a  lesson plan of what was taught
that day, include pertinent questions and answers, include a
list of  everyone present and the date.  It  is a good idea  to
post a  synopsis  of the  meeting for employees  who were not
present  and (or)  as   a  reminder for  those who were.    For
especially important programs it may be necessary to conduct
two  or  three  training  sessions  to  be   sure the entire
affected staff is able to attend.

Remember that some regulations have specific formal  training
requirement such as OSHA or RCRA.

In Conclusion

Education   cannot   rest  on   its  laurels.    Walk   through
facilities   periodically  to   remind   operations   of   your
presence.    Discuss   what   you   see  with    supervisors.
Procedures  may be  in  writing, you may have done training  on
a subject,  but repeating yourself  on  the  importance  of
proper  waste handling can  only  help.   Communicate,  talk  to
people  on their  level, use  examples they can relate  to,  make
compliance  real  to your audience.   Material presented  over
their heads will stay  there and not provide any benefit.   Be
direct  and  to  the  point,  rule  number one   "do  not   bury
barrels."

Remember the rules are constantly changing.  As a  result you
must update  or  change  procedures  and  you   must   provide
 continuing  education.    Never  take for granted that if  you
 know something everyone  does  or that  you told the  supervisor
 therefore his  staff knows.

 One  good thing about waste  management  and waste minimization
 is that you  can always appeal  to managements overwhelming
 preoccupation  with  the  bottom  line.   Operations  must  be
 instructed  to  use products, don't waste anything,  put on one
 more coat  of paint rather  than  throw  it away, keep  inventory
 as small as possible, recycle used  oil  as fuel  or in  the
 crude    oil,   return   used   batteries.     Minimize   waste
 generation.
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There  are  many  commonsense approaches  to  achieving waste
minimization,  recyling  and  reduction of  compliance costs.
The most  effective way is  by education of  both operations
personnel and management.
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DETERMINATION OF SOIL CONDITIONS THAT ADVERSELY AFFECT THE
SOLUBILITY OF BARIUM IN NONHAZARDOUS OILFIELD WASTE
Robert T. Branch, Dr. Janlc Artiola. and Walter W. Crawley
Soils Division
K. W. Brown & Associates, Inc.
College Station, Texas
Introduction

Concerns about potential changes in the solubility of barite (BaSC^) found in oilfield wastes
were initially voiced by Crawley et al (1). This report presented a literature review and field
data on water soluble  barium, plant  uptake of barium,  and outlined some  potential
environmental effects of uncontrolled land disposal of barium-containing wastes.  The same
report also indicated that although barium is very toxic, its geochemistry is such that it forms
very insoluble barite in the presence of excess sulfate ions.  The basic equilibrium chemistry of
barite is such that soluble barium should not exceed 2 mg/L in a typical aquatic environment.
Barium found in the barite form is also essentially nontoxic to man  (even if ingested in large
quantities) and severely limits barium plant uptake in the soil environment.

Literature Review

The element Ba is a divalent cation which belongs to the alkaline-earth series. Barite is the
most common natural source of barium and is the primary mineral mined for barium.  Due to
barite's density (4.5 g/cm^), it is commonly used as a weighting agent in drilling muds. Spent
drilling cuttings are the primary component in nonhazardous-oilfield waste (NOW).
Barium in soils is normally associated with the sulfate anion and has a solubility of
Barium is also found associated with other anions (namely carbonate, hydroxide or chloride),
however these forms are far less common, probably due  to their availability in  the  soil
solution and significantly higher solubilities. At normal temperatures of 15 to 30° C these
three barium salts  have significantly higher (S.lxlO'9 for BaCO^, and about 2x10' l for
Ba(OH)2'8H2O and BaCl2'2H2O) solubilities.  Therefore, in most well aerated neutral pH soils
the amount of barium in the soil solution will be controlled by the solubility of barium sulfate
(2).

Conditions that  affect sulfate's reduction are redox and pH  (2).  Ultimately these  conditions
also  control the  solubility of barium.  The reduction of the sulfate (SC>4=) ion  in the  soil
environment has a favorable  formation constant (Log K° = 20.74), but requires very reduced
conditions seldom encountered in well aerated surface soils (2). The redox potentials necessary
to begin sulfate reduction in NOW is about -240 mV (pH of 8) (2). As seen in Table 1 , this value
requires very reduced  conditions (3). Redox of this magnitude and intermittent sulfate
reduction has been recorded in marshes of Southern Louisiana (4).
                                      217

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Although there is limited data available, recent studies on the effect of EC (5) and redox (6) on
barium solubility have been performed.  Sposlto and Tralna show barium solubility can
Increase slightly from  1-2 mg/L at < 5 mmhos/cm to 7 mg/L at 45 mmhos/cm with high
chloride solutions (5). Deuel and Freeman show Increased soluble barium with decreased redox
values  (6).  Because of the limited nature  of both studies, additional data under natural
conditions may be required. In general, however, the most Important factors that will control
the amount of barium in the soil-pore water are:

        1.  Ionic  strength, particularly the amount of chlorides as measured by EC of a
          saturated soil-water paste (5).

       2.  Redox and pH changes, as measured by a decrease in the Eh (electron potential) and
          an Increase In the H+ ion activity of the soil at or near saturation conditions (2). Eh
          and pH values as they relate to  sulfate reduction may control the solubility of
          barium.

       3.  Common ion effect, as measured  by the total amount of free sulfate ions from other
          sources such as gypsum. The presence of high levels of SO4 ions in the soil solution
          can have a dramatic effect on the decreased solubility of barite.

Table 1. Jackson's Redox Potential for Given Soil Conditions (3).
        Oxidation
           or
        Reduction                                       Redox •
        Condition                                      Potential
                                                      millivolts
 KMnO4 In 1 U H2SO4                                    1.500
 Very well oxidized soil                                    800
 Well oxidized soil                                        500
 Moderately well oxidized soil                              300
 Poorly oxidized soil                                      100
 Much reduced soil                                       -200
 Extremely reduced soil                                   -500
 Na2S2O4 (pH 8)                                         -600
   Redox potential (Eh) is the most common value reported in biological and soU literature.

 Study Objectives

 The primary objective of this study is to determine the effects of soil-water environment on the
 solubility of barium found in drilling mud.  Barium found in drilling muds is assumed to be
 almost exclusively barium  sulfate.   The  effects of reducing conditions  and high salt
 concentrations Indicate the possible formation of other more soluble barium forms, resulting
 from traditional treatment and disposal practices of nonhazardous oilfield waste. A model of
 this treatment and disposal environment has been attempted under greenhouse conditions and
-monitored for one year. A simulation of this environment would allow the assessment of a
 long-term effect of such an environment on the solubility of barium sulfate.

 Methods and Materials

 Materials used in this study included both treated and untreated NOW. The treated NOW meets
 the treatment  criteria outlined by Louisiana Statewide Order 29-B.   Mainly these criteria
 require  the reduction  of electrical conductivity (EC), sodium  adsorption ratio (SAR).
                                        218

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exchangeable sodium percentage (ESP), and oil and grease percentages. Typically these treated
wastes have had a gypsum amendment. A baseline analysis of the three materials used In this
study are outlined in Table 2. Materials 1 and 2 are essentially the same except for the addition
of oily NOW added to increase the oil and grease concentration to  about 6% (Oil and Grease
Amendment).  Untreated NOW was collected the day of arrival at the waste facility for the third
material.

Table 2. Description of Various Treatments.
BUCKET #
1
2
3
4
5
6
7
8
9
10
11
12
AMENDMENT
Treated
Treated
Treated
Treated
Treated Hi O & G
Treated Hi O & G
Treated HiO&G
Treated Hi O & G
Untreated
Untreated
Untreated
Untreated
TREATMENT
Aerated
Flooded
Aerated
Flooded
Aerated
Flooded
Aerated
Flooded
Aerated
Flooded
Aerated
Flooded
The three materials used in this study were placed under aerated and flooded conditions.
Duplicates of materials and conditions were made for a total of twelve treatments.  The
description of these treatments are shown in Table 3.  Figure 1 contains a sketch of the bucket
design.

Table 3. Initial Readings on Samples used for Treatments.
MATERIAL
Gypsum
Gyp + O&G
No Amend
MATERIAL
Gypsum
Gyp + O&G
No Amend
PH
(s.u.)
7.3
7.3
7.8
S04
meq/L
40.4
35.5
31.6
EC
mmhos/cm
4.85
4.93
25.6
Ba
mg/kg
13.640
10.808
8.461
Na
meq/L
25.9
25.7
233.0
O&G
%
1.03
6.1
1.84
Ca
meq/L
30.0
29.5
35.1
CEC
meq/lOOg
15.8
14.4
21.2
Mg
meq/L
3.8
3.6
4.7
Extr. NA
meq/lOOg
3.09
4.18
32.4
HC03
meq/L
2.3
3.1
2.0
Exch. NA
meq/lOOg
0.50
1.61
9.06
Cl
meq/L
16.7
15.8
232
SAR
6.3
6.31
52.2
Water saturated conditions were maintained in the flooded treatments by plugging the drain.
Each month soil-pore water for the flooded treatments was allowed to drain  out  of the
saturated systems, collected, and analyzed for EC and soluble constituents, including barium
and zinc.  Aerated treatment leachates were collected into a loosely sealed plastic gallon jug.
All solutions collected were  analyzed immediately for pH and  EC.  pH equipment was
calibrated on a standard two point curve with pH 4.0 and pH 7.0 standard solutions. Electrical
conductivity probes were calibrated using  standard stock solutions of 720 and 20,000
Hmhos/cm.   Redox was measured on each of the twelve treatments with Pt electrodes
standardized using  a 2% NaSO4 solution. Redox measurements were based on averages of
several Pt electrode readings.
                                        219

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                          ooooooo
                            ooooo
                             o o o p/o o o o
FIGURE 1:   CROSS SECTION OF BUCKET USED IN GREENHOUSE STUDY
                       220

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The water drained out of each system was replaced and water-logged conditions continued for
another month.   Because some of the flooded buckets demonstrated dispersive properties,
flooded conditions were maintained with little or no loss of pore water.

    Analysis
The following data and discussion are based on the results obtained for the period of one year.
Table 4 presents a summary of the soil and water data collected every other month during the
same time interval.

Redox Measurements

An initial statistical evaluation of the soil redox potential (Eh) data using the mean values of
four or more platinum electrodes, collected during the last eight sampling periods indicates
that these means are significantly different between the flooded and aerated treatment (1, 3, 5.
7, 9, 11. and 2, 4. 6, 8. 10, 12. respectively). The average Eh (in mV) was approximately +176. and
-142 mV for the period of November 1988 to September 1989 for all of the aerated and flooded
treatments, respectively. Figure 2 shows the changes in redox with time for the aerated and
flooded conditions.   Eh values for the aerated treatments have remained  constant at
approximately 4-180 for the past eight months. During this same eight-month period, flooded
treatments have experienced a gradual decrease in redox Eh from about -1 1 to -240 mV, in the
same period of time. The redox values for the flooded and aerated conditions are statistically
different (at the 0.05 level). These were, however, the only statistical differences among the
treatments due to random micro-variability of the NOW.
     Figure 2. Changes in Redox in Aerated and Flooded Treatments with Time.
               -325    -225
                            -125
                                    -25     75
                                     Redox mV
175
275
                                       221

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Table 4. Analysis ol Chemical Parameters of Soil Pore Waier Data
Date Bucket Material Conditior
*
pH
(S.U.)
C J Na
mmhos/cnj mq/L

Ca
mq/L
Mg
mq/L

HOO3
mg/L

Cl
mg/L

SO4
mq/L

Ba
mq/L

Zn
mg/L
12-Sep-88
12-Oci-ee
17-OCI-88
14-Nov-88
12-Dec-88
25-Jan-89
9-Mar-89
14-Apr-89
1B-May-89
07-JUI-89
28-Auq-89
1
1
1
1
1
1





Treated
Treated

Treated '
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
.
-
7.86
.
8.19
7.69
8.06
8.03
8.63
.
-
.
-
-
-
4.00
4.70
4.00
3.30
2.80
.
-
-
-
-
-
-
595
-
542
400
-
-
-
-
-
-
-
514
-
427
273
-
-
-
-
-
-
- -
47
-
38
23
-
-
-
-
-
-
-
68
-
55
66
-
-
-
-
-
-
-
732
-
615
403
-
-
-
-
-
-
-
1,720
-
1.440
1,000
-
-
-
-
-
-
<0.5
<0.5
<0.5
<0.5
<0.5
-
-
-
-
- '
-
0.04
0.29
0.02
0.12
<0.01
-
-
12-Sep-88
12-OCI-88
17-OCI-88
14-NOV-88
12-Dec-88
25-Jan-89
9-Mar-89
14-Apr-89
18-Mav-89
07-Jul-89
28-Auq-89
27-Sep-89
2
2
2
2
2
2
2
2
2
2
2
2
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Flooded
Flooded
Flooded
Hooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
.
-
6.94
.
7.23
7.22
6.95
6.82
8.44
6.91
6.95
6.92
-
.
2.28
-
3.40
2.80
3.20
4.00
0.72
2.40
2.00
2.20
-
-
320
-
-
265
-
-
66
-
-
123
-
-
314
-
-
548
-
-
412
-
-
324
-
-
26
-
-
46
-
-
23
-
-
34
-
-
256
-
-
305
-
-
438
-
-
80
-
-
167
-
-
1 11
-
-
1 1
-
-
11
-
-
1.060
• -
-
1.700
-
-
1,030
-
-
744
-
-
0.5
-
<0.5
<0.5
<0.5
-
<0.5
<0.5
<0.5
<0.5
-
-
0.07
-
0.05
0.06
0.03
. •
<0.01
<0.01
0.02
0.03
12-Sep-ae
12-OCI-88
17-OCI-88
14-Nov-88
12-Dec-ae
25-Jan-89
9-Mar-89
14-Apr-89
18-May-89
07-Jul-89
28-Auq-89
27-Sep-89
3
3
3
3
3
3
3
3
3
3
3
3
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
.
.
7.72
-
8.24
7.64
8.16
7.05
8.24
8.22
8.63
7.85
.
.
-
.
3.40
4.10
3.20
2.20
1.40
0.88
0.44
0.80
-
.
-
.
-
530
-
284
154
-
-
100
.
.
-
-
.
504
-
304
188
-
-
106
-
-
-
.
.
46
.
23
14
-
.
7
-
-
-
.
.
27
-
60
54
-
.
82
-
-
-
.
-
477
-
300
114_
-
-
27
-
-
-
.
.
1.970
-
931
644
-
.
298
-
-
-
.
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
.
-
-
.
0.03
0.04
<0.01
0.28
<0.01
<0.01
0.01
0.01
12-Sep-88
12-OCI-88
17-OCI-88
14-Nov-88
12-Dec-88
25-Jan-89
9-Mar-89
14-Apr-89
18-May-89
07-JUI-89
28-Auq-89
27-Sep-89
4
4
4
4
4
4
4
4
4
4
4
4
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Treated
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
Flooded
-
-
7.10
-
7.28
7.24
7.03
8.00
7.38
7.33
7.11
6.9
-
.
6.42
.
5.50
4.95
4.80
6.10
4.20
4.00
3.60
2.80
.
.
864
.
-
788
-
728
563
-
-
524
.
-
642
-
-
679
-
602
742
-
.
489
.
.
66
.
.
73
.
79
60
.
.
36
_
.
1090
.
.
391
.
1080
560
.
-
323
_
.
863
-
.
840
.
479
436
.
.
147
_
.
1.730
.
.
1,970
.
1,960
2.050
_
_
1.400
.
.
<0.5
.
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
.
.
0.06
.
0.03
0.04
0.16
<0.01
<0.01
0.03
0.03
0.03
222

-------
liable 4. Analysis ol Chemical Parameters ol Son Pore Water Data.
T Date Bucket Material Condition pH 1 C
i * 1 (s.u.) frnmhos/crr
Na
mg/L
Ca
mq/L
Mg
mq/L

HC08
mg/L

Cl
mq/L

SO4
mg/L

Ba
mg/L

mg/L
J2-S8P-88
12-OCI-88
17-Oct-BB
U-NOV-8B
12-Dec-B8
25-Jan-89
9-Mar-89
14-Apr-89
18-Mav-89
07-JUI-88
28-Auq-8E
27-Sep-BJ
5
5
5
5
5
5
5
5
5
5
5
5
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Treated Hi O&G
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
.
.
7.70
.
7.65
7.98
7.98
8.01
7.91
8.01
7.93
7.76
.
.
7.07
.
5.00
6.00
4.70
4.00
3.30
3.40
3.00
2.60
.
.
1030
.
.
960
-
676
453
-
-
624
-
-
772
-
-
436
-
458
448
-
-
371
-
.-
88
-
-
82
-
60
41
-
-
35
-
-
333
-
-
98
-
206
228
-
-
239
-
-
1,370
-
-
1,190
-
555
359
-
-
191
-
-
1,650
-
-
1,910
-
2,050
1,560
-
-
1,210
-
-
<0.5
-
<0.5
<0.5
<0.5
<0.5
<0.5

-------
Table 4 Analvsis of Chemical Parameters of Soil Pore Water Data.
Date Bucket Material Conditior
*
PH
(S.U.)
C I Ma
mmhos/crrj mg/L
Ca
mg/L
Mg
mg/L
HCO3
mg/L

Cl
mq/L

SO4
mg/L

Ba
mg/L

Zn
mg/L
12-Sep-88
12-Oct-88
17-Oct-88
14-NOV-88
12-Dec-88
25-Jan-89
9-Mar-89
14-Apr-89
18-M3V-89
07-Jul-89
28-Aug-89
27-Sep-89
9
9
9
9
9
9
9
9
9
9
9
9
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
.
-
-
.
8.26
7.37
8.27
7.99
8.19
7.75
8.14
8.01
-
-
-
.
4.20
52.00
5.22
7.10
17.00
7.8
5.5
9.1
.
-
-
-
-
13160
-
1750
4860
-
-
5000
-
-
-
-
-
2690
-
228
783
-
-
297
-
-
-
-
-
310
-
25
82
-
-
39
-
-
-
-
-
91
-
77
61
-
-
91
-
-
-
-
-
27,600
-
2,920
8,280
-
-
4,480
-
-
>-
-
-
1,530
-
307
996
-
-
313
-
-
-
-
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
<0.5
0.5
-
-
-
-
0.02
0.09
<0.01
<0.01
<0.01
0.01
0.03
0.02
12-Sep-88
12-Oct-88
17-Oct-88
14-NOV-88
12-Dec-88
25-Jan-89
9-Mar-89
14-Apr-89
18-May-89
07-Jul-89
28-Auq-89
27-Sep-89
10
10
10
10
10
10
10
10
10
10
10
10
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Flooded
Rooded
Flooded
Flooded
Flooded
Rooded
Flooded
Flooded
Flooded
Flooded
Rooded
Flooded
„
.
7.34
-
.
.
7.81
.
7.95
8.33
8.22
-
.
-
-
.
-
-
9.00
.
4.80
3.20
3.70
-
.
-
-
-
-
.
-
-
-
-
.
-
.
-
-
-
-
-
-
-
-
-
.
-
.
-
-
-
-
-
-
-
-
-
-
-
.
-
-
-
-
-
-
-
1410
-
-
-
.
-
-
-
-
-
-
-
762
-
-
-
-
-
-
-
-
-
-
-
593
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
.
-
-
-
-
-

-
-
-
.
-
12-Sep-88
12-Oci-ee
17-OCI-88
14-Nov-88
12-Dec-88
25-Jan-89
9-Mar-89
14-Apr-89
18-May-89
07-Jul-89
28-Aug-89
27-Sep-89
11
11
11
11
11
1
1
1
1
1
1
11
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
Aerated
.
-
.
.
7.15
7.73
7.63
7.95
8.44
8.26
8.56
8.39
.
.
.
-
40.00
1.00
24.00
18.00
7.20
6.00
1.40
2.60
.
-
.
.
-
20160
.
4900
1700
.
.
1000
-
.
.
.
.
2928
.
477
152
-
.
73
.
-
-
-
.
536
.
79
20
.
-
5
.
.
.
.
.
49
.
150
117
-
.
98
.
.
.
.
-
36.260
.
7,450
2.450
.
-
692
-
-
-
-
-
2.610
.
1.550
581
.
.
314
.
-
.
-
1.0
-
<0.5
0.9
<0.5
<0.5
<0.5
<0.5
.
'.
.
.
0.09
-
0.09
0.04
<0.01
0.01
0.02
0.02
12-Sep-88
12-OC1-88
17-Oct-88
14-NOV-88
12-D6C-88
25-Jan-89
9-Mar-89
14-Apr-89
18-May-89
07-Jul-89
28-Aug-89
27-Sep-89
12
12
12
12
12
12
12
12
12
12
12
12
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Untreated
Rooded
Rooded
Flooded
Rooded
Rooded
Flooded
Rooded
Flooded
Rooded
Flooded
Rooded
Rooded
.
-
.
-
7.01
7.05
6.99
-
7.25
7.94
7.68
-
.
.
.
.
42.00
26.00
26.00
.
20.00
13.00
4.00
.
_
.
-
.
.
.
.
.
• •
-
-
-
_
.
.
.
.
.
.
.
• •
.
-
.
_
.
.
- -
.
.
-
-
• •
.
.
.
" Insufficient Sample.
.
-
.
.
_
.
.
.
187
.
.
_

.
-
.
.
.
.
.
.
10 510
.
.
.

.
-
.
.
.
.
.
.
4 340
.
.
.

.
-
.
.
<05
.
<05
.



.
.
.
.
.
0.57
.
0.02
.


. .
.

224

-------
|;H Measurements .

fPhfle the trend is not significant, there appears to be a slight reduction in pH occurring in the
^ooded and treated systems (Table 4). This is consistent with the improved leaching of sodic
kalts, as induced by gypsum, and the increased microbial activity and increased concentration
itjf C02 that occurs in flooded soil, which tends to reduce the pH.  Further reductions in pH will
Ibe controlled by the rates of microbial  activities and the  buffering capacity of the  NOW
systems.

yfl and Soluble Ions Measurements

The  amounts of soluble ions as measured by leachate EC (mmhos/cm) for the systems are
reported in Table 4. In general, the EC of untreated NOW is much higher than the treated NOW.
This is expected based on the initial EC of the materials  and the classic  dispersal
characteristics demonstrated by the untreated  flooded treatments.  These characteristics
prevented internal drainage and concentrated EC further. The aerated untreated NOW systems
also had high initial EC. but with significant leachate collections EC shows a downward trend.
The EC for the  eight treated  buckets has  decreased  roughly 36 to 53% since the initial
measurements.

The data on the specific ions from the water are limited at this time and will not be discussed in
depth (Table 4).  It should be noted that the sulfate concentrations appear to be at or above
gypsum saturation in all of the 12 systems, which range from 1.500 to 2,600 mg/L 804. This
points to the fact that both treated and untreated NOW contained sulfates. Historical analyses
of NOW indicate large variances in sulfate concentrations.                    —

Soluble Barium and Zinc Measurements

Soluble barium was measured directly from the filtered and acidified soil-pore water leachate
(Table 4). These data Indicate that, thus far. the soluble barium remains at or below the
detection limit of 0.5 mg/L in all of the treatments. These data are consistent with the high
sulfate levels detected in all of the waters from all of the buckets. Even flooded buckets, which
had EC values as low as -300 mv. had <5  mg barium/L. The common ion effect is likely
responsible for the undetectable amounts of barium present in the water, since excess amounts
of the 804 Ion drive the equilibrium chemistry toward the formation of BaSO4.

The soluble zinc data reported in Table 4 are also consistent with the chemistry of zinc in water
at above neutral pH. As expected, zinc Is not very soluble in alkaline pH systems. Therefore,
only traces of this element have been measured thus far  in the soil-pore water of all of the
systems.  Zinc concentrations are expected to remain at or below these levels and even decrease
further In the flooded systems due to the likely formation of very insoluble zlnc-sulfides which
occurs under reduced conditions.

Summary and Conclusions

The  data collected from the NOW  experiments indicate the following conclusions concerning
flooded versus aerated systems, and the treatment effects.

      •   The only redox data of statistical significance was found between flooded  and
         aerated treatments.  Redox readings of the aerated treatments were not conclusive
         statistically between the three treatment materials.  Treatment effects within the
         flooded and aerated conditions proved to be not significant.
                                      225

-------
         Gypsum amendments Improve the physical nature of the NOW as evidenced by the
         lack 'of water  movement through both the flooded and  aerated unamended
         treatments.

         Sulfate saturated soil-pore water concentrations in all treatments Indicate that
         both the treated and untreated NOW used In this experiment contained significant
         amounts of sulfates prior to the start of the experiment. The unexpected presence of
         high free sulfate levels in "untreated" NOW may have overridden any effect of high
         EC on the solubility of barite.

         The soil-pore water data indicate that both barium arid zinc remained at or below
         detection in spite of very low soil redox values. This trend is expected to continue
         due to the excess 804 ions.

         The effect of low redox (<-250 mV)  on the solubility of barite found In some of the
         flooded  and "untreated" NOW systems may have  been overridden by the
         unexpectedly high levels of free sulfate ions found in them. Although little evidence
         exists that the  sulfate reduction has occurred, conditions are conducive for sulfide
         production as might be expected.  Further research should include the effects of
         redox on a low sulfate system.
REFERENCES

1,   W. W.  Crawley. J. F. Artiola. and J. A. Rehage, The Environmental Effects of Land
     Disposal of Barium Containing Wastes. Conference on the Disposal of Oilfield Wastes,
     Norman. OK. May. 1987.

2.   W. L. Lindsay. Chemical Equilibria In Soils. Wiley - Intersclence Pub., 1979. 449 p.

3.   M. L. Jackson. Soil Chemical Analysts — An Advanced Course. Published by the author.
     Dept. of Soils, Univ. of Madison, WI. 1974. 991 p.

4.   T. C. Feljtel. R D. DeLaune. and W. H. Patrick, Jr.. Seasonal Pore Water Dynamics in
     Marshes of Barataria Basin, Louisiana, Soil Scl. Soc. Am. J. 52, 1988. 59-67.

5.   G. Sposito. and S. J. Traina, An Ion-Association for Highly Saline Sodium Chloride-
     Dominated Waters. J. Envir. Qual. 16.  1987. 80-85.

6.   L. E. Deuel. Jr. and B. D. Freeman. Amendment to Louisiana Statewide  Order 29-B,
     Suggested Modifications for Barium Criteria. SPE/IADC. 1989. 461-466.
                                        226

-------
THE DEVELOPMENT OF A WASTE MANAGEMENT SYSTEM FOR THE
UP-STREAM, ON-SHORE OIL AND  GAS INDUSTRY IN WESTERN CANADA
Ross  D. Huddleston  , W.A.  Ross
Faculty of Environmental  Design
University of Calgary, Alberta
Jacques R. Benoit
Sr. Staff Environmental  Engineer
Mobil Oil Canada
iCalgary, Alberta
ABSTRACT

This paper describes  the  development of  a waste management system to  assist
personnel required to  deal with wastes  generated in  the up-stream,  on-shore
oil and gas industry  in Western Canada.

The system was designed to accommodate the  waste streams presently generated
by Mobil Oil Canada's Western Canadian operations and to serve as a guide for
the treatment of  waste streams which  may evolve  in the future.   The  system
incorporates basic principles  of waste management that  are prevalent  in the
literature.  The  elements presented are:

      The  waste   data  sheet   a   standardized  form  presenting   information
regarding  a  specific waste  types  chemical  data, possible  toxic  components,
handling and  storage  methods,  transportation related  information,  disposal
guidelines,  available  contractor  services,  and  regulatory  and corporate
contacts;

      The  waste  tracking  program  a computerized data  management  tool  for
gathering  information  regarding:  waste generating location,  date that waste
was generated,  type  of waste,  volume of  waste,  disposal method,  disposal
location and contractor employed;

      The  site specific waste  disposal  manual  a  quick reference guide  for
determining safe  and reliable long-term disposal options for waste  materials.
It provides information necessary  for field personnel,  working in  a  discreet
area of  a  company's  operations,  to  carry  out  their daily waste  management
needs;
 1  Presently  Environmental  Specialist  with  David  Bromley  Engineering(1983)
 Ltd., Calgary,  Alberta
                                      227

-------
Introduction

Waste management has  come  to the forefront of the  decision making process for
the oil  and gas industry  in Canada.  This  claim  is  substantiated throughout
the  literature and  is frequently  a  "head-line"  topic  for  the  mass  media.
Government ensures that companies,  operating in these  industries,  comply with
the  regulations . via  strict,  harsh  penalties  for  infractions(1).    These
circumstances,  as well as  the acceptance  of  the "due diligence"  process,  has
prompted  the   development  of  a  systematic  approach  to  the  consistent,
acceptable, and safe management  of all waste  streams.

One  of the  major  aspects  of a waste management  system  is  the  appropriate
disposal of  all wastes.   Waste  is defined as the end result of  a  process  for
which  there  is no further apparent  use.   Many  of  the wastes produced  in  the
oil and  gas  industry are  hazardous because they pose  a treat to human  health
and  the  environment.   This paper  will  outline   the  major components of a
proposed waste disposal manual.

A waste  disposal manual is intended to assist personnel required to deal with
wastes generated  in the up-stream,  on-shore  oil and  gas  industry in Western
Canada.   Research  of  the  literature  and discussions with  field personnel
indicate that  this  manual  is an efficient method of organization  for a large
and  diverse  operation such  as is  common  in  the  oil  and  gas industry.
Government  regulations  and waste  management   technologies  'in  Canada   are
evolving rapidly and hence the information presented in this paper  is based on
the best data  available at this  time.

The  safe,  long-term  management  of wastes requires in depth  knowledge about
government regulations, available waste  disposal technology and  the chemistry
of  wastes  and  how  they react with the  environment.    In  order to properly
address  all of these aspects  a voluminous  waste  disposal manual  would be
required.   However,  in practice a voluminous waste disposal manual would  not
be  used  by  field operations personnel(2).   For this  reason  a  site-specific
waste disposal manual(SSWDM) has been developed.

The  SSWDM  system of organization  addresses  the  unique   opportunities   and
constraints  of each  identifiable  area  of   a  company's  operations.   Areal
boundaries  are determined  by  geographic  and  political  region,  production
characteristics(e.g.   oilfield   vs.  gas   plant),  and  corporate  managerial
divisions.

Implementation of this system requires that  the company follow a specific  set
of  procedures  to  promote  compliance  with  all  applicable  legislation   and
corporate environmental policy.   The system  will provide field personnel with
information necessary  to execute regular waste management tasks.
                                     228

-------
The waste disposal manual  described in this paper  was designed to accommodate
the waste streams  presently generated  by Mobil Oil  Canada's Western Canadian
operations and  to  serve as  a  guide for  the  treatment of  waste streams which
may evolve in the future.

To ensure that  the waste  disposal manual  is  utilized and evolves along with
the  company's endeavors, a  mechanism  has been  built in for modification and
update.   This  task  will  rely heavily on the  cooperation  and  assistance  of
field operations personnel.

Users are encouraged  to participate in the modification  and update process  to
ensure  that  it meets their needs and complies with  all  present  and future
waste management  legislation.   Ultimately this waste disposal  manual should
prove to be  a  useful tool which  can  be  shown  to  be both  cost  effective and
environmentally wise.
Background

In 1984, The Canadian  Petroleum Association(CPA)  published a guidance document
for the petroleum  industry in  Western Canada(3).    The primary  objective of
this document  was to set out  standards of good practices  for  the disposal of
conventional  oilfield  wastes   in  an environmentally acceptable  manner.   It
defines and recommends eight principles for good waste  management practice in
the oil and gas  industry:

1.    Minimize the  amount of waste generated;
2.    Recycle waste materials  whenever  possible;
3.    Eliminate  production  of  the  waste whenever  possible;
4.    Determine  the hazards associated  with the waste;
5.    Avoid landfill pollution;
6.    Approve disposal service companies prior to their employment;
7.    Use an approved  hazardous waste treatment facility
      for disposal  of  hazardous wastes; and
8.    Initiate research into safe  disposal practices.

These guidelines were  the  first to propose the concept  of  a waste data sheet.
A  total of twenty  waste  types were provided giving  limited  information on
waste disposal,  potential hazards  and regulatory  requirements.

The  waste   data sheet was  further   developed   in  1986  by  the  Petroleum
Association for  the Conservation  of the Canadian Environment (PACE) (4) .   PACE
developed fifty-five waste data sheets providing information  on  physical and
chemical data, hazards,  handling and storage,  transportation and treatment and
disposal guidelines.  Many  of these waste  data  sheets related to downstream
oil and  gas activities,  however  those associated  with  the   up-stream were
reviewed and the  applicable  information  incorporated  in  the  waste  disposal
manual.
                                      229

-------
In  Canada  there  are  many  provincial  and  federal  statutory  requirements
regarding the  management of wastes.   In 1987,  the Alberta government issued
the Alberta User's Guide for Waste Managers(5).  This  document  summarizes the
various  acts  and  regulations  and  provides  guidance  for  the  appropriate
disposal of waste material.

Two  regulations relate  directly  to  the disposal  of  waste  in Alberta:  The
Hazardous Waste Regulations(Alberta) and  the Transportation of Dangerous Goods
Regulations(Canada).

The appropriate disposal of waste  in Western Canada is  primarily determined by
the  classification  of  the  waste,  i.e.  hazardous vs  non-hazardous.    Most
Western provinces in Canada have adopted  the Transportation of Dangerous Goods
Regulations as  the basis for classifying  wastes.

These  regulations  provide a list  of chemicals  or  products which,  if present,
will  render  a waste  hazardous.    The  Government of  Alberta,  through  the
Hazardous  Waste   Regulation,   has  provided  exemption  from   the hazardous
classification  for  some oilfield wastes.    However,  the  exemption  relates
mainly  to the  manifesting  and storage  requirement and not  to  appropriate
disposal.   Classification of  oilfield  wastes in Western Canada is presently
under  review   and  as   such   any  waste  disposal  manual   will have   to be
continuously updated.

U.S.  legislation and various  API(American  Petroleum Industry)  projects  were
also  reviewed since  Canadian regulations have  often followed  trends  in  the
U.S.

Discussions with operational personnel was critical to  the  development  of this
waste  disposal  manual.    These   discussions  identified  some  of  the  major
problems with present waste disposal practices:

a) the lack of  a  systematic approach, by the oil and gas industry  as a whole,
to waste management;

b)  a  vast  amount of   information  regarding  waste  management regulations,
technical  waste  disposal  methods,  waste chemistry  and  chemical  protective
methods dispersed throughout many  documents;

c) many waste types for  which  there is no information available;

d) inaccurate classification of hazardous vs non-hazardous  waste; and

e) the lack of  a  comprehensive system with  which to account for waste  related
activities and  information(types and volumes  generated,  disposal  methods  and
locations  used,  storage and  handling methods,  regulatory and  transportation
requirements, and contractor services).
                                      230

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      on  this information it was  determined  that  a  "useful"  waste  disposal
manual should:

a) provide simple, straightforward  solutions to the waste management problems;

b) provide specific  information relevant to  their situation and  locality(e.g.
personnel  involved  in  heavy   oil  operations  do  not  require   information
concerning the handling of waste at a gas plant);  and

c) provide  information regarding all of the wastes that are  produced in  the
specific area.

The elements  of this waste disposal manual are the Waste Data Sheets,  the Site
Specific  Waste Disposal  Manual, the  Waste  Tracking  Program and methods  for
generating, updating and modifying  these elements.
Waste Data  Sheets

The waste data  sheet(Fig.  1)  consists of eleven sections.  The following is an
explanation of the information   provided  for  each section of  the waste data
sheet.

1. Revision Date;   Each  time  the waste  data sheet  is  revised  this  will be
updated.  It will  give an indication of whether the data is up-to-date.

2.  Sheet   Number:    The  purpose   of  this   number  is  for  reference  and
organization.

3. Name of  Waste:   The most widely used name appears as the name of the waste.

3a. Synonyms:  Any synonyms for the waste  are  to  be included and identified as
such.   All field, chemical,  and  slang names must be  included  in  order to
better identify the waste data sheet to potential users.

4. Chemical Data:  Based on the most  authoritative literature on the chemistry
of oilfield wastes.

Research of the literature was necessary to complete this section  of the waste
data sheet.  Few oilfield wastes have had adequate chemical analysis done and
therefore a waste characterization process was used to determine  the chemical
information.    The  waste characterization process  is  meant to  assist  in the
identification and definition of target chemicals.

This project did  not  include any laboratory chemical analysis of waste.
                                      231

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5. Possible Toxic Components;  The information provided was  dependent upon the
chemical data available in the literature.

5a.  Potential  Hazards:  The   synergistic  effects  of   the   chemicals  that
constitute the waste form the principal basis  for  this  section.

5b. Personal  Protection;  This section  of the waste  data sheet  contains  only
limited  information  explaining   the  need  to  address  PPE.     Preliminary
information about  Personal  Protection  Equipment(PPE)  and information sources
are  provided.   This   section stresses  the  need  for  proper  training  and
familiarity with handling of dangerous chemicals.

6.  Storage  Methods;   Storage  methods  are  directly  related  to  the waste
characterization  process.    The  storage  of  waste  is   dependent  upon   the.
following  characteristics:     the  hazards  associated with  the  waste;    the
compatibility of the waste with other chemicals;  the amount of waste produced
on a regular basis;  and the disposal options(6).

The most important characteristic  used to  determine storage  options is  the
hazards  associated  with the waste.   The storage vessel  must  be resistant to
damage  resulting in  a  situation  that is  dangerous to  human health or  the
environment.  For example,  if  a  corrosive  material is being stored then it is
suggested to use non-corrosive containers.  If explosive or flammable material
is being stored then it is suggested to use storage vessels  which  are spark
proof and well vented.

Details  about storage options for  hazardous  waste are provided in  Hazardous
Waste Storage Guidelines. Alberta Environment, 1988(7).

All  waste storage  facilities must be  clearly identified  and  -  under  the
Federal  Government  of Canada's Hazardous Products  Act -   all  workers must be
informed  as  to the hazards  posed by  stored  wastes through a combination of
identification  and  worker   education(S).      Some   wastes   must  be  stored
indefinitely, until an acceptable disposal option is discovered.

6a. Handling  Precautions:  As  is  the case  with storage methods,  the hazards
associated with a waste are the  most important characteristic for determining
handling precautions.   Precautionary measures  necessary for  the safe  handling
of hazardous  chemicals  are well documented(9).    It  was  decided  that  the
handling precautions for a mixture of hazardous chemicals are a compilation of
the handling precautions for each of the hazardous chemicals in the mixture.

7. Transportation:  The information provided  is that which is  necessary to
complete a  federal  or provincial  Canadian Transportation of  Dangerous Goods
Act (TDGA) manifest form.
                                     232

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This  section of  the  waste  data  sheet refers  directly  to  the  (TDGA)  and
Transportation  of Dangerous Goods  Regulations (TDGR).   Hazardous  substances,
including wastes, are  regulated under  this  act and must be  manifested  when
transported  (7).    The main reasons  for this  practice are:  to  ensure  that
hazardous  materials   are  comprehensively  managed;   to  indicate  to   first
responders the  hazards present  in  the event of a  transportation accident;  to
aid  in  the  determination  of  packaging  and  other  precautionary  measures
necessary  for  safe  transportation;  to assist  in  the tracking  of dangerous
goods; and to delineate potential routes of travel (7).

The degree of hazard posed by a substance  determines its TDGA classification.
If it falls  below the  well  defined limits set out in the act  then it is  not
considered hazardous,  under  the  act.

It was  found  that  the  petroleum wastes  examined  are  often  difficult  to
classify under  the TDGA due  to their diverse constituency.   In these cases  the
waste mixture  was  classified as  the most hazardous chemical present  in  the
waste and  comprising  the  largest  component of  the  waste.     However,   all
chemicals in the waste were considered  to  ensure that  low  concentrations  of
extremely hazardous chemicals were addressed.

Wastes  that were  determined,  through  the  literature,  to  be  sufficiently
hazardous to  warrant  classification  under TDGA  which were  not  explicitly
regulated (i.e.  the name of the waste did not appear in the list of regulated
substances  in  the  act) were classified as Not Otherwise  Specified (N.O.S.).
This classification scheme  is legislated under the TDGA   and  is based on  the
hazardous nature of the waste.

In  situations  where  neither of  the  above  methods were  possible with  the
available information, it  is  indicated on the  sheet  that  the  waste  is  not
listed in the TDGA and therefore a chemical analysis of the waste is necessary
to determine its hazards  and subsequent TDGA classification.

7a.  TDGR Identification Number:  The product  identification   number   (PIN)
corresponding to the regulated name of the waste is provided.

7b.  TDGR Classification:The hazard classification number corresponding to  the
regulated name  of the waste  is provided.   These  numbers are  in  the Alberta
User Guide  for  Waste  Managers  (1987).   Either a waste was  classified as  a
substance appearing in the  TDGA, in  which case  the classification number  was
given, or a waste was classified due  to the identified chemical hazard.
                                       233

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There  are  seven  potential  characteristics   which  may,   depending  on  the
magnitude,  cause  a  substance  to  be  considered  hazardous  under the  TDGA.,
These    characteristics    are:    explosivity,    corrosivity,    reactivity,
radioactivity, flammability, toxicity and  inclusion on a Federal or Provincial
dangerous substance list  (10).

7c.  Type of  Carrier:  This refers  to  the  vehicle  required to  transport  the
waste under the TDGA.

7d.  Waybills  Required: A waybill is a document  describing goods  shipped  by
rail  or truck.   For wastes regulated  under  the TDGA  a federal  manifest  is
required.  Company specific manifest requirements are  also  indicated.

7e.  Loading-Unloading Precautions: The activities  reviewed  include  loading,
unloading,  transferring,  transporting  and  packaging  of  the  waste.   The
information that provided was  based  on the safe work procedures  outlined  in
Glenn and Sterling (1988)(9) and  Glenn  et  al.  (1988)(10).

8. Disposal Guidelines: A designation of either "Hazardous"  or "Non-hazardous"
for  each waste type under this section of the  waste  data sheet  is provided.
This  designation is  not the same as  the hazard classification system  used  in
the  TDGA.    The  reason  for  this  is  that the Disposal  and  Transportation
sections of the waste  data sheet  provide information for different purposes.
            *
For  example,  under TDGA  a solid substance is  considered  to be  biologically
hazardous (toxic  or poisonous)  only if  the LD-50 (oral, rat)  is  less  than 200
mg/kg  (11).   However, there is potential  for  adverse  health  effects  to  occur
from prolonged  exposure   to  a  substance  with  a  much higher  LD-50  rating.
Therefore  the  potential   for  workers  or  the  environment  to be  exposed  to
chronic (long-term,  low-level) toxic  levels  of  harmful substances is strong
and  must be considered.

Determination that a waste was  hazardous under  the  Disposal  Guidelines section
of the  waste  data sheet was based on the following  considerations:

a)    the waste  or a chemical  in the waste was classified as hazardous  under
the  TDGA;

b)    the persistent  toxic substances:  (PTS)  polycyclic  aromatic hydrocarbons
or heavy metals  (which are commonly  found in oilfield wastes)  were in the
waste;  or

c)    information from the literature suggesting that  the degradation  products
from  a waste  disposal   technique  contained  PTS's.    (e.g.   heavy  metal
contaminated  fly  ash  from an  incinerator  used  to  incinerate waste  oilfield
sludge).
                                     234

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For  those  wastes for which  it was  impossible  to obtain  information from  the
literature regarding hazard potential,  it is indicated on the waste data  sheet
that it  is necessary to determine  the  hazards prior  to  the identification  of
potential  disposal options.

The  waste  disposal  options that are provided on  the  waste data sheets  include
various  combinations of  the following techniques: chemical treatment, physical
treatment,  biological  treatment,  thermal treatment,  storage  (long  and  short
term),   recycle,  reuse,  recovery,  reduction,  minimization,  transformation,
engineered redesign, and substitution (12).

The  potential disposal  options presented on the waste data sheets are based  on
the  following classification  scheme:

      Ideal:  The ideal  disposal  option  is  either the only  available  option,
the  best available  option, or the most  practical option available.   The  ideal
disposal option must meet  the following two criteria:

1- it is in compliance  with all existing laws;  and

2- it is not harmful to human health or the environment.

      Acceptable:  An Acceptable  disposal option is  substandard  to  the  Ideal
disposal option.  Either  cost,  efficiency, logistics, or feasibility make  it
less  desirable than  the  Ideal  disposal  option.    However,  it meets  both
criteria  necessary  to  be  an  Ideal disposal   option  and  therefore  may   be
employed if necessary.

      Alternatives:  Alternative  disposal options  are those  with an unproven
track record.   Either  due to a lack of case study, a lack of  scientific study,
or a strong potential  for undue risk the disposal option  is not implementable.
The  alternatives section  is  a compendium  of  all potential  disposal  options
which may in  the future  through research  and  development  attain Acceptable
status  or ultimately  replace  the  Ideal  option on  the  waste data  sheet.
However,  Alternative disposal options  do not  meet the  Ideal option criteria
and should never be employed in the field.

9.  Contractor   Services  Available:    Listed  contractors   that  offer  waste
management assistance  to the petroleum  industry were identified through review
of  the  Alberta Special Waste Services Association  (ASWSA)  Directory,  1988.
-Each  of the waste  data sheets has  at  least one potential contractor  service
listed.    Selected  contractors  should  be   approved  through  a   corporate
purchasing program.

10.  Regulatory Agency Contacts:    List  of  provincial  and  federal  agency
contacts are provided

11 •  Environmental   And Regulatory  Affairs Contacts:    A  contact  from  the
Corporate Environmental Department  is provided.
                                      235

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Site Specific Waste Disposal Manual(SSWDM)

The site  specific  waste disposal manual is intended  to  address the wastes and
concerns  specific  to an area of  a  company's operations.   This can be organized
depending on  the business aspects of a  company but more often  on the type of
oil and gas activities  being conducted  in a part of the  organization.

An inventory  of  all waste types  generated in the area must  first be compiled.
This will require  close communication with operating personnel  since often an
accurate  inventory  is  not  kept.    Also,  operating personnel  may be  well
acquainted  with  local  contractors  and  disposal  facilities.     A  review  of
provincial regulations  must be conducted.   In some cases the facility or  area
is covered under two separate  legislative jurisdictions.

Once  all  the information  has  been gathered  the site-specific  waste  disposal
manual can be organized as follows:

      1.    Waste  Identification;

      2.    Present Waste Management Methods;

      3.    Waste  Data  Sheets; and

      4.    Instructions for Using the SSWDM.

The resulting manual  is  often a small pocket  size book with  twenty or less
waste data sheets  which can easily be referenced by field personnel.
Waste Tracking Program

A waste  tracking program was  developed to keep track of waste types, volumes,
and disposal method and location.  The program is  PC based and can be used by
all  field personnel.   Waste information  is gathered  either  through  truck
tickets or purchase orders and is submitted to head office on a monthly basis.
Each site-specific waste  disposal manual has  instructions on the  use  of the
program.
Discussion

One  of  the  major  problems  in developing  a  waste  disposal  manual  is' in
obtaining accurate  characterization  of a waste product.   This often requires
in-depth  discussions   with  field  personnel,  chemical   manufacturers  and
extensive laboratory analysis.   Mixtures such as sludges  and filter backwash
material are  often  difficult to characterize.   Also  filters,  primarily from
gas plants,  are of particular concern.
                                      236

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Furthermore,  treatment techniques,  prior to disposal,  are still being tested
for many waste products.

*the development of  waste data  sheets  is  an  important component  of  a  waste
Management  program.    The sheets  provide  generic  information regarding  each
specific  waste  type.    They  contain  information  collected  about  a  waste
including  waste   disposal  techniques  which  are  innovative  and  unproven.
{Additional research  will be necessary  to address PPE on a site-specific  basis
lonce a chemical analysis has been  done to  determine  the  hazards of  various
(wastes.

rWhile investigating  the waste management practices  used in Mobil Oil  Canada's
field operations  it  was discovered  that field personnel often had  suggestions
for how to manage  wastes.   Some of these suggestions were truly  insightful and
upon further investigation  were deemed  to  be non-harmful  to human health  or
the  environment  and  in  compliance  with government  regulations  and  company
policy.

An  example  of  this   is  the  draining  of used  oil filters  through  a homemade
screening device.    It was  made from an old  drum fitted with a strong metal
mesh  about   six   inches  from  the  bottom.     This  practice  facilitates   the
recycling of used  lubricating  oil.    Suggestions such  as  this  should  be
incorporated into  the waste  data sheets.

Information regarding waste data sheet  modification  must flow  from field  to
. head  office  and  vice  versa via  the waste  data sheet modification process.
However,  waste  data  sheet updates should be disseminated from head office out
to  all applicable operating areas.   This convention will help to ensure:  that
waste  data   sheet  control  remains  central   to the   corporation;   that   new
information is  acceptable prior to  implementation;  and that all areas of the
company's operations will reap the benefits of additional information.

Waste data sheet  updates  should be sent out  each time  a  waste  data sheet  is
modified.   Each area in possession  of  the respective  waste data sheet  must  be
notified of  the changes.   The  person responsible for  management  of the  area
should be instructed to replace the old waste data  sheet with the new  version
and destroy  the old  version.

The current status  of  a  waste data  sheet  is determined by  the  Revision  Date
appearing in the  top left hand corner of each waste data sheet.  A master  copy
of the Waste Data Sheets must be kept  on file located in head office and  will
serve to verify the  current  status for each waste data  sheet.
                                      237

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Field generated  information regarding actual waste management practices is to
be recorded using the waste  tracking  program.

The function of  the waste tracking program is  to provide a mechanism to record
all  waste  related  information.    This  information  is  necessary for  SSWDM
development,  waste  data sheet  creation,  and  to protect the  corporation's
interests.   Field personnel should be  responsible for  recording information
about  waste  disposal.    It  was  discovered  that  field  personnel  have  a
reluctance  towards recording waste related information.   They perceive it as a
task which  makes their work more  complex and,  by slowing them down, appears to
make them less productive.   However, due  to  the attention recently  given to
hazardous waste  by the  media, field personnel are beginning to  realize  the
importance  of  using company approved waste management practice  including  the
tracking  of waste related information.

Decisions regarding waste management  require a knowledge of chemistry,  safety,
toxicology,  governmental regulations and  the regulatory  process, and  waste
disposal  technology.   Personnel  making these  decisions  should be  trained  to
deal with waste management  issues  and to  identify  and reduce the associated
risks.

Since  the SSWDM  is  a sub-set  of  the  waste management  system,  changes to  the
SSWDM  must be  done  by  qualified  personnel   and  controlled  from a  location
central   to  the  corporation.     The   rationale for  this  is  that  decisions
regarding waste  management  have potential  to produce catastrophic results.

The  waste  data  sheets   provide  a   comprehensive list  of  all  waste  types
generated by the company  and a  mechanism to  address  them.    This is a very
important consideration  for oil and gas  companies that  are now forced  to
exercise  due  diligence in all waste  related  activities.   A company operating
in  the oil and gas  industry can use the waste data  sheets to  effectively
manage their wastes.

The  waste disposal  manual  will  assist' the company  in the identification  and
correction  of any waste  management practice which may  cause adverse effects  on
human  health  or the  environment.    The  manual provides  a  window into  the
company's operations  regarding waste  and how it is handled.   Most importantly,
it provides a mechanism to monitor  waste  management  practice for compliance
with existing laws.
                                       238

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This waste disposal  manual presents  the opportunity  for  companies, operating
in the oil and  gas  industry, to approach  the management  of  their wastes  in  a
systematic manner.   In doing so they  will help to ensure compliance with all
waste  related  legislation  thus  reducing  the  risk  associated  with  waste
handling,  transportation and  disposal.   The  manual  provides  the company's
field personnel  with a  document  which  is focused, easily understandable  and
comprehensive.

It enables environmental  professionals to  summarize  waste related  data  and
present   upper   management  with  meaningful   information   regarding  waste
management problems.
Acknowledgements

The authors  would like  to  thank Mobil Oil  Canada for  it's  financial support
during this project.    Also  they  would  like  to  thank  the  field operating
personnel  who  provided  many practical suggestions and  assistance throughout
this project.
References

1. Canadian Environmental  Protection Act (S.C.  1988, c.22)  (CEPA).

2.  G.   Colin,  Chairman,   CPA  Waste  Management   Subcommittee.     Personal
Communication,  Calgary,  Alberta 1988 - 1989.

3. Canadian Petroleum Association (CPA).  Waste Disposal  Guidelines for the
Petroleum  Industry.    Prepared  by:  Environmental  Planning  and Management
Committee.   Calgary,  Alberta,  1984.

4. Petroleum Association for Conservation of the Canadian Environment  (PACE).
Waste Management Guidelines for Petroleum Refineries and Upgraders.   Prepared
by: Peter T.  Budzik and  Associates Incorporated.  Ottawa, Ontario, 1986.

5. Alberta  Environment.  Alberta User Guide for Waste Managers.  Prepared  by:
Alberta Environment,  1987.

6. P.  Cheremisinoff.   A  Guide  To  Working With Hazardous  Materials.   Pudvan
Publishing  Company,  Illinois,  1987.

7. Alberta  Environment,  1988.   Hazardous Waste  Storage Guidelines.

8. M.  Grossman, WHMIS  -  A Charted Overview.  Canadian  Hazardous   Materials
Management  Magazine Vol.  1,  No. 1,  1987
                                       239

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9. W.M. Glenn, T.M. Sterling, The   Environmental   Managers   Safety   Manual,
First Edition, William M. Glenn, Ontario, 1988.

10. W.M. Glenn, D. Orchard,  T.M.  Sterling,  Hazardous Waste Managers  Handbook,
Fifth Edition, William M. Glenn, Ontario, 1988.

11. Danatec Educational Services, 1985.

12.  American  Petroleum  Institute  (API).    Environmental Guidance  Document
Onshore  Solid Waste  Management  in  Exploration  and Production Operations,
Washington, D.C,  1989.
                                     240

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REVISION DATE:                                 SHEET NUMBER:
NAME OF WASTE:                                    (Synonyms:)
CHEMICAL DATA:
POSSIBLE TOXIC COMPONENTS:

Potential Hazards:
Personal Protection:
STORAGE METHODS:
Handling Precautions:
TRANSPORTATION:

TDGR Identification Number (PIN):
TDGR Classification:
Type of Carrier:
Waybills Required:
Loading & Unloading Precautions:
DISPOSAL GUIDELINES:   (Hazard Classification)

Ideal:
Acceptable:
Alternatives:
Contractor Services Available:
Regulatory Agency Contacts:
ENVIRONMENTAL AND REGULATORY AFFAIRS:
Contact Waste Management Coordinator at:    (XXX) XXX-XXXX
                            Fig.  1 Waste Data' Sheet
                                       241

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THE DEVELOPMENT OF AN OEM CUTTING CLEANER IN THE
NETHERLANDS
L.R.  Henriquez
Chief Inspector of the State Supervision of Mines
of the Ministry of Economic Affairs of the Netherlands
Introduction

Drilling with oil based muds[OEM] can result in a
considerable reduction of drilling time and costs(l),
compared with water based muds[WBM]. However, the big
disadvantage of OEM is the discharge of oil contami-
nated cuttings and the impact on the marine environ-
ment (2) .

On offshore drilling locations in the Netherlands,
discharge of oil contaminated cuttings into the sea
is allowed provided the average oil content[OC] is
below 100 grammes of 1000 grammes of dry cuttings
per section of the well being drilled with OEM.
Monitoring around drilling locations, where in the
past oil contaminated cuttings[OOC] have been dis-
charged, showed a longterai negative effect on the
marine environment(3) .

In order to minimize the above-mentioned effect the
Dutch authorities are stimulating clean technology
to be developed to cope with the problem of OCC. In 1987
the Dutch government decided to support financially a
project for the development of an OEM cutting clea-
ner, having the following objectives:

- to reduce the OC on OCC below 20 grammes per 1000
  grammes of dry cuttings;

- to recover the base oil in such a condition that
  the oil can be re-used;

- to process 3 to 6 tonnes per hour and the unit
  should be applicable offshore:


                       243

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- the discharge of the dried OCC[DOCC], after treat-
  ment by the process should not introduce an extra
  environmental hazard for disposal on- or offshore -

Onshore the Netherlands OCC, having more than 50
grammes of aliphatic oil by dry weight are considered
to be a chemical waste, which has to be treated before
disposal.

This paper comprises results of a longterm onshore
fieldtest with the new development of an OBM cutting
cleaner, which has processed 1200 tonnes of OCC.

OPERATING PRINCIPLE

The operating principle of the OBM cutting cleaner is
as follows[see figure 1]:

From the collecting tank[l] the wet oil contaminated
cuttings[WOCC] are pumped with a hydraulic pump into
the feed screwconveyor[2] of the rotating assembly[3].
The shaft with hammers of the rotating assembly is
driven by a diesel engine[4]. The outside of the ro-
tating assembly wall is heated with thermal oil from
the thermal oilheater[5]. When entering the rotating
assembly, the WOCC are crushed and heated simultaneously
By crushing the cuttings a large area for heat transfer
is created and any water and oil within the cuttings are
released.
The solids are discharged via the discharged screwcon-
veyor[6] at the bottom, while the steam/oil mixture is
discharged via the upper outlet into a cyclone[7].
Any dust taken along with the steam/oil mixture is sepa-
rated in the cyclone, while the vapor is cooled with an
aircooler[8] and collected in a sludge tank[9]. In this
tank three phases, water, sludge and clean oil. can be
distinguished.

RESULTS OF THE CAPACITY-PERFORMANCE TESTS

In order to determine the average capacity of the  OBM
cutting cleaner several bottle-necks had to be overcome.
The major problem during the startup period was to rea-
lize a continuous feed into the rotating assembly.
                       244

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Another  problem was the large amount of large stones or
other  litter present in the WQCC, which often caused the
plugging of  the feedsystem and excesive wear of the ham-
mers.  Due to a too low velocity of the steam/oil vapour
mixture  in the horizontal section of the pipe from the
rotating assembly to the cyclone, solids could settle.
This resulted also in plugging of the horizontal pipe.
After modification of the unit which resulted in solving
the above-mentioned problems the reliability increased
up to 85% and the amount of manpower to operate the unit
went down from 3 to 2 men per 12 hours shift.

The capacity of the unit has been calculated from thermo-
dynamic  properties, which are dependable on the oil- and
watercontent of the WOCC. Official capacity testruns,
held during  the field trial and supervised by an inde-
pendent  consultant, revealed the following capacity-
performance  of the OEM cutting cleaner, as shown in table
1.

                    TABLE 1
Comparison between actual and calculated capacity
Testurns    Oil*   Water*  capacity tonnes/hour
            %      51       calculated   actual
no.
no.
no.
no.
1
2
3
4
9
12
13
11
.1
.3
.0
.7
7
11
13
18
.5
.0
.0
.9
2
1
1
1
.0
.7
.5
.2
2
1
1
1
.14
.14
.5
.1
* content of oil or water by dry weight in WOCC.

The average capacity during the processing of the
whole batch of 1200 tonnes was calculated to be 1.3
tonnes per hour. Oil-, water-content and hammer-wear
are parameters which can have a great influence on the
capacity-performance of the OEM cutting cleaner. These
influences have been established and based on the
studies carried during the pilot testing, proposals for
modifications are being evaluated in order to increase
the capacity of the unit. With these modifications, new
calculations show that it is possible to achieve a ca-
pacity of 3 tonnes per hour.
                      245

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RESULTS OF THE ENVIRONMENTAL-PERFORMANCE TESTS

In 1986 the Dutch authorities instructed the national
working group on clean technology[ĄST]  to study  alter-
native technology to treat OCC. After studying several
alternatives the OEM cutting cleaner has been selected to
have a good potential for a solution for the problem of
oil contaminated cuttings.

The working group WST developed a model to assess the en-
vironmental performance of these technologiesr which has
been named the "black box"-approach. The basic philosophy
of this approach is to screen environmentally the dis-
charges and recovered products resulting from the appli-
cation of these technologies, to get information whether
these discharges can disposed on- and offshore and also,
to assess if the recovered products can be re-used wit-
hout having an extra environmental burden.

Based on the "black box"-approach the following environ-
mental performance parameters have been considered to be
applicable when testing the OEM cutting cleaner:

a. the determination of the massbalance for the solids.
   water and oil in order to evaluate the capacity of the
   process;

b. to determine the influence of certain processparame-
   ters, like energy requirement, the residence time of
   the cuttings, the process temperature and pressure;

c. to analyse the physical-chemical characteristics of
   the wet - and dried(treated) oil contaminated cuttings
   e.g. :
   - oil - and water content;
   - the content of polycyclic aromatics. heavy metals
     and salts;
   - leach out tests in rainy - and seawater for the
     assessment of the disposal on - and offshore;
   - the particle size distribution for the evaluation
     of the spreading mechanism into the marine environ-
     ment ;

d. to analyse the physical-chemical characteristics of
   the recovered base oil e.g.:
   - the determination of the density, flashpoint, the
     kinematic viscosity and the boiling range in order
                         246

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    to compare the  recovered oil with the original base
    oil;
   - GC/MS-fingerprinting  for comparison with the origi-
    nal base oil;
   - the content on  polycyclic aromatics and heavy metals
    for the assessment  of the influence of the process-
    parameters, like  temperature and pressure, on the
    quality of the  recovered oil;

e.  to  determine the  drilling fluid properties of an oil
   based mud made with the recovered base oil by:
   - determination of  the  Theological properties accor-
    ding  to API RP  13B;
   - density, oil/water-ratio, HPHT, etc. according to
    API RP  13B;
   - simulation tests  for  down hole emulsion stability
    of the mud;

f.  to  test the oil based mud made with the recovered oil
   for the marine aquatic  toxicity towards three marine
   organisms(one algae and two Crustacea);

g.  to  test the dried(treated) oil contaminated cuttings
   for the marine sediment toxicity towards a marine
   sediment reworking  organism.

Due to the limited space available for this paper
only the most important-  results will be presented here.

During the fieldtrial  two  different- OBM-cuttings have
been processed, namely cuttings contaminated with OEM
nr. A  and  cuttings contaminated with OBM nr. B, having
different  base oils  as make-up oil in their mudformula-
tions. The complete  analysis as prescribed in the "black
box "-approach has been carried out by an independent
laboratory. Before each  official test-run sampling
strategies have been discussed and agreed upon in order
to  garantee a representative sampling. Table 2 presents
an  overview of the oilcontent on cuttings before and
after  processing by  the  OBM cutting cleaner during
testruns  1 and 2. Field  measurements are results obtained
by  applying the retortprocedure as prescribed by the
Dutch  regulations, while the laboratory applied a Dutch
standard procedure.  As can be noticed a small difference
have been  experienced  between the two procedures.
                      247

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                   TABLE 2
   Results of the oilcontent on cuttings


Sample %
Testrun 1
oil bv dry weiaht
Labresult Field
WOCC(feed)
DOCC{ treated)
9.1 9.5
i.O 1.2
Testrun 2
% oil bv dry weiaht
Labresult Field
12.3 12.7
1.1 1.3
The conclusion of the independent consult and laboratory
is that the OEM cutting cleaner can reduce the oilcontect
on cuttings to approximately 1% by dry weight.

The results of the petrochemical analysis for the recove-
red oil from OBM nr. B is presented in table 3. where
also the comparison of properties is shown with the ori-
ginal base oil Shell Sol DMA.

                  Table 3
Petrochemical properties of the recovered oil compared
with the original base oil

PropertyStandardUnitTestrun 2 Shell Sol DMA
                          Original     Recovered
Flashpoint ASTM D93   °C      98          98

Density    ASTM D1298 kg/1    0.7S78      0.8003
Viscosity  ASTM D445  cst     1.99        2.05
(40°C)

Boiling    ASTM D86   DC     223-269.5   223-275
range
The GC/MS fingerprinting confirms that the recovered oil
is very similar in quality as the original base oil Shell
Sol DMA. In the case of the recovered'oil freak OBM nr^- A,
which is formulated with BP S3 HF  the same results hav*
been experienced.

                       248

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During  the  fieldtrial temperature-changes in the process
of less than  10  degrees C did not have any effect on the
quality of  the recovered oils. This have been verified by
GC/MS-fingerprinting of the recovered oils.

Table 4 presents the concentrations of aromatic hydrocar-
bons, the polycyclic aromatics(PAHs) and the heavy metals
analysed in the  oil, recovered during testrun 2.

                    Table 4
     Aromatics,  PAHs and heavy metals in recovered oil

  Parameter	Unit	Concentration	

Heavy metals:
Cadmium             mg/kg        < 0.1
Chromium              .,           1
Copper                 ,,         < 1
Mercury               ,,         < 0.1*
Hickel                 ..         < 1
Lead                  ,,         < 1
Zinc                  .,         < 1
Arsenic               ,,         < 0.2

Total aromatics      wt %         0.11(0.03)**
PAH's(16 of EPA)     mg/kg          4***

* mercury measured in aqua regia-destruate
** average  result of a three-fold measurement. The con-
   centration in the original Shell Sol DMA has been de-
   termined to be 0.03 wtjt
*** only naphtalene has been detected.

Based on the  results as presented in table 4 the follo-
wing conclusions can be drawn:
- in the recovered oil the concentration of aromatic hy-
  drocarbons  is  found to be slightly higher than the ori-
  ginal base  oil Shell Sol DMA.  Regarding the presence of
  PAH's, only naphtalene has been detected;
- no heavy  metals have been encountered in the recovered
  base  oil.

No explanation has been found why the recovered oil .con-
tains a slightly more aromatic hydrocarbons and naphta-
lene than the original base oil. Therefore it was decided
to check the  emulsitiers, applied in the OEM nr. B for
the presence  of  PAH's. Analysis shows that no PAH's could
be detected in the emulsitiers.


                          249

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Also a GPC-analysis{gelpersaeationchroisatoyraphy} has  been
carried out in order to determine the content of
emulsifiers in the recovered oil. The conclusion is that
due to the small concentrations of these emuisitiers
applied in the OBM-formulations, no eumlsifiers could be
detected.

Disposal characteristics of the OCC before and after
treatment

The disposal characteristics of the OCC are determined by
the chemical composition, the particle size and the lea-
ching properties when the material has to be dumped on-
shore or into the marine environment.

The WOCC as well as the DOCC have been analysed for nine
heavy metals: cadmium, copper, chromium, mercury, nickel,
lead,zinc, arsenic and barium. Besides that also the
PAH's have been analysed in the WOCC.
From the results it is concluded that basically none  of
the heavy metals, except for barium, surpass the refe-
rence concentrations as set by the Dutch government for
disposal onshore and into the marine environment. Onshore
the WOCC is considered to be a chemical waste, based  on
the barium - and oilcontent, while the DOCC is a chemical
waste, based only on the bariumcontent. Also the salt-
content will cause a problem onshore, that's why the
waste material has to be disposed onshore on special  dump
locations. No PAH's have been detected in the WOCC.

The particle size-distribution(2-2000 um) was determined
in the WOCC and the DOCC. The results show that although
more of the smaller particles are expected to be present
in the DOCC than in the WOCC, this appears to be not  the
case for particles of smaller than 63 um. The explanation
for this result is that this could be a consequence of
the analysis due to the treatment of the WOCC prior to
the measurements. Such a experience has also been repor-
ted in the literature(1). From the physical appearance
of the DOCC, which is a powder, it is concluded that  the
spreading in the sea will be enhanced compared to the
sticky material, like the WOCC. Computer modeling of  the
spreading mechanism of these materials into the sea has
confirmed this expectation.
                         250

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For the  determination of the leaching properties of the
waste material the WOCC and the DOCC have been subjected
to two cascade tests; in one case acidified demi-water
(pH at the beginning of the test= 4) has been used as a
leaching medium,  and in the other case artificial sea-
water was used. The tests have been carried out in ac-
cordance with the Dutch standard procedure HVN 25OB.
The leaching liquids have been analysed for:
- 11 heavy metals: cadmium, chromium, copper, nickel,
  lead,  zinc, mercury, arsenic, antimony, barium and
  molybdenum;
- chloride;
- oil.

The results of the cascade tests on the WOCC and the
DOCC indicate that the most components, except for
barium,  chromium, molybdenum and oil, are leached out in
only limited amounts. Oil and molybdenum are more easily
leached  out of the DOCC than out of the WOCC. For barium
and chromium, no difference in leaching behaviour from
both waste material has been noticed. The concentrations
of the heavy metals, which are leached out in artificial
seawater, are below the target-levels as set by the Dutch
government for seawater, except for barium which leach-
out concentration surpasses the background level in the
seawater.

Mudproperties of drilling fluids made with the recovered
base oil

In order to show if the recovered base oil can also be
re-used  as make-up oil for oil based muds, tests to
determine the mudproperties have been carried out accor-
ding to  the standard procedure for field testing dril-
ling fluids, API RP 13B iit-h ed,(1985)J on such a mud.
The mud  made with the recovered base oil has also been
subjected to hot rolling during 16 hours at 120 degrees
C under  the following downhole simulation conditions:
- without any influx;
- with a 10%(w) seawater influx;
- with an influx of 86 grammes per liter MgCl2-fc^O-water-
  solution.
These tests have been carried by a Dutch mudsupplier and
an oilcompany. After interpretation of the results the
main conclusion is that the recovered oil can be re-used
to formulate adequate oil based drilling fluids.


                        251

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The toxicoloqical behaviour of a drilling  fluid based on
the recovered base oil and the treated DOGC

A drilling fluid, based on the recovered oil  and having
the same mudformulation as OEM nr. B, has  been  prepared
for aquatic toxicity testing according to  the Dutch re-
gulations by a government appointed independent labora-
tory. The toxicity of aqueous extracts of  the OEM was
determined for three organisms:
a. the crustacean chaetogammfir-as marinus
b, the brown shrimp (crangon crangon)
c. the marine algea skeletonema costatum.

The results of the aquatic toxicity-tests  have  been
compared with those of the original OEM nr, B and found
to behave similar. When these results are  evaluated
by applying the relative cut-off-values as set  by the
Dutch authorities the OEM nr. B, based on  the recovered
oil, is approved.

A sediment toxicity test- with treated DOCC using the
sediment reworking organism, the heart urchin Echino-
cardium cordatum, has been carried out during a test-
period of 14 days. Although the test method is  still
under development, it is concluded that the DOCC may be
harmful for the heart urchin at 0.32 grammes  per kilo-
grammes dry sand and higher concentrations. Compared with
results of the sediment toxicity tests of  the OEM nr. B.
the DOCC seems to be more toxic. A possible explanation
may be the better leaching behaviour of the oilcomponent
from the DOCC compared with the WOCC, contaminated with
OEM nr. B. The Dutch government intend to  start a new
project to study meso-cosm experiments on  the long-term
behaviour of the DOCC on sedimentary ecosystems gathered
from the Dutch North Sea continental shelf .

CONCLUSIONS

After processing 1200 tonrj^s of OEM Buttings  an OBM
cutting cleaner has been developed with an average
capacity of 1.3 tonnes per hour of wet oil contaminated
cuttings[WOCC]  and achieving a reduction of oil on
cuttings to approximately 1% by dry weight- From the oe-
trochemical analysis and the GC/MS-fingerprints it is*
concluded that the recovered oil is similar to the origi-
nal base oil.


                      252

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Oil based muds  made with the recovered oil show to have
the same stable emulsion - and Theological properties as
the original  mud.  The toxicity results of the mud made
with the recovered base oil has passed the criteria set
by the  Dutch  authorities,  Onshore the DOCC has to foe
disposed on special dumpsites. while for the disposal
offshore more research is needed in order to assess the
impact  on the marine environment. However it is expected
that the longterm impact of the DOCC is less compared to
the discharges  of  the WOCC due to better spreading mecha-
nism and leaching characteristics.

Although the  objective to process 3 to 6 tonnes per hour
has not yet been achieved, the unit can be improved.
After modifications, based on a thermodynamic and me-
chanical evaluation of the results obtained during- the
pilot plant tests, an offshore unit with the capacity to
handle  the amount of cuttings being generated while
drilling a 12 l/4"-hole with OEM is viable within one
year.

             ACKNOWLEDGEMENTS

This project  has been supported by the company Solids
Control Services,  the Dutch organisation of gas & oil
producers{N.O.G.E.F.A.}, the oilcompanies N.A.M. and
Conoco  Netherlands Oil Co. and the Dutch government.

References

1. T.J. Bailey, J.D. Henderson, T.R. Schofield..
   Cost effectiveness of oil-based drilling muds in
   the  UKCS,  SPE 16525,  Offshore Europe 87 Aberdeen.
   8-11 September 1987

2.  F.R. Engelhardt. J.P.  Ray, A.II. Gillam. Drilling
    Waste, Elsevier  Applied  Science-  London and Hew York,
    1989

3. M. Mulder, W.E. Lewis,  M.A. van Arkel, Biological
   effects of the  discharges of contaminated drill -
   cuttings and water-based drilling fluids in the
   North Sea, Dutch government project 1985-5990, The
   Hague 1988
                      253

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                   •Oocc
1.

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DISPOSAL PRACTICES FOR WASTE WATERS FROM COALBED METHANE EXTRACTION IN THE BLACK WARRIOR BASIN,
ALABAMA
D.  Troy Vickers, P. E.
Regional Environmental Coordinator
Amoco Production Company, Houston Region
Houston, Texas, U.S.A.
INTRODUCTION

An emerging industry  has developed in  Central Alabama's Black  Warrior Basin to  recover a
natural resource that until  1980 was considered by the mining  industry to be a dangerous waste
by-product.  An  industry that  can neither be  defined strictly as an oil   and gas production
operation or as a mining operation,  coalbed methane extraction has expanded into the 1990s with
exponential  growth.   It  has  been  estimated  by  the U.S.  Bureau  of Mines  and  the National
Petroleum Council that coal  seams may contain in place gas  reserves of 398 trillion cubic feet
(TCF)(l). The  Black Warrior Basin,  alone, is  estimated to contain in place  reserves of 19.8
ICF(2),  with recoverable reserves approximately  16.0(3).  The  first Alabama coalbed methane
well was permitted in 1980 and  by January 1,  1990,  the industry had permitted  2,068 wells.

Of primary  environmental concern to the  fledgling industry is  disposal of water produced in
association with the methane.   The produced water  ranges  from 'fresh' to  'brackish', but does
not approach the definition  of brine associated with  that  produced by conventional oil and gas
operations.  The water quality is identical to  that from coal seams in the minable depths (less
than 1,500  feet)  and increases in salinity with depth.  Currently primary disposal methods of
produced  water are:  (l) National  Pollutant Discharge  Elimination  System (NPDES)   permitted
stream discharge and (2) land  application by  Industrial Land Application Treatment Permit.

Management of  disposal  of produced  water and non-point source  discharges,  normally associated
with construction, is essential to prevent water quality  degradation.  This paper will present
a case study of  the evolution  of  the coalbed methane extraction industry in the Black Warrior
Basin of Alabama and  one company's approach to  protection of  the  environment  through waste
management and responsible environmental  planning.

BACKGROUND

As the  energy needs  of  the   United  States continue  to  increase  and  the   availability of
conventional domestic  resources continue  to  decline, unconventional  fuel sources that provide-
environmentally clean and economic energy oust be  exploited.   Coalbed gas meets these criteria
and also reduces the necessary required safety  emissions of methane by mining  operations.

Coalbed gas  is present  in  all coalbeds  to  some  extent.  Concentrations  of methane usually
ranges between 80 - 99%.   When these concentrations are mixed  with air to form a mixture of 5
- 15% methane  a highly  explosive vapor  is formed.   This may be  easily ignited  by any spark
                                            255

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caused by mining operations.  In  1969,  Congress recognized the inherent  dangers of coalbed gas
and legislated  the Federal Coal  Mine  Health and Safety  Act which  issued limits  for methane
concentrations  in  mines.   To assure  compliance with these standards  and for  safety aspects,
mining operations included the venting  of coalbed methane  gas  to  the atmosphere with no capture
of these resources.  It is noted,  however,  that the capture and use  of these  gases was studied
in 1953 by the Council of the Organization for European Economic  Cooperation^) and even in the
early 1900's  a minor, scale project  in the Powder River  Basin produced  gas from a water  well
that heated ranch buildings(l).

In 1980, the  National  Petroleum Council concluded that "natural  gas from coal  seams,  Devonian
shale, and tight gas reservoirs could make significant contributions to the United States  gas
supply"(5).   The  United  States  Department of  Energy sponsored  additional study  and  further
defined the coalbed methane  resource potential of the major  coal basins of the United  States.
In addition,  the  Gas  Research Institute  (GRI) published  geologic  assessment  reports on  the
natural gas reserves in various United States coal basins. To date,  the major basins that  are
being developed for coalbed methane production  are  the San Juan Basin  in Southern Colorado  and
Northern New Mexico and the Black Warrior Basin found in West  Central Alabama.

In Alabama,  coalbed methane  production now  contributes  approximately 12% of  the annual  gas
production.   The  increased activity in drilling  presently occurring in  the outlying frontier
areas of existing  production  will soon exceed this  production value(6).  An intense program is
underway to  drill as  many wells as possible by January  1,  1991, which will  qualify a large
amount  of  production  for the  special  tax credit  for unconventional  fuel sources under  the
amended Section 29 of  the Crude Oil Windfall Profits Tax  Act  of  1980.  The production produced
from these wells will  continue  to earn the  tax credit (presently $0.86 per MCF) until the year
2000.

Coalbed methane gas is found  in two  forms in  the coalbeds: (l) free gas found in the fractures
and  fissures  of the  coal, and  (2)  bound gas  which is adsorbed  to the  coal particles.  The
adsorbed gas  accounts  up  to 95% of the methane and  desorbs with  comparatively slow rates over
an extended  period of  time.   The amount of  gas contained in a  particular coalbed seam in a
particular basin depends  on many  factors including  :  (l)  depth of overburden,  (2)  hydrostatic
pressure, (3)  geological  conditions, and (4)  coal rank.   In the Black Warrior Basin, there are
specific stratigraphical  horizons comprised of multiple coal seams  that range  in thickness from
two to  eight  feet.  These are known as the Pratt,  Cobb, Mary Lee/Blue Creek, and  Black Creek
Zones.  Gas  contents of  these coal  seams  range from  200 to 550 standard cubic  feet/ton of
coal(6).

To allow the production of the gas, adsorbed  to the coal particles, it  is necessary to create a
pressure drawdown  which requires  the removal  of the water that naturally occurs in  the  coalbed
fractures and  fissures.   This water  results from migration of surface  waters downward until it
is trapped  by the coal seams or from  water  which was present at the time of deposition  and
stratification  of  the coal beds.  As  the water is removed,  by pumping,  the gas  is  desorbed  from
the coal, and flows into the wellbore.  The  gas and water flows up the tubing-casing  annulus
and tubing, respectively.

ENVIRONMENTAL CONCERN

The disposal  of the produced water is  both a major  environmental and  economic concern.  Water
production rates  vary from  basin to basin,  from coal zone   to  coal zone, from  seam to  seam
                                             256

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within the zone, and even varies to the geographical area within a given coalbed methane field.
Rates upward to  1,000  barrels per day  have been reported in the  Black Warrior Basin.   Just  as
rates vary,  so  does the chemical  composition with variations  from depth to  depth and  area  to
area.   The  major  contaminant of  concern  found in  the  produced  water is  chloride. However,
various trace elements such as iron and manganese are also found in the produced water.

Additional environmental concerns  resulting from coalbed  methane  extraction operations  include
non-point  source  discharges  which  result  primarily  from  run off  and  erosion  of newly
constructed  roads,  pipelines,  and  drilling locations  and  the  multiple  land  use (mining,
silviculture, agriculture and residential)  in and adjacent to the area of operations.

In 1987,  Amoco  Production Company, after achieving  successful  results in the  San Juan Basin,
began an  intensive effort to develop  the coal gas  reserves in the Black Warrior Basin.  This
project involved Amoco alone and in  partnership with  Taurus Exploration,  Inc.  The  area  of
operations  cover  approximately  160,000  acres  located  between  Xuscaloosa  and  Birmingham,
Alabama,  along  the  Black Warrior River  (Fig. l).   The  majority of  the  land  is  forested and
could be  considered semi-wilderness.  The many streams in  the area are tributaries of The Black
Warrior River,  a  controlled  level river  that  is  used for transportation and  electric power
generation  in  addition to  recreation (skiing,  swimming,  boating,  and  fishing).  Early   in
planning,  Amoco recognized  the  potential  impact on  the  environment by  its operations  and
endorsed  a position of  cooperation with  the regulatory  agencies controlling  coalbed methane
operations,  the  Oil and Gas Board  of Alabama (O&GA) and the Alabama Department of Environmental
Management  (ADEM).   A  goal of maintaining the environment in as near to pre-existing conditions
as possible, with the providing  of  improvements where  possible,  while developing the natural
resource  (methane gas) was adopted.

Amoco approached the commingling of the capture of  a  natural  resource with protection  of the
environment by  commissioning studies  by The  University of Alabama,  Auburn University,  and  a
major environmental consulting firm.    Studies identified potential effects on aquatic  species
by NFDES  discharges and general groundwater information,  plant and soil effects by land applied
produced  water  and an overall  view  of  environmental  aspects  of  the  total  project.  The
University  of Alabama  studies,  although  limited in time and scope,  confirmed areas of work
previously  performed(7)  (8)  in  the aquatics  field and added  to  the base of  information for
toxicity  to indigenous species.   With  the  aid of the Geological Survey of Alabama,  an  initial
groundwater assessment  study for Tuscaloosa,  Jefferson,  and portions  of  Walker  Counties,
Alabama was done.   The studies  performed  by Auburn University provided initial  studies upon
produced  water  disposal through land  application and the effects on soil structure  and plant
life, along  with a brief review of  potential  use of  produced  water  in aquaculture.   An
environmental  consulting  firm reviewed the  overall  environmental  aspects  of  the  project,
including  air,  noise, aesthetics, archaeological,  wetland determination,  land use  and other
areas of potential  concern.

This paper will   focus  on  issues  pertaining  to water  quality  maintenance  and   overall
environmental planning.
                                           257

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WATER DISPOSAL

     STREAM DISCHARGE

Stream discharge  of produced waters  is permitted  by NPDES Permit  issued by  the ADEM , under
primacy from the  EPA,  which prescribes effluent limitations for chlorides, iron, manganese and
pH.  Although  coalbed produced water is not technically classified as  brine (>3.5% dissolved
solids), they  are slightly to moderately  saline.   Chloride concentrations  range from 150 mg/1
to 11,000  mg/1.   Iron concentrations range from <0.05 mg/1 to 0.2 mg/l(7),  and pH ranges from
7.3 to 9.0.   There may  be other detectable associated  inorganic constituents  that vary with
area but are not  limited under NPDES  permitting.

In  1982,  studies were  undertaken  by  the ADEN  and  Alabama  Methane  Production Company  in
association with  Dames and Moore to  set effluent  limitations for stream discharge of produced
waters.  Initial  NPDES discharge guidelines were restricted to  500 mg/1  total dissolved solids
(IDS) instream.   The  EPA ultimately moved from "technology based" permitting to toxicity based
requirements  and  cited  numerous  investigations on aquatic species  toxicity  to chlorides(S).
The EPA,  in  establishing an instream chloride  limit, selected data based on acute and  chronic
toxicities for two (2)  species of vertebrae (fathead minnow and rainbow  trout) and  one  (l)
invertebrae  (ceriodaphnia).   The acute values  ranged from 1470  mg/1  to 6570  mg/1.   The final
acute  value  adopted  was 1720 mg/1.   A conservative standard  was  established  at 50% of  the
adopted acute  value (860 mg/1) as the criterion maximum concentration.   (A maximum value not to
be  exceeded  for  more  than one  hour  every three  years,  i.e. an  acute value).   The  final
acute-to-chronic  ratio  for  the  three species  was 7.6.  To  establish a value to protect  the
aquatic species over  their life history, the acute value (1720 mg/1) was divided by  the ratio
thus a value  of  230 mg/1,  i.e. a chronic  value.   This value is a four day average that cannot
be exceeded  more  than once  every three years(9).   The ADEN,  furthermore, established a  7  day
average once every  10 years low flow as a basis for the NPDES Permit, which  resulted  in a more
conservative number.

In June  1989,  the GRI and  the Geological Survey of Alabama (GSA) jointly issued  a 5-year study
of effects of  produced water chlorides on  aquatic species.   This study  concluded that  the  230
mg/1 limit as  established  by the EPA "is sufficient to protect warm water species occurring in
relatively natural  streams"(7) and  "a threshold value of  565 mg/1 was determined below which no
significant change of  macro invertebrate community was observed"(7).

Due to potential  for variation of produced water and  the  interaction with insitu stream waters,
The University of Alabama,  Department of  Mineral Engineering and  Department of Biology,  was
commissioned  to  study the  effects  of produced water on-site of the  Amoco project area.   The
study  was  conducted during  the  Summer of  1989 with results  confirming  those of the GRI/GSA.
Effects on total  macro-invertebrate taxa and taxonomic richness  from The University of  Alabama
study  are  shown  in Figures 2  and 3, respectively.   Corresponding chloride  concentrations  for
effluent and instream are  found in Figures 4 and 5.  As the instream chloride concentration at
Shoal Creek increased, a decrease of  total macro invertebrate  taxa was seen.  However, this  was
not experienced at the Fox Creek Test Site.   It is apparent that the decrease in total taxa  was
not completely dependent upon  chloride concentration, but may have been  influenced by instrean
components and subsequent  mixtures.   At neither  site was taxonomic richness  (total species)
affected by chloride  instream concentrations.

Acute  toxicity testing yielded results similar to those  of the GRI/GSA  long term studies(lO).
However, an area  identified by The University  of  Alabama as a potential major concern  was  the

                                              256

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interaction of low dissolved oxygen content and high chloride  concentration with the effect on
species.   Although no direct correlation was  identified, it appeared that this  interaction may
have  resulted  in  data that  was  inconsistent.   This  interaction  may possibly  be  a  source
identified by O'Neil, et al(7) to have also yielded inconsistencies during toxicity testing.

Stream  discharge  is  accomplished by collection of  produced water  from individual  wells to  a
central treatment facility.  This  facility  normally consists of two ponds,  each with a  10,000
barrel capacity that are lined with a one-piece polyethylene  liner.  The ponds are designed to
allow for  aeration  in  the  receiving  pond  and—also  provide  retention  time  to  allow  for
flocculation and settlement of iron and  manganese.  The flow continues into the second pond by
gravity flow.   The  volume discharged  is  metered.   The  discharge  occurs  through  a diffuser
placed  parallel  and  upstream to  the stream flow.   Wet  chemistry monitoring and  analysis  is
performed weekly on criteria required by the NPDES Permit and  at more  frequent intervals as is
dictated by stream conditions.

LAND  APPLICATION

Land  Application of all types of waste waters  has  been used throughout the country with various
results.   In Land Application  a specific  form of  the effluent,  either partially  treated  or
untreated,  is released  at  specified  times  onto  designated  land  area.   Some waste  supply
nutrients  to the covering vegetation.   However,  chlorides provide  no nutrient value  and  may
cause an  upset  to  the osmotic  balance  and  result   in a  growth  decrease or  death of  the
vegetation.   Additionally, application of water over  an extended period of  time to a specific
area may result  in loss of vegetation due  to  oxygen reduction.  Also,  chlorides may alter  the
soil  chemistry resulting in an unstable  soil that  is unable to support vegetation.

Since very little  information  on  land  application of coalbed  produced water  was  available,
Auburn University was commissioned  to  study  the  effects resulting  from land application(ll).
The study consisted  of three (3) phases:   (l) on-site investigation of sites under short term
application and  long  term application,  (2) greenhouse  studies of  plant effects by produced
water application, and (3) soil chemistry changes  by produced water.

The on-site investigation  of two land application  sites No. 139 (discharging for two years)  and
No.  64  (discharging  for  six months) was  conducted to  determine  litter  and plant elemental
concentrations (Fig.  6).   Water application rates were initially 400 barrels per day (BPD)  and
308 BPD,  respectively and  had declined to 21 BPD and 116  BPD,  respectively.  In addition, Site
No.  151 was used as  a natural revegetation study site.   Initially all vegetation  within  the
treatment  area was dead  (24 hour  continuous application at  >149  BPD).   Within 2.5 months after
stoppage,  the area had revegetated  without  remediation.

Greenhouse studies were conducted  to determine the effects  of  (l)  chlorides upon plant yields,
(2)  effects of  water application  management  and  (3)  effects  on new  plant growth  on  soils
previously irrigated with produced  water.   Three studies were  conducted  utilizing sorgham
sundangrass and produced water at various concentrations of chlorides.   One study was performed
utilizing  continuous irrigation  and  intermittent  irrigation with  two harvest (Fig.  7),  an
additional  study performed using soils that had previously been irrigated  with produced water
utilizing  various  irrigation treatments and only  one harvest  (Fig.  8) and  one  study of plant
recovery response  with soils previously  irrigated continuously with various concentrations  of
produced water (Fig. 9).
                                              259

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Results  of  the  study   indicated  that  produced  water  containing  up  to  1100  mg/1  IDS
(approximately 450 ng/1) may improve plant growth if the irrigation system is properly managed.
Additionally, plant response depends not only upon salinity but the  length of time the soil is
saturated with water.  No exact threshold  IDS was established for plant growth.  However, under
all methods of irrigation plant growth will begin to decrease at ± 1280 to 2560 mg/1 IDS and a
greater reduction was  found for continuously saturated soils.  Soil  structure was studied for
effects by  produced water  by  evaluating  the chemical equilibrium  between produced  water and
soil  absorption  and the  adsorption capacity of  the  soil.  Equilibrium Ion  Exchange  testing
indicated that no salt buildup was occurring on sites with applied water containing IDS levels
of 2800 mg/1 or less (1,700 mg/1 chloride).   It  is reasoned that applied water will leach salts
when  applied in excess of plant uptake and water holding capacity.

Soil-water  interactions  were further  studied   using  a  vacuum  extractor  to  determine  the
equilibrium between soil  and produced  water with a IDS content of 2800  mg/1.   The results show
that  the  cation exchange sites of the soil  are nearly saturated with  Na  after  one (l)  soil
volume of applied  water leaches through.   This  would equate to  16"  of  water applied per unit
area  on  soils  with a depth of 20" (with 20% rock fragments).   (Fig.+10).  Correction of  this
was  additionally  studied  and results yield that  only  60%  of  Na  was  removed  with  the
application equivalent of 320" of  distilled water per  unit  area.  However, water saturated  with
gypsum displaced  essentially  all  Na  with the  equivalent of  64"  of solution per unit area.
(Fig. 11).  However,  only 1/2 column  volume  (approximately two (2) pore  volumes)  of  distilled
water was necessary to return the soil the  low hazard  range of conductivity for  plant growth
(Fig. 12).

Due to  the amounts of  water  being applied at rates  of  l"-2" per day/unit area, it would be
necessary to move the  irrigation  system on a regular schedule of 2 weeks  or a system  regulated
to  be off  for  a 48  -  72  hour  interval between  applications.   This was verified with field
observations.

From  the research done by Auburn University,  it  was apparent  that neither the  soil structure or
the native vegetation would be severely impacted on a long term basis after application ended.
However,  it was  determined  that  neither the  soil  nor  the  plant  uptake of  chlorides  was
sufficient to significantly limit  the  chlorides  from being  leached through the soil.

A preliminary assessment  of groundwater was undertaken for Jefferson, Tuscaloosa and  a portion
of  Walker Counties,  Alabama,  by  the  Geological  Survey  of Alabama in  cooperation  with  the
University of Alabama.  This  assessment identified the  extent of groundwater in  this area  and
to  a  limited  extent water  quality.  It was  shown that the major  source of useable water  for
this  area could be  classified  as  groundwater with the major recharge  being from surface waters
and rainfall(ll).

CURRENT STATUS

To  provide additional  control  of  water  quality, Amoco  was  an active participant  in  the
development of  a unique  industry monitoring system installed  on the  Black  Warrior River by
Warrior  Basin  Environmental Cooperative,  Inc.  (WEBCl).   WEBCI  was   formed by eleven  coalbed
methane  development companies to  monitor  the Black Warrior  River,  draining some  4,000 square
miles, for  flow and  chlorides to  assure  maintenance of water quality well  below the limits
established by the Safe Drinking Water Act.
                                               260

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Die  alternative of disposal  through underground  injection was studied  by Amoco and others  for
this area.  Geological information  in  the area concluded that no suitable strata was
available for injection of produced water.   In review of the River Gas Corporation's Blue  Creek
Coal Degasification field adjacent  to  Amoco's Oak Grove Field,  Joiner concluded "geologically,
that there is no suitable subsurface disposal zone in the vicinity of this field"  (13).

A major  concern  that until  recently  was   only  minimally addressed was  non-point  source
pollution.  Non-point source  pollution  in  this area consists primarily of  sedimentation  in
storm runoff (erosion).  Due to the necessary construction of roads, well sites, pipelines,  and
rugged  terrain,  erosion  is  induced   during  normal  rainfall.    To control   this  source   of
pollution,  it  is  necessary  to develop  a  'Best Management Practices  Plan1  which  details   an
approach  to erosion control and  construction techniques.   By doing so contractors  and others
involved  in  the  installation and maintenance  of   facilities  become directly  involved   in
accomplishing the control of pollution.

This type of plan should include (l)  criteria for siting roads,  pipelines and well  pads;  (2)
erosion measures  - hay bales, silt fences,  rip rap,  stream side management  zones,  mulching,
etc. (3)  construction techniques  -  slope controls,  terracing, wing ditches, diversion barriers,
etc. In  addition, this plan details stream  crossings for pipelines and roads.

Amoco and  other  operators  have established  an industry  organization,   the   Coalbed  Methane
Association of Alabama  (CMAA).  This  organization  provides  industry input   into  regulation
development and  provides  a  convenient avenue  for  transfer  of  technology,  information,
methodology and regulation.

The combination of  the studies performed indicated that the better environmental  control could
be performed utilizing the NPDES  permitted stream discharge.  This system allows for monitoring
of  effluent  and  downstream  concentration  of  contaminants  for  management  judgements  of
environmental concerns.   Also, additional scientific studies have been performed  that further
defined the toxicity  limits  of freshwater organisms  to chlorides.   To perform  land application
for an  extended period of time,  it would be  necessary to perform a site  specific groundwater
study to  predict and  monitor for  potential chloride contamination.

Exploitation of  natural  resources  is  necessary for  the  continued development  of  industry and
life styles as  expected by citizens  of the  United States.   However, this  exploitation cannot
exist with  exploitation  of  the  environment.  As  projects  are approached,  evaluation  of
environmental impacts on  and by the project  are necessary.   The resulting  management  plan may
include some of the -items discussed,  but should  not be  limited to these.  As the  project  is
undertaken and  development begins,  it is necessary to continue to evaluate the effects  on the
environment and  be willing to alter the course.  These changes may result in  higher  costs  to
the project, although in some  instances  the change may result in a positive economic impact.

Through proper management of the  project and the generation and disposal  of waste, development
can proceed without damage to  the environment.

AGKMOWT.FnGEMENTS

Dr.  Steve Marinello for review and  figure preparation.
Mr.  Greg  Ulrich for review.
Ms.  Te  Weber for many redrafts.


                                             261

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REFERENCES

1.  C. T.  Rightmire,  G. E. Eddy,  J.  N. Kirr, Coalbed  Methane Resources of  the United States,
American Association of Petroleum  Geologists.  Studies in Geology Series *17. 1984.

2.  K. S.  McFall, D.  E. Wicks, V. A. Kooskraa,  A Geologic Assessment of Natural Gas from Coal
Seams in The Warrior Basin. Alabama;  Topical  Report. Gas Research Institute, GRI 8610272.

3.  SOHED, Department of Energy,  The Development Potential of  Coalbed Methane  in  The Warrior
Coal Basin of Alabama. Contract No. DE-AG21-82 MC 19334,  July  1984.

4.   H.  von  Schonfeldt,  Joint  Development  in  The Appalachian Basin.  Eastern  Mineral Law
Foundation Syposium, Nashville, November 1989.

5.   J.  F.  Bookout,   Unconventional Gas  Sources . Vols.  I-V,  National   Petroleum  Council,
Washington, D.C., December 1980.

6.  K. Stremel, "Alabama Coalbeds", Oil and  Gas  Investor. Vol.  9, No.  9, April  1990.

7.  P. E.  O'Neil, S.  C.  Harris,  M. F. Metter, Biomonitoring of A Produced Water Discharge from
the  Cedar Cove Deeasif ication Field.  Alabama.  Geological Survey of  Alabama/ GRI Contract No.
5084-253-1019, Tuscaloosa, Alabama, 1989.
8.  T.  E.  Simpson, The Effects  of Coalbed Me^hanp Produced  Waters on Biol
Eastern Mineral Law Foundation Symposium, Nashville, November,  1989.
9.  S. L. Graves, Regulatory  Rationale for In~Strpain Di
                                                                 of Produced Water from Coalbed
Methane Wells. Coal Gas Seminar, St. Louis, June 1989.

10.   S. A. Marinello, J. F. Scheiring, R. D. Hood, C. Teare-Ketter, Evaluation of  the Potential
Effects  of Coalbed  Methane Well  Produced  Waters on  Aquatic  Organisms in  the  Black Warrior
Drainage Basin. June 1990,  (Unpublished).

11.   G. L.  Mullins,  B.  F. Hajek,  An Investigation of  the Potential Environmental Effects from
the Land Application of Water. Produced from Coal-Rod Methane Wells In Jefferson and Tuscaloosa
Counties. Alabama. December 1990,  (Unpublished).

12.   J.  A.  Hunter, P.  H.  Moser,  Groundwater  Assessment  in  Tuscaloosa  County.  Alabama.
Geological Survey of Alabama, Tuscaloosa, Alabama, 1989,  (Unpublished).

12b.   J.  A.  Hunter,  P.  H.  Moser,  Ground-water  Assessment  in Jefferson  County.  Alafo"1".
Geological Survey of Alabama, Tuscaloosa, Alabama, 1989,  (Unpublished).

12c.   J.  A.  Hunter,  Ground-water  Assessment  in  a   Part   of  the  White  Oak Creek Coal
Degas if ication  Field  in  Southern Walker  County.  ,*i «>"•",   Geological  Survey  of  Alabama,
Tuscaloosa, Alabama, 1989,  (Unpublished).

13.   T. J.  Joiner, Affidavit, Leaf, Inc. vs. The River  Gas Corporation, U. S. District  Court,
Middle District of Alabama, Northern District, Civil Action No. CA 89-H-263-N, June 1989.
                                              262

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                                  (**
              White Oak Creek
                     Field
Tuscaloosa
                                                                              Birmingham
                                  Area of Operations
                                         Figure  1
                   B Fo«Cn.k,.tovePOD
                   B FoiC»ei.belo»POD
                   B SbMlCnek.ib»eFOD
                   Q

Figure
       yu/n
2 • Tolil Macro-inverKbrilc Tiu Collected, Primary Sites
          after Mirlnello el al. (10)
                                                   :
                                                                       *. Foi Cnck, above POD
                                                                       I. Fo«Cn.k,belo»POD

                                                                       >, Shoil Cnck. ibove POD
                                                                       «. Sbo«l Ovk. below POD
                                                            Figure 3 • Tanonomlc Richness, Primary Sites
                                                                    after Marinello et al. (10)
                                          263

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800
600
                                                                       300
                                                                    c
                                                                    g
                                                                    v
                                                                    g
                                                                   a
                                                                      200
                                                                   1   100-
          6/1  6/9  6/16 6/13 6/30  7/7  7/14 7/21 7/28  V«  S/U  W»
                          Sampling Date
          Figure 4 - Shoal Creek  Chloride Concentration*,
                      after Marlnello el aL (10)
                         6/2   60  6/16 6/23  6/30  7/7  7/14  7/21 7/21  I/t 1/11  I/It
                                            Sampling Date
                            Figure  5 -  Fox Creek  Chloride  Concentrations,
                                        •Her Marlnello el at (10)
                                  Figure 6 - Chemical analysis of vegetation samples Site No. 64,
                                                     after Mullins, ci al (11)
      Area     Sample Type
                                  Ca      K
Mg
                       Cu
                                                                                   Fe
                                                                                              Mn
                                                     Zn
    Chemical analysis of vegetation samples Site No. 139
Na
e/Ke
Control1
Treated2
Control
Treated
Grass
Grass
Surface Litter
Surface Litter
3.5
4.0
7.51
13.9
5.1 '
2.8
0.7
0.6
2.5 '
0.9
1.3 '
2.2
0.9 '
1.9
0.5 *
0.8
6*
15
8"
14
95 •
17725
1230 •
8490
mg/Kg
331 V
695
860 b
1169

	 17 '
37
42'
62

323*
8287
157'
8970
Control
Treated
Control
Treated
Control
Treated
Control
Treated
Control
Treated
Dogwood
Dogwood
Hickory
Hickory
Oak
Oak
Surface Litter3
Surface Litter
Honeysuckle
Honeysuckle
20.9
12.2
20.9
6.9
15.9
8.2
21.0
19.8
18.2
5.0
8.5
6.4
8.7
10.4
7.2
7.3
1.3
1.1
22.6
19.1
3.2
2.5
4.6
2.9
1.5
1.9
2.1
2.0
6.7
2.6
0.8
0.9
1.4
1.2
0.9
0.8
0.8 •
1.1
1.4
1.7
4
4
11
9
6
6
11 '
22
5
7
91
96
106
100
87
51
3818 '
9449
101
78
22
16
583
427
255
211
1255 '
976
239
59
4
4
63
21
6
14
66*
62
27
10
100
190
250
540
240
210
410'
9087
125
13795
    'Control = areas at locations that had not been affected by produced water.
    ^Treated = areas at same location that had received produced water.
    'Surface litter was the only sample type where enough subsamples were collected for statistical analysis.
    "Control area is significantly different from the treated area al the 0.05 level of probability.
    ''Control area is significantly different from treated area at the 0.10 level of probability.
                                                         264

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                                                                             12 i
                                                                             10
                                                                         I

                                                                         a
                                                                          S,  «-!
                                                                         I
                                                                             2-
                                                                                                    14 Dv/t, Cominuoui
                                                                                                    28 D*y«, Continuous
                                                                                                    14 Diyi. Inennincnt
                                                                                                    28 D«yi, Inrnninent
                                                                                                                                          8000
N3
                                                              0             2000           4000           6000
                                                                               Total Dissolved  Solids,  mg/L
                                                                 Figure 7  - EtTccI of Irrigation Method  on Forige Yield,
                                                              14 D»j Intern! Hir»«ti with  Varloui Wileri  (First Study)
                                                                                   •ner Mullliu el *L (11)
                      30
|
a
                  >•
                       20
                       10
                                                            Coolimiouj brifUicn
                                                            bteiminent Imjition
                                                            Field C«p«aly Imfition
                                                                                                                                   15
                                                                                                                               S
                                                                                                                                   10-
                                   1000
                                                                           5000
                                             2000      3O»      4000
                                           ToUl  Dlnolvcd Solid],  mg/L
                                          Figure 8 - 30-Day  Forage Yleldj
                          for Varloui  Irrigation Method!  and  Watere, Single Harvest
                                              •Her Mulllni el «l. (11)
                                                                                     6000
                                                                                                                             •	1	•	—I	•	1	•	
                                                                                                                     0             2000            4000           6000            8000
                                                                                                                                      ToUl Dissolved Solids,  mg/1
                                                                                                                 Figure  9 • Forage Recovery Response of  Soils,  Harvest at 30  Days
                                                                                                                         (after 28  Day Pre-treatment with Continuous Irrigation)
                                                                                                                                          after Mulllns et al.  (11)

-------
                                                       1.0-
                                                   I
0.9-
                                                 1 1
0.7 -\
                                                      0.6 H
                                                      0.5-
                                                                         246

                                                                           VolMM (4«% dllalloa)/Soll  Volant
                                                          Figure  1* - RelitlTt Effluent  ConductlTlty,  Site  59 Soil

                                                                             •flcr Mulllni et aL (11)
1.2-
1.0-
0.8 H
0.8 A
0.4-
                 Pnaba LetdxA, DiftUla) Wnr

                 Betim Luched, SMuraied Oypnm Sohrtioo
0.2-
                                                                                                          2.0
                                                                                                          1.5 H
                                                                                                     2"   1.0

                                                                                                     >
                                                                                                     c
                                                                                                     o
                                                                                                     u
                                                                                                          0.5 H
                                                              100
                          Colurax Volimci


          Figure 11 - Fraction N»   Leeched, Site 151 Soil

                        •Her Mullliu et •!. (11)
                                                                                                          0.0
                                                                                                                                                        MeditmHaanlRai|B

                                                                      246

                                                                    Volume Soil/Volume Dblllled Water


                                                           Figure 12  -  Leachate  Conductivity, Site 151 Soil

                                                                          after Mulllni et al. (11)

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DRILLING  WASTE  LANDSPREADING   FIELD TRIAL IN THE COLD LAKE  HEAVY  OIL  REGION,
ALBERTA, CANADA
T.M. Macyk, F.I. Nikiforuk
Environmental Research  and  Engineering Department
Alberta Research Council
P.O. Box 8330,  Station  F
Edmonton, Alberta,  Canada
O.K.  Weiss
ESSO  Resources  Canada  Limited
3535  -  Research Road  N.W.
Calgary,  Alberta,  Canada
Introduction

Drilling  associated  with  the  oil  industry  generates  wastes  that  must  be
disposed  of   in  an  environmentally  safe manner.  Drilling  in  the  Cold. Lake
region  of Alberta,  Canada  generates  a number of different  types  of wastes
dominated  by  freshwater  gel  wastes and potassium chloride  (KC1) and sodium
chloride  (Nad)  types  to  a  lesser  extent.    Landspreading  is one of  the
disposal  options   available and loading rate guidelines have  been established
by the Alberta Energy Resources Conservation Board (7).

The  Alberta   Research  Council  has  conducted  research   into  sampling  and
characterization  strategies  to  characterize major drilling  waste types on a
province  wide basis.  Greenhouse work has been conducted  to assess the impact
of  these  wastes  on soils and plants.  Field studies  designed  to validate  and
calibrate the greenhouse results were seen as the next  step  required  to assist
in defining maximum or tolerable loading on the basis  of waste  type.

As  a result  a joint program was developed by the Alberta  Research Council  and
ESSO  Resources  Canada  Limited and undertaken in the  Cold  Lake  area in 1988.
This paper describes the results of the research conducted in  1988 and  1989.

Objective

The objective of the experiment is to identify the impact  of different  loading
rates of KC1, NaCl, and freshwater gel drilling wastes  landspread on  Luvisolic
(Cryoboralf)   soils  commonly  occurring   in  the Cold  Lake  region of Alberta.
Emphasis was  placed on determining maximum tolerable  loading rates.
                                     267

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Materials and Methods

Experimental plot establishment

The  plot  site  ultimately  selected  for  the  experiment was characterized by a
commonly occurring Luvisolic  (Cryoboralf)  soil  within the ESSO Cold Lake lease
area  and  also  a  significant   portion   of   northern  Alberta.    Plot  site
preparation  included cleanup  of  the area  and  plot  staking.

All  plots   were  sampled  prior   to   waste   application  to  provide baseline
information  so  that   comparisons  could  be  made  to the results of subsequent
sampling  events.   A  composite  sample from five-sample locations was obtained
for  the  0  to  15 cm  depth  interval  at each  of the plots.  Additional samples
were  obtained   from   the  15 to 30 cm,  30  to  60 cm, and 60 to 90 cm depth
intervals at some of the plots.

All  plots   were  rototilled   and then the wastes  were applied.  The waste  wa§
removed  from  the respective sumps by a  large  backhoe and loaded into a 11  m
cement   truck.    The   cement mixer   was  constantly revolving as the loading
proceeded   so  that  the   material  was  thoroughly mixed.  When the truck  was
filled  a sample  was removed  for  analytical purposes.'

The  waste  was spread  by pail to maintain  uniform  application rates at each  of
the  plots.  Barrels having  a 200 L capacity  were  used for unloading the waste
from  the   truck  and  10 and  20  L pails were  then  utilized for spreading.   The
maximum rates   of  freshwater  gel   required  the application of 200 pails  of
waste.    Some raking  was  required to maximize  uniformity and to get the waste
materials to the extreme margins  of the plots.   On the other hand extreme care
was. required  in spreading the relatively  small volumes of 40 L per plot.   The
resulting experimental design is  illustrated  in Fig. 1.

Following waste  application  the  materials  were  incorporated into the top 15  cm
of  the soil  utilizing a  tractor mounted  rototiller unit.  For the freshwater
gel  plots   receiving   the higher application rates some time was left between
passes  or cultivations to  allow  for some  drying to occur.

All plots were seeded  during  the period July  11 and 12, 1988.  Brome grass  was
hand broadcast at the  rate of 75 kg/ha and 300  kg/ha of 16-20-0 fertilizer  was
applied.     The  plots were  hand raked to incorporate the seed and fertilizer
 into the soi1  surface.

Soil  sampling   and selected  tissue sampling  was completed in mid-September  of
1988.    Each  plot had soil  samples taken  in  the 0 to 15 cm interval.  In some
plots   a composite sample  of  five locations was obtained and in selected plots
10   individual   samples were collected to assess  the degree of variability of
the  chemical  parameters.    Sampling of the  15  to 30 cm, 30 to 45 cm, 45  to
60  cm,   and 60  to 90  cm  intervals was also  completed in several plots.  Plant
tissue   was collected from  each of the freshwater gel amended plots and 12  of
the  KC1  and  NaCl amended plots. Vegetation cover on the remaining plots  was
not adequate to  obtain an  appropriate sample.
                                      266

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KCI/NaCI
 Gel
              KCI
  Treatment
      1 • Control
      2 • Minimum application rate
      3 • Application rate >Trt.2
      4 - Application rate >Trt.3
      5 • Maximum application rate
                                                          5m
                                                                                         i
                                                                                          in
                                                                                         T
        Freshwater gel
Treatment
    1 - Control
    2 - Minimum application rate
    3 - Application rate >Trt.2
    4 - Application rate >Trt.3
    5 - Maximum application rate
              NaCI
  Treatment
     6 • Control
     7 - Minimum application rate
     8 - Application rate >Trt.7
     9 - Application rate > Trt.8
     10 - Maximum application rate
Figure 1. Schematic diagram of experimental design.
                                           269

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In  1989  tissue samples were  collected  in the latter part of June at the time
of  plot  harvest for yield determination.  Tissue material was collected from
several  locations  within  each   plot   and  the  samples  transported  to the
laboratory in paper bags, and  dried  at  70  C for 24 hours prior to grinding and
analysis.

The harvesting was done by use of  a  lawn mower so that all plant material from
each  plot could be removed.   Harvesting the entire plot removed any bias from
randomly  selecting smaller unit areas  within each plot and the use of a mower
set  at a given height ensured, to the  greatest extent possible, uniformity in
harvest.

All  material  from  each  plot  was weighed to determine the fresh weight.  A
subsample of this fresh material was weighed and transported to the laboratory
for drying so that a dry weight could be determined for each plot.

Soil  sampling was completed  in mid-August of 1989.  Samples were collected  in
the same manner as done  in 1988 to allow for comparison of results.

Methods of analysis

Water   content  of sump  solid  samples was  calculated after drying at  105 C for
24  hours,   pH was measured  in a paste  (6) and in a 2:1 slurry of 0.01  M CaCl2
(17).    Total  carbon   content  was measured with a LECO CR12 carbon analyser
(11),   CaCO, equivalent  by acid dissolution (4) and acid neutralizing capacity
by  addition  of 0.5 M HC1, and back titration with 0.25 M NaOH (methods 1.004
and   1.005   (3).    Saturated   pastes were prepared according to the  USDA Soil
Salinity  Laboratory method  (20;  18); were extracted and the extracts filtered
through  a   0.45 mm  filter   and   analysed  for  pH,  electrical conductivity,
alkalinity,  chloride,  and for  soluble salts (Na, K, Ca, Al, Cr, Fe,  V,  Ti, Cd,
Cu,   Pb, Zn, Mn, Mg, Li, Sr,  B, Ba,  P,  S,  Mo, Ni, Se, As, Co, Si) using an ARL
model    3400    simultaneous    Inductively    Coupled   Plasma  Atomic   Emission
Spectrometer   (ICP-AES).    Cation  exchange  capacity  (CEC)  and  extractable
cations  of  the sump solid samples were  determined by extraction with a normal
(1 M  at  pH 7.0) ammonium acetate  solution  (10), where NH4 ions were determined
by  a   Tecator  Kjeltec  Auto  1030  Analyser distillation and titration unit and
the   exchangeable   ions  by   the  ICP-AES.   The particle size analysis was done
using  a  simplified hydrometer  method (9).

DTPA-NH  HCO    extractable  elements  (Fe, Cd, Cu, Pb, Zn, Mn, Ca, Mg,  Na, K,  B,
P, Mo,  Ni, Se)  were determined by  the method of Soltanpour and Workman (19).
Total   elemental analysis of  the  solid  sump samples was done by digestion in a
CEM   microwave  digestion  system.    The   procedure  used included ashing the
material  overnight   in  a 425 C muffle furnace, digestion in a teflon bomb, in
the   microwave  oven   with 1.5 mL  HN03,  4.5 mL HC1, and 10 mL HF for 10 min  at
100%   power,   20 min   at  50%  power,  and 10 min at 100% power.  The digested
solutions  were transferred  and made up with saturated H.BO. to 50 mL,  and the
metal   concentrations  measured using ICP-AES.  Minerals were identified in the
sump  solid samples using a Phillips  X-ray  diffraction (XRD) instrument.
                                     270

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Oil  content in the samples was measured  gravimetrically by soxhlet extraction
with  methylene chloride (16).  The methylene  chloride extracts were separated
into  acid,  base  and  neutral  fractions  by  extracting with HC1 or NaOH, and
submitted for analysis by gas chromatography mass  spectroscopy (GC-MS).

The  grass samples were digested with  a concentrated HN03 - HC10  acid mixture
in a  teflon  bomb  heated in a CEM microwave digestion unit ana the solution
concentration  of  Al, Fe, Zn, Mn, Ca, Mg,  Na, K,  Sr,  P, Ba, Mo, B, S, Si, and
As measured  by  ICP-AES and Cd and Pb by  graphite furnace atomic absorption.
Chloride  content was determined by the sodium nitrate extraction procedure of
Gaines et al. (8).

Results and Discussion

Data  pertinent  to the properties of  the soils prior  to waste application and
subsequent to waste application were reported  by Macyk et al. (13).

The  plot treatments  illustrated  in Fig.  1  represent various application rates
of waste  based  on  chloride concentration.   Initially, the objective of the
experiment was to apply O(control), 450 kg  Cl/ha,  900  kg Cl/ha, 1800 kg Cl/ha,
and  3600  kg Cl/ha.   It was  not possible to achieve the suggested rates using
the  freshwater  gel  because  of  its  low chloride content relative to the other
waste  types.    Levels very  close to  the target values were achieved with the
use  of   the  KC1  and  NaCl  materials.   Table 1  provides the chloride levels
applied for each of the treatments.
                                    TABLE 1
                         Waste  application treatments
       Treatment
Chloride addition (kg Cl/ha)
       Freshwater  gel  1
       Freshwater  gel  2
       Freshwater  gel  3
       Freshwater  gel  4
       Freshwater  gel  5

       KC1  1
       KC1  2
       KC1  3
       KC1  4
       KC1  5

       NaCl 6
       NaCl 7
       NaCl 8
       NaCl 9
       NaCl 10
               0
              15
              30
              60
             120

               0
             500
            1000
            2000
            4000

               0
             350
             700
            1400
            2800
                                      271

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Plot yield

Observations relative to the brome  grass  growth  on the various plot treatments
were made throughout the growing  season.   The  freshwater gel  treated plots  had
the best growth overall with the  FW 2  and  FW 3 treatments having better growth
than  the  FW 1  (control)  treatment.     The  FW 4 and FW 5 treatments had  the
poorest growth and appeared the most pale  green  or chlorotic  in color.
Germination  appeared  to  be  affected by the application of the KC1  and NaCI
waste  materials,  particularly the KC1 5  and  NaCI 10 treatments.  These plots
contained  far  fewer plants than plots with  lower application rates,  however,
the  plants  present  appeared  much   larger and mature than  the plants in  the
other treatments.

Table  2  provides  a  comparison  of  the  mean yield  values for the treatments
within  each  waste  type.  There were apparent  differences but no significant
differences  in yield between the  treatments for  each  of the waste types.

For  each  of the waste treatment types the yield obtained for the lower waste
application  rates  exceeded  the  yields   obtained  in the respective control
treatments.    Rates 2  and  3 for  the freshwater gel  plots and the NaCI plots
exceeded  the  control  yield.    The KC1  rate  2  treatment exceeded the control
yield value.  For each of  the waste types  the  maximum application rate
                                  TABLE  2
       Comparison  of  the  mean  yield  values  for  the  field  trial  plots
Waste
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
KC1
KC1
KC1
KC1
KC1
NaCI
NaCI
NaCI
NaCI
NaCI
Rate
1
2
3
4
5
1
2
3
4
5
6
7
8
9
10
N
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Yield
(9)
5750a
7660a
5850a
4230a
2780a
2240a
2680a
1870a
1630a
1380a
2740a
2800a
3010a
2280a
1090a
         Treatment  means of each waste in  any one column not followed by
         a common  letter are significantly different at 0.01 probability
         by Tukey's Studentized Range (HSD) Test.
                                     272

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resulted  in the  lowest yield.   Similar trends were observed  relative  to  yield
of   brome grass grown  in  freshwater  gel, KC1, and NaCl waste  and  soil  mixtures
in  the greenhouse  (14).

Field plot soil properties

A  total  of  77   soil  samples   were collected at the 45 plots prior  to  waste
application and 207  samples  were collected in mid-September 1988  approximately
two months  following  waste   application and incorporation  (13).  A  total  of
207 samples were  collected  in  mid-August 1989.

The  samples  obtained  in 1988 were  analysed for several chemical and  physical
properties,  soluble  ions   in saturated paste extracts, plant available  trace
elements   (DTPA   extractable),  and  total elemental content (13).  The  samples
obtained  in  1989  were  analysed for some chemical properties as well as  soluble
ions  in   saturated   paste   extracts and total elemental content  to assess the
extent   of  change in salt concentration (EC and chloride levels)  and elemental
levels  at the various  depths in the  different treatments.

Chemical  properties

The Alberta  Soils Advisory  Committee (1) suggests that no limitations  to  plant
growth   occur   at pH levels  in the surface soil of 6.5 to 7.5, and that slight
limitations  occur at  levels of 5.5  to 6.4 and 7.6 to 8.4.  The mean pH values
in  the  0  to  15  cm depth interval of the freshwater gel plots ranged  from 6.5
to  7.0  prior  to waste application  which indicates that these soils exhibited
no  limitation to  plant  growth.  Following waste application,  the  FW 4  and FW 5
treatments   had   pH   values   that  could result in slight limitations  to  plant
growth.   The difference of  0.1 pH units between 1988 and 1989 was minor.

The  mean  pH   values  in  the 0 to 15 cm depth interval of the KC1 plots ranged
from  6.7  to   7.2  prior  to waste  application and 7.2 to 7.4 following  waste
application.     These   values  indicate  that  the KC1 waste  additions  did not
result  in pH values  that  could be considered  limiting to plant growth.
The  mean  pH  values in the  0 to 15  cm depth  interval of the  NaCl plots ranged
from  6.6  to   7.0  prior  to waste  application and 6.9 to 7.6 following  waste
application.     These   values  indicate  that the NaCl waste  additions  did not
result   in   pH  values  that  could be  considered limiting to plant  growth except
for  the NaCl  10  treatment  which had a mean pH of 7.6 in the  fall 1988  and 7.4
in  the  fall  of  1989.

Saturated paste  extract data

These  data   indicate   the   magnitude of the  soluble components in a saturated
solution of  these materials  and can  be used to assess the suitability  of  these
materials  for   plant   growth  and the possibility of trace element transport.
Table 3  provides  more detailed data for ŁC, and Cl for the  individual depths
within   the  various  treatments.   The data include values for  the  soils  sampled
in  May  1988  prior  to  waste application and then in September 1988 and August
1989.
                                    273

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                       TABLE 3
Mean values for EC and C1 for the various treatments
Waste
Freshwater












KC1










NaCl












Rate
1
2
2
3
3
4
4
4
4
5
5
5
5
1
2
3
4
4
4
4
4
5
5
5
6
7
7
8
8
8
8
8
9
9
9
9
9
Depth
(cm)
0-15
0-15
15-30
0-15
15-30
0-15
15-30
30-45
45-60
0-15
15-30
30-45
45-60
0-15
0-15
0-15
0-15
15-30
30-45
45-60
60-90
0-15
15-30
30-45
0-15
0-15
15-30
0-15
15-30
30-45
45-60
60-90
0-15
15-30
30-45
45-60
60-90

Pre
0.62
0.51
-
0.59
0.25
0.59
0.45
0.36
0.36
0.58
0.31
0.26
0.26
0.51
0.54
0.52
0.61
0.31
0.41
0.41
0.23
0.47
0.55
0.19
0.53
0.57
-
0.61
0.55
0.34
0.34
0.36
0.60
0.39
0.21
0.21
0.16
EC
Post
0.76
0.91
0.53
1.14
0.36
1.10
0.58
0.35
0.35
1.39
0.80
0.32
0.32
0.86
1.20
2.60
2.87
0.47
0.80
0.54
0.13
3.54
2.51
1.65
0.70
1.95
-
1.38
0.49
0.28
0.27
-
3.01
_
_
_
-

1989
1.06
1.17
-
1.37
0.93
1.11
0.49
0.39
0.39
1.44
0.73
0.54
0.46
0.72
1.09
2.02
2.75
1.09
0.72
0.72
0.09
1.59
_
-
0.89
1.20
0.58
1.80
2.01
0.43
0.33
-
1.80
_
_
_
-

Pre
20.3
18.7
-
17.8
15.9
18.2
8.8
11.3
11.3
16.3
9.6
8.9
8.9
19.1
20.6
20.3
22.7
11.5
7.9
7.9
6.0
18.2
17.6
6.7
25.9
22.2
-
20.8
13.1
9.1
9.1
6.9
23.4
19.2
12.8
12.8
16.4
Cl
Post
25.1
22.3
11.7
33.0
15.8
36.3
15.9
11.6
11.6
40.0
37.9
15.8
15.8
22.7
396.0
740.0
1070.0
69.1
281.1
52.5
17.9
3135.0
889.0
555.0
35.6
480.0
-
870.0
85.1
90.3
9.7
-
876.0
168.0
114.2
188.2
144.1

1989
12.2
19.8
-
22.4
19.3
16.0
7.9
6.9
6.9
32.1
13.5
11.0
9.9
13.1
118.8
403.0
863.0
386.0
221.0
43.2
10.2
353.0
_
-
37.2
151.0
75.0
331.0
496.5
51.0
41.1
-'
325.0
307.0
135.4
116.5
-
                         274

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                             TABLE 3  (Concluded)
            Mean values for EC and C1  for  the  various treatments

                                        EC                         Cl
Waste
NaCl




Rate
10
10
10
10
10
ueptn
(cm)
0-15
15-30
30-45
45-60
60-90
Pre
0.51
0.46
0.25
0.25
0.12
Post 1989
7.27 5.36
0.96
0.31
0.22
0.11
Pre
24.4
14.6
7.5
7.5
8.2
Post
3352.0
206.1
42.6
25.4
20.2
1989
1728.0
539.0
306.0
192.0
454.0
Pre = Sampled prior to waste application;  Post  = Sampled September 1988;
1989 = Sampled August 1989.


These  data  illustrated  the   changes   that  occurred resulting from the waste
application  and  the  subsequent   change   with  time  and  can be compared to
existing  criteria to assess soil  quality  or  the extent of limitation to plant
growth that may occur.

Electrical conductivity  (EC) values

The Alberta Soils Advisory Committee  (2)  suggests that no limitations to plant
growth  occur  at  EC  levels  of 0 to 2  dS/m,  slight limitations occur at 2 to
4 dS/m,  moderate  limitations  occur  at   4  to 8 dS/m, and severe limitations
occur at values greater  than 8  dS/m.

The  mean  EC  values  for all  plots  and  all  depths prior to waste application
were well below 1.0 dS/m with  the  highest  values of about 0.6 dS/m in the 0 to
15 cm  depth interval (Table 3).   This  indicated that on the basis of EC soils
presented  no  limitation to plant growth.   Following the application of waste
materials  the  soil  EC values  increased  at  all locations.  In the freshwater
gel plots the maximum EC values were  in  the 1.39 to 1.44 dS/m range.  These
values  suggest  that  the  EC   levels   of   the  plot  soils  would present no
limitation to plant growth.

Changes  in  EC  levels  in  the   KC1  plots   were  greater  than those  in the
freshwater  gel  plots.    For  all treatments  the EC values in the 0 to 15 cm
depth  interval  decreased  from the  fall  of  1988 to August 1989.  Concomitant
with this were increases in EC  levels in  the  depth intervals below the surface
15 cm.   This indicates  the degree of leaching  that occurred.  On the basis of
the  soil  quality criteria described above,  treatments 3, 4, and 5 would have
had  slight  limitations to plant  growth  on the basis of EC for the 0 to 15 cm
depth in the fall of 1988 with  a reduction  in  limitation by the fall of  1989.

In the  NaCl  plots  the  mean  EC   values  were  somewhat higher than  in the
freshwater  gel and KC1  plots.  The trends  regarding the changes that occurred
with  time  are similar  to the  freshwater  gel  and KC1 treatments.  The highest
application  rate  of  NaCl  waste resulted in  EC levels that imply a moderate


                                     275

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limitation  to  plant growth.   The  mean EC value for the NaCllO treatment was
7.27 dS/m in the fall of  1988  and decreased to 5.36 dS/m by the fall of 1989.

Chloride values

Maas (12) indicated that  the maximum chloride content that could be present in
saturated  extracts  without   loss   of   yield  in  grasses ranges from 1000 to
2600 ppm.    Following  the  application  of  waste  materials  the  Cl values
increased  at  most  depths  in all  plot treatments.  The smallest change in Cl
content  occurred   in   the   freshwater   gel plots simply because of the low Cl
levels  in the gel wastes  applied.

Leaching  of  the   Cl was evident by the change that occurred between 1988 and
1989.     Using  the  criteria  of   Maas  (12)  indicates  that  the  chloride
concentration in the plots will  have no negative impact on plant growth.

The  KC1  treatments  had considerably  higher Cl additions than the freshwater
gel  treatments.    Using  the  value of 1000 ppm Cl as the level  in soil  that
begins   to   impact  plant  growth  suggests that some limitation was  possible for
treatment KC1 4  and more  so  for  treatment KC1 5 in the fall of 1988.  The  mean
Cl  values for the 0 to  15 cm depth  decreased in 1989.

The  trends   associated  with   Cl   levels  in the KC1 waste treated plots  were
similar  for  the  NaCl waste treated  plots.

Tissue  Analysis  Data

The  total   elemental   content of the brome grass tissue collected  in 1988 and
1989  was   determined.    The  1988  data obtained represents an incomplete  set,
simply  because  the  vegetation  cover in  all plots was not adequate  to provide a
sample  particularly in  the case  of  the  KC1 and NaCl waste amended  plots.

The  effect   of  the addition  of drilling waste on the elemental enrichment of
the  affected plants can  be  demonstrated by the enrichment ratio (ER).   The ER
of  a chemical element  is  calculated by  dividing the elemental concentration of
the waste -  affected plant tissue by that of the unaffected plant  tissue.

The  tissue   from   the  treated   plots   exhibited elevated levels  of chloride,
sodium   and   to  a  lesser extent copper in comparison with the tissue from the
control   plots.     Boron,  levels  increased two-fold over control levels  for the
FW  5 treatment  in  1988, however, they were down to control levels  in 1989.

Copper   levels   -n  the  tissue  were  higher in 1989 than in 1988.  Tissue levels
of   1.0   to   5.1 ppm  and 5.2 to  18.0  ppm copper are considered deficient and
normal,   respectively.  Tissue grown in the control plots had copper levels at
about   the   mid-point   of the deficient range.  Addition of waste resulted  in
increased tissue copper values with some of the values occurring in the normal
range for grasses.

Sodium   levels  in  the tissue increased  with increasing application rate of the
different   wastes,  particularly the NaCl material.  Substantial differences  in
the  uptake  of Na between  1988  and  1989  were evident from the ER values  of  29.0
                                     276

-------
vs  2.3  for   the NaCl 9 treatment, respectively.   This  is related to the fact
that  the sodium was leached downward from the  zone of waste incorporation and
out  of  the   currently established root zone.   Normal and excessive levels of
sodium in grasses are 300 to 1100 ppm and 3200  to  43700  ppm, respectively.  On
the  basis  of these criteria, it was apparent  that the  normal  levels were not
exceeded, and that for many of the treatments were not even achieved.

Tissue   chloride   values  ranged  from  2.89  mg/g  (2890 ppm)  to  6.01 mg/g
(6010 ppm).    Chapman (5) reports an  intermediate  range  of 7000 ppm and a high
range  of  8700 to 15400 ppm for chloride in  grasses.  Using these values as a
guideline  suggests that the application of all  wastes resulted in high levels
of  chloride  in  the  tissue  in 1988 particularly the tissue from the KC1 and
NaCl  treated  plots.    The   chloride   levels   in  the   tissue  in  1989 were
considerably lower than those  in 1988.  The decrease in  tissue  chloride levels
 in  1989  is  directly  related to the decrease  in soil/waste chloride levels.
All  values  reported  for 1989 were  below the  intermediate level  of 7000 ppm,
reported by Chapman (5).

The  concentration  of  potassium  in the tissue did not change at all  for all
treatments  except  for the KC1 4 plots, despite the fact that  the KC1  treated
plots  received  a  high  concentration  of potassium especially at the higher
 application rates.  Magnesium  uptake  declined with increased waste application
 rate   and  in particular with  the NaCl waste.   It  is likely that the levels  of
other  cations were in part responsible for the  lowered  uptake  of  magnesium by
the brome grass.

 Conclusions

 Observations  made  and  results obtained pertinent to the field study in 1989
 form   the  basis  for  the  preliminary  conclusions  presented  herein.    The
 application  of  the  different  wastes at varying rates had both  positive and
 negative  impacts on the soils  and the plants  grown thereon.

 The  freshwater gel treatments reduced yield  below control levels  for the FW 4
 and FW 5 plots, and the resultant soil/waste mixtures  exhibited pH levels that
might  exhibit a slight limitation to  plant growth.   These results  suggest that
 the  application of freshwater gel, to the levels  of treatments FW 2 and  FW 3,
 presented  no limitation to the plot  soils or the  plants grown  thereon and,  in
 fact,  enhanced the soils and plant growth to  some  extent.

 Similar  trends  were  observed  for  the KC1  and NaCl  treatments,  however, the
.impacts were more marked for some of  the parameters.   From a yield standpoint,
 the  application  of  KC1  wastes resulted in a  negative impact for the KC1  3,
 KC1 4,   and  KC1 5 treatments.  From  a soil quality standpoint  in  1989, slight
 limitations  due to EC were evident for the KC1  3,  KC1 4, and KC1  5 treatments
 and a  slight  limitation due to Cl.

 The  NaCl 7  treatment  resulted  in  essentially   no  negative impact  on soil
 Quality  and  enhanced  plant  growth.   Depending upon  time elapsed following
 waste  application,  the  NaCl 8, NaCl 9, and NaCl  10  treatments had slight  to
 severe   impacts on soil quality (EC,  SAR, Cl  levels).  The impact  was lessened
with time.


                                     277

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References

1.    Alberta  Soils  Advisory  Committee.     1977.   Soil quality criteria for
      agriculture.  Report printed  by  Agriculture Canada.

2.    Alberta Soils Advisory Committee.   1987.   Soil  quality criteria relative
      to  disturbance  and  reclamation.   Soil  Quality Criteria Working Group,
      Soil Reclamation Subcommittee.

3.    AOAC.    1981.    Official  methods   of   analysis.    Fourteenth edition,
      Association of Official Analytical  Chemists, Arlington,  VA.

4.    Bascomb,  C.L.    1961.    A  calcimeter  for routine use  on soil samples.
      Chemistry and Industry (Part  II):1826-1827.

5.    Chapman,  H.D.   (ed.).  1966.  Diagnostic criteria  for plants and soils.
      Department of Soils and Plant  Nutrition,  University of California Citrus
      Research   Center   and   Agricultural   Experiment   Station,   Riverside,
      California.

6.    Doughty,  J.L.    1941.    The advantages of a  soil paste for routine pH
      determination.   Soil Science  22:135-138.

7.    ERCB.    1975.    Interim  Directive  ID-OG 75-2:    sump fluid disposal
      requirements.

8.    Gaines,   T.P.,  M.B.  Parker,   and   G.J.  Gascho.     1984.     Automated
      determination  of   chlorides   in soil  and plant tissue by sodium nitrate
      extraction.  Agronomy Journal  76:371-374.

9.    Gee,  G.W. and J.W.  Bauder.   1979.   Particle size analysis by  hydrometer:
      a  simplified method for routine  textural  analysis and a  sensitivity  test
      of  measurement  parameters.     Soil   Science  Society of America Journal
      43:1004-1007.

10.   Holmgren,   G.G.S.,   R.L.   Juve,   and   R.C.   Geschwender.    1977.    A
      mechanically  controlled  variable   rate  leaching  device.  Soil Science
      Society  of America  Journal 32:568-570.

11.   Leco  Corporation.    1979.    CR-12  carbon system 781-600.   Instrument
      Manual 200-195.

12.   Maas,  E.V.    1986.  Physiological  response of plants to chloride:  In:
      T.L.   Jackson  (ed.).    Chloride  and   crop   production.   Papers of an
      American  Society   of Agronomy Annual  Meeting  (November  1984), published
      by the Potash and Phosphate  Institute (August  1986).
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13.
14.
15.
16.
17.
 18.
 19.
20.
Macyk,  T.M.,  F.I.  Nikiforuk, and S.A. Abboud.   1989a.   Drilling waste
landspreading field trial - a joint research  project  of  Alberta Research
Council and ESSO Resources Canada Limited.  Terrain  Sciences  Department,
Alberta  Research  Council  Report  prepared   for  ESSO  Resources  Canada
Limited.

Macyk,  T.M.,  F.I.  Nikiforuk,  S.A.  Abboud,  and Z.W.  Widtman.   1989b.
Detailed  sampling,  characterization  and  greenhouse  pot  trials relative
to   drilling   wastes   in  Alberta.    Alberta   Land Conservation  and
Reclamation Council Report No. RRTAC 89-6.  228  pp.

Macyk,  T.M.,  S.A.  Abboud,  and  F.I.  Nikiforuk.    1987.   Oil and  gas
reclamation  research  program:    drilling   mud  disposal:  sampling  and
detailed  characterization.   Volume I:  Report,  Volume  II:   Appendices.
Terrain  Sciences  Department,  Alberta  Research  Council.   Unpublished
report  prepared   for  the  Land  Conservation   and  Reclamation Council,
Reclamation Research Technical Advisory Committee, Alberta  Environment.

McGill,  W.B.  and  M.J.  Rowell.   1977.  Extraction of  oil  from  soils.
Chapter 4.  In:  'The Reclamation of Agricultural  Soils After  Oil Spills,
Part   I:    Research', edited by J.A.  Toogood.   AIP  Publication M-77-11,
University of Alberta, Edmonton.

Peech,  M.  1965.   Hydrogen-ion activity.   In:  'Methods of  Soil  analysis,
Part  2', C.A. Black et al.  (ed.).  Agronomy 9:914-926.  American Society
of  Agronomy, Inc., Madison, Visconsin.
 Rhoades,   J.D.     1982.    Soluble  salts.  In:  'Methods
 Part   2,   A.L.  Page et  al.  (ed.).  Agronomy  9:167-179.
 of  Agronomy,  Inc., Madison,  Wisconsin.
                                          of Soil Analysis,
                                           American Society
 Soltanpour
 Colorado  State
 University.
P.N.  and S.M.  Workman
    University  soil-testing
1981.   Soil-testing methods used at
      laboratory.     Colorado State
 USDA.     1954.—   Diagnosis   and   improvement  of  saline  and  sodic  soils.
 Agriculture  Handbook  60,  United States  Department  of  Agriculture.
                                     279

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DRILLING WASTES MANAGEMENT FOR ALASKA'S  NORTH  SLOPE
Bradley Fristoe
State of Alaska
Department of Environmental Conservation
North Slope District Office
Fairbanks, Alaska, U.S.A.
Introduction

The primary state agency in Alaska  for regulating the disposal of drilling waste
is the Department of Environmental  Conservation.  The department uses its solid
waste, water quality and waste water regulations for oversight of these wastes.
Tools for managing  include facility plan reviews, waste  discharge permits and
onsite  inspections.   These activities  are  done through  the  Fairbanks  office,
located 400 miles from  the major oil fields of Prudhoe Bay.        ~"

In the  early  1980s  department presence  in  the oil  fields was  as  little as 10
person-days a year.  This was  changed when  the North  Slope District Office was
formed  in  1983.   Office space was leased in Deadhorse,  the  population center
for oil development on the North Slope.  Field presence is now over 200 person-
days a year.

With increased monitoring,  there was improved documentation of the effectiveness
of waste management practices of drilling wastes in the oil development area of
the North  Slope.   Wastes were stored in pits  made of berms  of pit run gravel
placed directly onto the tundra.  The tundra served as  floor; no lining materials
were used.  The dikes were believed to  have  frozen cores which were impermeable.
What  was  found was  that the  gravel  rapidly  thawed  and  subsequently  leaked.
During  the  wind  swept winter months extensive snow drifts accumulated in the
pits.  When they melted the pits overflowed, and hydraulic head caused leaching
and rupture of the dikes.

The department reacted  to these  observations  with  new  regulations  that were
promulgated  in the summer of 1987.   The intent of  these regulations  was to
require total  containment of drill ing wastes, encourage consol idation of disposal
sites, encourage alternatives to surface disposal  of wastes and, most important,
encourage waste minimization.  This was  accomplished by setting minimum standards
for reserve pits, requiring fluid  management plans  to reduce  fluid levels that
promote leaking,  and  limiting the  disposal  of  materials  incompatible with pit
design, such as freeze depressants in pits that rely on permafrost containment.
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Minimum monitoring for sites is outlined in the regulations, which is providing
the beginnings of a data base  on pit performance.

Realization  of unacceptable practices  has  caused  a  renaissance of  ideas  to
improve the handling of drilling wastes.  This report discusses the development
status of  these ideas, regulatory  schemes that the  department  is  using,  and
concerns the department has for success of options being tried.  Practices that
have  been  tried  and  are  being evaluated  are waste  reduction,  injection  of
drilling wastes,  deep hole burial  using  permafrost containment,  shallow hole
burial using permafrost containment, and  treatment  of  waste and subsequent use
as construction material for roads  and  pads.

Waste Reduction Techniques

Waste reduction can be  looked  at as the reduction  in  volume  of wastes needing
disposal or the reduction of waste  toxicity.

Toxic additives  can be introduced  throughout  the  drilling process.   Drilling
fluids are used to  control  pressures,  flush cuttings  to the  surface,  seal the
well casing,  lubricate and  cool the  drill bit, and transmit hydraulic horsepower
to the bit (1).  Exotics that are added to the drilling system that potentially
add  toxicity include lubricating  agents, emulsifiers,  coagulants, pipe  dope
containing lead,  biocides  used to  prevent reservoir contamination  by sulphur
reducing  bacteria,   solvents  for   removing  paraffins,  corrosion  inhibitors,
weighting  agents such  as  salts,   pH  adjusters,  freeze  suppressants,  tracer
materials  for  studying  reservoir characteristics,  and stimulation  fluids.   In
addition,  toxic  contamination  can  occur  from cuttings and fluids  encountered
during drilling such  as from formation hydrocarbons.  Reservoirs  on the North
Slope presently being developed range from 6,000 feet deep to over 10,000 feet.
As  drilling  depths  increase  more  demands are  made  of  the  drilling  fluids,
increasing the need for additives.

Industry  has been  looking  at  less toxic additives  for use  in the  drilling
operation.  For instance, chrome mud was used freely in the drilling of Prudhoe
Bay unit wells. Newer fields,  such as the  Kuparuk River unit, tend to use chrome
free mud.  Diesel  based  mud  is  being used less frequently as drilling technology
improves  and  as  subsurface  geology  is  better  understood.    The  department
encourages the addition of less toxic additives  and considers  it to be  an
important  adjunct to  waste disposal.   Less  toxic  wastes reduce  the risk from
disposal site  failure.

One method for reducing waste volume being  tried is separating out the non-toxic
portion of the wastes.  ARCO Alaska, Inc.  has a pilot project in which  they are
separating cuttings that are brought up from the first 3500 feet of wells from
the drilling mud.  These cuttings account for approximately 50% of the  cuttings
volume total.  The top hole  drilling tend to be vertical and consists of thawing
sands and  gravel  cemented  together with  permafrost.  These cuttings  are  very
similar to sand and gravel  from local  pit  mines.


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The  sand  and  gravel,  once separated,  are  then washed of  residual  mud.  After
testing to verify that washing is complete and that the cuttings are chemically
similar to surface  sands  and gravel, the cuttings will  be approved for use  in
construction.   These recycled  materials may  end up  in a road,  a structural
foundation, or in sand bags.  The  ease of  separating sand and gravel particles
from drilling mud and additives  is an  important  aspect of this project.

The  department requires  plan review of the washing  equipment and the sampling
plan proposed for verifying leachate potential.  As of  this writing the sampling
plan ARCO has proposed is to  determine  sample pH  and total petroleum hydrocarbon
concentrations,  followed by acid  digestion  and  analysis  for arsenic,  barium,
cadmium,  chromium,  copper,  iron,  lead,  manganese,  mercury,  nickel,  selenium,
silver, sodium,  sulfates,  and zinc.  Samples  are to  be taken every 500 feet of
drilling  depth.   Results  are  compared to analysis  results  for  typical  local
surface  gravel.    Should  the  samples fail   this test,  ARCO  is proposing  a
Teachability  test with the leachate being compared to the state's water quality
standards.  The department is looking  forward to results of this pilot project.

Recycling the mud system is another method  used to reduce waste  volumes.   As
the  mud  surfaces, shakers and  cyclones  are  used to remove  cuttings,  cleaning
the  mud for  reuse.   A typical  well on the North  Slope requires the use of two
separate  mud  systems.  The first is used through the permafrost^zone.   Once at
the  depth where horizontal deviation occurs,  approximately 3,500 to 4,000 feet,
the  initial  mud  system is disposed and a second  system  introduced.   Recycling
the  second system is done  throughout drilling the remainder of the well, at which
time it,  too, is disposed.   Recycling mud  systems from  well  to well  is  not
currently performed on the North Slope, though the department understands it is
done in other states.  We  are interested in  knowing more about  and promoting well
to well recycling.

Reducing  the  drilling hole volume  reduces  the  waste  volume generated.   This is
being done in a number of ways on the North Slope.  New technology is improving
the  efficiency of drilling, requiring fewer holes to  access more reservoir.  For
instance,  if a  bottom hole is unsuccessful in accessing a producing zone,  the
well can  be  recycled  by deviating  from the  well  bore to  a  new  bottom hole
location.  Similarly,  multiple bottom hole locations can be drilled from one well
during exploration.  Successful  reworking  of  a well  allows new sections of the
well bore to be used  for  production of  hydrocarbons.    Improved  reservoir
stimulation practices allow oil  recovery at greater distances  from  the well bore
'') •

Recently,  horizontal  drilling has  been  used  on  the North Slope.   Horizontal
drilling,  a  refinement   of  directional  drilling,  allows  the  well  bore  to
horizontally  travel through the  reservoir  resulting  in increased  reservoir
contact.   It is  limited  to  deeper reservoirs  which allow enough  room  for the
drill to  angle into the oil  horizon.
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The department,  as policy,  encourages  all methods  that reduce  waste volumes
needing  disposal;  however,  there  are  no mandatory State  requirements  for
reduction of waste volumes.  Economics play a  major  role in when and how waste
reduction occurs.

Disposal of Drilling Waste bv  In.iection

Subsurface  injection  of drilling wastes  is  an ongoing  practice on  the  North
Slope.  Though this method of disposal has been questioned for use in the Lower
48, there are a number of reasons it is an  accepted practice  in our most northern
part of the country.  These  reasons have  to do with  the  availability of wells,
the geology, and  relative  importance  of resources.

Obviously,  with  the primary industry on the North  Slope being  oil and gas
development, resources for drilling and maintaining wells are readily available.
Though waste injection has not occurred at these depths,  it shows the extent of
known technology.   Many injection wells  are  located at  the oil well  drilling
sites, eliminating the need  to transport  wastes and  subsequent  spillage.

The North  Slope  is a 30 to  80 mile wide  alluvial  plain which  stretches  along
Alaska's north coast.   It  is formed  from silt, sand and gravel  sediments that
originated  from  the Brooks Range, the mountain  range which forms the  plain's
southern  border.    Subsurface  geology is uniform throughout  the area,  which
partially  accounts  for  the large oil  and gas  traps  found.  For  instance, the
Prudhoe  Bay  formation  is  approximately  30 by  50 miles.  Also of  importance is
the continuous permafrost across the North Slope descending from near the surface
to between  1000  and 2000  feet.  In the Prudhoe Bay area the permafrost bottom
is in the 2000 foot range.  In addition to permafrost, horizons of siltstone and
shales confine subsurface  fluids  (3).  Large  uniform formations  and  2000 feet
of  permafrost  and  shales  forming   impermeable  boundaries  makes   injection
attractive on the North Slope.

It is worth noting that should oil and gas exploration be allowed in  the Arctic
National Wildlife Refuge,  injection will be considered as  a major method of waste
management.   However, the  geology of  this area has not been proven  and may be
significantly different from the Prudhoe Bay area.  One known difference is that
the permafrost only ranges to  the 1000 foot depth  in  the refuge.

Subsurface  injection  is   highly  preferred  by  the  department  over  surface
discharges that can compromise surface water  resources.  The  North  Slope  forms
one  of  our nation's  important wetland complexes,  supporting  rich  biological
resources  (4).  The surface  resources also provide the only drinking water for
North  Slope  human inhabitants,  whether  they  be  indigenous  populations or
industrialist  migrants.    Groundwater found  below the  permafrost mostly  have
total dissolved solids concentrations over 10,000  milligrams  per liter,  though
some range  from  3,000  to  10,000.   In  the  early 1980s one  company tried ground
water as a drinking water source.   The source  was abandoned after two years due
to the high costs of treatment and maintenance.
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Two methods of  injection are  practiced on the  North Slope:  through the well
tubing and through a well annul us.   In  general,  wells that dispose through the
tubing are deeper and inject a wider variety  of  wastes.

Wells which use tubing  for  injection are referred to  as  dedicated wells.  Few
of these wells on the North  Slope have  been drilled specifically for injection.
Host are converted wells that have exhausted their original purpose.  Dedicated
«ells typically inject  between the 5000 and 6000 foot depths,  but some are as
shallow as 1900 feet.  Dedicated  wells  dispose, in addition to drilling wastes,
other  field  wastes  such   as  production  facility  clean  ups,  workover  and
stimulation fluids, and produced fluids.  Dedicated wells are regulated through
the Underground Injection Control program and are classified as Class II wells.
In the  state  of  Alaska,  the Alaska Oil  and  Gas  Conservation  Commission  has
primacy over Class  II wells.   One well  has recently been  permitted as  a Class
I nonhazardous well, and will likely be open  for support  industry use.

Annular injection occurs by injecting  through the annul us  between the  surface
casing and the casing immediately inside of it.   The tubing  can then be used for
other purposes.  The surface casing is typically set at  between the  1900 and 3500
foot depth.  Figure  1 is a  schematic of what  a well  looks  like and where
                 Fig. 1.  Annular injection well schematic.
injection occurs.   Annular injection consists primarily of disposing the liquid
portion of drilling wastes from drilling a well  itself,  other wells and reserve
pit  fluids in the  immediate vicinity.   One well can be used  for  disposing all
wastes at a production pad, which may have up to sixty wells.  Annular injection
is exempt from the  Underground  Injection Control Program and is regulated by the
department.  To simplify regulating these disposals, a general  permit has been
issued which stipulates what information,  shown in Table 1,  must  be submitted
to  the  department  for  authorization to  inject.   The general  permit  limits
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disposal to fluids produced from the drilling, servicing, or testing of oil and
gas exploration,  development,  service, and  stratigraphic test wells  to zones
containing total dissolved solids of greater than  3000 milligrams per liter.

                                    TABLE 1

      Information Requirements  To ADD!V For Annular In.iection

        1.  Well  designation or  name,  and description of the well  with  a  map
            or plat of the well  location.

        2.  A  list  of materials  to  be injected, description of the materials,
            estimated  volumes  of each material, and  sources of  all materials
            to be injected.

        3.  The  total estimated  volume of material to  be disposed.

        4*. A  description  of the zone  that the wastewater will be  entering
            including the  top  and bottom depths, the geological  make-up above
            and  below the  zone,  permeability of the zone, operating pressure
            of the  zone, and salinity of  the ambient water within the  zone.

        5.  The  depth at which injection  will  occur.

        6.  Beginning and  ending dates the disposal will  occur.

        7.  A  schematic  of the well  and  casing layout to a point 100  feet
            below the bottom of  the injection  zone.

        8.  The  method to  be used to seal the  injection  zone when disposal are
            finished.

        9.  Anticipated  time by  when the  injection zone  will be sealed.

      * For wells where  this  information  will  not  be available prior  to
        disposal, as  in  an exploration well,  the information is to  be  reported
        in the final  report.

A recent development in injection on the  North Slope  is BP Exploration  (Alaska)
Inc.'s  pilot  project  which  uses a  ball  grinder  to grind  cutting solids to
particle sizes that  can be injectioned. This  pilot project has proven successful
enough that a full  scale unit was installed  beginning  July 1,  1990. Injecting
the solids, reduces  surface discharges needed and the surface disturbances needed
for those disposal.   The department sees  this  as a major improvement.

Though injection  is a preferred method of disposal  by the department, there are
some  concerns.   The integrity  of well  hardware  is an  important consideration.
We depend on the Alaska Oil and Gas Conservation Commission to provide expertise
and to enforce their  well  integrity program.   Another  concern  is  the migration
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of wastes and  surfacing through  a well bore.  There appears to be no,  or minimal,
flow  in  the  aquifers  below the  permafrost  (3).   However,  as  early as  1975
industry has been concerned about  thawing  around well casings from warm  fluids
flowing  through  them (5).  Thawed soils  may provide a  migration pathway  for
wastes.  Because of  low  flows  in aquifers and the  presence of other  confining
zones  the  department feels the likelihood  of this  occurring to be  low,  but
further data should be collected.

Below  Grade Burial of Wastes

Having found  that  surface pits  cause  leaching problems  even  when  covered,
permafrost was looked at  for improving  containment.  Permafrost was considered
because  of  its  ability  to bind wastes  in  a  stable cemented  matrix.   Further,
permafrost burial could be accomplished by currently used construction methods.

Two types of below grade pit designs, shallow burial and deep burial,  have been
used to freeze wastes into permafrost, a practice referred to in Alaska  as  freeze
back.  Shallow burial pits are constructed  by ripping  frozen soils using tractor
mounted  rippers.   The resulting  pit is up  to 60 feet deep  and  can encompass
several  acres to several hundred acres.  Deep burial pits are constructed using
a power  auger to drill  a hole  up to 12 feet  in  diameter  and  120 feet deep.  A
minimum  6  feet  of undisturbed  soil  must  be  left between auger holes  for soil
stability.

An important part of a freeze back design  is the thermal regime.  Wastes  placed
in below grade reserve  pits have been documented  thawed for  two years after
closeout due to stored heat and  latent  heat of freezing.  An excavated  pit forms
a bowl in the  permafrost which can fill  with the sheetflow  of surface meltwaters.
Actions  to promote freezing include removing  free liquids, cooling wastes prior
to disposal,  and closing pits in the fall providing a full winter for freezing.
The deeper  into permafrost the  waste is buried,  the colder and more static the
surrounding soil temperatures.   This  is one reason why the  deep auger hole  burial
is preferred  for freeze  back.

The freezing temperature of wastes in relation to surrounding soil temperatures
is also  important.  Freeze back does not work unless the wastes freeze.   Freeze
depressants such  as  salts, hydrocarbons  and alcohols complicate freeze back.
Brine  pockets caused by  dissolved solids being concentrated  as they are excluded
during the freezing process are a common feature in natural permafrost found on
the North  Slope.   Because many  mud systems  have high salinity concentrations,
significantly sized  brine pockets potentially could  form.   Other concerns are
frost  heaves  and contraction cracks caused  by  soil  contractions  during cold
weather  (6).

The State's regulations  require that in freeze  back the surface level  of all
wastes at  close-out  be at least  two feet below the  active  thaw zone.   It is
important  to  delineate  the active thaw zone, which is defined  as  the surface
layers of  organic  matter and mineral  soils  which  thaw each year in  areas-of
permafrost. As  a rough estimate, the modified Berggren equation has been applied
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to sites where below grade pits have  been  proposed (7).   The Berggren Equation
is typically expressed as follows  (8):

   X =  A x sq rt of (48 k. x nl/L)

Where:

  X  =  depth of thaw

  X  =  coefficient  which  considers the effect of temperature  changes within
        the soil mass

  k. = average thermal conductivity

  I  =  air thawing  index

  n  =  an empirical constant  relating  air and  surface thawing  indexes

  L  =  latent heat

Many of these variables, including the empirical  factor, are not well established
for North Slope sites and predicting  specific thaw depths has proven difficult
(7).   Factors that  can  affect sites are wind exposure,  sun  exposure,  distance
to the  ocean  or  Brooks  Range,  cover material used, soil  moisture  content,  and
susceptibility  to  snow drifting.   Little  is known  how  disturbing  soils will
affect  their  insulating  capacity.   Thaw depth vary from  site to site,  as well
as within a  site.   For  example,  the south west corner of a  site will  have  the
greatest exposure  to the sun  and,  because of prevailing winds, will  have  the
greatest snow cover  from drifting.  Activities that change  the thermal  regime
of a site so  as to negatively  affect  freeze back  are prohibited.

Only  limited  data  exists for  extreme climactic conditions on  the North Slope
due to  the  short history of collection.    Except  for  the past 15 years, most
historical data  is  from Pt. Barrow,  over  two hundred miles from  Prudhoe Bay.
Long-term climatic  trends  must also be considered in  determining  thaw depths.
Long-term trends are difficult to  predict,  though there is much debate currently
surrounding such concepts as the global greenhouse effect.

To verify thaw depths,  thermistors are now required in  all  closed-out reserve
pits using freeze back.   Thermistors are capable of measuring temperatures based
on electrical  conductivity changes as temperature changes.   They  have provided
reliable results without disturbing a site.  Thermistors can be removed, tested
and replaced  without affecting the  site.    Good  design   requires  attention to
conductive and convective heat transfer  through  the  well casing. Thermistors
are placed  in the  pit  center, and  other  locations where variability  in  the
thermal regime can be expected, such as areas of  snow drifting or surface waters.
Maximum thaw occurs during late September  into October, which is a  critical time
for monitoring.
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As the department learns more about  permafrost,  concerns about fluid migration
through upper frozen  layers have  increased.   Migration can  occur through the
formation of lakes,  meandering of creeks and rivers, and fluid movement through
permafrost cracks. These are long-term problems that may not manifest for years,
long after an operator has discontinued monitoring and has abandoned a site.

Lakes can form due to altering the thermal regime.  Heat input will increase by
removing the insulating organic  soils or having  shallow water.   The increased
heat input will  thaw  into  the permafrost, thawing  ice  rich  soils.  Subsequent
collapse of  the  soils,  known as  thermokarsting,  creates  a lake  which further
increases heat input.  This process repeats until thermal  equilibrium is reached.
What starts  as  a small  depression may grow  to a lake that will  influence the
integrity of a site.

Many creeks and rivers on the North Slope have cut banks which are tens of feet
below the surrounding tundra.  Most North Slope soils lose structural stability
once thawed.  As  a river bank erodes through thawing,  the  river undergoes lateral
migration.  Though mostly  low energy systems,  aerial photographs show evidence
of the thaw induced meandering of rivers.  An example of this is near the Oxbow
Landfill operated by  the  North  Slope Borough, which  has been  the recipient of
drilling  wastes  in  the past.   One  hundred  feet  from this  landfill  is  the
Putuligayuk River.  During the spring thaw of 1989, high runoff caused six foot
wide sections of river bank to erode.  Similarly, thermal  erosion occurring along
the ocean coast moves the coast inland at an average rate of a  foot a year.  This
thawing is  important  in the  siting of disposal  sites.

Below  surface ice lenses and  ice  wedges  form when a portion  of water migrating
through cracks in the permafrost freezes.  Figure 2 is a diagram of the formation
of an  ice  wedge.  The top 20 feet of the soils on  the  North  Slope often have
massive  concentrations  of ice wedges and  lenses.   The  typical  soil  boring in
Figure 3 demonstrates this.   The  water  that  migrates through  permafrost cracks
has the potential of leaching contaminants from a  site.   We have had experiences
where diesel has been  found to migrate laterally through cracks  in the permafrost
hundreds of  feet.  This phenomenon is poorly understood at this time and needs
to be better understood if more shallow depth pits are to be constructed.  Deep
auger holes have the  advantage of being able to be  below these surface phenomena.

An important  part of pit  maintenance is a fluid  management program to prevent
the pit  from leaking  or overtopping.  Fluid management  is an ongoing concern,
as each winter,  drifting  snow will fill  a pit.   Presently, the main method of
fluid management  is injection as  described earlier.   Removal  of uncontaminated
snow prior to thaw is also widely practiced.   In the past,  discharges of fluids
directly to tundra or to road surfaces were allowed.  These practices have been
discontinued  because  of difficulties with monitoring  and  of  controlling water
quality.  Frequent violations of the water quality standards were recorded.  To
avoid fluid management  requirements,  some  pits have been designed to be closed
out after one season  of use.  This has been  accomplished by utilizing cellular
development  or  the  auger  holes.   The difficulty with one  season  pits has been
predicting the volume of one  season's waste  production.
                                   289

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                                                           TO 3 FT. DEEP
                 MINERAL SOILS    ;
                         ICE LENSES
                  PERMANENTLY FROZEN SOILS - PERMAFROST
                  TO DEPTHS UP TO 2000 FT. BELOW THE SURFACE
       Fig.  2.   Fluid migration  and ice  formation of near surface soils.
                  bontonr
I!  ,h!il
                                71.9



                                27.9
Equ1p*tnt

E1tvitlon
                                                        LQ6 OP JOEING Ctll S

                                                       8-61/Solld-rHaht »ua«ii
                                                          Ota
                                         to*
                                                DARK 8RWN PUT (Pt)
                                                 loou, «oUt to ««t
                                                DMK BROWN OttMIC SILT (OL, Nb)
                                                 lOOH, Uttt to tMt
                                                 bondtd (Nb) btlow l.S fMt

                                                MASSIVE ICE !ICE)
                                                 Mlth tract of orginlcs
MASSIVE ICE AM) LIGHT BROWN SILTT
SRAVELLY SAND (ICEISN)
  
-------
will be monitoring some sites for years  longer.   In general, present reserve pit
operators are required to do site visits, aerial photography, and surface  water
monitoring.  In  addition,  samples of the waste are taken and the crystallization
point of the waste determined for comparison  to ambient soil  temperatures.

Visual  inspections  are conducted at least once  per year during  late  summer.
During these visits the site  is  inspected  for any degradation or damage to  the
cap or facility  from  erosion,  cracking,  freeze-thaw  cycles, frost  heaves,
burrowing animals, changes to the thermal regime, any ponding surface  waters on
or adjacent to the cap, any seepage from the disposal site or any surface  water
discoloration,  any  damage to vegetation adjacent to  the site, any damage  to
monitoring devices, any damage  to  survey monuments  at  the  site,  the  status  of
revegetation of the disposal  site  cap,  and any other  events  of note.  Besides
visual observations, thaw probing by driving a rod into the ground until refusal
is required during the  period of anticipated  maximum thaw.

Aerial  photos of  each  site are  required during late summer of each monitoring
year.   Photographs  are not  required to be taken  for scaling, so  they can  be
taken  out the  side  window  of  a helicopter  or  plane during  a  fly-by.   The
photographs  must clearly show  the  disposal  cell  and  surrounding  area for
approximately 300 feet.   These  photographs are  required during each year  of
operation, at close-out,  as  well as during  the  post-closure monitoring period.

Water  quality monitoring  consists  of taking samples at  two sites  downgradient
and one upgradient of the facility,  and field testing around the pit perimeter.
Typical  analysis for  the  samples   is  pH, conductivity, salinity,   chromium,
cadmium, barium, lead,  sodium, zinc,  potassium, aluminum,  arsenic, and chlorides.
Field  testing consists of monitoring for pH and salinity every 50  feet of the
perimeter  of the  site  where  surface water  is  found.

Consolidation of  Sites

The state  is developing a policy that will  require  that surface disposal  sites
be limited through consolidation.   Most North Slope  oil  and gas development  to
this point has been on state lands.   Consolidation is meant to reduce  liability
the state may  incur  should the long-term integrity  of  sites not  perform  as
expected.   Besides  reducing the number of sites where  liability  is  incurred,
consolidation reduces long-term monitoring costs, and consolidates drilling waste
handling facilities.  Consolidation  allows more resources  for site investigation
and equipment development fewer  will  be needed.

Concluding Comments

During  the  early  1980s,  drilling  wastes  were   being  managed  in surface
impoundments  which  contributed  to  the  release of  the  wastes to  surrounding
environments.   During  the past  five years a  series  of management  alternatives
have been  tried.   These alternatives include waste  reduction,  injection,  deep
hole freeze back, shallow hole freeze back, and treatment and subsequent use  of
the treated waste as construction material.  All  these methods have shown promise


                                     291

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in helping  to reduce  or eliminate  contamination from  drilling wastes.   The
department's  preference  in  descending  order  is  waste  reduction  with  no
discharges,   injection   below  the  permafrost,  treatment   to  remove  inert
constituents  and  the product used as  construction material,  burial  deep into
the permafrost where the frozen matrix is the most stable and shallow burial in
the permafrost.   Treatment  to  remove inert  constituents is  limited  to those
situations where the treatment  can be  conclusively verified,  which would limit
its use.

The North Slope is known for  its wetlands which have international significance.
Protection of these resources is a department priority.  Any future policy that
is developed will  likely emphasize the  discontinuance of surface discharges, and
to promote the elimination of reserve pits.  These goals appear to be attainable
based  on  the success  of pilot  projects that  have been  tried,  though  further
research will be needed to refine these  waste management methods.
References

1.  ARCO Alaska, Inc., Exxon USA, and Standard Alaska Production Company.  Arctic
    Operators  Production  Waste  Report,  1987b.

2.  B. Wondzell, Petroleum Engineer, Alaska Oil and Gas Conservation Commission,
    personal communication.

3.  W.W.  Barnwell,  Commissioner, Alaska  Oil  and Gas  Conservation Commission,
    State  of Alaska, Memorandum--North  Slope Coastal Plain:   Geohydrological
    Considerations,  October 2,  1986.

4.  R.A. Post, Effects of Petroleum Operations in Alaskan Wetlands:  A Critique,
    Technical  Report No.  90-3 (In Press),  State  of  Alaska,  Department of Fish
    and Game,  Habitat Division,  June 1990.

5.  T.K.  Perkins,  et al., Prudhoe Bay Field  Permafrost  Casing and Well Design
    for Thaw Subsidence  Protection,  Atlantic Richfield Company,  White Paper,
    1975.

6.  T.L.  Pewe, Ice Wedges  in  Permafrost,  Lower  Yukon River Area Near Galena,
    Alaska,  reprinted from Biuletvn Peryglac.ialnv.  nr 11,  Lodz 1962.

7.  R. Cormack,  Thermal  Modeling for Freezeback Disposal of Drilling Wastes on
    Alaska's North  Slope,  The Northern Engineer. Vol. 19,  No. 2, Summer 1987.

8.  R.L.  Berg,  Thermoinsulating Media Within Embankments on Perennially Frozen
    Soil,  A Ph.D.  dissertation  presented  to the faculty  of the University of
    Alaska,  1973,  172 pp.
                                      292

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E&P WASTE  MANAGEMENT IN THE COMPLEX CALIFORNIA REGULATORY ENVIRONMENT -
AN OIL AND GAS  INDUSTRY PERSPECTIVE
W. A.  Brommelsiek
Manager,  Environment,  Safety,  Fire and Health
Chevron  U.S.A.  Inc.,  Production Department
San Francisco,  California
J. P.  Wiggin
Sr. Staff Engineer,  Regulatory Affairs
Exxon  Company,  U.S.A.,  Western Production Division
Thousand Oaks,  California
INTRODUCTION

The California regulatory  environment  presents unique  challenges for waste
management operations  in  the oil and  gas exploration  and  production (E&P)
industry.  Major production facilities  are  located  in  environments that vary
widely from desert areas and fragile coastal  dunes, to the densely urbanized
Los Angeles  Basin.  Waste  management  operations  in  these  areas must  be
carried out  in a  manner  that  is  both  environmentally sensitive  and cost
effective. Operators  must  comply  with  the  requirements   of the  complex
California regulatory framework  which  is separate from,  and typically more
stringent  than, the federal waste management  framework (RCRA). Additionally,
California regulations do  not include any exemption for E&P waste comparable
to that found under_RCRA.

Industry is meeting this regulatory  challenge  through continued development
of comprehensive waste  management  programs staffed by  career environmental
professionals.  Environmentally sound approaches to  beneficially reusing and
recycling  waste streams have been developed to reduce the volume of material
that  must  be   disposed.   Programs   to  reduce  waste  toxicity  have  been
implemented.  Additionally,  comprehensive  audit  and  training  programs  are
being  conducted to  ensure that  waste  is  being  managed effectively  and in
compliance with applicable regulations. Industry,  working though the Western
States  Petroleum   Association  (WSPA),  has   also  been  proactive  in  the
development of  waste management regulations that are workable and protective
of human  health  and  the  environment.  Emerging issues  for  E&P  operations
include new requirements for the management  of wastes that  contain organics
(mandated  pretreatment  prior  to land  disposal and  imposition of emerging
                                    293

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organic toxicity characteristic standards);  risk-based soil  clean-up levels;
and imposition of corrective action programs at  E&P facilities.


INDUSTRY OVERVIEW

California is a major oil and gas producing  state,  ranking fourth nationally
in oil production.  In  1988,  California's 44,000 oil and gas  wells  produced
387 million  barrels  of oil  and 2.8  billion  barrels of water.  Thermally
enhanced production  (both cyclic  and  steam flood) accounted  for  186 million
barrels  of this  total  oil  production  and  waterflcoding  accounted for 57
million barrels. These enhanced oil recovery (EOR)  projects  injected a  total
of 1.8 billion barrels of water-1

Total   annual  waste  volumes  from  E&P operations   are  estimated to  be
approximately  one  billion  barrels  of  produced  water  (excluding  produced
waters beneficially  reused  in  EOR);  700,000  tons  of tank bottoms  and  other
associated  wastes   (including  scrubber  fluids  and  and  water  softener
regeneration brine); and 300,000 tons of drilling muds.2

The magnitude of these waste streams gives some indication of the management
challenge facing both industry and state regulatory  agencies.  An  overview of
the principal  agencies which regulate  waste management  operations and the
overall regulatory framework follows.


REGULATORY FRAMEWORK

The regulatory  framework governing  waste management in California  presents
something of a paradox.  The  regulations, which  are administered  by  a number
of independent agencies, are complex and lack an exemption analogous to the
federal  RCRA provision  that exempts  E&P  waste  from being  classified  as
hazardous  waste.3 The  regulations  for  California-only hazardous waste  do
not, however, incorporate the rigid  "listing" approach that is found in the
RCRA regulations. The  regulatory  framework  therefore  is  flexible enough  in
most  cases to  altow operators to  manage  waste streams  in  a manner  that
reflects site-specific considerations.

Four  agencies  oversee  the  majority of the  requirements  governing  waste
management:  the  Department  of  Health  Services,  the  State  Water  Resources
Control  Board  and  associated  Regional  Water Quality Control  Boards, the
Division  of  Oil  and Gas,  and  the  California  Integrated Waste  Management
Board.  The relationship  between each   of  these  agencies with  respect  to
management of E&P waste  is  depicted  in  Fig.  1.  While the  four  agencies have
overlapping   jurisdiction   for  E&P    waste  management,    memoranda  of
understanding  among  the  agencies  reduce  duplicative   regulation.4  (The
"sieves" in  Fig.  1  define  each  agencies operational  involvement  in  various
E&P waste streams.)

Specifics regarding each agency's role in E&P waste management  follow.
                                   294

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Department of Health Services  (DHS)

The  primary  role of the DHS  is  the administration  of the  state hazardous
waste program. Waste is  defined statutorily as hazardous if, "because of  its
quantity,    concentration,     or    physical,    chemical,     or   infectious
characteristics  [it] may either:  A) Cause  or  significantly contribute to  an
increase  in  mortality  or serious...illness.  B) Pose  a  substantial...hazard
to human  health  or environment when  improperly...managed."5 The DHS has also
promulgated  recjulatory  criteria   used  to  classify  waste  as  hazardous   or
non-hazardous.°  Due  to  the lack  of a  California E&P  exemption,  some   E&P
wastes  are hazardous under  these  regulatory criteria.

At present,  the  DHS  does not  have  authorization to manage  the RCRA program
in California; accordingly  operators  must  comply with  both state and federal
regulations.  The  DHS   is   currently  working  to  develop  an   integrated
regulatory framework and will  likely  obtain authorization  to manage the RCRA
program within   the  next year.  The  oil   industry,  through  WSPA, has  been
heavily involved in this massive  regulatory development  effort (discussed  in
subsequent section).

As noted  above,  there are no  "listed" wastes  in California analogous to RCRA
listed  wastes. The regulations do,  however, include lists  of waste  that  may
be hazardous. These lists include drilling mud and tank  bottoms.7 California
has  developed detailed  scientific  criteria  for determining  if  a waste   is
hazardous. °   Operators   must  determine   that  a  waste   is   hazardous   or
nonhazardous  based on  laboratory  testing or knowledge of  the waste  stream.9
Laboratory analysis  includes  testing for  toxicity, ignitability,  reactivity
and  corrosivity. Toxicity testing includes testing for  aquatic toxicity  (96
hour LC50 <  500  mg/L)   and   testing  for  specified  organic  and  inorganic
chemicals. The  heavy metals test  is  performed  at  pH  5.0  with digestion   in
citric  acid   (except  for chromium  VI  which  is done in  deionized  water).
Table  1 provides the heavy  metal  limits  for hazardous  waste classification.

State Water Resources Control  Board  (SWRCB)

The  SWRCB is  primarily responsible for  the protection of  the  state's  water
resources (including  groundwater), and  preservation of beneficial   uses  of
those  waters. The  state program  is  implemented by  nine  semi-autonomous
Regional  Water Quality Control Boards (RWQCB). In  the  waste area,  the RWQCBs
are  responsible  for  regulating   and  permitting  discharges  to  land  (at
classified  and  unclassified  waste   management  units   or  land  disposal
facilities) and  to water.10 RWQCBs also  administer the federal  NPDES program
and  the  state underground  injection program  (except Class II wells).  The
RWQCBs  also  develop "Basin Plans" for  the maintenance and  improvement  of
surface and ground water quality.11  All  discharges within  a  basin which  may
impact  waters  of the  state are required  to  be  consistent with  the  Plan's
goals.

The  SWRCB maintains a waste classification framework which is related to  the
DHS  scheme and primarily focuses  on nonhazardous waste.   Nonhazardous  waste
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is further  delineated as  "designated", "non-hazardous  solid",  or "inert".
Designated  waste,  which may  include drilling  muds  and  tank  bottoms  under
certain  conditions,   has  separate  management  requirements  from  solid  and
inert waste.

The SWRCB has adopted a policy identifying  "sources  of drinking water"  which
specifies  that,  with  limited   exceptions,   al_L waters  of  the  state  are
considered  to  be  sources of municipal  or  domestic drinking  water (existing
or  potential).12   The policy  provides  exemptions  for  some  waters which,
because  of  existing  contamination,  quantity, or  other  considerations  make
them unsuitable as drinking water sources.  Aquifers which are  exempt  under
the underground injection control program are not  sources  of  drinking water.
Groundwaters containing  3000 ppm or  greater total  dissolved solids can be
exempted based  on  beneficial use designations.

A  related  regulatory framework  for  the  protection  of  drinking  water is
Proposition 65, the Safe Drinking Water and  Toxic  Enforcement Act of 1986.13
Although  the   Health  and  Welfare  Agency   is  primarily  responsible   for
implementing  Proposition  65,  key  terms  are  defined in  SWRCB  plans   and
policies.  Passed   by  the voters  as  a  popular  ballot initiative,  the  law
prohibits the  discharge  of chemicals  into water or  onto  land when  that  the
chemical will  pass or probably will pass into  any source of drinking water
and  pose a "significant risk"  of causing cancer  or reproductive  toxicity.
Over 200 chemicals,   including benzene, have been  identified by the state.
The  law potentially  impacts E&P operations  in  several  ways, including  pit
construction and operation, and  produced water disposal. Assuring compliance
has been a  concern to industry because  of the ambiguity of  the  law.

Department  of Conservation  -- Division  of Oil and  Gas  (DOG)

Charged  with   responsibility for management and conservation of  the state's
oil,  gas  and   geothermal   resources,   the   DOG  permits  new  oil,  gas   and
geothermal  wells,  mechanical  modifications to existing  wells,  and   well
abandonments.14 The  DOG has primacy  from the  EPA under  the Safe  Drinking
Water Act to administer  the underground injection control  (UIC)  program for
Class  II  wells. 15 The DOG program has  received  high marks from  the EPA for
environmental  (groundwater) protection.

The  DOG also has  environmental  oversight responsibilities  for  all surface
production  facilities (including  well   locations,  sumps,  and  above ground
tanks);   oilfield   waste/refuse   management;    and  site  restoration.16
Additionally,  the DOG  requires  oil  spill   contingency  plans  for all   tank
settings where  releases might impact public  health or  the  environment.

California  Integrated Waste Management  Board (WMB)

The  WMB regulates  landfill  disposal   of nonhazardous industrial waste  and
municipal  solid  waste.1'   County  agencies   typically  serve  as  the   local
enforcement agency for E&P waste, granting permits for waste  disposal sites.
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The WMB jurisdiction  overlaps with that of the  SWRCB,  although the  focus  of
the two regulatory programs  differs.


INDUSTRY WASTE MANAGEMENT  PRACTICES

Waste  management practices  are dictated  by the  geographic  setting of the
facilities  and  the  applicable  state,  regional,  and  local  regulations.
Typical  industry  practices  are outlined  below  for  the  major  E&P waste
streams.

Produced Water

Produced water  is by  far  the largest  waste  volume generated in California
oil and gas production. Of the approximately 2.8 billion barrels produced  in
1988,  over 60% was utilized  in secondary and thermally enhanced oil  recovery
projects.  This  use  of  produced  water  also   results   in  ancillary waste
generation  (through  filtering, treating and  softening),  which are discussed
later.

In addition  to  the  produced water injected  in enhanced  recovery projects,
678 million barrels were  injected in  1988 for disposal  in Class II injection
wells.  The remaining  volume  of produced water was disposed to publicly owned
treatment works  (POTWs);  discharged  to the ocean; used  for agricultural  or
industrial  purposes;  or disposed in  evaporation  and percolation  ponds  (in
areas  where  no  groundwater  exists or  where  beneficial   uses  of groundwater
would  not be  impaired).

The  EOR injection programs  and  injection  for disposal  are  regulated by the
Division of  Oil  and  Gas  consistent with  the federal  Class II  UIC  program.
All  surface discharges of produced water  are regulated by  both  the  DOG and
the RWQCBs. RWQCBs have primary regulatory authority over surface discharges
and  issue  the  required waste discharge  permits. Discharges to  POTWs  are
managed by permits  between the dischargers and  the  receiving  sewer  systems.
These  permits typically   specify  stringent  discharge  limits for   produced
water  constituents (e.g.,  oil  and grease,  ammonia, dissolved ^S).

Drilling Muds and Cuttings

The  disposal   of  muds and   cuttings  is  regulated  by  the  four   agencies
discussed above  and depicted in  Fig.  1.

In areas  where  there  are  groundwater  concerns, mud pits  must be  lined  or
tanks  must  be  used   to  manage  mud   systems  onsite.   Where   there   are   no
groundwater concerns,  state  regulations permit  the discharge of nonhazardous
muds and cuttings  to onsite  sumps  provided  all  the wastes  are removed from
the sump prior to closure, or all  free liquids are removed and  the  sump  is
promptly closed.  The  practice of burying  solids is only  permitted in areas
where  beneficial  uses of groundwater will  not  be  impaired.  Since  only
                                    297

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nonhazardous  muds  and  cuttings  may  be  disposed  onsite,  operators  are
required to verify that materials  left  in  the  pit  are indeed nonhazardous.

It  is  important  to  ensure  from  an  operational   point of  view  that no
extraneous  materials  enter  the mud  pits  (such as  pipe dope  cans,  waste
lubricating oils, mud sacks,  solvents,  or excess  treating chemicals).  The
presence of extraneous materials could  result in the entire contents  of the
pit being considered hazardous.

In  fields  where  onsite  disposal  is  not  permitted,  such  as  in  urban  and
agricultural  areas,  the  muds and  cuttings must  be  disposed in  permitted
disposal facilities. Operators  are now  using solids removal equipment  (belt
and  filter  presses, centrifuges,  etc.) to  separate solids  and liquids at
some  sites. The  liquids  are injected  in Class  II  wells  and  the  solids
disposed of in permitted facilities. This  practice  significantly reduces the
total  volume  of  waste  that  must  be   transported   to offsite   disposal
facilities.

Some  operators   also  utilize  company-owned,   permitted   land   treatment
facilities  to manage  their muds and cuttings.  In  this process, the liquids
are  allowed to  evaporate, the  metals  are adsorbed  onto  clay particles  and
organic  materials biodegrade.  Solidification  and  immobilization   processes
have  also been utilized  to  treat muds and cuttings, chemically  fixing  metal
and  organic constituents.  Nonhazardous  muds  and  cuttings  treated in  this
manner are  being beneficially reused for daily municipal  landfill cover.

Industry has  worked  cooperatively  with  the DHS  to  develop  an approved  list
of drilling mud additives which, when used in concentrations typically  found
in  drilling operations,  will  not  cause the  muds  and  cuttings  to  fail  the
DHS's hazardous  waste testing  criteria.  If additives  other than  the  those
listed  are  used,  the  muds  and cuttings must  be tested  to  ensure  they  are
nonhazardous.  The   approved  additives  list   is   published   in   the   API
Environmental Guidance Document.1°

Muds  and  cuttings which  fail  the  hazardous  waste  test  are  disposed  of in
permitted hazardous  waste disposal facilities.  General  industry experience
is that very few muds  fail the DHS characteristic tests.

Well  Workover and Completion  Fluids

Spent wprkpver and  completion fluids  include weighting agents,  surfactants,
acids, inhibitors, and gels.

These fluids  are regulated  in the  same  manner  as muds and  cuttings.  The
fluids are  typically produced through the  flowlines  to  production facilities
and  injected into Class  II wells.  The nonhazardous  solids that are  separated
from  the  fluids  can be  buried  onsite  in  areas where  the practice has  been
approved  by the  RWQCB.  In  areas  where onsite  disposal  is  not permitted,
management  alternatives  include disposal   in  approved  sites  or treatment to
solidify/immobilize constituents.
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If the wastes are  hazardous  and  are  to be  shipped offsite  for  disposal,
tanks  are  used to  contain the  fluids and  solids.  Offsite  disposal  of  any
hazardous  fluids  or  solids must  be to  permitted hazardous  waste disposal
facilities.

Tank Bottoms and Other Crude  Contaminated Solids

The management of crude  oil  contaminated  solids (tank  and  vessel bottoms,
oil contaminated soils, sump  bottoms,  etc.)  is primarily dictated  by whether
or not the  material  is  hazardous.  Recent experience  indicates  that over
two-thirds  of  these  wastes are nonhazardous.  The wastes  that do fail  the
hazardous waste tests do  so primarily because  of ignitability; the  remainder
fail due  to heavy metal  contamination (usually  lead, arsenic,  vanadium,  or
nickel), or reactivity  (release  of hydrogen sulfide).

Nonhazardous  oil  contaminated  solids must  be managed  in  a way  which will
protect  the  environment.  Operators  are  in   some   cases  processing   these
materials  to  recover oil,  utilizing solvent  (condensate)  treatment methods
and mechanical  separation equipment (filter and  belt presses and high  speed
centrifuges).  The  remaining solids are either  land disposed  (including land
farming)  or utilized onsite  as  road  base  or  berm material.  Some operators
have installed equipment  to beneficially use the solids  to make road paving
material  similar to commercially available products.

Substantial volumes of  oily soils  are being generated in  E&P site clean-ups
as regulatory  agencies   impose  clean-up  standards  which  are  increasingly
stringent.  Mandated  clean-up levels  vary from 0-10,000 ppm  total  petroleum
hydrocarbons,  based  on  land use,  hydrogeology, and the policy  of the  local
enforcement agencies. Agencies have in some cases  specified  clean-up levels
which  go  far  beyond  what  is required to  protect  the  environment and without
considering  natural  biodegradation  processes.  WSPA is   supporting  a DHS
initiative  to  implement  a   risk-based  approach   to   clean-up  based  on
site-specific  considerations.

California  is  in the  process  of  promulgating regulations which will prohibit
the disposal  of hazardous  petroleum  waste without pretreatment  for removal
of organic constituents.  These regulations,  which are part of the California
land disposal  restrictions program,  are analogous to the federal  land ban
for  third-third   RCRA   waste   (i.e.,   treatment   to    remove   hazardous
characteristics).19   Complex   waste  treatment   facilities  (e.g.,  solvent
extraction  units  for  removing  petroleum  from waste)   will  have  to  be
constructed at sites  where significant  volumes of hazardous  oily waste are
generated.

Other  Associated Wastes

Thermally enhanced oil recovery  projects  generate several  waste streams. The
highest  volume streams are water  softener regenerate  brine, water  filter
backwash  and  filter media,   and  SO?  scrubber  liquor.  The  DOG,  with
concurrence from the  EPA, has approved  these  fluids  for  injection in  Class
                                    299

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II wells. The fluids are either commingled with produced  water for injection
or  injected  in  dedicated  wells.  In  some  cases,  $02   scrubber  liquor  is
beneficially  reused   as   an  oxygen  scavenger   since  it   contains   high
concentrations of sodium bisulfite.  Filter media is managed  as  nonhazardous
solid waste and disposed in approved industrial waste disposal  sites.

The  treatment  of  produced water  to meet  permit  limits for discharge  to
surface waters or POTWs also  results in  the generation of wastes.  Depending
on the permit limit for oil and grease discharge,  the water may  be processed
in gas or  air  flotation units in addition  to  primary separation  units. The
flocculated  materials  resulting  from this  process  may  be  reprocessed  to
recover additional oil  or managed as oil contaminated solids.  Soluble oil  is
also  occasionally  a  discharge  problem.  In  one  case,  an   operator   is
processing produced water  through carbon filters  to meet discharge limits.
The spent carbon is sent to a recycler for regeneration and reuse.

Sweet  gas  production  frequently must  be  treated  to  remove  water vapor.
Dehydration  is  usually accomplished  by using  either liquid  desiccants such
as glycol  or solid  desiccants such as alumina or  silica  gels, or molecular
sieves. Spent glycol must  be managed as a hazardous waste,  and can be sent
to a  recycler  for regeneration and reuse. The solid desiccants are managed
as  nonhazardous  solid wastes  as they  do  not  fail  the  hazardous  waste
characteristic tests.

Industrial Wastes

Thermally enhanced oil  recovery  projects  also  generate  several unique waste
streams.  The   refractory   bricks  which   line  generator  fire  boxes  are
periodically  replaced. These bricks  have  had  a  mixed  history  of  being
hazardous  and  nonhazardous  waste.   In   general,  bricks   from  gas-fired
generators are nonhazardous, while those from oil-fired generators are often
found  to  be hazardous  due  to  heavy  metals  such  as  lead,  nickel,  and
vanadium. Periodically, the internal  sections of steam generators  are washed
to remove buildup of soot and other materials. The wastewater  resulting from
this  practice often contains  concentrations  of heavy metals  which causes  it
to be hazardous. Some  operators  treat these  fluids to concentrate the heavy
metals and send the concentrate either to  permitted recyclers or hazardous
waste disposal facilities.

Chemical drums have historically been a major  waste management issue in the
oil  fields.  Since California  treats empty chemical  containers differently
than the EPA, the empty drums that contained hazardous materials are in some
cases considered  hazardous  wastes.  Most operators  now  have  drum  management
programs in  place to  minimize  the  number of  drums used  in  the oil fields
through use of bulk chemical tanks (which are refilled when empty).  Drums  of
chemicals  are  accepted only  from suppliers  who will  take  back  the empty
drums.

Nonhazardous waste  lubricating oils  from  compressors,  turbines,  pumps and
other moving equipment are  typically  recycled  by  mixing them with crude oil
                                     300

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streams for transportation to refineries.  Under current  law,  motor vehicle
engine oil and certain non-halogenated  solvents are considered hazardous  and
must be sent to an offsite recycler or sent to  a refinery which is owned  by
the  generator-20  Industry,  working through  WSPA,  is  assisting the  DHS  in
sponsoring legislation which will  allow the environmentally sound recycling
of lease-generated  used  engine  oils and  non-halogenated  solvents  in  any
refinery  (not solely the generator's).

Spent  halogenated solvents  present  a  special  waste management  challenge.
Onsite recycling  in the crude  stream  is  not allowed under the regulations.21
Additionally,  few  offsite   recyclers   will   accept   halogenated  solvents.
Therefore, operators  have made  it  standard practice  to avoid use  of these
solvents. When used, they  must be segregated from  other recyclable oils and
solvents.  Disposal   is  by  offsite  recycling  at  a   permitted  recycler   or
incineration.


INDUSTRY  INVOLVEMENT IN THE  REGULATORY  DEVELOPMENT  PROCESS

Industry  and regulators   are  often  characterized  as  being  at  odds,  each
having completely opposing goals in the regulatory development  process. Our
experience  indicates  that when  industry  and  regulators communicate  their
objectives  and   constraints,   more  effective  regulations   can   often  be
developed.

The  oil industry  has committed considerable resources to providing technical
input  to  the agencies  and  legislature to  assist  in  their development  of
effective,  environmentally   sound   regulations.  WSPA's   Waste   Management
Committee has been  an active  participant  in the various  citizen's  advisory
boards  established  by  the  agencies  to  provide  rnput  to  the  regulatory
development process. Two recent  efforts  are discussed below.

Development  of  an effective yet practical waste  minimization program has
been the  goal of  an extensive industry effort over the  past  two  years.  WSPA
worked extensively  with  legislative  staff on  an approach that  is  feasible
from industry's perspective  and  meets regulatory objectives.  WSPA supported
the  waste minimization  bill  that  was  ultimately  passed in  1988,  and   is
currently working with  the  regulatory  agencies  to  develop  implementing
regulations. The  law requires  the development  of facility waste minimization
plans and periodic performance assessments to review  and  oversee  industry's
progress  in minimizing  waste.  It   provides  flexibility for  operators  to
develop their own plans  to  meet waste  minimization objectives,  considering
facility  economics  and  other  factors.  Numerical  goals  are not  mandated,
making  implementation  of  the   law  much  more  effective   in   extractive
industries like E&P,  and  more workable  than the current  waste  minimization
proposals being considered in Congress.

For the last two years WSPA  has  also  been  actively  involved with DHS efforts
to recodify  the  California  hazardous  waste regulations  and integrate  the
RGRA   program   into  the   state   regulatory   framework   to  obtain   RCRA
                                    301

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authorization from the EPA. This massive  regulatory package (over 3000 pages
with several  major re-writes  and  re-proposals)  has required  a  significant
commitment of WSPA resources to provide substantive input to the agency.  The
process has  yielded  a set  of  regulations that  are more workable  from  both
the agency's and industry's perspective.

A key  industry  issue in both  of  these efforts  has been the development  of
regulations  which industry can  comply  with  on  a consistent  basis.   Our
experience is that regulators  often do not  fully appreciate the  importance
of strict  compliance  to corporations, or the difficulties  and  frustrations
that can  arise  when  corporate  compliance  staffs  are  forced  to  implement
regulations that are not based on good science.

Industry's  ability to  maintain strong  compliance  programs is  also being
threatened by the  deluge of waste  management statutes that  have been  passed
by  the  legislature   in  recent years.   Regulatory  agencies,   as   well   as
industry,  are scrambling  to keep up with these new statutory  requirements.
The statutes  are often unnecessarily detailed,  and sometimes  contradictory
with existing law or regulations.

Several major emerging issues will  require  a  commitment by government and
industry to  work together  if  sound regulatory  policy  is to be developed. A
significant  issue  for industry is  the  possible  application of the federal
organic toxicity characteristic to California E&P wastes. The impact of such
an action  would  be  particularly acute  with respect  to the  management  of
produced water which is currently regulated  by  the  DOG in an environmentally
sound  and  effective  program.  Addition of  this  hazardous waste criterion to
the  current  regulatory  picture   would   detract  significantly  from  the
flexible,  yet   environmentally   protective,    regulatory   framework  that
currently  exists, and  from  the  ability of   the  California  oil   and  gas
industry to be competitive with operations in other  states.

Another  major  issue  for  industry  is  a  recent move   by  the  agencies  to
formally bring  E&P facilities  into the  corrective action  program.  Agency
proposals  may require  facilities  which  employ specified  onsite hazardous
waste  treatment  processes  (e.g.,  elementary  neutralization,  wastewater
treatment,   drum  rinsing)   to  conduct   environmental   investigations  to
determine  if hazardous  constituents  have  been released  anywhere  on  the
lease.  Where releases have occurred, clean-ups will  be required. Industry  is
advocating a program whereby corrective action  would only be undertaken for
significant releases.


ACKNOWLEDGEMENTS

The authors  would  like to acknowledge the significant  contribution to this
paper made by Stephen  P.  Piatek of Huntway  Refining Company.  We would also
like to gratefully acknowledge the contributions made  by Don 0. Culbertson
and Jeanette  F. NewVille  of  Chevron  U.S.A  Inc.,  and  Meg  Rosegay-Kott   of
Pillsbury,  Madison & Sutro.
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References

1.    Seventy-Fourth  Annual  Report  of the  State Oil  and Gas  Supervisor -
     1988.  California  Dept.   of  Conservation,  Div.   of   Oil   and  Gas,
     Sacramento, 1988.
2.    Evaluation of  Alternate  Technologies  to  Land Disposal  of Oily Waste.
     Western States  Petroleum Association,  1987.
3.    40 C.F.R. § 261.4(b)(5).
4.    E.g.,   Memorandum  of   Agreement   Between  the   DHS   &  SWRCB   on
     Implementation  of the Hazardous  Waste  Program.  1986.
5.    Cal. Health & Safety Code  §  25117.
6.    22 Cal. Code Regs. § 66305.
7.    22 Cal. Code Regs. § 66680.
8.    22 Cal. Code Regs. §§ 66696-66723.
9.    22 Cal. Code Regs. § 66471.
10.   Cal. Water Code § 13263.
11.   Cal. Water Code § 13240.
12.   SWRCB  Resolution  No.  88-63,  Adoption  of  Policy Entitled "Sources  of
     Drinking Water." May 19, 1988.
13.   Cal.  Health  &  Safety  Code  §§ 25249.13,  25180.7,  25192,  25189.5(d);
     22 Cal. Code Regs. § 12000,  et seq.
14.   14 Cal. Code Regs. §§ 1712-1724.10,  1900-1993.
15.   40 C.F.R. § 147.250.
16.   14 Cal. Code Regs. §§ 1750-1779.
17.   14 Cal. Code Regs. § 18720,  et seq.
18.   API  Environmental Guidance Document  -- Onshore  Solid Waste  Management
     in Exploration  and Production Operations.  API,  Washington, D.C., 1989.
19.   Cal. Health & Safety Code  §  25179.6.
                                     303

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20.   Cal. Health & Safety Code § 25143.2(d)(2)(B).

21.   22  Cal.   Code   Regs.  §  66796(b)(2)(A);  Cal.  Health  &  Safety  Code
      § 25143.2(e)(3).
                                    304

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TABLE I - CALIFORNIA ASSESSMENT MANUAL -  HEAVY METAL LIMITS


   SUBSTANCE                 TTLC*                 STLC**
                             (mg/kg)                (mg/1)

  Antimony (Sb)                 500                    15
  Arsenic (As)                  500                   5.0
  Barium (Ba)                 10000                   100
  Beryllium (Be)                75                  0.75
  Cadmium (Cd)                  100                   1.0
  Chromium (VI)                 500                   5.0
  Chromium (Cr)                2500                   560
  Chromium (III)
  Cobalt (Co)                  80OO                    80
  Copper (Cu)                  2500                    25
  Fluoride (F)                18000                   180
  Lead (Pb)                    1000                   5.0
  Mercury (Hg)                   20                   0.2
  Molybdenum (Mo)             3500                   350
  Nickel (Ni)                  2000                    20
  Selenium (Se)                 100                   1.0
  Silver (Ag)                   500                   5.0
  Thallium (Ti)                 700                   7.0
  Vanadium (V)                 2400                    24
  Zinc (Zn)                    5000                   250


  TTLC - Total Threshold Limit Concentration:  If the total
  sample concentration exceeds this level, the material is
  hazardous.

**
  STLC -  Soluble  Threshold Limit  Concentration:  If  the
  Waste Extraction  Test (WET)  concentration exceeds  this
  value,  the material is hazardous.
                             305

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                                   FIGURE 1
                                                                      MRA01-10
          E&P WASTE MANAGEMENT REGULATORY FRAMEWORK
              E&P WASTE STREAM
                  DEPT. OF HEALTH
                     SERVICES
NONHAZARDOUS WASTE
   REGULATED
  WASTE STREAM

HAZARDOUS WASTE
                  WATER BOARD &
                  DfV. OF OIL & GAS
                               DESIGNATED & SOLID
                                     WASTE
SOLID AND INERT WASTE
        INERT WASTE
                   WASTE MQMT.
                     BOARD
   REGULATED
DISPOSAL OPTIONS
                   CLASS I DISPOSAL FACILITIES
                   RECYCLING
                   ASPHALT INCORPORATION
                   CLASS ll/lll DISPOSAL FACILITIES
                   CLASS II DISPOSAL WELLS
                   (APPROVED FLUIDS ONLY)
                   ONSITE LAND DISPOSAL
                   RECYCLING/BENEFICIAL REUSE
                   CLASS III DISPOSAL FACILITIES
                   ONSITE LAND DISPOSAL
                   RECYCLING/BENEFICIAL REUSE
                                     -14-

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AN EPA PERSPECTIVE ON CURRENT  RCRA  ENFORCEMENT TRENDS AND THEIR
      APPLICATION TO OIL AND  GAS PRODUCTION WASTES
Charles W. Perry and Kenneth  Gigliello
U.S. Environmental Protection Agency
RCRA Enforcement Division
401 M Street, S.W.,  (OS-520)
Washington, D.C., 20460


Introduction

The purpose of this paper  is  to present an introduction and
overview  of the RCRA enforcement program,  both generally and
specifically  as it applies to the management and disposal of oil
and gas exploration and  production (E&P)  wastes,

Most E&P  wastes are non  hazardous solids,  liquids or dissolved
gases that are covered by  RCRA regulations.  The Resource
Conservation  and Recovery  Act (RCRA) is the statute on which the
RCRA Enforcement Division  of  the Office of Waste Programs
Enforcement operates,  under the Office of Solid Waste and
Emergency Response  (OSWER).

We will discuss three  main areas;

     I.    A general  overview  of the universe of E&P wastes,
     II.   A review of  the  existing RCRA Subtitle C hazardous
          waste enforcement program, and
     III. A discussion of  how the E&P wastes are impacted by the
          existing Subtitle C enforcement program and the
          emerging-Subtitle D solid waste enforcement program.


I. The Universe of E&P Wastes

By any measure, the  U.S. oil  and gas producing  industry  is  big.
It produces roughly  eight  million barrels of crude oil daily,  and
44 billion standard  cubic  feet of natural gas.  This
production comes  from  roughly 800,000 wells at  over 70,000  sites.
(There are many more  inactive and abandoned wells.)

The biggest volume waste is salt water, produced concomitantly
with  crude oil, at roughly 21 billion barrels annually.   Most  of
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this is reinjected into the oil-bearing sands to stimulate more
crude oil production.  The next largest volume waste is about 361
million barrels annually of drilling fluids that comes from
drilling about 70,000 new wells, or reworking old ones.

There are many smaller volume wastes that have been divided into
exempt and non-exempt groups in an EPA Regulatory Determination
dated June 29, 1988.  Most E&P wastes are non-hazardous, as
mentioned above, and therefore would be regulated as Subtitle D
solid wastes under RCRA and the oil states* regulations.  Also,
the EPA Office of Water regulates and enforces two closely-
related programs important to E&P wastes.  They are the National
Pollutant Discharge Elimination System (NPDES), and the
Underground Injection Control program for disposing of salt
water.

The NPDES program regulates waste water from oil and gas
production discharged to navigable waterways of the United States
through a discharged permit system.  The UIC program regulates
disposal of salt water from oil and gas production, enhanced oil
recovery wells, and wells used for the underground storage of
crude oil, liquified petroleum gas (LPG), and other liquid
hydrocarbon products by establishing a system to control the
permitting, construction, operation, and closure of injection
wells.

The exempt group specified by the Regulatory Determination
mentioned above is primarily high-volume low-toxicity waste that
is clearly Subtitle D by today's definitions.  The non-exempt
group wastes are potentially all Subtitle C until testing proves
otherwise.  There are at this time 26 exempt wastes and 21 non-
exempt wastes... Table 1 attached gives the wastes in each
category.


II. Review of Existing Subtitle C Hazardous Waste Enforcement
Program

RCRA enforcement has to date largely focussed on Subtitle C
hazardous wastes.  Subtitle D solid wastes are evolving into a
larger part of the overall enforcement picture.  RCRA  is a
complex statute covering many different types of wastes
including:
                               308

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   o  Hazardous waste under  Subtitle C

   o  Solid Wastes  (non-hazardous  and special wastes)  under
      Subtitle D

   o  Underground storage  tanks  under Subtitle I

   o  Medical waste under  Subtitle J

Each of these Subtitles  establish a different Federal/State
relationship and a different  enforcement scheme.   Only Subtitles
C and D will be discussed here.   Figure 1 shows how the volume of
E&P wastes compare with  others  in the Subtitle D universe.   Under
Subtitle D where most of the  E&P  waste is currently regulated,
states have by far the largest  enforcement role with only a very
limited Federal authority.*

EPA's Subtitle C enforcement  program includes the following
components:  monitoring  compliance  at facilities and taking
enforcement action against  violations.  The next two paragraphs
briefly describe this process.

                     Compliance  Monitoring

Section 3007 of RCRA gives  EPA, an  authorized state, or a
representative of either authority  to conduct inspections,
including examining  facility  records and obtaining samples.  The
two primary methods by which  EPA  or the states monitor compliance
at RCRA facilities is by inspections or reviewing reports
submitted by the facilities.  The frequency of these inspections
varies depending on the  type  of the facility.

                      Enforcement  Actions

The primary goal of enforcement actions is to bring facilities
into compliance and  force the facilities to stay in compliance.

*  Federal enforcement authority  occurs only when the EPA
Administrator determines that a state has not adopted a program
adequate to address solid waste management facilities that may
receive household hazardous waste or hazardous waste from small
quantity generators.
                              309

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There are a number of enforcement options available under RCRA
Subtitle C.  These include:

    o  Informal actions such as written notices

    o  Administrative actions such as an order or hearing

    o  Civil actions filed in court

    o  Criminal actions against firms or individuals

The complex relationship between EPA compliance monitoring and
the civil enforcement process for RCRA is shown in Figure 2.
This begins with an inspection report of violation(s).  A
decision to take enforcement action is made in which the state
involved may take the lead.  In these cases, the state procedures
would be followed.  An increased emphasis within RCRA is being
placed on civil penalties as an effective enforcement tool. In
general, penalties are rising for cases involving Subtitle C
wastes.  Although not uniform among the oil states, there has
been a general tightening of enforcement in the disposal of E&P
wastes in recent years.
III. Impact of Existing Subtitle C Program and Evolving Subtitle
p Procrram on E&P Wastes

Impact of Subtitle C

As discussed previously, some E&P wastes are non-exempt under the
Subtitle C program.  In other words, E&P wastes that are listed
as non-exempt are potentially Subtitle C hazardous wastes.  A few
examples of these are:

     o painting wastes

     o waste solvents

     o used equipment lubricating oils

Generators of non-exempt wastes are required to determine  if the
waste is hazardous and, if so, properly manage and dispose of the
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wastes according to the hazardous waste  regulations.   These
regulations include requirements for  proper management and the
restrictions on land disposal.  This  is  an important  fact that
oil and gas production facilities must be  aware of and comply
with as potential generators  of hazardous  waste.

impact of Subtitle D

The basic concept for the RCRA Subtitle  D  program is  that it is a
program that deals primarily  with non-hazardous solid waste.  The
goals of the program are to encourage solid waste management
practices that:

    o Promote environmentally sound  disposal  methods

    o Maximize the reuse of  recoverable resources

    o Foster resource conservation

In the past few years the Office of Solid  Waste (OSW) and OWPE
have begun to focus more attention  on the  management  of the
Subtitle D wastes.  These wastes include among others:

    o Oil and gas wastes           o  Agricultural waste

    o Mining wastes                o  Demolition debris

    o Municipal solid waste        o  Municipal sewage sludge

    o Industrial waste             o  Municipal runoff

OSW and OWPE are focussing a  good amount of resources on three of
these solid wastes: municipal solid waste, mining, and oil and
gas.  We will now discuss the oil and gas  E&P Subtitle D program.

Historically, enforcement of  the management of E&P wastes has
been performed by the States. Various  state agencies have the
enforcement authority and state authorities differ greatly in how
tfie E&P wastes are regulated  and managed.

With this background, OSW and OWPE  have  been working on a number
of initiatives to determine the current  state regulatory and
enforcement mechanisms and for developing  an overall strategy for
regulating and enforcing the  proper management of E&P wastes.
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An appropriate grant has been active since early  1989 with the
Interstate Oil Compact Commission  (IOCC) to develop minimum
generic state technical and administrative criteria for the
management and disposal of E&P wastes.   A separate paper on this
is being presented in this symposium.  The final  report on this
will be completed in December 1990.  Continuing IOCC work in 1991
will be on training of state people, state peer reviews to
promote consistency, and a data base for state oil and gas, and
state environmental agencies.  It  is particularly appropriate to
have IOCC as an organization of the governors and staffs of the
30 oil states performing such tasks for their own benefit as well
as to benefit EPA.

The overall oil and gas strategy is still evolving and being
updated with new information.  In  addition, further definition of
the RCRA Subtitle D role may be expected when the Congress passes
a new RCRA reauthorization bill.   Many expect that this could
occur within the next two years.

Based on the current discussions within the Agency and with the
states, it appears that some of the elements of the RCRA Subtitle
C program may be incorporated into a stronger Subtitle D program.
These elements include a routine compliance monitoring program
and some type of enforcement authority to aid the states in
regulating E&P wastes more thoroughly and with more national
consistency.


Summary and Conclusions

    We have presented a broad picture of RCRA enforcement in
general and as applied to E&P wastes.  The exempt and non-exempt
wastes have been tabulated.  The Subtitle C procedures have been
examined and related to the developing Subtitle D scenario for
E&P wastes.  Some Subtitle C materials will undoubtedly appear
among the non-exempt .wastes.  The  relationship between RCRA
compliance and enforcement has been discussed.

    Conclusions can be drawn that  a growing trend toward more
comprehensive (tighter) enforcement specifically  of exempt and
non-exempt E&P wastes is underway, including the  elimination of
gaps in existing regulations.
                               312

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   EPA's List of Exempt Exploration and Production Wastes

The following wastes,are listed as exempt in EPA's Regulatory Deter-
mination submitted to Congress in June 1988.

      -  Produced water

      .  Drilling Fluids

      .  Drill Cuttings

      •  Rigwash

      .  Drilling fluids and cuttings from offshore operations disposed of
        onshore

      •  Well completion, treatment, and stimulation fluids

      •  Basic sediment and water and other tank bottoms from storage
        facilities that hold product and exempt waste

      -  Accumulated materials such as hydrocarbons, solids, sand, and
        emulsion from production separators, fluid treating vessels, and
        production impoundments

      •  Pit sludges and contaminated bottoms from storage or disposal of
        exempt wastes

      •  Workover wastes

      •  Gas plant dehydration  wastes, including glycol-based
        compounds,  glycol Miters, filter media, backwash, and
        molecular sieves


      •  Gas plant sweetening wastes for sulfur removal, including
        amine, amine filters, amine filter ntoriia, backwash,
        precipitated amine sludge, iron sponge, and hydrogen sulfide
        scrubber liquid and sludge

      •  Qtolmgtowerblowdown

      •  Spent filters, filter media, and backwash (assuming the filter
        itself is not hazardous and the residue in it is from an exempt
        waste stream)

      •  Packing fluids

      •  Produced cand
                              313

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                    TABLE  1   (CONTINUED)


Pipe scale, hydrocarbon solids, hydrates, and other deposits
removed from piping and equipment prior to transportation

Hydrocarbon-bearing sofl

Pigging wastes from gathering lines

Wastes from subsurface gas storage and retrieval, except for the
listed nonexempt wastes
Constituents removed from produced water before it is injected or
otherwise disposed of

Liquid hydrocarbons removed from the production stream but not
from oil refining

Gases removed from the production stream, such as hydrogen
sulfide and carbon dioxide, and volatQizecl hydrocarbons

Materials ejected from a producing well during the process
known as blowdown

Waste crude oil from primary field operations and production
and

Light organic* volatilized from exempt wastes in reserve pits
or impoundments or production equipment
                     314

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                    TABLE   1   (CONTINUED)
EPA's List of Nonexempt Exploration and Production Wastes


   •  Unused fracturing fluids or acids

   .  Gas plant cooling tower cleaning wastes

   .  Painting wastes

   •  Ofl and gas service company wastes, such as empty drums, drum
     rinsate, vacuum truck rinsate, sandblast media, painting
     wastes, spent solvents, spilled chemicals, and waste acids

   •  Vacuum truck ana drum rinsate from trucks and drums
     transporting or containing nonezempt waste

   •  Refinery wastes

   •  Liquid and solid wastes generated by crude ofl and tank bottom
     reclaimers

   •  Used equipment lubrication ofls

   •  Waste compressor ofl, filters, and blowdown

   -  Used hydraulic fluids

   -  Waste solvents

   •  Waste in transportation pipeline-related pits

   •  Causticor acid cleaners

   •  Boiler cleaning wastes

   •  Boiler refractory bricks

        "iTi^fflfajf »mh

          scory ^vi
     Sanitary wastes
     Radioactive to
     Drums, insulation, and miscellaneous
                      315

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                  Subtitle  D   Universe
            AGRICULTURAL WASTE






             MMNQ WASTE
MUNICIPAL SOLID WASTE




      MUNICIPAL SEWAGE SLUDGE







         MUNICIPAL RUNOFF
     NOUSTNAL WASTE
DEMOLITION Deems
MISCELLANEOUS WASTE
                                              aLANDQASWASTE
                              FIGURE  1

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COMPLIANCE MONITORING  & CIVIL ENFORCEMENT
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    Develop Administrative
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                            Writ* Inspection Report
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                            Decision to take enf. action
                             Offer State enforcement
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                                                               State Enforcement
                                                           Administrative
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                                                       Noncomoiianee
                                 FIGURE  2
                                               317

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THE ECONOMIC IMPACTS OF  ENVIRONMENTAL REGULATIONS ON  THE COSTS OF FINDING  AND
DEVELOPING CRUDE OIL RESOURCES IN THE UNITED STATES
M.L. Codec, K. Biglarbigi
ICF Resources Incorporated
9300 Lee Highway
Fairfax, Virginia 22031 1207
Introduction

This paper summarizes the results  of  an assessment of the potential cumulative
economic impacts of environmental  initiatives on U.S. crude oil supplies.  The
assessment involved a  review of selected environmental  initiatives that could
affect U.S. oil and gas operations.   Potential initiatives under the authority
of the Resource Conservation and Recovery Act (RCRA),  the Safe Drinking Water Act
(SDWA), the Clean Water Act  (CWA),  and the Clean Air Act (CAA) were considered.

The estimated incremental unit compliance costs associated with each initiative
were based on the likely practices  required to comply with the initiative.  From
a  review  of   these  initiatives,  three  composite  regulatory  scenarios  were
developed, representing low,  medium,  and high levels of incremental compliance
costs.  The regulatory  initiatives  considered under each  scenario are summarized
in Tables  1 through 4, organized by environmental statute.

The scenarios  proposed  are  intended  to  represent  the   range   of  possible
combinations of  regulations under  consideration,  used  only for estimating the
impact  of  these  initiatives  on U.S.  crude  oil  supplies.    The  estimated unit
compliance costs used in this assessment are based on recent analyses performed
by the Environmental Protection Agency (EPA) and the American Petroleum Institute
(API).

The initial  step in  the  assessment  involved  estimating economic  recovery
potential  under  baseline conditions, which  assumed costs  of  compliance with
environmental regulations currently in place.  The  analysis established recovery
potential under baseline conditions,  providing the reference case against which
the other  scenarios were compared.

Future production from  four  categories of U.S. crude oil  resources was evaluated:
(1) continued  conventional  operations in known fields in the Lower-48 onshore,
(2) future infill drilling and waterflood projects in known fields  in the Lower-
48 onshore, (3) future enhanced oil recovery (EOR) projects in known fields  in
the Lower-48 onshore,  and (4) onshore  and offshore crude oil fields  remaining  to
be discovered  in the Lower-48 and Alaska.  For some categories of resource, two
                                     319

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 levels of technology were  considered --  implemented and  advanced -- described
 below for each resource category.

 Summary of Analytical Approach

 After  currently  proved  reserves are  produced  by conventional   (primary  and
 secondary) recovery methods, nearly  two-thirds of the known U.S.  oil resource
 (over 300 billion barrels)  will remain unrecovered, Fig. 1.  Although not all of
 this  remaining  resource in  place could  ever be  recovered,  it   represents a
 substantial target for future advanced recovery operations.   DOE estimates that
 an additional 76  billion barrels  of  this resource could be recovered at a price
 of $32/Bbl, given some advances in extraction technologies  over  the next 15 years
 (1).

 The analysis  of the production potential of the known oil resource  relies on the
 Tertiary  Oil  Recovery Information System  (TORIS), developed  by  the  National
 Petroleum Council (NPC) and  maintained at  the U.S. Department of  Energy  (DOE)
 Bartlesville Project Office (2).  TORIS utilizes comprehensive oil reservoir data
 bases and detailed engineering and economic  evaluation  models,  considering data
 for individual reservoirs to estimate potential crude oil reserves.   The analysis
 of the undiscovered crude oil resource uses  models  also developed  by DOE in its
 Replacement Costs of  Crude  Oil  (REPCO) Supply Analysis  System (3).   This system
 is designed to determine the cost of finding and developing U.S.  undiscovered
 crude  oil resources,   of  which  over  30   billion barrels  are  economically
 recoverable at $32/Bbl (4,5).

 Cumulative Impacts of Environmental Initiatives

 Industry-wide compliance costs could range from $15 to $79 billion initially, and
 from two to seven billion dollars per year thereafter, assuming  the continuation
 of 1985 levels of drilling  and development (4).  These estimates assume that the
 increased regulations would not affect industry activity except in adding costs
 to operations that would be pursued regardless of the increased regulations.

 However, overall  industry expenditures will  not necessarily increase because of
 increased regulations.  Increased environmental regulations could  lead  to some
 previously viable projects  becoming uneconomic to pursue.  Reduced  development
 of crude  oil  resources could more than offset the  increased compliance costs.
 Ultimately,  overall  industry expenditures  could decrease as  a result of the
-increased regulatory requirements.

 The cumulative impacts of  the  regulatory initiatives  considered are presented
 below for most resource categories and crude oil prices  in terms of the reserves
 that become uneconomic as a result of increased environmental  regulations, and
 the  state and federal  revenues  (from royalty payments,  income  taxes,  and
 production taxes) that are  not collected as a result of lost reserves.

 1.  Current Production.   This analysis is based on estimated future production
 from  individual  reservoirs in nine  major  oil producing  states:    California,
 Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas,  and Wyoming.
 These states  were chosen for  the availability and comprehensiveness  of resource
                                    320

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data, production  data,  and well  counts;  because  the  states represent various
stages  of  oil  resource maturity;  and  because  they  account  for  75%  of  the
remaining oil in place  in  the  Lower-48 states (6).

In the reference case, production  projections assumed that historical activities
to maintain production are continued in the  future.  Oil production  was assumed
to be viable to the economic limit of production, where revenues from oil  sales
just offset associated  production costs.

The  impacts of  the  incremental costs  associated  with  the  regulatory scenarios
were examined by  performing an economic evaluation  of each reservoir over  its
productive life,  assuming  that the reservoir must  incur  the incremental  costs
associated with the  regulatory  scenario analyzed.  The analysis is performed from
the perspective of the operator of the reservoir, who would conduct  a financial
analysis to determine the  impact  on  project profitability from the  incremental
compliance costs over the  life of the  reservoir,  at  the time the regulations go
into effect.  At this point in  time,  each operator would make a decision whether
to continue with  production and incur the  incremental costs of compliance,  or
begin  to shut  in production.  As  a  result, a considerable  portion  of current
production  could  be shut  in immediately after  the  implementation  of  the new
regulations.  For those reservoirs that  continue to operate, the imposition of
additional regulations  could rapidly accelerate the point  of abandonment.

In the 1970s,  oil production in the reservoirs analyzed in the nine states peaked
at about 4.8 million barrels per  day (MMB/D),  Fig.  2.   By  1989, production had
dropped to  2.2 MMB/D,  a   55X  decrease over  the  20 years.   This is based  on
historical, reservoir-by-reservoir production data through  1988  (the  most recent
date reservoir-specific production data  were available).   TORIS predictions  of
reservoir-specific production  were used over the  1990 through 2015 time period.
In this analysis, 1990 was assumed  to  be   the year the  regulations would  be
implemented.

At an oil price  of $20/Bbl, by 1995, production in the reservoirs analyzed in the
nine  states could  drop by  about  320,000  B/D  in the  medium scenario  (a 22%
decrease over  that  in the reference  case).   Production in  1995  could  drop  by
450,000 B/D in the high scenario,  a  31X decrease.   In the  low  scenario, the
impact  of increased regulations on production in  the nine states would be small
(less than a IX change). By the year 2000, production under the medium scenario
could decrease  50,000 B/D  more than the reference case, a 12X decrease.  In the
high scenario,  approximately 190,000 B/D of  production could be lost by 2000, a
decrease of 21Z. The decrease  in production could result in lost reserves of 100
to 1,800 million  barrels   (MMB) in the nine states over the  1990  to 2000  time
period.

The  future recovery of  the known  remaining  crude oil resource presupposes  that
the existing wells and infrastructure  in producing reservoirs will be available
for the application of future recovery technologies.  Moreover, it assumes that
operators  can  retain  production  rights  (leases)  to  produce  oil  from  these
reservoirs.  Once  abandoned, the resource in these  reservoirs becomes  essentially
inaccessible  to  future  development  within  the range  of  prices  generally
                                     321

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considered likely over the next 15 to  20  years,  even with further improvements
in recovery technologies.

The impact of  the  three regulatory scenarios  on the abandonment  of crude oil
resources in the nine states  is shown in Fig. 3.  At $20/Bbl, only an additional
2% more of the resource  in place in the reservoirs  analyzed in the nine states
could  be  immediately  abandoned  (in  1990)  under  the  low scenario  than  that
abandoned in the reference  case  at the same point in  time.   Under the medium
scenario, 23X more of the resource in place could be immediately abandoned, while
30% of the resource  could be immediately  abandoned under the high scenario.

Assuming  no future  development  in  the  reservoirs  considered  takes  place,
increased regulations  can accelerate  the  pace  of oil resource abandonments by
approximately ten years.  This could  result in a significant  reduction in the
time available  for technological development to make a contribution to production
from these reservoirs  currently on the  verge of  abandonment.

2.  Unrecovered Mobile Oil  in Known Fields.   Unrecovered mobile oil  (UMO) is
displaceable by water but left in the reservoir  at the conclusion of conventional
recovery operations  because of reservoir  heterogeneity  or mobility differences
that cause injected water to finger through or around the oil.   Producing the UMO
requires additional wells drilled at closer spacing, to  improve contact with the
bypassed and/or uncontacted oil in order to improve waterflood  sweep and pattern
conformance. Additional improvements in secondary recovery can be achieved with
the application of  polymers,  to help  improve  mobility, or gel treatments, to
reduce permeability  contrasts between  reservoir  layers.

The assessment of the economic impact of environmental regulations on recovering
the UMO resource was  based on analyses  of  700 oil reservoirs in Texas, Oklahoma,
and New Mexico  (7).  The reservoirs are estimated  to have originally contained
112 billion barrels  of oil in place, representing  about one-fifth of the total
resource in place in the U.S.

Three recovery processes for  improving  the producibility of UMO were considered:-
infill drilling, permeability modification treatments  (which directs the flow of
injected water to lower-permeability layers containing mobile oil), and polymer-
augmented waterflooding (where polymers are added to the  injected water to obtain
a more favorable water-oil mobility ratio and  improve recovery efficiency).

Two technology  cases were assumed in the  evaluation of  UMO recovery potential.
The cases were  based on two different levels of geologic understanding and using
two classes of polymers.  The first level,  corresponding to technology currently
being  implemented  in  the  field, reflects  limited  geologic  understanding of
reservoir heterogeneity  and  the  technical shortcomings  of currently available
polymers.

The  second level,  corresponding to an advanced  technology  case,  assumed an
improved   understanding  of  reservoir  heterogeneity  and   improvements in
waterflooding  techniques that increase the  applicability and productivity of
these processes, including the development of improved polymers for application
in higher temperature  and higher salinity settings.  This scenario assumed that


                                     322

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sufficient geologic data would exist to characterize the reservoir and delineate
it into distinct segments, or facies, with reservoir parameters and heterogeneity
relationships developed independently  for each segment to allow the operator to
undertake a geologically targeted  infill drilling program.

Under the implemented technology case  at $20/Bbl, the low scenario could result
in 300  MMB becoming  uneconomic to develop  in  the three  states,  16%  of the
reserves that would otherwise be economic (Fig. 4).  Under the medium scenario,
700 MMB could be lost, 35% of otherwise recoverable UMO reserves.  Finally, under
the high scenario,  900 MMB could become uneconomic, 43% of UMO reserves otherwise
recoverable.

In the  advanced  technology case,  low  scenario,  300 MMB could be  impacted at
$20/Bbl, about 6% of the reference  case reserves becoming uneconomic.  Under the
medium scenario, 1,300  MMB could become uneconomic,  24% of the  reference case
reserves.  Finally,  under the high scenario,  1,500 MMB could be  lost,  28% of
otherwise recoverable reserves.

Under the implemented technology case,  public sector revenues associated with UMO
reserves development in the three  states could decrease by as much as 45%, a $4
billion loss.  Under advanced technology, revenues could drop by as much as 31%,
a $6 billion loss.

The development of the UMO resource requires that a considerable number of new
production and injection wells be drilled.   Environmental regulations that apply
directly to drilling  these wells,  such as management and disposal requirements
for drilling  fluids and area-of-review and corrective  action  requirements for
siting new injection wells, are the most significant environmental cost factors
influencing the economics  of  developing the UMO  resource.

3.  Enhanced Oil Recovery  in  Known Fields.  Enhanced oil  recovery (EOR), for
purposes  of  this  study,  is defined  as the incremental recovery of oil  in a
reservoir over that which could technically be produced by conventional primary
and secondary recovery methods.    EOR methods  include miscible  gas  injection
(typically  carbon dioxide),   chemical  flooding  (normally  surfactants  and
alkalines) and thermal recovery (which relies  on  the  introduction of thermal
energy to reduce oil viscosity and increase recovery).

The analysis of EOR potential  is based on TORIS  (1), containing a data base of
over 3,700 U.S. reservoirs, representing over 72% of the original oil resource
in place in the U.S.

The implemented technology case for EOR represents technology currently available
and proven in successful field applications.    The advanced technology case
assumes  technological improvements resulting from successful R&D,  improving
reservoir description and EOR efficiencies  and  expanding  the  applicability of
various EOR processes  to  a broader range of reservoirs.

In the  low scenario under the implemented  technology case  at  $20/Bbl, 100 MMB
could  become uneconomic;  corresponding to  3% of the reserves  economic under
reference  conditions  (Fig.  5).    In  the  medium scenario, 600  MMB  could be
                                    323

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impacted, 24% of the reserves that could otherwise be economic.   Finally, in the
high scenario, 800 MMB could be  lost,  29% of the reserves that could otherwise
be economic at $20/Bbl.

In the advanced technology case,  low scenario,  700 MMB of reserves could be lost
at $20/Bbl,  11% of otherwise recoverable reserves.  In the medium scenario, 2,000
MMB could be lost,  three times that lost under the implemented technology case.
This represents  36%  of  the reserves that could  otherwise be economic.   In the
high scenario, 2,500 MMB  could be  lost,  42%  of otherwise recoverable reserves.

This loss in  reserves could translate to as much  as  a 40% reduction in public
sector  revenues  in  the  implemented  technology  case,  and a 47% reduction in
revenues in the  advanced  technology case,  a  $2 to $7 billion loss.

The impact on EOR from increased  compliance costs is  similar  to that for the UMO
resource.   EOR  projects   also  generally  require the  drilling  of  additional
production  and injection  wells;  however,  tertiary recovery projects are  also
impacted by regulations on the reinjection of produced water.  Consequently the
incremental compliance costs associated with this activity will greatly influence
project economics.

4.   Undiscovered Crude Oil  Resources.   Undiscovered crude oil resources, as
defined by the U.S.  Department of Interior (DOI)  (5), are those resources judged
to  exist  in  geologically  promising but unexplored  areas.    The economic
feasibility of recovering  these resources was determined assuming that the volume
of oil  associated with  a  discovery must support all  costs associated with its
development,  including all  finding  costs.    The undiscovered  resource  base
analyzed was  based  on the most recent DOI assessment (5).

In  this analysis,  the  entire U.S undiscovered crude  oil  resource base was
considered.  No exclusions for areas currently under leasing moratoria,  such as
the Arctic  National Wildlife Refuge  (ANWR)  or certain areas off the coast of
California  and Florida,  were  considered.   If  development  in  these areas is
prohibited or substantially  delayed,  the  impact  on undiscovered  reserves could
be greater than  those predicted  in this  assessment.

The three scenarios considered are expected to all have a significant impact on
the economic  viability of finding,  developing, and producing U.S. undiscovered
crude oil reserves.  Under the  low scenario at  $20/Bbl,  up  to 1,000 MMB could
become uneconomic to develop as a result of increased environmental regulations,
9% of otherwise recoverable reserves (Fig. 6).  Under the medium scenario, 2,100
MMB could be  lost,  18%  of otherwise recoverable reserves.   Finally, under the
high  scenario,  up  to 4,900 MMB  could be lost,  42% of  otherwise  recoverable
reserves.

Increased regulations will have the greatest  impact on undiscovered oil reserves
in the  onshore Lower-48.   At $20/Bbl, 1,000 MMB  could be lost under  the low
scenario (22% of reserves), 2,100 MMB could be lost in the medium scenario  (46%
of reserves), and 3,000  MMB could become  uneconomic in the high scenario (66% of
reserves).  Increased regulations will have a lesser  impact on the discovery and
development of oil  reserves in  Alaska and the offshore  Lower-48 than  that on


                                       324

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onshore Lower-48 reserves under the  low  and medium scenarios.   In the offshore
and Alaska, the  increased  costs  of environmental  compliance make up a smaller
portion of total project costs  than that  in  the Lower-48 onshore.  Consequently,
the environmental initiatives considered under the low and medium scenarios are
estimated  to  have  a  relatively  small  impact  on project  economics  in  these
relatively high cost areas.

Under  the high  scenario,  however,  the  impacts   of  increased regulations  on
undiscovered  crude oil reserves  in  the  Lower-48  offshore   and  Alaska  are
considerable.   In  the  Lower-48 offshore, up to 1,000 MMB of reserves could be
lost,  17%  of  otherwise  recoverable  reserves.    The  impacts  of  increased
regulations on undiscovered crude oil reserves in  Alaska could be  as high as 900
MMB  lost  at $20/Bbl, 67% of otherwise  recoverable reserves.

The  loss  of  undiscovered  reserves  as  a  result of  increased  environmental
requirements could result in as much  as a $15 billion reduction in public sector
revenues  over the  life  of  these projects, a 36% reduction.

Conclusions

The  results of  this assessment lead  to the  following  major  conclusions:

•     Depending on'the extent of  new  regulatory  requirements, the  additional
      costs of environmental compliance could substantially decrease recoverable
      crude oil  reserves.  At  a price  of $20/Bbl  (Table 5):

           reserves from  future  infill development in known reservoirs  could
           decrease by 6% to  43%

           reserves from the application of enhanced oil  recovery processes in
           known  reservoirs could decrease by  3% to  42%.

           reserves from  the  development of future new reservoir  discoveries
           could  decrease by  92 to  42%.

•     The abandonment  of  remaining  resources  in known reservoirs could  be
      accelerated  by  approximately  10 years;  at $20/Bbl,  up to  30% of  the
      resource  could be immediately abandoned because of increased regulations.

•     The increased costs  of  environmental compliance  reduces reserves  under
      both implemented  and advanced  technology  conditions.
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References

1.    U.S. Department  of Energy/Fossil Energy, Office of  Oil,  Gas,  Shale,  and
      Special  Technologies,  Oil  Research Program  Implementation Plan.  April
      1990.

2.    National Petroleum Council,  Enhanced Oil Recovery.  June 1984.

3.    Lewin and Associates, Inc.  Replacement  Costs of Domestic Crude Oil: Supply
      Analysis Methodology,  report prepared  for the U.S.  Department  of Energy,
      Office of Fossil Energy, July  1985.

4.    ICF Resources Incorporated, Potential Cumulative Impacts of Environmental
      Regulatory  Initiatives on  U.S.  Crude Oil Exploration and Production;
      Volume  2 -  Final  Report,  prepared  for the  U.S.  Department of  Energy,
      Office of Fossil Energy, June  1990.

5.    U.S. Department  of Interior, Estimates of  Undiscovered  Conventional Oil
      and Gas  Resources  in the  United States --  A  Part of the  Nation's  Energy
      Endowment.  1989.

6.    U.S. Department of Energy, Bartlesville Project Office,  Abandonment Rates
      of the Known Domestic  Oil Resource.  April 1989.

7.    ICF Resources Incorporated and the Bureau of Economic Geology. University
      of Texas at Austin, Producing Undiscovered Mobile Oil:  Evaluation of the
      Potentially Economically Recoverable Reserves In Texas.  Oklahoma,  and New
      Mexico.  report prepared for  the  U.S. Department  of Energy,  May  1989.

8.    Economic Analysis, Inc., Economic Analysis of Proposed EPA Regulations on
      Drilling  Fluids and Cuttings:  Offshore Oil and Gas  Industry,   report
      prepared for the American Petroleum  Institute, December  31,  1988.

9.    J. Jones,  G. Marfin, and L. Hoffman,  An Analysis of Petroleum Industry
      Costs Associated with  Air Toxics Amendments to the Clean Air Act,  report
      prepared  for the  American  Petroleum  Institute, Interim Final  Report,
      October  17,  1989.
                                      326

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                             SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS

                                                    Resource Conservation and Recovery Act
1.
5.
6.
       Regulatory Initiative
Management and Disposal of
Drilling Waste
       Disposal   of   Associated
       Wastes into Central Disposal
       Facilities
                                    Low
                         Regulatory Scenario

                                    Medium

                                    Oil-based muds use closed systems
Oil-based muds disposed into lined
pits
                                    Salt water-based muds disposed into
Salt water-based muds disposed into    lined pits
lined pits
                             Liquid  wastes into offsite disposal
                             well; solid wastes into nonhazardous
                             waste landfill
       Upgrading Emergency Pits     AD emergency pits must be lined.
Replace Workover Pits with
Portable Rig Tanks

Organic   Toxic ity
Characteristic Test

Corrective   Action   (Soil
Remediation Only)
                                    Required on all rigs
                                    Liquid wastes  into offsite  disposal
                                    well;  solid wastes into  hazardous
                                    waste landfill
                                    Existing  emergency pits  must  be
                                    lined; new pits must be replaced with
                                    tanks

                                    Required on all rigs
High

Oil-based muds use closed systems

All water-based muds disposed into
lined pits
                                                                       Liquid wastes  into offsite disposal
                                                                       well;  combustible  solid wastes into
                                                                       incinerator;  non-combustible  solid
                                                                       wastes into hazardous waste landfill

                                                                       Tanks must replace emergency pits
                                                                       for both new and existing pits
                                                                       Required on all rigs
Applied to all facilities and new wells    Applied to all facilities and new wells   Applied to all facilities and new wells


Land   treatment  of  hydrocarbon    Excavation of salt water contamina-   Excavation of hydrocarbon and salt
contamination   at   50%  ^of  tank    tion at 100% of SWD wells and 75%   water  contaminated sites  at same
batteries and EOR projects            of EOR projects* and tank batteries    frequency as Medium Scenario

                                    Land  treatment   of   hydrocarbon
                                    contamination  at  50% ^of  tank
                                    batteries and EOR projects*
  EOR projects refers to both secondary and tertiary recovery projects

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                                                                 TABLE 2

                            SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS

                                                          Safe Drinking Water Act
       Regulatory Initiative
 1.  Mechanical Integrity Testing
        Parti

        Part 2
        Non Injection-Related Fluid
        Movement
2.  Area of Review (on wells drilled
    prior to 1984)

3.  Corrective Action (on wells drilled
    prior to 1984)
4.   Construction Requirements
                                    Low
                         Regulatory Scenario

                                   Medium
No incremental requirements (5-year
pressure test)
Radioactive  tracer  test  every  five
years
No incremental requirements




No incremental requirements


No incremental requirements
No incremental requirements
Pressure test frequency based  on
corrosive potential of basin
Radioactive tracer test and noise or
temperature log run to injection zone,
frequency based on basin corrosh/ity

Oxygen activation log  and  noise or
temperature log  run to lowermost
underground  source  of  drinking
water.

1/4 mile area of review (AOR) under
area permit

5% of  producing wells within AOR
assumed to require remedial squeeze

10% of abandoned wells within AOR
assumed to require reentering and
replugging

1% of  producing wells within AOR
must be redrilled

10% of  injectors require  remedial
squeeze
                                                                      2% of injectors must be redrilled

  MIT Part 1 addresses tubing, casing, and packer integrity.  MIT Part 2 addresses fluid movement behind the casing.
High

Continuous positive annular pressure
monitoring and 5-year pressure test
Radioactive tracer test,  noise, and
temperature log run to injection zone,
frequency based on basin corrosivity

Oxygen  activation,   noise,   and
temperature log  run to  lowermost
underground source of drinking water
1/4 mile area of review (AOR) under
individual injector permit

15% of producing wells within AOR
assumed to require remedial squeeze

30% of abandoned wells within AOR
assumed to require reentering and
replugging

3% of producing wells within AOR
must be redrilled

30%  of injectors require remedial
squeeze

6% of injectors must be redrilled
                                                                    10

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                                                                    TABLE 3

                              SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS

                                                                 Clean Water Act
    Regulatory Initiative
1.  NSPS for Offshore ^Discharge of
    Muds and Cuttings*
2.   NSPS for Offshore Discharge of
    Produced Water
3.   NPDES Stormwater Permits

4.   Above Ground Storage Tanks
5.  Ban  on  Onshore  Surface and
    Coastal Discharge of Produced
    Waters
                                Regulatory Scenario
                                     Low
EPA Approach A (EPA's estimate of
facilities  affected  and associated
compliance costs)
Existing facilities:  no change
New facilities: treat to 59 mg/l
Required for 55% of facilities
API  Partial  Discharge   Limitation
Scenario (EPA Approach A with API
estimates of compliance costs)
Existing facilities:  treat to 59 mg/l
New facilities:   shallow water, no
discharge; deep water, treat to
59 mg/l
Required for 55% of facilities
Only  leak  detection  and  financial    All  aspects*1'  considered for new
responsibility for new tanks larger    tanks  larger  than   500  barrels;
than 1,000 barrels                    financial responsibility for all tanks
High

API   Zero   Discharge   Limitation
Scenario  (API  assumption  that all
facilities are affected, using API cost
estimates)

Existing facilities:  shallow water, no
discharge; deep water, treat to
59 mg/l
New  facilities:    no discharge  all
depths

Required for 55% of facilities

All aspects'1" considered for all new
and existing tanks
No incremental requirements
Ban on discharges from new facilities    Ban on discharges from all facilities
  See EAI, 1988 (8).

    Aspects of regulations include injection and integrity testing, overflow prevention equipment, leak detection equipment, additional corrosion protection, and
    financial responsibility requirements.
                                                                       11

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                                                               TABLE 4

                           SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS

                                                             Clean Air Act
    Regulatory Initiative                                           Regulatory Scenario

                                  Low                              Medium                           High

1.   Onshore Air  Toxics  Emissions   API Case I scenario                 API Case I Scenario                 API Case II Scenario
    Standards*


2.   Offshore Air  Toxics  Emissions   California only; no mitigation costs   California  only;  mitigation   costs   Entire  DCS;  mitigation  costs  for
    Standards                      considered                        considered                        California only
  See Jones, Marfin, and Hoffman, 1989 (9)
                                                                 12

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                                       TABLES

                IMPACT OF POTENTIAL ENVIRONMENTAL REGULATIONS
               ON U.S. CRUDE OIL SUPPLIES AT AN OIL PRICE OF $20/BBL
                                              Resource Category
                          Conventional    Unrecovered      Enhanced Oil
                          Production*      Mobile Oil        Recovery
Undiscovered

Level of Assessment          Nine States**    Texas, Oklahoma  Lower 48         Entire
                                         and New Mexico  States (Onshore)

Implemented Technology

Resource Lost (%)
 Low Scenario                    2              16                 3              9
 Medium Scenario                23              35                24             18
 High Scenario                   30              43                29             42

Public Sector Revenues Lost (%)
 Low Scenario                  n/a              16                 5              7
 Medium Scenario               n/a              35                32             17
 High Scenario                  n/a              45                40             36

Advanced Technology

Resource Lost (%)
 Low Scenario                  n/a               6                11             n/a
 Medium Scenario               n/a              24                36             n/a
 High Scenario                  n/a              28                42             n/a

Public Sector Revenues Lost (%)
 Low Scenario                  n/a               7                15             n/a
 Medium Scenario               n/a              26                42             n/a
 High Scenario                  n/a              31                47             n/a
n/a = not analyzed
*  Represents incremental resource lost (over the reference case) immediately (in 1990) from
   premature abandonment
   California, Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and Wyoming
**
                                         331

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Remaining Oil-In-Place
  341 Billion Barrrels
         (67%)
Economically Recoverable
    at $32/Bbl with
  Advanced Technology
                                                                                                      Conventional Recovery
                                                                                                         172 Billion Barrels
                                                                                                               (33%)
                                                         Unrecoverable
                                                       69 Billion Barrels
                                                              Cumulative Production
                                                                145 Billion Barrels
                                                                      (28%)
  Recoverable
30 Billion Barrels
                                         Mobile Oil
                                       99 Billion Barrels
                                           (20%)
                                       Recoverable
                                     46 Billion Barrels
                                                                                              Proved Reserves
                                                                                              27 Billion Barrets
                                                                                                  (5%)
                               Immobile Oil
                             242 Billion Barrels
                                  (47%)
                                                                 Unrecoverable
                                                                196 Billion Barrels'^
              Source: DOE, 1989
                                                               513 Billion Barrels
                                                               Original Oil-In-Place
                                             Fig. 1. Over 300 Billion Barrels of Known U.S. Oil Resources Will
                                                  Remain After Conventional Production (As of 12/31/87)

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                                                                    TORIS Projections
                                                                              Reference Case
                                                                              Low Scenario
                                                                              Medium Scenario
                                                                              High Scenario
      2-
1-
      0
      1970
           1975
1980
1985
1990
1995
2000
2005
2010
2015
                                                       Year
                          Fig. 2. Impact of Environmental Regulations on Crude Oil
                     Production in the Reservoirs Analyzed in the Nine States ($20/Bbl Oil Price)

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Medium Scenario
High Scenario
                     Implemented Technology
                                              Advanced  Technology
                                   Fig. 5. Impact of Environmental Regulations on EOR
                                          Reserves in the U.S. ($20/Bbl Oil Price)

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     15-1
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                                                                            Alaska

                                                                            Lower 48 Offshore

                                                                            Lower 48 Onshore
               Reference
Low
Medium
High
                        Fig. 6. Impact of Environmental Regulations on Undiscovered

                            Crude Oil Reserves in the U.S. ($20/Bbl Oil Price)

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ENVIRONMENTAL AUDITING  AT PRUDHOE  BAY: A  WASTE MANAGEMENT
TOOL
Pepsi Nunes and Michael J. Frampton
Environmental Coordinators
ARCO Alaska, Inc.
PRB 7
P.O.  Box 196449
Anchorage, Alaska 99519-6449
Introduction

Producing oil  at Prudhoe  Bay  required development  of  new
technology for  the hostile Arctic  climate and  the  creation of
a small industrial enclave in  the far north.   Gravel  roads,
five to seven feet thick, were constructed to provide  year-
round travel across  the tundra.    Gravel  pads are  used  as
drill  sites for production  wells.    Wells  are  drilled
directionally at  an  angle from gravel drill pads,  with  30 to
40 wells per pad, and covering a producing area of up  to  six
square miles beneath the earth's surface.   Drilling from  a
central  site  minimizes  surface  disturbance  and  sharply
reduces  the need  for  roads  connecting  well  sites.    In
addition to  drill  sites,  all buildings  are set  on  gravel
pads.

Unlike many  fields,  which require surface  pumps to draw  the
oil  out of  the  ground,  the  Prudhoe  Bay  reservoir  has
sufficient   pressure  to  force  oil  to  the surface  without
pumps.   Several systems keep the natural oil  flow at Prudhoe
Bay at a constant level  and help recover  more  oil from  the
field.   Waterflooding,  a secondary  recovery method began in
1984 with over  one million barrels a day of seawater  injected
into selected patterned  wells.   Located at the  end of West
Dock,  the Seawater Treatment  Plant  (STP)   filters, deaerates
and heats seawater used in waterflooding.   After the  seawater
is  heated,   it  is  pumped through  pipelines  to  an  onshore
injection plant  (SIP)  where  it  is  pressurized and  sent  to
injection wells.   The water  intake at the  STP is  designed to
divert  fish  and marine  life and return them, unharmed,  to  the
sea.
                             339

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Three flow stations  on  the east side of  Prudhoe Bay and one
in Lisburne process  the  oil  from the drill sites, separating
it  from  the  gas  and  water.    The crude  oil from  these
facilities is  shipped by pipeline  to Pump Station  No.  1 of
the trans Alaska pipeline.

The  separated gas  is transported  to  a  Central  Compressor
Plant (CCP)  for injection into the reservoir's gas cap and to
the  Central  Gas Facility  (CGF).    The  produced  water  is
injected into the oil reservoir  as  part of the waterflooding
program.

More  than three billion cubic  feet  of gas  per day can  be
compressed from about 600 psi to about 4500 psi at CCP.    The
compressed air is injected into the  gas cap were it is stored
until a market is found  for it.

Designed to handle more  than  three  billion  cubic feet of gas
a day,  the  Central  Gas  Facility (CGF)  at Prudhoe Bay is the
largest  gas  handling plant  in the  world.   CGF provides  an
artificial lift system,  another enhanced.oil recovery method.
Enriched hydrocarbon gas  (miscible  gas) is  injected  into the
tubing in an oil producing well.   The bubbles of gas  mix with
the  oil, making  it lighter and more capable  of rising to the
surface.  CGF  also  produces 55,000  barrels a  day  of natural
gas  liquids,  which  are  blended with crude  oil and  shipped
through the pipeline.

A crude  oil topping  unit (COTU)  produces  Arctic grade diesel
fuel, gasoline and formerly jet  fuel for use at  Prudhoe.

The  Prudhoe  Bay  Operations  Center  Wastewater  Treatment
facility provides sewage treatment  services  for a  population
of  2600.   The  design capacity  is  210,000  gallons   per  day
average  flow  with a  maximum monthly average  flow  allowed  by
the  National  Pollution  Elimination  Discharge  System (NPDES)
permit  of 234,000 gallons  per day.   The  system was  designed
to provide tertiary treatment including a minimum 95% removal
of biochemical oxygen demand  (BOD)  and suspended solids.   The
plant, however, consistently achieves removal efficiencies  in
excess  of  98%.   Water sludge from  the process  is thickened
and  burned on-site in an incinerator  operating between  8 and
18  hours  a  day.    Treated  effluent  from  the plant  is
discharged to a  polishing  lagoon constructed  in a portion  of
an  unnamed  lake.   The  effluent from  the polishing lagoon
enters the lake by flowing through a shallow weir in  a gravel
dike.

AAI  also operates  an offshore  exploratory  well  in  nearby
Camden  Bay,  a hazardous waste  storage  facility (C  Pad),  a
non-hazardous  waste,  disposal facility  (Pad  3),  two  barge


                              340

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docks, an  airfield,  hotel facilities, a  medical facility, a
crude  oil  testing  laboratory, a  fire department,  numerous
warehouses and  service shops,  and a  hundred  miles  of gravel
roads. AAI employees  at  Prudhoe  work round-the-clock  on a
shift  -basis.    Audit  scheduling  was  therefore designed to
involve both shifts.

Disposal and treatment  of  all  wastes  produced at Prudhoe Bay
are  regulated by permits  issued by the Alaska Department of
Environmental  Conservation  and  the  U.S.  Environmental
Protection Agency.   Hazardous  waste  is carefully managed and
consequently has not been a problem  in  the oil field.   The
low  volumes  generated and  the  nature  of  the   hazardous
material have enhanced our ability to properly  manage these
wastes.

Environmental protection  at Prudhoe  Bay  is a  complex task,
which  starts with the combined efforts of field environmental
compliance personnel  and personnel  from  each  field  facility.
Compliance audits are  one of  many tools employed  to ensure
environmental  protection, especially in the  area  of waste
management.   The compliance audit program  covered  all drill
sites,  production   facilities,  drilling,   workover   and
exploratory    rigs,   field    support    facilities   and
waste/wastewater  treatment,  storage  and  disposal facilities.
Audits were designed  to:  1)  identify  specific compliance
problem  areas,   if  any;  2)  recommend  solutions  for  any
compliance  issues discovered,  including training  programs;
and  3) assist in  establishing schedules for implementation of
solutions.

Materials and Methods

A cooperative problem-solving approach was employed.  Inhouse
environmental  professionals worked  closely  with  facility
personnel  from  all levels.  No  facility  and no area  of the
eastern  half  of Prudhoe Bay and Lisburne fields were placed
off  limits to the  audit  program.   The  audits  consisted fo
five  major  elements,  namely,  the  audit  team,   pre-audit
questionaires and activities, compliance checklists, employee
interviews and  facility  or   site  inspections .    At  the
completion  of   each  audit,  a  summary   of  findings   and
recommendations  was  issued  by  the  Field  Environmental
Compliance (FEC) Office to the  facility's  supervisor.

Audit  teams were  composed of environmental professionals from
FEC  and the facility's supervisor  or his/her designee.

A pre-audit questionaire,  including a copy  of the  compliance
checklist and a  request to nominate an audit  team member and
                            341

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personnel for interviews,  was  sent  to  the  facility  supervisor
three weeks  before the  audit.   The  pre-audit questionaire
provided  a  listing of  topics  to  be  covered  in  the audit.
Typically, these  concerned paperwork or  documentation and
equipment  required  by  regulations  or   by  the  facility's
permits,  such as the facility's permits,   correspondence with
regulatory  agencies,  monitoring  reports,  any notices  of
violation,   monitoring   equipment   records,   equipment
inspection,   calibration  and/or   repair   records,   waste
manifests, records of  required  training,  and the  facility's
environmental manuals and procedures.

Individual checklists were  prepared for each  facility.  Areas
of  compliance  included NPDES,  Prevention  of  Significant
Deterioration   (PSD),   Air  Quality  Control,  Resource
Conservation and  Recovery  Act   (RCRA),   Spill  Prevention
Control  and  Countermeasures  (SPCC)  plans, facility-specific
waste disposal  permits,  Class  II  injection,  tundra  travel,
water  use,  used  oil   handling,  used  drum  handling  and
labeling, waste management, spill  prevention,  reporting and
cleanup,  bulk storage tanks, black  smoke,   reserve,  relief and
flare pits fluids management,  snow removal/gravel  carryover,
potable  water  use  and  wastewater treatment.    Regulatory
requirements, often  not specifically  cited  in  permits  but
still requiring  compliance, were also included.

Input from  facility  operators  is  invaluable.   Accordingly,
interviews   were  conducted  with  25% of each  facility's
personnel  from  all  levels and  job  functions.   Interview
questions  were  not  included  in   the pre-audit package.
Results   from   the  interviews   were   employed  to  develop
fieldwide and  facility-specific  environmental  training
programs.

Each audit included a walk-through  physical inspection of the
facility and its  grounds  or gravel  pad  and  access  roads
following the records/documentation examination and personnel
interviews.   An exit meeting with the facility supervisor
covered  specific areas  of  concern,recommended  solutions for
problems  and  scheduling of  solution  implementation.

A full audit was conducted during  one  shift  and a secondary
brief audit  was held with  the other shift.   The brief audit
consisted of personnel interviews   and a  discussion  of the
previous  full audit's  findings  and recommendations, with the
facility  supervisor.   Follow up  of easily correctable areas
was also  performed  during the brief  audit.

Results
                            342

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The  ultimate  test  of a  compliance  audit  is not  in  the
elegance  of  its  design  but  in  the  results  it  produces.
Although generally accepted audit standards have not yet been
fully  developed,  our audit program has  yielded results that
can  only  aid in  meeting  the company's  stated goal  of full
compliance:

     •Verified  the company's compliance with  federal,  state
and  local statutory and regulatory requirements
     •Reinforced top management's commitment to environmental
protection
     -Increased  awareness  among  supervisors  and operators  of
their  permit and other regulatory requirements
     •Improved  the  abilities  of  facility   personnel  to
determine when and how to  make environmental  decisions
     •Reduced  the possibilities  of discovering  significant
"surprises"  or  recurring   patterns  of  shortcomings  in
environmental performance
     -Identified  areas  where  environmental  training  is
desirable and necessary for ensuring continued compliance
     -Increased  confidence   in  management   that  the
environmental  activities   and  efforts of  the  company  are  a
sound  investment
     -Identified attitudes or practices that pose a potential
for  punitive administrative penalties  and actions
     •Determined   the  extent   to  which  employees  are
knowledgeable  about   and  adhering  to  company  policies
regarding environmental protection,  waste management, etc.
     •Confirmed  that the  communication  link between  FEC and
the  various facilities was functioning  properly

Conclusions

The  current  regulatory climate presents a host of potential
and   unresolved   issues-technological,    legislative,
interpretative,   institutional  and legal-that may  have  a
substantial  effect on the company.  The specific  outcome  is
not  always predictable or measurable.   This   is  especially
true  in  the  area  of waste  management,  which derived the
greatest number of benefits from  the audit  program:

     •Refined,  facility-specific  inventories  of  the  volume
and  types of wastes generated were developed
     •The  procedures  and  facilities  in  place  to  handle,
store,  transport and dispose of the different types of wastes
were clarified for field personnel
     •Management's  confidence  that  the   company's  waste
management  policies  and  procedures  are  in good shape and
being  complied with was increased
                            343

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     •Measures to reduce the volume  and/or  toxicity  of  wastes
generated were initiated
     -Integrating  waste  reduction  into  normal  operating
activities was initiated

To  the  extent  that  firms  initiate  or  expand  programs,
environmental  auditing  improves  the  quality and  level of
compliance.   Auditing  results  in better  information  about
current operations,  protects  the company  from  legal, economic
and public image problems,  and gives  management an additional
tool in its strategic planning process.
                            344

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AN ENVIRONMENTAL  COMPLIANCE AUDIT OF FOUR  OIL AND GAS FACILITIES
IN KENAI, ALASKA
Reller, C.
entropy - senior scientist
Box 101255
Anchorage, Alaska    99510


Introduction

Nikiski, a small Alaska  town on the Kenai peninsula, 100 km SW of
Anchorage,  hosts four  oil  and  gas facilities  on  less  than one
square  mile,   including  the  world's largest  ammonia/urea plant,
North America's largest exporter of natural  gas,  and  two other
petroleum refineries. Located on a deep water port of Cook Inlet,
Nikiski is adjacent to  21  oil and gas fields.  Along  the ice
affected coast 15 platforms extract petroleum.  Across Cook Inlet
is Marathon's Trading  Bay  facility, the largest  oil production
facility  in North America.  Also on the  west shore  is  the Drift
River  crude  oil  storage  terminal, located  in  a flood  plain
dramatically  affected by Mt. Redoubt, an active volcano.

Prior to this  study there  were no comprehensive  evaluations of
pollution   discharges,   no   compiled   records  of  environmental
violations, nor an  analyses  of  enforcement  actions for the Kenai
industries.    The Nikiski   facilities  selected  for investigation
because of  their proximity to human habitation  and potential to
pollute. Further research is needed regarding platforms, facilities
on the  western shore of  Cook Inlet,  and drilling mud pits.

Research  covered a  period  from the late 1950's  to January 1989.
More recent events may add  to the results but would not affect the
conclusions.  The four facilities studied are the Unocal-Mitsubishi
ammonia/urea  plant,  Phillips-Marathon-USX  natural gas refinery,
Tesoro  Alaska  refinery,  and  Chevron  USA refinery.   At Unocal-
Mitsubishi  over 3 billion pounds of nitrogen  based chemicals are
produced  annually - equal  to 2%  of the world's  annual nitrogen
fixing  by soil bacteria. Contiguous to  the ammonia/urea plant are
three refineries that produce and export 2.6  billion gallons a year
of gasoline,  jet fuel, fuel  oils, asphalt, and natural gas. If the
refineries  combined  annual  production  capacity  was placed  in
barrels and  put  end-to-end  they  would  encircle  the  globe  with
enough  left over to  reach  from Prudhoe  Bay to San  Francisco.
                              345

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Method

The research method used is historical  in  nature.   Agency records
were systemically collected  and evaluated in order to understand
past events and analyze trends in environmental regulation. Primary
sources of information are inspection reports, permits, enforcement
orders, interviews,  facility self reporting, letters,  and memos.
Approximately  5,000  copies  were  made  from a total  of  20,000
reviewed  pages.  Alaska Department  of Environmental  Conservation
(DEC) records were searched in local, regional, and central offices
of Kenai,  Anchorage,  and  Juneau.  If information was  missing  or a
lack  of  data  was important  to document  requests  were made in
writing  in accordance  with  Alaska  Public  Records Act.  Federal
records are predominately kept in Seattle and were obtained through
the Freedom of  Information Act.
Results

The data  is  organized according to receptor media; that  is,  air,
water, and soils.  It is through these media that  adverse effects
of  pollution are  transferred between  each other  and to  living
things.   The total pollution released  into each media is  listed
first then major violations followed by agency  responses.

                          AIR POLLUTION

     RELEASES
The  four Nikiski  facilities release   67  million  pounds of air
pollutants   annually  (Table   1) .     If  these  pollutants  were
individually and uniformly distributed across the  state  National
Air Quality  Standards would be  exceeded to  a height of 250 feet.

     MAJOR VIOLATIONS
Unocal-Mitsubishi  operates in almost daily  violation  of Clean Air
Act  limitations on  suspended  particulates  (1) .  Major spills of
ammonia,  as  much  as  800,000  pounds at one time  (2)  occur  on a
regular basis, usually two or three times a year (3).  Off  site air
monitoring instruments have exceeded maximum readings for six hours
at  a  time (4).   A major  air  release occurred  during  unpermitted
hazardous waste treatment,  when uncontrolled gasses  escaped,  (5)
spreading across public roads and disrupting industrial operations;
including the adjacent  liquified natural  gas storage  facility.'

Tesoro refinery hydrocrackers exceed nitrogen oxide standards and
Tesoro recently built new sources of air pollution without prior
authorization, a violation of the  Clean Air Act (6).
                               346

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At the Phillips-Marathon-USX refinery waste  oil and  gasses were
dumped into a  flare pit  and burned in  violation of  air quality
standards for a period of 18 years  (7) .
                            TABLE 1

 Annual Air Pollution from the Nikiski Oil and Gas Industry  (8)

                   pounds         pollutant

                   30,000,000     ammonia
                   19,000,000     nitrogen oxides*
                     5,400,000     carbon monoxide*
                     4,300,000     hydrocarbons
                     3,400,000     methanol
                     2,400,000     particulates*
                     1,000,000     sulfur oxides*
                     1,000,000     hazardous waste-arsenic
                       73,000     benzene
                       45,000     xylenes
                       32,000     chloroform
                       31,000     toluene
                       18,000     1,1/1 trichloroethane
                       17,000     cyclohexane
                       13,000     ethylbenzene
                        4,000     formaIdehyde
                           500     naphthalene
                           100     lead*
                            34     ethylene dichloride
                            22     polycyclic aromatics
                            5     ethylene dibromide
                            2     cadmium
                            1     chromium
                   67,000,000

 (*  Clean Air Act permitted releases).

     AGENCY RESPONSE
 In response to  over 15 years of violations  at  Unocal-Mitsubishi,
 DEC has done  the  following:  stopped  recording violations  (9) ,
 requested  EPA  not  to  issue  an  enforcement  letter  to  Unocal-
 Mitsubishi (10), promised to refrain from fines  or legal action for
 past violations (11),  amended state air quality regulations thereby
 creating  less  stringent  standards  (12),   and  allowed  Unocal-
 Mitsubishi to operate with an expired permit.
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In response to violations at Tesoro DEC  reissued an air permit.

In response to over  18  years of violations at  Phillips-Marathon-
USX, DEC issued a Notice of Violation.

                         WATER POLLUTION

     RELEASES
The Nikiski  facilities  release 6.5 million  pounds of waste  into
Cook Inlet each year  (Table 2), which does not  include  the weight
of polluted water.

                             TABLE 2

             Annual  Surface  Water Pollution from the
                Nikiski Oil and Gas Industry  (13)

                   pounds          pollutant

                3,300,000          nitrogen compounds*
                2,400,000          sulfuric acid*
                  690,000          unidentified  suspended solids*
                  140,000          oil and grease*
                   18,000          zinc*
                    7,000          ethylene glycol
                    2,500          1,1/1 trichloroethane
                      970          chromium*
                      460          phenols*
                      550          sulfide*
                      370          polynuclear aromatics
                      200          cyclohexane
                      200          xylenes
                      130          benzene
                       60          toluene
                        7          ethylbenzene
                        7          arsenic
                        7          cadmium
                        4          nickel
                        4          cyanide
                 6,500,000

 (*   Clean Water Act permitted releases).

     MAJOR VIOLATIONS
 The  ammonia/urea plant  was formerly owned by "Colliers" at which
 time self monitoring reports were  intentionally falsified (14).
 More recently Unocal-Mitsubishi dumped hazardous waste containing


                                348

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methanol  and  formaldehyde into Cook Inlet in violation of RCRA and
the Clean Water Act  (15).  Unocal-Mitsubishi  allowed the  out  fall
diffuser  to  become  plugged,  then  cut  the  diffuser  off,  thus
negating  the  permit mixing zone  calculations (16) .

Over 200  unpermitted underground injection wells are used to  dump
water  contaminated with  ammonia and  arsenic   (17).    A  Unocal
underground injection well  exceeded pressure  limits and  injected
prohibited waste,  violations of the Safe Drinking Water Act permit
(18).

Tesoro did not meet schedules  for effluent bioassays.

Phillips-Marathon-USX   uses   unpermitted   shallow    underground
injection  wells to  dump contaminated  water.  Also the  facility
discharges waste water  into Cook Inlet without  a Clean Water Act
permit.

    AGENCY RESPONSE
After  nearly a  decade  and a half  of  documented ground water
pollution  by  Unocal-Mitsubishi  neither   state  nor   federal
authorities have taken  enforcement actions.

When  Tesoro  production capacity  increased,  EPA and  DEC  simply
allowed total pollution to increased (19)  despite the fact  bioassay
studies have shown the effluent so toxic that all  species subjected
to a 1:10 dilution  were killed and even  a 3%  mixture  severely
affected reproduction  (20) .

                          SOLID WASTE

    RELEASES
Unocal-Mitsubishi  disposed  of  70,000 pounds  of  drummed hazardous
waste  by giving it to the City of Kenai  for  road oiling  (21,22).
No records  of  manifests,   storage facility permits,  or other
required RCRA reports were  found in the public record.

Each  day Unocal-Mitsubishi dumps  10,000 pounds  of metal  sludges
containing high levels of zinc (250,000 ppm), arsenic  (3,300 ppm),
copper (25,500 ppm) and lesser amounts  of chromium, nickel, lead,
and cadmium,  into gravel  pits  (23,24,25).  In  addition,  Unocal-
Mitsubishi generates one half million pounds of catalyst each year.
Used catalysts are dumped on the ground, used for fill, and buried
(26).  Laboratory   testing  in  1983 indicated  used  catalysts  are
hazardous  waste  due  to  high  levels  of  extractable chromium.
Unocal-Mitsubishi  repeated  laboratory analyses until the  catalyst
passed EP-tox tests.  Intra-laboratory differences of more than  100,
between  three  separate  labs  were  not  resolved  (27) ,   and  the
catalyst waste was declared  non  hazardous.


                               349

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In a single year as much as 640,000 pounds of hazardous waste were
spilled at the ammonia/urea plant (28).  Between 1983 and 1985 there
were seven reported major hazardous waste spills (29). Halogenated
solvents are  disposed in waste  oil  (30,  31),  a practice clearly
prohibited by the RCRA.

Tesoro generates  10,000,000 pounds of  elemental sulfur  each year
which is dumped on the ground without  a permit.

Phillips-Marathon-USX filter charcoal contaminated with arsenic and
mercury  (32)  is used for  disposal,  masquerading as  "road oiling
dust control", rather than managed as solid waste.  The most recent
disposal  involved 22,000 pounds  of  contaminated charcoal.  Waste
oil, possibly mixed with RCRA listed hazardous waste,  is dumped on
the ground with the  intent  of disposal  (33).

Chevron  dumps  "oil  filter waste"  on  roads  for the purpose  of
disposal  (34) . In  the  past  Chevron  dumped  hazardous  waste  in
unpermitted pits  on  Chevron property (35, 36).

     MAJOR VIOLATIONS
Unocal-Mitsubishi ignored RCRA regulations and stored over 140,000
pounds  of  hazardous  waste in violation of 40  CFR 270.71.  Further
mismanagement  resulted  in unreported  spillage  from bulldozers
knocking over drums of hazardous waste  (37).  Hazardous waste tanks
 (190,000 pounds capacity)  do not have RCRA tank permits  (38).

Tesoro dumped hazardous waste into unlined pits  dug in porous soils
 (39), spread it on public roads (40), illegally stored and shipped
hazardous  waste (41), and  hazardous waste  solids were  allegedly
recycled for  disposal pits  walls (42).

Chevron adds hazardous waste to consumer products (43). A disposal
method  not  approved  by RCRA;  because,   solids  derived  from listed
hazardous waste are  not  eligible for recycling (40  CFR 261.1).

     AGENCY RESPONSE
EPA  cited  Unocal-Mitsubishi for  violating  the same RCRA  storage
regulation  as  many as three times in only four months (44).

At Tesoro,  EPA imposed  fines totalling  $57,750 (45,  46).

Chevron  was  twice   served  Notices  of  Violations  by  EPA  for
noncompliance  with hazardous waste laws (47).
                               350

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AIR POLLUTION

EPA has delegated authority of the Clean Air Act to DEC.  Therefore
inspections, reporting, and enforcement are the responsibility  of
the state.  As a  result of state  authorization  DEC lowered state
air quality standards;  that is,  an opacity limit was raised, for
the purpose of allowing Unocal-Mitsubishi  to  gradually come into
compliance.  However for almost two decades the ammonia/urea plant
has exceeded even the generous variance allowed by DEC.  When EPA
threatened to override  DEC primacy the state  commissioner pleaded
with EPA to not issue an enforcement letter. Unocal-Mitsubishi also
leveraged  the  DEC  by  pressuring  the Alaska  legislature.   As a
result  of  testimony at public hearings,  Unocal-Mitsubishi sent a
letter  protesting proposed  ambient air  standards.    The protest
letter was sent all  Alaska's congressmen,  governor, and every state
representative and  senator  (48).

Inability  and unwillingness to enforce are further illustrated by
DEC knowingly allowing construction of new air  pollution sources
by Tesoro in violation of the  Clean Air  Act.    Despite ongoing
violations, the Tesoro permit was renewed. Tesoro  and DEC justified
renewing  the  air permit  because  it  would  be more  economical to
bring the  facility  into compliance at some time in the future.

Prior  to  DEC  acquiring primacy  of the Clean Air Act, Alaska had
state air guality regulations  at which time facilities such as oil
and  gas platforms and  incinerators were required to  both obtain
operating  permits and  report  regularly.  However  since assumption
of Clean  Air  Act primacy  DEC has substituted less  stringent air
quality regulations;  thus, effectively deregulating  oil  and gas
platforms  and  large incinerators such as  the oily  and chemical
waste  incinerator located at Trading Bay,  across Cook Inlet from
Nikiski.  These deregulated sources are not insignificant. Oil and
gas  platforms, off  shore from Nikiski, emit  approximately 34% of
the  35 million  pounds/year of NOX produced in upper  Cook Inlet.
Additional deregulation is evident by the fact that none  of the oil
and gas platforms;  including  three with permit^ report, measure,
or are  required  to  even estimate SOX emissions.  Despite a history
of almost daily violations at multiple facilities, no  evidence was
found  of  state assessed fines.

SURFACE WATER POLLUTION

EPA retains authority  for  enforcing the Clean Water Act. The four
Nikiski facilities  discharge  waste water to Cook Inlet.  A review
of discharge monitoring reports  (DMRs) indicates a  high level of
                              351

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compliance.   The  exception  is  an  intentional  falsification  of
ammonia/urea plant DMRs. A search of state and federal records did
not reveal this  enforcement case. However  personal communication
with a state regional supervisor  and enforcement officer revealed
the nature of this case.  A criminal conviction was reportedly plea
bargained for a fine of approximately $400,000, one of the highest
ever assessed nationwide, at  the  time.

GROUND WATER POLLUTION

DEC regulates the  discharge of waste water  to the land.   However,
neither the Unocal-Mitsubishi 200 underground injection wells nor
a  leaky Unocal-Mitsubishi waste  water pipeline nor the  several
dozen discharges of Phillips-Marathon-USX are permitted.  Likewise
none of the Nikiski  facilities have  the state required  permits  or
plans for waste water sludge  disposal.

An  example of  state inability  to  enforce is  illustrated by a
Unocal-Mitsubishi  response  to DEC requests for  monitoring wells.
Unocal-Mitsubishi  claimed their  carcinogenic  arsenic-containing
hazardous  waste  is  "less toxic  than table salt"  (49).   Unocal-
Mitsubishi used human subjects for a  taste and odor panel to screen
for contamination.  Unocal claimed "Should  any  contaminated water
somehow  reach a domestic water  well, the  water would  acquire a
detectable  taste  or odor  prior to becoming  hazardous."  (50).
Eventually   Unocal-Mitsubishi  groundwater   investigations  were
transferred  from RCRA to CERCLA  (51).  A  CERCLA  study found  that
contaminated ground water and unpermitted air releases resulted  in
a  Hazard Ranking System score over  30,  high enough  for National
Priorities  List  nomination (52). Later,  ground  water  compliance
issues  were  reassigned  back to RCRA. There are  neither  plans nor
schedules  to evaluate the contamination issues  under either  RCRA
or CERCLA. In the future DEC may request Unocal-Mitsubishi to study
their ground water problems.

SOLID WASTE

Solid  waste regulations  are  a  complex web of state and  federal
laws.    State  laws  regulate  non-RCRA  solid waste.  None  of the
facilities have  solid waste permits  yet they all dispose of solid
waste on their facilities.  No record was  found of any  attempt  by
DEC to require solid waste permits of these facilities.  Additional
evidence  of  widespread  disregard for solid waste  regulations  is
borne by the fact that 60 nearby pits used for disposal of drilling
muds have  no  permits.

RCRA waste is regulated jointly  by EPA and DEC.  EPA  actions have
resulted in several major compliance  actions with  fines.  Additional
federal actions  include  forcing Tesoro to submit  closure plans for


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unlined hazardous  waste  surface  impoundments.  DEC  actions a're
limited to a few simple reports by an inexperienced  inspector.  DEC
has  never taken  a  RCRA  sample from  any  of  the  four  Nikiski
facilities (53) .
conslusions

I.   Environmental laws with sole federal  jurisdiction;  such as the
    Clean Water Act in Alaska,  have  the  best compliance record.

II.  When the state is authorized to enforce federal environmental
    laws; such as,  the Clean Air Act and Resource Conservation and
    Recovery Act,  compliance  is limited to  incidents  of federal
    involvement.

III. State  environmental   laws   without   federal  oversight  are
    virtually without  compliance and enforcement;  such as, solid
    waste, waste water, and waste water  sludges.


References

1.   G.  O'Neal,  (undated).  Notice of Violation from EPA  to  CT
    Corporation System Agent  of Unocal-Mitsubishi,  EPA  file No.
    1087-04-05-113.

2.   Tryck,  Nyman  and  Hayes.     (1987).  Suspected  Uncontrolled
    Hazardous Waste Site  Inspection.   DEC CERCLA Site Inspection

3.   P.  Crawford,  (August  9, 1988). What  is the Unocal-Mitsubishi
    Plant Putting Into the Air?. Peninsula Clarion, pp. 1, 20,24.

4.   M.  Lucky,  (June 12, 1985).   memo to  file DEC Kenai Office.

5.   D.  Turner, (September 1, 1982). letter from Unocal-Mitsubishi
    to  M. Lucky of DEC.

6.   R.  Grantham,  (March 4 and 30, 1988) .  letters  from Tesoro to
    L.  Verrelli of DEC.

7.   M.  Lucky.  (May 12, 1986). Notice of Violation Permit #8223-
    AA  002. DEC vs. Phillips  Petroleum Company.

8.   Data  compiled  from  air  permits,  SARA  Title  III  facility
    reports and Alaska Air Toxics Emission Inventory-  EPA Region
    X Contract Number  68-02-3899  Work Assignment 81.

9-   M.  Schulz,  (April  20  1987).  EPA  Notice of Violation Report.

                              353

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10.  D. Kelso,  (May 15, 1987).  letter from Commissioner of DEC to
     Air and Toxic Division Director EPA.

11.  Compliance Order by Consent.  (1987) DEC vs. Unocal-Mitsubishi.

12.  L. Verrelli, (June 27,  1988).   letter  from Air Quality Program
     Manager DEC to Unocal-Mitsubishi plant manager.

13.  Data compiled from federal and state waste water permits, and
     SARA section 313 of Title  III  facility reports.

14.  R. Bayliss, B. Lamoreaux,  (1988).  personal communication.

15.  R. Burd,  (February 27, 1987).  letter  from EPA to W.  White  of
     Unocal-Mitsubishi.

16.  EPA.  (July  26, 1988)  Fact Sheet Regarding Unocal-Mitsubishi
     NPDES Permit Number AK-000050-7.

17.  M. Lucky,  (August  6,  1984).  letter from  DEC to D. Turner  of
     Unocal-Mitsubishi.

18.  R. Burd,  (April  10,  1987). letter  from EPA to G. Graham  of
     Unocal-Mitsubishi.

19.  R. Bowker,  Department of  the  Interior to H. Geren  Chief  of
     Water Permits and  Compliance Branch EPA.

20.  B. Duncan,  (January 6, 1987).  memorandum  from EPA to J.  Howe
     of DEC.

21.  W. White,  (November 20,  1986).  letter from Unocal-Mitsubishi
     to B. Brighton of  City of  Kenai.

22.  K. Laurie,  (June 11,  1987). letter  from Unocal-Mitsubishi  to
     K. Kornelius of City of  Kenai.

23.  Unocal-Mitsubishi. (December 4, 1980). Schematic of Water Flow
     from NPDES  Application.

24.  EPA.  (July  26, 1988)  Fact Sheet Regarding Unocal-Mitsubishi
     NPDES Permit Number AK-000050-7.

25.  Tryck, Nyman and Hayes.   (1987).

26.  Tryck, Nyman and Hayes.   (1987).

27.  C. Heus,  (October 20,  1983). memorandum from Union Oil Company
     Chemicals Division to Turner.
                               354

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28.  M. Lucky,  (March 5,  1984).  memorandum of DEC to B. Lamoreaux.

29.  Tryck,  Nyman and Hayes.  (1987) .

30.  Tryck,  Nyman and Hayes.  (1987).

31.  C.  Burgh,  (May 31,  1986).  notes of  DEC concerning Unocal-
    Mitsubishi.

32.  H.  Patterson, (March 4, 1988).  letter from Phillips Petroleum
    Company to L. Leatherberry of DEC.

33.  C.  Burgh, (September 16, 1987).  RCRA Inspection Report of DEC
    Phillips Petroleum Company Kenai Plant.

34.  R.  Williams, (April  16, 1984).  letter from Chevron USA Kenai
    Refinery to M. Lucky of DEC.

35.  Tetra-Tech.  (1984) .  Preliminary Assessments on  45 Potential
    Uncontrolled Hazardous Waste Sites. DEC  CERCLA.TetraTech

36  C.  Rice,  (March 3, 1985). memorandum  of  EPA to S. Torok.

37.  A.  Smith, (February 29, 1984).  Complaint and Compliance Order
    RCRA Docket No. X84-02-08-3008, EPA vs.  Union  Oil Company of
    California.

38.  K.  Laurie,  (July 19, 1985). letter from  Union  Oil Company to
    J.  Webb of EPA.

39.  C. Findley,  (September 28,  1987).  Complaint and Final Order
    on Consent Requiring Submission  and Implementation of Proposal
    for Sampling, Analysis, Monitoring,  and Reporting RCRA Docket
    Number 1086-07-12-3008 from EPA to Tesoro Alaska Petroleum Co.

40.  M. Necessary,  (August  9, 1988). personal communication.

41.  R. Fuentes,  (July 27, 1984). memorandum of EPA to the file of
    Tesoro Alaska  Petroleum Company RCRA.

42.  S. Torok,  (May 5,  1983).  letter from EPA to R.  Measles of
    Tesoro Alaska  Production Company.

43.  C. Burgh,  (September 16, 1987). RCRA Inspection Report DEC on
    Chevron USA  Kenai Refinery.

44.  c.  Findley,  (November 14, 1984).  Notice  of  Violation and
    Warning  letter from  EPA to Keith Laurie  of Union Oil Company
    of California.


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45.  M. Caldwell, (September 30, 1986 - facsimile date). Complaint
     and Compliance Order RCRA  Docket  Number 1086-07-12-3008 from
     EPA to Tesoro Alaska Petroleum  Company.

46.  C. Findley,  (September  28, 1987). Complaint and  Final Order
     on Consent Requiring Submission  and Implementation of Proposal
     for Sampling, Analysis,  Monitoring, and Reporting RCRA Docket
     Number 1086-07-12-3008 from EPA  to Tesoro Alaska Petroleum Co.

47.  I. Alexakos, (November 12,  1987).  memorandum of EPA to C.Rice.

48.  W. White, (August 31,  1988). letter from Unocal-Mitsubishi to
     Senator F. Murkowski.

49.  D. Turner,  (July 20, 1983). letter Unocal to M.  Lucky of DEC.

50.  C. Scott, (January 22, 1975). letter from Unocal to D.  Wright
     of Collier Carbon and Chemical  Corp.

51.  G. Miller,  (June 6,  1985) .  memorandum of DEC to  D.  DiTraglia.

52.  Tryck, Nyman and Hayes.  (1987).

53.  L.  Dietrick,  (September 14,  1988).  letter  from  DEC  to C.
     Reller.
                               356

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ENVIRONMENTAL  EVALUATION  OF  OIL  DRILLING   AND  COLLECTION
SYSTEM- A CASE STUDY  FROM INDIA
K C  BARUAH
Central  Pollution  Control Board/
46-B/  Gautamnagar;  Race Course/
Vadodara -  390  007  (Gujarat)
INDIA
PREAMBLE  :

Environmental   evaluation  of  oil  drilling   and   collection,
system was first made during 1982 in a limited  area of  Eastern
Region of  Oil  and  Natuaral  Gas  Commission   (ONGC)  anc  Oil
India Limited(OIL) in Assam.  Environmental damage  as a result
of these  activities  observed at that  period was so prominent
that  a  follow-up  visit2 was  made  in  1985 to  have an  impact
study and also to evaluate the status of pollution.

Increaseddemand on petroleum:

Consumption of  petroleum  products  in  India  is  in leaps  and
bounds. Trend  in  rise is  steep:  In  seventies/ when the  rise
was  about  5%, between  1981  and 1987,  it was  40%; from  49.8
million  tons  in  1988-89  to  projected  95  million  tons  in
1999-2000, the  rise  is  91%  About  56%  of this  accounts  for
transport  sector.  The   vehicles   population  from   meagre  10
million  in 1987  is  expected to  be  a  little more than  42
million  in 2000  AD. So  there will  be  no respite from  the
steep rise of consumption of  petroleum.  India having  a  poor
foreign  exchange  reserve  with  large  deficit   budget  can  not
afford  the luxury  of  importing  more  crude.  Only recourse
left is to exploit more  from domestic crude.

Extended Exploration Activity

The  area  of operation of both ONGC and  OIL has been extended
throughout the length and  breadth  of the  country.  An environ-
mental audit  thus becomes all the  more  important. Study  of
environmental   impact,  then  and  now,  corrective measures
already  taken  and  scope  of  further  improvement, necessity
of development of standards for such activities as  a guideline
                             357

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to  the  explorers  becomes very  significant. For  convenience
however/  the  study  is  restricted  to  on-shore  production
only.

Environmental damages caused:

Though  "API  Recommended  (RP.51   First   Edition).   On-shore
Production Operating Practices for  Protection of  the  Environ-
ment  was   published  in  1974,  production  of oil  started  in
Eighteenth  century  and  fields  visited  during   the  study
were operational from 1966.

a)  Due to drilling operation:

    In  1982,  about  20  drill-sites  were visited  and  adverse
    environmental impact noticed were:
Major impact

    .Spoiling surrounding  land (Blight):
    Many  temporary  sheds are  built  and  lot  of excavation
    takes  place  to  set   the  irilling  rig. After   drilling
    operations were over, all scars  are left behind.
    .Destroying plants and vegetation  including  crops.

    .Oily patches around drill-sites  were a common  sight.
Medium impacts

    .Threat  to animal  life  due  to  grazing  in  oil   covered
    land  -cattle-death  was  reported due  to  grazing  in such
    areas. All rejects of drill-sites were nowere  contained.
Major impacts

    .Destroying  rare fibre-producing  worms  (Muga)  which are
    unique  and  specific  of  North  Eastern  states  of  India
    -  a  specie very sensitive to  noise  and  may be to  hydro-
    carbons  often  due  to  burning  of  left  over  crude and
    waste  lubricants,   are  getting  extinct  and  has  become
    an  endangered  specie in operational  areas  where  it grew
    in  abudance.  This  has  adversely  affected   the  rural
    economy of flood-prone population.
    .Top  soil,  ground  water and  surface  water  was  badly
    affected.  Damage  to  soil  was   irreversible.  Oil  found
    in  shallow hand  tube wells  for drinking  purposes were
    found  infested with oil.
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  .Possible threat  to  human health is yet to be assertained.

Flowing  of oil  laden  waste from  so-called  evaporation  i.
pits  supposed to be  used  for  evaporation of  the formation
water  by  using  natural  gas  only  added  another dimension
of the  problem  of unburnt  hyudro-carbons  in  addition to
highly  saline  oily waste  flowing  down to  cultivable land/
streams  and finally the river sources.

b) Due to  collecting  system

  In  oil  collecting   stations   (DCS)   or  Group  Gathering
  stations (GGS),  the  environmental impact was more persis-
  tent  and  acute  compared to  drilling sites  which  was a
  transitory  phenomenon.  Due  to   againg of  the  filed  oil
  &  gas flows  out with  30%  to  40%  (Sometimes  as  high as
  95%)  formation water.  In the OCS,  crude and  gas is sepa-
  rated  through  Emulsion  Treater  under  physico-chemical
  process, adding  chemical  at  60°c  to  65°c.  The   treated
  water  from  Emulsion  Treater  was   taken  to  evaporation
  pits  where  with the help of  natural gas/ this  water is
  supposed  to  be  evaporated/  neither  being  completely
  evaporated  nor  the  natural   gas  was   completely  burnt.
  This  resulted  in air, water  and land  pollution.  In some
  ideal cases  only,  the  formation  water  was  injected back
  into  formation for pressure build-up  in  the reservior.

  Due  to  round-the-clock  flare  in   the  evaporation  pits
  neither fenced nor enclosed with  asestos sheets  or  protec-
  tive  brick  walls,   the  tea  bushes nearby were affected
  reducing tea crops and paddy  crops  did not give  the  desir-
  able  yield.  Due  to  incomplete  combustion,  unburnt hydro-
  carbons  released into  the environment,  thick  smoke  was
  a  common  sight.  The  effect  of this  on  plant, vegetation
  or even human health could not be estimated. A Schematic
  diagram of a GGS is  shown in  Fig. 1,  appendix.I.

Desirable practice

API  RP51 "is  an industry  consensus  on  recommended onshore
pro'duction operation practices for protection of  the  environ-
ment"  Though  it can "improve company  profits by approaching
environmental  consideration  in  and   orderly  and  planned
manner",  the   realisation   did  not  come fully  at  least  to
                        359

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company till  the study  was  made  in  1982.  The other  company
by tradition had developed good environmental  practice-injec-
ted the  treated formation water  into dry  well or well  sunk
for  this  purpose   and  monitored ground  water  around  such
injection well to see  if it was polluted:

-even in case of necessity to flare the unutilized gas  either
 surplus  due  to less off-take by customers  or  lean  gas at
 low  pressure,  flaring  was  either  stopped  or  brought to
 a bare minimum during October to  December when seed formation
 in  paddy  took  place.  The  excess  natural gas  is released
 in a controlled way atop a stack  at a higher  level.

Actual practice:

In  spite  of  a  claim  to  have  total  evaporation  and zero
discharge  from  the  evaporation   pits,  in  actual  practice.
it was found to let out the formation water into the environ-
ment  having a  COD  upto 15680 mg/1  and oil  and  grease  upto
1261  mg/1  (copies  of  analysis   reports  placed  at Table  1
and  2,   Appendix  II  & ITT.  Such  discharges  into  adjoining
land  caused  stagnation  with  top layer  of  oil  completely
spoiling  the  vegetation,  the  fertile  paddy  land sometimes
converted to stagnant  p©61.

Follow-up

In  earlier  findings  of 1982,   environmental damages   were
reported  and  remedial  measures  were  suggested  to  follow
desirable practices.

Therefore,  a  second  impact  study  and  also  an  evaluation
of  the  pollution  status  were  done    by  the  Central  Board
in  association  with   the  Assam   Pollution  Control  Board in
April-May,  1985. The objectives of the present study were:

a)  to  evaluate  the  present  status  of  the  Group Gathering
   Stations(GGS) in the Lakwa Oil-field in respect of flaring,
   wastewater  disposal,  oil-spill etc. and  to make a compa-
   rative  study between  the  conditions prevailing  in 1982-
   83 and those at present.

b) to  study the performance of  the  Effluent  Treatment Plant
   (ETP) at Lakwa.

c) to  study the conditions of GGSs  and  Oil-fields at Rudra-
   sagar, Galeki and Borhola areas.
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d)  to study the  conditions of drilling sites in general.

e)  to  study  the water  injection  system recently introduced
   in some of  the  oil-fields of ONGC in Assam.

f)  to  make  a  general  assessment  of the  environmental
   damages  that may  be  caused by  oil-exploration  and  to
   suggest probable remedies to abate such pollution.

During  the  period  from April  30  to May  3,  1985 the three
oil fields  of  Lakwa/  Galeki/  Rudrasagar  areas  of  ONGC
were  photographed/  and  Borhola  area  was  inspected.  The
ETP at  Lakwa was visited  to study its performance/  critical
areas   were  photographed  .and  samples  of  the  wastewater
at  the  different  stages  of treatment  were  collected  for
analysis of their  oil  and  grease  and pH content. The report
of  the  analysis  is  annexed  at  Annexure  IV  at  Table  2.
In  table 3/  the  range of  parameters  like  oil (free  and
emulsified)/  pH/  Total alkalinity/  salinity/  TDS  and  COD
as  observed in  different  units of  the ETP  for April  1985
are shown.

The proposed  site for water-injection  system, which  was
under  construction at  the  Galeki  fields was also inspected.
During  discussion/ it  was  revealed  by the ONGC authorities
that  only  the  tube-well  water  would  be  injected  to  the
reservoir down  below  for  building  up pressure  in  the  oil
bearing strata.

Findings

Overall findings
At  the  first  impression  it appeared  that  the oil-fields
belonging to  ONGC situated at  Lakwa/ Rudrasagar/  Galeki
and Borhola were  better  maintained  when  compared  to  the
conditions  prevailing   in 1982-83. Also,  there was  a change
in  the  attitude of the people  manning these installations/
and apparently  prevention  of  pollution  was  getting  some
priority. There was an appreciable  improvement in  cleaning
the environment.

Production wells.
Some  of the drilling well  revisited bore scars of  original
drilling and evidences  of  oil-spill  and leakages-
GGS:
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Improvement was seen,  streams  were  cleared  of oil,  it was
expected  that  surrounding  areas might  be  fit for vegetation
after  sometime.   Some  of  the  flare  pits  were  found  still
kept open.  Seepages  through broken masonry walls of evapora-
tion pit appeared to be a common  feature.

Effluent Disposal Methods

In  the oil  fields  surveyed,  the wastes are  being disposed
in the following manners.

a) Physico-chemical treatment

b) Disposal in wells

c) Vaporisation in flare-pits

d) Releasing the effluent without treatment  into environment.

Physico-chemical Treatment:
In  the Lakwa  fields,  the  ONGC  has  installed  one  ETP which
is  functioning well.  It  was  understood that  it  would take
the  entire  effluent  from  the  Lakwa  area.  The  ETP,  apart
from  treating  the  effluent  is  also  helping  in  recovering
substantial quantity of slop oil(Fig.  2,  Annexure  TV

The treatment  was found to  be effective  and  result  of  analysis
of    grab sample  for one month is shown in range  (Analysis
report of  effluent is annexed at  Table 3, Annexure  V)

Disposal  in Wells

Disposal  of the  effluent in wells  is practised  in  some  of
the  oil-fields of  OIL.   Its  efficacy and  long-term effects
on  groundwater,   if  any,  quantity-disposal,  and cost-effec-
tiveness  are yet  to be studied.

Vaporisation in Flare-pits:
This  system is  in  vogue  in most  of  the GGSs.  But whether
it  really  evaporates  the  entire  quantity  of effluent  is
not  knowo. In  all  probabilities,  it  does  not.  These pits
are  often  flooded  and  the  effluent  goes  out.  It  is not
possible  to contain the  effluent water  entirely  within the
pits.

Release of  Raw Effluent:
Instances  of occasional,  accidental  and  even  regular discharge
of  untreated  effluent  into  the environment  are  prevailing
in  some areas.
                          362

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Wash Water Tank:
In Rudrasagar  area,  ONGC  authorities  are  experimenting  with
wash-water  tank to  remove oil  from the  effluent by  applying
heat and using  compressed air.

RECOMMENDATION

In  the  oil-fields,  environmental  awareness  must   be  given
top priority and  all  sections of  people  should be made  aware
of the necessarty  environmental protection.

It is essential  that  ETPs  are  constructed  in  all  the  oil-
fields  for  the  treatment   of  entire  effluent.  The  treated
water  may be  allowed  to  be  discharged or  it may be  suitably
used.

The practice of  evaporating  the  effluent at evaporating  pits
should be  discontinued.                               ~

However,  so  long  the  evaporation  pits  are  in use,  masonary
walls  and other structures  are to be so  designed and  constrc-
ted to ensure  total elimation of  spillages or seepages.  Dis-
charge  of  effluent  to  suitable   underground  strata  or  into
dry-wells  may  be  practised  but   it  must  be  seen  that  such
effluent  does  not  mix  with  the  aquifers of shallow or  deep-
tube wells.

Ways and  means  must  be  found out  to use  the  natural  gas,
so that  the practice  of  flaring  may  be discontinued  except
for emergency and for  other technical reasons.

Regarding  drill  site,  the American  Petroleum  Institute  reco-
mmendations  (API  RP  51,   October  74)  should  be  strictly  ad-
hered  to.

Continuous monitoring and  adoption of anti-pollution  measures
by inhouse committees  should be encouraged.

Dissolved  air  floatation system  whereever  possible  and  is
found  to  have practical application may be  attempted.

Continuous  monitoring  system  for  NOKHC  and  SPM  should  be
established at  selected locations:

In-depth   study of  effects  of oil exploration,  drilling  and
production  activities  on  the  silk-worms,  around-water  in
particular  and other  flora  and   fauna  is  general  should  be
made.


                          363

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Evaluation of Minimal  National  Standards  (MINAS)  for  Industrial and

                           other Discharges.
Water  Pollution  Control Programmes  are  designed  essentially  to  maintain/
restore the  natural  water  bodies  to  various  designed  best  use.    General
approach  to  achieve this objective would  be using any  one of the following
tools or combination thereof:

-  Control  of  Pollution  at  the  sources  to  the extent  possible giving  due
regard  to  techno-economic feasibility  and  social expectation.

- Optimal  utilization of assimilative capacities of natural water bodies  to
minimize investment  in pollution control  at source.

Maximization of  reuse/recycle  of  domestic and   industrial  wastewater on
land for agricultural use of industrial purpose.

-  Minimization  of  pollution  control  requirements  by  judicious  location
of industries and  relocation of  industries  wherever necessary.

-  Introduction of  discipline in  water abstraction  and  wastewater discharge
and  a  sense of water  conservation.

-  River flow regulation.

This  water   quality  management  in  any   region   involves  manipulation of
several  tools  individually  and  in  combination  to  achieve the  end  objective
which in  this case, is  the  optimal utilization of  water  resources.

The industry-specific  effluent  standards  which   will  be  evolved  at  the
national  level is  to  be  recognised  as  "Minimal  National  Standards".
This model  envisages  treatment  of all  wastes  to certain  minimum standards
regardless of the type  of wastewaters  and  locations.   No  State  Boards
are  required  to  relax on  the  "Minimal  National  Standards",  but  if  the
quality  criteria  of  the  ambient  water  at  some  reaches  warrants  stricter
effluent quality  the  State  Boards shall  prescribe  that  and  thus   would
make  the  Minimal  National  Standards  altered  to  suit  the location.   This
model  is  effective in halting  the  obvious pollution immediately and envis-
ages  a  steady  progress  in  meeting  the  water  quality  objectives.   It
also provides a  fair  degree of the  flexibility to the  Regulatory  Authority
for  Control  of Water Pollution.

The minimum  treatment to  be  provided  in any   wastewaters  aims  at  the
removal of  the following pollutants:

-  Pathogens by  effective disinfection
-  toxic  substances
-  colloidal  and  dissolved organic  solids
                                364

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- mineral oils
- adjustment of PH


The Minimal  National  Standards,  abbreviated  as  MINAS  are evolved  for
different  types of industry  considering the  treatability of  the  wastewaters
and the  various  unit  processes  and  unit  operations  that  are available
for  treating  such wastewaters.    The  unit  processes  and  unit  operations
are the building  blocks and each has  an associated  factor  and  pollutant
removal factor.    Any  combination of  unit  processes  and  unit  operations
provides  a  stage of  treatment,   the  performance  of  a stage  of treatment
is expressed by  the percentage  of removal  of pollutants.  The  percentage
of removal  does  not  increase continuously  but  by  quantum  as  stages of
treatment  are increased.   To elucidate  further,  the  domestic  waste water
is  subject  conventionally   to the  three  stages  of   treatment:  primary,
secondary,   and   tertiary.     With  each  stages  of treatment  the  quality
of the treated  effluent,  if  expressed by the  conventional  parameter  BOD,
improves  from  BOD  removal efficiency  of  30  percent  by  primary  stage
to 85  percent  by  secondary  stage  to  95%  by tertiary stage  of treatment.

The acceptability of the  MINAS  is linked to  the techno-economic  accepta-
bility  of the suggested stage of  treatment to the polluted  which is possible
by  linking  the  annual cost of  pollution control  measures  (capital  and
capitalized  operation,  maintenance  and  repair cost  converted  into  annual
burden) to  the  annual  turnover  of the industry.    The stage  of treatment
whose  annual burden  remains   within  the  critical  percentage  of  annual
turnover  is  generally  accepted   as  minimal  stage of  treatment  and  the
concomitant  effluent  standards  is  the  MINAS.    There   may  be  medium
hard  industry for whom the annual burden  of  the minimal stage of treat-
ment  should  remain  above   the  critical  percentage  of  annual  turnover
but below  the super-critical  percentage.   The  industries  for  whom  the
annual  burden  of  the  minimal  stage of  treatment remains  above super-
critical  percentage   of annual   turnover   are   obviously   hard  industry.
What  percentage   of  annual   turnover  is  critical and   super-critical  is to
be  decided  by  the Industry  Committee.

Though the MINAS for oil   Refinery  has  been  developed  in 1981-82,  the
field   of  oil  drilling  operations  with  collection and  transport system
was so far  not  done in  India.    Recently in Dec.'89  M/s.  Engineers  India
Ltd.,   a  Govt.  of India  undertaking  has  been  engaged  by  the  Ministry
of Environment  5  Forests,  Govt.  of India to develop the  MINAS.   While
 developing the MuN^S, stress has been  laid to method of disposal of  waste drilling fluids,
 its probable effects  on  soil,   method  of  treatment  of  formation  water,
 efficacy  of different  process units in  an effluent  treatment plant  alongwith
 the use of  chemicals alongwith cost economics  thereof.
                                  365

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Effluent Treatment Plant 6 Lakwa

Plant Lay-out

The  plant lay-out  is  shown in  Figure  2  of Appendix  IV.    The  process
units comprise of

      Surge ponds - 2 Nos of 5000 M capacity
      API  Gravity Oil  Seperator - 2 Nos

      Flash mixer - 2  Nos

      Flocculator - 1 No

      Clarifer - 1 No
      Guard  Pond - 1  No of  5000 M   capacity

      Sludge  lagoons -  2  Nos of 4000 M  capacity

      Other units like siop-sump,  supernatant sump,  sludge sump  slop
      tank etc.

Process  Units

A.   Physical process  :

     (1)   Surge  pond

          The effluent from  various GGS  enters  into  the surge pond (one
          number  to  act aas   stand-bye),   the  measurement  of  the flow
          being  made  with  a  Parshal  flume  (Photograph 38).   This unit
          alongwith the  stand-bye unit like  a  balancing tank  shall  effect
          uniform  hydraulic  and   pollutant  loading  and  in case  of plant
          upset/excess flow, the  stand-bye unit  will  be used  for  storage.
          This  unit  is  provided   with   oil-skimming  arrangements  with
          manually  operated  scooping   devices  to  remove  free oil  which
          passes into the slop-off  sump.

     (ii)  API Separators

          The effluent  from  surge  pond   flows  to  the  API  Seperator  at
          controlled  rate where the  free oil  is  removed.    The  industry
          claims  80%  removal  efficiency  of  free  oil in  this  unit.   Two
          channels are  provided,  one  to  act as  stand-bye, in  which free
          oil  is  removed continuously  from  the  top  of the  effluent with
          the help  of wooden  paddles  moved in  a chain.     The top oil
          is   collected in a  slotted  pipe  which  is  taken  to  the   slop oil
          sump.   The oil-free  effluent  passes into the  Flash mixer.

B.        Chemical  process  :

     (iii)  Flash mixer
                                 366

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Rapid  mixing of  chemicals  like  FeSO  ,  alum  lime  and  bentonite  in  the
effluent takes  place.   Usually  a dose of  300-500 mg/1 of  alum,  250-300
mg/1  of lime and 20  mg/1  of  bentonite  are recommended  depending  upon
the  oil  concentration  of  the effluent  from API  seperator  -  lower  does
for the range of  1000  to 2000 mg/1 of  oil  and  higher does for the higher
range of 2000 mg/1  to  4000  mg/1.   On  the  day  of the visit, alternatively
400-500  mg/1  of  ferrous  sulphate  with  250  mg/1  of  lime  and  20  mg/1
of bentonite  was  used.


(iv) Clariflocculator

    The  effluent after thorough mixing of  chemical  moves into this  unit.
    With  the  slow-moving   paddles  attached  to  the  operational  bridge
    and  the sludge scraping arrangements  at  the  bottom,  it  looks  like
    any  other  clarriflocculator  of  a  water treatment  plant.   The  sludge
    collected  at  the  centre  of  the unit  is passed  of to the  sludge-sump
    from  where  the sludge  is  pumped to  the  sludge lagoons  for  drying.
    The  clear  effluent  overflows  to  the  launder  arrangement.    There
    is arrangement  for skimming of floating oil  in the operational  bridge.
    The  skimmed oil  is  taken  to the  slop-oil sump and  the  clear  effluent
    passes  into  the guard pond.

 (v) Guard  pond
    This  unit  is  another tool  in  the  process  to  have  contol  over the
    treated  effluent   before  final   discharge.     With  a  hay-filter   box
    at  the  discharge end,   the residual  oil   traces  shall  be  absorbed
    by  the hay.    This  unit   provides  for   24 hours storage.    There
    is arrangement  for PH adjustment  by adding  sulphuric  acid.

 (vi) Sludge  lagoons
    Chemical  sludge   from  the clarifier  and  oily  sludge  from  the  API
    Seperator  are  pumped to  the   sludge  lagoons.     These  units   are
    just for  thickening  and  drying  of sludge  having  suitable  inlet and
    outlet   arrangements.     The  supernantant   liquid  is  drawn  off   at  3
    3  different  levels to the  wastewater  treatment  plant.   Oil  skimming
    arrangements are  provided in  this  unit  also the  skimmed  oil   being
    sent to the  slop-oil sump.   The  thick sludge with  or without burning
     will be used for  land-fill.

(vii) Anc illiaries/ Facilities

    Chemical storage   for 15  days,  office-cum-operators room,  Laboratory
    and  other   facilities,  chemical  preparation  tank,   pump  houses  for
     pumping of  sludge  and  slop-oil  comprise   of  other  facilities  in  the
     wastewater treatment plant  at Lakwa.
                                    367

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Reference

1.   Asssam  Pollution  Control  Board and  Central !Board'
     for the Prevention and Control of Water Pollution,
     Initial  Environmental   Evaluation   Oil  Drilling  and
     Group  Gathering  Stations/ programme  objective  series,
     PROBES/8/1982-83
2.   Central Board  for the Prevention and Control of Water
     Pollution,   Environmental  Evaluation   of  Oil  Drilling
     and Collection Systems - A Follow-up Pursuit, Programme
     objective series,  PROBES/33/1985-86
                              368

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         Barn
                                                                     To

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             GAS

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                                                               OIL
                                                                     TIOH
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                           Table 1
                                              Annexure II
              Analysis  Report  of Treated Water
                      from GGS II/Lakwa
                 REPORT ON CHEMICAL ANALYSIS
A. Laboratory Reference No
B. Source of the Water
C. Place of collection
D. Sampled by

E. Date of Collection
F. Date of receipt
G. Sent by

H. Sender's reference no.
Tech. 267/82
Water from G.G.S.II/Lakwa
Lakwa.
Shri K.C.Baruah/
Executive Engineer.
2-6-82 at 16.50 Hrs.
4-6-1982
Executive Engineer,
B.P.C.W.P. Assam.
Letter dated 4th June/1982
              PHYSICAL APPERANCE-OILY AND  TURBID
                       CHARACTERISTICS
PH                      (mg/1)
C.O.D                   (mg/1)
Oil and Grease          (mg/1)
Kjeldahl Nitrogen as N  (mg/1)
Chloride as Cl.         (mg/1)
Total Solids            (mg/1)
Total Volatile solids   (mg/1)
7.3
3,120.00
  872.00
   12.8
2,200.0
6/880.0
1,988.0
                             370

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                                       Annexure  III
                          Table 2      "	
             Analysis  Report  of Treated Water
                     from  GGS  III/Lakwa
A.  Laboratory Reference No.     Tech. 268/82.
B.  Source of the water          Water from G.G.S. Ill Lakwa,
C.  Place of collection          Lakwa.
D.  Sampled by                   Shri K.C.Baruah,
                               Executive Engineer/
E.  Date of Collection          2-6-82 at 17.30 Hrs.
F-  Date of receipt              4-6-1982
G.  Sent by                      Executive Engineer,
                               B.P.C.W.P.  Assam.
H.  Sender's reference No.       Letter dated 4th June, 1982.

             PHYSICAL  OILY AND TURBID  (SAMPLE)
pH                    (mg/1)    7.1
C.O.D                 (mg/1)    15,680.0
Oil and Grease         (mg/1)    1261.0
Kajeldahl  Nitrogen  es (mg/1)       5.6
N
Chloride  as Cl.        (mg/1)     500.0
Total Solids           (mg/1)    3,920.0
Total Volatile  Solids (mg/1)    3,640.0
                               371

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                                                BY  PASS
EFrLULUT
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To  Ła*v/  DISPOSAL.
      GKOVND
                                                             To
                                                                               X
                                                                               c
                                                                               m
                                                                              PI

-------
                                           Annexure V

                           TABLE 3
          PERFORMANCE  OF ETP AT LAKWA AS OBSERVED
                FOR THE MONTH OF  APRIL,1985.
Parameters

Unit of ETP
 Oil  (mg/1)
free
Emulsi-  pH
fied
    ,.Salinity  TDS  COD
Alkali-    ,,  2    ,,
nity    m<3
mg/1
Surge pond from trace
inlet to 2,500 to
15,000
Post API nil to
Seperator trace

5,650
to
9,500
1,400
to
4,100
7.6 to
8.0

7.9 to
8.2
—
Guard pond  nil
outlet
           6-11    2.9  to  62to  865to
                   9.5     390   9500
                           1,600to  127
                            2,730   to
                                    240
Source:  ONGC
                          373

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ENVIRONMENTAL   PROTECTION   PLANNING  FOR  PRODUCED  BRINE
DISPOSAL   IN   SOUTHWESTERN  SASKATCHEWAN  NATURAL   GAS
FIELDS
Graham  R.P.  Mutch
Environmental  Assessment  Branch
Saskatchewan  Environment  and  Public  Safety
Regina,  Saskatchewan,   Canada
Int roduct ion

Southwestern  Saskatchewan and adjacent areas  of  southeastern
Alberta, Canada  have  extensive  deposits  of  shallow sweet
natural gas  in the  Milk River,  Medicine Hat,  and  Second White
Specks formations.  A total of some 40 000 gas wells has been
drilled throughout  this  area  located about  midway between
Calgary, Alberta  and Regina,  Saskatchewan  (2).  Saskatchewan's
portion of  this field, termed the Hatton field,  extends west
from Swift  Current,  Saskatchewan  to  the  Alberta border.  The
gas, at depths of some 500 - 600  m,  is easily and  relatively
inexpensively produced using  conventional methodologies.

Southwestern  Saskatchewan has  a  continental  climate, with
warm,  dry summers   (mean  daily  July  temperature:  19  C)   and
cold, dry winters (mean daily January temperature:  -14  C).  It
is one of the most  arid regions in Saskatchewan  (mean  annual
precipitation: about 350 mm),  and  precipitation  is   highly
variable year  to year. Annual  evapotranspiration generally
exceeds precipitation substantially. Prevailing winds from
the  north,  west,  northwest  and southwest  have  an important
influence on evaporation  rate.  Drying action of these winds
during the frost-free  period is significant from  a produced
fluid-disposal perspective.

Land  use  in  the  area is agricultural,  either  ranching   or
cultivation  of annual cereal crops,   primarily wheat. Human
population  is sparse.  Cultivated soils  are predominantly
medium-textured  brown  chernozemic  loams.  There are also
extensive areas  of aeolian  sand,  most  of  which are   thinly
vegetated  grazing  lands. Groundwater,   especially  in   the
                              375

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extensive  sandy areas,  often  occurs at  a depth of  a  few
meters.

Dugouts and shallow wells incorporating wind-driven (and more
recently, electrically powered) pumps  are  used to access the
shallow water. The presence  of  this widely available, easily
obtained, and  relatively high-quality groundwater  is key to
the  ranching  economy and also  during historic times to  the
substantial populations of ungulate  wildlife.

Much of the ranching area, particularly in the 2000 km? Great
Sand Hills,  is relatively inaccessible and  is  considered by
many to  be  a  unique  wilderness  worthy  of  enhanced
environmental  protection. This  concern, together  with a more
general emphasis on shallow groundwater protection, increases
the  priority on  environmentally responsible gas development,
including disposal of blow-down  brines.
The Problem

Hatton  wells  normally operate  with  minimal environmental
impact.  The  wells are  periodically inspected visually,  and
gas meters, which may be remotely located, are read at weekly
to  monthly intervals.  Associated  disturbances are  minimal,
raising  few direct concerns even in environmentally sensitive
areas.  The principal environmental concern  during operation
is  co-production  with  the  gas  of  varying   volumes  of
moderately salty brine  termed blow-down  fluid  or  water  of
condensation.

Gas/water  production ratios vary both over different parts of
the Hatton field  and over  the  average  20-year-plus life  of a
given  well.  Reduction  of  hydrostatic  head by producing the
water  in the  well bore enhances  gas-production rates. Within
the  Saskatchewan  portion  of  the  field,  brine  production
ranges  between 0  to  0.3  m3/well/day   (1),  while production
rates  for the whole field  (Saskatchewan  plus Alberta)  range
between  0 and 1 mVwell/day (2) .    Given  that there are  some
3500  -  4000  producing  Hatton wells  in  Saskatchewan,  with
substantial additional drilling anticipated,  cumulative brine
production is substantial.
                                376

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Brine  characteristics vary  somewhat from  well  to well,  and
from different formations. Table  1  summarizes blow-down  fluid
composition from the three producing formations (2).

Several  options  exist for producing and collecting the  blow-
down brine. Operators may produce the brine at each wellsite,
resulting  in up  to three  brine collection  and  containment
facilities per km2  (8/mi2) .  This approach tended to be  adopted
at older  wells.  More  recently, some  operators  are moving
produced  water  with  the   gas via flow  lines  to  either
centralized metering or compressor  stations.  Flow lines must
be below the  frost  line  (about 2 m) ,  and  collection  systems
designed to allow  efficient  gas/water movement. Frequent line
pigging  is  necessary.   Central  collection   allows  more
efficient  handling,  including  facility  construction  and
reduced trucking  and  other costs. The wide dispersal and
discontinuous arrangement   of  production   areas  complicates
brine-disposal options, both economically and logistically.
Historical  Practices

Enhanced environmental  awareness and  rapid development in the
Hatton  field have  increased  concern  with  brine-disposal
practices in government,  industry and the  public.  Prior to
1987, the  small  quantities produced  in Saskatchewan  were
usually blown to  atmosphere,  coating plants  and the ground
surface  with fine  clays  and  releasing soluble materials,
primarily salts, into the environment (2).

Concern with implications of this practice  for  groundwater,
soils,  vegetation  and livestock/wildlife grew in the  1980's,
accentuating increasingly  negative  public  perceptions.
Operators,  required  to  collect  these  materials  in pits and/or
tanks,   were  faced with the question of  disposal.  Accepted
practice was to dump the brines  in a relatively unregulated
manner,   usually  into  shallow, often  intermittent,  alkali
 (sodium sulphate)  waterbodies  or sloughs near the production
area. While  there  was no  direct  evidence  of groundwater
contamination  (these  sloughs  are normally  in  groundwater-
discharge areas)  or of problems  associated  with  overflows
from the sloughs,  concern  grew on the part of government and
industry  that   legal  and  environmental  problems   could be
created. Continued unregulated  disposal in this  manner became
unacceptable.
                               377

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Few other options have been available  for brine  disposal. The
Hatton area  has  had a lack  of  brine-injection wells within
economic  hauling distance.  Besides cost,  trucking damages
rural  roads  constructed  to  relatively  low  standards and
adversely affects  unimproved  trails  in  environmentally
sensitive  terrain.  Surface  spreading,  even on  a one-time
basis, was never considered an acceptable  alternative due to
concern for groundwater and soil  quality.
The Environmental Review Process

Saskatchewan  Environment  and Public  Safety  administers The
Environmental Assessment  Act,  the legislative reference for
the   province's  environmental-impact  assessment  (ETA)
procedures  (5) .   The  EIA process  can  be  divided  into  two
functional  components (4).  The first  step  is  the initial
inter-agency  review  or  screening  of  disclosure  documents
 (project proposal) to identify  environmental issues  raised by
the  proposal  and to  determine  whether a full-scale  EIA is
necessary. After obtaining what  is  in  effect an  "approval-in-
principle"  following  the  proposal  review,  proposals  are
referred  to  other  provincial   agencies to obtain  specific
licences  or permits.  If  an EIA  is required,  however,  the
second part of the  review procedure ensues, with preparation
and  review  of the EIA and  ultimately  a decision on project
acceptability.

Since  initiation of  the requirement  for detailed,  formal
environmental reviews (screening)  of brine-disposal  proposals
on  January  1, 1989,  some  30 proposed  facilities  have been
reviewed  (to  July 1,  1990). These reviews are coordinated by
the  Department  of  Environment  and Public Safety,  but they
involve   all  other provincial  agencies with  regulatory
interests or  other  concerns. Those few proposals which were
felt  to  be  unacceptable  at the conclusion of  the proposal
review  were  voluntarily  modified  or  withdrawn  by  the
proponents  without  attempting  to  obtain  approval  for  the
original proposal through  a  full-scale EIA review.

Once  the  environmental review  is  satisfactorily completed,
and  the  proposed  design  and operation of  the  disposal
facility considered environmentally acceptable,  the  principal
approving agency  becomes the Department of Energy and Mines.
This  provincial  agency is  directly responsible  for most on-
                                  378

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lease hydrocarbon-development activities,  including drilling,
cleanups,  waste  disposal,  spills,  and  abandonment.  They
inspect  approved  disposal  sites  during  construction  and
operation,  specify  monitoring  requirements,  receive  and
review  all monitoring  data,  and  may  require operational
changes or  site  decommissioning and closure in  the  event of
environmental problems or  non-compliance with  operating
conditions. Additional  regulatory requirements may relate to
local  zoning  ordinances, approvals  for drainage  works,  and
agreements with the land owner/occupant.
Acceptable Options for Disposal/Storage

Current policy  developed  cooperatively  by  Saskatchewan
Environment  and  Public  Safety and  Saskatchewan Energy  and
Mines,  in  consultation  with other  provincial  agencies,
recognizes  three on-surface disposal/evaporation  procedures
as acceptable  in principle for disposal of blow-down  brines
in southwestern Saskatchewan (3).  Policy  requires that all on-
surface,  brine-disposal or -storage  facilities  undergo  a
detailed,  pre-construction  environmental  review. Proposals
must   be    prepared   by  licensed   engineers   and/or
hydrogeologists,  and  must demonstrate  both  horizontal  and
vertical  fluid  containment,   based  on  some  combination  of
natural and engineered features.

Policy  now  emphasizes  waste management,  as  opposed to  simply
considering waste disposal,  as a  key  consideration.   Where
available,  deep-well disposal  remains  the preferred  brine-
disposal option from an environmental point of view.

The three  basic brine-disposal options  considered  acceptable
in principle are:

-  Disposal  for evaporation into  confined areas  of  alkali
   sloughs.  Approved  sloughs  will  have  confined  drainage
   basins,  groundwater  discharge,  and  high-concentration
   surficial deposits  of sodium sulphate  (Na2S04) and other
   salts  due  to  long-term  evaporation.  Geochemistry  of
   groundwater  in these  sloughs is commonly highly saline (TDS
   greater than 30 000 mg/L, dominated by sodium and sulphate)
   and  unsuitable for domestic or  livestock  consumption  or
                              379

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  irrigation.  Alternate uses of  these  sloughs must  also  be
  considered;

- Disposal  for evaporation  into  non-alkali  depressions
  lacking  shallow groundwater and underlain by >  5  m of low-
  permeability  clays; and

- Disposal  for  storage/evaporation   into   double-lined,
  engineered ponds, with between-liner monitoring.

At  each  of  these  facility  types,  secure  fencing and
piezometers  with  prescribed  monitoring   protocols  are
required.
The balance of  this  paper  outlines  in some detail the basic
design requirements  and  information  which must be submitted
by the  developer for  environmental  review of  each  type of
surface storage/disposal/evaporation facility -
Alkali Sloughs

The following requirements pertain  to direct  dumping  of blow-
down brines into unlined,  alkali sloughs:

i)      a qualified hydrogeologist  shall  document  groundwater
        level and  determine  whether the  location  is  in a
        groundwater  recharge  or  discharge  zone.  Unlined
        disposal sites  in  slough areas will be permitted  only
        in clearly  defined groundwater-discharge  zones;

ii)     report grouhdwater quality at disposal site;

iii)    report quality  of ponded surface water (if present);

iv)     perform  testhole  logs using  standard  procedures to
        describe soil characteristics to a minimum 10-m depth;

v)      a qualified hydrologist shall describe hydrology of
        the slough  and  surrounding drainage basin:

             estimated  effective  and gross drainage  areas of
             the slough and  a  plan  illustrating these areas;
                               380

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           anticipated runoff  volumes  (mean  and  l-in-25-
           year extreme events)  into the slough;

           estimated slough spill  (overflow)  frequency with
           and  without  dumping additional  material.    A
           multi-year   simulation   of   fluid   levels
           incorporating wet years  is advisable.  Indicate
           downstream implications of  slough spillage;

           estimated annual gross  and  net  evaporation  (mean
           and l-in-25-year extreme  events),  and derivation
           of these  estimates explained.  Include allowance
           for   excessive  precipitation,   below-normal
           evaporation,  and salinity effects  on evaporation
           rates;

  vi)  describe   and  evaluate  any   proposed  hydrologic
      isolation of the proposed  disposal area  (e.g.,  dykes),
      and  estimate  storage  volume  of  the isolated  area.
      Size  of  the  area  which  may   be   used should be
      minimized.   Will  isolation  measures affect  existing
      water levels, run-off patterns,  and nearby lands?

vii)   include   a  statement  from  appropriate  licensed
      professional(s)  that  the  facility  is  capable of
      receiving annually  a  specific maximum volume of wastes
      and  isolating these  wastes  so as  to  prevent   both
      vertical and  horizontal migration.  Waste  containment
      and isolation must  be based on demonstration of all of
      the following:

           hydrologic  isolation  -   dykes,   landforms,
           localized extent of the slough;

           horizontal isolation  -  absence  of  permeable zone
           at or near surface;

           vertical isolation -  groundwater discharge zone;

           a calculated net annual evaporation potential on
           average  in excess  of  the  proposed  fluid  disposal
           volumes plus  estimated natural water inflows;

viii)  include other relevant information, such as:
                               381

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            detailed chemical characterization of wastes;

            locations  of  surface and  groundwater users  and
            water quality  in dugouts, wells,  impoundments,
            lakes or streams within  1 km;

            monitoring  program  for  leakage   detection.
            Piezometers installed according  to  conventional
            protocols and to  an  appropriate  depth  are  to  be
            located on each side  of  the slough. Submit twice-
            yearly  tests  of piezometers  and monitoring,  or
            more frequently as may be required;

            describe  other actual  or  potential beneficial
            uses of the proposed location  -  e.g.,  wildlife,
            particularly waterfowl.  Describe vegetation;

            contingency  plans   for  flooding,   lack   of
            evaporation,  leaking, and major spills;

            evidence   of   landowner/occupant   and   local
            government approval/consent;

            fencing and gating to prevent  public,  livestock
            and wildlife access;

            facilities for fluid  dumping and access;

            decommissioning plans,  including potential need
            for  remediation  and/or  disposal  of   salt-
            contaminated   soils .     The  proponent  must
            explicitly  accept   responsibility  for  all
            reclamation  and  disposal  requirements  at the
            time of decommissioning.
Non-alkali  Depressions

Requirements  pertaining to direct dumping of blow-down brines
into  shallow,   unlined,   non-alkali   depressions   (e.g.,
topographic lows,  kettle  sloughs)  are  similar  to those which
apply to alkali  sloughs.  The points which  follow  represent
the  differences  in information and design  requirements  for
disposal into non-alkali depressions. Requirements  numbered
                                382

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ii), iii),  v),  vi),  and viii)  for Alkali Sloughs (above),  and
pertaining to the following topics,  are  common  to  non-alkali
depressions: groundwater quality  and production  potential,
quality of  any ponded  surface water,  basic hydrology  data
(including estimated capacity of the  depression) ,  methods  of
hydrologic  isolation,  nearby water  users  and water  quality
data,  monitoring  programs,  waste  characterization,  other
potential  uses  of   the  location,  contingency  plans,
appropriate approvals/consents,   ancillary  design  details
(fencing,   gating,   access),  and  decommissioning  plans.
Additional information includes:

i)      this practice  is NOT a preferred option,  and any such
       proposal  MUST  be accompanied by an  explanation of  why
       alternate methods/locations are not proposed;

ii)     a  qualified hydrogeologist  shall  document groundwater
       level and  determine  whether  the  location  is  in  a
       groundwater  recharge or discharge zone.  Disposal into
       shallow,   unlined,  non-alkali depressions  may   be
       permitted only in areas adequately underlain  by  low-
       permeability natural materials;

iii)    perform a minimum of four testhole logs using standard
       procedures  to  describe  soil  characteristics  to  a
       minimum 10-m depth.  Determine soil permeability;

iv)     include  a  statement  from   appropriate   licensed
       professional(s)  that  the  facility  is capable   of
       receiving annually a specific maximum volume of wastes
       and  isolating these  wastes  so  as  to  prevent both
       vertical  and horizontal migration. Waste containment
       and isolation  must be  based on demonstration of all  of
       the following:

            hydrologic  isolation  -  dykes,   landforms,
            localized extent  of the basin;

            vertical   isolation  -  low-permeability clay  or
            other  similar material (in the range of 1 X 10~7
            cm/sec or  lower  in  situ, after  salt-saturation
            effects on the soil)  to a depth of  at  least 5  m
            below  the base  of the  disposal location;
                               383

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            horizontal  isolation   -   presence   of  low-
            permeability  zones  at  surface  and  at depth.
            There   must  be  a  demonstrated   absence  of
            interbedded, high-permeability materials (e.g.,
            sand,  gravel)  within  the  required   5-m  low-
            permeability  zone   forming the sides  of  and
            underlying the disposal location;

            a  calculated net annual evaporation potential on
            average  in  excess  of  proposed fluid disposal
            volumes plus estimated natural  water  inflows.
Lined Evaporation Ponds

The  following  requirements pertain  to proposals  for  lined
storage/evaporation ponds.  Lined ponds are required wherever
brine containment cannot  be  guaranteed based  on  soil  type,
hydrodynamics  (groundwater discharge)  and landform.

i)       document groundwater level  and quality;

ii)     report quality of any ponded surface water;

iii)    perform  testhole logs  using  standard  procedures  to
        describe  soil  characteristics  to  a minimum 5-m depth
        below projected pond base;

iv)     provide  detailed design for lined ponds,  including a
        statement  of  design  life.    A double-lined  system
        incorporating  a sump and monitoring  between  the two
        liners  normally  is required.   How  will  fluids  be
        dumped  into  the pond?  A minimum  0.3-m freeboard is
        required;

v)       include  liner  specifications and ability to withstand
        anticipated     stressors   (e.g.,  cold,   flexing,
        chemicals, UV, IR, and freeze-thaw and wet-dry);

vi)     include  incidental design  elements   such  as  surface
        diversions to  exclude runoff,   fencing,  and  rope
        ladders to assist emergency escape;

vii)    evaluate  the  pond's annual  gross and net evaporative
        potential  and  explain  derivation  of  these estimates.
                                384

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      Precipitation, run-off (from dykes),  drifted snow, and
      evaporative  potential  for  mean  and  l-in-25-year
      extremes  are   to  be  considered.    Anticipated
      evaporation  rates  should   include  allowance  for
      excessive precipitation,  below-normal evaporation, and
      salinity effects  on evaporation  rates.  Where  will
      excess  (non-evaporated)  fluids be disposed? Clean-out
      and  disposal   of  accumulated  solids  should  be
      discussed;

viii)   include  a  statement   from  appropriate  licensed
      professional(s)  that the  facility  is  capable  of
       receiving annually a specific maximum volume of wastes
       and  isolating  these wastes so as  to  prevent  both
       vertical and horizontal migration;

ix)     include a variety of  other  relevant information,  as
       outlined in point  viii) under Alkali  Sloughs, above.
References

1. R.  Dafoe,  Saskatchewan  Energy  and  Mines,   personal
  communication,  1990

2. P. Hanley, Management  of Drilling and  Production  Wastes
  from  the  Oil  and  Gas  Industries  of  Saskatchewan  and
  Alberta,  M.Sc.  Thesis, University of  Alberta,  Edmonton,
  1989

3. Saskatchewan Environment and  Public  Safety,  Saskatchewan
  Energy and Mines,  Policy Statement: Handling of Blow-Down
  Brines and Salt-Based Drilling Mud Systemsf  Regina, 1990

4. Saskatchewan   Environment   and  Public  Safety,   The
  Saskatchewan Environmental  Assessment and Review Process,
  Regina,  1988

5. Saskatchewan Government,  The Environmental Assessment Act.
  1980,  Chapter  E-10.1 of   The  Revised  Statutes  of
  Saskatchewan, as revised, Regina
                                385

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Acknowledgements
Larry  Kratt,  former  Director of  Environmental Assessment,
Saskatchewan  Environment  and  Public  Safety,  and  Jerry
Gossard,  Director  of Petroleum Development,  Saskatchewan
Energy and Mines,  kindly  reviewed a draft of this paper.
         Table 1:  Summary of Blow-Down Water Quality,  as
                  reported by  Hanley  (1989)

             Concentration in mg/L - pool  or zone1
Constituent
Total Hardness
(as CaC03)
Total Alkalinity
Salinity as NaCl
Sodium (Na)
Potassium (K)
Calcium (Ca)
Magnesium (Mg)
Iron (Fe)
Chlorine (Cl)
Fluorine (F)
Bicarbonate
(HC03)
Carbonate (C03)
Sulphate (S04)
PH
Total Dissolved
Solids, TDS
Medicine Hat
276

611
11,852
4,440
59.0
48.4
37.2
1.41
6,550
0.37
745

0.00
37.4
7.60
11,919

Second
White
Specks
287

1,161
10,896
4,140
224
42.2
39.8
10.3
6,020
0.16
1,390

12.6
<10.0
8.12
11,870

Milk River
83

636
6,058
2,400
45.4
12.6
12.5
0.205
3,340
0.13
776

0.00
<10.0
8.03
6,587

 1. Except pH
                                 386

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ENVIRONMENTAL   CONSEQUENCES  OF  MISMANAGEMENT  OF  WASTES   FROM
OIL  AND  GAS  EXPLORATION,   DEVELOPMENT,  AND  PRODUCTION
Robert  W.  Hall
Environmental Scientist
U.S.  Environmental  Protection Agency
Washington,  D.C.
Over the past  several years,  EPA has  been  investigating the  environmental
impacts caused  by  oil and  gas  operations in most  producing regions  of the
United States.  Much  of  this research  was  conducted for our 1987  Report to
Congress on exploration,  development, and production wastes required by RCRA—
the Resource Conservation and Recovery Act.

That report  and the  public  comments  we  received led  to  EPA's  regulatory
determination that  oil  and gas  wastes from exploration,  development,  and
production  should  remain  excluded  from  RCRA's  hazardous  waste  management
requirements.   In  making  this  determination,  the Agency  recognized  that
improvements in  waste  management  were needed at least in some instances.  As a
result, EPA and  the  States are now developing strategies for improving oil and
gas  waste  management under  RCRA's provisions  for  managing  nonhazardous
wastes—that is, under Subtitle D of RCRA.   This authority offers the kind of
flexibility and region-specific  responsiveness  that the  States  and industry
need.  From our point of view,  it can  also provide  the  benchmarks needed to
improve the standards  and bring about  consistency in the way  certain wastes
are managed from area  to  area.

This paper illustrates the kinds of problems that need to be addressed.  More
important,  it shows that most of  these problems have proven solutions.  We
have concluded that, although adverse impacts can  result from improper oil and
gas  waste  management,  those impacts can often be minimized  through improved
housekeeping practices and use of existing  technologies.

The  pictures  in this  paper  are  all recent—no earlier than  1987--with most
being taken in 1988.  There are some problem areas, such  as the management of
reserve pits on the Alaska  North  Slope,  that  I  touch on only lightly because
significant progress has  bsen made since we started our research for the  1987
Report to Congress.

Let's  start with disposal of produced water.  Produced  water  is the highest
volume waste  stream generated by production activities  and  has historically
been responsible for  some  adverse environmental  impacts  associated with  this
industry.  Some 20 billion  barrels  of produced  water were generated in  1985,
according  to the estimates  used in the  1987  Report  to Congress.    It is
estimated that most of this produced water (roughly 80 percent)  is reinjected
into Class II  wells.    A  small  percentage,  however, is managed  onsite in
unlined pits or  is  discharged to  surface water.
                                 387

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                              '
             Louisiana, May 1988
Figure 2.   Louisiana,  May 1988.
Figure  1  shows the  impact of  discharges of  produced waters  to freshwater
wetlands in the Gulf Coast  region.   Vegetation damages caused by the release
of saline produced waters  are  clearly visible  in  the  center  of the area shown.
This discharge occurred without  the  required permit.

Figure  2  shows an  unlined produced water skim pit  used  to skim  oil  from
produced  water prior  to  discharge  to  a river in  a protected  freshwater
wetlands area.  This pit  was  constructed out  of porous native peat allowing
for  the potential  of  seepage  of pit  contents  into  the  surrounding  area.
Produced  water  in this  pit   may  contain  benzene,   heavy  metals,   and
radioactivity.
Figure 3 is another example of how disposal of some produced water  in  unlined
onsite pits  can lead to adverse  environmental impacts.   Using such pits to
manage produced water  may  lead to ground-water  contamination, surface water
contamination,  and vegetation  damage.   (Of course,  some  produced waters may be
suitable for beneficial use,  such  as  irrigation.)
                                  388

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                                                                   i
                                                               j     fc
                                                  ••*_»
   Figure 4.   Arkansas, March 1988
Figure 5.
1988
West  Virginia, February
Figure 4 shows  the  results of  long term discharges  of produced  waters  to a
forested area  in  the south.   The  environmental impact  of this  practice is
apparent.   All vegetation is  absent  in the  area  receiving the  discharge.
Although the source of the acute damage  from produced water is chlorides, EPA
remains concerned about  other  potential constituents  of  produced water,  such
as metals,  benzene,  and radioactivity.   Additional information is needed about
the presence  of these  constituents  in produced water  and their  resulting
impacts on  the environment.

Figure  5 shows a reserve pit  that is  located  on a  steep hillside  above a
residential community.    The  pit was  partially  lined with a plastic liner.
Fluids  from  reserve  pits  like this  have  the  potential  to  run  off-site,
potentially contaminating ground water and  surface  water.   This  pit, in fact,
did breach,  discharging produced waters down the hillside.
   Figure 6.   Arkansas,  March 1988
Figure 6  shows  another  example of produced water disposal.    In  this area,
dozens of stripper wells discharge produced water directly onto the surface of
the land.  The  area  shown in the  photograph has been  denuded of vegetation.
The practice has been allowed   for  many  years  and  may  lead to  adverse
environmental impacts.

Currently, management  of produced water—through  use of pits   (particularly
unlined pits) or  discharge  to  streams,  wetlands,  or other  bodies  of  water--
                                  389

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poses threats to the environment  at many  sites.   The solution includes better
housekeeping practices and use of  reinjection  in Class II wells either onsite
or at properly  designed  and maintained centralized  or commercial facilities.
The operable word  here is "proper."   We  have  seen many  cases  where improper
management of produced water has led to adverse environmental impacts.

To illustrate,  let  me  turn  to injection facilities,  which  handle the bulk of
produced water  disposal.  Injection of  produced  water and other aqueous waste
in properly designed  and maintained injection wells provides a  desirable
method  for  managing such wastes;  however,  surface  facilities  (tanks,  pits)
associated with injection facilities can pose RCRA-related problems.
   Figure 7.   Arkansas,  March 1988
Figure 8.  Utah, March 1988
Figure 7, for instance, illustrates a centralized  Class  II injection facility
that  operates  a holding  pit in  conjunction  with the  injection well.   The
facility accepts  many types  of  oilfield wastes,  including tank bottoms  and
produced water.  The  pit  shown  here is  unlined and has  been  in  operation  for
some time.   Housekeeping is poor.

Figure 8 shows another Class  II facility.  At  this facility,  this unlined  pit
is referred to as an emergency overflow  pit,  but the buildup of oil around  the
edge of the pit indicates  that "emergencies"  may be fairly common.
                                   390

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   Figure 9.   Texas, March  1988
i  ,* .

 Figure  10.   Arkansas, March 1988
Figure 9 illustrates  an example  of  proper management  of  produced water.   At
this commercial Class  II  injection facility,  the  pits are lined  with  100-mil
polyethylene lining, and the  site also has ground-water monitoring.   Although
this slide  doesn't show much besides the lined pit,  the  appearance of the site
indicates  good housekeeping practices  where  healthy-looking  vegetation  is
located quite near the pit.

In contrast, this Class II  injection facility (Fig. 10) accepts tank bottoms,
produced water, and many other oilfield wastes.  The unloading hose shown here
spills wastes onto the ground and into a nearby ditch.
                                                        i
                                                            ,,*„.
   Figure 11.   California, May 1988
 Figure 12.   California, May 1988
Figure 11 shows  a  facility where,  among a number  of  desirable features,  the
unloading hose  is  provided  with  its  own containment sump.   Site  operators
perform onsite waste  characterization prior to  accepting any waste,  and have
equipped tanks  with  high  level alarms  and automatic shutoff  valves.   This
                                   391

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picture also illustrates  sound housekeeping practices
of the same site (Fig. 12).
               This  is  another shot
   Figure  13.  Texas, March  1988
Figure 14.   California, April 1988
Figure 13 illustrates another example  of  sound oilfield waste management at a
commercial  disposal facility.   This is a  Class  II injection  well,  equipped
with automatic  injection  of corrosion inhibitor into  the  annulus,  continuous
pressure monitoring,  automatic  shutoff  valves,  and ground-water monitoring.
It provides another example of sound waste management practices.
                                                             •
Let me now  go  on to other types of  centralized or  commercial facilities that
manage produced water  and other oilfield wastes.   While  alternative means of
produced water  disposal,  such as  through  evaporation in  open  centralized or
commercial  pits,  may be  effective in the  more  arid regions of  the country,
minimizing  adverse  environmental  impact   depends  largely  upon the  design,
maintenance, and overall housekeeping practices of a facility.

Figure 14 shows an  example of a poorly designed and maintained unlined ditch
used  by  a  conglomerate  of operators in  California.     Produced water  is
discharged . to   this  unlined ditch  that  leads to  centralized  disposal  pits.
Over  the  years,  ground water  in  the area has been  contaminated  with high
levels of chlorides  and other salts associated with produced water, rendering
the ground water unsuitable for drinking purposes.
                                    392

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Figure 15.
              Louisiana, April  1988
Figure 16.  Louisiana,  May  1988
Figure 15 shows a commercial  landfarm  operation in Louisiana.  It accepts  all
types of oilfield wastes, not  just  produced water.  At this site, trucks wash
out the residue in their tanks directly into ditches.  These  in turn  discharge
into an adjacent stream.

Storage tanks can also be a problem at commercial  facilities.  This commercial
oilfield disposal facility  (Figure  16)  accepted all types of oilfield  wastes.
In this case, oily waste from one  of  the  storage tanks is leaking through  the
earthen berm that is  supposed to contain any  spills  from the tank.  The land
surrounding  the units  shows  signs of contamination  from spills  and  leaks.
[NOTE: the facility is now closed by order of  the  State.]
                            *     **

   Figure 17.   Louisiana,  May 1988
                                        Figure 18.   Louisiana,  March 1988
Figure 17  is  another photograph of the  same commercial  facility, this  time
showing its produced water discharges.   The saline  produced water was  being
discharged directly to a nearby  freshwater stream.
                                   393

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This photo  (Fig.  18) is  taken at an  abandoned crude  oil reclaimer facility
located  directly  adjacent  to the  Intercoastal Waterway on  the  Gulf Coast.
Notice  the oily  berm  surrounding  the  impoundment.    One  of the  problems
associated with some commercial facilities is the absence of  State  remediation
or reclamation requirements.
   Figure 19.   Louisiana,  April 1988

Here's another  photo  taken at an abandoned  commercial  treatment and disposal
facility in the Gulfcoast  area  (Fig.  19).   This one has been proposed for the
CERCLA National Priority List for  cleanup under the Superfund program.   The
site accepted many wastes associated with oilfield operations,  such as fracing
fluids,  emulsifiers,  mud  additives,  biocides,  and workover  fluids,  some of
which may  not have been  suitable  for management through  land treatment and
disposal.

Onsite pits are commonly used to handle categories of oil and  gas wastes other
than produced water,  including drilling muds  and associated oilfield wastes.
Let me now discuss a few issues raised by these multipurpose pits.
   Figure 20.   Alaska, June  1988.
Figure 21.   New Mexico,   March 1988
This picture  (Fig. 20)  shows  well-designed pits used for oily waste disposal.
Note the heavy lining and  the fence  surrounding the site.  This pit was about
to  be  closed but  apparently is in  good condition  even  at  the  end  of its
operating life.
                                  394

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The opposite type of  situation is shown  in  Figure 21.   This site  accepts all
types of  wastes, with  no characterization prior to disposal.    Hydrocarbon
odors were very strong when this site was visited  in  March  1988.

   Figure 22.  Texas, September 1988
Figure 23.   Texas, September 1989
 So far,  I've  discussed design problems,  operational problems,  the  mixture of
 associated wastes with produced water,  closure  problems,  remediation problems,
 wetlands impacts, and surface water  contamination.   But oil and gas operations
 can also pose threats to wildlife.   The next  group  of photographs was provided
 by the  U.S. Fish and Wildlife Service.   This aerial shot  shows extensive oil
 production in the  Southwest  (Fig. 22).   From this bird's-eye  perspective, it
 is  clear  that  in  areas  where  development   is   this   intense,  there's  a
 significant likelihood that  some birds  looking  for  water  will land on oilfield
 waste pits and tanks.

 Figure  23 shows  a typical open sludge pit  within such an  area.   Note that it's
 unlined.   The point of  the picture, however,   is  that it is  also  uncovered,
 offering no barrier to birds  that might enter it.
                              -
   Figure 24.   Texas, September  1989
Figure 25.  Texas, September 1989
Similarly,  this  (Fig.  24)  is  a  typical open-topped storage tank  in  the same
general area of the country.   Note  that  it  too is uncovered.
                                   395

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This photo  (Fig.  25),  taken in the Southwest  in 1989, shows  dead birds in an
open produced water tank.
                                         1,
   Figure 26.  Texas, September 1989
Figure 27.   Texas, September 1989
Here  (Fig. 26) migrating ducks died  in  an  uncovered pit in 1989.  The majority
of pits  that  pose problems  like  this are sump  pits that were  constructed in
the 1940s and 1950s, but are still in use  in  certain states.

Figure 27  shows  a duck carcass at  an oil sludge  pit.   Estimates  vary on how
many birds are destroyed each  year  by entering oilfield  waste  pits and tanks.
A U.S. Fish and  Wildlife study suggests that at least  500,000  animals, mostly
waterfowl  and migratory birds,  were  killed annually  from  the 1950s  to the
early 1980s.
                         •i

   Figure 28.  Texas, September  1989

This is a Sandhill crane carcass taken  from a  sludge pit in 1989 (Fig. 28).
                                   396

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   Figure 29.   Texas,  September 1989
Figure 30.   Texas, September  1989
The solution  to this  problem is  to cover  the pits  and tanks  with mesh  to
prevent animals  from entering.   New Mexico has  recently enacted  regulations
requiring such covering, and  Oklahoma has developed guidelines suggesting  use
of  the same  approach.    Here  is  a sludge  pit   (Fig.  29)  that  has been
effectively covered with wire mesh.

The same technique works for tanks  (Fig.  30).

One category of  wastes  with which EPA is  particularly concerned is  the  broad
catch-all of "associated wastes"  that I've already alluded to.   These  include
various wastes  that  pose special  problems because  of  their often  relatively
high toxicity compared to produced water  and conventional  water-based drilling
fluids.   What  follows  are  some  examples of associated  waste  management
practices that may lead to adverse environmental  impacts.

             1   #•:••&    •
                 '••*»«•   *&&*•:
   Figure 31.   Texas,  September 1989
Figure  32.  Utah,  March 1988
At this site  (Fig.  31),  still  bottoms from a tank bottom  hydrocarbon recovery
process are dumped onto an unlined vacant  lot adjacent  to  the facility.

This is another  site  (Fig.  32) where tank  bottoms are dumped with  no lining,
cover,  or ground-water monitoring.
                                   397

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   Figure 33.  Texas, March  1988
Figure 34 .
1988
West Virginia, February
Figure 33 shows a tank bottom hydrocarbon recovery  operation  using below grade
concrete pits for storage of oily sludges.  No  leak detection or monitoring  is
provided.

This  photograph  (Fig.  34)  shows potential  problems  resulting  from  improper
storage  or  disposal  of  drums containing  solvents, corrosion  inhibitors, and
biocides.   Leakage  from the drums into  a  nearby freshwater  stream poses risk
of surface  contamination.   This type of problem can be directly addressed  by
proper disposal of used containers.

   Figure 35.  New  Mexico,  March 1988
Figure 36.  Utah,  March 1988
Unlined produced water pits are banned  in  certain  areas  of some States because
of high  soil permeability and  relatively  shallow unconfined ground  water.
However,  unlined  drip pits such  as this  (Fig 35) are  still allowed  by  some
States if  the  units  involved  have low  production  rates.   Despite the  low
                                   398

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production rates,  there can still be a potential  for  environmental impacts in
some areas .

This photograph (Fig.  36)  shows  oily heater treater  exhaust  being discharged
to an unlined pit  in one of the western States.

The last group of  slides I want to present  today  are  from Alaska.   As you are
all aware, development in Alaska,  both  on the Kenai peninsula and on the North
Slope,  poses several unique problems—unique in  terms  of production and unique
in  terms  of environmental protection.   One of  the  most important  current
issues is lack of  adequate capacity for offsite  waste  management.
                                                                          .... v
   Figure 37.  Alaska, June  1988
Figure 38.   Alaska, June  1988
As  I mentioned  earlier,  strides have  been  made in the last  several years in
improving  operation and maintenance  of North  Slope  reserve pits.   Problems
like  these are  becoming  less  common.   This  illustration  (Fig.  37)  shows
leakage  of  oily  waste  from  a  reserve  pit,  with  a tundra  kill  in  the
surrounding area.

Here is a photograph  (Fig.  38)  of  an  unreported spill from one of the service
company pads  on the  North Slope .   The  tundra mat  was  saturated  with what
appeared to be  diesel fuel.  This  spill  resulted in issuance  of a  Notice of
Violation  from the Alaska DEC,  but  some  incidents  such  as this  have gone
undetected in  the past  because  of  the  remoteness  of  the area and  the
difficulty of conducting most inspections during the brief summer months.
                                  399

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   Figure 39.    Alaska,  June 1988
Figure 40.
                                                      Alaska,  June 1988
Given the  improvements made in  handling reserve pit  wastes and spills, the
problem  that  we  at  EPA  are concerned about  most is  the general  lack of
capacity available for proper management of wastes  generated by parties  other
than the major  producers.   This is a photograph (Fig. 39)  of  garbage piles,
industrial wastes, and an incinerator  in the service company area of Deadhorse
on the North  Slope.   Note  the  drums  and the array of garbage.  Diesel  fuel
spillage was evident  on the facility's pad.

This illustration (Fig.  40) shows  how  the landfill problem is beginning to
overwhelm  capacity to manage wastes.   It's the  North Slope Oxbow  Municipal
Landfill, which is divided into  two sections—one for municipal wastes and one
for  industrial  oilfield wastes.   Capacity of  the  industrial  segment,  shown
here, was  initially projected  to  be  adequate  for 15 years,  but  it is now
filled.   The State has rejected the permit application  for expanding the  site,
considering it technically inadequate.

It  is  becoming  increasingly difficult  to  site  properly managed  facilities
adequate to handle the demand posed  by the continuing high volume  of  wastes
generated  by  Alaskan production.   However,  some operators  are investigating
the  possibility  of constructing large new waste management  facilities  on the
north slope.
The  illustrations  above demonstrate  a few critical  points.   First,  adverse
impacts resulting from mismanagement of oil and gas wastes are real, but their
degree  ranges  from high to  low.   Although many  States have made  strides  in
recent  years in putting better  controls in  place,  we're  still  faced  with
leftover problems  of  past years, such  as abandoned substandard  sites  of all
types.   In  addition,  we have yet to  put  adequate controls  on  such issues  as
protection of wildlife.

Finally, we  have to plan  for  the future.  When  production  increases,  as  it
eventually  will when  current  depressed  oil  prices  rebound,  we have to  be
prepared for the additional  stresses  this will place on  the waste management
system.
                                  400

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The good, news is  that  oil and  gas  waste management  problems can be  handled
using  improved housekeeping  practices  and  current  technology.    EPA  is
interested in exploring  waste minimisation  and pollution prevention approaches
to reducing  waste generation  at the source,  but  even without new approaches
here, the technology exists to improve most  oilfield  sites.   Onsite  waste
management  remains a  continuing problem,  but it can  be addressed by  making
better use  of offsite facilities and offsite management  techniques,  improving
offsite waste management techniques,  or  using closed circuit  (e.g.,  tanks)
onsite systems.  These  are some of  the issues the Agency will be  tackling  in
the coming months and years.
                                 401

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EVALUATION  OF  CONTAINERIZED  SHRUB  SEEDLINGS  FOR  BIOREMEDIATION OF  OILWELL
RESERVE PITS
Darrell N.  Ueckert
Texas Agricultural Experiment Station
7887 N. Hwy.  87
San Angelo, Texas  76901  U.S.A.
Steve Hartmann and Mark L. McFarland,
University Lands - Surface Interests
The University of Texas System
P.O. Box 553
Midland, Texas  79702  U.S.A.
Abstract

Vegetation (secondary) succession  is  extremely slow on soils  contaminated with
soluble salts by petroleum exploration activities  in arid and  semiarid  areas.
Excessive  salt  accumulations  interfere  with seed  germination  and  seedling
establishment of most species used for revegetation.  Establishment  and  growth
of transplanted  fourwing  saltbush (Atriplex  canescens)  seedlings and  rooted
stem  cuttings,   and  seedlings of  oldman  saltbush  (Atriplex   nummularia),
winterfat  (Ceratoides lanata),  and prostrate kochia  (Kochia prostrata)  were
evaluated on  three  saline-sodic (EC = 23 to  93 ds  nf1 ,   ESP  =  13 to  46%)  oil
well  reserve pits   over  a  3-year period.    Survival  of  fourwing  saltbush
seedlings from an accession not adapted to saline soils was only  32%,  compared
to 1 73% for seedlings  or stem cuttings from an accession adapted to  saline
soil.   Oldman saltbush  suffered   100% mortality  subsequent  to   sub-freezing
temperatures  during   the   first  winter  following  planting.    Survival   of
winterfat and prostrate  kochia  transplants was 61 and 48%, respectively,  after
3 years, and growth of these  species was  acceptable on the saline-sodic  soils.
Selection of specific accessions of species adapted to the existing  conditions
of the  site  to  be revegetated  appeared most  promising for revegetation  under
extremely harsh environmental conditions.


Introduction

Revegetation  of  oil and natural gas   drilling locations  in  arid  and  semiarid
areas  is  complicated by soil profile  disturbance and contamination.  On-site
disposal  of  drilling fluids  in shallow,  earthen pits  (reserve pits) usually
results  in formation  of  salt-affected  soils (1),  and  many  of  these  sites
remain  barren for  decades.  Artificial   revegetation is often  necessary  to
stabilize critical areas and  to attain an acceptable level of productivity.
                                    403

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Several shrub species  are well adapted  to  drought and saline soils because of
structural or physiological  adaptations of roots and foliage  (2,  3).   Fourwing
saltbush  (Atriplex  canescens) has  been used successfully for revegetation of
disturbed,  salt-affected  soils   in the  southwestern  United  States  (4,  1).
However,  many  other native  and  introduced  species from  regions  with similar
soil and  climatological characteristics  warrant evaluation  to  identify plant
materials suitable for  revegetation of  severely disturbed areas.

This paper  reports  results  from a  3-year study  in which  the  potential  of
seedlings and/or  stem  cuttings of 4 shrub  species  for revegetating disturbed,
saline-sodic soils was  evaluated.
Materials and Methods

The  study  site  was near Big Lake  in  Reagan County, Texas  (31°15'N 101°40'W).
The  climate is  semiarid,  with  hot summers  and cold,  dry winters.   Average
annual precipitation  is  414  mm and about 78% of  the precipitation is received
from May  to October.   Estimated mean  annual lake  (free water)  evaporation  is
1800 mm (5).  The  average  daily maximum temperature in July is 35.5° C and the
average frost-free period  is 229  days.   The  soil is a Reagan  silty clay loam
(fine-silty,  mixed,  thermic  family  of  Ustollic calciorthids ).   The  Reagan
series  consists  of deep upland soils  formed in  calcareous, loamy sediment  of
ancient outwash  and aeolian  origin.

Field  plantings  were  established  on  three  oil well  reserve  pits in  1984  to
evaluate  establishment  and  growth  potentials  of:    1)   fourwing  saltbush
seedlings  grown  from  seed harvested  from a native  population on  a moderately
saline  soil (EC ^15  ds  m~i)  27  km west  of the study area,  near Texon;  2)
fourwing saltbush  stem cuttings taken from  Texon  plants which  had  successfully
established on  highly saline  (EC =  71 to  114  ds  m-i) reserve  pits  (1);  3)
fourwing saltbush  seedlings  grown  from  seed  harvested  from  a native population
on  a non-saline (EC ^4  ds m-i )   soil  approximately  145 km southwest of the
study  area,  near Bakersfield;   4)  oldman  saltbush  (Atriplex   nummularia)
seedlings  grown from seed  produced  in  Australia; 5)  winterfat  (Ceratoides
lanata) seedlings  grown  from seed  harvested  from native populations  near Los
Lunas, New  Mexico; and 6)  prostrate kochia  (Kochia prostrata)  seedlings  grown
from seed harvested in Utah.

Seedlings were  grown  in a greenhouse  in 4- by 5-  by   18-cm polyethylene  tube
packs  in a  2:1:1 (v:v:v) peat moss/vermiculite/soil mixture and were  7 months
old  at planting.   Stem cuttings  were  propagated  in  a greenhouse using  an
automatically regulated  misting system.

Plots  were  established  on reserve  pits of three adjacent  oil wells  ( 0.5  km
apart) drilled  in  1983-84.  The  drilling fluids  had been allowed  to dry,  then
the  pits were  closed  by the conventional method  of mixing the  dried  drilling
wastes with the  soil  from  the pit borders.  Each reserve pit  was  disked  twice
and  fenced  to  exclude cattle and  sheep.   Field plantings were  established  on
21  September  1984. Seedlings  were planted on 1.8-m centers in  rows  2 m  apart
                                    404

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(16 seedlings per  row)  using a  Whitfield Model  57-DS-12 transplanter  mounted
on  a  30-kw  farm  tractor.   Each  reserve  pit  planting  was  arranged  as  a
randomized complete block  design with three  replications (rows) of  each plant
material.

Five  soil  cores  were   taken  with  a  bucket   auger  to  45-cm   depths   at
equidistantly  spaced  intervals  on  the  diagonal  of  each  reserve  pit  and
separated into  15-cm increments  for  determination  of electrical conductivity
(EC) of the  saturated paste extract  and exchangeable sodium percentage  (ESP)
(6).  Each site was sprinkler  irrigated with  51 mm  of  water  of low salinity
(EC = 2 ds m-1)  immediately after planting.   Seedling survival was  determined
2,  12  and 36 months after planting by  counting  the  number  of  live plants  in
each row.  Shrub heights and canopy  diameters were measured  12 and 36 months
after planting.

Data  for  each  sampling  date  from  the  three reserve  pits  were  combined  for
statistical  analyses following  Bartlett's  test   for  homogeneity  of variance
(7).  Survival  data were analyzed as  a split plot where site was the main plot
effect  and  plant  material was the  subplot effect.   Prior  to   conducting
analyses  of  variance,  percentage data  were  transformed by  sine"1^.   Means
were separated  using Duncan's multiple range test where appropriate  (PŁ0.05).
 Results  and Discussion

 Average  soluble  salt concentrations  in  the surface 45 cm  of  soil ranged from
 23 to  93  ds  m-i  and  ESP  values  ranged   from  13  to  46%  (data  not  shown).
 Soluble  and  exchangeable salt concentrations were  sufficiently high for these
 sites to  be   classified  as  saline-sodic   (6).   Salt  concentrations  and  ESP
 values  were  highly variable  within each  reserve  pit,  making  it  difficult to
 assess  the "average" level  of soil contamination.

 Rainfall (130 mm) plus  irrigation (51  mm) resulted in  a  total  of  181  mm of
 water on  the  study sites  prior  to  the  2-month  evaluation  (November 1984),
 which was  about 168% of the long-term  average  for that time  period.   Annual
 precipitation  received on the study sites  during 1985,  1986 and through August
 1987 was 92,  174 and 105% of  the long-term average, respectively.

 The site x plant material interaction was  not significant for any of the three
 sampling dates.   Thus,   the main effects  of  site  and plant material from the
 pooled  analyses  were evaluated  within each sampling date.  Plant survival at
 site A  was significantly greater than survival at  sites B or C after 2, 12 and
 36 months  (Table  1).   However,  overall plant  survival  on the  more  severely
 contaminated  sites  (B and C)  tended to stabilize by 12 months after  planting.

 Average  survival  2  months  after  planting  ranged from  65%   for Bakersfield
 fourwing saltbush  seedlings  to  92% for  Texon fourwing saltbush stem  cuttings
 (Table  2).  Oldman saltbush seedlings exhibited strong establishment potential
 2  months after  transplanting  (88%  survival),   but  the seedlings  died during
                                   405

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extended  periods of  low temperatures  (<0°  C)  in  December  1984  and January
1985.   Similar  winterkill  of  spring-planted  oldman  saltbush  on non-saline
soils  in  western Texas  has been  observed  (D.N.  Ueckert,  unpublished data).
Survival  of  Texon fourwing  saltbush stem  cuttings was  significantly greater
than  that  of  the  other  plant  materials  except  Texon  fourwing  saltbush
seedlings 12 and  36 months after planting.   Plant mortality between the 2- and
12-month  evaluation  dates (excluding  oldman saltbush)  ranged from  8 to 33%,
but was  Ł4% during the  subsequent  24 months.

Differences in survival  between  the two  fourwing saltbush accessions supported
previous  findings that germplasm from favorable environments  is  usually less
adapted to harsh environments  (8, 9).  Bakersfield fourwing saltbush seed were
obtained  from  an  area  more  xeric than   our  study  site,  but  the  native
population was on a  non-saline  soil.  Fourwing saltbush seed from  the  Texon
population germinated under  lower  (more  negative)  osmotic potentials than seed
from  native  stands located  further east or west of  the study area  (10).   A
further degree of selection  may  have been provided by  the  Texon  stem cuttings
taken  from Texon seedlings  that  had survived  and thrived  on highly  saline
reserve  pits.    We  hypothesized  that  the Texon stem cuttings  would be  more
tolerant  of  the high  levels  of   salt  in   the  reserve  pit  soils.   However,
survival  of  the  Texon stem cuttings was not  significantly  different  from  that
of Texon  seedlings.                                                    .__

Average shrub  heights and canopy diameters  12 and  36 months after planting are
presented in Table 3.   The  growth  rates  and growth forms  of  prostrate kochia
and  winterfat  are inherently  lower than that  of fourwing  saltbush,  thus no
statistical  comparisons  among  species  were made.   Texon  fourwing  saltbush
seedlings and  stem  cuttings  grew more rapidly and produced more  robust plants
than  the  other  species  or  Bakersfield fourwing saltbush seedlings 12 months
after  planting.   However,  Bakersfield  fourwing saltbush  surviving  after 36
months  had  produced   topgrowth comparable to that  of Texon seedlings  and  stem
cuttings.   Prostrate  kochia appeared more  susceptible to  feeding by insects
and  small  herbivores   than  the  other  species,  which  may  have  partially
contributed  to its poorer growth.   Fourwing  saltbush, winterfat,  and  prostrate
kochia  produced  seed  in  the  second  and third growing seasons,  and  seedlings of
the  three species where  found  adjacent to established plants  after  36  months.


Conclusions

Transplanted  seedlings  and  stem  cuttings   of  a  fourwing  saltbush  accession
originating  on   saline   soils  near  the  study  area   showed   the   greatest
establishment  potential  on saline-sodic  oil well reserve pit  soils in western
Texas.   These  results supported  previous laboratory  and field studies which
indicated that  highly adapted  accessions of  some  species may exist which are
more  suited  for  revegetation  of   extremely harsh  sites  (9,  10).   Oldman
saltbush  appeared to  be  adapted  to the saline-sodic soils;  however,  mortality
of  the  seedlings the  first winter  suggested  that  the species  lacks sufficient
cold  tolerance  for  the  study area.  Winterfat  and prostrate kochia had  lower
survival  percentages   than fourwing saltbush but  produced acceptable growth.
                                     406

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The  use  of  shrub  transplants   may  facilitate   revegetation  of  severely
contaminated rangeland  soils where seed germination and seedling establishment
nay  be  poor.    Further  evaluation   of  gennplasm   from  harsh   soil  and
environmental conditions should greatly improve  the potential for revegetation
of salt-affected  rangeland soils in arid and  semiarid  areas.
References

 1.  M.L. McFarland,  D.N. Ueckert, S. Hartmann,  Revegetation of Oil Well
    Reserve Pits in  West Texas, Journal of Range Management,  40,  1987,
    122-127.

 2.  T.T.  Kolzlowski, Physiology of Water Stress, Wildland Shrubs  — Their
    Biology and Utilization, U.S. Dept. Agric.  Forest  Service General
    Technical Report INT-1, 1972, 229-244, Logan,  Utah.

 3.  G. Orsham, Morphological and Physical Plasticity in  Relation  to Drought,
    Wildland Shrubs  — Their Biology and Utilization,  U.S.  Dept.  Agric.
    Forest Service General Technical Report  INT-1,  1972,  245-254,  Logan,
   . Utah.

 4.  E.F. Aldon, Techniques for Establishing  Native  Plants on  Mine  Spoils  in
    New Mexico, 3rd Symposium on Surface Mining and Reclamation,  1,  1975,
    21-28, National Coal Association, Washington,  D.C.

 5.  E.L. Blum, Soil Survey of Sterling County,  Texas,  U.S.  Dept. Agric.  Soil
    Conservation Service, U.S. Govt. Printing Office,  Washington,  D.C.,
    1977.

 6.  United States Salinity Laboratory Staff, Diagnosis and  Improvement of
    Saline and Alkali Soils, U.S. Dept. Agric.  Handbook  No.  60, U.S.  Govt.
    Printing Office, Washington, D.C., 1954.

 7.  K.A. Gomez, A.A. Gomez, Statistical Procedures  for Agricultural
    Research, John Wiley and Sons, New York, 1984.

 8.  G.A. Van Epps, Winter Injury to Fourwing Saltbush, Journal of  Range
    Management, 28,  1975, 157-159.

 9.  J.L. Petersen, D.N. Ueckert, R.L. Potter, J.E.  Huston,  Ecotypic
  ~ Variation in Selected Fourwing Saltbush  Populations  in  Western Texas,
    Journal of Range Management, 40, 1987. 361-366.

 10.  R.L. Potter, D.N. Ueckert, J.L. Petersen, M.L.  McFarland,  Germination  of
    Fourwing Saltbush Seeds: Interaction of  Temperature,  Osmotic  Potential
    and pH, Journal of Range Management, 39, 1986,  43-46.
                                    407

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                                   TABLE  1
Average survival of  transplanted shrub seedlings  or stem cuttings 2,  12  and
36 months  after  transplanting on 21 September  1984 on oil well  reserve pits
as affected by site.
Months after transplanting
Site
A
B
C
2

77 a1
65 b
49 c
12
f°r\
\'°)
62 a
48 b
42 b
36

62 a
47 b
42 b
        within a sampling date followed by similar lower case letters are not
  significantly different (P10.05) according to Duncan's multiple range
  test.
                                   408

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                                 TABLE 2
Average survival of transplanted  shrub seedlings  or stem cuttings  2,  12 and
36 months  after  transplanting on 21 September  1984 on oil well reserve pits.-
Species/
plant material
oldman saltbush
winterfat
prostrate kochia
fourwing saltbush
Bakersfield
Texon
Texon
Propagation
method
seedlings
seedlings
seedlings

seedlings
seedlings
stem cuttings

2 months

88 a1
73 be
72 be

65 c
86 ab
92 a
Survival
12 months

	 2
65 b
48 c

32 d
73 ab
80 a

36 months

—
61 be
48 c

32 d
73 ab
77 a
       within a column followed by similar lower  case  letters  are not
  significantly different (P Ł0.05) according  to Duncan's  multiple range
 2test.
  Indicates no survival because of winterkill.
                                   409

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                                   TABLE  3
Average canopy heights  and canopy diameters  of transplanted shrub  seedlings
or stem cuttings  12  and 36 months after planting on  21  September  1984  on oil
well reserve pits.
Species/
plant material
winterfat
prostrate kochia
fourwing saltbush
Bakersfield
Texon
Texon
Mean ± standard
Propagation
method
seedlings
seedlings

seedlings
seedlings
stem cuttings
error.

12
Height
30 ±
23 ±

74 ±
99 ±
84 ±

3
3

7
5
14

months

Diameter
23 ±
25 ±

74 ±
104 ±
99 ±

	 (cm)-
2
5

9
8
13



36
Height
59
47

121
117
129

+
+

+
+
+

2
2

5
8
3

months

Diameter
62 ±
68 ±

233 i
219 ±
231 ±

4
2

20
11
9

                                    410

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EVALUATION  OF LIMITING CONSTITUENTS SUGGESTED  FOR LAND  DISPOSAL
OF EXPLORATION AND PRODUCTION WASTES
L. E. Deuel, Jr.
Soil Analytical Services, Inc.
College Station, Texas
SECTION 1
Introduction and Summary


This  document provides definition, technical justification,   and
applications  guidance  for salinity  and  petroleum  hydrocarbon
threshold  values established for landspreading, on-site  burial,
or  roadspreading  of E&P wastes.   Measurable  parameters  which
serve as indices for proper management of salinity and  petroleum
hydrocarbons  include: electrical conductivity  (EC),  sodium   ad-
sorption  ratio (SAR), and exchangeable sodium  percentage   (ESP)
for salinity; and oil & grease  (O&G) for petroleum hydrocarbons.

The  threshold  guidance values generally  recommended  for  land
applied waste:soil mixtures are EC < 4 mmhos/cm, SAR < 12, ESP <
15%,  and  O&G < 1%.  Index parameter thresholds  have  been   de-
veloped to be generally applicable for any waste containing salts
or  petroleum  hydrocarbons including E&P wastes  under  ordinary
conditions.

Under certain restrictive conditions the generic guidance thresh-
olds  have  to be adjusted or crops temporarily changed  to  more
tolerant species.  Depending on drainage, cover crop, and  chemi-
cal  treatment a soil with a loading no greater than that  recom-
mended  should  recover over a  few seasons.   The  operator  must
determine  whether the guidance values apply over the  short-  or
long-term, or whether conditions warrant less restrictive values.


SECTION 2

Technical Justification and Literature Review

2.1  Limiting Constituents

Salts  and  hydrocarbons have been identified  as  the  principal
limiting  constituents of concern relative to onshore E&P  opera-
tions because they may induce a phytotoxicity or, in the case  of
sodium salts, may deteriorate soil structure interrupting  normal
soil-plant-water  relationships  and  causing  excessive  erosion
                               411

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(Miller  and Honarvar, 1975; Ferrante,  1981;  Freeman  and  Deuel,
1984;  Nelson et al., 1984).  Salts  and  hydrocarbons  associated
with  E&P  wastes may pose a significant  threat  to  surface  and
groundwater resources when not properly managed (Henderson,  1983;
Murphy and Kehew, 1984) .


2.2  Salinity

Salinity  is  a general term reflecting the levels   of  available
cations  and  anions  in aqueous solution.    Major   ions  include
sodium   (Na), calcium  (Ca), magnesium  (Mg), potassium (K),   chlo-
ride (Cl), sulfate  (S04), bicarbonate  (HC03),  carbonate (C03)  and
hydroxide (OH).  EC reflects the ionic  strength or  total level of
these constituents, while SAR and ESP consider the  influence that
specific ions may have under particular circumstances.

2.2.1   Definitions

Charged particles in solution will conduct an electric  current to
an  extent determined primarily by the  concentration  and type  of
ionic  species present, hence the term  electrical  conductivity.
EC  is  measured directly in reciprocal units  of  resistance   and
conveniently  reported  in millimhos per  centimeter   (mmhos/cm).
Since  dissolved solids are predominately dissolved salts in   the
form  of  dissociated  charged particles, EC may be   used  as  an
indirect, approximate measure of total dissolved solids  (TDS).

TDS  is  defined in chemical terms as  the  unfilterable residue
associated with agueous fluids resulting from  the evaporation  of
a  known quantity of water, and is reported in terms  of  mass   per
unit  volume  (mg/liter).  This residue  is predominately   composed
of salts, but may include organic materials (humic substances  or
anthropogenic compounds) or mineral colloids passing  through   the
filter.

An exact relationship exists between concentration of a   specific
salt  in pure water and electrical conductance of  that   solution
(Barrow, 1966).  However, this relationship is inaccurate at high
salt concentration, solutions of mixed salt species,  or  presence
of  nonionic dissolved species.  Of more immediate use have  been
empirical  correlations  between TDS and EC for  various aqueous
solutions:

                        TDS - (A) X  (EC)

with the regression constant "A" (slope), being used  as  a conver-
sion  factor.  Values of "A" have been  found to  range   naturally
from  540  to 960 cm.mg/mmhos.liter  (Hem, 1985).   For   naturally
occurring  saline/sodic  soils a constant of  640 may  be assumed
(USDA  Handbook 60, 1954).  Using the above equation, one  calcu-
                               412

-------
lates a TDS of 2560 mg/liter at a corresponding  EC  of 4  mmhos/cm,
and "A" of 640 cm.mg/mmhos.liter.  A recent analytical review  of
E&P  wastes  by the EPA (1987), and parallel review  by   the  API
(1987),  suggested that an "A" value of 613 gives a better  esti-
mate of TDS in E&P wastes when calculated from EC.

TDS is generally not an accurate measure of salinity for many E&P
wastes, due to errors associated with hydrocarbons  and fine   clay
passing  the  filtration step.  If one wants the perspective  of
salinity  on a mass basis, it is best estimated  from EC.   EC  has
long  been the parameter of choice in defining   salinity  hazards
associated with production agriculture.

2.2.2  Concerns

Although  some  elements,  such as boron, are  toxic  to  plants,
generally  the  ill effects of salinity are caused   by  increased
osmotic  pressure  of soil solution in contact with  plant  roots
(Haywood  and  Wadleigh, 1949; U.S.  Salinity  Laboratory Staff,
1954).  Osmosis is a process that controls the movement  of  water
between solutions and depends upon the number of dissolved  mole-
cules  or  ions   (salinity). Water flows from  lower  to  higher
osmotic  pressure.   Plants have an osmotic  pressure associated
with  their  cell  solution which varies  greatly   between  plant
species and to some degree between cultivars within species.    If
the osmotic pressure  in  soil solution outside  the plant exceeds
that inside, the plant wilts.  The point of permanent wilting  is
reached when the plant can not recover even when exposed to   less
saline  water.   There is a direct relationship  between  osmotic
pressure and EC:

        Osmotic Pressure (OP), atm. = 0.36 X EC, mmhos/cm

Salts also effect plants by disrupting normal nutrient uptake and
utilization  (Kramer,  1969).   The mechanism is one of simple
antagonism,  whereby a given salt specie in excess   inhibits  the
plant  uptake of required elements.  The effect  is  usually  mani-
fested as a deficiency resulting in lowered yield expectations  or
overall crop quality.

There  is no one critical or threshold salinity  level  where  all
plants fail to grow or maintain acceptable yields.   General   crop
response  to  soil salinity is shown in Table 1  (U.   S.   Salinity
Laboratory  Staff, 1954).  The sensitivities of  various   agricul-
tural  crops  to  salt are shown in Figures 1  through  3 (Maas,
1986).   For example: at an EC of 4 mmhos/cm barley,  cotton,   and
bermuda  grass  are  not affected by salt,  whereas,   yields  are
expected  to  decrease  for rice and corn  (0-15%),   alfalfa  and
sugarcane  (15-30%) and beans (30-50%).  Yield response  intervals
shown  in  Figures 1 through 3 were developed  from  agricultural
systems receiving salt-containing irrigation water  over  the   long
                               413

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term and may overestimate the anticipated response for a one time
land disposal of E&P wastes.  Lunin  (1967)  suggests that  irriga-
tion  water salinity guidelines developed for continual use  sys-
tems  can be doubled for a one time  application.    The  rationale
being that salt accumulated outside  the  bulk soil  mass (in  pores
and on ped surfaces) is more easily  displaced than that penetrat-
ed into and reacted with the bulk  soil mass.

                             Table 1.
            General Crop Response as a Function of EC.
          (After U. S. Salinity Laboratory  Staff,  1954)


              EC         Affect on Crop  Yield
          (mmho/cm)


            0-2        None
            2-4        Slight to none
            4-8        Many crops  affected
            8-16       Only tolerant crops yield well
              > 16       Only very tolerant crops  yield well


If the salinity is initially too high for a given  crop after  land
application  of  waste, soils will  generally recover  following
rainfall or irrigation water containing  less salt  because   excess
salts  are leached when adequate drainage is present.   Growth of
more  salt  tolerant plants may be desirable during  the  interim
between application and recovery  (Foth and  Turk, 1972).  Reclama-
tion of salt-containing soils may  be hastened through the   appli-
cation   of   calcium sulfate (gypsum)   which results  in  the
replacement of exchangeable sodium by calcium (Oster and Rhoades,
1984).   Plants  grown on gypsiferous soils will tolerate   an EC
approximately  2  mmho/cm higher than those shown   in  Figures  1
through  3  (Mass, 1986).  This is  because gypsum is dissolved at
moisture  equivalents used in preparing  saturated   soil  extracts
for  analysis  but not at moisture equivalents normal  to field
conditions.

USDA Handbook 60 (U.S. Salinity Laboratory  Staff,1954)  classifies
water with EC values above 2.25 mmhos/cm as unfit  for agricultur-
al purposes except under very special circumstances.   Soils  with
salinity  levels > 4 mmhos/cm are  considered saline.   The   recom-
mended  criteria  of  4 mmhos/cm is  too  high  for   the more  salt
sensitive  crops (Table 1.), and some adjustments  may have to be
made  relative to intended land use.  Miller and   Pesaran   (1980)
found  that high concentrations of soluble  salts   in  mud-treated
soil hindered plant growth in a 1:1  mud:soil  mixture.  Extracting
their  data  where EC of the mud:soil mixture was   <  8  mmho/cm,
yield  decreases  averaged only 7% for green  beans  and  13%  for
                               414

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              Fiber,  Grain,   and  Special  Crops
cn
          Barley
           Bean
      Broadbean
           Corn
          Cotton
         Cowpea
           • Flax
         Peanut
     Rice, paddy
        Sorghum
        Soybean
       Sugarbeet
      Sugarcane
          Wheat
    Wheat, Durum
Wheat (semldwarf)
                                                     E23 o-i5%
                                                       EH is - 
-------
                   Grasses   and  Forage  Crops
0)
             Alfalfa
      Barley (forage)
       Bermudagrass
              Clover
       Corn (forage)
     Cowpea (forage)
         Fescue, tall
     Foxtail, meadow
        Hardinggrass
           Lovegrass
        Orchardgrass
 Ryegrass (perennial)
           Sesbanla
       Sphaerophysa
         Sudangrass
         Trefoil, big
   Trefoil, narrowleaf
     Vetch, Common
Wheat, Durum(forage)
      Wheat (forage)
 Wheatgrass, fairway
Wheatgrass, standard
     Wheatgrass, tall
   Wildrye,  beardless
                            0
                            5      10      15      20      25
                           Soil EC (saturated extract), mmho/cm
       Figure 2.  Yield decrease  due to soil salinity (Maas, 1986)
30

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           Vegetable  and  Fruit  Crops
     Asparagus
          Bean
      Beat, red
       Broccoli
       Cabbage
         Carrot
         Celery
    Corn, sweet
     Cucumber
        Lettuce
         Onion
        Pepper
         Potato
        Radish
       Spinach
 Squash, scallop
Squash, zucchini
     Strawberry
   Sweet Potato
        Tomato
         Turnip
•M4KN
•i III  I :
• II I I  1
                                VTA
o%

0 - 15%

15 - 30%

30 - 5Q%
               0      5      10     15     20     25     30
                        Soil EC (saturated extract), mmho/cm
     Figure 3. Yield decrease due to soil salinity (Maas, 1986)
                                               35

-------
sweet  corn.   Nelson et al.  (1984) measured  average  yield  de-
creases  of 20% and 38% for swiss chard  and  rye-grass,   where  EC
ranged  from 6.3 to 18.6 mmho/cm.   In  these  studies EC  was  above
the recommended criteria of < 4 mmho/cm.   Tucker (1985)   reported
adding  drilling  mud with resulting EC  values from  1.3  to  5.3
mmho/cm with no adverse effect on bermudagrass and at 1.7 mmho/cm
with  no adverse effect on alfalfa.  He  also reported a  signifi-
cant  decrease in EC with time following application,   reflecting
the leaching of salts out of the root  zone.

It  is  apparent that a one-time EC application  guideline  of  4
mmho/cm is  sufficient to limit yield decreases for most crops  to
<  15%.  In those cases where precipitation,  drainage,   or   crop
type  places special restrictions on waste management,   some  ad-
justments   may have to be made relative  to waste addition  levels
or intended land use while the soil recovers.

In  areas of net infiltration, the  soluble salts are transported
from  the surface to lower soil zones.   Murphy and  Kehew  (1984)
found  that soluble salts from a pit containing  saturated  brine
drilling  fluids  (EC > 200 mmhos/cm) posed a threat to   localized
ground water resources. It is obvious  that an EC of 200   mmhos/cm
greatly exceeds the recommended threshold of 4  mmhos/cm.     Bates
(1988),  working with a fresh water drilling fluid,  demonstrated
that Cl was not retained in the zone of  incorporation when  mixed
with surface soil.

The criteria of 4 mmhos/cm  (2452 mg/liter TDS for "A" =  613)   can
be  expected to have no measurable  impact on groundwater even  in
the  most sensitive hydrological settings.   Water and   associated
dissolved   constituents do not move through  soils as an   isolated
unit   (plug flow),  instead there  is  a  natural  redistribution
controlled  by water potentials, pore  dynamics,   dispersion,   and
diffusion   (i.e. chromatographic effect).  Recent field   research
studies conducted by Owens et al.  (1985)  and Bruce et al.   (1985)
perhaps best illustrate this principal in that they were conduct-
ed  at concentrations comparable  in magnitude to the 4   mmhos/cm
threshold.  Both studies observed the  redistribution of  surface
applied bromide  (Br) by rainfall infiltration and percolation.

The Owens group demonstrated better than a 7 fold decrease in  Br
after passing through only 2.4 m of a  well-drained silt loam soil
due  to attenuation processes mentioned  above.   Under   conditions
similar to  their study, a surface loading of NaCl  eguivalent  to
4  mmhos/cm  (2452  mg/liter  TDS)  would result  in  an  EC  <0.6
mmhos/cm and corresponding Cl of <  213 mg/liter at a depth of 2.4
m.  Bruce et al.  (1985) showed Br redistribution from as great as
1800 mg/liter  at the surface to <20 mg/liter below a depth of  3
m, after nearly 4 years and 4.7 m of rainfall.   The Br  level  was
100 mg/liter at a depth of 1.5 m after 4 years with none detected
below  3.8  m.  If one substitutes  Cl  for the Br  salts  used  in
                                 418

-------
these studies  it  becomes apparent that percolating water will  be
at  or below  the EPA drinking water  quality  standard  of  250
jig/liter  Cl  (Part 143, 40 CFR, Sec. 143.3)  within a few feet  of
the source  at  controlled land applications  (EC < 4 mmhos/cm).

2.2.3  Criteria

In  summary the   EC criteria of 4 mmho/cm  based  on  a  one-time
application  serves to protect vegetation,  land  and  groundwater
resources  at  most drilling and production  locations  including
those  located  in sensitive regions if  amenable to  a  temporary
adjustment   in plant species.  The criteria may be  adjusted  to
meet special  requirements.

2.3  Sodicity (ESP and SAR)

2.3.1 Definitions

The  capacity  of a soil to adsorb positively charged  ions  (ca-
tions)  is  called the cation exchange capacity (CEC)  and  may  be
expressed in meq/100 g. It follows that  the exchangeable  cations
in  a soil  are those positively charged  ions held on the  surface
exchange  sites  and in equilibrium with  the soil  solution.    The
major  cations calcium (Ca), magnesium  (Mg),  sodium (Na),  and  K
(potassium)  are  called basic cations and the percentage  of  the
CEC  occupied  by these cations is called  the  base  saturation.
Fertile  soils have a base saturation greater than 80%  with  the
cations distributed mainly as Ca and Mg.

ESP  is a measure of the degree to which the soil exchange  sites
are saturated with sodium and is calculated as follows:

                   ESP,% = (NaX / CEC)  x 100

where  NaX (exchangeable Na) and CEC are expressed  in  meq/lOOg.
Ca  and  Mg are  generally needed in relatively large  amounts  to
maintain  good soil structure (physical  status relative  to  tilth
and  permeability)  and  fertility, but  they form  salts  of  low
solubility in soils.  Na salts are much  more soluble and  readily
dominate soil  solutions, often with a detrimental impact.

SAR is an empirical mathematical expression developed by the DSDA
Salinity Laboratory as an index to detrimental sodium effects  in
soils  (U.S. Salinity Laboratory Staff, 1954).   SAR is computed as
follows:
                    SAR = Na //(Ca + Mg)/2

where concentrations are expressed in meq/liter.    Concentrations
are  determined  by direct chemical analysis  of   pit  liquids  or
aqueous extracts of waste solids or soils.
                              419

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2.3.2  Concerns

High  Na levels  (SAR >12) in soil solution  cause  Ca and Mg  defi-
ciencies in plants by both antagonistic reactions and shifting of
solubilities  by common ion effect  (Kramer,  1969;   U.S.   Salinity
Laboratory Staff, 1954).
Soils reacted with solutions of high SAR are at risk of  becoming
sodic.   A soil is termed sodic when the ESP exceeds 15%  of  the
CEC   (U.S.  Salinity Laboratory Staff, 1954).  The  most  distin-
guishing  feature of sodic soils is their lack of   structure  and
tendency to disperse in water.  A dispersed  soil  condition has a
devastating impact on plants by limiting the free  exchange of  air
and   infiltration of water (Reeve and Fireman, 1967;   Bresler   et
al.,  1983).

Research  conducted by Tucker  (1985) involving land  disposal   of
waste  drilling fluids confirmed that SAR <  15 and ESP < 15%  are
required  for  maintaining good soil structure and  normal  plant
growth.  Miller and Pesaran  (1980) measured  ESP for 1:1   and  1:4
mud:soil  mixtures and found average yield decreases  of   12%  for
green  beans and 20% for sweet corn at an average  ESP of 11.5%.
The ESP in their study ranged from 0.6 - 19.7%.

SAR   is  somewhat less critical in that it   represents  the  more
easily  altered  solution phase.  Deuel and  Brown   (1980)  showed
that  the detrimental effect for water with an EC of 2.8   mmhos/cm
and SAR of 16.1 was directly proportionate to the  solid  phase   Ca
in  the receiving soil. The occurrence of appreciable amounts   of
gypsum  in the soil, either naturally or by  amendment may permit
the   disposal  of highly sodic E&P wastes,   particularly  if  the
ionic  strength  of total salt is relatively low.    Freeman  and
Deuel  (1984) reported the successful pit closure  (SAR <  15,  ESP <
15%)  by land disposal of  E&P waste solids  with SAR's > 200  and
ESP's  > 90, when  salinities were < 4 mmho/cm.    Treatment  con-
sisted  of blending waste solids with native soils at chemically
defined  mix  ratios in conjunction with  gypsum   and fertilizer
amendments.

2.3.3  Criteria

Therefore, The API Environmental Guidance Document recommends   an
SAR   of  <12  and ESP of <15% for land disposal  of  E&P  wastes.
These  values are widely accepted thresholds recommended  by  the
USDA  for  preventing soil sodicity (U. S.   Salinity   Laboratory,
1954).  Field and laboratory studies with drilling muds  have also
shown them to be reasonable values.  It is important  to  note that
guidance  values pertain to final disposition or closure  status:
values do not limit the amount or composition of the  wastes  that
can  be  land disposed.  However, operators  must be  prepared   to
provide necessary management inputs for wastes applied to land in
exceedance of recommended values.
                                420

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2.4  Hydrocarbons

2.4.1  Composition and Analysis

Crude  oil and diesel are the principal  hydrocarbons   associated
with  E&P wastes (Miller et al., 1980; Thoresen and Hinds,   1983;
Whitfill and Boyd, 1987).  They are sometimes added to  water base
drill  systems to lubricate the drill bit and pipe  string.    O&G
levels in freshwater drilling wastes are generally < 4%  (Freeman
and  Deuel, 1986).  Other E&P waste such as tank  bottoms,   emul-
sions,  and oil-contaminated soil may have higher  concentrations
of  O&G. A number of other hydrocarbons including  asphalt,   lig-
nite,  and  lignosulfonates may be used in trace  amounts  during
drilling  operations  (Honarvar, 1975; Miller et al.,   1980)    In
general, the deeper the hole the greater the hydrocarbon level in
mud  formulations.  Crude oil may also be incorporated  into  the
drilling mud by contact with oil-bearing formations.

Crude  oil and diesel fractions are comprised of a complex   array
of saturate and aromatic hydrocarbons  (Thoresen and Hinds, 1983).
Both  fractions  are readily partitioned from  water  by  solvent
using a separatory funnel or extracted from solid mineral  compo-
nents using a Soxhlet apparatus  (Brown et al., 1983).   Hydrocar-
bons  extracted are assayed gravimetrically and reported  collec-
tively  as oil and grease (O&G).  Methylene chloride is the   sol-
vent  of choice owing to its efficiency for extracting  petroleum
hydrocarbons  without  co-extracting  significant  quantities  of
naturally occurring organic matter  (Brown and Deuel, 1983).

2.4.2  Concerns

A  considerable  amount of research has been carried out  on  the
detrimental  effects  of crude oil and gas on  plants   and   soils
 (Baldwin, 1922; Murphy, 1929; Schollenberger, 1930; Harper,  1939;
Plice,  1948; Schwendinger, 1968; Garner, 1971; and  Odu,  1972).
The most phytotoxic compounds are lower molecular weight aromatic
hydrocarbons, present initially, or formed as metabolites of  the
various degradation processes (Baker, 1970; Patrick, 1971; Thore-
sen  and  Hinds, 1983).  Several studies  (Murphy,  1929;  Plice,
1948; Udo and Fayemi, 1975)  reported marked inhibition  of  germi-
nation and corresponding yield reduction for row crops  planted to
soils  receiving crude or waste oil applications in excess of  2%
by  weight.  Pal and Overcash" (1978) reported that the  growth  of
vegetables  and row crops were affected at an oil application  of
1% by weight.  Yields were generally 50% of control at  2% oil  by
weight.  Bulman and Scroggins (1988) showed that plant  growth was
good on field plots with oil content of 3.5% or less but poor  on
plots  with oil content of over 5%.  At another site  they   found
reduced crop growth in the first season after applying  1% and  2%
oil in the soil.  However, areas that received levels of 0.5% oil
showed enhanced crop growth.
                                421

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Frankenberger  and  Johanson  (1982)  reported   certain  crude  oil
components and refined petroleum products  added  to  soil at 20% to
60% disrupt the oxidative and soil microflora  activity  requisite
for  biological assimilation following oil spillage  events  with
oxidation being slowest for heavier  molecules.

Miller  et  al. (1980) found that a  1% soil loading  with   diesel
fuel  resulted in decreased yields of 49%  and  69% for  beans  and
corn,  respectively.  Replanting after 4 months  resulted in  near
normal growth.  Younkin and Johnson  (1980) grew  reed   canarygrass
in  soil  initially  containing 0.45% diesel fuel   and  found an
initial  germination decrease of 69%, a first harvest  yield  de-
crease  of  79% and no yield decrease with a second  harvest  (75
days  after diesel addition).  Overcash (1979) determined  an  oil
level  of  about 1% of soil weight as the  threshold  for  reduced
yields,  and with 1.5 - 2% causing yield reductions greater  than
50%.   These effects occur immediately after  application   before
hydrocarbon is assimilated by the various  loss mechanisms.   Table
2 lists  the  oil  tolerance for selected  crops  (Overcash,  1979).
Work by Ellis and Adams (1961) suggested that iron  and   manganese
released under anaerobic conditions  contribute to the  phytotoxic
response to soil contamination by petroleum hydrocarbons.   Phyto-
toxic response was lowered after assimilation of the  hydrocarbon
by the soil.

                             Table 2.
                 Oil Tolerance for Selected Crops
        Crop Type
Single Oil Application
     yams, carrots, rape,
     lawngrasses, sugar beets

     ryegrass, oat, barley,
     corn, wheat, beans,
     soybeans, tomato

     red clover, peas, cotton.
     potato, sorghum

     perennial grasses,
     coastal bermuda grass,
     trees, plantain
  .< 0.5% of soil weight
  < 1.5% of soil weight
  < 3.0% of soil weight
  > 3.0% of soil weight
These  studies indicate that under high hydrocarbon  loadings   (>
1%), E&P wastes may be detrimental toward plant growth.  However,
at  1% or less of mixed hydrocarbons, little or no yield reduction
is  expected based on existing information.  Also,  recovery   of
                                422

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the   site  is  expected after  a   few months    to   one  growing
season,  following a one-time application.

Several general observations of oil mobility in  soil  bear direct-
ly  on  any assessment of  potential  groundwater  contamination.
Plice (1948) observed that when oil enters  the soil as  a  liquid,
there  is  a  natural segregation whereby   the   higher   molecular
weight,  more viscous compounds are held near the  surface  while
the lighter fractions penetrate deeper.  Also, while  the  overall
concentrations  tend  to  decrease with  depth,   the  composition
towards  the  lighter  end aromatic fraction  tends  to  increase
(Duffy et al., 1977; Weldon, 1978).

The  recent review by EPA (1987) of E&P wastes showed  only  pro-
duced  waters  contained significant levels of the notably  more
mobile  hydrocarbons including benzene, toluene,   ethyl  benzene,
and  xylenes  (Roy  and Griffin,  1985).    These  compounds  were
present in diesel oil-base  drilling fluids but  at concentrations
that  would  be  readily attenuated in subsurface  strata by  an
adsorptive mechanism (El-Dib et al., 1978).  Mobilities are  also
restricted  by  the  chromatographic effect  of  liquids moving
through  a porous media (Waarden, Groenewoud, and Bridie,  1977).
Oil floats, and its movement through soils  is restricted to  those
pores  of passable diameter, not saturated  with  water.    Movement
is  further  retarded by the "Jamin effect" or obstruction  of   a
non-wetting fluid in a porous media (Schiegg, 1980).

At low levels of hydrocarbon addition to surface soils,   leaching
has not been found to be a problem.  Watts  et al.  (1982)  found no
migration  at a 30 to 45 cm depth after applying  14%  industrial
waste oil to the top 15 cm.  Raymond et al. (1976)  added about 2%
oil to the top 15 cm and determined that 99% remained within the
top 20 cm after 1 year.  With loading rates of 3 and  13% of  soil
weight  per year Streebin et al. (1985) found no significant oil
migration  below the zone of incorporation.  Oudot et al.   (1989)
found  the  potential  for leaching  of  unmodified  hydrocarbons
towards  the  groundwater was slight at a loading of  2%  oil  in
soil.   The  one-time 1% level recommended  for   production  waste
additions to soil is therefore not expected to create any leach-
ing problems.
              f
2.4.3  Biodeqradation

It  has been demonstrated that soils have an  adequately  diverse
microbial population and capacity to degrade E&P waste   hydrocar-
bons   (Raymond  et al., 1967; Atlas and Bartha,  1972;  Jobson  et
al.,  1972; Kincannon, 1972; Westlake et al., 1974;   Horowitz  et
al.,  1975).   Saturates  and light end  aromatics are  degraded
first, with kinetics or rate of degradation controlled  by concen-
tration and composition of hydrocarbons, nutritive status,   aera-
tion,  moisture and temperature (Schwendinger, 1968;  Francke and
                               423

-------
Clark,  1974;  Huddleston and Meyers,  1978;  Brown et  al.,   1983;
Flowers et al., 1984; Bleckmann et al.,  1989).   Whitfill and Boyd
(1987)  reported that soils may be treated with up to 5%  oil by
weight  with  no adverse environmental impact.    Several  studies
have shown that controlled oil applications  actually improve soil
physical  conditions and fertility status  (Plice,   1948; Mackin,
1950; Ellis and Adams, 1961; Baker, 1970; Giddens,  1976).

Watts et al.  (1982) measured a 2 year half life for a 14% loading
of oil to soil. Streebin et al. (1985) also  found a half life of
about 2 years at a similar loading rate. At  a loading rate of 2%
in  the field, 94% of hydrocarbons were  removed after  3.5   years
(Oudot  et al., 1989). Lynch and Genes (1987) determined a   half
life of 77 days on a field plot containing 5% polyaromatic hydro-
carbons.

2.4.4  Criteria

The  API Environmental Guidance Document recommends  a  1% oil  and
grease threshold for land disposal of E&P wastes based on attenu-
ation and degradation processes that will occur under  landspread-
ing  conditions.   This  value is predicated on the   concept  of
minimum  management,  whereby an operator may load  a   soil   (add
hydrocarbon) at an appropriate mix ratio (E&P waste:soil) not  to
exceed  1%  oil and grease.  Available  information  demonstrates
that 1% hydrocarbon by weight was a reasonable  threshold initiat-
ing temporary plant yield reductions.

2.5 Conclusions

This  information  supports the guidance values  that   have  been
developed  for  the land disposal of Exploration  and   Production
wastes.  For a one-time application the guidance values are EC  <
4  mmho/cm,  SAR  < 12, ESP < 15%, and O&G  <1%.  These  guidance
values  have  been developed to be generally applicable  for  any
waste  containing salts or petroleum hydrocarbons  including  E&P
wastes. They are designed to protect the environment under condi-
tions  most  likely  to be found at E&P  locations.  While  being
generally  applicable,  it  is up to the  operator  to  determine
whether they apply to his particular site.
                              424

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63.  Streebin, L.E.,  J.M. Robertson, H.M.  Schornick,  P.T. Bowen,
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                                 430

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EVALUATION   OF  LEACHING  AND   GYPSUM  FOR  ENHANCING   RECLAMATION  AND
REVEGETATION OF OIL WELL RESERVE PITS IN A  SEMIARID AREA
S.  Hartmann
University of Texas Lands - Surface Interests
P.O.  Box 553
Midland,  Texas  79701  U.S.A.
D. N.  Ueckert
Texas  Agricultural Experiment Station
7887 N.  Hwy.  87
San Angelo,  Texas  76901  U.S.A.

M. L.  McFarland
Texas  A&M University
Texas  Agricultural Extension Service
College Station, Texas  77843  U.S.A.
 Leaching a saline-sodic soil (initial EC 73 to 143 dS m"1;  initial SAR 63
 to  90) with  1 m of  good  quality water  (EC <2  dS m"1)  reduced EC  by an
 average  of  59%  and  SAR  by an  average of  43%  in  the  surface  45  cm.
 Subsequent surface applications of 8 to 9 Mg ha"1  of  gypsum and sprinkler
 irrigation (280  mm)  did not  further reduce EC  or SAR values, possibly
 because of slow and  ineffective gypsum  dissolution.   Survival  and canopy
 height of fourwing  saltbush (Atriplex canescens)  and oldman saltbush
 (Atriolex nummularia)  transplants  were  not affected by  gypsum treatment
 5  months  after planting.    Survival of transplanted fourwing saltbush
 seedlings was about 65% after 38 months, but survival was not affected by
 gypsum treatment.   All oldman  saltbush  seedlings  died as a  result of
 winterkill.

 Introduction

 On-site disposal of petroleum and natural gas  drilling fluids in arid and
 semiarid  regions  usually  results   in  long-term  soil  disturbance  and
 contamination.   High concentrations  of soluble  salts  in  these  wastes,
 primarily NaCl, often seriously inhibit germination  and establishment of
 most native plant species (1).
                                  431

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Earthen   basins  (reserve  pits)  about 30  to 60  m  and <1  m deep  are
constructed adjacent to each drilling site and used for handling,  storage
and disposal of drilling fluids.  When drilling is completed, the drilling
fluid and cuttings are usually allowed  to  dry  in the reserve pit, and then
mixed with soil from the pit borders.

Typical drilling  fluids  consist  of a 5% slurry of bentonite  in water or
brine with NaOH added as  a dispersant, an organic material such as  lignite
or  lignosulfonate  to  stabilize  the  slurry,  and  a  density-increasing
material, usually barite (BaS04) . to float out rock particles (2).  High
salt  concentrations  characteristic of  drilling  fluids are caused  by
chemical additives, by contact with certain subsurface geologic formations
during drilling,  or by the use of brine as the carrier.   Ten   individual
drilling fluid components significantly reduced yields  of corn  (Zea mays
var. saccharata)  and beans (Phaselous vulgaris)  (3).  High  total  soluble
salt concentrations  (EC) or high  exchangeable  sodium percentages  (ESP)
caused by additions of KC1, NaOH, and Na2Cr207 in  1:1  and 1:4  mixtures  of
drilling fluid  and soil  were  the primary causes of reduced plant growth
(4).

High osmotic potentials produced by soluble salts  retard water* imbibition
by seeds, resulting in decreased  germination and slower seedling  emergence
rates  (5).  Transplanting seedlings bypasses  the  critical phases of seed
germination  and  seedling  establishment.   Many  shrub  species  are well
adapted  to  droughty and saline  conditions because of structural and/or
physiological adaptations of roots  and foliage (6,7).  However, even  the
use  of  halophytic   shrub   seedlings   may  not  result  in  successful
revegetation  of  severely  contaminated   soils.    Survival of  fourwing
saltbush  (Atriplex canescens) transplants was  only  26  and 30% 2  years
after planting on soils with EC values of 71 to 114 dS  m'1  in western  Texas
(1).   The  use of  more  intensive  soil  reclamation  practices,  such  as
leaching  and/or  the use of  soil  amendments,  may be necessary in such
cases.

Leaching, either by rainfall or irrigation, is the primary method used  for
removal of  soluble and exchangeable salts from contaminated  soils.   The
effectiveness  of  intermittent  ponding  or  sprinkler   irrigation  has
generally been  greater than  that of continuous ponding  (8,9).  However,
Na  saturation  of  the  soil  cation exchange complex  results  in clay
dispersion, decreased permeability, and a reduction in soil  leachability.
Chemical  amendments  which  supply  soluble   Ca   facilitate  removal   of
exchangeable Na by leaching.   Gypsum (CaS04) ,  elemental sulfur (S),  CaCl2,
and HC1 have  been used for reclamation of calcareous saline-sodic  soils
in  southern New Mexico (10).   Gypsum is most commonly used due to  cost,
handling and  availability considerations.
                                 432

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Surface  applications of gypsum were reported  to  be more effective  than
incorporation   for   increasing   exchangeable   Ca-ion   and   hydraulic
conductivity   (11).    Soluble  carbonate  precipitated  when  gypsum  was
incorporated  into  soil,  while leaching  after surface  applications  of
gypsum removed much of the  soluble carbonates prior  to  reaction.  As  a
result,  surface application rates  of gypsum could be reduced by  as much
as 50%.

Plant responses to  gypsum treatments have  been variable (12,13,14,15).
Infiltration   rates  and  plant  yields   have  increased  after   gypsum
applications   on   some  salt-affected  soils  (12,15).     However,   gypsum
applications  at rates as high  as  21.6  Mg ha"1  did not improve  growth of
native plants on  salt-affected soils in  the Northern Great Plains  (13).
Applications  of gypsum at 2  to  14  Mg ha"1  to a fine-textured saline-sodic
soil  in India  did not  affect  growth  or  yield  of  cotton  (Gossypium
hirsutunO or  sorghum (Sorghum bicolor)  (14).

The objectives of this study were to investigate the effects of leaching
and  leaching  plus  surface  applications  of  gypsum  on soil  chemical
properties and on survival and  growth of  two facultative  halophytic shrub
species  on  saline-sodic  reserve  pit soils  in the  southwestern  United
States.

Materials and methods

The  study was  conducted  in  the northern Edwards  Plateau of Texas 10 km
northeast of  Big Lake  in Reagan County (31°15'N 101°40'W). The climate is
semiarid with an average  annual precipitation of 414 mm and a mean annual
pan  evaporation of  1800 mm  (16).   The  average daily maximum temperature
in July is 36 C and the average frost-free period  is 229  days.   The study
area  was  on  a level, upland  site  on a  Reagan clay  loam (fine,   mixed,
thermic Ustollic Calciorthid).   The Reagan series  consists of deep upland
soils formed in calcareous,  loamy  sediment of  ancient outwash and  aeolian
origin.   Slopes  at the   study site were  <1%.   Physical  and chemical
properties of  the native  soil  and  drilling  fluids characteristic  of the
study area are presented in Table 1.

Native  vegetation at the  study site  is characterized  by  buffalograss
(Buchloe dactyloides') , red threeawn (Aristida  longiseta) , and tobosagrass
(Hilaria  mutica).   Major  forbs   include  broom  snakeweed   (Gutierrezia
sarothrael,  desertholly  (Perezia  nana),  and  leatherweed croton  (Croton
pottsin.  The area  also  supports a moderate stand  of honey mesquite
(Prosopis glandulosa var.  glandulosa).

Earthen berms were constructed  around the perimeters of three  reserve pits
exhibiting extremely high levels of salt contamination and each  pit was
                                 433

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flooded with 1.0 m of good quality (EC <2.0 dS   m"1) water in March 1984.
Soil cores were collected from six permanently marked sampling locations
on  each  pit at  0 to  15-,  15 to  30- and  30 to  45-cm depths  prior  to
flooding and shortly after infiltration of ponded water.  Samples were air
dried, ground to pass  a 2-mm  sieve,  and  analyzed for exchangeable Na and
cation exchange capacity (CEC) (17).   Each pit was divided into two plots,
one  of which  received  a gypsum  treatment  on 12  June  1984.    Gypsum
application  rates were determined  using a  modification of  the  formula
developed by Doering and Willis (18): GR - (CEC) (ESPinitia,  -  ESPfinil|)/100,
where GR (gypsum  requirement) and CEC are in cmol  kg" .

Fourwing saltbush  seedlings were transplanted on 2-m spacings on half  of
each  plot  and  oldman saltbush  (Atriplex  nummularia)  seedlings  were
transplanted on 2-m centers  on  the  other half  of  each plot on  12  June
1984, providing about  20  seedlings per subplot.   Fourwing  saltbush  is  a
native, evergreen  shrub commonly used for revegetation of disturbed~soils
in  the  southwestern  United  States  (1,19).    Oldman  saltbush  is  an
introduced,  evergreen  shrub  commonly used  for revegetation  of salt-
affected land in western Australia (20,21).  Both species are facultative
halophytes.

The fourwing saltbush seed  from which  transplants  were grown had  been
collected  from  a native  population growing on a saline-sodic soil 10  km
west  of Big  Lake.  Oldman saltbush seeds  were purchased from  a commercial
firm  in western Australia.  Seedlings of  fourwing and oldman saltbush  were
grown in  a greenhouse  in a  2:1:1  (v:v:v)  peat  moss/vermiculite/soil
mixture and were  4 months  old at time of planting.   All transplants  were
pruned  to  10-cm heights prior to planting.

Gypsum  was  applied  at 8  to  9 Mg  ha"1  to one plot  on each  reserve pit
immediately after  planting.  About 280 mm of additional water was applied
to  all  plots  by  sprinkler  irrigation   during  the  next  2  months for
additional  leaching.

Five  soil  cores  were collected from 0 to 15-, 15 to  30- and 30  to 45-cm
depths  along one  diagonal  of each  plot 15  and  38 months  after  gypsum
applications.  Samples were prepared as described previously and used for
laboratory  determination of electrical conductivity of the saturated paste
extract  (EC) and  sodium adsorption  ratio (SAR)  (17).   Plant  survival and
canopy height of the shrubs were  determined 5  and 38 months after planting
by  counting the number of live plants in  each  subplot  and by measuring the
height  of  each  live plant.

Experimental  design  was  a  randomized  complete   block,   with  three
replications.  Soil data were treated  as a split plot, with gypsum as the
main  plot  effect  and  time  as  the  subplot effect.   Vegetation data  were
                                  434

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treated as  a  split plot with gypsum  as  the main plot and  species  as the
subplot.   Data were  subjected to  analyses of variance,  and means  were
separated by  Duncan's multiple range test where appropriate  (22).

Results and discussion

Annual precipitation at the study site was > the 21-year average  in  1984
through  1987  (Table  2).    Flooding  with  1  m  of  water  significantly
decreased  EC  and  SAR in the surface 45  cm of soil  (Table 3).   Soil  EC
values ranged from 73 to 143 dS m"1  before flooding and from 34 to 48  dS
m"1 after the water  infiltrated and the  soils had dried, reflecting  a  53
to 66% reduction.   Soil SAR values  decreased by 35 to 58%.  Initial SAR
values were  63 to   90  and were  38  to  43 after  flooding.   Although
reductions  in salt  levels  were substantial, leaching  did  not reduce  EC
and SAR  levels sufficiently for growth of non-halophytic plants.

Electrical  conductivities  and  SAR values  after 15 months  tended to  be
greater on  plots receiving gypsum than on untreated plots, but differences
were not significant (Table 4) .   The  large  variability  in  EC  and SAR
within pits  after  15  months  probably  masked  treatment  effects.   The
conventional  practice  of mixing  soil with  drilling wastes  results  in
considerable  spatial variation  and exacerbates the difficulty in assessing
the level  of  site  contamination.

Electrical conductivities and SAR values of gypsum-treated and untreated
plots were  similar after 38 months  (Table 4).  Gypsum reduced both  EC and
SAR slightly  over  time,  but differences  were not significant.  Failure  of
gypsum to  reduce salinity levels in these soils  may have been due to  slow
and ineffective gypsum dissolution caused by high  S04-ion  concentrations
in the soil-drilling fluid mixtures.  Weber et al.  (23)  reported that  high
S04-ion  levels in  water used for leaching reduced the efficacy of  gypsum
for reclamation of sodic mine  spoils.  Reduced effectiveness of gypsum  in
reclamation trials  on  saline-sodic soils high  in  S04-ion  has also  been
observed (9,24).   High concentrations of S04-ion in leaching water or  soil
retard dissolution of gypsum due to the common  ion effect.  Soluble  S04-
ion concentrations in drilling fluids used in the region commonly range
from 10 to 12 mmol U1  (1).  The concentration of S04-ion in the water  we
used for leaching was not determined.

Gypsum  treatments   did  not   affec't  survival   or  canopy  heights   of
transplanted fourwing and oldman saltbush 5 months after planting  (Table
5).   All  oldman  saltbush  plants  died  during the  winter  of  1984-85,
apparently because of freeze damage.  Extended  periods (2  to 4 days)  of
sub-freezing (<0 C)  temperatures occurred during that time.  Use of  oldman
saltbush appears  to be  limited to  regions with  more  moderate  winter
temperatures.
                                  435

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Survival and canopy heights of fourwing saltbush transplants were also not
affected by gypsum application  after  38  months  (Table 5).   Seedling
survival was satisfactory at  63 and 65%  on plots with and without gypsum,
respectively.
                                 436

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References

 1.   M.L.  McFarland, D.N. Ueckert, S. Hartmann,  Revegetation of oilwell
     reserve pits in West Texas. J.Range Manage.,  40,  1987,  122-127.

 2.   J.P.  Simpson,   Drilling fluid principles and operations.   (F. Fisher,
     Ed.)  Conf. Proc., Environ, aspects of chemical use in well-drilling
     operations.  Office of Toxic  Substances, Houston, TX, 1975, 463-472.

 3.   R.W.  Miller, S. Hanarvar,  B.  Hunsaker,   Effects of drilling fluids
     on soils and plants.  I.  Individual fluid components.  J. Environ.
     Qual.,  9. 1980, 547-551.

 4.   R.W.  Miller, P.  Pesaran,   Effects of drilling  fluids  on soils and
     plants.   II.   Complete  drilling fluid mixture.   J. Environ.  Qual.,
     9, 1980,  552-556.

 5.   W.J.   McGinnies,    Effects of moisture stress  and  temperature  on
     germination of six  range  grasses.  Agron. J.,   52, 1960, 159-162.

 6.   T.T.  Kolzlowski,  Physiology of water  stress.  In:  Wildland shrubs-
     --their biology and utilization.  Logan, Utah.   USDA For. Serv. Gen.
     Tech. Rep. Int. 1., 1972,  229-244.

 7.   G. Orshan,   Morphological and  physical plasticity  in  relation  to
     drought.   (C.M. McKell, J.P.  Blaisdell,  J.R.  Goodin,  Ed.)  Wildland
     shrubs	their biology and utilization.  Logan, Utah. USDA For. Serv.
     Gen. Tech. Rep. 1.  Intermountain Forest and Range Exp. Sta.,  Ogden,
     Utah, 245-254, 1972.

 8.   J.  Keller, J.F.  Alfaro,    Effect  of  water application  rate  on
     leaching.  Soil Sci.,  102,  1966, 107-114.

 9.   G.A. O'Connor,  Limited  gypsum applications  on sodic  soils.   New
     Mexico Agric.  Exp.  Sta. Res.  Rep. 290, 1974.

 10.   C.W. Chang, H.E.  Dregne,  Reclamation of  salt-  and sodium-affected
     soils in the Mesilla Valley.   New Mexico Agric.  Exp. Sta. Bull. 401,
     1955.

 11.   I.P. Arbol, I.S. Dahiya, D.R.Rhumbla,   On the method of determining
     gypsum requirement  of soils.  Soil Sci.   120, 1975, 30-36.

 12.   C. Boawn, F.  Turner,  C.D.  Moodie,  C.A. Bower,  Reclamation  of  a
     saline-alkali  soil by leaching and  gypsum treatments  using sugar
     beets as  an indicator crop.   Proc. Am. Soc.  Sugar Beet Tech., 1952.

                                   437

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13.  D.J.  Dollhopf,  E.J.  Depuit,    Chemical amendment  and  irrigation
     effects  on sodium migration and vegetation  characteristics in sodic
     mine  soils  in  the  Northern Great  Plains.    In:   Symp.  on  surface
     mining hydrology, sedimentology and reclamation.  Univ. of Kentucky,
     Lexington, KY,  Dec.,  1981,  481-485.

14.  O.P.  Mathur,  S.K.  Mathur,  N.R. Talati,  Effect of addition  of sand
     and gypsum to  fine-textured  salt-affected soils on  the yield of
     cotton   and  jower  (Sorghum)  under  Rajasthan  Canal  Command  Area
     conditions.   Plant  and  Soil.,   74,  1983, 61-65.

15.  R.F.  Reitemeier,   Effect  of gypsum,  organic matter and drying on
     infiltration  of a sodium water  into a fine sandy loam.   USDA  Tech.
     Bull.  937,  1948.

16.  E.L.  Blum,  Soil  survey of Sterling  County,  Texas.    USDA  Soil
     Conservation  Service.   US  Govt. Printing  Office,  Washington  DC.,
     1977.

17.  United States Salinity  Laboratory Staff,  Diagnosis  and improvement
     of saline and  alkali soils.  USDA Hbk. No.  60,  US Govt. Printing
     Office,  Washington DC., 1954.

18.   E.J.  Doering, W.O. Willis,   Chemical  reclamation for  sodic strip-
     mine  spoils.  ARS-WC-20.  USDA, Agric.  Res. Serv.,  Peoria, IL. ,  1975.

19.  J.L.  Holechek,   Root biomass  on native range and  mine spoils in
      southeastern  Montana.   J.  Range Manage., 35,  1982,  185-187.

20.   B. Kok,  P.R.  George,  J. Stretch,  Saltland revegetation  with  salt-
      tolerant shrubs.  Reclam.  Reveg. Res.,  6,  1987,  25-31.

21.   C.V.  Malcolm,   Forage  production from  shrubs on  saline land.  J.
     Agric.  West.  Aust., 15, 1974,  68-73.

22.   R.G.D.  Steele, J.H. Torrie,   Principles and Procedures of Statistics.
     McGraw-Hill  Book company,  New York,  1960.

23.   S.J.  Weber, M.E. Essington,  G.A. O'Connor, W.L.  Gould,   Infiltration
      studies with  sodic  mine spoil  material.   Soil Sci.,  128,  1979,  312-
      318.

24.   R.J.  Prather, J.O. Goertzen,  J.D.  Rhoades, H.  Frenkel,   Efficient
      amendment use in sodic soil reclamation.   Soil Sci. Soc.  Amer. J.,
      42, 1978, 782-786.
                                    438

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Table 1.  Physical and chemical characteristics  of  soil and drilling
fluids from the study area
Parameter
Texture
Sand (%)
Silt (%)
Clay (%)
Class
PH
CEC (cmol kg'1)
EC (dS nf1)
SAR
ESP
Soil1

28
34
38
clay loam
7.5
32
1
0.2
0.3
Drilling fluid2

28
42
30
clay loam
7.5
25
174
199
65
 Average values for the surface 45 cm of soil, including Al, A2 and
Bwl horizons.
2Average values for four drilling fluids.
 Table 2. Monthly precipitation  (mm)  for  the  study  area,  1984  through
 1987
Month
January
February
March
April
May
June
July
August
September
October
November
December
Total
1984
25
6
8
0
19
44
50
1
93
75
41
43
405
1985
0
20
24
14
67
45
50
11
80
63
5
0
379
1986
6
34
4
63
114
75
19
76
61
169
14
84
719
1987
4
50
37
25
166
81
2
71
9
_l
-
.
445
21-year
average
13
18
19
33
52
49
42
39
56
52
24
17
414
 Rainfall data were not collected at this time.
                                   439

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Table 3. Soil electrical conductivities  and sodium adsorption ratios
at three depths on oil well reserve pits before  and after flooding
             EC (dS uf1)
SAR

Depth (cm)
0 to 15
15 to 30
30 to 45 ,
Before
flooding
143 a1
86 a
73 a
After
flooding
48 b
37 b
34 b
Before
flooding
90 a
67 a
63 a
After
flooding
38 b
43 b
41 b
'Means within EC or SAR and depth followed by the same lower case
letter are not significantly different  (P<0.05) according  to Duncan's
multiple range test.
Table 4. Soil electrical conductivities and sodium adsorption ratios
at three depths on oil well reserve pits 15 and 38 months after gypsum
application
Depth (cm)

0 to 15
15 to 30
30 to 45

0 to 15
15 to 30
30 to 45
EC (dS nf1)
Gypsum


811
53
60


46
32
31

No


38
22
16


47
39
33
SAR
gypsum Gypsum
t * r . t v

68
72
77


42
52
55

No gypsum


55
49
40


60
62
59
 'Means within EC or SAR and within a collection period and depth were
 not significantly different  (P<0.05).
                                   440

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Table 5. Survival  and canopy heights of transplanted  fourwing saltbush
and oldman saltbush seedlings on oilwell reserve pits  5  and  38 months
after gypsum  application
                     Survival (%)
                          Height  (cm)
Species
Gypsum    No gypsum
Gypsum   No gypsum
fourwing saltbush
oldman saltbush

fourwing saltbush
oldman saltbush
641
88
63
0
70
75
	 /
	 V
65
0
              (5 months)	
                           22       22
                           21       22
             (38 months)	
                          110      120
 'Means for survival or canopy height within a collection period
 were not significantly different (P<0.05).
                                  441

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EVALUATION OF OILY WASTE INJECTION BELOW THE PERMAFROST IN PRUDHOE BAY FIELD,
NORTH SLOPE, ALASKA
D. E. Andrews, A. S. Abou-Sayed, I. M. Buhidma
ARCO Alaska, lnc./ARCO Oil and Gas, Inc.
Anchorage, Alaska, U. S. A.
Abstract

This paper presents the results of an extensive study  and field test carried out at the site of
Prudhoe  Bay's four oily  waste  injection wells.   The field  work was part of  an overall
environmental  assessment intended to:  (a)  confirm  earlier results indicating that no  fluid
communication was occurring  with the  permafrost; (b)  determine optimum  conditions for the
disposal of waste in the presence of hydraulically induced  fractures; (c)  substantiate that an
increased injection pressure could be safely implemented. A three-day injection test,  including
a step-rate stage,  was carried out.  Data collected included surface and downhole pressures, in-
situ stress measurements,  and monitoring of ground surface deflections and wellbore  hydraulic
impedance.

Radially symmetric surface tilt patterns showed that the test well was connected to  a horizontal
fracture of 60-foot  radius.  Wellbore impedance measurements indicated that  a horizontal
fracture with a 9-18 foot radius  communicated with the well.  Integration of rock mechanics,
historical information, and the collected data provided  a clear picture of what was occurring
underground.  The  different evaluation  techniques showed consistent results  as  reflected in
estimated fracture  size, placement, and damage zone properties.

Introduction and Overview

In 1973, five wells drilled to a 2200-foot depth  in Prudhoe  Bay  Field formed  a five  spot
pattern with a lateral spacing of 23 feet.  They were used for  an  extensive thaw subsidence test,
then shut-in.  They were later converted to injection for waste fluid  disposal under a Class II
UIC permit.  The Center well was never perforated and the Northeast  well  has been abandoned.
Fluids can be directed to any one of the remaining three. Each well has 20-50 feet of casing
perforated at 2000 feet, approximately 150 feet below the base of the permafrost.   Injection is
intermittent, depending upon  when trucked fluids arrive  at  the site.   The plant  typically
operates at a 900± psi discharge pressure which means the rate usually varies  between 1-2
-bpm,  depending  upon  fluid characteristics.   Approximately  3  million barrels  have  been
injected.  Disposal rates average 600 bpd with peak rates of 6000 bpd.

A  simple description  of  the injection  stream  is difficult  because  of its  many  sources.
Predominantly  it consists  of waste waters,  but also includes contaminated  crude oil, vessel
sludge,  acids,  unused frac sand,  gels, drilling muds,  stimulation fluids and  formation fines,
unset cement, tank bottoms, and solutions of methanol and glycols. The range in temperatures,
viscosities, and densities is large.  The solids content is sometimes very high.
                                          443

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Continued  efficient fluid disposal will  require an  injection pressure of 1200 psi:   When a
Class-l UIC permit was sought in 1986, a 1400 psi  limit was requested.  The elevated pressure
was  provisionally allowed;  however, it  has gone through  an  extended  review in light of  new
regulations.  Central issues of concern have been the  need to demonstrate that a 1400 psi
pressure is necessary and safe, that the confining zone is not being fractured, and that no fluids
are penetrating the confining zone or damaging the permafrost.  It was decided that definitive
reservoir modeling, actual field tests,  and/or other supportive,  correlative  data would be
required  during the regulatory review process.

Geology and Sedimentology

Figure 1  shows a typical subsurface  log of the injection interval.  The wells  are perforated  in a
heterogeneous interval  of  thinly  bedded  shales, siltstones and sandstones, 30 feet  below a
laterally continuous thick bedded sandstone with excellent porosity and permeability, and  150
feet  below  permafrost.  Above the sandstone unit at the permafrost base lies a shaly interval
which is  believed to be an effective barrier to upward fluid flow.  These sands rise toward the
southwest and eventually intersect the permafrost.

Geologic and sedimentation studies of the lithologic column above the injection zone are detailed
in a  1970 Alaska Test Lab Report^)-   This work outlined  mechanistically how the permafrost
was  most probably  formed, and suggested that although the stress fields  appeared normal, they
may differ from those that exist in more conventional depositional environments.

Injection  Zone Performance From Conventional Data Analysis And Prior Measurements.

•  A general plugging of the zone was suspected and subsequently confirmed by an interference
   test in  which  virtually no communication existed  between the wells.  Further,  it was
   calculated that total plugging of the porosity could be expected to a radius  of 70+ feet using a
   conservative volume for injected solids.

   Falloff tests showed that the  injection zone was not  overpressured.  These tests  indicated
   severe  wellbore damage existed, but no major fracturing was evident from the data. Further
   interpretation was inconclusive and  it  was felt that additional conventional pressure testing
   was useless.

•  Surveys demonstrated that the perforated interval was in communication  with the sandstone
   interval just below the permafrost;  however,  no  uphole channeling  behind  pipe was
   occurring  as evidenced by three pump-in temperature surveys.

•  Sonic/Radioactive  logging   and  casing strain  measurements  confirmed  that  the
   sandstone/shale rock units were reacting very  differently  to the dynamic forces resulting
   from  radial thawing  of the permafrost  around the well  casings.(2)  The combined  effects
   further  compact the shales,  bond  the casings,  and successfully   prevent vertical fluid
   movement of injected fluids.

   Increasing, and sometimes   unusual,  injection  pressure  spikes could be explained  by
   progressive permeability reduction in  the  local  region surrounding the  wellbores, coupled
   with the existence of a fracture system that was opened and closed.

•  Depositional studies indicated that  theoretically, the  stress  regime favored creation of
   horizontal fractures  over vertical fractures.  In  total, it  was concluded  that there was  no
   evidence  of permafrost  fracturing or confining zone penetration.
                                          444

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    Plan and Objectives

To substantiate the safe use of a 1400 psi injection pressure, an  extensive field test  was
devised.  The goals were to fully understand the response of the injection zone when waste was
injected at normal  operating  conditions, to obtain sufficient  technical backup to support the
permit request for 1400 psi, and to determine what realistic limit was possible on pressure or
rate without penetrating the lower confining zone.

To achieve these objectives, it was felt necessary to obtain the  following data:

•  Record the deformation of the  earth's surface during an injection  operation since this  is a
   function of the subsurface anomaly  resulting  from the injection.  Surface tilts describe the
   plane and azimuth of any created fracture, or the absence of it.  The tilt vectors provide very
   different signatures for  vertical  and horizontal fractures^3)-   Monitoring the  vectors'
   progressions  during an  injection operation can  also establish the responsive  nature of the
   near wellbore region.

•  Measure the borehole impedance prior to, during, and  immediately  following  fluid
   injection^4).  Pulsing  the  injection stream and measuring the free pressure oscillations is
   indicative of the existence  and, to a lesser degree, the geometry (size and orientation) of any
   hydraulic fracture connected to the wellbore.

 •  Determine the  mechanical rock properties via sonic logging,  using  state-of-the-art tools.
   This would allow calculation of the minimum  horizontal stress profile.

 The Field Injection Test

 Implementation consisted of pumping  fluids  at  various rates  into the  southeast well while
 monitoring surface and  downhole pressures.  The surface pressure was sampled 150 times per
 second for the free oscillation studies.  Ground surface tilt rates were monitored before, during,
 and after the  stimulation, with a surface array of 17 high gain  tiltmeters, to determine source
 characteristics of any fractures that formed  as a result of the injection.   Free oscillation pulse
 and decay  experiments were  conducted throughout  the  injection periods to monitor wellbore
 impedance.

 The surface array of biaxial tiltmeters  is shown in Fig. 2. It consisted of  two concentric circles
 with  radii of 38  and 50 percent of the injection depth  to optimize the signal-to-noise ratio.
 Maximum surface tilts  for a horizontally oriented fracture occur at a radius of 800 feet.  As
 shown in Fig. 3, the maximum expected  signal amplitude was 390 nanoradians.  For a vertically
 oriented fracture, the maximum tilt magnitude is approximately one-fourth the magnitude of a
 horizontal  fracture  and occurs at a radius of 1000 feet.  Installation holes for the tiltmeters
 consisted of 8-inch pipe cemented 25 feet into the permafrost.

 Background data from the 34  tiltmeter  channels was  collected for six  weeks.   Sampling
 intervals averaged  eight minutes.  The  interval was decreased to once per minute during the
 injectivity/fracture testing  period.   Data  was transmitted  from  each instrument via cable to a
 centralized  dual computer  system.  The three-day  test consisted of the following pumping
 sequence:
                                          445

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Stage 1) 1000 bbls of 27 API crude oil  pumped at 2 bpm; 38 cp viscosity, BHP-1400 psi
Stage 2) 1000 bbls of 27 API crude oil  pumped at 4.8  bpm; 38 cp viscosity, BHP-1500 psi
Stage 3)   800 bbls crosslinked gel pumped at 8-10 bpm; 68 cp FANN viscosity, BHP-1700 psi

Tilt Meter and Wellbore Impedance Results

Surface  deformations  associated with each  of  the injection  periods  are detailed in the
consultant's  report^5).  Figure 4 shows examples of raw tilt data for station five during the
second day of testing.  Data quality was excellent as all channels recorded the solid earth tides
and induced deformations.  The  tiltmeter noise  levels were  extremely  low, averaging one
nanoradian.  Figures 5-7 provide a summary of the final tilt vectors at the end of each pumping
period.

1.  The injection  periods lasted different lengths of time, yet the total accumulated surface  tilt
    magnitude for each period was virtually identical.  A single vertical planar dislocation could
    not be  made  to fit  the recorded signatures.  However, the radially symmetric tilt patterns
    could be  modeled by subhorizontal, rectangular,  mode-1 dislocations.

    An  inversion  analysis  indicated  that the  tip-to-tip  length of  the  modeled horizontal
    fractures  did  not exceed 140 feet  and the fracture opening was  approximately 0.3 inches.
    The maximum fracture  radius was approximately 70 feet.  The modeled fracture volume
    averaged 327 cubic feet, and fracture  fluid efficiency was extremely low, averaging 0.058.
    This means that 94 percent  of the  injected fluid  leaked into the formation.  If any portion  of
    the  leak-off dilated the  formation and  contributed to the  observed deformations,  then the
    modeled fracture volume would be proportionately decreased.

2.  The above analysis assumes that the dislocation source is  a planar feature.  However,
    spherical source  distributions also produce radially symmetric surface tilt patterns.  If a
    discrete fracture  did not form and  the injected  fluid only diffused  outwardly, dilating a
    highly permeable zone, then the integrated effect when modeled as a dislocation source would
    appear as a horizontal  planar feature  with the same  characteristics outlined above  in
    item 1.   Inversion of the surface tilts, assuming  that a spherically  dilatant source geometry
    exists,  is highly non-unique  since  the source parameters  appear as multiplicative terms  in
    the  theoretical  expression  for surface  tilts.   A typical  inversion solution  for spherical
    source  parameters  for  the  third stage injection  yields a fluid infiltration radius of 62  feet,
    dp/G  = 0.00125.  The  dimensionless  ratio dp/G typically ranges from  0.0001  to 0.001.  It
    relates  the net pressure above overburden pressure  in the fluid infiltrated region, dp, to the
    formation shear modulus, G.  Based  upon this range in dp/G, the upper and lower limits for
    fluid infiltration radius  probably  range  from  50 to  100  feet.   The possibility  that a
    spherical source existed was repeatedly examined (5> 6), yielding an average 72 foot dilated
    radius.

3.  The tilt data alone cannot distinguish between a dilatant source geometry and a horizontal,
    planar source; however, the  above  indicators allow us to conclude that the well is connected
    to either  a horizontal fracture or a spherically  dilated  zone.   In this  instance, the inability
    to distinguish between  the  competing geometries is  due to the  radial symmetry of the
    observed surface  tilt field. If a fracture had been created  that was either steeply dipping  or
    vertical, then  the possibility of a spherical source geometry could be eliminated and a plot of
    the resulting azimuth and dip constructed.
                                          446

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4.  Wellbore  impedance  measurements clearly indicate the existence  of a  fracture^).  A
   horizontal fracture,  with radii calculated for the three stages of pumping, varied between
   9-18 feet as illustrated in Fig. 8.  The data could also be made to fit (to a lesser degree) a
   contained vertical fracture  5 feet high and 80  feet long,  an  unreasonable  dimension.
   Therefore, it  is concluded  that  the  impedance calculations support  the existence of a
   horizontal  fracture.

Pressure Transient Analysis and Observations

Quantitative interpretation of the pressure  transient data is difficult if not  impossible because
of  the complex  mobility  profile.  However, qualitative inspection  of the  step-rate and falloff
data support  either a  no-fracturing  situation  or  a  short  radius  horizontal  fracture.
Specifically:

1.  Step-rate data from a vertical fracture shows a  distinct decrease in slope on the Cartesian
   plot of pressure-versus-rate when injecting above  fracturing  pressure.  The change in
   slope is a reflection  of the  improvement in the well's injectivity resulting  from  the shift
   from radial to linear flow  regimes.  Data in Fig. 9 does not show the decrease  in slope;
   rather, it increases.   In the case of  a horizontal fracture of short radius, the increase in
   injectivity is  insignificant  in  a relatively thick formation.   Gringarten  and  Ramey  (1974)
   have  shown  that in a formation such as this, a short horizontal  fracture  does  not
   significantly enhance  a  well's performance.  The increase in  slope seen  here can only  be
   explained as  a result  of short injection time.

2. Inspection of the  falloff  data after each period did  not show indications of fracture closure.
   Multi-rate  analysis following the second  injection period, assuming  radial flow existed,
   gives a mobility of 46 md/cp. This is indicative of fluid entering  1-2 darcy rock.

Measurement of In Situ Stresses

The  minimum closure stress was  measured using the breakdown test technique.  Measured
fracture gradients ranged from 0.82 to 0.85 psi/ft.  The overburden gradient, calculated from
the porosity-density log profiles, was estimated between  0.80 and 0.90 psi/ft. Hence, it almost
equals the measured gradients. These numbers indicate  horizontal fractures should occur at the
injection horizons.  This conclusion  is supported by the fracture reopening  pressure which was
measured at 1590 psi during  the step-rate  test while pumping gelled fluid.

Comparative Considerations

Basic fracture theory(8),  coupled with the  high  permafrost plasticity, suggests that multiple or
successive horizontal fractures are  possible when plugging of earlier fractures occurs.  This
phenomenon has been observed and mapped at a similar facility(9'11). At Oak Ridge  in Melton
Valley, radioactive grout  has  been  successfully injected into shallow shale layers since 1959.
Seven fractures were  mapped  and all appeared  to be nearly horizontal.  This phenomenon may
also be occurring here.

Sumrfiarv and Concluding Remarks

1 • The surface tilt data was generated by  a horizontal fracture of approximately 60 feet radius
    at all three injection rates.  No  vertical fracturing was discernible.  This result agrees with
                                          447

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   fracture theory and was also verified qualitatively by impedance analysis.  Step-rate testing
   and pressure falloff data support this finding.

2. The horizontal  stress above 2000 feet appears to equal or exceed the vertical stress.  This
   North Slope data tends to agree with observations in other localities around the world, and
   hence leads us to believe that any subsequently created fractures will also be basically
   horizontal in nature.  Further documentation on this can be provided.

3. Test data confirmed that  the  injection process occurred through a horizontal conduit that
   penetrates a severely damaged region. While the damaged area may contain some secondary
   conjugate fractures, no principal vertical fracture exists.

4. Localized radial thawing around  the wellbores  has had no effect on vertical fluid movement.
   Lithologic heterogeneities and  permafrost rock  mechanics have combined to prevent vertical
   migration of the dirty wastes.  This is to  be expected, since the injection zone is not overly
   pressured and is overlain by an essentially impermeable barrier.

5. In  total, the  study  confirmed that the  reservoir provides a  good waste  disposal site.
   Injection  at a sustained  rate  of  4 bpm will  pose no  problem.   With the  current well
   completions, the use of surface pressures up to 1400 psi  is safe. Temporary rate increases
   to  6-8 bpm can occur without risk of forcing  fluids  into  confining  zones or damaging the
   permafrost at  the site.

REFERENCES

1.     Adams, Corthell,  Lee, Winch and Associates, "Coring and Testing Permafrost to a Depth of
       1850  Feet, Boring 12-10-14, Prudhoe Bay, Alaska," Alaska Test Lab Report for B. P.
       Alaska, Inc.; June, 1970  (Distributed to All Unit Owners).

2.     T.  K. Perkins, et al, "Permafrost and Well Design  for Thaw Subsidence Protection,"
       Report to Alaska  Oil and Gas Commission, May, 1975.

3.     M. D. Wood, D.  D. Pollard,  and C. B. Raleigh:  "Determination of In-Situ Geometry of
       Hydraulically Generated Fractures Using Tiltmeters," SPE Paper 6091 presented at the
       1976 SPE Annual Technical Conference and Exhibition, New Orleans, Oct. 3-6, 1976.

4.     G. R. Halzhonsen, "Impedance of Hydraulic Fractures:  Its Measurement  and Use for
       Estimating  Closure Pressure  and Fracture  Dimensions,"   SPE/DOE  Paper 13892,
       SPE/DOE  Symposium  on  Low Permeability, Denver, May,  1985.

5^^    G. Gezones, "Hydraulic Fracture  Mapping, SE Disposal Well, Pad #3,  Drill Site #6,
       Prudhoe Bay, Alaska,"  Report, Hunter Geophysics, Santa Clara, CA., Sept., 1987.

6.     J. Walsh,  Private Communication, 1987.

7.     H.  Egan and G.  Baker, "Results of Hydraulic Impedance Testing of Oily Waste Disposal
       Well  OWDW-SE,   Prudhoe  Bay  Field,  Prudhoe  Bay,  Alaska,"  Report, Applied
       Geomechanics, Inc., Santa Cruz, CA, 1988.

8.     E. R. Simonson,  A. S.  Abou-Sayed, and R.  J. Clifton, "Containment of Massive Hydraulic
       Fractures,"  Soc.  of Pet. Eng. J. (SPEJ), Feb., 1978, pp 27-32.
                                         448

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9.


10.




11.
G.  W. Belter, "Deep Disposal Systems for Radioactive  Wastes,"  Underground Waste
Management and Environmental Implications,  AAPG Publications, 1972, pp 341-350.

W.  deLaguna, et al, "Engineering Development of  Hydraulic Fracturing as Method for
Permanent Disposal of Radioactive  Wastes,"  Oak Ridge National Lab. Report  ORNL-
4259,  1968.

C. S. Haase, "Geological and Petrophysical Considerations Relevant to the Disposal of
Radioactive Wastes by Hydraulic Fracturing: An Example at the U. S. DOE's Oak Ridge
National Laboratory," Proc. of Material Research Society Symposium, Vol. 15, 1983, pp
307-314.
                                                     Base of Thickly
                                                     Bedded Sandstone
             Oily Waste Injection
             Interval (NE/NW wells.)
                                 Fig. 1—Typical log for OWI wells.
                                      449

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    600 -,
    400 -
g   200-
cr
o
UJ
O
    200 -
    400 -
Fig. 2—Tilt meter location map around pad 3.

                         VOLUME (CD. FT.) = 5580.0
                         DIP  (DEGREE)     =0.0
                         MAX. TILT         =590
                         MAX. X/D         =0.4170
                             X = DEPTH, 2000 FT.
                             D= SURFACE
                                DISPLACEMENT, FT.
    600 ->
                   0.00     1.00

                      X/D RATIO
                                                  2.00     3.00
        Fig. 3—Theoretical tilts for a 1000 bbl horizontal dislocation
               at a depth of 2000 feet.
                              450

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VOLTS
 .05
  .04
  .03
            H	h
             I      I
    00:00        04:

VOLT RANGE:  .025
    CHANNEL   9
Oft M        14: 34       1ft IB
   10: 38   13: 55::
       TIME
                                                              00: 00
 VOLTS
 -.01
 -.03
 -.05
    00:00       04: 4B

 VOLT RANGE:  .034
    CHANNEL   10
                   l     I     I
                                   •4-
                                               H	H
              V	>
0* M        14:14
   10: 38   13: 55:
       TIME
                                                  1ft IK
                                                              OO: 00
          Fig. 4—Tilt record during the second day injection test
                 showing effect of pumping.
                                 451

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                        f
         - r..       10
         -i?
             17
                           #1
                                 •T
                                12
                                        500 FEET
 FRAC #   AZ   DIP  DEPTH(FT)
     1  -33   4.4    2000
                                            REAL
	 THEO

 L ' W * T (CU ft)
114  «  94 ..029
 Fig. 5—Tilt map at end of first day pumping.
                  10
                        /\
                       \
                           #1
                               12
                                    13
                        4

                                        500 FEET
FRAC *   A2   OIP  DEPTHCFT)
     1  -39   5.7    2000
	. REAL
	» THEO

 L ' W * T (CU ft)
 B7  .  133  ..028
Fig. 6—Tilt map at end of second day pumping.
                   452

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                            17
                                          11
                                                 /
                                              12
                                                  13
                                                     4  •>
                                                       500 FEET
  1000
                                                       _, REAL
                FRAC *    A2   DIP  DEPTH(FT)

                    1    38   4.7    2000
	 THEO


 L • H * T (CU ft)


136  •  B2  -.031
                 Fig. 7—Tilt map at end of third day pumping.
       After BOO Dbljinjection t 9 dpi
                                   	Observed Have    —-  Modelled Wave
  aoo
ui eoo
u
a:
g
a.
  200
                                 11  Seconds Duration
       Fig. 8—Typical well impendance response during pressure pulsing.
                                      453

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   1540
CO
w  1500
OC

CO
CO
UJ
oc
a.
P 1450

O
m
                                                                PAD 3 TEST

                                                                STEP RATE TEST
    1400-
                                     4567

                                   INJECTION RATE (BPM)
10
          Fig. 9—Pressure-rate record during step rate test at pad 3 N.E. well.
                                        454

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EVALUATION OF SELECTIVE-PLACEMENT BURIAL FOR DISPOSAL OF DRILLING FLUIDS
IN WEST  TEXAS
Mark L.  McFarland
Texas Agricultural Extension Service
Texas A&M University
College  Station,  Texas  77843  U.S.A.
Darrell N.  Ueckert
Texas Agricultural Experiment Station
7887 N. Hwy 87
San Angelo, Texas  76901  U.S.A.
Steve Hartmann
University of Texas Lands - Surface Interests
P.O. Box 553
Midland, Texas  79701  U.S.A.
Introduction
Onsite, surface disposal of drilling fluids used in petroleum and natural
gas exploration is a common practice  in arid  and semiarid  regions of the
southwestern  United States,  even  though soils  may  be  severely and
permanently  contaminated.    Selective-placement   burial,  a technique
developed for coal mine reclamation,  presents an alternative to surface
disposal  in  which  drilling  fluids  are  worked,  stored,  dried,  and
eventually buried at a predetermined depth below  the soil  surface.   In
this process,  limited contact  of soil and the  contaminated wastes reduces
the  waste  volume  and preserves  the  quality  of  topsoil  and  subsoil
essential for site reclamation.

This paper presents  results  of the 4-year evaluation of an experiment
                                   455

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initiated in 1986 to determine the effects of selective-placement burial
of drilling fluids on soil chemical properties and on growth and chemical
composition of two species used for revegetation.  Data collected as of
20 months  after  treatment  installation  indicated that  soluble  salts
migrated upward  15  to  30 cm into  overlying  soil and  that capillary
barriers of coarse limestone were only partially effective  for reducing
salt  movement (1).   No  evidence  was  found  to  suggest  that  upward
migration of heavy metals  (Ba, Cr, Cu,  Ni, Zn)  contained in  the drilling
fluids and  detected in  concentrations near, or  above,  those in native
soils had occurred.  Survival and growth of fourwing saltbush (Atriplex
canescens (Pursh)  Nutt.)  and  buffalograss  (Buchloe dactyloides (Nutt.)
Engelm.) 17 months after planting were  not affected by depth of drilling
fluid burial, although significant increases in Na and K concentrations
in both species at one location indicated plant uptake of drilling fluid
constituents  where burial depth  was  30  cm (1).   A  more  significant
finding was evidence of elevated Zn concentrations in fourwing saltbush
tissue on plots where drilling fluid was buried 30 or 90 cm.

Materials and Methods                                       —
The field study was  established  in  1985-86  in  the northwestern Edwards
Plateau of Texas.   The study sites were 10 km north of Big Lake in Reagan
County  (Weatherby site)  and  34 km  southwest  of Mertzon  in Schleicher
County  (Mertz site).  Reagan  County  is semiarid  with an average annual
rainfall of 430 mm and a  mean annual  lake evaporation  of 1800 mm.   The
study area  was  on  a level,  upland site on a  Reagan clay  loam  (fine,
mixed, thermic, Ustollic  Calciorthid).   The average  annual rainfall in
Schleicher county is 460 mm and the mean  annual lake evaporation is 1780
mm.  The study site  was on  a  flat valley floor above the overflow zone
on an Angelo clay  loam (fine, mixed, thermic,  Torrertic Calciustoll).

Fifteen, 12-  by  12-m simulated reserve pits separated by 15-m buffers
were  constructed  at each  location  in August  1985 using  a bulldozer.
Treatments  included  burial of drilling fluid 30,  90,  or 150 cm,  burial
90 cm with a 30-cm capillary barrier of coarse  limestone (Edwards Group)
immediately above  the  drilling fluid,  and  an  undisturbed control from
which existing vegetation was cleared with the  dozer blade.  Topsoil and
subsoil were removed and stockpiled separately during pit construction.
Spent drilling fluids from  two drilling locations near each study site
were transported  to  the areas in dump  trucks in  September 1985.   Equal
volumes of about 25  m3 of  drilling fluid were placed as a uniform 30-cm
layer into  each pit, allowed to dry,  and  then covered  by sequential
replacement of subsoil and topsoil in January 1986.  Experimental design
was a randomized  complete  block  arranged  as  a  split plot with  three
replications.  Replications were blocked by drilling fluid  source.

The study  sites  were fenced  to  exclude livestock and lagomorphs,  and
field plantings were established in spring 1986.   Each reserve pit plot


                                 456

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was divided into two, 6- by 12-m subplots.  Fourwing saltbush  (Atriplex
canescens  (Pursh)  Nutt.),  a  native,  evergreen, halophytic  shrub, and
"Texoka" buffalograss (Buchloe  dactyloides  (Nutt.)  Engelm.), a native,
perennial, warm-season shortgrass were  used to evaluate the effects of
plant material on contaminant migration.  Forty seedlings of buffalograss
were transplanted on 1-m centers on one subplot of each pit.  Seedlings
were grown in a greenhouse  in  an equal-volume peat moss\vermiculite\soil
mixture in 4- by 5-  by  18-cm  polyethylene containers.   Twenty-four, 1-
year-old rooted stem-cuttings of fourwing saltbush were transplanted on
1.5-m centers on the  other subplot.  Stem-cuttings were  taken  from mature
plants which were  established in 1982 on a highly saline reserve pit (EC
- 90, SAR - 46) near Big Lake, Texas.   The seed from which these shrubs
were produced was harvested from a native population near Texon (Reagan
County),  Texas.   Stem-cuttings  were rooted for about  2 weeks  in a 1:1
(v:v) sand\vermiculite mixture  using an intermittent misting system in
a greenhouse, and transferred to 4- by 5- by 18-cm polyethylene tubpaks
containing an equal-volume peat moss\vermiculite\soil mixture.

Results from  soil  analyses conducted on  samples collected  1,  8  and 20
months after pit coverage were reported previously (1).  Data presented
in this paper concerns results from similar analyses conducted on samples
collected 44 months after pit coverage.   Sampling trenches bisecting each
plot  were excavated to the  soil/drilling  fluid  (or soil/limestone)
interface using a backhoe.   Samples were collected from the pit wall in
30-cm  increments,  with zones at  the  soil/drilling  fluid  and soil/air
interfaces subdivided  into 15-cm increments.   Composited  soil samples
from  each subplot  were  air-dried and pulverized to  pass a 2-mm sieve.
Samples were analyzed using methods reported previously (1).

Survival  and  growth  of fourwing saltbush and buffalograss transplants
were  determined  41  months  after  planting  using  methods  reported
previously (1). Representative aboveground tissue samples were collected
from  10 plants  in  each  subplot  in August  1989, oven-dried  at 60 C, and
ground to pass a 0.15-mm sieve.   Total concentrations of Ca, Mg, Na, K,
Ba, Cr, Cu, Ni and Zn were determined by ICP  atomic emission spectroscopy
after HN03-HC104 digestion of composited subsamples.

Soil  data were  treated  as  a split-split  plot  with depth of burial the
main-plot effect,  plant species the subplot effect, and time (20 and 44
months)' the sub-subplot effect.   The data were subjected to analyses of
variance  and treatment means separated where appropriate using Fisher's
least significant difference method. Plant  data were subjected to split
plot analyses of variance, where depth of burial was the main plot effect
and  plant species was  the subplot effect.   Means  were  separated by
Duncan's new multiple range test where appropriate.
                                 457

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Results and Discussion
Physical and chemical characteristics of the native soil profiles and the
drilling fluids  used at each study  site  were reported previously  (1).
Salt contamination was the predominant concern as evidenced by  drilling
fluid EC values of 155 to 185 dS nv1 and ESP values of 42  to 89.  Sodium
and  el' were  the  dominant  soluble  ions, although  K+,  Ca+2,  and  Mg+2
concentrations were also much greater in  drilling fluids  than in native
soils.  Among-treatment comparisons of upward contaminant movement in the
reconstructed   soil   profiles  were  facilitated  by  redefining  the
soil/drilling  fluid  (or soil/limestone)  interface as  the zero point.
Treatment comparisons for EC and ESP data were made within each increment
above this reference point.

Rainfall at the Weatherby site during 1988 and 1989 totalled 454 and 281
mm,  respectively,  compared  to the long-term  annual  average  of 415 mm.
On the Mertz site, rainfall totalled 514  mm in 1988 and 353 mm  in 1989,
compared to the  long-term annual  average  of  466  nun.   Thus, in  the year
preceding this evaluation rainfall was considerably less  than the long-
term averages at both study sites.

  Salt  movement  into soil  overlying drilling  fluid  was similar in
subplots planted to fourwing saltbush and  buffalograss,  so the data were
pooled for presentation.  The time x depth of  burial interactions  were
significant for EC in the 0 to 15-.  15 to  30-  and 30 to 60-cm  increments
above drilling  fluid on the Mertz  site  (Table 1).   In  the  0 to 15-cm
increment, EC values  in the 30-  and 150-cm burial treatments increased
significantly over time, and  a  similar  trend was observed in the 90-cm
treatment.   The 90-cm + barrier  treatment significantly decreased the
extent of upward salt migration compared to other  burial  treatments after
44 months.   Similar  treatment effects were observed in the 15  to 30-cm
increment.   Electrical  conductivities in  the  90- and 150-cm  treatments
increased over  time  and were  greater than those  in the 30-cm and 90-cm
+ barrier treatments  after  44 months.   Evidence  of salt migration  from
drilling fluid  into  the  30  to 60-cm increment was observed only in the
150-cm depth of burial treatment.  The greater mean soil moisture content
presumably maintained year-round at this  depth below  surface in  the  150-
cm treatment, which corresponds to much more  shallow  depths in the other
burial  treatments,  may  have  facilitated  greater   salt movement by
diffusion.

Patterns of  salt movement  from drilling  fluid into overlying soil  were
somewhat different on the Weatherby  study site.  Mean soil EC values in
the  0 to 15-cm increment tended to increase in all  treatments  from  20 to
44 months, but differences were not significant (Table 2).  Averaged over
depth of burial,  electrical conductivities in the 15 to  30-cm increment
increased significantly  over  time from 3.9 to 18.2 dS nv1.  The  greatest
EC values occurred in the 90- and 150-cm burial treatments (37.3  and 17.4
                                  458

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dS m'1, respectively).  However, mean EC values of 10 dS m'1  in the surface
15 cm of  the  30-cm  treatment represent  salinities which  will likely
impair establishment  of  many non-salt-tolerant plant  species.   The
capillary  barrier tended to decrease average EC values only  slightly  in
the 0 to  15-  and  15  to  30-cm increments.   Failure  of  the limestone
material used at this site  to  provide  an effective barrier was evident
after 20 months (1).  The  time x  treatment interaction was  significant
for EC values  in  the  30 to  60-cm increment.   Both  the  90- and 150-cm
burial depths exhibited significant increases  in EC values from 20 to  44
months.    In contrast,  the  capillary  barrier  appeared  to  limit  salt
movement into this zone over time  and resulted in significantly lower  EC
values compared to the 90-  and 150-cm treatments  after  44 months.  There
was no  evidence of salt  movement above  the  30 to  60-cm  increment  on
either study site.

Time and the time x depth  of burial interaction were  significant for ESP
values in the 0 to 15- and 15  to 30-cm increments, respectively, on the
Mertz site (Table 3).   Averaged over depth of burial, ESP values in the
0  to 15-cm increment increased significantly over time from  5.7 to 13.6
after 44 months. The capillary barrier tended to reduce Ha"1" accumulation
on the  soil cation exchange  complex  in  this increment,  but treatment
differences  were  not significant.   Conversely,  at  15 to  30-cm above
drilling fluid ESP values  in the  30- and  90-cm + barrier treatments were
<1 and were  significantly  less  than  those  in  the  90-   and  150-cm
treatments  (5.1 and 6.9,  respectively).    Significant  increases  in ESP
values  in the  90  and  150-cm treatments  over  time  corresponded  with
greater EC  values  in  these treatments (Table 1).   Exchangeable sodium
percentages  in  the 0 to 15- and 15 to 30-cm increments on the Weatherby
site increased significantly over  time  (data not shown). Depth of burial
did not significantly affect ESP values,  although the smallest increases
were observed  in the  90-cm + barrier  treatment  in both increments.    No
significant  treatment effects  on ESP values were observed above 30 cm.

Depth  of  burial did  not   significantly  affect  upward  salt migration.
However, increases in EC and ESP values in the 15 to 30-cm  increment  of
the shallow, 30-cm  treatment tended to be less  than those observed for
greater depths  of burial.   Lower  soil  water contents in this increment
of the 30-cm  treatment  caused  by  evaporation  may have  reduced  Na+
diffusion.   Soil columns open  to evaporation have been shown to support
less upward  Na+ movement  than columns without  evaporation, thus lower
soil-zone water contents under  evaporation reduce diffusion more  than any
concomitant  increase of convective salt flows.   The effect  in this study
was greater for the clay soil (Mertz site) than  the clay loam (Weatherby
site).   Similarities in  the  nature of  salt migration  from different
depths  of  burial   suggests  that  diffusion  is  the  dominant  process
affecting upward salt movement (1) . Additional  salt  migration since the
20-month  evaluation,   particularly into  the  30  to  60-cm increment,
                                  459

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indicates that an "equilibrium" condition has not yet been achieved with
respect to upward salt movement.

Initial analyses of samples of the drilling fluids from each study site
identified  5  metals  (Ba,   Cr,   Cu,   Ni  and  Zn)   which occurred  in
concentrations near, or greater than, those in  the native  soil profiles
(1).  However, evaluations of soil samples collected  from  the 0 to 15-cm
zone above drilling fluid 1 and 20 months after  pits  were  covered showed
no  evidence  of upward  movement  of  these metals  over time.   Similar
comparisons were made with data collected after 44 months  and there was
again no evidence of metal movement within the reconstructed profiles at
0 to 15- or  15  to  30-cm above drilling fluids (data  not shown).   These
data support  the contention  that  little  or no movement of these metals
should be expected  in the alkaline,  calcareous soils characteristic of
this  region  due  to sorption and/or   precipitation reactions  which
immobilize them in or near the waste/soil interface.

Survival of fourwing saltbush transplants after  41 months  ranged from 92
to  100% (data  not shown).   Depth  of  drilling  fluid burial did  not
significantly affect saltbush survival.   Spread and  overlap  of stolons
of  buffalograss   transplants  prevented  measurement of  individual
transplant survival, but  there were  no  indications of additional plant
mortality after 41  months.  Canopy cover of fourwing saltbush transplants
41 months after planting was  significantly greater on plots with buried
drilling fluids (45 to 76%) compared to control plots  (22 to 32%) at both
study  sites   (Table  4).   However,  average  canopy  cover of  fourwing
saltbush on the 30-cm treatment on the Mertz site was  significantly less
than those on other treatments with buried drilling fluid.   A similar
trend was observed for buffalograss on both sites, although differences
were not significant.  Fourwing saltbush canopy cover  increased by 6 to
20% from  the 17-month evaluation, while buffalograss canopy  cover had
decreased on most plots  by 3 to 11%.  Enhanced plant growth on plots with
buried  drilling fluid  and attributed to  the  tillage effect  associated
with pit construction was still evident  after 41 months.

Regression equations for estimating total aboveground  biomass of fourwing
saltbush were:  log W -  -5.024 + 0.918 [log (4irr3/3)]  for the Mertz site,
and log W -  -7.660 + 1.063  [log (trr^)]  for the Weatherby site, where r
is the  average  plant canopy  radius in  cm,  h is  plant height  in cm, and
oven-dry weight (W) is expressed in g.  These  equations accounted for 89
and 97% of the variability in aboveground biomass for  fourwing saltbush
on the Mertz and Weatherby study sites, respectively.   Fourwing saltbush
biomass production was significantly greater on treated plots (11450 to
21501 kg ha'1) compared  to control plots  (1749 to 4184 kg ha'1)  after 41
months  (Table 4).  This  corresponded  with results observed at 17 months,
although  saltbush  yields  increased  by  561  to  14261 kg   ha'1  after 41
months.   Yields of fourwing  saltbush  on the Mertz  site  on  plots with
                                  460

-------
drilling fluids buried 30  cm were  significantly less than those on the
150-cm treatment.   Buffalograss yields in the  fourth  growing season were
56 to 906  kg ha"1  less than those  after two  growing seasons.   Results
observed for  plant canopy cover and biomass data may  represent early
indications of burial depth effects on plant performance.  Below-average
rainfall in  1989   probably limited  plant  growth,  particularly  on the
shallow, 30-cm treatment, where rooting depth was restricted.  Additional
effects stemming  from the  impacts  of  greater rooting zone salinity on
plant growth on the 30-cm treatment are likely, but not distinguishable.

Sodium concentrations in buffalograss growing on the 30-cm treatment on
the Weatherby site were significantly greater  than those in buffalograss
growing on control or 150-cm burial treatments,  and tended  to be greater
than  those on  the  90-cm  and  90-cm +  barrier  treatments (Table  5).
Similar  results  were observed  for  fourwing saltbush  leaves on  the
Weatherby  site.    In contrast, there was no evidence  of elevated  Na
concentrations  in  either   species  on  the  Mertz site.    These  site
differences  are  likely attributable  to greater upward  salt  migration
which  occurred on the Weatherby   site  (Table   2).    The  elevated  Na
concentrations were  similar in magnitude to those observed at_17 months
after planting. Thus, although additional upward salt movement occurred
by 41 months,  accumulations in plant tissue remained relatively constant.
Concentrations of K in fourwing saltbush leaves growing on control plots
at both locations  were  significantly less  than  those in plants growing
on plots with buried drilling  fluids.  In contrast, concentrations of Ca
in fourwing saltbush  leaves growing on control plots at both locations,
and  saltbush stems  growing  on the  Weatherby site  were  significantly
greater than  those in plants growing  on  treated plots.  A similar trend
was  observed  for  Mg  concentrations in fourwing  saltbush leaf  tissue on
the  Weatherby site.   These results were attributed to residual effects
of  pit construction on plant growth  (tillage  effect)   and  nutrient
availability  (soil profile mixing).

There was  no  evidence  of  accumulation  of  Ba,  Cr,  Cu,  Ni or  Zn from
drilling fluids by fourwing saltbush or buffalograss plants  growing on
either study site  after 41 months.  These results corresponded with those
observed at  17 months,  and indicated  that profile disturbance was the
primary factor influencing treatment  differences for these metals.

Conclusions
Burial  of spent  drilling  fluids   in arid  and semiarid  environments
represents a  viable  alternative to  the  conventional method  of surface
disposal.   Soluble  salt migration as  much  as  30 to 60  cm  into soil
overlying  drilling fluid  after 44 months  suggests  that burial  >90 cm
below the soil surface may  be  necessary.   Increases in plant tissue salt
concentrations indicate that uptake of drilling fluid constituents may
occur with shallow burial,  but heavy metals will not be plant available
                                 461

-------
under  the conditions  reported  here.    Selective-placement  burial  of
drilling  fluids will  reduce soil contamination  on  drilling sites, and
should facilitate revegetation by natural and/or artificial means.

References
1. M. L.  McFarland, D. N.  Ueckert,  F.  M.  Hons, S. Hartmann, Selective-
  placement  burial  of  drilling fluids.    Dissertation.    Texas  A&M
  University,  College  Station,  Texas,  1988.
Table 1. Average soil electrical conductivities at five  increments above
drilling  fluid on  the Mertz  study  site after  20 and  44  months  as
influenced by depth of burial.
      Depth of                       	Time (months)	
       burial                            20                 44

        (cm)                                   (dS m'1)
                                	(Increment  above  drilling fluid)	
                                              (0 to 15 cm)
30
90
90+barrier
150

30
90
90+barrier
150

90
90+barrier
150

90
90+barrier
150

90
90+barrier
150
4
8
2
9

0
0
0
1

0
0
0

0
0
0

0
0
0
.4
.1
.6
.2

.5
.5
.5
.4

.4
.5
.8

.5
.5
.5

.5
.5
.4
a"

	 "
a
(15 to 30 cm)

a

a
(30 to 60 cm)


a
(60 to 75 cm)



(75 to 90 cm)



24
14
4
21

0
6
1
14

0
0
2

0
0
0

0
0
0
.2
.5
.2
.0

.9
.8
.3
.8

.6
.5
.7

.5
.4
.6

.6
.8
.7
b C
B
A
b C

A
b B
A
b C

A
A
b B








"Means within a depth of burial and  row followed by similar lower case
letters and within an increment above drilling fluid and colum followed
by  similar  upper case  letters  are not significantly  different  by LSD
(P<0.05).
                                 462

-------
Table 2.  Average soil electrical conductivities at five  increments above
drilling fluid on  the Weatherby study  site  after 20 and  44 months as
influenced by depth of burial.
      Depth  of                       	Time (months)	
      burial                             20                44
        (cm)                          	(dS m'1)
                                 	(Increment above drilling fluid)	
                                              (0 to 15 cm)
30
90
90+barrier
150

30
90
90+barrier
150
Mean

90
90+barrier
150

90
90+barrier
150

90
90+barrier
150
19.5
21.1
10.6
14.2
(15 to 30 cm)
4.3
5.2
3.4
2.7
3.9 a*
(30 to 60 cm)
0.7 a
1.0
0.9 a
(60 to 75 cm)
0.4
0.5
0.7
(75 to 90 cm)
0.5
0.5
0.9
23.6
21.0
16.4
20.6

10.0
37.3
8.2
17.4
18.2 b
,
5.7 b
1.6
4.2 b

0.7
0.8
0.8

0.7
0.6
0.7











B
A
B








 Heans within a depth of burial  and row followed by similar lower case
 letters and within an increment  above drilling fluid and colum followed
 by similar upper case  letters  are not  significantly  different  by LSD
 (P<0.05).
                                  463

-------
Table  3.    Average  exchangeable  sodium  percentages  (ESP)   at  five
increments above drilling fluid on the Mertz study site after 20 and 44
months as influenced by depth of  burial.
      Depth of                       	Time  (months)	
       burial                            20                44
        (cm)                           	(%).
                                 	(Increment above drilling fluid)	
                                              (0 to 15 cm)
30
90
90+barrier
150
Mean

30
90
90+barrier
150

90
90+barrier
150

90
90+barrier
150

90 -
90+barrier
150
7
7
1
6
5

0
0
1
1

0
1
2

0
1
1

0
0
1
.1
.1
.9
.6
.7

.6
.9
.1
.8

.8
.5
.0

7T
.3
.8

.5
.7
.2


a"
(15 to 30 cm)

a

a
(30 to 60 cm)



(60 to 75 cm)



(75 to 90 cm)



15
14
4
19
13

0
5
0
6

1
1
1

0
1
2

0
0
1
.4
.9
.9
.1
.6

.7
.1
.9
.9

.1
.2
.9

.5
.5
.1

.6
.7
.0


b

A
b B
A
b B












"Means  within a depth of burial and row  followed by similar lower case
letters and within an increment above drilling fluid and colum followed
by  similar  upper case letters  are  not significantly  different  by LSD
(P<0.05).
                                  464

-------
Table  4.    Average  canopy cover  and  biomass production  of  fcurving
saltbush and buffalograss  transplants 41 months  after planting  on the
Mertz and Weatherby study sites as influenced by depth of drilling fluid
burial.
Depth of
burial
Mertz studv site
Saltbush Buffalograss
Weatherbv studv site
Saltbush Buffalograss
  (cm)

Control
30
90
90+barrier
150

Control
30
90
90+barrier
150
_Canopy cover (%)
22 a"
45 b
64 c
62 c
60 c

1749 a
12822 b
17884 be
18826 be
21501 c
6
10
16
14
20
Biomass
115
101
231
381
372
32 a
76 b
62 b
65 b
67 b
(kK ha'1)
4184 a
16464 b
11450 b
13000 b
12433 b
12
14
24
23
24

301
226
555
345
278
 "Means within  a parameter  and column  followed by  similar lower  case
 letters  are  not  significantly  different  according  to  Duncan's  new
 multiple range  test  (P<0.05).
                                 465

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Table 5.  Concentrations of Na, K,  Ca and Mg in fcurving saltbush and
buffalograss tissue 41 months after planting on the Mertz and Weatherby
study sites as influenced by depth  of drilling fluid burial.
 Depth of
 burial
       Mertz study site
Fourwing saltbush
  Leaf     Stem
                              Buffalograss
	Weatherbv study site	
Fourwing saltbush
  Leaf     Stem   Buffalograss
(cm) (gkg"1)
(Na)
Control
30
90
90+barrier
150

Control
30
90
90+barrier
150

Control
30
90
90+barrier
150

Control
30
90
90+barrier
150
0.02 a*
0.01 a
0.01 a
0.01 a
0.01 a

44.6 a
52.3 ab
61.6 be
60.3 be
63.7 c

36.9 b
23.6 a
22.0 a
19.5 a
22.5 a

6.6
7.1
6.6
6.1
6.4
0
0
0
0
0

12
12
13
13
12

10
5
5
5
4

2
1
1
1
1
.04 b
.02 a
.02 a
.02 a
.02 a

.8
.5
.7
.8
.6

.2
.7
.3
.3
.8

.0
.7
.7
.7
.6
0
0
0
0
0

3
3
3
3
4

7
8
8
8
7

1
1
1
1
1
.03
.05
.04
.04
.04
(K)
.5
.7
.7
.7
.3
(Ca)
.7
.3
.5
.5
.7
(ME)
.3
.3
.4
.1
.2
0
0
0
0
0

45
63
60
59
61

35
21
21
24
20

9
7
8
9
10
.11 ab
.14 b
.09 a
.10 ab
.08 a

.-6 a
.7 b
.5 b
.2 b
.8 b

.3 b
.4 a
.2 a
.7 a
.3 a

.9 c
.5 a
.6 ab
.0 be
.0 c
0
0
0
0
0

16
16
15
18
16

8
5
5
6
5

2
2
2
2
2
.03
.04
.03
.03
.03

.3
.1
.6
.1
.6

.4 c
.2 a
.3 ab
.6 b
.3 ab

.5
.0
.1
.4
.3
0
0
0
0
0

4
3
4
4
4

8
14
11
11
13

1
1
1
1
1
.03 a
.07 b
.05 ab
.05 ab
.04 a

.4
.9
.3
.7
.4

.8
.0
.6
.5
.2

.1
.6
.3
.4
.5
"Means within an element and column followed by similar lower case letters
are not significantly different according to Duncan's new multiple range
test  (P<0.05).
                                466

-------
AN EVALUATION OF THE AREA OF REVIEW REGULATION FOR CLASS II INJECTION WELLS*
Georges Korsun
Senior Economist
The Cadmus Group, Inc.
Waltham, Massachusetts
Matthew Pierce
Research Analyst
The Cadmus Group,  Inc.
Waltham, Massachusetts
Introduction

      As  part  of regulations promulgated under  the  Safe Drinking Water Act of
1974,  as  amended in 1980, the Environmental Protection Agency (EPA) implemented
a program to address  potential  contamination resulting from underground injec-
tion practices  in  the oil  industry.   EPA mandated that owners and operators of
Class  II  injection wells must locate all wells within an  "Area of Review" (AoR)
around each injection well  being permitted.   Class II injection wells are used
in the oil field in conjunction with production wells,  either  for disposal of
produced  water  or  for enhanced  recovery.   Wells within this AoR that represent
potential conduits for contamination of underground sources  of drinking water
(USDW) must be  properly plugged by the owner or  operator.  Although the size of
the AoR conducted theoretically  depends  on reservoir characteristics  and the
potential for  contamination of a USDW,  the  de  facto standard  AoR  radius for
Class  II  wells  is  1/4 mile.

      The EPA  originally proposed regulations requiring  an AoR action for all
Class  II  injection wells,  including those that  existed  prior to the effective
date of the regulation,  April 1982.  Preliminary analyses suggested that this
regulation would impose a significant economic burden on  the oil and gas indus-
try, in contravention of the Safe  Drinking Water Act.   Consequently,  the EPA
modified  the regulation to require an AoR study  only for  those wells that began
injecting after the  establishment  of the  state primacy  program, April 1982.
The rationale for  this modification was that as  existing  fields were developed,
the AoR coverage of new wells  would  eventually encompass  the  AoR coverage of
    *  This research  is  funded in part under Contract  no.  68-C9-0040, Office
of Drinking Water, USEPA.  The  authors  wish to express their gratitude for the
substantial help  provided by the  Texas Railroad Commission,  particularly the
staff of the UIC  section.
                                     467

-------
pre-priinacy wells.   Thus,  in the long run, the  exemption would not materially
reduce the protection of USDWs provided  by the original regulation.

      This paper presents an approach for the evaluation of two characteristics
of the Area  of Review provision, the  exemption of pre-primacy  Class  II wells
from the regulation  and  the  effect  of the size  of the  AoR.   Our objectives  in
this evaluation are  to:

            estimate the  impact  of the  exemption on the  effectiveness  of the
            regulation for a randomly-drawn sample of oil fields in Texas;
            identify  substitute  measures for  predicting this  effectiveness
            using a  less data-intensive  methodology;
            generate  statewide and  national   estimates  of the  impact of the
            exemption, using the  alternative methodology;
            project  the effectiveness  of the regulation over  time;  and
            assess the consequences of changes in the radius  of  the AoR.


Study Sample and Database

      The  AoR  regulations apply  to the surface area  of a  field.   However,
fields are often  stacked so  that several producing zones  (each  called a  field
in  this  paper  and  by the Texas Railroad  Commission)  reside under a  common
surface area.  The appropriate unit of analysis,  therefore, is the  stack.  All
injection wells for  all fields in a stack need to be  considered  together  since
the AoR regulations  apply  to  the  common surface area.  Specifically,  the cor-
rective action sometimes  required under  the regulation may  apply  to  any well
that penetrates production zones around the one being reviewed.   Unfortunately.
records are kept for individual fields rather  than stacks  and there is no easy
way to identify which fields  combine to form a  stack.  Consequently, the  sample
must be drawn  at  the field level and  then enlarged  by other fields that form
stacks with the fields drawn for  the sample.

      At the time we drew our sample, there were approximately 6,500 oil and
gas fields in  Texas with at least  one Class  II  injection well.   Fields that
contained  no  pre-1982 injection  wells  (2,004)  are   irrelevant  to  this  study
(since the exemption under evaluation  is not  applicable for these  fields) and
were excluded from the sampling universe.  An additional 3,035 fields contained
no post-1982 injection wells;  these fields are  relevant  to  this effort  since
they have wells that benefitted  from the exemption.   While they must  be  taken
into account  in estimating the  statewide impact of  the  regulation,  they can
safely be excluded  from  the  sampling universe.  This leaves 1,455  fields with
at least one pre- and post-1982  injection well from which to draw  the sample;
these fields contained 34,787 pre-1982 and 14,410 post-1982 Class II wells.

      From this universe, we  drew a  random sample of  200 fields using an  inven-
tory provided by the Texas  Railroad  Commission  (TRRC).  Twenty five  fields were
eliminated due  to missing  data at the well level (primarily missing  API well
numbers).   The  175 remaining  fields  were  evaluated individually to determine if
they belonged to a stack;  other fields  from the same  formation (generally iden-
tified by  similar names  but  different  producing depths)  were added to the
                                    468

-------
sample.   The final  sample, after  expansion, consisted of 402  fields  in  175
stacks, containing 9,840 Class II wells.

     The  sample was stratified  along three dimensions:  geography, size,  and
type of injection  activity.  Geography was assumed to be an  important stratifi-
cation variable  because  it reflects geologic and historical variables  that  are
important  determinants  of past and future injection activity (e.g., discovery
date, reservoir  depth,  basin).   The geographic units  used for  stratification
were TRRC  districts because no records are kept by oil basin.  Once  fields were
selected,  however, they  were plotted on geologic maps to identify which of  the
seven major Texas basins  they belonged to.   Three  size categories were used,
based on the total number  of injection wells  in each field;  the ranges  were  two
to ten,  11 to 40, and  over 40.   Size was deemed an  important  stratification
variable because it  reflects  the likelihood  of  further injection activity  and
because it influences the  effectiveness measures eventually  selected.   Finally,
the type  of  injection  activity  is  important because  disposal  and  enhanced
recovery imply very  different well-siting patterns.   Disposal wells are often
located on the edges of  fields while secondary recovery  wells  tend to be spaced
regularly  around production wells within the production outline  of the  field.
Exhibit 1  provides details on  the number of fields in the sample by stratifica-
tion category.
                           Exhibit 1:  Sample Stratification
                    2 to 10 wellt
                                           11 to 40 wells
                                                                  > 40 wells
TRRC
DIST
01
02
03
04
05
06
6E
7B
7C
08
«A
OB
10
FIELD NO
SAMPLE DISPOSAL
10
12
20
19
4
11
1
28
12
30
24
24
5
2
0
0
3
0
2
0
7
3
4
3
5
0
BOTH
2
3
4
4
2
3
0
8
3
S
6
e
1
NO NO
ENHANCED DISPOSAL
1
4
e
4
1
1
0
2
1
1
1
1
1
1
0
0
2
0
1
0
3
2
6
3
3
0
BOTH
2
2
6
4
1
4
0
4
2
4
5
4
1
NO NO
ENHANCED DISPOSAL
0
0
1
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
1
1
6
1
1
0
BOTH
1
0
2
2
0
1
1
2
1
9
7
1
1
NO
ENHANCED
0
0
0
0
0
0
0
0
0
0
0
0
0
        200
                 30
                        45
                               23
                                        22
                                              38
                                                               12
                                                                     29
      It is  important  when sampling  to assure  that  the sample  selected is
representative  of the universe.   This turns out  to be largely  true for  this
                                    469

-------
study.  About 71 percent of injection wells in the  1455  fields from which the
sample was  drawn were pre-1982 wells;  about  91 percent of  injection wells  in
these fields were used for secondary recovery.  For the sample, the percentages
were 66 percent and 89 percent, respectively.   Evaluation of the stratification
by  size  suggests  that large  (>40 wells) and  medium (11-40 wells)  fields  are
over-represented, (21 percent in the sample against 13 percent in the universe,
31  percent  in the sample  against 21 percent  in the universe,  respectively).
This bias is not particularly disturbing since small field  effectiveness  mea-
sures are subject to great variations due to  the  small  number  of wells.   It  is
impossible  to  evaluate  the  geographic  representation of  fields since  there
exists no central source for  the distribution of fields by  basin for the  uni-
verse .

      Once  the  fields were selected,  we used  the  TRRC Underground  Injection
Control data  tape  to create a well-level database  with each  injection well's
API number.   Other elements  of  this database are  the  type of  injection, the
date  of permit  approval,  the  operator and lease identifiers,  and location and
survey data.  Latitude and longitude data for  each well  were  obtained separate-
ly  from a commercial  vendor  and merged with the well-level  database.  Because
we  use  computerized  mapping  to  permit the  evaluation of  our large sample,
accurate location data is critical to  this study.   We  relied on matching API
well  numbers; this procedure  was successful for 86  percent of  the 9,840 wells
in  our  sample.   For some  of  the remaining wells,  it was  possible to compute
latitude and longitude by using survey,  block,  and section  location data off of
the UIC data tape.   This was not feasible in all cases;  consequently  the effec-
tiveness measures  for some field  will  incorporate  a bias.   The direction of
this bias will  depend  on whether the missing  location data applies to pre- or
post  1982 wells.

      A second,  stack-level database was also  created for the regression analy-
sis discussed later.   Details about the  variables  of this database are present-
ed  in a subsequent section.


Measures of Effectiveness

      The ideal method for evaluating  the  implication  of  the  exemption is to
compare well counts for the pre-  and post-82 AoR's in each  field in the sample.
Then, it  is possible  to assess  directly  the number  of  wells  that would be
excluded from  review  and  estimate the  scope  of the  potential  contamination
problem.   However,  data  on  well  counts  are  unobtainable except through the
conduct of  AoRs;  this is clearly  not  feasible for this study and some proxy
measure of  effectiveness must  be devised.   In  this  paper,  we consider two
measures of surface area as  our  proxies,  overlap and percentage  of production
outline covered.

      By its nature,  AoR is a  surface area concept.  While  the  effectiveness of
the regulation  depends on both its design  and its  implementation, we concern
ourselves here  only with the  former.   This means that  we  can approximate the
coverage of the  regulation for a particular  field  by estimating how much of the
pre-1982 well AoRs area  has  or will be covered by  the  AoR areas of  injection
wells permitted after  April 1982.   This  is our first  measure,  which we term


                                     470

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"overlap".  Formally, it is the ratio of the intersection of pre- and post-1982
AoR areas to the pre-1982 AoR area:
                        intersection of pre- and post-1982 AoR areas
     Overlap —          	
                                     pre-1982 AoR area

     The higher  the ratio,  the greater the  degree of  coverage  by post-1982
wells and  the lower  the "cost"  of  the exemption  of pre-1982 wells  from the
regulation  for  any particular field.   Overlap is only an indirect measure of
this  cost  in the  sense that  it is  not readily convertible  to  a  measure of
potential risk to USDWs.  With additional assumptions and  information about the
relationship  between field  and  operator characteristics and the presence of
abandoned  wells,  this  overlap percentage  could be  used for a more  explicit
assessment  of contamination risk.

     A  second, more general, measure of the-effectiveness of the AoR regula-
tion  is  the percentage  of the surface area  of  the  field  covered by the AoR of
post-1982  injection wells.   Unfortunately,   the surface area of  a  field is not
readily  available.    Moreover,  since  the unit of  analysis is the  stack,  the
surface  area  over  the stack must be  computed as  the  union of the  areas of all
fields in  the stack.  This  measure  is impossible to obtain.  We use instead an
approximation of the production  outline of  the stack as the base surface area.
This  approximation is generated  by  first imposing the well spacing guideline
for the  field on  each plotted injection well and taking  the outer envelope of
the areas  around all wells  in the stack. The area  of the resulting polygon is
then calculated and  used as the base  surface  area.   Formally, the "coverage
area" is:

                         area of post-1982 AoRs
     Coverage Area -
                        area of production outline

      Both measures  are obtained for each stack  in  the  sample using Atlas CIS
software.   To compute overlap,  the program first plots each pre-primacy well in
a stack,  using latitude and longitude coordinates obtained from the database.
It then draws the AoR radius around each well and calculates the sum of the AoR
areas.   This is recorded as  the denominator of the overlap measure.   It then
plots all the  post-primacy wells permitted  in  1982, draws  the appropriate AoR
radius around each, and  identifies the intersection of the pre- and post-prima-
cy polygons.  This area is  the numerator of the overlap measure for 1982.  The
program repeats  this procedure for  each  year that injection wells were permit-
ted in this stack.  The  outcome  is an annual cumulative overlap measure for the
period April 1982 to April  1990. An illustration of the overlap measure for a
field in  the sample  is  presented on the  next page as Exhibit 2.   To   compute
coverage  area,   the  program  first  plots  all  injection  wells, defines  areas
around each well based on  well spacing  rules,  and  defines  a polygon  whose
perimeter is the outer  boundary of the areas  around  all wells.   This  is the
area of the production outline,  the denominator of this measure.  It then draws
the appropriate  AoR  radius  around post-primacy wells and computes the area of
                                     471

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Goldsmith
  35652
overlap

post-primacy
                                                HI   pre-primacy
                                                    AREAS (sq mi.)
                                                    Pre = 64.1225
                                                    Post = 20.7522
                                                 Intersection = 17.4574
                                                   Overlap = 27.23%

                                                    No. of Disposal
                                                  Pre = 7  Post = 3
                                                No. of Enhanced Recovery
                                                 Pre = 851  Post = 180
                                                    Total =  1,041
                                                                        ft
                                                                        to
                    o
                    t->
                    PI
                    rt
                    (-••
                    o

-------
this polygon.  This  is recorded as the numerator of the coverage area measure
and it can also be computed cumulatively.

     With this  database  and software,  it is relatively easy  to  assess  the
impact of changes  in the AoR radius.  In  this  paper,  we consider the standard
1/4 mile radius and  an alternative 1/2 mile radius.


Cross-sectional Study  of the Determinants  of Overlap

     The methodology  developed and discussed  above represents a considerable
improvement over manual plotting and paper map evaluations.  It could easily be
extended from  our  sample of Texas fields  to  include a representative national
population except  for  data availability and  acquisition costs.   Well-specific
latitude and longitude data, for example,  are  prohibitively expensive if they
are available at all.  In this section, we discuss the use of regression analy-
sis  to  identify predictive measures  of  overlap  that could provide  national
estimates without  the  expense of collecting well-specific data.

     Regression  analysis  attempts  to  explain  the variance  in a  dependent
variable by attaching weights to independent or explanatory variables.  In this
application, the  dependent  variable  is the  overlap measure presented  above.
The  explanatory variables are stack-specific characteristics that  are consid-
ered, a priori,  to  have potential for affecting the dependent variable.   In
general, these might be categorized as geologic, productive, and institutional.
Because  this  is  a cross-sectional study  (in which  we attempt to  account for
differences  across stacks),  we take  only  the  cumulative overlap as  of  April
1990 as our dependent  variable.  We can also ignore explanatory variables that
would affect overlap over time;  these are largely economic  in  nature  (such as
oil prices).  They are treated in  the  next section.

     Geologic variables reflect the relationship between reservoir character-
istics and the likelihood of undertaking secondary recovery or disposal activi-
ties.   These might include reservoir porosity, permeability, and depth.   Pro-
ductive variables  attempt to explain  differences in overlap across  fields on
the basis  of industry behavior.   These might include the  discovery  date, the
ratio of pre- to post-Lprimacy wells, the ratio of disposal to enhanced recovery
wells, and the number  of operators working the  stack.   Institutional variables
account for the impact of regulations;  typical  of these  are well spacing rules
that  govern the  minimum  distance between production  wells  and  unitization
rules.

     To conduct this analysis, we created a separate stack-level database that
consisted of the overlap measure  previously calculated  for  each  stack and the
independent variables  listed above.   This database  is used to  regress overlap
on the  set of  explanatory variables,  using ordinary least  squares  (OLS)  tech-
niques.  The procedure yields a series of  weights to be  attached to each inde-
pendent variable, along with statistics on the  "goodness of fit"  of the  entire
model and  the  statistical  significance  of each  variable.   Preliminary  tests
with a  small subsample of Texas  fields suggest that there  is a high  degree of
fit of the model and that well spacing, the age of the field, and the  ratio of
disposal to enhanced recovery wells are significant explanatory variables.  If


                                   473

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this finding  obtains  with the full  sample,  it implies  that  reliable national
estimates of current overlap could be  obtained without expensive well-location
data.


Longitudinal Study of the Determinants of  Overlap

      The AoR  concept  is dynamic,  meaning that it is intended  to  achieve  its
goals  over  time.   The  cross-sectional  analysis  discussed  above  is  static,
meaning that  it  attempts to  explain  overlap  at a single point  in time.   While
the  latter  is useful  for identifying certain predictors  of overlap, a true
evaluation of the effectiveness of AoR should consider what is likely to happen
in the future.

      To address  this  issue  we add four  economic variables to  the  stack-level
database discussed  in  the previous  section.   These new explanatory  variables
treat the price  of  oil,  the  tax policy affecting oil production, and the type
of operator working the  stack.

      It is safe to assume that operators respond to price changes  in deter-
mining the rate  of  oil extraction;  one way  in which they may vary production
levels  is  through  secondary  recovery.   Therefore one would  expect that oil
prices would  affect overlap over  time.   In reality, however,  there is a lag
between price  changes  and production changes,  so the proper  independent vari-
able to use is lagged  prices.   A second  way in which oil prices  may  influence
the  decision  to  undertake secondary recovery  reflects  the uncertainty about
future prices.   When prices  fluctuate  a  great deal in a short  time,  operators
will be  less  certain about  their  future price expectations  and will be more
hesitant to invest  in  additional production.   To proxy this uncertainty about
future prices, we use the variance  in prices  over three  and  five year  horizons.
The extant tax policy is another important  economic^determinant of the level of
investment by  oil and  gas firms.   Since  the  1970's, a number of  provisions of
the  tax code  directly affecting these firms have  been eliminated or modified
(e.g., the windfall profits tax,  the  oil depletion  allowance, corporate tax
rates).  To account for  the  potential  impact of these tax rules, we  use dummy
variables to  indicate  their  presence over  time.  Finally, the  characteristics
of the operator should be helpful in  predicting secondary recovery activity and
thus  the  development of overlap over time.   Different  firms have  different
capital constraints and capital costs;  different firms also  have varying levels
of technological sophistication and available engineering resources.   Since
these factors will all influence the timing of  secondary recovery projects,  it
is important to consider  them  in this longitudinal model.  We  greatly simplify
these operator characteristics by  classifying  firms into one of  three catego-
ries, major,  independent,  and  minor, on the assumption that  firms of similar
size will behave similarly with respect to the  factors just discussed.

      Aside from  these additions to  the  set  of explanatory variables, we must
also consider a different dependent variable  for the longitudinal analysis, the
annual change  in  overlap for each  stack.   Because  a single incremental change
in overlap measure for the sample (such as a weighted average)  is meaningless,
we have to resort to a panel data analysis (which combines cross-sectional and
longitudinal data).  The database  now  consists of  nine observations  per  stack


                                     474

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(one for  each year of  the  1982-1990 sample period).   The objectives  of this
analysis are essentially the same as those of the pure cross-sectional analysis
although the  choice of  method and test statistics will differ.   We still look
to  identify  those variables that are  significant in explaining  the  growth in
overlap through time.

     The last  step  of the analysis  is  to estimate overlap  for  several years
into the future.  This requires the adoption of a scenario for each significant
variable identified by  the  econometric work briefly discussed in this section.
If, for example, lagged oil prices are significant predictors of overlap chang-
es,  an assumption about  a future  oil  price path  will  have  to  be made.   By
combining likely  scenarios for  all the  significant explanatory variables,  a
range  of  probable outcomes for future overlap can be generated  and the "cost"
of the exemption  of pre-1982 wells  derived.
                                      475

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References

1.    Drollas, L.P., "The Search for Oil in the USA: An  Econometric Approach",
      Energy Economics.  July 1986, pp 155-164.

2.    Galloway, W.E. ,  I.E.  Ewing,  C.M.  Garrett,  N.  Tyler,  and D.G. Bebout,
      Atlas of Major Texas Oil Reservoirs. Bureau  of Economic Geology, Univer-
      sity of Texas, Austin, Texas, 1983.

3.    Railroad Commission of  Texas, 1988  Oil and Gas Annual Report. Austin,
      Texas, 1989.

4.    Rice, P. and  V.K.  Smith,  "An Econometric Model  of the Petroleum Indus-
      try", Journal of Econometrics. 6, (1977), pp 263-287.

5.    Schmidt, R.H., "The Effect of Price  Expectations on Drilling Activity",
      Economic Review.  November 1984, pp 1-8.

6.    United States General Accounting Office,  Drinking  Water:  Safeguards Are
      Not Preventing Contamination From Injected Oil and Gas Wastes,  GAO/RCED-
      89-97, Washington, DC, July 1989.
                                     476

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EVALUATION OF 'THE GROUNDWATER CONTAMINATION POTENTIAL OF ABANDONED
WELLS BY NUMERICAL MODELING
D.  Warner
Dean,  School  of Mines & Metallurgy and Professor, Geological  Engr.
University  of Missouri-Rolla
Rolla, MO 65401
C. McConnell
Associate Professor,  Geological Engineering
University of Missouri-Rolla
Rolla,  MO 65401
ABSTRACT

A detailed study has been made of the characteristics of abandoned oil and gas
wells in  the  Lower Tuscaloosa Sand  trend of Mississippi and  Louisiana and
their potential  as conduits  for movement  of saline water from  the  Lower
Tuscaloosa into underground sources of drinking water (USDW's).

The study included  correlation of the stratigraphic units throughout the Lower
Tuscaloosa trend; documentation of the engineering  characteristics of geologic
units and of abandoned wells  in the trend and estimation of the  thickness,
porosity and permeability  of drilling mud  and sloughed shale  in  abandoned
wells in the  trend.    Also,  although  breach of  casing  by  corrosion  is
considered unlikely in this region, the location of the stratigraphic interval
most susceptible to corrosion was established.

After assembly of the data listed above, finite difference numerical modeling
was performed to  determine  the extent  to which water might be forced from the
Lower Tuscaloosa Sand into  an USDW as a result of  injection into  the Lower
Tuscaloosa.  Within the range of conditions that were modeled, water from the
Lower Tuscaloosa was found  never  to travel into  an USDW.   These  conditions
included the  two scenarios of  an  abandoned uncased  well  with a  column of
settled  sloughed shale and settled mud solids in the borehole and of a cased
well with corrosion of casing in the lower Wilcox Formation and with sloughed
shale and settled mud solids in the casing-tubing annulus.

The procedures developed in this  study should be  readily applicable  to the
analysis  of  the  potential  for abandoned  wells  to  act   as  pathways  for
contaminant flow into  USDW's in other oil and gas producing areas  of the
country.
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INTRODUCTION
Purpose and Scope of Study

Because of increasing focus by regulatory agencies upon abandoned oil and gas
wells, the University of Missouri-Rolla has  conducted research for assessment
of  the  potential  for  abandoned  oil  and gas  industry  wells  in  the  Lower
Tuscaloosa Sand oil  producing trend of Mississippi  and Louisiana  to act as
conduits  for flow  of  saline water  from  the  Lower  Tuscaloosa  Sand  into
underground sources of drinking water.

The locations of selected wells from oil fields in the Lower Tuscaloosa Sand
trend are shown in Fig. 1.  As can be determined from the lines of the cross
sections formed by the wells  (see footnote), the Lower Tuscaloosa Sand trend
extends for about 135 miles from south-central Mississippi northwestward into
eastern Louisiana and for about 100 miles from north to  south.

The study included the assembly of the geologic and engineering data necessary
to formulate numerical models  that would allow simulation of the range of flow
conditions through abandoned wells in the Lower Tuscaloosa trend.  The final
step in the study was the actual numerical simulation of flow conditions for
such abandoned wells.
Previous Work

The first numerical  modeling  work known to the authors with  respect  to the
movement of fluids through an  abandoned well was that carried out by Ward, et
al.(2)  in which the leakage  of  injected contaminants through  an  abandoned
unplugged borehole was  modeled.   The problem here is  different, in that it
involves tracking of the movement of native saline water from a saline-water
bearing  aquifer into a nearby  abandoned well  in response to  the  pressure
created by an injection well.

Warner(3) modeled the response of  a  specific  existing  abandoned well in the
West Mallalieu  oilfield to injection through a nearby water-injection well.
An analytical model of the abandoned well problem was developed by Javendel,
et al.(4)
STATEMENT OF THE ABANDONED WELL PROBLEM

Many thousands of wells have been  drilled  and  abandoned during the 130 year
history  of  the U.S. petroleum industry.   Regulations for plugging  of such
wells were  nonexistent  in the  early days of the  industry and have evolved,
over the years, to their present effective level.  Thus an unknown but large
number of abandoned wells exist that may be unplugged or inadequately plugged
by today's  standards.
The cross sections are not contained in this paper but are available  in
Ref. 1.
                                  478

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As a result  of  incidents in which abandoned wells have  been implicated as
sources of  ground  water contamination,  such wells  are  often  considered,
without discrimination among them,  to be potential pathways for contamination
of an underground  source of drinking water  (USDW).   Such contamination can
result from interaquifer flow of natural  formation water or by transmission
of injected fluids from the injection reservoir to  an USDW.

In fact, the  relative contamination potential of such wells ranges from highly
likely to impossible,  depending on a complex set of  well factors and geologic
and hydrologic  circumstances.   The  relative contamination potential  of an
abandoned veil or wells  in  a particular  geologic  and  hydrologic setting can
be first analyzed qualitatively by an understanding of the factors involved.
Warner(5) has listed  and discussed, at length, those factors which include
well  age,  well  depth,  well  type,  well  construction,  well plugging  and
abandonment history and the hydrogeologic conditions at the well site.

In instances where an abandoned well does have possible pathways through which
natural brines  or  injected fluids  could  migrate  to USDW's  and  where  the
hydrogeology is  also  amenable  to  such interaquifer flow,  then quantitative
analysis with numerical  computer models  may be  a  useful means of predicting
whether  or not  such  interaquifer  flow  is  likely to  occur.   This  report
documents  the processes  of both qualitative  and  quantitative evaluation of
abandoned oil and gas wells in the Lower Tuscaloosa trend of Mississippi and
Louisiana.
 GENERAL DESCRIPTION OF NUMERICAL MODEL

 Modeling  for this  research project  was  carried  out using  the  SWIFT III
 numerical  code.   SWIFT 111(6)  is  a revised and improved version  of a code
 originally developed for the U.S. Geological Survey specifically for injection
 well  modeling.    SWIFT  III is  the result  of more than  10 years  of model
 evolution.   The original model acronym,  SWIP, stood  for  (U.S.  Geological)
 Survey  Waste Injection  Program.    SWIFT  is  the  acronym for  Sandia Waste-
 Isolation  Flow and Transport Model.  The original documentation for SWIP was
 presented  by Intercomp(7).   This was followed  by  SWIPR(8), SWIFT(9). SWIFT
 11(10,11)  and SWIFT 111(6).

 The  SWIFT code  is  a fully transient,  three-dimensional  finite difference
 numerical  code  that  solves the coupled equations  for  fluid flow,  transport
 of chemicals that do not decay  radioactively, transport of radionuclides and
 heat  transport.   According  to  Prickett,  et ai.(12) the SWIP (or SWIFT) type
 models  represent the  latest  in  such  numerical  models and  are  the most
 comprehensive ones available.
 GEOLOGY AND  PETROLEUM  PRODUCTION  IN  THE  LOWER  TUSCALOOSA TREND

 Fig.  2 depicts a  generalized  stratigraphic column of  the Mallalieu Field,
 Lincoln County,  Mississippi.   Strata shown in Fig. 2  range in age from the
 Cretaceous Lower Tuscaloosa Sand  at  the  base to the Eocene  Cook Mountain and
                                     479

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Sparta Sand  units at  the  top of  the  column.   At the Mallalieu Field and
elsewhere in southern  Mississippi and in southeastern  Louisiana, strata of
Oligocene through Holocene age overlie the Cook Mountain  and  Sparta.

The only geologic unit that has produced oil or gas in the study area is the.
Lower Tuscaloosa Sand.   This fact is of great practical importance, since it
means that there are no younger  and  shallower or deeper and older producing
units in  the many Lower Tuscaloosa  fields  into which oil  or gas producing
wells have been drilled and abandoned.   This fact considerably  limits the
possibilities of interaquifer flow through abandoned  wells,  since it is not
necessary to be concerned  about  any significant number of  such wells other
than those specifically drilled to the Lower Tuscaloosa Sand.

The  fact  that   the  Lower Tuscaloosa  is  the  only producing  formation  also
restricts  the   manner   in  which  wells  have  been drilled,  completed  and
abandoned.   Lower Tuscaloosa oil production  began in the early  1940's and
fields are now  in the very late stages of petroleum recovery.   The Mallalieu
and Little Creek fields are, for example, undergoing tertiary  oil recovery
by  injection of carbon dioxide.    Because  drilling in the  Lower  Tuscaloosa
trend did not  start  until  the 1940's the technology and  regulation  of  well
construction and abandonment had  already advanced  considerably  over  that
practiced in the early 1900's.  The actual practices used will be covered in
the next section.                                               —

Cross sections  that were developed for the study(l) show  correlation of the
strata throughout the Lower Tuscaloosa  oil producing trend.  While all of the
geologic units  of interest are different in thickness and in lithologic detail
in any one of the oilfields for which a log is shown, the section as it occurs
in  the Mallalieu Field is  as representative as any that  could  be selected.
Therefore, the  stratigraphic section for the Mallalieu  Field, as shown in Fig.
2, was selected for modeling purposes.
Uncased Well Scenario

The  conditions  of  the  uncased well  scenario are  shown in  Fig.  3.   This
scenario is very  straightforward  in that surface casing has  been typically
set  to  about  1,400 - 1,500  ft  [427   457 m]  of depth and cemented to the
surface.  The remainder of the hole  needed to reach the Lower Tuscaloosa Sand
is left open until the Lower Tuscaloosa has been reached and its thickness and
production capability assessed.  If the Lower Tuscaloosa Sand is present and
sufficiently thick and  promising  of production,  the well is  cased.   If the
Lower  Tuscaloosa  Sand  is  missing  or   thin  or  otherwise  likely  to  be
uneconomically productive, the well  is plugged and abandoned with the drilling
mud  in the hole and with no casing other than the surface casing.   Many such
abandoned wells do contain cement plugs.   However,  in the worst case, a well
might not contain anything other than drilling mud upon abandonment.  That was
the  scenario selected to be modeled.
                                     480

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Cased Well Scenario

When a Lower  Tuscaloosa Sand well  is drilled and  the  sand is  found to be
present and judged  likely  to be sufficiently productive,  the  well is cased
with production casing through the Lower  Tuscaloosa  (Fig. 4).  The production
casing is cemented at the bottom with about 2,000 ft [610 m] of cement.  The
remainder of the annulus behind the production casing is left mud  filled.

Of course, if the casing were to remain  intact,  there  is no possible threat
to groundwater  resources.   It  is possible,  however, that  the  casing could
become corroded to  the extent  that  it would be  breached and a  pathway to
formations behind the casing would exist.   If corrosion were to occur, it was
judged most likely  to be  in the lower portion of the Wilcox  Sand(13) where
injection of brines  could render the water more corrosive.  An arbitrary depth
of 6,000 ft [1830 m] was selected as the possible location of such a corroded
interval of casing.
WELLBORE PROPERTIES OF SETTLED MUD SOLIDS AND FORMATION MATERIALS

Through procedures described in Ref. 1, it was calculated that, in the uncased
well  scenario,  a 154.5 ft  [47  m] thick  column  of sloughed shale  would  be
present at the  bottom  of  the hole and that would  be overlain by  a  4,620  ft
 [1409 m] column of settled mud solids  (Fig.  3).  The porosity of the sloughed
shale column  was assumed to  be  that  of  the  in-place  material  or  3%.   The
permeability of the sloughed shale was assumed to be 0.1 md.  The porosity of
the settled mud  solids column was assumed to be  84%  and  its permeability  to
be 1.0 md.  The rationale for those values  is contained in Ref. 1.

In the cased well scenario, a cement sheath extended from bottom hole to 8,500
ft [2591 m].  A  sloughed  shale column 200 ft [61 m]  thick was  calculated  to
be present on top of  the  cement  and a settled mud column 3,740  ft  [1140  m]
thick on  top  of  the sloughed shale (Fig.  4).   The  sloughed shale  and mud
solids were assumed to have the  porosity and permeability values given above
for the uncased well scenario.
MODELING OF TWO REGIONAL SCENARIOS
Uncased Well Scenario

A three.dimensional 47 node x 20 node x 10 layer model grid was designed for
simulation of  the  uncased well scenario.   Because the geologic  units  were
treated as if  they were homogeneous and infinite  in  areal  extent,  the  flow
field was symmetric and only half  of the grid was present in the Y dimension.
The  injection  well and the abandoned  well  were located 500  feet apart and
roughly centered along  the X boundary.  The X-Y extent  of  the grid was  10 x.
105 by 9 x 105 ft  [3 x  10s by 2.7 x 105 m] and  was established by trial and
error to be large enough so that no significant boundary effects would occur
during the 10-year modeling period.
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The 10 model layers used in the vertical or Z dimension are shown  in Fig. 3.
Table 1 lists the values for the model parameters used  in simulation runs for
the uncased abandoned well scenario.

Representative simulation results for the Uncased Well Scenario are shown in
Table 2.  Table  2 lists the AP at the bottom of  the injection well (bottom
hole pressure or  BHP),  the AP  at  the bottom of  the abandoned well, the rate
of flow of saline water  into the  ground  water  zone (USDW),  the rate of flow
into the abandoned well and the rate of flow into  the  Upper Tuscaloosa.

To  study  the effect  of the maximum  likely injection  rate  on flow up the
abandoned well and  into the upper Tuscaloosa the  simulation  of  Table  2 was
performed  with  an  injection  rate  of  600 bbl/d  and an  injection  zone
permeability of 30 md.   The  simulation showed no  flow  into  the USDW zone at
the 600 bbl/d injection rate.  Flow rates of less than 10"2  bbl/d should be
considered so small as to be highly  inaccurate.  For practical purposes, such
rates indicate that no measurable flow is occurring.
Cased Well Scenario

A three dimensional 48 node x 22 node x 12 layer model grid was designed for
simulation  of the cased  well scenario.   Because  the  geologic units  were
treated as if they were homogeneous, isotropic and infinite in areal extent,
the flow field was symmetric and only the upper half of the grid was present
in the Y dimension.  The injection well and the abandoned well were ,500 feet
apart and roughly centered along the X boundary.  The X-Y extent of the grid
was 3.4 x 105 by 2.1  x 105  ft  [1  x  105 by 6.4 x 10* m] and was established by
trial and error  to be large enough so that no  significant boundary effects
would occur during the 10-year modeling period.

The 12 model layers used in the vertical or Z dimension are shown in Fig.  4.
The layers were  selected to discriminate  the  hydrogeologic units and,  also,
the cement, the  sloughed shale and the settled  mud layers behind the casing
and the interval of corroded casing.  Table 3 lists the values for the model
parameters used  in simulation runs for the cased abandoned well  scenario.

Representative simulation  results  for the Cased Well Scenario  are shown in
Table 4.   The  flow  of saline  water vertically  from the Wilcox  Formation
through the Winona Shale and  Cane  River Marl  and  into the USDW was zero for
all simulations.

As in the uncased well scenario,  flow rates of less than 10~2 bbl/d should be
considered highly  inaccurate.   For practical purposes,  such rates indicate
that no measurable flow is occurring.
                                     482

-------
CONCLUSIONS

On the basis of the modeling  that  was  performed,  it is concluded that it is
very unlikely that conditions would ever exist in the Lower Tuscaloosa trend
of Mississippi and Louisiana  where abandoned oil and  gas  wells would serve
as conduits for movement of water  from the Lower Tuscaloosa  into  an USDW.
In the scenario of the uncased well, essentially  no water was found to move
vertically through the  sloughed  shale-settled mud  column  and no measurable
amount of that which  did penetrate  the  settled mud column reached the Sparta,
which is the USDW in the Mallalieu Field area.   In  the cased well scenario,
essentially no water moved through the settled mud sheath  into  the Wilcox
Formation  and none  of that  water which did  flow into  the  Wilcox  moved
vertically through the Wilcox and the Winona-Cane River into  the Sparta.

The procedures developed  in this study should be readily  applicable to the
analysis  of  the  potential  for abandoned wells  to  act as  pathways  for
contaminant flow  into USDW's in other oil and  gas producing  areas  of the
country.  Modeling is considered  to be a very powerful tool for classification
of abandoned wells.  While  such  modeling is not a trivial exercise,  and the
necessary  data are  not  routinely  available,  the information  produced can
return  the necessary investment  many fold by diverting concern where  it is
unwarranted and, thus, avoiding  unnecessary regulatory effort.
 ACKNOWLEDGEMENTS

 The authors thank the American Petroleum Institute for its financial support
 for the research documented in the paper.  Shell Oil Company commissioned the
 stratigraphic study of the Lower Tuscaloosa  Trend  as a separate but essential
 part of the project.  B.E. Esquinance, Shell Offshore Inc. , developed the well
 scenarios  described herein.   Nina K.  Springer,  Exxon  Production  Research
 Company,  developed the  methodology for  estimating  the  characteristics  of
 settled mud and sloughed shale in abandoned  wells, as used in the study.  Ms.
 Springer also chaired the API Control Issues Group that provided oversight of
 the  study.   We express our  appreciation  to  that  group  for  its  helpful
 suggestions and input to the  study.
                                       483

-------
REFERENCES

1.  D. Warner and C. McConnell, "Abandoned Oil and Gas Industry Wells - A Quantitative Assessment of their
    Environmental Implications", A Final Report to the American Petroleum Institute, Washington, D.C., Nov.
    1989, In Press, American Petroleum  Institute,  Washington, D.C.

2.  D. Ward, D.  Buss and J.  Mercer, "A Numerical  Evaluation of  Class  I Injection Wells for Waste
    Confinement Performance", Final Report Prepared for the U.S.  EPA Office of Drinking Water,  Underground
    Injection Control Program,  1987, 2  Vols.

3.  D. Warner,  "Response of  Abandoned Well 9-6A  to  Injection Through  Well 9-6, West Mallalieu Field,
    Mississippi", in Appendix  1 of Ref.  1.

4.  I. Javendel, C.  Tsang, P.  Witherspoon and D.  Morganwalp,  "Hydrologic Detection of Abandoned Wells
    Near Proposed Injection Wells for Hazardous Waste Disposal", Water  Resources  Research,  1988, Vol. 24,
    No. 2, p. 261-270.

5.  D. Warner,  "Abandoned Oil and Gas Industry Wells  and their Environmental Implications",  in  Proceedings
    of the Summer Meeting Underground  Injection Practices Council,  UIPC,  Oklahoma City, OK, 1988, p. 69-
    90 (included as Appendix 2  in Ref.  1)

6.  D. Ward, "Modifications to Reeves,  et  al,  1986", Geotrans, Inc., Herndon, VA,  1987.

7.  Intercomp,  "A model for Calculating Effects of Liquid Waste Disposal in  Deep Saline Aquifer", USGS WRI
    76-61, 1976.

8.  Intera,  "Revision of the  Documentation for a  Model for Calculating Effects of Liquid Waste Disposal
    in Deep Saline Aquifers", USGS WRI  79-96,  1979.

9.  R. Cranwell and M.  Reeves "User's Manual  for  the Sandia Waste-Isolation Flow and Transport Model
    (SWIFT)", Release 4.81, NUREG/CR-2324, SAND81/2516, Sandia National Laboratories, Albuquerque, NM, 1981.

10. M. Reeves,  D. Ward,  N. Johns  and R. Cranwell, "Theory and  Implementation for  SWIFT II,  The Sandia
    Waste-Isolation Flow and  Transport  Model  for  Fractured Media",  Release 4.84,  NUREG/CR-3328, SAND83-
    1159, Sandia National Laboratories, Albuquerque, NM,  1986.

11. M. Reeves,  D. Ward, N. Johns and R.  Cranwell,  "Data Input Guide for SWIFT II,  the Sandia Waste-Isolation
    Flow and Transport Model  for  Fractured Media", Release 4.84,  NUREG/CR-3162, SAND83-0242,  Sandia
    National Laboratories, Albuquerque, NM, 1986a.

12. T. Prickett, D.  Warner and D.  Runnells,  "Application of Flow,  Mass Transport  and Chemical Reaction
    Modeling to Subsurface Liquid Injection",  iri  Proceedings of the International Symposium on Subsurface
    Injection of Liquid  Wastes, National Water Well Assoc., Dublin, OH, 1986, p. 447-463.

13. T. Michie,  Michie and Assoc.,  Inc.,  New Orleans,  Louisiana, personal communication to B.E. Esquinance,
    Shell Offshore, Inc.. 1988.


SI METRIC CONVERSION FACTORS
         bbl  x  1.589 873   E-01 - m3
         psi  x  6.894 757   E+00 •= kPa
                                                          484

-------
               Table 1.  Model Parameters -  Uncased Abandoned Well  Scenario
Model
Layer

  1
  2
  3
  4
  5
  6
  7
  8
  9
  10
           Permeability (K., = K]C/101
    1 darcy
    2.5 x 1CT8 darcy
    1 darcy
    1 darcy
      darcy
     .5 x 10"8 darcy
     .1 darcy
    2.5 x 1CT8 darcy
    2.5 x 1CT8 darcy
    2 md or 30 md
1
2.
0.
    Porosity

         35%
         3%
         30%
         30%
         30%
         3%
         23%
         3%
         3%
         25%
Permeability

drilling mud
sloughed shale
empty borehole

Other Parameters

water compressibility
rock compressibility
fluid specific weight
viscosity
                   Porosity

          1 md
          0.1 md
          3.7 x 108 darcies
                        (109 ft/day)
        84%

       100%
                                  [-1
                       3  x  10'6 psi
                       5.5  x  10'6 psi'1
                       67.3 lb/ft3
                       1  cp
        Table 2 - Listing of pressure  buildups and flows, with time,
      for an injection rate of  600 bbd/day and a Lower Tuscaloosa Sand
           permeability of 30 md, uncased abandoned well scenario
   Time
Jsince inj. AP (BHP)
   began1)   inl veil
 .01 d
 .1
 1.0
 10.0
 100.0
 1000.0
 2000.0
 3650.0
AP(bottom)
 abd veil
        Q(into)
         USDU
Q(into)
  upper
Tuscaloosa
252
332
399
488
559
640
664
684
psi
.6
.5
.7
.5
.1
.4
.9
0
0.
6.
63.
130.
211.
235.
256.
psi
1
9
2
3
5
8
3
0 bbl/d
0
0
0
0
0
0
0


1
6
3
6
8
1


.67
.6
.0
.6
.3
.0
0
0
x
x
X
X
X
X
bbl/d

ID"7
10'6
ID'5
io-5
ID'5
10'*


9
1
2
6
8
1
0
0
.9 x
.6 x
.0 x
.0 x
.1 x
.1 x
bbl/d

lO'11
10'8
ID'7
io-7
ID'7
10'6
                                       485

-------
         Table 3 - Model Parameters,  cased abandoned well scenario.
                           Lower Tuscaloosa .Trend
Model Layer

  1
  2
  3
  4
  5
  6
  7
  8
  9
  10
  11
  12
Permeability
                          k.)
            1
          .5 x
            darcy
            10~8 darcy
          1 darcy
          1 darcy
          1 darcy
          1 darcy
          1 darcy
          1 darcy
              -8
        2.5 x lO'8  darcy
          0.1
        2.5 x
            darcy
            10~8  darcy
          2 or 30 md
   Porosity

      35%
       3%
      30%
      30%
      30%
      30%
      30%
      20%
      3%
      23%
      3%
      25%
drilling mud
empty borehole

Other Parameters
1 md
  3.7 x
      108 darcies (109  ft/day)
water compressibility
rock compressibility
fluid specific weight
viscosity
                        3.6
                        5.5
                        67.3 lb/ft3
                        1 cp
                            ID'6  psi
                                    -i
        Table 4 - Listing of pressure buildups and flows, with time,
      for an injection rate of 200 bbl/day and a Lower Tuscaloosa Sand
            permeability of 30 md, cased abandoned well scenario
  Time
(since inj.
  began)

.01 d
.1
1.0
10.0
100.0
1000.0
2000.0
3650.0
       AP (BHP)
       in1 well

        44.7 psi
        70.4
        84.5
       115.8
       132.9
       149.5
       154.6
       158.4
                             Q into abandoned well

                                      0 bbl/d
                                      0
                                  1.6 x 10'5
                                      x 10-*
3.7
7.8 x 10'
1.2 x 10
1.4 x 10'3
1.5 x 10~3
                                          -3
                                       486

-------
                     CROSS SECTIONS
                    LOWER TUSCALOOSA
                         TREND
                           MALLALIEU
                           FIELD
Fig. 1 - Map showing location of wells
used in Lower Tuscaloosa Trend study.

-------
2JOOO •
jpotf •
BASE USDW

4.0001 •
MOtf •
6.OO0 .
7.000'
ecoo' •

9P001 •
IQOOCr
II.OOO1 -

3100'









•fev^T-r^-'-
— — — -" — -^
"7^-^r
'r^Tritll'
~^ — ~^=
"r^Vif
Vx^iV-^i

'.'•'''/' ; '• •''.:•'. ''•'•:.'.

SPARTA SANDS AND SHALES
CANE RIVER MARL
WINONA SHALE
WILCOX SANDS AND SHALES
SAND COMPRISES 70-75% OF WILCOX

MIDWAY SHALE
CLAYTON CHALK
AUSTIN CHALK
EAGLE FORD SHALE
UPPER TUSCALOOSA SANDS AND SHALES
MIDDLE TUSCALOOSA SHALE
LOWER TUSCALOOSA SAND
Fig. 2 - Generalized stratigraphic
column Mallalieu Field, Lincoln Co.,
Mississippi.
               488

-------
                                            TOP OF SETTLED
                                            MUD SOLIDS 5726'
OJOO'.
           KMSOfl.)

   TO  IO.5Z5   |"

SLOUGHED SHALE (O.I md)
          Fig. 3 - Illustration of uncased abandoned
  i—    well scenario,  Lower Tuscaloosa trend,   	
          showing finite  difference model layers.
                       489

-------
i




.-.. ...— .;.•;, Bo»« '::

WINONA -=-=-_^=

\ -'':~-'. - '• • .-
.-"'. ;_•' '~ '•'_/
WILCOX : .*-••••
:'~" __"""• : •:-• ~;.
•— ' • ' . • • ~". .
•-'• •-;•.'•'. :—•'''
'7^ ' .*— • .'' - ''• —

MIDWAY 	 — T —

CLAYTONjI Ilf^"'
TllTT -r -J T,-

-.-Ipg-EAGLE teRD^T?^- —

M1DCLE_ tUSCALOOSA
' .LOWER TUSCALOOSA


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'l:
\
'
t
'<
j




f
\e
(

<
'
^Hrt.g^o.ing
d
i
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i





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lii




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x;
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)<
X
\
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v







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1(700 ft.)

2(400 ff)
3(660ftJ
1 MUD SOLIDS 4560'
4(l40Oft.)


' f
5(40
-------
EVALUATION  OF THE USE OF A PIT MANAGEMENT SYSTEM


Richard A.  Spell, Charles R. Hall
Oryx  Energy Company
Houston,  Texas


Darrell Pontiff,  John Sanunons
SOLOCO, Inc.
Houston,  Texas


Introduct i on

The ability to effectively manage drilling wastes during the
drilling  of a well can result in greatly reduced waste disposal
costs.  Traditional reserve pit designs consisting of a one or
two pits  do not allow flexibility in managing the drilling
wastes.   The use of a pit management system consisting of a
minimum of  four pits allows the operator to segregate the waste
and manage  its treatment or disposal either during the drilling
operation or after completion of drilling.

If any unforseen problems such as drilling into salt, taking a
saltwater kick, having to change to a mud system that contains
environmental contaminates, or other similar situation, are
encountered while drilling using a conventional reserve pit, the
only  management option is to place the contaminated mud and/or
cuttings  into the pit and potentially contaminating the entire
contents  of the pit.  If onsite treatment or disposal becomes
impossible  because of either contamination, problems with annular
injection,  or other reasons, the cost of disposal increases from
a range of  $0.30/barrel to $l,00/barrel to as high as
$7.00/barrel or more.

This  paper  utilizes case studies from wells drilled in the
central Gulf Coast to evaluate the Pit Management System as
compared  to the more traditional waste management practices of a
conventional reserve pit or a closed system.  These case studies
compare waste volumes and cost of waste disposal.  The results of
this  study  support the use of the Pit Management System.
                              491

-------
Concept of the Pit Management System

A traditional reserve pit associated with most onshore drilling
operations consists of one large pit into which mud, drill
cuttings, wash water, rain water, and other liquid wastes are
placed and stored until the end of the drilling operation.  Then
the waste is analyzed, the water treated and discharged, and the
remaining material is either injected into the annulus of the
well, buried, landfarmed on site, or hauled to a approved offsite
treatment or disposal facility.

Problems with a traditional reserve pit can result when
contaminated mud or cuttings are mixed with uncontaminated
material in the pit rendering the entire contents of the pit
unsuitable for onsite treatment or disposal.  This can occur when
an operator drills into salt and is forced to place salt cuttings
into the pit, when saltwater bearing formations are encountered
and the saltwater contaminates the pit contents, or when weighted
muds containing barite cause barium contamination of the pit
contents.  This situation can be extremely costly and can be
prevented with a minimum of planning and the construction of a
pit system which allows management of the pit contents.

The use of a managed pit system will allow the drilling wastes to
be segregated.  Relatively uncontaminated materials can be
treated or disposed of on site, while the more contaminated
wastes can be injected or transported to an offsite commercial
disposal facility for treatment or disposal.  This can be done
either during the drilling operation or at the completion of
drilling activities.

The cost of construction and management of the pits is slightly
higher than the conventional reserve pit, but is significantly
lower than either a closed system or a conventional reserve pit
when total haul-off to a commercial facility is required.  The
case studies presented in this paper show that the cost of
treatment/disposal of wastes from a managed pit will range from a
low of $0.40/barrel to a high of $1.84/barrel, which is
significantly lower than the cost of the closed system which
ranged from $2.67 to $7.00/barrel of waste treated.

The Pit Management System consists of a minimum of four pits
constructed in the area normally occupied by a conventional
reserve pit.  Area is also provided for a drag-line to move
solids from one pit to another and to remove material from pit
                                492

-------
during the drilling operation.
system is shown  in Figure l.
The layout of a typical pit
        FIGURE 1.   Typical Layout of a Managed Pit System
Pit Ł 1,  the Shaker Pit receives drill cuttings from the shale
shakers.   The solids in this pit are moved, as needed, into Pit #
2, the Storage Pit.   Liquids from the Shaker Pit are transferred
into Pit  # 3,  the Settling Pit.   If necessary, either rain water
or water  from Pit # 3 can be pumped into Pit # 4, the Treating
P.it.  Pit # 5 is an Emergency Pit.  The number, size, and
arrangement of the pits can be modified as needed.

The ability to move solids from  Pit # 1 to Pit # 2 allows the
operator  to segregate uncontaminated solids from contaminated
solids. Even solids that are suspected to be contaminated can be
segregated while awaiting the results of laboratory analyses.
Solids from Pit # 2 can be removed from the pit during the
drilling  operation and managed appropriately.  This management
option is not available using a  conventional reserve pit.
                              493

-------
Liquids may be managed similarly.  Liquids are moved from Pit # i
into Pit # 2 for the purpose of gravity settling and, if
necessary, into Pit # 3 for chemical treating prior to discharge.
Pits # 2 and 3 provide a reservoir for rain water that will keep
the relatively clean rain water from contacting the solids which
frequently contaminate the rain water.  By careful management,
rain water can be segregated from contaminants and discharged
without any treatment.  This greatly reduces the volume of
liquids that have to be treated since rain water can account for
up to 50% of the liquid in a conventional reserve pit.  The rain
water, water from the settling pit, or treated water is available
for use as make-up water in the mud system, resulting in further
savings.


Case Studies

Twelve case studies will be presented which support the use of
the managed pit system.  Two studies are wells which used the
Managed Pit System.  Three wells used a conventional pit and
onsite treatment/disposal.  Three wells used a conventional pit
and offsite commercial treatment/disposal, one well used a closed
system with onsite treatment/disposal, and three wells used a
closed system with offsite commercial treatment/disposal.

The data and information detailed below is summarized in Table 1.
Case # 1

Case # 1 well was a 17,800 foot well drilled in Acadia Parish,
Louisiana, using a Managed Pit System.  The drilling of the well
generated 59,236 barrels of drilling waste.  By utilizing the
sectioned reserve pit and managing the waste as it was generated,
43,200 barrels of waste were handled onsite by treating and
discharging the liquids and landfarming and injecting the solids.
Due to difficulties during annular injection, 16,036 barrels of
waste had to be hauled to an offsite commercial facility for
treatment and/or disposal at a cost of $3.66 per barrel.  The
cost of onsite treatment/disposal was $1.16 per barrel.  The
total cost of waste management was $1.84 per barrel. If the
majority of the waste had not been treated and disposed of
onsite, it is projected that the entire pit contents would have
had to be taken to commercial facilities at an additional cost of
$64,709, for a total cost of $173,670, This would increase the
disposal costs to $2.93 per barrel, an increase of $1.09 per
barrel.
                               494

-------
Case # 2

Case # 2 is a well  that is nearing completion in Cameron Parish,
Louisiana, at a proposed depth of 19,000 feet.  Though not
complete,  it is felt that enough data has been generated using
the Managed Pit System for this well to provide significant
information.  Currently the well is at a depth of 16,356 feet and
has generated 129,000 barrels of waste.  Much of this volume is
rain water which  has been collected in the pits and on the
location.  The liquid has been treated and discharged.  The waste
solids have been  landfarmed adjacent to the site.  Current waste
treatment/disposal  costs are $0.40 per barrel.  It is anticipated
that all wastes will be treated and disposed of onsite and the
final costs are projected to be about $0.50 per barrel.


Case # 3

Case # 3 is a well  drilled in East Feleciana Parish, Louisiana to
a depth of 16,100 feet using a conventional reserve pit.  All
wastes were either  injected via annular injection or buried on
site.  A total of 31,935 barrels of drilling waste was disposed
of at a cost of $35,428 or $l.ll/barrel.


Case  # 4


Case  # 4 is essentially a twin of Case # 3.  This well was also
drilled in East Feleciana Parish, Louisiana to a depth of 16,170
feet using a conventional reserve pit.  26,451 barrels of waste
were disposed of  by injection and burial.  The disposal cost was
$33,182 or $1.25/barrel.


Case  # 5

Case  # 5 is a well  drilled in Acadia Parish, Louisiana to a depth
of 15,000  feet using a closed system.  The use of the closed
system was required because of the limited area available for the
drill site.  The  cuttings were stacked on location and dried.
Fly ash was added to stabilize and dry the waste prior to
landfarming.  At  approximately 10,500 feet, it was calculated
that the contaminate concentration in the mud and cuttings had
increased  to a level that onsite landfarming was no longer
feasible and the  waste was hauled to a commercial facility.  The
total cost for waste handling, both onsite landfarming and
commercial disposal was $85,571.  The additional cost for the
                               495

-------
closed system was $36,000.  The total volume  of waste generated
was 32,000 barrels.  The cost for disposal was $3.81/barrel.


Case f 6

Case # 6 is a well drilled in Allen Parish, Louisiana to a depth
of 10,500 feet using a conventional reserve pit.  Approximately
14,650 barrels of drilling waste was generated.  Approximately
12,150 barrels of pumpable waste were disposed by annular
injection at a cost of $1.07/barrel.  The remaining waste was
landfarmed on site.

A post-closure sample of the landfarming area was taken and the
results of the analyses showed that the area did not meet the
requirements of Louisiana Office of Conservation's Statewide
Order 29-B.  Further studies determined that the area could be
brought into compliance with the addition of gypsum and further
landfarming.  The two landfarming operations cost $8,000.  The
total cost of waste disposal was $20,950 or $1.43/barrel.


Case # 7

Case # 7 is a well drilled in Covington County, Mississippi to a
depth of 14,400 feet using a conventional reserve pit.  The
wastes generated by drilling this well vere to be disposed of by
annular injection.  The design of the location allowed rain water
and other waste water run-off from the drill site to enter the
reserve pit.  Near completion of drilling, the reserve pit
reached capacity and it was necessary to haul pit fluids to
offsite disposal.  Upon completion of the drilling, the annular
injection was begun, but almost immediately, problems forced
cessation of injection .  There was inadequate area for
landfarming so remaining liquids were treated and discharged.
All residual liquids and solids had to be taken to offsite
facilities.  The total cost for the waste management was $102,583
or $2.28 per barrel.


Case # 8

Case # 8 was to Case # 7, a 14,400 foot well was drilled in
Covington County, Mississippi using a conventional reserve pit.
Again annular injection was planned as the disposal method, and
again injection problems prevented the injection of the pit
contents.  This well encountered salt and the entire pit contents
were contaminated to a point that treatment and discharge of the
pit liquids was not allowed, and landfarming was not possible.


                                496

-------
All waste  had to be taken to offsite facilities.  The  cost  for
disposing  of 54,900 barrels of waste was $200,262 or $3.65  per
barrel.


Case  #  9

Case  #  9 was a 17,300 foot well drilled in Cameron Parish,
Louisiana, in the same field as Case #2.  A concept similar  to
the Managed Pit System was designed and utilized at this  site.
An existing pit was used as one of the four pits in the system.
Though it  was anticipated that the pit contained contaminants, it
was thought that those contaminants could be managed along  with
the drilling wastes generated during the drilling of the  well.

Due to construction problems, pit walls separating the various
pits  were  breached allowing the uncontaminated pit contents to be
contaminated with barium from contaminated pit contents.  The
result was that no solids could be treated and disposed of  on
site  and all solid wastes had to be hauled to a commercial
facility.   It was possible to treat and discharge most j>f the
liquid wastes.  The cost of disposal of the 100,000 barrels of
waste from this well was $400,000 or $4.00 per barrel.


Case  # 10

Case  # 10  was drilled in Newton County, Texas, to a depth of
11,800 feet.  Due to space limitations, a closed loop system with
an integrated solids control system was used.  10,447 barrels of
drilling waste were generated.  To offset the high cost of
off site disposal, the same waste management practices
characteristic of the Pit Management System were applied  to the
waste generated from this well.  Wastes were segregated into
three general categories; injectable fluids, uncontaminated
solids, and contaminated solids.  Wastes were handled by  the
appropriate disposal method, annular injection, onsite
landfarming, and commercial disposal.  Though the disposal  costs
were  high, it was felt that this management practice reduced the
disposal cost.  The disposal cost was $34,826 or $3.33 per
barrel. When the incremental cost of $39,000 for the closed  loop
system was added to this cost, the disposal costs per barrel
increased  to $6.61.


Case  | 11

Case  # 11  was a well drilled in Acadia Parish, Louisiana  to a
depth of  15,350 feet.  The land owner would not allow the


                               497

-------
application of any drilling waste to his land so the use of a
reserve pit and burial and/or landfarming was not possible.  A
closed loop system was used and all waste was hauled to a
commercial disposal facility.

23,930 barrels of drilling waste was disposed of at a cost of
$105,180 or $4.40 per barrel.  The incremental cost of the closed
system must be added to this bringing the total cost to $168,180
or $7.03 per barrel.


Case # 12

Case # 12 was drilled in Lafourche Parish, Louisiana to a depth
of 12,400 feet using a closed system.  Because this well was
located in a swamp with limited land area, landfarming was not
possible and hauling to a commercial facility was planned.
14,000 barrels of waste was hauled at a cost of $98,000 or $7.00
per barrel.  Adding the incremental cost of the closed system,
the costs increase by $91,800 to $189,000 for a cost per barrel
of $13.50.


Discussion of Case Studies

One of the advantages of the of the Pit Management System is the
ability to handle most of the waste during the drilling operation
rather than at the completion of drilling,.  Our experience has
shown that this option should be utilized for several reasons.
First, and perhaps most importantly, it forces the rig personnel
to become more involved with the management of the drilling
wastes and to realize the effects that their actions and
decisions have on the wastes and waste management options.

Secondly, it reduces or eliminates the possibility of
contaminating the majority of waste with the more contaminated
wastes typically generated near the end of drilling operations
when heavier, more complicated muds are used and when
contaminated formations are most commonly encountered.  Cases # 8
and 9 support this.  In Case # 8, the entire contents of the
reserve pit was contaminated by salt cuttings and when the
anticipated disposal practice, annular injection, failed the  .
entire pit contents had to be hauled to offsite disposal.  If a
Managed Pit System had been employed, the majority of the wastes
could have been handled on site by either burial or landfarming
and it is estimated that the disposal costs could have been
reduced by approximately 50 %.
                              498

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EXAMPLE
NUMBER
          LOCATION
 1    ACADIA PARISH, LA.

 2    CAMERON PARISH, LA.

 3    E. FELECIANA PARISH, LA.

 4    E. FELECIANA PARISH, LA.

 5    ACADIA PARISH, LA.

 6    ALLEN PARISH, LA

 7    COVINGTON COUNTY, MS.

 8    COVINGTON COUNTY, MS.

 9    CAMERON PARISH, LA.

10    NEWTON COUNTY, TX.

11    ACADIA PARISH, LA.

12    LAFOURCHE PARISH, LA.


DEPTH
(FT)
:==sa=BS
17,800
16,350
16,100
16,170
15,000
10,350
14,400
14,400
17,300
11,800
15,350
12,400


WASTE HANDLING
SYSTEM
SSSESS5SSSSSSS3S32S2S!
MANAGED PIT
MANAGED PIT
CONVENTIONAL PIT
CONVENTIONAL PIT
CLOSED SYSTEM
CONVENTIONAL PIT
CONVENTIONAL PIT
CONVENTIONAL PIT
CONVENTIONAL PIT
CLOSED SYSTEM
CLOSED SYSTEM
CLOSED SYSTEM
TABLE 1
SUMMARY OF DATA
INTENDED
TREATMENT/DISPOSAL
METHOD
BS5SSSSE=scsssxsss:ssa:sssssE==s==:
ANNULAR INJECTION/LANDFARM
ANNULAR INJECTION/LANDFARM
ANNULAR INJECTION/BURIAL
ANNULAR INJECTION/LANDFARM
ANNULAR INJECTION/LANDFARM
ANNULAR INJECTION/LANDFARM
COMMERCIAL FACILITY
COMMERCIAL FACILITY
COMMERCIAL FACILITY
COMMERCIAL FACILITY
COMMERCIAL FACILITY
COMMERCIAL FACILITY


VOLUME
OF WASTE
(BBL)
59,236
129,000
31,935
26,451
32,000
14,650
45,000
54,900
100,000 EST
10,447
23,930
12,000


COST
$108,961
$ 51,080
$ 35,428
$ 33,182
$ 85,571
$ 20,950
$102,583
$200,262
$400,000
$ 34,826
$105,180
$ 84,000


COST/
BARREL
$1.84
$0.40
$1.11
$1.25
$2.67
$1.43
$2.28
$3.65
$4.00
$3.33
$4.40
$7.00

-------
and it is estimated that the disposal  costs could have been
reduced by approximately 50 %.

In Case # 9,  internal pit walls  separating pit segments were
breached allowing drilling wastes  with high barium content from
barite to contaminate the entire pit contents.  Since no waste
had been removed from the pit  system and treated on site, the
entire pit contents had to be  hauled to a commercial facility.
If the Managed Pit System had  been constructed properly and if
the waste would have been managed  as it was generated, the waste
disposal costs could have been reduced by an estimated 50 %,
also.

Planning is  one of the keys to the successful application of a
Managed Pit  System.  Designing the drill site and pit system in a
manner that  prevents the majority  of uncontaminated storm water
from  entering pits containing  contaminants can greatly reduce the
volume of liquid that has to be  treated.  This can result in
significant  savings.  Case  # 2 is  an example where a large volume
of  liquid was effectively managed, contamination was minimized,
and disposal costs were kept very  low.

Closed mud systems  (closed  loop  systems) have been used recently
in  situations where total haul-off of  all of the drilling wastes
is  anticipated.  The closed system is  used to reduce the waste
volumes, thus reducing disposal  costs.  Most commonly, the
increased equipment costs   required of the closed system more
than  off set the savings resulting from the reduction in waste
generation.   The Managed Pit System is an effective compromise.
The segregation of the waste can result in saving in several
ways. Relatively uncontaminated wastes are frequently disposed
of  at lower  costs at many commercial facilities.  Segregation of
the liquid wastes results in more  water that can be discharged at
the drilling site resulting in less liquid being transported to
disposal.  Solids can be placed  in one of the pits and allowed to
dry further  reducing the volume  of waste to be transported and
disposed. Comparing Cases # 1  and  2 to Cases # 5, 10, 11, and 12
_shows that the use of the Managed  Pit  System can result in
significant  cost  saving  over the use of a closed system.
Comparing Cases  #  1 and  2 to Cases # 3 and 4, shows that the use
of  the Managed Pit System is very  cost competitive with the use
of  a  traditional  reserve pit.

Other Considerations
 Most operators are concerned about the continuing liability
 associated with the handling and disposal of their drilling
 wastes.  Many feel that the liabilities are greatest at
                                 500

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reduce the volume  of waste taken to commercial facilities.  The
Managed Pit System accomplishes this.   An evaluation of the cases
presented herein shows that over 70 %  of drilling wastes can be
handled on site. Most operators feel their liability is less with
onsite disposal or treatment.


Conclusions

In reviewing  the cases,  it is  apparent that the Pit Management
System, when  properly used, will reduce disposal costs.  The case
studies indicate that the isolation of wastes will prevent the
contamination of the majority  of the drilling wastes.  This will
maximize onsite treatment or disposal  and greatly reduced costs.
The planning,  waste management practices, and monitoring of the
waste will greatly reduce the  possibility of contaminating
significant volumes of waste because of "surprises".  The case
studies show  that  the Managed  Pit System is cost competitive to
all methods of drilling waste  management.
                              501

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FATE AND EFFECTS OF PRODUCED WATER DISCHARGES IN COASTAL ENVIRONMENTS



Nancy N. Rabalais3



Jay C. Means*5, Donald F.  Boesch3
Louisiana Universities Marine Consortium, Chauvin, Louisiana 70344, U.S.A.
"Institute for  Environmental Studies, Louisiana State University, Baton  Rouge,
Louisiana 70803,  U.S.A.
Introduction

Produced waters,  or oilfield brine, are generated during the production  of  oil
or gas.  Water  that is trapped  within the permeable  sedimentary rock  of  the
formation is brought to  the surface with  the product.  This  water,  which  is
elevated in  salinity and  various  organic and  inorganic  substances,  may  be
reinjected or treated and  discharged.   The discharge  of  produced waters into
brackish and marine  waters is widespread  in  the northwestern  Gulf of  Mexico
region and in coastal Alaska  (1).   In  addition,  discharges of produced  waters
into   the   Mississippi   and   Atchafalaya   Rivers   and   their  freshwater
distributaries  and into  some  intermittent streams  leading to Texas estuaries
are currently allowed (2).

The total emissions of produced  waters into coastal and offshore environments
in  the  Gulf of  Mexico  is estimated   at  3.4 million barrels  per  day  (2).
Approximately  70%   of   these  discharges  enters  the  estuarine   systems   of
Louisiana and  Texas  (Fig.  1) .     The distribution  of  these  discharges   is
widespread throughout the  coastal  zones  of  both  states,  but  discharges  are
more numerous and voluminous in  southeastern  Louisiana and on the upper Texas
coast.

Discharge of oilfield  brine,  or produced  waters,  into  the State  waters  of
Louisiana is approximately 2 minion  barrels per  day from  nearly 700  sites
(2).  Most discharges average less than 1,000  bbl/d but a  few exceed 50,000 to
100,000 bbl/d.   In  response to concerns about  the fate and effects  of produced
waters in coastal environments,  several studies have  been conducted by state
and federal  agencies, university research  groups,  and private industry;  other
studies are  nearing completion.   Several  sites representing different volumes
of produced  water  discharges and different  receiving environments have been
examined    for    the    delimitation    of     the    scope     and     nature
                                      503

-------
          v>
          T3
          C
          CD
          v>
               500-1
          ^   400 -
               300 -
          to
          TJ
          !o
          CD
           T3
           C
           CD
           (/)
           3
           O
           05
           JO
           CD
               200 -
               100-
                    SABN CALC MERM VRML ATCH TERR BARA MRD  O-TO PONT GULF
                400-i
                300-
                200 -
100 -
                     LMa   CCh   Ara   SAn   Mat  Col   Bra  Galv  Sab  Gulf


Fig. 1.      Distribution  of  produced water discharges in  Louisiana's estuarine
basins  or areas  by  habitat type,  top,  and in  Texas coastal  waters,  bottom.
[Modified from Boesch and Rabalais (2)]
                                        504

-------
of the impacts  from these  effluents.   Selected  results from  case  studies in
fresh,   brackish',  and   saline  marsh  environments   (2,   3)   are  presented;
additional details are available  in  the complete  reports.

nascription of study areas

Of the 2 million barrels of produced  waters discharged into  the State waters
of Louisiana daily, 23,  22, and  17 percent  are discharged into fresh, brackish
and  saline  wetland environments, respectively,  with the  remainder discharged
into  open  embayments  or  nearshore  Gulf   of Mexico   waters   (2) .    Coastal
facilities which separate produced  water  from product  streams originating in
the  Federally-controlled outer continental  shelf (OCS)  are few  in  number but
account for  large volumes,  individually  and  collectively.   Three  areas were
the  focus  of a  recently  completed study  funded by  the Minerals  Management
Study  (2)  and are included in an  expanded and  ongoing study funded  by MMS.
These   sites   represent   large   volumes   of   OCS-generated   produced  water
discharges: Bayou  Rigaud,  behind Grand Isle;  Pass Fourchon; and the bay side
of East Timbalier Island.  Two  facilities  discharge large  quantities  of OCS-
generated  produced waters  into  Bayou Rigaud.    Volumes  of 105,000  bbd/d and
45,000  bbl/d enter  the dredged  channel  within  1  km  of each other.   Tidal
currents  through  the  northeastern  end  of  Bayou  Rigaud  are  swift,  being
influenced  by   tidal  exchange   through  the   nearby   Barataria  Pass.    Two
facilities discharge  a  total of  45,000 bbl/d  at  the Pass  Fourchon study site;
26,000 bbl/d  of  this volume are  generated  on  the Federal OCS.   The effluents
enter  a  dead-end canal which  leads  into Pass Fourchon,  which  itself  is
occluded by a beach  with shoreline stabilization structures.   The receiving
canal and  dead-end arm  of  Pass  Fourchon  are poorly flushed by tidal currents
which  are  otherwise  quite  strong through  Belle  Pass  and Pass  Fourchon into
Bayou  Lafourche  and the network of canals  to the east  of Pass Fourchon.   A
total  of  24,000  bbl/d of OCS  produced  waters are   discharged   from  three
facilities  at the East  Timbalier Island  study site.  The three  effluents are
located  in  dredged  access   channels leading  from   the  otherwise  shallow
Timbalier  Bay into  East  Timbalier  Island.   Tidal currents   flow  sluggishly
through the canal  network.   Details of the  large-volume discharge study areas
are  given  in Boesch and  Rabalais  (2).

The  focus  of  the study  funded by the Louisiana  Division  of the Mid-Continent
Oil   and   Gas   Association  was  on  discharges  into   fresh  and  brackish
environments.    One  site  was located in  a tidally  influenced, fresh  marsh
environment  within the  Bayou  Sale  oil field.   The discharge  volume averaged
2,700 bbl/d and  terminated in  a  dredged access canal.   Two sites were selected
in  brackish  marsh environments,  one  within   the Lafitte  oil  field in the
Barataria  estuarine  basin  (ambient  salinity at  time  of sampling 6  to 7 ppt)
and  the other in the  Golden Meadow  oil field in the Terrebonne estuarine basin
(ambient  salinity 9  to  10  ppt) .  The discharge -rate for  the  Lafitte facility
was  3,7000  bbl/d  and  the  effluent  entered   a  dredged  north-south  bayou
intersecting  some  natural open  water  areas   which  have  been  extensively
channelized.  Two discharge points  were  examined in the  Golden Meadow field:
1)  1,400 bbl/d  in a dredged bayou and 2)  2,800 bbl/d in  a  dredged canal.  In
each of   the   above  three  study  areas,  station  grids  were  located  on
combinations  of  dredged canals,  canals which intersected some  natural  water
                                    505

-------
areas, or natural bayous.   Details of the study areas  are  given in Boesch and
Rabalais (3) .

Characteristics of the discharge plume

Based on measurements of  salinity in  the  vicinity of the discharges at  the
time of field sampling,  it is possible to develop a crude  picture  of  the  fate
and dilution  of the  effluent,  using salt  as a conservative  tracer.   At  all
sites investigated,  there was  an  increase in  salinity in bottom  waters  near
the point  of  discharge,  but  surface salinities showed little or  no  increase
over ambient conditions  (2, 3).  Produced water effluents act  as a  dense plume
upon  discharge  into  estuarine waters  because  of  the  high concentration of
dissolved  solids.    Elevated  levels  of  salinity,   and  sometimes  volatile
organics,  were  found just  above  the  bottom  near  discharges  (2, 3) .    The
probable .source of the  volatile organics was  the effluent plume  rather  than
the  sediments  because  these  more  soluble  compounds  are  not particularly
concentrated in the sediments  (2,  3).

Dilution of the produced water upon its discharge into  the receiving  bayou or
canal appeared  to  be  rapid,  with an approximately 20-fold  dilution within  the
immediate mixing zone of the bottom-hugging dispersion  plume.   Salinity levels
at the  bottom were indistinguishable from background levels  (necessitating at
least a 100-fold dilution) within a maximum of 1000  meters of the discharge
points.  Where  bottom currents are  swift,  sufficient turbulence is generated
to mix  the bottom-hugging  plume.   Consequently  elevated bottom salinities,  and
sometimes volatile  organics  in overlying waters, were not  observed beyond  the
immediate vicinity of the  discharge  at  Bayou  Rigaud and Golden Meadow.  On  the
other hand, where  tidal  flows are  much less energetic because  of the  dead-end
nature  of  a  receiving  environment  or  restricted  water movement  because of
altered hydrography,   the density plume  retained its  identity  for   greater
distances  (e.g., Bayou Sale, Lafitte, Pass Fourchon)  (Fig.  2).

Contamination of sediments

Sediments  up to  one  kilometer from the produced water discharges exhibited
evidence  of petroleum  contamination   (2,  3) .    Contaminated  sediments   were
typified  by  1)  elevated  concentrations  of  polynuclear  aromatic (PAH)   and
saturated  hydrocarbons,  2) the presence  of petroleum-derived PAHs, 3) alkyl-
substituted homologs  at  higher concentrations than unalkylated parents, and 3)
a  fossil fuel  pollution index  which  indicated  that  more than  one-half of  the
PAHs  were  of petroleum  origin (FFPI > 0.5)  (2, 3).   Sediments well  removed
from  the discharges  contained trace  or non-detectable  levels of petroleum-
derived hydrocarbons  and a FFPI < 0.3.   PAH  in these  sediments, if detected,
were  usually pyrogenic in  origin.  PAH  concentrations  and characteristics  were
more  useful  than  saturated  hydrocarbons  in  determining  the likelihood of
contamination  by  produced  water   discharges  (2).    The  resolved  saturated
hydrocarbons were  usually very weathered with no homologous series of alkanes
present, even in contaminated sediments.   This  lack of  alkanes made the use of
indices  such as  odd-even  preferences,  pristane/nC-17,  and phytane/nC-18 of
little  use  in quantifying  petroleum  hydrocarbon concentration.
                                     506

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   IOOON.
                    500W
                   	1	
        IOOW    IOOE
   250 W      0       250E
                                       500E
                                                       IOOOE
  I '
  I
  I-
  Q.
  UJ o
  <-\ L-
     700W
500W
250S   IOOS
                                         IOONE 250NE
                                           500NE
                                           750NE
    Q.
    UJ
    O
                    •CANAL-
                                PASS  FOURCHON-
          xxxxxxxxxxxxxxxx
          xxxxxxxxxxxxxxxx
          'XXXXXXXXXXXXXXX
                              •xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx '
                                •'xxxxxxxxxxxxxxxxxxxxxxxxx'
             100    200    300   400   500   600    700    800
                     DISTANCE   FROM  DISCHARGE  POINT  (m)
Fig. 2.     Water  column  salinity   (ppt)  profiles  at  mid-channel   in  the
discharge area at  the  Bayou Sale site in August 1988, top; in  the discharge
area along the NE-W  transect at  the  Lafitte site in  August  1988, middle; and
along  the  access canal and adjacent  Pass  Fourchon in January  1988,   bottom.
[Modified from Boesch and Rabalais (2,3)]
                                  507

-------
Hydrocarbon  contamination  of  bottom   sediments   was  more  extensive  where
discharge  volumes  were  large  and/or   where  tidal  current  velocities  were
reduced and where  fine  sediments  accumulated.   In  Bayou Rigaud,  where 150,000
bbl/d of  two  combined effluents  are discharged,  elevated levels of  PAHs  and
saturated hydrocarbons were evident at  station BR-1, proximate to the largest
discharge (Fig. 3), and the FFPI  indicated  petroleum hydrocarbon  contamination
to a  distance  of 500 m  from  the  discharge.   Where smaller volumes  (2,700  to
3,800 bbl/d) are  discharged into dredged canals  or bayous, PAHs  are  elevated
near the discharge  and  up to  500  m from the discharge  (Fig. 4, Bayou  Sale  and
Lafitte).  In  other instances,  however, elevated PAHs  are  evident within only
100 to 250 m of the discharge  (Fig.  4,  Golden  Meadow).

The degree  of  contamination of bottom  sediments  by trace  metals  contained  in
the  produced  waters  is  far  less than  that  for  petroleum hydrocarbons  (2) .
Strong  outliers from  the aluminum  concentration  in  surficial  sediments  are
generally an indication of sites  of  probable contamination. Sediments showing
probable  zinc  contamination  were  found  at  stations   near  the  large-volume
produced  water discharges in Bayou Rigaud  and Pass Fourchon  (Fig. 5).   Fewer
sediment  samples   showed variation  from   the   linear  relationship   between
aluminum  and  lead  (Fig.  5); elevated levels of barium  in  surficial sediments
were  not  consistent  with  discharge   locations.     For  the smaller-volume
discharges  (Bayou  Sale,  Lafitte,  Golden  Meadow),  trace  metals,  except  for
barium,  did not  show a  consistent pattern of  enrichment  in sediments near
produced  water discharges (3).

Effects on benthic  communities

The  benthic  environments adjacent  to  produced  water  discharges  that were
examined  ranged  from  freshwater  to   saline  (2,  3) .    In  most  cases,  the
environments   were  disturbed benthic  habitats  even  without  the  effects  of
produced  water contaminants.   These environments  were channels in which fine
sediments  accumulate,  which  are  periodically dredged,  and  in  which  vessel
traffic  disturbs  the  bottom.    In each   site  investigated,   differences   in
benthic  fauna  were examined with consideration of the  fauna  in  as similar a
physiographic  and  hydrographic  regime as possible.

In  the  study  of   large-volume  discharges  (2),   the  macrobenthic  fauna  was
essentially  eliminated  at  locations closest  to  the  discharge  where  bottom
sediments  were  heavily  contaminated  (PAH   >  2,300 ppb) .   Low  densities  of
organisms and  few species were found under  conditions  of moderate hydrocarbon
contamination  of  sediments  (PAH > 200 ppb) .

In the  second  study cited above (3)  where the  volume of discharges were one to
two  orders  of magnitude  smaller,  the  levels of contamination were  consistent
with  the same differences in  benthic  macroinfauna.   Benthic organisms were
present  in  reduced densities  and reduced diversity of  species where  there  was
high  to moderate contamination of  sediments by petroleum  hydrocarbons (PAH'>
1,000 ppb)  (Fig.  6).   There were  changes in species composition  and population
size  structure  in  areas of  moderate  contamination   (>  300 ppb  PAH)  when
compared  to uncontaminated sediments  (Fig. 6) .   The  effects  on  benthos were
                                     508

-------
       30000-1
       25000-
   a  20000
   c

   •Z   15000
   a
   +*


   o   10000
   ' c
   o
   o

         5000
                Hydrocarbon concentrations
  -•—  PAH


  -o—  Resolved Saturates (*0.05)
BR-1
                   BR-4
            -3.0    -2.5


                 FFPI
    0.
    L_

    U.
          1.0 -\
          0.8-
          0.6-
          0.4-
          0.2-
          0.0
            • 2.0    -1.5    -1.0    -0.5    0.0     0.5    1.0
                                                 BR-1
                                BR-2
                                                           BR-5
    BR-3
BR-4
            •3.0
    •2.5    -2.0    -1.5    -1.0    -0.5    0.0     0.5     1.0
                                      Distance (km)

   - 3.     Concentrations  of hydrocarbons  in surficial  sediments,  top,  and

     bottom, with distance from station BR-1  in  Bayou Rigaud in October 1987.

[From Boesch and Rabalais  (2)]
                                    509

-------
                 a
                 1
                    4000
                    3000-
                    2000 •
                     1000-
                      .2000      -1000
                                                     1000
                                                               2000
                    2000
                    1500 -
                <   1000
                a.
                     500-
                                                   Pel, f N/E-
                Ł
                a.
                                                               1000
                       • 2000
                                 •1000
                                                     1000
                                                               2000
                                         Dltunc* (m)
Fig. 4.      Spatial distribution of normal PAH in discharge and reference site
surficial  sediments  for study  areas at  Bayou Sale,  top; Lafitte,  middle;  and
Golden Meadow primary  site, bottom.   Note differences in scale.    [From Boesch
and Rabalais (3) ]
                                       510

-------
400
300-
200-
 100
              Zn Uig/g)
                              PF-2
             BR-2,
              BR-1
                    BBR-11
                              .PF-4
            0PF-2
       BT-5
G
            B
                 Q
        B
   0.0
1.0
          2.0
                          120
                                        100-
                                         80-
                                         60-
                                         40-
                                         20-
3.0    0.0
                                            (jjg/g)
                                                      Br-1
                                                 PF-5
                                                         PF-2m


                                                       0PF-4
                                                               D BR-7
                                                          El
                                         PF-7


                                         B   f
                                          B
                                          B

                                           B
                                             JBl
                                                      B
                                                    BB
                                                                             3.0
   .  5.     Relationship of  Zn and Pb  to Al  in  surficial  sediments  at  all
produced water  sites in  the study  by Boesch and Rabalais  (2) .   Some station
numbers given next  to data.  Lines  represent the expected concentrations of a
metal in the  sediments  based on  the aluminum  concentration.    [Modified from
Boesch and Rabalais  (2)]
                                       511

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greatest  at the  Lafitte  site,  where  only  very  depauperate populations  of
brackish  water, polychaete  worms  were  found  within  250  to  300 m of  the
discharge  (Fig.  6) .    Effects on benthos  in the  freshwater habitat  at  Bayou
Sale  were less  severe  (3) .   Near  the produced water  discharge there,  the
diversity  of the  fauna  was reduced  but  oligochaete  worms  were present  in
higher densities  than were  found  in uncontaminated sediments.    Increases  in
oligochaete  population size have been characterized in the literature  (4)  as
benthic community changes in tidal freshwater and estuarine areas in  response
to  physical disturbance  and organic  pollution.   Because  ambient  salinity
conditions  at  the Golden Meadow  site were  higher, more  species of  benthos
occurred there than at the other two sites.   Even under conditions of  moderate
sediment  contamination near  the discharges,  no depressions  in  total  faunal
abundance or diversity were  found  (Fig.  6).

Comparison of fate and effects

The principal  impacts uncovered in the two  studies (2, 3) are related to the
contamination of  the estuarine environment  with organic compounds and metals
contained  in the produced waters and  the  effects on the benthic  communities.
There  is  considerable, variation in the level and  extent  of bottom  sediment
contamination at  the sites which is a  function of the volumes discharged and
the  hydrodynamic  and sedimentologic  features  of the  sites.   The  heaviest
contamination  and the most extensive  impacts  were seen  where  the discharge
volumes  are extremely  large (Bayou Rigaud)  and/or where  the tidal  flushing
rates  are low  (the  dead-end canal system at Pass  Fourchon) .   The levels  of
contamination  reported for  the  three  sites  with  smaller discharges  (3) were
generally an order  or  two of  magnitude  less  than those  reported for more
saline  environments  with  larger  volumes  of produced  water  discharges  (2) .
Given  comparable discharges, less contamination is witnessed in  regions with
vigorous  tidal  flushing,  such  as Golden Meadow,  compared  to   less  flushed
sites,  such as  Lafitte.   The  range  of  effects  on benthic communities seen
within  the  study  areas   were  1)  low  densities  of., organisms  and  few  species
under  conditions of high to moderate  hydrocarbon contamination of sediments,
2)  changes  in  the  species  composition  and  population  structure  in  areas  of
moderate  contamination,  or 3) no obvious  effects in areas of low hydrocarbon
contamination.

References

1.     J.M.  Neff,  N.N. Rabalais,  D.F. Boesch, Offshore  oil  and gas development
      activities  potentially causing  long-term  environmental effects,  Pages
      149-173  in  Long-Term  Environmental Effects  of  Offshore  Oil  and Gas
      Development.  D.F.  Boesch  and  N.N.  .Rabalais  (eds.),  Elsevier  Applied
      Science Publishers, Ltd.,  London,  1987.

2.     D.F.  Boesch and  N.N. Rabalais  (eds.),  Produced  Waters   in  Sensitive
      Coastal  Habitats:  An  Analysis   of  Impacts.  Central  Coastal  Gulf  of
      Mexico.   DCS  Report/MMS   89-0031,   U.S.   Dept.   of  Interior,   Minerals
      Management  Service,  Gulf  of Mexico DCS  Regional  Office,   New  Orleans,
      Louisiana,  1989, 157 pp.
                                       512

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e
.
-18 T T ' ,
0 200 400 800 800 1000 1200 1400 1800
sw Distance from Discharge (m) NE PAH (ppb)
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I
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 16
 14
 12
 10
  8
  6
  4
  2
  0
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 180

 160

 140


 100

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 60

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                                                                         D
                          I
                                            180,

                                            160

                                            140

                                            120

                                            100

                                             80

                                             60


                                             20
 •1200-1000-800 -600 -400-200  0  200 400 600
  S        Distance from Discharge (m)
                                   800 1000 12000
                                          N
                                                 so
                                                                       250
                                                        100    ISO   200
                                                              PAH (ppb)
Fig.  6.    Number  of  species  per  replicate  and  number  of  individuals  per
replicate  (+ S.E.) for benthic macroinfauna  along a NE-SW  transect through the
Lafitte  discharge site  (A);  comparison  of number of  species  and  number of
individuals  to  polynuclear  aromatic  hydrocarbons  (PAH)   for  the  Lafitte
discharge  site (B); similar data for benthic macroinfauna  along a N-S transect
through  the  Golden  Meadow  primary  discharge  site   (C)   and  (D).     Note
differences in scales.   [Modified from Boesch  and Rabalais  (3)]
                                      513

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3.    D.F.  Boesch and  N.N.  Rabalais  (eds.),  Environmental Impact of  Produced
      Water Discharges in Coastal  Louisiana,  Report to The Louisiana  Division
      of the  Mid-Continent  Oil and  Gas Association,  Louisiana  Universities
      Marine Consortium,  Chauvin, Louisiana,  1989, 287 pp.

4.    R.J.   Diaz,  Ecology  of  tidal  freshwater  and  estuarine  Tubificidae
      (Oligochaeta),  Pages  319-329  in  Aquatic  Olicrochaete  Biology.  R.Q.
      Brinkhurst  and  D.G.  Cook   (eds.),  Proceedings,  First  International
      Symposium  on  Aquatic  Oligochaete  Biology,  Sidney,  British  Columbia,
      Canada,  Plenum Press, New York, 1980, 529 pp.
                                    514

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A HARMONIZED PROCEDURE FOR APPROVAL, EVALUATION AND TESTING OF OFFSHORE
CHEMICALS AND DRILLING MUDS WITHIN THE PARIS COMMISSION AREA.
L.- 0. Reiersen
State Pollution Control Authority, Norway.
Oslo, Norway.
Introduction

- The North Sea and The Paris Commission
The  North  Sea  is  one of the most productive seas in the world and has
been one of the main supplier of fish  to  the  European  Common  market.
Surrounded  by  heavily industrialized and cultivated countries the North
Sea receives large amounts of waste from landbased industrial activities,
farming,  sewages in addition to discharges from shipping and oil and gas
explotations in the North Sea itself.

Over the last decades the public's worries about the state of  the  North
Sea due to dumping and discharges of wastes and chemicals from industrial
activities have increased. For the health of the public it  is  important
that  fish  brought  to  the  marked  is uncontaminated. The occurence of
diseased and contaminated fish is a  very  sensitive  topic  and  reports
documenting  increased  frequencies  and/or  concentrations  can  lead to
restrictions on sales and import and thereby  negative  consequences  for
the  fishing  industry.  It  is  thereforee  very  pertinent  to  prevent
pollution of the North Sea.

The Paris Convention was established in 197^ and entered  into  force  in
1978.  For  the prevention of marine pollution from land based sources in
the North East Atlantic (including the North Sea). Under this  convention
"land based sources" are defined as including "man-made structures placed
under the jurisdiction of a Contracting Party" and this includes offshore
exploration and exploitation of petroleum-hydrocarbons.  Article 1 in the
Paris Convention states that "the Contracting Parties  pledge  themselves
to  take  all possible steps to prevent pollution of the sea, by which is
meant the introduction by man, directly or indirectly, of  substances  or
energy  into  the  marine  environment (including estuaries) resulting in
such deleterious effects as hazards  to  human  health,  harm  to  living
resources  and  to marine ecosystems, damage to amenities or interference
with other legitimate uses of the sea."

The Contracting Parties shall, jointly or  individually  as  appropriate,


                               615

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implement  programmes  and  measures adopted  by the commission.  There has
been agreed upon specific standards for discharges  and emissions,  control
mesurements  and monitoring methods, with  the aim to reduce the  pollution
of the sea and to get a better documentation  of the pollution level  (e.g.
on  discharge  of  oil  .contaminated  cuttings).  Over the last  years the
increasing use of offshore chemicals has been looked upon  as a  problem
area without satisfactory regulation.

- The use of chemicals in the offshore oil and gas  activity
In connection to offshore activities fairly large amounts of drilling and
production products/chemicals are used and discharged to  the sea,  either
adhered  to  drill  cuttings,  or  with  produced  water  (table  1). These
figures are from Norway, but similar discharges  takes place  in  UK,   the
Netherlands  and  Denmark.  Due to higher drilling  activity and  number of
production platforms the total discharges will be higher  in UK,  and lower
in  the Netherlands and Denmark were the activity and number of  platforms
are lower.
                               TABLE 1
        The use and discharges of some selected types of
        chemicals from Norwegian offshore installation in 1988
        (tons), based on figures reported from the operators.

                                DRILLING     PRODUCTION
                              used  disch.   used  disch.
Weight agents
Inorganic chem.
Polym . viscosif .
Biocids
Oxygen scaven.
Corrosion inhib.
Scale inhib.
Shale inhib.
Gas treatment
Others
146.000 86.000
3-700 2.700
1.800 1.200
30 25
2 1
90 40
60 60
2.500 2.500
-
3.875 1.544
-
-
-
1.400
1.000
1.100
1.100
-
8.000
1.051
-
-
-
35
12
15
750
-
140
400
         Total	158.057 94.060  13.651 1.352

The effects on  the marine environment due to discharges of  oil   contami-
nated drill cuttings have been documented several times  (1, 2, 3)

As  production  persits  and the fields gets "older",  the fields  normally
produce more water  (Fig.l) and an acidification may  takes  place.  In  an
attempt  to  prevent  corrosion  of  the  platforms  and the pipelines the
operators have  normally solved their .problem by an increased use  of
                                516

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    120
  en
  w
    100
     80
     6°
  O
  H
  a
  H
     20
                                             TOTAL
                                     BALLAST DISPLACEMENT WATER
 \	
:ED
 ir
                                       PRODUCED WATER
                                                                  I
        1986     1980     1990     1992     1994

                                     YEAR
   1996
1998
2000
Fig. 1.: Projected increase in dicharge of water, based on figures
         presented by the operators.
chemicals. The most common "production" chemicals used are biocides, anti
corrosion  products,  oxygen scavengers, anti scaling products  (table 1).
Chemicals are also used increasingly in an attempt to stimulate wells and
fields  in  an attemt to produce more oil. In addition chemicals are used
for maintainance of pipelines and large  amounts  of  chemically  treated
water can be discharged over a short period into a limited sea area.

During  the offshore process some of the chemicals will follow the oil or
gas phase while others follow the water phase and thereby  discharged  to
the  sea  as  a  part  of  the produced water. Some of these products may
degrade very fast, while others are more stable and may be detected for a
long  period.  Bioaccumulation of products is dependent on the lipophilic
character of the product, some products may thereforee  accumulates  very
fast  (lipid  soluble  e.g.  oil products) while others e.g. those with a
high molecular weight may not accumulate. The toxicological  effects  are
dependent both on the fate and concentration of the products, but also on
the organisms exposed - e.g. the life stage, living and feeding behaviour
etc.  The  fate  and  effects on the the marine environment of chemically
treated water have been difficult to investigate  due  to  methodological
problems  caused  by  the  great  dilution  of  the chemicals in the sea,
continous exchange of water masses due to currents, etc. However, effects
have  been reported from laboratory tests on marine organisms (4, 5). For
selection of the right chemical product, the operators have so  far  only
focused  on  the  technical problem and functional testdata have been the
                                517

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only criteria. Only after special requests  from the authorities potential
environmental  effects  data have been  searched for.  Very often such data
have either not been available because  the  products have not been  tested
for  such  information,  or  the  data  had low value since only tests  on
mammals (rats and rabbits)  were  those performed  and  none  on  marine
organisms.

- Excisting practices for approval of offshore  chemicals and muds
The  North Sea states which have offshore activities  are UK,  Denmark, the
Netherlands and Norway and  they  have  previously  introduced  different
systems  for  notification  and  approval   of   the  use  and discharge  of
offshore chemicals and drilling muds. For oil based drilling muds special
requirements  have been in force for toxicity testing during the 80-ties.
However, the tests required have been different in  the  four  countries,
and  thereby  the same mud system had to be tested by four different test
systems before approval in all four countries were achieved.

For all other offshore chemicals there  have been no  common  mandatory
requirements  on  testing.  In UK there has been.a voluntary  notification
system where the operator could report  the  amount  discharged  and document
toxicity  data  if  available.  In Norway the discharge applications have
been evaluated on a case by case basis, where the  operator had to specify
the  amount  to  be  used,  the concentration used and discharged,  and  as
exact  information  as   possible   on   toxicity.    biodegradation  and
bioaccumulation  in  the  marine  environment.   Normally  the data sheets
received containes insufficient data on the product's fate and effects  in
the marine environment.

The harmonized procedure

In the mid 80-ties the Paris Commission commenced  an  attempt  to harmonize
the test requirements for oil based muds, so that  repeated testing of the
same product could be avoided. During this  process the scope  was extended
to include all kind of muds and offshore chemicals,   and  the  objectives
were  specified  in  such  a  way that  the  new  system should  increase the
quality control for handling of  all  kinds of offshore  chemicals and
thereby  reduce  the  pollution of the  sea.  The selection and approval  of
offshore chemicals should be more effective and thus  reduce the cost and
work involved.

Within  the  Paris  Commission  there has been  a special working group  of
experts that  has  prepared  the  guidelines for   the  harmonization   of
procedures for approval, evaluation and testing of offshore chemicals and
drilling muds. Norway has been lead country for this  work,  and scientists
and  authorities  in UK, the Netherlands, Denmark,  Sweden and Norway have
participated in this work. Appendix 1.  In addition representatives  from
the  operators,  the E&P Forum* and suppliers have been involved in parts
of the work.
                                 518

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At the Paris Commission meeting in June  1990   the  guidelines   regarding
harmonization  of  procedure  for  approval,  evaluation   and  testing of
offshore chemicals and drilling muds was adopted  to be  followed as   close
as  possible on a trial basis. The guidelines will be reevaluated after a
two years period.

- the decision tree
In Fig.2 a decision tree is  presented.  This   tree  is  to   be  used   by
suppliers  or  producers in their search for products to be used offshore
that are "acceptable" from an environmental point of view.

- the Paris Commissions black and grey lists
In box II (Fig.2) one has to check whether  the actual  product include
substances which are listed in Annex A of the Paris Commission.  Pollution
of the maritime area from land-based sources by substances   in  Part   I,
Annex  A  (black  list) are to be eliminated while substances in Part  II,
Annex A (grey list)  are  to  be  strictly  limited,  or   as  appropriate
eliminated.

- the "green list"
In box III  (Fig.2) there are listed products which are classified as "non
hazardous"  for  the  marine  environment,   e.g.   composed    by  major
constituents of the sea water or inert material. A list of products which
do not need to be tested for  toxicity,  degradation  or   bioaccumulation
before  they  are  used  offshore  are under preparation within the Paris
Commission, the "green list". Even "green list"  substances   or  products
might  be  subject  to discharge restrictions in certain vulnerable area,
and a discharge application has therefore to be sent to the authorities.

- the central data base
Box IV  (Fig.2) is a very essential  part  of  the  system.  That is   the
establishing  of  a  central  data base where all the product information
specified in table 2  shall  be  stored  and  thereby  be  available   for
operators  and  authorities.  By using this data base the  operator should
receive an overwiev of excisting products and   their  potensial  environ-
mental hazard, and thereby be able to avoid the most harmful  products.

The  data  in  table  2  is  essential  for  the  evaluation  of potential
environmental effects and is mainly based on the Minimum Data  Set   (MDS)
and the SHOC report prepared by the E&P Forum.  Some adjustments have been
made by the Paris Commissions working group of  experts. The list contains
most  of  the  information  which  also  is required by the OECDs Minimum
Premarketing Data set (the MPDs).

     Forum - The Oil Industries International Exploration  fc Production
             Forum .


                                 519

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SUPPLIER/OPERATOR
                           I Substance or product
                             planned for offshore use
            Yes
                       II Is any component substance listed
                          in Annex A of Paris Convention ?
 Then the product will
 probably be subject to
 bans or restrictions in
 application
 (Drop plans or continue?)
       (continue)
  Identify data needed
   Send information to
     E & P database
                                         No
III Is the substance or product:
      I.One of the major
    constituents of sea water ?
            or
    2.LJsted (by GOP) as not
   requiring further testing for
        offshore use ?
                                         No
                         IV Select relevant information from
                            the E & P Forum database
                           V Is the information complete ?
                                      i
                                         Yes
                         VI Submit application to national
                            authority according to table 2
                                                               Yes
                                   Submit application
                                       to authority
AUTHORITY
                                                    Permit not
                                                      given
  Fig. 2.:  Decision tree to be followed  for selection of
            offshore chemicals  and drilling muds.
                                       520

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                             TABLE 2
Product information regarding physical, chemical and biologial properties
to be specified in an application  for  use  and  discharge  of  offshore
chemicals and drilling muds.	

PART I: SUPPLIER DATA

      Trade names and synonyms of the product used in various countries:
      Contact person in the company:
      Position in the company:
      Address:
      Telephone no:
      Emergency telephone no (24 hours):
      Telefax no:
      Country of manufacture/formulation:
      Name and addres of supplier:
PART II: CHEMICAL COMPOSITION DATA

      Application:
      Composition: - single compound/mixture solution/suspension/emulsion
      Chemical (or generic) composition *:
          Active ingredients:
          Solvents:

      Analytical methods and procedures to detect and quantify the
      product in water, sediment and organisms.

      Regulatory requirements:
      Indicate if the product contains any compounds regulated under
      the Paris Convention Annex A.
        - metals, organohalogens, organophosphorus
          compounds, organotin compounds, other listed.
        - radioactive substances.

      If yes, specify: item, concentration, trace **, intentional
      additive.
 •  In  addition  to  these  data  stored  in  the  central data base, the
 authorities will ask for Cas No. for all components in a mixture and  the
 concentration  of  all  components  with X intervals:  <1. 1-2, 2-5. 5-10.
 10-20. 20-40, 40-60, 60-100. Where necessary the authorities may  require

 100Z coposition.


 *• Trace is defined as less concentration than 0.01 *  (lOOppm).
                                521

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PART III: PHYSICAL PROPERTIES

      Physical form and appearance:  solid/liquid/gas.
      Odour and colour:

      Density (kg/m ), Boiling - and Melting points  ( C),
      Solubility in water and oil, pH (of saturated  solution  in
      water). Vapour pressure (mbar), Flash point  (  C)  and  OECDs
      requirements for special Fingerprints (e.g.  spectra).

      Bioaccumulation potential:
      For mixtures this information should be available for all
      components (above trace content). The OECD test guidelines should
      be followed and n-octanol/water partition coefficient should be
      documented. For at least inorganic components  the Biological
      Concentration Factor (BCF) should be documented.
PART IV: TOXICOLOGICAL DATA

      Environmental data:
      Results from acute toxicity tests on marine organisms has to be
      presented from at least one of the species listed in each of the
      three following groups:

      ALGAE:
               Phaeodactylum sp.
               Skeletonema costatum

      HERBIVOROUS:
               Acartia tonsa
               Chaetogammarus marinus
               Mytilus edulis (adults)
               Crassostera gigas

      SEDIMENT REWORKING SPECIES:
               Abra alba
               Echinocardium cordatum
               Polychaeta sp.
      Biodegradation:
      The OECD updated guidelines on marine tests  for biodegradation
      (BOD-28) should be followed. For mixtures there should  be  available
      data on biodegradation  (e.g. BOD) on all components  in  the mixture
      (above trace content), not for the total mixture.  %  degradation,
      time and method used have to be presented.
                                522

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The E&P Forum in London has been asked to establish  and administrate, this
data base and the plan is that a data  base  shall   be   operative  during
1990.  Ideally  the North Sea states would have  the  Cas.  No specified for
all components in a mixture  and  the  concentration of  all  components
within  %  intervals  (e.g.  <1,  1-2,  2-5,  5-10,   10-20,  20-40,  40-60,
60-100$). This information was, however, considered   to  be  confidential
information  by  the  industry  and  the  E&P  Forum would not store such
information in a data base with an open access.  Although such information
will  not  be  available  from the central data  base, it is expected that
most countries will ask the  operators  to  present   these  data  in  the
application  to  the  authorities.  If  the  producers  are not willing to
submitt such data to the operators they can send these  data directely  to
the  authorities.  In addition to the data specified in table 2,  national
authorities may require additional information to be submitted  -   on  a
confidential  basis  where necessary, e,g, 100#  chemical  composition.  For
this purpose trace contaminants are defined as less  than  0.01% -   ie  Iss
than 100 ppm.

-  the tests required
In  table  2, part IV are listed the marine species  which are included in
the  GOP* toxicity test system for offshore chemicals and   drilling   muds.
At  least  results from one species in each of the three  groups should be
presented to the authorities.

This list is based on information available from tests  that are operative
in  the North Sea states. The intention by this  system  is to minimize the
chance for a  toxic  product  to  pass  the  test system  without   being
classified  as  toxic.  The  following criteria  have been used; a product
should  be  tested  for  toxicity  against  marine   species   representing
different  feeding  types,  trophic levels and living biota,  see table 3-
Thereby the acute toxicity of products which are either   water  soluble,
lipid soluble or "sedimentophilic" should be detected by  the system.

Preferably   long —time   (chronic)  exposure   tests  under  "realistic"
conditions should be performed. Such tests would be rather  costly  and
time consuming.  As  a  compromice  it  was decided to base the approval
system on acute tests and try to harmonize against existing international
systems,  e.g.  the  OECD's test Guidelines. A marine fish test is  highly
recommended to be included in the system, but it has not  been  possible
for  the  group  to  specify  such  a  test  at  present due to restricted
availablitity of suitable tests  and  high  cost.  However,   there   is  a
recommendation   that  in  special  cases,  e.g.  planned  discharges  to
sensitive areas the authorities should require toxicity testing  on  fish
species relevant of the discharge area.

Until  the toxicity test systems are operative,  national  authorities will
accept test results from other tests covering similar group of test
•GOP - The Paris Commissions. Working Group on Oil Pollution.
                                 523

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organisms, trophic levels and feeding type   and   living  biota  as   those
presented in table 2 part IV, see also Quality Assurance.

The  authorities would preferably like to see the potential  environmental
hazard of the single products  and  mixtures discharged   to  the  marine
environment  after  being  treated offshore  (e.g. by high temperature and
pressure in the well). Since this "treatment" is  not easily  obtained in a
normal  laboratory, the regulation is focused on  the products  as they are
entering the offshore system. However, for planned  discharges  of   large
amounts  of  chemically  treated water, e.g. emptying of  pipelines,  tests
should be performed on the total mixture after a  simulation.

In addition to the toxicity tests, data from test on  biodegradation and
bioaccumulation  have to be presented. These tests should be based on the
OECD guidelines for such tests, table 2 part III.

The toxicity should be tested on the "whole" product if it is a mixure of
several  chemicals due to possible synergistic effects. The documentation
of accumulation and degradation should be for all  single  components  in
the mixture (above trace content).

Today  most  data  on  degradation  is  BOD  data on a whole product. This
information gives information on how much owygen is  used,  it  does  not
give  information  on  whether only some of  the components in the mixture
are degraded, or the change in toxicity is due to  degradation.  This  is
the reason why one ask for degradation information of all components.

                            TABLE 3
         Some of the criteria used in the evaluation and selection
         of species to be incorporated in the test system:
         FEEDING TYPE:        Filter- or deposite feeders,
                              grazers or predators  (hunters).
         TROPHIC LEVEL:       Primary producers, herbivours etc.
         BIOTOP:              Planktonic and benthic.
         SENSITIVITY:         High, low or insensitiv.
         REPRODUCIBILITY:     Important, but little info, avail.
         BEHAVIOUR:           Avoidance, closing etc.
         LETHAL/SUBLETHAL:    Subleathal are preferable.
         TEST DOCUMENTATION:  Publication of the test method.
         SIMPLICITY:          Which tests are comparatively simple?
         AVAILABILITY OF TEST ORGANISM: In laboratory culture or not?
- check points
Box  V  (Fig.2) is  a  check point to ensure  that all necessary information
                                 524

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is available and documented  by   test  protocols   and  results  from  the
authoriced  test-laboratories.  The  operator  should  at this point have
available information on several  products which could be used offshore to
solve  his  problem. The selection of  the "right"  product should be based
on a policy where the most "polluting  products" are avoided.

Hutagenicity and carcinogenicity  represent   a significant  problem  and
should   also   be  part  of  the evaluation  although  there  are  some
difficulties in testing and classification.  In the  decision  tre   these
items  should  be  evaluated  after degradation and accumulation has been
evaluated.

- application
If  the  operators  have  followed  the  decision   tree,    presented   an
application (box VI, Fig.2) with  all requirements  filled in (table  2)  and
documented test reports from test laboratories, it should be  a relatively
easy  job for the Authorities to  control the information given and  make a
decision regarding the specific application.  By contacting the EiP   Forum
data  base  the  Authorities  can check  that the  "best environmental"
products have been selected. If not the operator has to document why   he
has  selected another product. If the  authorities  is not convinced  by  the
operator another product has to be selected.                  ~

- decision
As a part of the scope, the  group  of experts should  try   to present
specific  criteria  for  decision  (box  VII  in   Fig.2)   of  "acceptable"
discharges. However, at this stage it  has  not been  possible  to   reach
concensus.  Several  aspects  are of  importence   for  the evaluation of
planned discharges. For instance  the following: due to variation in areal
sensitivity  one product may have acute toxicity,  biodegradation and bio-
accumulation potentials that are  acceptable  for one area,  but not  for a
more  sensitive  area.  It  may also occur that one product is acceptable
during one season, but not during another e.g.  due to migration of  birds,
fish  etc. Further it is very difficult to introduce one specific concen-
tration which is the limit for acceptable pass/not  acceptable.   This   is
due to several aspects, e.g. the  test  methods,  toxic kinetic,  species  etc

One  can  not  decide which products are acceptable for discharge into an
area only by considering  data  regarding  toxicity.  biodegradation  and
bioaccumulation, but environmental data from the potential influence area
hase to be taken into consideration. One ought to   carry  out  an  impact
assessment of the planned discharges - alone and in relation  to all other
activities and discharges influencing  the actual areas.

Within several international organizations there is  work  going on  for
identifying more and less "similar" selection/decision criteria, e.g.  the
Commission of the European Communities had a special meeting  this  summer
regarding  "The  setting  of  a   common  selection  scheme of  dangerous
                                525

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substances", the  Scandinavian  countries  are   preparing  a  system  for
classification  and labeling of environmental hazard products,  the MARPOL
73/78 Annex 2, and within the Oslo Commission there  is ongoing  work  for
evaluation  of  waste  dumping  to  the marine environment (6).  Hopefully
within some years a group of experts will be able  to present  a  list   of
criteria  that  can  be used as Guidelines both  for  the selection and  the
decision process.

Quality Assurance (QA)

This is an important part of this system. How can  users  and  authorities
be  sure  that  the  product actually contains what  is declared,  and what
requirements need to be enforced to ensure reliability on product  infor-
mation  and  test  results  -  e.g. can one rely on  test results  from  the
producers own test-laboratories, or are results  from  independent   test-
laboratories  needed? According to the group of  experts the  data  specifi-
cation in table 2, the Cas. No. and  concentration  intervals   are   basic
parts of the QA. Special fingerprints (spectra)  may  also be  required.

The  authorities  can  at  any  time  due  to  these data ask  for control
analysis  of  a  product  sold  on  the  market  and  check  whether  the
information  given  by  the producer/importer are  in accordance whith  the
commercial product.

The harmonized system requires that test laboratories receiving a product
for  testing shall check that properties specified by the producer  are in
accordance with  the  actual  sample  received   e.g.   melting  point  and
specific gravity. If discordance with the specifications are observed  the
product should be returned without any further'testing.

It has been decided thet the test laboratories either have to  present  a
GLP-documentation, or be approved by national authorities. Within each of
the four North Sea states  there  are  specific  institutions  which  are
authorized  to  give  GLP-documentation.  This   means that results  from a
producers  laboratory  can  be  accepted  provided  the  laboratory  has
GLP-documentation.  However,  normally  the  individual  authorities  can
require retesting or additional testing from independent laboratories.

Introduction of this harmonized system and performing of a ring test

This system entered into force from June 1990.   However,   the   first  two
years  will  be  a  test  period  which  will include a ring test for  the
toxicity tests and  laboratories  involved.  In  addition to   the   test's
presented  in  table  2  part IV, other tests can  be included  in  the ring
test if the appropriate laboratories pay the cost.

In 1992 the Paris Commission group of experts will meet again  and perform
an  evaluation  of  the  whole system - including  the data base.  Based on
                                526

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this evaluation a more permanent system will be proposed.

Denmark has kindly taken the  offer  to  act  as  lead  country   for   the
administration  of the ring test. However, each country, laboratories  and
the industry are expected to share the cost.  Four  test-substances  have
been  chosen  for the ringtest and the idea is that all tests should test
the effect of those four products; 3,5,dichlorophenol, Bioban P-1487 (EPA
reg.  no  48301-7),  Vantocil IB, and an oil based drilling mud Carbo  Sea
DMA. The first product is already a standard used by the  ISO  system  in
their  ring  test  for algaae. Bioban P-1487 and Vantocil IB are  biocids,
with a different fate in the environment. Vantocil IB is a  product  that
has  a tendency to adsorb to particles and thereforee be sedimentated  - a
"particulophilic" product.

Further research

This harmonized system as it is proposed is  not  "perfect".  It  is   the
intention  that  it will not be a static system, but improved and updated
as  soon  as  possible  when  new  sientific  results  makes   room    for
improvements.  The  group  of  experts  recommended  that research on  the
following items should be carried out:

- a fish test on marine species that can be performed all through the
  year.

- a combined toxicity and biodegradation test indicating what is degraded
  and the corresponding change in toxicity.

- a test for biodegradation on sparingly soluble products, e.g.
  surfactants which are difficult to test at present because they adhere
  to glass surfaces.

In addition I will personally  add  the  research  for  better  tests  on
bioaccumulation and especially for mixtures.

References

1.    J.M. Davies, D.R. Bedborough, R.A.A. Blackman, J.M. Addy, J.F.
      Appelbee, W,C, Grogan, J.G. Parker, A. Whitehead, The Environmental
      Effect of Oil-based Mud Drilling in the North Sea. In Proceedings
      of the International Conference on Drilling Wastes (F.R.
      Engelhardt, J.P. Ray, A.H. Gilliam Eds.) Elsevier Applied Science,'
      London and New York, 1989, pp 59-89.

2.    L.-O. Reiersen, J.S. Gray, K.H. Palmork, R. Lange, Monitoring in
      the Vicinity of Oil and Gas Platforms; Results form the Norwegian
      Sector of the North Sea and Recommended Methods for Furthcoming
      Surveillance. In Proceedings of the International Conference on
                                527

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      Drilling Wastes (F.R. Engelhardt, J.P. Ray, A.H. Gilliam Eds.)
      Elsevier Applied Science, London and New York, 1989, pp 91-116.

3.    T. Bakke, L.-O. Reiersen, J.S. Gray, Monitoring in the Vicinity of
      Oil and Gas Platforms, Environmental Status in Norwegian Sector
      1987-1989. In this Proceedings, 1990.

4.    B.S. Middledtich, Ecological Effects of Produced Water Effluents
      from Offshore Oil and Gas Production Platforms, Ocean Management.
      9, 1984, 191-316.

5.    A.E. Girling, An Assessment of the Environmental Hazard Assosiated
      with the Discharge of Production Water from a North Sea Oil
      Platform Based on Laboratory Bioassays with a Calanoid Copepod -
      Acartia tonsa (Dana). In Proceedings of the Conference on Oil
      Pollution Fate and Effects of Oil in Marine Ecosystems (J.  Kuiper,
      W.J. van dan Brink Eds.) . Martinus Nijhoff Publishers, Dodrecht,
      Boston, Lancaster, 1987, pp215-2l6.

6.    M.C.T. Scholten, C.T. Bowmer, J.M.A. Janssen, W.C.de Kock,  M.
      Molag, G.J. Vink, M.P. van Veen, An Appraisal of Marine Waste
      Dumping Criteria Based on Risk Analysis and Ecological Effects.
      Netherlands Organization for Applied Scientific Research,
      TNO-report nr: R 89/034.

APPENDIX 1:
The  following  persons  participated at the Paris Commission workshop in
Oslo, November 1989. where the harmonized system was discussed before the
final preparation was done by Norway.

United Kingdom:                   Denmark;
R.A.A. Blackman, MAFF.           E. Bjflrnstad, VKI.
L. Massie, DAFS.                 M. Robson, MoE.
P. Worthington,  DoE.             P. Wrang, Milj0styrelsen.

The Netherlands;                 Norway;
A. Hanstveit, TNO.               G. Halm0, SINTEF.
L.R. Henriquez,  MoEA.            T. Kaellquist, NIVA.
P. Meertens, NSD.                G.M. Skeie, CMS.
K. Meijer, MoE.                   T. Stromgren, BIOCOSULT.
                                 T. Syversen, UoT.
Sweden:                          F. Thingstad, UoB.
M. Tarkpea, SNV.                 I.G. Engeland, SFT.
                                 L.-O. Reiersen, SFT.
E&P Forum:
W.de Ligny, Shell.               IMP;
A.D. Read, E&P Forum.            M. Watanabe, IMO.
J.A. Hansen, Statoil.


                                528

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HAZARDOUS WASTE TREATMENT/RESOURCE RECOVERY
VIA HIGH TEMPERATURE THERMAL DISTILLATION
TOM F. DESORMEAUX
Inventor and C.E.O.
T.D.I. SERVICES, INC.
Baton Rouge, Louisiana
BRIAN HORNE
General Manager
Marketing & Environmental Affairs
T.D.I. SERVICES INC.
Baton Rouge, Louisiana
INTRODUCTION

TEST BURNS/AFTER BURNERS/SCRUBBERS/ASH/OXIDIZED METALS/PUBLIC
HEARINGS/TREATMENT PART B PERMITS/CARCINOGENIC EMISSIONS/ACID
RAIN/N.I.M.B.Y. (Not In My Back Yard)

The   preceding   subjects    have    traditionally   been   associated     with   the
hazardous  waste  treatment  alternative,   high  temperature  incineration.  Until
recently,   incineration  has   been   the  preferred  method  of  treatment.   The
process,  however,  by which a waste  generator  must  go through  in order  to
implement  incineration   is  extremely  tedious,  time  consuming,  and,  in many
geographic   areas,  is  simply  an  impossible   task.  The U.S. E.P.A.'s ban  on
the  disposal    of  organics   in land  fills  has  put  additional  pressure    on
industry  to remove  the  organics   from  waste  prior to  it's  ultimate  disposal
and  to perform  the  task  in  a fashion   which  is  acceptable   to  the  general
public.  As a  result,  increasing  emphasis  is  being  put  on the use  of recy-
cling   processes    which  both  meet  the  E.P.A.'S  disposal   restrictions   and
can    be   readily    implemented.    The  Tom   F.   DesOrmeaux     process
accomplishes these tasks in an unprecedented fashion.

The  Tom  F.  DesOrmeaux   Technology   (HT-5  Thermal  Distillation  Process),
subjects  hazardous   waste   to electrically   generated   heat  in  a  nitrogen   at-
mosphere.  The HT-5 distillation  system   is  designed  to  vaporize   compounds
via three  segregated    distillation   chambers   and  recover,  via condensation,
the  segregated   effluents   (e.g.   oil,  water,  and   solids).     This  dynamic
process, therefore, can be utilized for the purpose of segregating any


                                    529

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hazardous   compound   with a  boiling  point  of 100  degrees
grees F. from the non-hazardous compounds in a waste product.
F. to  2100  de-
In  June,   1989,   Tom  DesOrmeaux    licensed   the   technology    to  Browning
Ferris  Industries   for  use   in  the  forty-eight  (48)  contiguous   states   of the
U.S.A.   In addition,  T.D.I. Services,  Inc. was  issued   the license   to construct
the HT-5 and offer technical support for its various applications.


PROCESS DESCRIPTION

The  HT-5  Thermal   Distillation   Unit  is   designed    to  meet   the  highest
standards    of  construction   and  safety.   All  electrical  systems   are  designed
to  Class   1,  Group  D,  Division   2  specifications.    AH  piping  follows  ANSI
D31.3  guidelines,   and   all  pressure   vessels   are   designed   hi  accordance
with ASME Section 8.

The  process  accepts  contaminated   hydrocarbon   bearing  waste   in  an  initial
dump  bin.  Hydraulic  powered  augers  transport   the  waste   into  a  feed silo
where   further  mixing   and  equalization    of  flow  occurs.   At  this   point,  a
nitrogen   atmosphere   is  introduced   and  the entire  system   is   sealed   until
the  segregated    effluents   leave  the system.    The feed silo   utilizes  a  transfer
auger   to,  again,   transfer  the   waste   into  a   feed   hopper   where  it   is
apportioned to three parallel distillation sections. (See Diagram #1).
    T F DitOrmtavx Ttctmology

        MODEL  HT-V
        ORTMOOIWMC WftESCrfUTW
  Diagram #1
            DISTILLATION SKID
                                     SEPARATION SKID
                                       530

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By using  gravity  and  a  system   of annular  augers,  the  waste  is transferred
through three  externally  heated   distillation   heating  chambers   which  operate
in senes.    (See  Diagram  #2.)   The  continuous   introduction
sweep   gas  creates   a   low   pressure   (below   atmospheric)
atmosphere   prevents   combustion/oxidation     and   facilitates
porization of volatile and semi-volatile compounds.
 of  a  nitrogen
condition.   This
the   rapid  va-
                                                                   3 PHASE SEPARATOR
                                                                °Ł  2HMWAMTI

                                                               CUENT
                              INERT  SOLIDS
    T. F. DesOrmeaux Technology

        MODEL HT-V
        DIAGRAMMATIC FLOW REPRESENTATION
 Diagram #2
                                                                          TO FLARE
                                       531

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The  waste  temperatures   and   resulting   conditions   for  each   of the  three
heating chambers are as follows:

       PROCESS          WASTE
       SECTION          TEMPERATURES            RESULTS

       Zone #1             Ambient to 400° F.               Volatilization of water &
                                                       light hydrocarbons

       Zone #2             400° F. to 900° F.               Volatilization of
                                                       remaining water and
                                                       light hydrocarbons

       Zone #3             900° F. to 2100° F.               Volatilization of
                                                       remaining
                                                       hydrocarbons


Specific   operating  temperatures   vary  with each  waste   stream;  however,  the
ability  to  operate  at  up  to 2200 degrees   F. results   in maximum  efficiency
and versatility.

Exact temperatures,   pressures,    and flows  are  electronically   monitored  and
controlled   via   over  1000   separate    points   throughout   the  HT-5  process.
Data  is represented in a graphics-based operator interface system.

The  final  inert  solid  effluent  stream  leaves   the HT-5  through  an  exit  port
after   the third  heating  chamber  and  is  transported  by  a  conveyor   cooling
auger  to  a  collection   bin  for  ultimate   disposal.     The gases   from  each
distillation   chamber   are  sent  to a  cyclone/dust   control  system  for  particle
removal.   After  the cyclones,   the gases   are gathered  and moved  through  an
air cooled  condenser,    which  lowers  the  gas   temperature   to  20  degrees   F.
above   ambient    air  temperature.    A  series    of  two-   and   three-   phase
separators   segregate    three  different   liquid  fractions   from  the  remaining
gases.    The  degree   of separation    can  be  increased    or decreased   and  is
dependant upon the application and required specifications.

The  light and heavy oils,  as  well  as  other recyclable   materials,  can  be  re-
turned to  the customer,  separately    or combined,   to be  used   as  fuel oil  or
refinery   feed   stock.    Recovered   water  is   typically   returned  to  the  cus-
tomer's API Separator or further treated for ultimate discharge.

The  remaining   gases    from  the separation    process   are  then  compressed,
dried,  and  refrigerated    at  -30  degrees    F.  in  order  to  recover  liquefied
petroleum   gases  (LPG's)  which  are   also   returned  to  the  customer.  The
remaining   nitrogen-rich  gases   are  recycled   with  a  small  percentage   being
sent to flare  or a fuel gas system.
                                       532

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APPLICATIONS

The  HT-5  Thermal Distillation   system   is  ideally  suited   for  and  capable   of
treating materials  with  solid  contents   ranging  from  10%  to 90% and wastes
with oil  contents  ranging  from 0% to  60%.  The  system   will readily  accept
and  process   solids   ranging   in  size   from  sub-micron    up  to 1.5  inches.
Consequently,   the  versatility  of the  process   allows  for  its application   to a
wide variety of waste products.

The  HT-5  system's    modular   characteristics    allow   for  the  sizing  of  the
system  based   on  site  specific   throughput requirements.   Typical  throughput
capacities range between 30 tons and 400 tons per day.

Specific  applications   for  the   process   have  been  identified   and  full scale,
as   well   as   pilot  scale   treatability   tests,   have   been   performed.   These
applications    are  E.P.A.   listed    refinery  wastes    KO-48  through  KO-52,
creosote    contaminated    soils,   hydrocarbon    contaminated    soils,    mercury
contaminated   soils,   and  oil   and gas   exploration   wastes.   Analytical   data
generated   from  processing   these   hazardous   wastes  document  that  the  pro-
cessed   inert   solid   effluent   contains   non-detectable     concentrations     of
volatile  and   semi-volatile   hydrocarbons.   This degree   of hydrocarbon    re-
moval will allow  for  the continued  land  disposal   of refinery  wastes   beyond
the August, 1990 land ban date.

The  benefits    of  the  process    are   numerous.   When   applied  to   refinery
wastes, the benefits include:

    1)    The  system's   reuses   of the  nitrogen sweep   gas resulting   in the
          process possessing an insignificant source of air emissions.

    2)    Over 99.9% oil removal  and subsequent recovery.

    3)    No oxidation  of heavy metals.

    4)    The ability to exceed land ban parameters on refinery wastes.

    5)    The   process    can  be   utilized   as   a  recycling/resource    recovery
          system   and   can  qualify  for exemptions    from  Federal  and  State
          treatment permits in a variety of applications.


CASE STUDY/DEMONSTRATION

A  comprehensive   case   study/demonstration     has  been   performed   utilizing
the  HT-5  Thermal  Distillation   system.    The  rated   throughput  capacity  of the
demonstrated    system    is  thirty  (30)  tons  of  sludge   per  day.   The  demon-
stration  was   witnessed   by a  major  oil  company  as  well  as  a third party
consulting firm, Law Environmental. As an unbiased third party, Law


                                      533

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Environmental^   task   was  to  insure  that all  samples   were  collected   and
analyzed   according   to   an  approved  Quality   Assurance   Project  Plan.  In
addition,   Law   Environmental   applied   a   QA/QC  concept   encompassing
sample collection through data validation.

WASTE DESCRIPTION

T.D.I. Services,   Inc.  demonstrated    the   HT-5's  hydrocarbon   removal   and
recovery   capabilities    by  processing    simulated    refinery   API  separator
sludge.   The  simulated  waste  was  prepared  by  adding  approximately  fifteen
(15) percent  Alaskan   North Slope  crude   oil  to  oil-based   drill  cuttings.   Top
soil,  diatomaceous    earth, and  drilling   gel   were  also  added   in  order to
raise the solid content and further emulsify the mixture.

ANALYTICAL DATA

Five  separate   sample   sets   of  the  waste   and  inert  solid  effluent   were
obtained   during  two consecutive    days   of  operation.   As  Tables   1  &  2
indicate,   three   (3)   of   the  five    (5)    treated   residue   samples    show
non-detectable    concentrations    of  volatile,  base/neutral,   and  acid   extractable
hydrocarbons.   The  data   also  shows   that  the lower  processing   temperatures
associated   with samples   three (3)  and  four (4)  did  not result  in complete
hydrocarbon   removal  even  though   the   concentrations    observed   are   well
below    the   land   ban    criteria.    (Specific    operating   temperatures    are
considered confidential by T.D.I. Services, Inc..)

In  addition  to  the  samples  represented    in  Tables  1  & 2,  numerous  other
samples    were  obtained   including   recovered   oil,  recovered  water,  recycled
sweep gases, and flare gases.

The on-line  gas  chromatograph   analyses   of the  sweep   gases    (which  are
representative   of the  gases  going  to flare)  indicated  no hydrocarbons   at  a
detection    limit  of  ten   (10)   ppm   (v/v)  for  ethane.   The  Tenax   sorbent
samples,   collected    immediately    after  the   GC analysis   were   performed,
were   then analyzed  several   days   later  by  GC-MS.  The samples   contained
no  detectable   volatile organic  compounds   at a  detection  limit  of 0.25  ppm.
The particulate  emission    levels,  monitored  at the  flare,  were  well below the
allowable   Texas   Air Control  Board  Regulations   for  particulate   emission
rates from any source.

Oil and  water  sample  analyses   indicate   efficient   recovery.   The quality  of
the  oil   and  water   is  such  that  the water  can  be  returned   to   the  API
Separator and the oil  can be returned to the refinery for refinement.
                                       534

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SUMMARY

The  HT-5  Thermal  Distillation   system    performed   as   designed   and  as
represented.    The  demonstration   not  only  documented   the  ability  to  meet
the  E.P.A.'s land  disposal    restrictions;   it  was   demonstrated   that the  total
removal  and  recovery   of  hazardous   hydrocarbon   constituents    from  both
simulated   refinery  waste   and   oil-based   drilling   wastes    can  readily  be
achieved.

Waste  retention  tune  and  the  amount  of Btu's  subjected   to the  waste  are
the  two  (2)  parameters   that control  the  degree   of removal   and  subsequent
recovery  of  various constituents.   It  was  demonstrated   that both  parameters
can  be controlled   to  an unprecedented   degree.   Therefore,  as  the numerous
pilot  scale   treatability   studies   indicate,  the  majority  of  the   hydrocarbon
contaminated   wastes   generated   by  the  petroleum   industry   and  the  wood
treating  industry   can  be  processed   by  the  HT-5 High  Temperature  Thermal
Distillation   system.   The  HT-5  Thermal  Distillation   system   will  render  the
inert  solid  effluent  stream  acceptable   for  land  disposal   and  will  allow for
the recovery of valuable and reusable hydrocarbons.

A  simple    and   effective   rule  of  thumb   to  expeditiously    evaluate   the
applicability of the technology to a specific waste is as follows:

    1.  Do the  "hazardous"  constituents   have  a  boiling  point  in  the range  of
       ambient to 2000 degrees F.?

    2.  Can   particle   size    ranges    of   sub-micron   up  to  1.5  inches   be
       achieved?

    3.  Is  the  liquid  concentration   in  the  waste  less   than  ninety-five   (95)
       percent?

If the  answers  to all of the preceding  questions  are  yes,  the  HT-5 Thermal
Distillation   is   most   likely  the   solution   for  waste   management.      The
versatile   characteristics   of  the  HT-5 Thermal Distillation   system  is the key
to implementing the technology on various wastes/applications.


1*ILOT SCALE TREATABILITY STUDIES

T.D.I. Services,  Inc.  has  performed   numerous   treatability   studies   via the
HT-5  Pilot   Scale  Unit  (P.S.U.).  P.S.U.   treatability   studies    have   been
performed   on  a  number  of refinery  generated   wastes,   Superfund  creosote
contaminated   wastes,    mercury   contaminated    soils,   as   well  as  oil-based
drilling  wastes.  Every  study performed  has   demonstrated   that the removal
and subsequent recovery of the specified contaminant was achieved.
                                       535

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The  P.S.U. utilizes   a single   heating  chamber   in  which  waste  is  subjected  to
indirect  heat  and  the nitrogen  sweep   gas.  The  temperature  and sweep  gas
volumes   are  varied  and  controlled   in  order  to  determine  the parameters
required   to  produce   acceptable   constituent   removal.   The  P.S.U.   also
utilizes   three  (3)   vapor  condensing    stages   for  further  evaluation.   Gases
which  do  not condense  are monitored   and  analyzed  with  the  use  of a  Gas
Chromatograph.   Typical   sample   sizes   required   to  perform  studies   are
two-three (2-3) kilograms of waste.

In order to  document  the  design  equivalency  and  the ability  of the  P.S.U.
to provide   scale-up   data   correlating  to  the  treatment  capability  of the full
scale   HT-5  Thermal  Distillation   system,   a  study  paralleling   the full scale
demonstration   was  performed.  The   study  was   performed   on a split  waste
sample   obtained   during  the  full scale   HT-5 demonstration.   The  analytical
results   are  represented   in  Table  1. The  results   from the  study  indicate  that
the  P.S.U.  does,   in  fact,  allow   for  the comprehensive    evaluation   of the
HT-5's capabilities as applied to various wastes.

There    are    numerous     other    applications    for   the   technology.       The
applications    currently   being   reviewed    include    dioxins,   Turans,   spent
activated  carbon,   municipal   wastes,   radioactive   mixed   wastes,   asbestos,
synthetic rubber, and tires.

Industries which are potential candidates for the technology are  as follows:
Agricultural Chemicals
Lumber & Wood Products
Machinery & Mechanical Service Industry
Nuclear Facilities
Organic Chemicals
Paints & Allied Products
Petroleum & Coal Distribution Industry
Petroleum Exploration
Petroleum Refining
Pharmaceuticals
Plastics Materials & Resins
Pipeline Industry
Pulp & Paper
Soaps and Detergent Industry
Surface Active Agents
Synthetic Rubber
Textile Mills
Currently,  there  are  treatability  studies   planned   for  wastes   contaminated
with  dioxins,   PCB's,  furans,  chlorinated   phenols,  and  mixed  radio  active
wastes.
                                       536

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                TABLE 1
LAW ENVIRONMENTAL CASE STUDY (EXCERPT)
\
PARAMETERS
Oil & Grease (ug/g)(wet weight)
PH
Specific Gravity, g/ml (Density)
Water, Karl Fiaher, %
Volatilei (mg/kg):
Acetone
Acrolein
Acrylonitrile
Benzene
Bromodichloro me thane
Bromoform
Bromomethane
2-Butanone
Carbon disulflde
Carbon tetrachloride
Chlorobenzene
Chloroe thane
2-Chloroethylvinyl ether
Chloroform
Chloromethane
Dibromochloromelhane
Dibromomethane
1 ,4-Dichloro-2-butene
Dichlorodifluoromethane
1 , 1 -Dichloroetha ne
1 ,2-Dichloroe thane
1,1-Dicloroethene
trans-1 ,2-Dichloroethene
1 ,2-Dichloropropane
cis-1 ,3-Dichloropropene
1TT-5
Feedstock
1/23/90
14:45
139,600.0
, 8.0
' 1.53
24.6

<12.5
<25.0
<25.0
284.0
<6.25
<6.25
<12.5
<25.0
<6.25
<6.25
<6.25
<12.5
<25.0
<6.25
<12.5
<6.25
<6.25
<6.25
<12.5
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
#1
Treated Residue
1/23/90
15:05
62.8
10.2
2.37
0.4

<0.010
< 0.020
< 0.020
< 0.005
< 0.005
< 0.005
<0.010
< 0.020
< 0.005
< 0.005
< 0.005
<0.015
< 0.020
0.005

-------
TABLE 1 (cont.)
PARAMETERS
trani-1 ,3-Dichloropropene
Ethanol
Ethyl benzene
Ethyl methacryltte
2-Hexanone
lodome thane
Methylene chloride
4-Methyl-2-pentanone
Styrene
1 , 1 ,2,2-Tetrachloroethane
Tetrachloroethene
Toluene
1,1,1 -Trichlocoethane
1 , 1 ,2-Trichloroelhane
Trichloroethene
Trichlorofluorome thane
1 ,2,3-Trichloropropane
Vinyl acetate
Vinyl chloride
m-Xylene
o,p-Xylene
Base/Neutrals (mg/kg):
Acenaphthene
Acenaphthylene
Acetophenone
Aniline
Anthracene
4-Aminobiphenyl
Benzidine
Benzo(a)anthracene
Benzo(b)fluoranthene
HT-5
Feedstock
1/23/90
14:45
<6.25
<25.0
290.0
<6.25
<25.0
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
617.0
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
<12.5
240.0
595.0

<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<19.6
<9.8
<9.8
#1
Treated Residue
1/23/90
15:05
< 0.005
< 0.025
<0.005
< 0.005
< 0.020
< 0.005
<0.005
< 0.005
< 0.005
< 0.005
< 0.005
< 0.005
<0.005
< 0.005
< 0.005
< 0.005
< 0.005
< 0.005
<0.010
<0.005
<0.005

<0.10
<0.10
<0.10
<0.10
<0.10
<0.10
<0.20
<0.10
<0.10
HT-5
Feedstock
1/23/90
19:15
<6.25
<25.0
312.0
<6.25
<25.0
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
630.0
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
<12.5
243.0
606.0

<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<19.6
<9.8
<9.8
#2
Treated Residue
1/23/90
19:48
<0.005
< 0.020
<0.005
< 0.005
<0.020
< 0.005
< 0.005
< 0.005
< 0.005
< 0.005
< 0.005
< 0.005
< 0.005
<0.005
< 0.005
<0.005
<0.005
<0.005
<0.010
<0.005
<0.005

< 0.099
< 0.099
< 0.099
< 0.099
< 0.099
< 0.099
<0.20
<0.099
< 0.099
HT-5
Feedstock
1/24/90
09:05
<6.25
<25.0
249.0
<6.25
<25.0
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
644.0
<6.25
<6.25
<6.25
<6.25
<6.25
<6.25
12.50
242.0
624.0

<10.0
<10.0
<10.0
<10.0
<10.0
<10.0
<20.0
<10.0
<10.0
#3 Page 2
Treated Residue
1/24/90
09:45
<0.005
< 0.020
<0.005
< 0.005
< 0.020
< 0.005
<0.005
< 0.005
< 0.005
<0.005
< 0.005
0.005
< 0.005
<0.005
<0.005
< 0.005
< 0.005
<0.005
<0.010
< 0.005
< 0.005

<0.10
0.56
<0.10
<0.10
<0.63
<0.10
<0.20
0.36
<0.10

-------
TABLE 1 (cont.)
PARAMETERS
Benzo(k)fluoranthene
Benzo(g,h,i)perylene
Benzo(i)pyrene
Benzyl butyl phthalate
Bis(2-chloroethoxy)meth»ne
Bis(2-chlorelhyl)ether
Bis(2-chloroisopropyl)ether
Bis(2-ethylhexyl)phlhalate
4-Bromophenyl phenyl ether
4-Chloro«iuline
1 -Chloronaphlhilene
2-Chlora naphthalene
4-Chlorophenyl phenyl ether
Chrytene
Dibenzo(a J)acridine
Dibenzo(a ,h)anthracene
Dibenzofuran
Di-n-butyl phthalate
1 ,2-Dichlorobenzene
1 ,3-Dichlorobenzene
1 ,4-Dichlorobenzene
3 ,3 '-Dichlorobenzidine
Diethyl phthalate
Dimethyl phthalate
p-Dimethylaminoazobenzene
7, 12-Dimethylbenz(a)anthra
a,a-Dimethylphenethylamine
2,4-Dinitrotoluene
2,6-Dinitrotoluene
Di-n-octyl phthalate
Diphenylamine
HT-5#1
Feedstock Treated Residue
1/23/90 1/23/90
14:45 15:05
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<19.6
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<0.10

-------
TABLE 1 (cont.)
PARAMETERS
1 ,2-Diphenylhydrazine
Fluoranlhene
Fluorene
Hexachlorobenzene
Hexachlorobuladiene
Hexachlorocyclopentadiene
Hexachloroe thane
lndeno(l ,2,3,cd)pyrene
Isorphorone
3 ,Melhy Icholanthrene
2-Methylnaphthalene
Methel methanesulfonale
Naphthalene
I-Naphlhylamine
2-Naphlhylamine
2-Nitroanaline
3-Nilroanaline
4-Nilroanaline
Nitrobenzene
N-Nitrosodi-n-butylamine
N-Nitrosodimethylamine
N-Nitrosodi-n-propylamine
N-Nitrosodiphenylamine
N-Nitrosopiperidine
Petachlorobenzene
Pentachloronitrobenzene
Phenacetin
Phenanthrene
1 2Picoline(2-methylpyridine)
Pyrene
1 ,2,4,5-Tetrachtorobenzene
HT-5#1
Feedstock Treated Residue
1/23/90 1/23/90
14:45 15:05
<9.8
<9.8
10.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
153.0
<9.8
87.9
<9.8
<9.8
<39.2
<39.2
<39.2
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<19.6
<9.8
36.7
<9.8
<9.8
<9.8
<0.10
<0.10
<0.10
<0.10
<0.10
<0.10

-------
                                                                         TABLE 1 (cont.)
PARAMETERS
       HT-5 #1
Feedstock     Treated Residue
1/23/90       1/23/90
14:45        15:05
       HT-5 #2
Feedstock     Treated Residue
1/23/90       1/23/90
19:15        19:48
        HT-5 #3
Feedstock    Treated Residue
1/24/90      1/24/90
09:05        09:45
                                                                                                                                                                 PageS
1 ,2,4-Trichlorobenzene
Acid Exlractahles (mg/kg):
Benzole acid
Benzyl alcohol
4-Chloro-3-methylphenol
2-Chlorophenol
2,4-Dichlornphennl
2,6-Dichlorophenol
2,4-Dimethylphenol (Xylenol)
2,4-Dinilrophenol
2-Methyl-4,6-dinilrophenol
2-Methylphenol (o-Cresol)
4-Methylphenol (p-Cres«l)
2-Nilrophenol
4-Nitrophenol
Pentachlorophenol
Phenol
2,3,4,6-Telrachlorophenol
2,4,5-Trichlorophenol
2 ,4 ,6-Trichlorophenol
<9.8

<49.0
<9.8
<9.8
<9.8
<9.8
<9.8
<9.8
<49.0
<49.0
<9.8
<9.8
<9.8
<49.0
<49.0
<9.8
<9.8
<9.8
<9.8
<0.10

<0.50

-------
INTERNATIONAL ASPECTS  OF WASTE MANAGEMENT, AND  THE  ROLE OF THE UNITED
NATIONS ENVIRONMENT PROGRAMME  (UNEP)
Fritz Balkau
Senior Programme Officer
United Nations Environment Programme
Industry and Environment Office
Tour Mirabeau
39-43 Quai Andre Citroen
75739 Paris Cedex 15
France
 Introduction

 The  production of oil  and  gas industry is  indisputably  a world scale
 industry,  whatever  criteria  we  use.    With an  annual  production of
 around  half   of   the  world's  energy  demand  the  industry  employs
 thousands  persons   worldwide,   and  transports  large  quantities  of
 product  over   long  distances.    Oil companies  are  the largest  of  the
 multinationals, with diversified  activities  worldwide.

 This  importance  carries  over  into  the  environmental  sector.    The
 environmental  impacts  of  the  industry are considerable,  whether in
 terms  of  size  of individual  accidents, or in aggregated  volumes of
 residues   released   from normal  operation.    The  industry  features
 prominently   in  the   environmental   literature.     And   among  the
 environmental  issues confronting the  industry waste management is  near
 the  top of the  list.

 Waste management  is however a  fairly  loose term.   Depending on one's
 point  of  view it   can  range   from standard  notions  of  disposal of
 production residues  to  also   include  clean-up  of   spills,    site
 reclamation,  and  control  of  air emissions.   It  can even  extend to
 release  of carbon dioxide, which is  beginning to  affect our climate.
 As  cradle  to  grave concepts  of  waste management  now  consider  the
 impact  from  products themselves,  the  conception,  use  and disposal of
 the  products of the  industry is  brought  into question.

 However  it is not only  the  scientifically  predicted ecological  impact
 that  is   important  to  waste   management.    National  perceptions to
 pollution  issues  vary greatly,  and are often  coloured  by perceptions
                             543

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of who  and  where the causes  of  such pollution are.   We should not be
surprised  that  there  is  a  high  intolerance  to  pollution  impacts
imposed  from abroad.   From  the  NIMBY  syndrome  we  already  know that
there  is  a  resistance  to  accept  local  impacts  for  the   sake  of
beneficiaries who are far away.

While  the  cause  and effects  of  environmental  impact  can  be  readily
identified,  those who are concerned with putting the global house into
better  order  are less well  known.   It  is  the  purpose of this paper to
outline  some of these  actors,  and  the  scope  of  their  programmes,  in
the hope  that better knowledge will also  eventually encourage better
contributions  to,  and enhanced performance of,  global  initiatives  of
waste management in  the oil and gas  sector.
Waste ManaEement Issues of International Concern

Let  us  briefly  look  at  some  of the  most  significant  international
issues which are relevant to the management of wastes.

Waste dumping  in international waters  is  one of  the  most  visible and
controversial  environmental   issues  wordwide.    Wastes   which  are
currently  dumped at  sea  include  toxic chemicals,  sludges, muds  and
solid waste,  oily  bilge waters and  ship cleaning  wastes,  and garbage.
Derelict offshore structures,  debris and equipment left on the sea-bed
interferes  with  fishing  and  other  uses.   All  these  add up  to  a
significant problem  in the  marine environment, with many  impacts also
felt on the coast.

A particularly pernicious aspect  of  waste  disposal in  recent years has
been  the   trade  in  industrial waste  which  we  cannot,  or will  not,
dispose of  at  home.    The argument  to support such trade  is sometimes
dressed  up  in  the  purported  economic  benefits  to  the  recipient
country, or  thai: in such and  such  a place the effect is  not harmful.
The motives  however  are seldom that benign.   No-one  engages  in waste
trade for  reasons  of charity.   Recipient  countries are as stigmatized
by this practice (even if  it were to be made technically  sound,  which
it never  is)  as would  be our  own communities  if  they were  to  be the
destination.

Waste dumping  is a particular example  of  the larger  issue of unequal
environmental  practices adopted  abroad   by  multinational  companies.
While many  large companies  have  now moved to redress this disparity,
it  remains  to  be   seen  how such  policies  influence   also  their
contractors, supply agents,  and local business partners.

Improved management  of wastes  has  also become  a component  of  larger
trade issues.    Transfer  of technology to developing countries  is  a
                             544

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sensitive  issue  on which  there  is  as  yet  no  consensus.    Cleaner
production processes  and better treatment methods  are  included in the
technology transfer agendas.   Better access  to, and  favorable terms
for  purchase   of,   such  technologies  is  increasingly  demanded  in
international negotiations.

The  newest  and  most  controversial  transnational  issue  is  that  of
climate  change.    The  link  between global  warming  and  industrial
emissions  is now  strong enough to  justify action.   As  the greatest
part of  the  world  production  of  oil and gas  is burnt as  a  fuel,  the
industry's contribution  to  anthropogenic  C02 is  not negligible.  Other
emission products  such as  S02  may  contribute to  the regional occurence
of acid rain.

All  the  above  must of  course be seen  in  the  context also  of local
impact from  waste  disposal operations.    In most instances  the local
effects  are  the  most acute.  Local  disposal  practices  determine  the
extent of  the  impact  there on humans and  the  ecology,  including  the
protection of  human  living resources.   Good  management at  the local
level will often  (but not always -  remember  the tall  stacks policy)
avoid also international problems.

Addressing International Issues - Institutions.
Responsibilities.  Programmes.

In  considering  how environmental  problems are best  resolved it  is
necessary  to keep in mind the diverse nature  of the  industry, and its
ubiquitous   location.    Large  multinationals  have  the  skills,  the
technology,  the  financial  means,  and the  organization necessary  to
take remedial  action.  Smaller companies  lack some of these attributes
and  therefore  contribute less well.   In developing  countries also,  a
simultaneous   shortage  of  information,  technology  and  organization
inhibits effective action, exacerbated by  a generally lower  level  of
management awareness  of  the need to  do  so.   This  leaves  the problems
at   the  local  level  more  acute,   and   simultaneously   less  of   a
contribution   is   made  to  international  action.     Overcoming  such
constraints  is   an  important  part  of   international  environmental
programmes.

In  order  to address  problems  of global  dimensions  we often  need  new
procedures,   and   new  organizations.     National   regulations   and
administrative  procedures  are  difficult to  apply  in  the international
arena  without  extensive  modification.     New  legal  structures  have
therefore  been created  to fill the  gap.   A number  of  international
conventions  and agreements already  exist for the  marine environment,
for  hazardous  waste,  and  more  recently   for   protection  of  the
atmosphere.   Implementation of international  agreements  however rests
                             545

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with   national   agencies,    using   new   provisions   under   national
legislation.

An  example   of  a   successful   convention   is   the  London  Dumping
Convention.    This  specifically  states what  can  and what  cannot be
dumped at  sea by the  signatory  parties.   The convention has  recently
moved  to  also address  land-based sources  of  pollution.   Other   more
regional  conventions  apply  to  the  North  Sea,  the  Baltic,  and the
Mediterranean,  and  cover such issues  as ocean  dumping and  land-based
sources of pollution.   Another  convention,  MARPOL,  is  well known by
ship owners.

Of  special   interest  in  hazardous  waste  management   is   the   Basel
Convention  (see  annex   1).     This  limits  international  trade  in
hazardous  waste, and addditionally  makes  a  strong  demand  for less
waste  to  be produced, and  for residues to be disposed  of as close to
the point  of  generation  as  possible.   There are now also  proposals for
a  forthcoming  convention  on climate  change, which  could  include  a
limitation on  C0Ł  production.   A  number  of countries  have  already
pledged to limit  future  C0Ł emissions.

Conventions and  codes  of practice  are  useful in agreeing  on  goals, but
they  are   less  specific  about how  the goals  are  achieved.   National
legislation   and  company   programmes   to  implement   conventions  vary
greatly in format and  in substance.   Each country  is  constrained by
its political and legislative system,  and of course  by  consideration
of economic  implications.   While developing countries contribute  their
share  of   waste  problems,  they  often  lack many  of the  technical and
managerials  skills  to overcome  them,   and  frequently do  not have the
economic means  that are  available to industrialized nations.

While  not yet  extensively  subject  to   international   agreement (or
perhaps  because  of  this lack)  the question  of disparity  in applied
environmental standards  needs to be tackled more creatively.  There is
a much greater diversity of  global circumstances  than is found at the
national  level.   We  need to  be  clear  about  the  implications of  "equal
regulatory standards",  whether applied  by  a  government  or   by  a
company.    Equal  standards may  not always  be  appropriate.    What is
actually    required    is   equal   environmental    goals,   and    equal
environmental performance,  defined according  to  local objectives, but
consistent with wordwide practice.

A  simple   example will  suffice.    A company  environmental policy 'that
assumes the  availability of  skilled disposal  contactors may work well
in  the  US   or   in  Europe,  but   is   totally inappropriate  in most
developing countries.   A  policy  of  equal  environmental performance
implies a  proportionally greater degree of company  self-reliance  where
                              546

-------
infrastructure is poor.   A policy of equal standards merely passes  the
buck to someone unprepared  to handle  it.

A  prerequisite  to  the  adoption  of  conventions   and   standards   are
activities  such  as  technical   assistance  and   information   transfer.
These   activities   are   essential   if   individual   corporations   and
government  agencies,  especially  in  developing  countries, are  to  act
effectively and cohesively.

Most intergovernmental  organizations already incorporate  environmental
considerations, and quite a few have explicit environmental assistance
and  information programmes.   In many  cases environment  is  not their
only  responsibility,  however.    UNEP  was created  in  1972  as  a   co-
ordinating  agency  to harmonize  the environmental  initiatives  of  UN
agencies.    Along  the   way  UNEP   launched  international  monitoring
programmes  such as GEMS,  and  an information exchange  system based on
INFOTERRA.    A  regional  seas   programme  specifically   addresses   the
marine  environment.  The Industry  and  Environment  Office (IEO) as  its
name  implies  deals  specifically  with issues  relevant  to   industry.
Waste  management through cleaner  production  and' proper  disposal   are
key  elements of its programme.

Industry   has   itself  created   several   organizations   to  focus  on
environmental  issues.   The International Chamber   of  Commerce  (ICC),
and  through  its   influence  the  International  Environmental   Bureau
 (IEB),  deal with all industry  sectors.   The oil industry has created
the   International   Petroleum    Industry   Environmental  Conservation
Association (IPIECA)  and the Oil Companies'  European Organization  for
Environmental Health  Protection (CONCAVE) for example as  international
co-ordinating   and   information  exchange  bodies,   and   serve   as  an
environmental  focal  point  for  the  industry as  a  whole.   The  tanker
owners  have  formed  a   "pollution"  federation.     These associations
participate in .discussions  on  conventions,  but  have also  taken some
measures  of their  own  to  induce their members  to  exercise  voluntary
restraint  on environmentally damaging  activities.   This is usually by
way  of  codes  of  practice  or  technical  guidelines.   On  an overall
industry  basis  the ICC  prepared some  time ago  a  policy statement on
environmental management.

UNEP/IEO  - Its  role,  programmes  and  activities as  relevant to the  oil
and  gas industry

The  Industry and  Environment  Office within UNEP   was  established in
1975,  and is located in  Paris,  France.   IEO has the specific task of
bringing  industry  and  government  together  to   ensure  a sustainable,
non-polluting industrial  development.
                             547

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Without  neglecting more  general  specific  pollution  issues,  IEO  has
concentrated particularly  on a number of strategic areas which help to
systematically  reduce  environmental  impact.    These  strategic   areas
include:

     waste  avoidance   through  promotion  of  information  networks   on
     cleaner  production  processes,  safer  chemicals,   and  low-impact
     products,

     proper methods of managing hazardous wastes in all  industries,

     awareness  and preparedeness  by  local  communities   of possible
     industrial accidents (APELL),

     adoption by  industry  of  strategic  environmental management   tools
     such as  environmental auditing,  environmental  performance goals,
     waste   minimization  programmes,   and   personnel   training  in
     environment.
How  does  IEO function?    lEO's  role  is to  inform,  co-ordinate  and
stimulate  others  to  take  the  initiative.   IEO deals directly with both
governments and with industry in  pursuing the above.  Industry sectors
where  IEO  has already  worked include  chemicals,  oil,  leather,  and
minerals.    IEO  also  works   with   other relevant   international  and
regional organizations  such as UNIDO, ISWA etc.

In  its  role as a catalyst for others  to take  action,  IEO activities
are concentrated  in  four major directions:

     (i)       publishing  technical  guidelines  on important industry
               sectors,  key environmental  issues,  and useful management
               tools  (see  annex 2),                     ,

     (ii)      facilitating direct information  exchange through its
               quarterly journal "Industry and  Environment", and
               through a query-response  service,

     (iii)     supporting  training workshops  and  on-the-job training
               projects,

     (iv)      arranging technical co-operation by way of studies,
               expert missions and seminars.

Many  of these initiatives are pursued jointly  with other interested
organizations  or   sponsors.   Technical  assistance  from  industry  and
government  experts often  underpins  the  practical work projects carried
out.
                            548

-------
For example, industry  provides  some of the expert resource persons for
training  workshops,   or   for   technical  co-operation   missions  to
developing  countries.     Through  expert  group  meeting  at  IEO  or
elsewhere industry makes  available its  management experience  in the
environmental  area.    In   assisting  with  technical  queries,  as  for
example   also   through   the   IEB,   industry   shares  some   of  its
environmental know-how with others.   Conferences and seminars on waste
management  or  other  topics  are  sometimes  sponsored  by  the industry
sector.

Complementary activities are also carried out by other UNEP divisions.
These  include  chemical   safety   (IRPTC  and  IPCS),  hazardous  waste
conventions  (ELIU,  IRPTC),  technical  information sources (INFOTERRA).
environmental  monitoring   and  climate  change   (GEMS),   and  marine
pollution (OCA-PAC). Other divisions  and regional offices play a vital
supporting role.

A  particularly   important  recent  role  is  that  of  the  (interim)
secretariat  of  the Basel Convention.  The  secretariat has the role of
both  guiding,  and monitoring,  activities in  the signatory  countries.
The secretariat is  located in Geneva,  Switzerland.

Application to the Oil and Gas  Industry

Although  many  company  managers are already  aware of the environmental
impacts  of  their  industry,  and  have taken  measures  to  reduce  them,
considerable further effort is  still necessary within  the  industry.

Initiatives  of cleaner  production,  ie. waste  minimization  could  be
particularly strengthened,  especially  in developing countries but also
in  the West.   In this respect  the role of  multinationals  in guiding
their  affiliates  in other  countries is particularly  important.

The .commendable principle  of  self-regulation could be  given greater
effect,   first   by   expanding   membership   and   activity   within
international  associations, and  subsequently  developing comprehensive
codes  of  practice.   The question  of monitoring  and enforcing members'
actions  on   such  codes has always  been a  delicate one  for industry
associations,  but  is  nevertheless  an  essential part  of -regulation,
whether self or otherwise.

At  the   company   level  a   more   widespread  elaboration  of  strong
environmental  policies would reinforce among  all personnel,  and among
contractors   and   clients,   that  proper   waste  management   is   an
inseparable  part   of   doing  business  in the  90's,  and  not  merely  a
peripheral nuisance.
                             549

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A strong  boost needs to be  given to our  less fortunate colleagues in
developing  countries.    An  expansion  of   assistance   programmes  is
needed, with  contributions  from the industry sector as well as from
government.     Bi-lateral   programmes  are  effective  in   reinforcing
existing  links; multilateral  programmes  such as through UNEP/IEO reach
a more  general audience.   In this  respect ISO would welcome  increased
participation  in,  and contributions  to,  its  initiatives  to help less
prepared  nations  to  implement  the  same  practices  and  standards that
are now in force in the more aware  industrialized  countries.

Among  the initiatives  that  IEO  sees appropriate  in the  oil  and  gas
sector are:

          the  preparation of  further sector  specific technical guides
          that   consider  appropriate  cleaner  technological processes,
          and   management  operations.    Guides  could cover   specified
          operations,  or issues,  or management tools,

          building  up a bibliography  of  relevant technical information
          on   cleaner  production   methods,   and   on   environmental
          legislation relevant to the industry.  This could be included
          in the International Cleaner Production  Information Clearing
          House (ICPIC)  data network  now being established  by IEO with
          the   co-operation  of the  US EPA.    Contributions to  such  a
          project  could  come both from  individual  corporations,  and
          through  existing  international  industry associations,

          joint work  on  developing further relevant  industry  codes  of
          practice  and  guidelines  on  for  example  marine pollution,
          waste dumping,  and global climate change  issues,

          providing   assistance   such  as   training   and  technical  co-
          operation  to  other  international organizations  and national
          entities.   Among  the audiences  in need of such assistance are
          government  planners,  industrialists and local consultants.
                             550

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                                Annex 1

                  Main Points of the Basel Convention

1. A signatory State cannot send hazardous waste to other signatory
   States that ban its import or to non-signatory countries.

2. No signatory country may ship hazardous waste to another signatory
   State if the importing country does not have the facilities to
   dispose of the waste in an environmentally sound manner.

3. Every country has the sovereign right to refuse to accept a
   shipment of hazardous waste.

4. Before an exporting country can start a shipment on its way it must
   have the importing country's consent in writing.  The exporting
   country must first provide detailed information on the intended
   export to the importing country to allow it to assess the risks.

5. Less hazardous waste should be produced. Residues should be
   disposed of as close to their source as possible.

6. If importing countries cannot dispose of imported waste in an
   environmentally acceptable way. exporting States must take it back
   for environmentally sound disposal elsewhere.

7. Illegal traffic in hazardous waste is criminal.

8. Shipments of hazardous waste must be packaged, labelled,  and
   transported in conformity with generally accepted and recognized
   international rules and standards.

9. Bilateral agreements by signatory States with each other and with a
   non-signatory countries must conform to the terms of the  Convention
   and be no less environmentally sound.

10.As authorities in developing countries may lack trained specialists
   and know-how to assess information about hazardous waste  greater
   international co-operation is required to train technicians, to
   exchange information, and for the transfer of technology.

11.A secretariat is to be set up to supervise and facilitate the
   implementation.

12.Signatory parties will report annually about transboundary
   movements of hazardous wastes in which they have been involved.
                              551

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                                Annex 2

    Some Publications of the UNEP Industry and Environment Office


Periodicals

     "Industry and  Environment"  - a  quarterly review  dealing with  a
     wide range of topics  and  issues.    Subscription US  $  45  p.a.

     Cleaner production -  Quarterly,  free

     APELL Newsletter

Monographs

1.   Environmental Management  Practices  in  Oil  Refineries  and Terminals

2.   Environmental  Aspects   of   Oil   Exploration  and   Exploitation
     (currently being prepared)

3.   Impact of Water-based Drilling Mud  Discharges  on the  Environment

4.   Environmental Auditing

5.   Storage of Hazardous  Materials

6.   Apell  -  Awareness and Preparation for Emergencies  at  the Local
     Level: a process for  responding  to  technological accidents


Other UNEP Publications

7.   The Cairo Guidelines and Principles for the Environmentally Sound
     Management of hazardous Wastes (1987)

8.   The Basel Convention on the Control of Transfrontier Movements of
     Hazardous Wastes and  their Disposal (1989)

9.   Treatment and Disposal Methods for  Waste Chemicals  (IRPTC)

10   The Disposal of Hazardous Wastes:  the Special  Needs  of  Developing
     Countries - 3vols., jointly  with the World Bank and WHO

11   Air  and  Water  Pollution:  a  Directory  of  Information  Sources
     (INFOTERRA/IEO)
                              552

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LAND FARMING OF DRILLING MUDS
IN CONJUNCTION WITH PIT-SITE RECLAMATION: A CASE HISTORY
Dr. G.A.(Jim) Shirazi
Shirazi & Assoc. Int'l Consultants Inc.
Oklahoma City, OK, 73105 USA
Abstract

Incorporation  of fresh  water drilling  muds in the soil media ( Land-
Farming) has been  practiced in the oil patch  for quite  sometime. In
order to ligitimize  the  practice,  several  states have enacted laws,
rules  and  regulations, to  meet  certain  regulatory  requirements.
Oklahoma adopted its "soil farming" rules during late 1985.

In this project the mud was analyzed  for several  limiting  parameters
such  as  Total Soluble Salts,  Oil and  Grease and Percent Dry Weight.
The  salt loading rates  were  calculated  based  upon  the salinity of
receiving  soil and  the salinity  of  each batch  of drilling mud.  An
onsite quality control program  was  established  to  determine the mud
weight, mud viscosity, pH, electrical conductivity, total soluble salts
and chlorides to assure compliance with State's regulatory reqirements.

This paper describes the  salient features  of  Oklahoma's  regulatory
program through a case history of a successful land farming project in
conjunction with site reclamation efforts at an off site mud disposal
pit in  Cater County,  Oklahoma. The process  was  found to be envoron-
mentally safe and cost-effective over other available options.
 Introduction

 Drilling muds  are  circulated  through  the well bore during drilling
 operations to remove the cuttings from down hole and to lubricate, and
 cool the drill pipe and drill bit.   A variety of  additives  are also
 mixed with the mud to cure and prevent certain specific conditions deep
 down in the hole resulting from high temperatures and pressures  (1).

 In Oklahoma, according to a rule of thumb, drilling operations generate
 about 2 bbls of spent mud and shale cuttings per foot of drilled depth.
 Due to continual influx  of  drilled  solids,  a portion  of the mud is
                            553

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rejected  and jetted out in a  reserve  pit.  The remaining mud is then
diluted with water to  reduce  solid buildup.  Other sources  of fluids
include  derrick floor wash resulting  from spills when connections are
made.

These reserve pits are in use only during  the  drilling  operation and
generally  remain open for about a year after the drilling is finished.
In Oklahoma, in shallow depth areas, the size of a typical reserve pit
is generally about an  acre in  area and contains approximately 5 to 6
feet of fluid. In the deep Anadarko Basin, however, it is not uncommon
to have a reserve pit approaching 2 acres in area and a fluid depth of
8 to 10 feet.

In the recent past, considerable  attention  has been  focused  on the
potential environmental impact of this vast amount of spent mud and the
manner in  which it is disposed.  The concerns range from the possibil-
ity  of surface  soil and  water degradation to ground water contamina-
tion due to the soluble salts  and  heavy metals  contained  in certain
types of drilling muds.  Oil-based drilling  muds pose their own speci-
fic concerns to the environment.

Incorporation of freshwater drilling mud in the soil media  has been a
practice in the oil patch for quite sometime. This paper describes the
salient features  of  Oklahoma's  regulatory  program  through  a case
history  of successful  soil-farming  project in conjunction with site
reclamation  efforts at an off-site mud disposal pit in Carter County,
Oklahoma.  The process  was  found to be environmentally safe and cost
effective over other available options.

Oklahoma's Regulatory Requirements

Existing practices of closing and disposing the reserve pit contents in
Oklahoma includes various options.  These options are standard industry
practices  and  are available  under  Oklahoma's regulatory program and
include,  but  are  not  limited  to:   (1)  evaporation / dewater  and
backfilling;  (2) solidification of pit contents; (3) annular injection;
(4) soil-farming;  (5) haul-off to  a commercial pit facility; (6) haul-
off to a commercial soil farming facility (2).

A soil-farming working guideline was issued by the Oklahoma Corporation
Commission back on October 7, 1986.   Final rules  and regulations were
adopted on November 10,  1986.  Since  then  there  have  been  several
upgrading  of those rules  and now the program even allows soil-farming
of the freshwater drilling  muds  from  a  "closed system"  steel tanks
concurrent to the drilling operations.
                               554

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The rules and regulations require compliance with a variety of issues
and concerns ranging from technical, environmental to operational
constraints (see TABLE 1).

The loading criteria are divided into two major categories; one dealing
with the  physical  and chemical properties of the drilling mud and the
second dealing with the physical and chemical properties of the receiv-
ing soil.  In addition to the loading restrictions,  several other req-
requirements were introduced  and  adopted which made the program more
effective.

Oklahoma  Corporation  Commission  did  not set any limits on  maximum
chloride concentration  on  the mud component.  However, it is required
that the total salt burden in the  soil shall not  exceed  6000 Ibs per
acre,  which includes the initial salt  contents of the receiving soil.
Furthermore, since plants respond to the osmotic potential due to total
salinity, the effect  of chloride is included in the total salt  burden
restriction (3).

In order to maintain sufficient aeration in the root zone, it was pro-
posed and later adopted that no more than 200,000 Ibs of mud ( on a dry
wt. basis )  be incorporated in  an  acre furrow slice  of soil,  which
contains 2,000,000 Ibs of soil (4).   Restrictions  on  toxic  elements
were also proposed and were adopted.  For commercial soil farming oper-
ations, chromium is limited to 40 Ibs per acre,  and arsenic  to 80 Ibs
per acre. No restrictions on barium are in place at this point in time.
Hydrocarbons are allowed up to 40,000 Ibs per acre or two (2) per cent
by weight.  The analysis of mud is based on one composite  sample  for
each   25,000 bbls  of  fluid volume in  a pit.  For  a  mud sample to
be representative, a  composite  sample  must consist  of a minimum of
five samples taken from different horizontally and vertically
distributed locations in each pit.  Restrictions on the receiving soil
are presented in TABLE 1.

Carter County Soil-Farming Project

The soil-farming project site is located in the Northeast quarter of
Section  21, Township  4  South and Range  2  West in Carter County,
Oklahoma  ( see Fig.l ).  Figure 1 shows the shape, size and the con-
figuration  of the  two  pits along  with the locations  of  several
receiving soil units.  These pits were permitted on April 17, 1981 by
the  Oklahoma  Corporation  Commission's  District  Office in Duncan,
Oklahoma.  These pits togather constitute the "offsite mud disposal
facility".  Pit dimensions  were  designed to accomodate the expected
volume  of spent drilling  mud from approximately 30 new unit wells in
                             555

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Hewitt Field in Oklahoma.   The operator,  Exxon Corporation, proposed
a pit size  of 300 ft by 300 ft and fluid depth of 6 feet for each of
the two pits in their Permit Application.  However, at the time when
the project started, the  total  volume  of  the mud  in  two pit was
measured to be about 168,000 bbls.

Characteri zation of the Drilling Mud

Mud sampling as a function of depth was conducted using a Bucket Auger
(Soil Test Inc.) for Pit # 1, while an 8 ft.  long 2 inch diameter  PVC
tube, fitted with a closing device, was used to sample the pit contents
of Pit # 2 which contained certain amount of top water.  This technique
allows  the mud sample  to be composited for various depths as required
by the rules and  regulations.  Chemical analysis of a composite sample
of mud from Pit #1 and Pit # 2 is presented in TABLE 2.  In addition to
that, a detail chemical analysis  of the  mud  samples from Pit # 1 and
# 2 was  conducted.  The data, not presented in this paper  but  can be
made available from the  author, indicated that there is  a great  deal
of  variation in the  salinity  level,  both  horizontally  as  well as
vertically,  since there  was  no  particular  pattern in the way  the
mud was dumped into these pits.  This variation  in  salinity  required
that onsite quality control be maintained for each batch of mud to be
soil farmed.

Pit # 1 and Pit # 2 were divided into  several "working  regions" based
upon the chemical make-up of the mud (see Fig.2).  In-pit slurry making
operations  were  controlled for horizontal and vertical variability in
the salinity level.  Mud in  each  working area was uniformly mixed and
analyzed for the most limiting parameter  and loading rate calculations
before hauled  of to the receiving soil Unit.  Tank truck crew was ins-
tructed  and  directed  to specific land areas in the unit of receiving
soil.  An accurate record was maintained of the quantity and quality of
the mud  disposed of at each given location to avoid salt over loading.

Characteri zation of the Receiving Soils

The "permit area" is dominated by one Soil Type, namely Normangee Loam
( # 31 )  however,  a certain amount of Durant Loam ( # 11) also occurs
in the soil-farmed  area ( see Fig.3 ).  Soils in  these groups consist
of well drained deep solum and gently to moderately sloping topography.
Normangee Loam has a slope of 2 to 5 per cent.  It was  formed  over  a
shaley parent material as reflected in the depth profile.  This soil is
characterized  by  top  6  inches of loam  and  6 to 80 inches of clay.
Durant  Loam is  quite  similar also,  being  loam in top 10 inches and
then  having a transition layer of clay loam from 10 to 16 in.  Rest of
                              556

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the profile is composed of clay  upto 83" deep,  similar  to  Normangee
Loam.

Although,  the receiving soils were high in sodium,  the overall sali-
nity status was low,  being only  911 ppm of TDS  for GT 2a and 935 ppm
for GT 2b soil tracts.  The Exchangeable Sodium Percentage (ESP)  and
Sodium  Adsorption  Ratio (SAR) as  defined  in  (3)  was only 3 units,
indicating that the soil has a large assimilative capacity for drilling
mud before any sodium hazard is noticed.

Loading Rates for Various Parameters

Loading Rates were calculated according to the formulae adopted by the
Oklahoma  Corporation  Commission.  Loading  rates of various limiting
parametrs for two receiving soil units,  namely, GT 2a and GT 2b  were
determined. It was found that the most limiting parameter in all cases
was the Total Dissolved Salt (TDS). Oil and Grease and Percent Dry Wt.
were never the limiting  factors.  Based  upon  the  analysis,  it was
calculated that the soil unit GT 2a,  which contained  37 acres of us-
able land can assimilate more than 43,000 bbls of mud from the Pit # 2.
Similarly, the soil unit # GT 2b, which contained 35 acres of land can
be used for another 42,000 bbls of mud from Pit # 2.  All calculations
were made on mud conditions on an "as is" basis.

From a bench scale model, it  was  determined that a certain amount of
water will be mixed with the mud,  to achieve a 9.0 ppg  or better mud
weight and a Funnel Viscosity of 36 or better to achieve proper rheolo-
gical properties for its incorporation in the soil.  For the purpose of
calculating the loading rates, one acre furrow slice of an average soil
was taken to be 2,000,000 Ibs.  Furthermore, for Oil and Grease calcul-
ations,  an API gravity of 35 was used.  Percent Solids were determined
on "as is" basis.  When needed, the  relative  density of  chromium and
arsenic was taken as 7.2 gm/cc  and 5.73 gm/cc respectively. Based upon
these assumptions, loading rates were  calculated  on  location using a
field lab.

Field level quality control and quality assurance

At the field lab, mud weight was determined by weighing a quart of mud
to the nearest hundredth of a pound.  The  mud viscosity  was measured
using  Marsh  Funnel for  the  same quart sample.  The sample was then
placed in an API Filter Press and an  adequate  amount of  filtrate was
extracted at 115  psi pressure.  The  filtrate  was  used to  determine
the pH, Electrical Conductivity, Total Dissolved Salts ( TDS  )  and the
Chloride  concentration.  The  results  of  wet chemistry were  used in
                           557

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loading rate calculations.  Data  summarizing  the daily  loading rates
for each  batch of mud for the soil-farming  project  can  be  obtained
from the author.  A portion  of the land  was designated for each batch
every day.  Mud was applied through a  spreader  bar using a tank-truck
operation.  With the exception  of few  accidental  spills, all mud was
spread uniformly on the  designated land.  A detailed  post-application
soil sampling was conducted  with in  a  week.  Samples were taken from
0-6" depth for each 2.5 acre land soil fanned.  Results of post appli-
cation soil salinity level are presented in TABLE # 3.

Results and discussion

Results of this  study  and other  previous  work (5) indicated  that
disposal of fresh water drilling mud through the soil-farming option
is environmentally safe, cost  effective,  and  does  not  adversely
affects the receiving soils.  Data from this study indicated that while
the TDS and Cl were high in the pits, they  were greatly diluted during
the slurry making operations.  Chloride  concentration  ranged  between
1,100 ppm to 2,500 ppm for most of the time, exceeding  3000  ppm  only
once.  However, the chlorides were significantly reduced after the soil
application due  to  additional dilution in the soil.  Post application
chlorides in  the soil  ranged from  230 ppm to 798 ppm. Similar trends
were observed in the total dissolved salts (TDS) data where the concen-
tration ranged from 1088  ppm to 2304  ppm.  It is interesting to note,
that the maximum salt burden allowed under Oklahoma's program is 6,000
Ibs of salt per acre of soil, which is  equivalent to 3,000 ppm TDS in
the soil. Post application data indicated that the salt burden level in
the receiving soil did not exceed even on areas where we had accidental
spills.  Soil farming, if  conducted  properly, can  be  beneficial  to
certain Sandy  soils by  adding fines to the texture thereby increasing
the water holding capacity  for  plant  growth  and reducing fertilizer
losses.  The technique  can  be  effectively  used  in conjunction with
other cleanup and  remedial processes  for salt  water  and hydrocarbon
spills and pipeline breaks.

Conclusions

Based upon our experience it is concluded that:

1.  Soil-farming of fresh water drilling muds and shale cuttings can be
    safely achieved under proper QA/QC proceedure.
2.  It provides an excellent option for "closed system" drilling
    operations.
3.  Shale cuttings from oil-based muds can be effectively soil-farmed.
    Naturally cccuring bacteria in the soil can effectively biodegrade
    the oil and grease adsorbed on the shale surface.
                               558

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Acknowledgement

The author wishes to acknowledge the assistance of Johnny Byars and
Logan Moore of Exxon Company USA in supporting various field activities
and providing regulatory liaison while carrying out this project.
Thanks are also due to the management for their permission to publish
this paper.  This project was supported by Exxon Company USA, through a
contract with Shirazi & Associates of Oklahoma City, Oklahoma.

References

1.  C.  Gatlin, Petroleum Engineering; Prentice-Hall Inc. Englewood
    Cliffs, N.J. 1980

2.  Rules and Regulations, Oil &_ Gas Conservation Div. Oklahoma
    Corporation Comm. June, 1990

3.  L.A. Richards, Dignosis & Improvement of Saline & Alkali Soils,
    U.S.D.A. Handbook # 60, 1969

4.  H.O. Buckman, N.C. Brady, The Nature & Properties of Soils,
    The MacMillan Co. New York, 1983
 5.  G.A. Shirazi, Soil Fanning of Drilling Muds; An Environmentally
     Safe and Viable Alternative, Proc. Nat. Conf. on Drilling Muds.
    Environmental & Groundwater Institute, Univ. of Okla. 1987
                              559

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           ADDITIONAL LAND
T T T T T
   6T3
      JTI
       Jl
                       CT2 i
                   POND
                      ST2 t
                                PIT
                                 DIS
                                                             EXXON OFFICE

                                                POND
    OSAL FACILITY   vATEl VEIL
                                 -'ft-
 •i
i
4
V
-(_
                                                                        T4S
                                  i Mr
       Fig.l.   Project location showing  the mud   pits  and
                various receiving soil units in Carter County,
                Oklahoma.
                               560

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                           TABLE 1

          Environmental and operational constraints
  on commercial and non-commercial soil farming in Oklahoma
    Environmental Constraints


1. No soil type having a slope
   greater than 5 % be used.

2. No soil where the depth to
   bedrock is less than 20" be
   used.

3. No land which lacks atleast
   12" of heavy textural soil
   in its profile be used for
   soil-farming.

4. Soils which are flooded at 2-yr
   frequency are not eligible.

5. Soils where salinity status is
   more than 4000 micromhos should
   not be used.

6. Soils having an ESP "> 15 should
   not be used.

7. Areas with shallow water table
   are not eligible.

8. Soil tract not within 100 feet
   of Water Quality Stream, pond,
   lake or wetland.
Operational Constraints
1. Sufficient amount of
   surity to reclaim the
   land if damaged.
2. Install monitoring
   wells at appropriate
   locations and sample
   every six months.
3. Weather Restrictions:
   a. no soil fanning
      during or when the
      rain is imminent.
   b. no soil-farming
      when soil moisture
      is high.
   c. when the ground is
      frozen.
   d. during gusty winds.

4. Buffer Zones:
   a. no soil-farming
      within 100' of a
      property line.
   b. within 50' of any
      stream.

   c. within 300' of
      domestic well.
   d. within 1300' of a
      municipal well.
                             561

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                         TABLE 2
Chemical composition of the mud in  Pit t 1  and  Pit t 2
Parameter
                            Concentration

EC (micromhos)
T D S (ppm)
Chloride (ppm)
% Dry Wt.
Oil & Grease (ppm)
Pit # 1
22,000
13,500
5,675
38.10
1,000
Pit # 2
14,000
9,000
4,050
13.04
3,000
         IHIIITT IEIIOIS  PIT+1
                                             SUIIITT  IEIIIIS  PIT *2
           \

                <
                n        N
          Fig. 2. Sampling locations and determination  of
                  "salinity regions" in pit #  1  & pit # 2,
                        562

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Fig. 3. Soil type distribution (series # 31 & # 11)
        and the topography around project location.
                        563

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                        TABLE 3




            Sunmary of the post-application
salinity status at various sampling locations
Sample #
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16 *
17
18
19 *
20 *
21
22
23
24
25
26
27
28
29 *
30
31
pH
7.53
7.51
7.08
7.52
7.51
7.55
8.06
8.02
7.52
7.53
8.03
8.02
7.52
7.52
8.03
8.02
7.50
7.52
8.03
8.00
7.58
7.82
7.72
8.02
8.00
7.50
8.02
7.81
7.56
8.03
8.00
T D S
1408
1280
1216
1024
1152
1088
1472
2304
1600
1216
2176
1472
1344
1728
1600
1760
1984
1600
2112
1792
1792
1344
1664
2176
1792
1664
1792
1472
1696
2336
1664
Cl
466
443
408
372
408
230
479
798
479
337
763
461
426
585
550
621
532
510
710
532
568
459
550
763
550
408
603
400
532
798
497
Cl/TDS
0.33
0.34
0.33
0.36
0.35
0.21
0.32
0.34
0.29
0.28
0.35
0.31
0.31
0.31
0.34
0.35
0.26
0.31
0.33
0.30
0.31
0.34
0.33
0.35
0.31
0.24
0.33
0.27
0.31
0.34
0.29
Areas where accidental spills were observed
                          564

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LANDFARMING OIL BASED DRILL CUTTINGS
Peter K. Zimmerman
Construction Supervisor
Amoco Canada Petroleum Company  Ltd.
Calgary, Alberta, Canada
James D. Robert
Senior Environmentalist
Amoco Canada Petroleum Company  Ltd.
Calgary, Alberta, Canada
 1.  Abstract

 Over   the   last  three years  Amoco  Canada  has  been developing a technique
 to  successfully  landfarm  oil  based drill  cuttings.  Oil based drill cut-
 tings  are  often  referred  to  as  DIMR,  a  residue of diesel invert mud  and
 rock cuttings.   This method  is  based  on the following principles:

 —  Modifications  to the  drilling  mud solid control system such that the
 amount of  oil  retained  in the cuttings  is substantially reduced.

 --  Minimizing  the  oil to  soil ratio by  evenly   spreading  the  cuttings
 over a suitable  land area.

 --  Utilizing the soil's natural  capacity  to biodegrade hydrocarbons, and
 enhancing   this  capacity  through the  application of chemical fertilizers
 and mechanical cultivation.

 Thirty-two wellsites in the  Grey Wooded soil  zone  of  Alberta,  drilled
 with   invert   mud, have   been   treated by landfarming and show positive
 results.   During the 3  years the program  has  been in place,  each   land-
 farming area  has been given 1 to 2  treatments  per year.  Each location
 has shown  a significant reduction  in  the  oil  content  of  the  soil,   in
 electrical conductivity (EC), and  salt  levels and it is anticipated that
 many will  meet or  exceed  government revegetation standards by the  end  of
 this year's growing season (1990). To  date,  no  deleterious effects from
 leaching   or   fluid migration have been observed, although monitoring  is
 still  ongoing.

 This type  of treatment  procedure is low cost, even considering sampling,
 analysis,  treatments, and the 2 to 4  years required to reclaim the site.
 It  is  hoped that this timeframe could be  reduced as  more  data  becomes
 available  and  the  technique  is  "fine  tuned".
                                565

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While this approach has apparently been successful in the soil zone men-
tioned, it could be limited by the availability of  biologically  active
soil  horizons, the surface area to cutting volume ratio, and the oil to
cuttings ratio.

Further  evaluation  is  still  required to determine the limits of this
reclamation method.   However, at this point in  time,  there  is  every
reason  to  think  that  this  approach  will become a primary method of
dealing with oil based drill cuttings.
2.  Introduction

Over the last 4 years, Amoco Canada has developed a  technique  to  suc-
cessfully  landfarm  oil based drill cuttings.  This is a method of dis-
posing of the Drilling Invert Mud Residue (DIMR) by utilizing the native
soil micro-organisms to degrade the oil phase of the invert  fluid,  and
the  naturally  occuring dilution and leaching action to reduce the high
chloride levels in the water phase.  An outline of this landfarming pro-
cess and an evaluation of the  analytical  data  is  contained  in  this
paper.
3.  Site Description

The landfarming sites almost all occur on crown lands invthe Grey Wooded
soil zone  (luvisol) of west central Alberta.  This soil zone is typified
by  a shallow weathered topsoil horizon, overlying a mostly clay subsoil
with occasional seams of sand and gravel.    Landforms  are  glacial  in
origin,  with  the  topography being gently to severely rolling.  Forest
cover type ranges from typical aspen woodland to boreal  species  (pine,
spruce, poplar).

Mean  annual precipitation  levels are approximately 550 mm, most of this
generally  occurring during  the spring break-up period and  early  summer
months.

There are  32 individual landfarm sites; 21 of which are clustered in the
"Ricinus"  field,  8  in the "Brazeau" field, and 4 other  scattered deep
hole exploration wells.  DIMR volumes range from approximately  200 - 300
m3 per  location in the Ricinus field, 300 - 400 m3  in  the  Brazeau
field,  and 450 - 700 m3 in  the 4 other locations.

Most  of these wells are in production and average approximately  1.65 ha
in area, of which roughly. 1/3 -  1/2 of the wellsite is available  for the
landfarming operation.
                                  566

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This means that the average ratio of cuttings to surface area  is roughly
450 m3/ha, or a layer of cuttings 4.5 cm deep, although  this   various
somewhat from site to site.
4.  Invert Mud System

Amoco1s  standard  invert  diesel  mud  system  is  based  on  a  1  to  4  water  in
oil emulsion.  The  oil  component is  #2   diesel   fuel,   while   the   water
phase   is  a  CaCla  brine   with chloride  ion  levels in the order  of
200,000 rng/1.    The  fluid will   also contain   emulsifiers  and  wetting
agents   (surfactants),  and  may  contain  lime and other additives  in small
quantities.
 5.   Landfarm  Operations

 The  invert  landfarming operation consists  of  several  steps:

 1.  Invert  fluid and water that has drained from  the   cuttings   pile  is
 first   treated  and/or removed for off lease  disposal.   The  cutting  pile
 is  dyked,  so  this fluid phase tends to be  mostly rain water.  A^  conven-
 tional  activated carbon/flocculent treatment  is generally usedr

 2.   The  oil  contaminated cuttings are then spread as thinly as  possible
 with a  dozer  over the designated landfarm  area.  A general guideline  is
 to   try  and   keep  the layer of cuttings  less than 5 cm thick,  although
 this is not always possible, as wet cuttings  can be difficult to  spread
 uniformly,  and the surface area available  is  sometimes limited.

 3.   The  previously  stockpiled  surface  strippings   (topsoil  and humus
 layer)  are then dozed over and mixed in with  the cuttings.   The  area  is
 cultivated  with  a  set  of discs, or a tractor mounted rototiller.  At
 this time, high nitrogen fertilizer is broadcast and  mixed into  the cut-
 tings topsoiI/layer.  If a soil conditioner or bacterial culture such as
 manure is to be added, it would also be introduced and  spread   at  this
 time.

 The  three objectives of this operation are to maximize the  surface con-
 tact between the cuttings and soil bacteria,  aerate the soil/cutting mix
 to promote aerobic decomposition, and boost the soil   microbe  count  by
 providing  additional limiting nutrients  in the form of high N2 fer-
 tilizer.  These are the same general principles that  are  applied  when
 treating small oil spills, or composting  in your back yard,  and are con-
 sistent with the findings of Scroggins, et al  (1988).

 The  cultivate/fertilize  cycle   is  then repeated as often as  required,
 generally twice a year for 2 or 3 years.   The type of  fertilizer,  and
                                  567

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recommended  application  rate  is determined by a regular  soil sampling
and analysis program.  The two most frequently used are  34-0-0  and   11-
51-0.   Rates vary a great deal, but have generally been in the order of
1000 kg/ha.

Once analytical results demonstrate the oil to soil ratio has dropped to
the 1-2% range, the site is given a final treatment and  a suitable grass
seed mixture is sown.  The most common one is Creeping Red  Fescue - 40%;
White  Dutch  Clover  - 12%;   Climax Timothy - 24%; Canada Blue Grass -
24%.
6.  Mud Solids Control                            i

Continuing the work begun by Braun and  Molner  (1988),  Amoco  Canada's
Drilling  Dept. has placed a renewed emphasis on "closed loop" drilling.
This has resulted in a substantial reduction in  the  amount  of  invert
fluid being dumped with the drill cuttings.

Initial modifications to the mud system involved:

-- increasing  mesh  screen size in the shale shakers
-- substituting 2 or more centrifuge units for the  desander  desilter
-- continuously agitating the shaker tank

Other  modifications  and in situ treatment systems are being evaluated,
but that subject is beyond the scope of this paper.  These efforts  have
been  paying  real  dividends  during the clean-up and landfarming oper-
ations, as the reduction in total invert fluid volumes left on site is a
key factor in reducing bioremediation time.

At present, our timeframe to completely finalize a site is 2 to 4 years.
Improved solids control at the rig should cut the recovery  time  by  as
much  as  half,  which reduces costs and minimize any negative potential
impacts of invert landfarming.
7.  Soil Sampling

Soil sampling was  initiated  in 1986 at  several  sites  in  the  Brazeau
area,  and  is currently conducted at 32 sites in the Brazeau and Ricinus
areas on an annual basis.

Landfarming sites  are divided into 2 to 4 sections  for  composite  soil
sampling,   and  a  minimum of 15 soil cores are taken in each section to
make a composite sample.   The intent  is  to  sample  soil  at  similar
locations each year.                                                 __
                                568

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The  depths  of  soil  sampling  are  0-15  cm  and  15-30  cm, with  a  few  sites
being sampled at  30-45  cm.   A  composite soil sample  is obtained for each
depth and each section  of the  landfarmed area.  A  control  sample is also
taken for comparison  with soils  being analyzed  from  the  landfarm area.

Composite  soil  sampling from  each section is  important  since it is dif-
ficult to evenly  spread the  spent  invert mud residues  and  cuttings  by
mechanical  means.    The concentration of total hydrocarbons or soluble
salts will vary  on  the site  due  to   the limitations   of  mechanical
spreading.    By  dividing a site  into  2 to 4  sections,  treatment can  be
specifically directed to each  section.
8.  Soil Analysis  Parameters

Each  soil  sample  is  analyzed  for  the  following  parameters:     pH,   total
hydrocarbons   (%  HC),  electrical  conductivity  (EC),  %  saturation,  sodium
absorption ratio  (SAR),  calcium (Ca),  magnesium (Mg),  sodium  (Na),  sulp-
hates (S04),  chlorides (Cl),  theoretical  gypsum  requirement   (TGR),
nitrogen   (N),  phosphorous  (P), and potassium  (K).   From  these  analyses,
fertilizer recommendations  are  determined.     At   present,   government
guidelines or  regulations   do  not  specify the parameters for the soil
analysis.
 9.   Trends

 The pH of the soil  has consistently  been  in  the  range  of   6.4  to   7.4.
 For most  of the landfarming sites  the  pH  of  the  soil has been very close
 to  7.   At a few sites, the soil  pH has ranged  from  5.1 to  5.7 due to the
 soil type and characteristics of the area.

 Before modifications were initiated at the  drilling rig,  and the appro-
 priate spreading depth of DIMR was  determined,   the  percent   of  total
 hydrocarbons in the soil  in the first  year was much greater than  1%.  An
 example  is Amoco Brazeau 10-28-45-14-W5M as shown  in Table 1.  The  per-
 cent total  hydrocarbons in the 0-15  cm depth has decreased from 7.37% in
-4987,  to  1.45% in 1988, to 1.28% in  1989, and  0.58% in 1990.  Fertilizer
 applied twice a  year  in  1987  and  1988,  and extensive cultivation
 accounts  for this rapid decrease in  hydrocarbons.

 Several landfarming sites, such as Amoco  Ricinus 5-34-32-7-W5M  and Amoco
 Ricinus  10-02-34-8-W5M  as  shown in  Table  2, had  total hydrocarbons of
 1.97% & 3.29% respectively, in the 0-15 cm   depth  in  the  first  year.
 After  3   fertilizer treatments and  cultivation, the percent hydrocarbon
 dropped dramatically to  approximately 0.14%  and  0.39%   respectively.
 This  rapid  decrease in the hydrocarbon  content is due  primarily to the
                              569

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 addition of nitrate fertilizers which assist  in  increasing  soil  bac-
 teria.

 Many landfarming sites have a percent total hydrocarbons content of less
 than  1%  in  the first year.   Table 3 for Amoco Ricinus 14-34-32-7^W5M
 shows a total  hydrocarbon content in the 0-15 cm depth of 0.72% in  1988
 and  0.2* in 1989, and 0.13% in 1990.  Amoco Ricinus 10-28-34-8-W5M shows
 a  similar  decreasein hydrocarbons.   The oil content on the shale cut-
 tings has been greatly reduced by the use of centrifuges  and  modifica-
 tions  to  the  shale  shaker screens.   This has resulted in an initial
 lower concentration of oil.

 The  soil analysis for the  32  sites  show  that  hydrocarbons  are  not
 migrating  or leaching.   Initially, the hydrocarbon content in the 0-15
 cm and  15-30 cm depths may be similar, depending upon the depth of  cul-
 tivation.    However, the maximum hydrocarbons content is normally found
 in the  shallower depth of 0-15 cm.   The hydrocarbon  content  does  not
 appear   to  increase in the 15-30 cm or 30-45 cm depth with time.   Other
 studies (Ashworth, Scroggins, McCoy,  1988)  have  also  indicated  that
 hydrocarbons are not migrating or leaching.

 There  is  a  wide  range of electrical conductivity for the sites, with
 some initial values reaching 66.7 mS/cm.  Table 4 shows  the  range  for
 the  landfarming  sites  at  wellsites  Brazeau 10-28-45-14-W5M, Ricinus
 5-34-32-7-W5M, and Ricinus 10-28-34-8-W5M.  Calcium Chloride (CaCl2)
 and other soluble salts are the factors contributing to the  wide   range
 of  electrical conductivity.  The trend has been for the electrical con-
 ductivity to decrease rapidly in both the 0-15 and 15-30 cm depths.  For
 many sites, the EC is well below 5 mS/cm in the second or third year and
 very similar to the control soil samples.

 Chloride levels as shown in Table 5 show a wide range in values for  the
 first  year  of landfarming.  Chloride levels in the first year may vary
 from several hundred to several thousand PPM.   Due to leaching  and  an
 abundance  of  rain in 1988, 1989 and 1990, chloride concentrations have
 dropped significantly each year.

 Overall sodium concentrations have not been a problem.   However,   where
 sodium  levels  have  been  excessive in comparison to the control site,
'gypsum has been added to alleviate the problem.

 With respect to calcium (Ca), magnesium (Mg) and sulphates   (S04-S),
 there  have  been  elevated  levels   in comparison to the control   sites.
 However, no  major  problems  with  respect  to  landfarming  have  been
 encountered.    For  five  landfarming sites, a complete soil analysis is
 given  in Table 6.   Amoco  is presently in  the  process  of  setting  up
 ground  water  monitoring  wells  at  four sites to determine movement of
 leachates.
                               570

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10.  Time for Reclamation

The  percent  total  hydrocarbon tends to be the limiting factor for the
reclamation.  Sites with a higher hydrocarbon content, 3%-7%, may take 2
- 4 years for reclamation.  Many sites with a percent  hydrocarbon  con-
tent  of  0.5  - 2% initially, have been successfully revegetated in the
second growing season.  Overall, once the hydrcarbon content in the soil
is 1% or less and chlorides are less than 1000  ppm,  the  site  can  be
revegetated successfully.

Fertilizer  is added at  least once per year with some sites receiving two
fertilizer  applications per year.  The addition of fertilizer containing
nitrates  and phosphorous has been a successful strategy.  Manure may be
added to landfarming sites and  previous  field  studies  (J.  Ashworth,
1989) indicate this would be beneficial.  The addition of straw in areas
of  very little topsoil has merit, especially where the topsoil is poor.
The addition of sewage  lagoon material is being assessed to see if  this
would  expedite  the  reclamation  process.    The objective would be to
increase the bacterial  numbers to enhance hydrocarbon breakdown.
 11.  Costs

 Thus far, the  landfarming  operation as outlined has proven to be a  very
 cost  efficient  method  of  handling  invert cuttings.  The average land-
 farming costs, above  and beyond  our   normal  site  clean-up  costs,  are
 approximately  $8,OOO/location.   This  includes the  landfarming operation,
 soil sampling  program and  lab  analysis.

 This  compares   very   favourably with  other disposal options currently
 being tried  in Alberta.  Based on field trials recently  conducted  with
 fixation  and  incineration,  it is estimated that costs for these methods
 would be  $40,000 and  $60,000 respectively.
 12.   Limitations

 Government  regulatory  bodies  in  Alberta  to date, have given the  industry
 a  somewhat  cautious  green  light  for  this disposal procedure.     We   have
 yet   to   see   any  serious  problems or  shortcomings,  and  at this  point  in
 time,  it  appears to  be a satisfactory  method  of  handling  invert   cut-
 tings.  However, there are limitations:

 As  mentioned  previously,  the oil/soil ratio must be around 1% by weight
 in order  to establish  a satisfactory vegetative cover.    Therefore,   if
 we:
                                571

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-- are  restricted  by the area available to spread the cuttings
— have to handle large volumes  of  cuttings.
-- have a high ratio of oil to cuttings

(or some combination of these), we may end up with a site that will take
a very long time to reclaim.

VOCs (Volatile Organic Compounds) may evaporate from the farmed cuttings
but  have  not  been  of great concern since most landfarm sites are not
close to any residences.  Furthermore, only trace amounts of VOCs may be
involved.

Salt loading of the soil from the brine  phase  of  the  DIMR  does  not
appear  to  be  a problem.   Regulations stipulate that no fluids with a
chloride concentration above 1000 ppm may be disposed of off site.    We
comply  with  this  by conducting our landfarming operation on the well-
site.   However, the fact is  that  soil  analysis  indicates  that  the
CaCl2  quickly  leaches  out.   We have yet to detect any observable
necrotic effects on either the surrounding forest or the new grass  crop
that would suggest salt damage.

Possible  ground  water contamination is a concern, although again there
have been no obvious indications  that  this  is  having  a  significant
impact.    This  aspect  of  our operation shall be further investigated
through a ground water monitoring program to be undertaken in  the  near
future.

Lack  of topsoil or humus material to mix with the DIMR can of course be
a very limiting factor.  Extra effort made during wellsite  construction
to  conseve  organics  is  more  than made up for during the landfarming
operations.  Trucking in and spreading a soil conditioner such as manure
is an expensive option.
13.  Advantages  _

Aside from the low costs, the primary advantage to landfarming is that a
natural process, with minimum energy input, is being utilized to dispose
of a waste substance.  The waste is not simply covered up or stored,  as
occurs  at  a landfill.  Landfarming of DIMR does not cause air emission
problems  in comparison to incineration where smoke and particulates  may
be of concern.   Basically, landfarming of DIMR handles the waste on-site
and transport of the material is not required.
                               572

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14.  Conclusion

To  date,  Amoco's  landfarming  of  oil  based  drill cuttings has been
showing positive results.  Reduction of invert residue on  the  cuttings
through  improved  solids  control  while  drilling,  is felt to be a key
factor in expediting the process.  There have been no  noticeable  envi-
ronmental  impacts,  but   studies  are  ongoing to try and determine the
implications of  leaching.   The revegetation of many  sites  shows  that
landfarming  is  an  acceptable disposal option for oil based drill cut-
tings.
15.  Acknowledgements

The authors would  like  to  acknowledge Mr. Ed Lambert of Alpine  Environ-
mental  Ltd.,  who   has played  a major role in developing Amoco's land-
farming procedure.
 16.  References

 Ashworth,  J.,  Scroggins,  R.P.  and  McCoy, D.  (1988). Feasibility of  Land
 Application   as   a   Waste  Management   Practice for Disposal of Residual
 Diesel  Invert-based  Muds  and  Cuttings  in the Foothills of Alberta.    In
 proceedings  of the  International Conference on Drilling Wastes, Calgary.

 Ashworth,  J.,  Scroggins,  R.P.,  and  McCoy, D. (November,  1988).  Land-
 Farming Invert Cuttings from  Sour  Gas  Wells  in the Rocky Mountain  Foot-
 hills.     In APCA "Chemicals  in  the  Environment" Conference Proceedings,
 Whistler,  British Columbia, November 9-11, 1988.

 Ashworth,  J.,  October,  1989,  Draft;  Field Study to  Assess  the  Feasi-
 bility   of Disposing of Diesel  Invert-Based Cuttings Residues Using Land
 Application.

 Braun,  B., November, 1988.   Invert Mud Systems in Amoco  Ricinus  Field,
 and  Revised  Solid Control Hook-up  in Amoco Canada's Ricinus Field.
                                573

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                             TABLE 1
Percent Total Hydrocarbons in 0-15 cm and 15-30 cm depths.

Amoco Brazeau 10-28-45-14-U5M
                      PERCENT TOTAL                PERCENT TOTAL
YEAR                  HC AT 0-15 CM                HC AT 15-30 CM
1987
1988
1989
1990
  7.37
  1.45
  1.39
  0.58
    5.95

    1.17
    0.69
                             TABLE 2
Percent Total Hydrocarbons in 0-15 cm and 15-30 cm depths.
Amoco Ricinus 5-34-32-7-W5M
YEAR

1988
1989
1990
PERCENT HC
0 - 15 CM

  1.97
  0.10*
  0.14
Amoco Ricinus 10-2-34-8-W5M
YEAR

1988
1989
1990
PERCENT HC
0 - 15 CM

  3.29
  0.40
  0.39
PERCENT HC
15 - 30 CM

    2.36
    0.10*
    0.19
PERCENT HC
15 - 30 CM

    1.15
    0.10
    0.30
NOTE:  * Questionable laboratory analyses in 1989.
                             TABLE 3
Percent Total Hydrocarbons in 0 - 15 cm and 15 -  30 cm depths.
Amoco Ricinus 14-34-32-7-W5M
YEAR

1988
1989
1990
 PERCENT HC
 0 - 15 CM

  0.72
  0.20
  0.13
Amoco Ricinus 10-28-34-8-W5M
YEAR

1988
1989
1990
 PERCENT HC
 0 - 15 CM
  2.04
  0.10
  0.15
PERCENT HC
15 - 30 CM

    0.80
    0.10
    0.13
PERCENT HC
15 - 30 CM

    0.86
    0.10
    0.13
                                   574

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                           TABLE 4


Electrical  Conductivity (mS/cm)
                                            0 - 15 CM    15 - 30 CM
Brazeau




Ricinus



Ricinus



10-28-45-14-W5M




5-34-32-7-W5M



10-28- 34-8-W5M




1987
1988
1989
1990

1988
1989
1990

1988
1989
1990

66.7
11.4
2.5
1.9

12.2
1.0
0.5

	
1.2
0.6

63.8
....
2.1
1.6

16.2
0.8
0.6

5.1
1.3
0.8
                          TABLE 5

Chloride (PPM)

                                            0 - 15 CM    15 - 30 CM

Brazeau 10-28-45-14-W5M
                           1987               8256         8550
                           1988               2140         	
                           1989                117           76
                           1990                 86           48

Ricinus 5-34-32-7-W5M
                           1988               2234         2653
                           1989                131           58
                           1990                 40           41

Ricinus 10-28-34-8-W5M
                           1988               	          741
                           1989                210          250
                           1990                 21           61
                                 575

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                                                     TABLE 6
                               DETAILED SOIL ANALYSIS REPORTS FOR FIVE SELECTED SITES
Location (Lsd)
Brazeau
10-28-45-14-W5
Ricinus
5-34-32-7-W5
Ricinus
14-34-32-7-W5
Ricinus
10-2-34-8-W5
Ricinus
10-28-34-8-W5
Date
1987
1988
1989
1990
1988
1989
1990
1988
1989
1990
1988
1989
1990
1988
1989
1990
Depth
1QM)...
Qr-15.-
is-10
n-JL5._
15^3H
(K15.
15.=3Q
Q-_L1
i5=ja
Q-_15_
15-30
0-15
l5r3jQ.
Q-_15_
15-30

0-15
15-30
0-15
15-30
0-15
15-30

0-15
15-30
0-15
15-30
0-15
15-30

0-15
15-30
0-15
15-30
0-15
15-30
TIIC
%
7.32-
R.QR
1.45

uaa
LJ.Z
(L.58.
0^69.
1.97
2.36
0.10
0,10
0,14
0.19

0.72
0.80
0.20
0.10
0.13
0.13

3.29
1.15
0.40
0.10
0.39
0.30

2.04
0.86
0.10
0.10
0.15
0.1.1
Pll
10.0
9.8
?.n

JLJ.
1.7
7.4
7.4
-LJL
7.5
6,7
6-7
7.2
7.3

6.6
6.7
6.5
6.5
7.3
7.3

7.1
7.3
6.7
6.7
7.5
7.5

7.1
7.0
6.6
6.6
6.9
.JL2.
E-C
mS/cm
fifi.7
fi.l.R
11.4

2.5
2.1
1.9
1.6

L2.JL
16.2
1.0
0.8
0.5
0.6

7.6
5.2
1.1
2.2
0.8
1.1

20.3
10.5
1.1
1.5
0.7
0.9

10.2
5.1
1.2
1.3
0.6
O.R
SAT
%
Ifi
3fi


49
47
50
48

52
47
65
57
55
52

85
77
75
73
66
64

40
38
66
67
55
53

47
49
65
62
51
S3
SAR
ll.fi
11.1
4.1

1.4
1.4
1.5
JL,0

2.5
_1JL
0.9
0.6
0.4
0.8

1.0
1.2
0.5
0.9
0.5
0.8

5.3
3.5
1.6
1.6
0.9
1.5

1.9
4.1
1.4
1.6
0.6
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4745
4658
966

201
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939
1194
155
110
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409
495
172
272
19
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168
186
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727
314
164
146
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74
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1656
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222
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         FOOTNOTE:   Soil  analysis  completed  from all 32 sites, but results  included  for  only  5  sites.

-------
MANAGEMENT OF AMINE PROCESS SLUDGES
Carol A. Boyle
Faculty of Environmental Design
University of Calgary
Calgary, Alberta, Canada
Introduction

THe petroleum industry in Alberta produces over 37 million m3 of oil and gas wastes which are
presently disposed of in landfills, deep wells, ponds and at the hazardous waste treatment facility
at Swan Hills (1). Since 1985, the Canadian Petroleum Association (CPA), in conjunction with
Environment Canada, has been assessing these wastes and evaluating environmentally acceptable
methods for their treatment and disposal.

Amine sludges, wastes from the process used to remove sulphur from sour gas  (gas containing
fyS), have been ranked as high with respect to their potential for  environmental concern (2).
Some amine sludges contain compounds that are carcinogenic, toxic or corrosive.  Disposal of
these wastes has become a problem because their classification was not clear. The acceptability of
landfilling these wastes is being questioned by landfill and sour gas plant operators.

The  management of these wastes must take into consideration their composition and hazardous
nature, ways of reducing any hazard they pose and the volume produced, their recycling potential
and  the technical, environmental and economical feasibility of disposal methods.  Most amine
wastes are produced from processes using either diethanolamine (DEA) or monoethanolamine
(MEA) as scavenger/solvents.  This paper focuses on these two types of waste, examining the
management options available and  providing an evaluation  of those options.    The  details are
summarized in a report prepared for the  CPA and Environment Canada (3).


Purpose

The  purpose of this project was to determine and evaluate the options available for managing sour
gas processing plant DEA  and MEA  sludges, to  recommend  management options that  are
environmentally  acceptable  to government  and the industry and  to identify further research
requirements to fully assess the recommended options.


(Characterization  of the Wastes

Amine compounds such as DEA and MEA are used  to remove the sulphur from sour gas under
pressure. The sulphur is then stripped out  of the amine compound at high temperatures and both
amine and sulphur are recovered. The amine is then recycled.  Sodium hydroxide is often added
to the amine to prevent corrosion (4).

During the process, the  amine compounds are attacked  by CO2 and break  down, forming
degradation products.  A number of factors  affect this process, including temperature, pressure,
gas composition and pH (5). At least 17 amine degradation compounds have been found in amine
solutions (5) and one, N-(hydroxyethyl)ethylenimme (HEM or aziridinethanol), is considered to
be toxic. HEM is also classified as a positive animal carcinogen as is triethanolamine (TEA) while


                                     577                                              l

-------
oxizolidone (OX) is a suggestive animal carcinogen.  Other compounds such as carboxylic acid,
thiosulfuric acid and thiocyanic acid, sodium chloride, iron sulphide and sodium hydroxide have
also been found in the amine solution (8).  DEA solutions are filtered to remove some of the
degradation compounds while MEA solutions are reclaimed; both systems produce a waste sludge.

The filters used in the DEA process include diatomaceous earth and cellulose fibre-diatomaceous
earth. The filters are backwashed periodically and the backwash liquids are often discarded into a
pond, then deep well  injected (9).  The filters are changed when  the process  indicates that
degradation products or particles are accumulating. There was little information available on the
backwash liquids but they may contain similar compounds  at lower concentrations.   Mpnenco
Consultants Ltd. (10) report that 5 - 30 m3 are produced annually by each gas plant while two
plant operators  estimate their volume of solid amine wastes to be  3  and 11 tonnes per year
respectively (11,12).

The MEA sludges are liquids  of  varying viscosity which are diluted with water, if necessary,
allowed to settle, then deej> well injected. Monenco Consultants Ltd. (13) reported the volume of
this waste to be less than 5 m3/year per plant but plant operators provided estimates of 55 and 71
tonnes of liquid MEA waste produced per year (14,15).

In this study, an analysis of amine  sludges from four Alberta gas plants (two DEA filter sludges
and two MEA reclaimer  bottoms) determined that  three had a high  pH and contained high
concentrations of nitrogen and sodium but levels of other elements were at or below Canadian
background soil levels (Tables 1, 2). These results agree with characterizations of amine leaf filter
sludges and reclaimer bottoms by Monenco Consultants Ltd. (16).  One DEA filter sludge (Plant
B) contained only  low levels of sodium and nitrogen but had concentrations of nickel and copper
above the levels found in Canadian soils (17).   Sodium hydroxide was not added to the amine
solution during  the gas treating process and the pH of the amine sludge was low (pH=4.5) so
corrosion of metals may have been  occurring.

Analysis of the  four amine  sludges by GC/MS  indicated that they contain a variety of amine
compounds, including a number of unknown and unidentified compounds (Tables 3, 4).  Of those
compounds known to be  carcinogenic or toxic,  TEA was detected in the  Plant B DEA filter
sludge. Other analysis of amine sludges found similar compounds (18, 19) although OX was found
in reclaimer bottoms from a vacuum reclamation of the Plant A amine solution (20).

In testing for hydrocarbon compounds in amine  filter sludges and reclaimer bottoms, Monenco
Consultants Ltd. (21) found a number of compounds such as phenols and benzenes, but  all at
levels less than 9 ppm (Table 5). Formic acid, acetic acid, proprionic acid and oxalates were found
in high concentrations in other sludges (22).

The toxicity of the four study sludges to bacteria, germinating seeds and  fish was also tested. All
sludges were found to be toxic to the organisms tested except for the Plant B DEA sludge which
was not toxic to germinating seeds  at a concentration of 20%. Other tests of amine filter sludges
and reclaimer bottoms have found them to be toxic to seeds, algae, fish, cladoceran, nematodes
and bacteria (23).  The S.O.S. Chromotest was also used to  detect  the  presence of genotoxic
agents which cause damage  to DNA of cells. Neither the amine filter sludge nor the reclaimer
bottoms were genotoxic at concentrations below their level of toxicity to the test organism (24).
However, the  toxicity of the  two wastes was  extreme,  and their genotoxicity  could not be
adequately tested.

In Alberta, the Hazardous  Waste Regulations (Alta.  Reg. 505/87) specify substances that are
classified as hazardous. Of  the compounds found in the sludges, MEA, acetic acid, formic acid,
proprionic acid  and oxalates are classified as hazardous due to their corrosive nature.  Benzene,
ethyl benzene and phenol are also  listed as miscellaneous hazardous materials  and  phenol is also
considered to be toxic. However, the pH of the sludges would  not result in their classification as
corrosive. There is no information available to consider the toxic nature of the wastes themselves


                                         578

-------
since that classification is based on toxicity to rats and the toxicity of the amine sludges to rats has
not been assessed.

The  unknown  nature of  many of  the compounds found  in  the  wastes  and  the  known
carcinogenicity of some of the  compounds indicate that  caution is required  in classifying these
wastes. In addition, the composition of these amine sludges varies from plant to plant and from
time to time within one plant.  They should be considered as hazardous with respect to both
handling and disposal until there is further evidence as to their nature. Otherwise, if future testing
of these sludges results in a hazardous classification, the producer may be liable for compensation
for any negative health effects and cleanup costs.

The metal content of  these wastes is low enough that  reclamation of the metals is not a feasible
option. Reclaimer bottoms analyzed by Monenco  Consultants Ltd. (25) contained 80% MEA,
enough to warrant further reclamation of MEA but analysis of other MEA sludges indicated that
most recovery processes were extremely efficient, with the wastes containing 0 to 8% MEA.  DEA
was also low in the analyzed sludges.

Treatments that will break down the hazardous compounds in the sludges will be required.  Both
sodium and nitrogen may also pose a problem in disposing of these wastes since sodium will  cause
salinization of soil and high concentrations  of nitrates  in ground or  surface  water are  toxic,
especially to infants (26).


Biodegradation

A number  of studies  have assessed the biodegradation of specific compounds found in amine
sludges, such as DEA, TEA and MEA (27, 28, 29). No  toxic intermediates were reported when an
isolated sewage bacteria was used  to  anaerobically degrade these compounds into substances
useable by the microorganisms (30).  Other aliphatic amines have been successfully treated  by an
activated sludge process (31).   Organic  compounds  such as phenols, benzenes,  aliphatic acid,
formic acid and acetic acid  also found in the sludges are also readily biodegraded by bacteria (32,
33,34).

The biodegradation of the  four amine sludges when mixed with soil and incubated for six weeks
was assessed in this study using changes in toxicity as  a measure (Table 6).  The  toxicity of two
 MEA reclaimer bottoms to fish decreased and toxicity to bacteria did decrease for Plant  D
although the results for Plant C were not significant.  The Plant A DEA filter  sludge produced
toxicity results that were inconclusive while the Plant B DEA cellulose fibre filter  sludge showed
no significant change in toxicity to fish but did decrease in toxicity to bacteria.

This study (35) also determined that perennial rye actually grew better in  low concentrations of
three of the four sludges than in the control soil.  The  plants appeared to be using nitrogen from
the degrading amine compounds as a nutrient. Only the Plant B DEA cellulose fibre filter sludge
 inhibited plant  growth at the lowest concentration tested, possiblyjdue to either  the release of
adsorbed toxic compounds by the degrading fibre or competition between the plants and bacteria
 degrading the fibre.  In general, the results suggested that there was biodegradation of the two
 MEA sludges and the  Plant A DEA diatomacepus earth filter sludge when the sludges were mixed
 with soil.  These results also indicated that soil immobilized compounds in all sludges that were
 toxic to seeds and to fish.   The assimulative capacity of the soil ranged from 0.5% to 2.5% (10-50
 t/ha).
                                          579

-------
Options for Treatment and Disposal

There  are  five options  that must be considered for disposal of these wastes;  landfilling, land
treating, deep weU disposal, surface water discharge and incineration.


Landfilling

Under Alberta regulations,  solid hazardous wastes  could be landfilled at any  Class II landfill
which  must have  a  synthetic  or clay liner, surface run-on and  run-off control systems, a gas
interception and venting system and a ground water monitoring system (36).  Liquid hazardous
wastes would not  be acceptable at such a site and it is not recommended that such wastes  be
landfilled due to problems with leaching and contamination of surface and ground water (37).
The classification of  MEA and DEA wastes as hazardous is still under question because they may
contain some compounds listed as hazardous and the toxicity of the wastes to rats or their effect
upon the environment has not been determined (38).

The solid DEA filter sludges, once they have been drained to ensure they contain no liquids, could
be  landfilled at a Class II landfill.  The MEA reclaimer bottoms could be solidified, using a
bulking agent such as Portland cement, then landfilled at a Class II site.  This would increase the
volume of waste for disposal.

Landfilling is becoming  an  unpopular  option  for waste  materials if  other environmentally
acceptable disposal methods are available. Landfilling only  stores the waste -  it neither renders
the waste harmless nor does it permanently immobilize the waste (39).  In addition, landfilling
fees are  increasing  to cover construction and decommissioning costs  of  the  landfill.   Landfill
operators are also becoming reluctant to accept industrial wastes such as amine sludges which may
be hazardous or classified as hazardous at some time in the future (40).


Land Treatment

Land treatment is the controlled application of  a biodegradable waste to soil  which allows soil
bacteria  to break down the waste into harmless components which are used by soil bacteria and
plants. Soil also will immobilize some waste compounds, assisting in preventing contamination  of
ground or  surface water (41).  The assimulative capacity of the soil  depends upon a number  of
Factors, including  the toxicity of the waste to bacteria and to plants, the  immobilization of the
hazardous  components of the waste, the rate of biodegradation of the waste compounds and the
transformation or detoxification of components by soil microorganisms (42).   It is important  to
ensure that the soil assimulative capacity is not exceeded when applying the waste, either in one
application or in repeat applications.  Otherwise, damage to  soil and  soil microorganisms and
contamination of surface or ground water may result.

This study indicates  that soil does immobilize these wastes,  tha| three of the four are degraded
when mixed with  soil and that addition of a low concentration of these three wastes results  in
increased growth in  plants. The MEA reclaimer bottoms and  Plant A basic DEA diatomaceous
earth filter sludges are good candidates for land treatment.

However, the acidic cellulose fibre filter DEA sludge inhibited plant growth and, although toxicity
to bacteria decreased, toxicity to fish did not. This sludge also inhibited growth of perennial rye.
Treatment such as composting  would be required for this sludge before it is applied to soil. In
addition, it contained levels of nickel and copper, probably from metal corrosion, that were higher
than levels found in natural  Canadian soils (43) and which could accumulate to toxic levels  if
applied repeatedly.  Increasing the pH of the amine solution to 7.0 using potassium hydroxide
would  probably reduce the nickel and copper content of the filter sludge.


                                         580

-------
Treatments

Amine sludges with high sodium content could cause salinization if applied to land.  It would be
important  to either reduce or eliminate the sodium from the waste prior to land  application.
Sodium  in the liquid waste  can be isolated by precipitation, flocculation or  other chemical
treatments and recovered for reuse, but this treatment would not be useable for the solid DEA
filter sludges and it is probably not economically feasible.

In order to eliminate sodium from the wastes,  potassium hydroxide could be  used to replace
sodium hydroxide to maintain the high pH in the process. This compound would  be more soluble
than sodium hydroxide, resulting in fewer  precipitation problems and would be used by bacteria
and plants as a nutrient, increasing the rate of degradation. It is possible that a potassium and
nitrogen rich amine sludge could be used as a soil amendment for reclamation.

It would also be possible to biodegrade the wastes prior to application, thus reducing concerns
regarding  overapplication  and ground and surface water contamination.   For the liquid amine
wastes, a bioreactor such as an activated  sludge system could be used.  However, the wastes would
require  dilution  prior to treatment because they are toxic to bacteria and this  would increase
water consumption.  If other liquid biodegradable wastes could be used to dilute the amine
sludges then this would be an acceptable option.  Once the wastes are biodegraded, their toxicity
should be  reduced and they could be applied to land at higher rates. It would still  be important to
ensure that the assimulative capacity of the soil is not exceeded.

The solid DEA wastes could be composted then applied to land once the organic compounds have
broken down.  The diatomaceous earth filter sludges would probably require addition of a bulking
agent such as straw, sawdust or biodegradable municipal waste.

However,  the acidic cellulose  fibre  filter  DEA sludge inhibited plant growth and, although toxicity
to bacteria decreased, toxicity to fish did not. This sludge  also inhibited growth of perennial  rye.
Treatment such  as composting would be required for this  sludge before it is applied to soil.  In
. addition, it contained levels of nickel and copper, probably from metal corrosion, that were higher
than levels found in natural  Canadian soils (43)  and which could accumulate to toxic levels if
applied repeatedly.  Increasing the pH of this process would probably  reduce  the nickel  and
 copper content.  Addition  of potassium hydroxide during the gas treating process  to maintain the
pH at 7.0 or higher would suffice.

 Further research determining the soil assimulative capacity in the field to different types of soil,
 the potential for repeat applications of the waste and assessing treatments is required.


 Deep Well Disposal

 Deep well disposal is a disposal method commonly used in  Alberta by the petroleum industry  and
 has been  used to dispose  of liquid  amine sludges (44, 45).  Deep well disposal involves  the
 injection of liquid wastes into rock  formations where the waste material should be contained  and
 isolated from surface and useable ground water. New guidelines are being implemented that  will
 outline the criteria for wastes that may be disposed of in such wells (46).  Under these guidelines,
 wastes that may be treated  by conventional physical,  chemical or biological  means are  not
 acceptable for deep well disposal.

 Only the liquid DEA backwash liquids and MEA wastes could be disposed of through deep well
 disposal.  These wastes would  require filtering and any solid material would require disposal.
 However, this study indicates  that amine wastes can be treated by conventional means. The metal
 content of the sludges is  generally low, the  sodium can be reduced at source or in the waste
 material and the organic amine wastes are biodegradable into non-toxic components.
                                              581

-------
Surface Water Discharge

At present, the Gas Processing Plants Waste Water Management Standards in Alberta (47) do not
allow liquid process sludges, such as the MEA reclaimer bottoms, to be released into surface
water. These standards are being revised and will be made more stringent (48).  However, it could
be argued that, if the amine sludges were biodegraded, ammonia removed and the resulting waste
met the standards, surface water discharge might be an acceptable option.

Such a disposal method would require a bioreactor to digest the sludges prior to discharge.  Under
the provincial standards, the levels of metals in the sludges, although lower than soil levels, are too
high to allow discharge into surface water. The pH and ammonia nitrogen content are both higher
than acceptable. There are, at present, no limits on the sodium content of wastewaters for surface
water discharge, but the sodium in these  sludges could have a detrimental effect upon soils along
the stream.


Incineration

Incineration converts wastes to gases and an incombustable solid residue. The product gases are
released to the atmosphere and the solid residues, if acceptable, are landfilled.  Tailgas scrubbers
and electrostatic precipitators are required to ensure that emissions do not exceed guidelines (49).
Waste from  the scrubber and the residue  will also require disposal and,  if the waste was
hazardous, must be treated as hazardous. Legislation  and guidelines regarding incineration,
particularly of hazardous waste, are presently being revised and are expected to become more
stringent (50).

With the exception of  the  diatomaceous earth filter,  amine  wastes are primarily organic.
Therefore, they  should be easily incinerated,  although preheating may be required.  However,
testing is required to ensure  that no toxic gases would form and that scrubbers and precipitators
would be adequate. Any ash  would also require analysis to ensure that the metal content is below
the limits acceptable for landfilling.

At present, only the Special Wastes Treatment Facility in Swan Hills has a licence to incinerate
industrial hazardous waste (51). The cost of constructing an incinerator for these wastes would be
high and further costs  would be incurred with disposal of the solid residues. The  diatomaceous
earth filter sludges would not greatly reduce in volume if incinerated and could not be incinerated
at high temperatures because the filter material would vitrify (52).


Recommended Management Option

Of the  five disposal options, land treating is the most acceptable because it  offers a means to
break down the wastes into their basic components which are then used by bacteria  and plants as
nutrients.  The  use of potassium instead  of sodium in the process would provide a nutrient,
hastening the  degradation process.  The process producing the cellulose fibre filter sludge should
also be maintained at a higher  pH to reduce corrosion and the sludge should be composted prior
to being applied to land .

Further research determining the soil assimulative capacity in the field  to different types of soil,
the potential for repeat applications of the waste and assessing treatments is  required.
                                                582

-------
Conclusions

1. Analysis of amine sludges indicates that they usually contain concentrations of metals lower
than found naturally in Canadian soils (53). One acidic DBA cellulose fibre sludge did contain
levels  of copper and nickel above those levels, which may be caused by metal corrosion.  The
other sludges all had a high pH and high concentrations of sodium and nitrogen. The sodium is
usually added to the amine solution during the gas treatment process.

2. Amine sludges contain a variety of amine compounds, some of which have not been identified,
and data on the known compounds is limited. Carcinogenic compounds have been found in amine
sludges. The results indicate that the composition of the sludges differs between plants and over
time at one plant.  Low concentrations of organic compounds such as phenols and benzene have
also been found in reclamation  bottoms and low levels of phenols were  found in amine filter
sludges (54).

3.  The study sludges were found to be toxic to bacteria, fish and, in most cases, to germinating
seeds. The acidic, low sodium DEA sludge was not toxic to seeds.   Another study has determined
that amine filter sludges and reclaimer bottoms were toxic to germinating seeds, bacteria, algae,
cladoceran, nematodes and fish (55).

4.  It is recommended that  the wastes be considered as hazardous for the purposes of handling and
disposal to prevent future liability in  human health issues and cleanup of spill or disposal sites.

5.  This  research  indicates that  the amine compounds in the sludges would be  amenable to
bacterial degradation.   Results  from the  incubation  and plant  growth  study suggested that
degradation of toxic compounds in three  of the four sludges had occurred.  Results for the fourth,
an acidic DEA cellulose fibre filter sludge, indicated  no  significant change in toxicity to fish,
although toxicity to  bacteria  did decrease.  However, addition of 2.5% of this sludge to soil
inhibited growth of perennial rye.

6. The recommended management option for these wastes  is  land treatment following treatment.
High  sodium contents of  the sludges must be reduced and  it is  recommended that potassium
 hydroxide be used in place of sodium hydroxide in the process.

 7. The process producing the acidic  cellulose fibre sludge should be maintained  at a higher pH to
 prevent corrosion and reduce the nickel and copper content of the  sludge.  This sludge should be
 composted then land treated.  However, further research  is  needed to assess biodegradation of
 this sludge.

 8.  Further research to determine the soil  assimulative capacity of amine sludge in the field for
 different types of soil, the potential for repeat applications of the waste, and  to assess treatments is
 required.
                                               583

-------
                                        TABLE 1

           PARAMETERS OF THE DEA FILTER SLUDGES (ppm unless otherwise stated)

Parameter                      Plant A                             Plant B

                      Concentration   Range           Concentration
pH
EC
Elutrient colour
Antimony
Arsenic
Barium
Beryllium
Cadmium
Chromium
Cobalt
Copper
Lead
Manganese
Mercury
Molybdenum
Nickel
Nitrogen
Selenium
Silver
Tin
Vanadium
Zinc
Boron
Calcium
Magnesium
Potassium
Sodium
   10.6         10.5 - 10.6
    1.6 mS/cm    1.3 - 1.6
  dark brown

  (total concentration)
   < 0.005 ppm
   <0.05
  259           217 - 265
    2               2-3
    2
  108           105 - 118
    14
    2
    62
    < 0.005
    <0.2
    51
16,300
    <03
    <0.5
    2
    84
    44
                 13-22

                 62-66
                 49 - 52
             16,300 - 24,800


                 2-7
                78-86
                42-45
                                                            Range
 (soluble concentration)
   238         2.25 - 2.50
   3              2-4
                                        4.5            4.5 - 4.6
                                        0.22 mS/cm   0.21 - 0.22
                                      no colour

                                      (total concentration)
                                        < 0.005 ppm
                                        <0.05
                                       277            273-284
                                         2              1-2
                                         2
                                        90            89-90
        310
         <2
         72
         < 0.005
         <0.2
        180
        600
         <03
  10
2,770
                                    2,600 - 2,780
         <2
         42
         38

(soluble concentration)
         0 JO
         3
        <1
         3
        118
 280 - 310

  66-72
 160 - 180
450-700
  36-46
  37-39
                                                     038 - 0.50
                                                       2-5

                                                       2-3
                                                     118 - 119
                                       584

-------
                                        TABLE 2

     PARAMETERS OF THE MEA RECLAIMER BOTTOM SLUDGES (ppm unless otherwise stated).

Parameter                    Plant C                              Plant D
PH
EC
Elutrient Colour
Concentration

     11.0
      3.1 mS/cm
     amber
Range         Concentration   Range

10.9 -11               11.6
  3.1  35              5.2 mS/cm
                      brown
11.5 - 11.7
 5.1 - 5.3
                      (total concentration)
                                          (total concentration)
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Copper
Lead
Manganese
Mercury
Molybdenum
Nickel
Nitrogen
Selenium
Silver
Tin
Vanadium
Zinc
0.15
<0.5
<0.1
<0.1
0.5
0.5
153
<0.1
0.2
0.4
9.3
<0.05
16.2
31
13,900
<2
<0.01
<0.2
0.7
53
0.14 - 0.18



0.5 - 0.6
0.2 - 0.6
150 - 164

0.1 - 0.3

9.1 - 9.6

15.2 - 18.0
31 34
12,800 - 16,000



0.6 - 0.7
5.2 - 5.9
(soluble concentration)
Calcium
Magnesium
Potassium
Sodium
6
<1
46
10,300
3-6

45-47
10,000 - 11,200
0.035
<0.5
<0.1
<0.1
0.3
<0.1
o!i
<0.1
<0.1
<0.4
0.2
<0.05
0.9
0.1
42,400
<2
<0.01
<0.2
<0.1
L5
0.019 - 0.087



0.3 - 0.4

0.1 - 0.2



0.2 - 0.3

0.7 - 0.9
0.1 - 0.2
42,400 - 43,400




1.4 - 1.5
(soluble concentration)
4
<1
45
13,700
3-6

44-45
13,200 - 14,000
                                         585

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                                                 TABLES
                   GC/MS ANALYSIS OF TWO DEA FILTER SLUDGES FOR AMINE COMPOUNDS

Plant A PEA filter sludge                             Plant B DEA filter sludge

Compound                   Concentration    Compound                         Concentration
H2N-CH2-R
Diethanolamine
Unknown, not N-containing
Unknown, difficult to interpret
Total
   532 ppm    Diethanolamine                        57,000 ppm
   480         N,N'-bis(2-hydroxyethyl) piperazine        7,800
 26,620         Monoethanolamine                      7,100
  7,300         Triethanolamine                         6,800
               N-(2-hydroxyethyl)piperazine              6,000
               N,N'-bis(2-hydroxyetnyl)imidazolidone     2,700
               N,N,N'-tris(2-hydroxyethyI) ethyldiamine    2,500
               Unknown, N-containing, mw 277 - 392     36,800
               Unknown, not N containing, mw 304, 372  13,100

 23,232         Total                                  139,800
                                                 TABLE 4

                 GC/MS ANALYSIS OF TWO MEA RECLAIMER BOTTOMS FOR AMINE COMPOUNDS

Plant C MEA reclaimer bottoms                       Plant D MEA reclaimer bottoms
Compound
Concentration   Compound
Concentration
N(2-hydroxyethyl)piperazine
HN(C2H4OH)-CH2R
Unknown ethanolamine
Diethanolamine
H2NCH-R, mw 405
2-hydroxyethyl-methylamine
HiNCH^-R, mw 389
Polycyclic, N containing
Unknown cyclic ethanolamine
N,N'-bis(hydroxyethyl)
        ethylenediamine  1,900
N(hydroxyethyl)-l,2-ethylenediamine
Unknown, N containing, mw 263 - 386
Unknown, not N-containing, mw 230

Total
    57,000 ppm Monoethanolamine                    82,000 ppm
    14,300      N(hydroxyethyl)imidazolidone           34,000
    10,300      N(hydroxyethyl)N'-methyl imidazolidone  17,000
     6,000      2-(2-aminoethoxy)ethanol               12,000
     4,600      Glycine                                6,300
     2,800      N-methyldiethanolamine                 5,700
     2,700      N(2-hydroxyethyl)-l,2-ethylenediamine    4,700
     2,500      2-ethylhydroxy-3-propylhydroxyamine      4,400
     2,400      Unknown, N containing, mw 276, 320, 395 22,000
               Unknown, not N containing, mw 198, 296  8,700

     1,800
    29,600
     7,200

     143,100    Total                                 196,800
                                                     586
                                                                                                      10

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                                               TABLE 5

        ORGANIC COMPOUNDS IDENTIFIED IN AMINE RECLAIMER BOTTOMS AND LEAF FILTER SLUDGES (58)
                                    Reclaimer Bottoms
Compound

Phenol
Dimethyl phenol
Ethyl benzene
Aliphatic acids (C2 -17)
Hexadecanoic acid ester
Cyclic thioethers
Pentathiepane
Range

4-8 ppm
2
0-0.7
0-7*
0-1
0-1*
1-5.5
Tetrahydro 1,1-dioxide thiophene  0 - 0.1
Benzole acid                    0 - 0.4
Compound

Methyl phenol
Ethyl phenol
Dimethyl benzene
Tetradecanoic acid, ester
Ethylhexanoic acid
Unidentified acids
Ethenythio octane
2-(2-phenoxy ethoxy)ethanol
Quinoxaline
                                    Amine Leaf Filter Sludge
Compound

Asphaltene material
Aliphatic acids (C6 - C8, C15, C17

* each compound
Range

3.5 - 3 ppm
0-0.1
0-3
0-1
0.2-1
0-2
0-0.1
0-0.2
0 - 0.07
      Range         Compound                      Range

      4350 ppm       2,6-dimethyl-2,5-heptadiene-4-one   2 - 3 ppm
       0.4 - 5*        Phenol                          0 - 0.1
                                               TABLE 6

                             CHANGES IN TOXICITY AFTER 6 WEEKS INCUBATION
   (Toxicity to bacteria and fish of liquid elutrient from a 10% sludge/soil mixture and to germinating seeds of a 5%
                                          sludge/soil mixture).
       Plant A PEA filter sludge
Test organism
bacteria EC5Q
seeds - 5% mix
fish LC50
Test organism
bacteria EC5Q
seeds - 5% mix
fish LC5Q
WeekO
Week 6
62.7% 55.2% *
100% germinated 100% germinated *
> 3% > 3.2%
Plant C MEA Reclaimer Bottoms
WeekO
11.8 %
5% germinated
3.5%
Week 6
20.9%*
0% germinated *
6.4%
 LC^ - Median Lethal Concentration
 ECjg - Median Effective Concentration
 * no significant change
                            Plant B PEA filter sludge

                           WeekO              Week (
                                                         9.4%
                                                         95% germinated
                                                         0.64%
                                               76.4
                                               100% germinated *
                                               0.5%*
                                                         Plant D MEA Reclaimer Bottoms

                                                         WeekO              Week 6
                                                         12.7%
                                                         95% germinated
                                                         1.5%
                                               44.7%
                                               100% germinated *
                                               6.4%
                                                587
                                                                                                   11

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References

1.  Wotherspoon and Associates and D. Bromley Engineering Ltd., 1Q8R. Industry Waste Survey.
Canadian Petroleum Association, Calgary, Alberta.
2. Monenco Consultants Ltd., 1985. Gas Plant Sludge Characterization: An Information Review.
A joint project by the  Canadian Petroleum Association and Environment  Canada.  Canadian
Petroleum Association, Calgary, Alberta.
3.  Boyle, C.A., 1990.  Petroleum Waste Management: Amine Process Sludges. A joint project by
the Canadian Petroleum Association and Environment Canada.  Canadian Petroleum Association,
Calgary, Alberta.
4.  Krett, J., 1988. DEA Quality, unpublished. Husky Oil Operations, Calgary, Alberta.
5.  Smith, R.F. and A.H. Younger, 1972.  Tips on DEA Treating. Hydrocarbon Processing 51(7),
98-100.
6.  Mather, A.E.  and  S.E.  Hrudey,  1985.    Review  of  Degradation  Products  Formed in
Alkanolamine Gas Treaters. Gulf Canada Resources Ltd., Calgary, Alberta.
7.  Sax, N.I.  and R.J. Lewis, Sr., (eds.),  1989. Dangerous Properties of Industrial Materials f7th
ed.). Van Nostrand Reinhold Co., New York, U.S.A.
8.  Mather and Hrudey,  1985, op.cit.
9. Patterson, B., 1990. personal communication. Environmental Manager, Ram River Gas Plant,
Husky Oil Operations Ltd., Rocky Mountain House, Alberta.
10. Monenco Consultants Ltd., 1987. Gas Plant Sludge Characterization: Pilot Program.   A joint
project by the Canadian Petroleum Association and Environment Canada. Canadian Petroleum
Association, Calgary,  Alberta.
11. Patterson, per. comm., op.cit.
12. McCarthy,  M., 1990. personal communication. Process Technician, West Whitecourt Plant,
Amoco Canada Petroleum Company Ltd., Whitecourt, Alberta.
13. Monenco Consultants Ltd., 1987, op.cit.
14. Dell, M., 1990. personal communication. Engineering Technician, Rimbey Gas Plant, Gulf
Canada Resources Ltd., Rimbey, Alberta.
15. McLeod, S., 1990. personal communication. Operations Manager, Okotoks Sour Gas Plant,
Canadian Occidental  Petroleum Ltd., Okotoks, Alberta.
16. Monenco Consultants Ltd., 1987, op.cit.
17. McKeague, J.A. et. al., 1979.  Minor Elements in Canadian Soils.  Agriculture Canada,  Land
Resource Research Institute Contribution No. LRRI27, Ottawa, Ontario.
18. Erickson, D., 1985. Degradation Products Formed in Alkanolamine Gas Treaters. Report #1.
Enviro-Test Laboratories, Edmonton, for Gulf Canada Resources Inc., Calgary, Alberta.
19. Monenco Consultants Ltd., 1987, op.cit.
20. Canterra Energy  Ltd., 1988.  Amine Analysis. Ram River Gas Plant. Canterra Energy Ltd.,
unpublished.
21. Monenco Consultants Ltd., 1987, op.cit.
22. Canterra Energy Ltd., 1988, op.cit.
23. Monenco Consultants Ltd., 1987, op.cit.
24. Ibid
25. Ibid
26. Stevenson, FJ., 1986. Cycles of Soil. John Wiley and Sons, USA.
27. Stover, E.L., 1980.  "Biological Treatment  of Hazardous Wastes."  in A.A.  Metry, ed., The
Handbook of Hazardous Waste Management. Technomic Publishing Company, U.S.A.
28. Gannon, J.E., M.C. Adams and E.O. Bennett, 1978. Microbial degradation of diethanolamine
and related compounds. Microbios 23: 7-18.
29.  Williams, G.R. and A. G. Callely, 1982.  The Biodegradation of Diethanolamine  and
Triethanolamine by a Yellow Gram-negative Rod. Journal of General Microbiology 128: 1203-
1209.
30. Ibid
31. Stover, 1980, op.cit.
32. Loehr, R.C. and  M.R. Overcash, 1985.  Land Treatment of Wastes: Concepts and General
Design.  Journal of Environmental Engineering, vol. 111(2): 141 -160.


                                         588

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 33. Parker, L.V. and T. F. Jenkins, 1986.  Removal of Trace-Level Organics by Slow-Rate Land
 Treatment. Water Resources  20(11):1417-1426.
 34. Stover, 1980, op.cit.
 35. Ibid
'36. Alberta Environment,  1987.  Guidelines  for  Industrial Landfills.  Alberta  Environment,
 Edmonton, Alberta.
 37. Jain, R.K, 1988.  "Overview of Hazardous/Toxic Waste Management." in Gronow, J.R., A.N.
 Schofield  and  R.K. Jain (eds.),  Land  Disposal  of Hazardous Waste.  Ellis  Horwood  Ltd.,
 Chichester, England.
 38. Fernandes, T., 1989. personal communication. Hazardous Waste Specialist, Industrial Waste
 Branch Alberta Environment,  5 floor, 9820 106 St., Edmonton, Alberta
 39. Sutter,  H.  1989.   "Review of Hazardous Waste Management Systems as  Applied by the
 Government and Private Sectors." jn S.P. Mltezou, A.K. Biswas and H. Sutter. eds., Hazardous
 Waste Management. Tycooly Publishing, London, England.
 40. Jackson, F., 1990. personal communication. Landfill Operator, Engineering and Sanitation,
 City of Calgary, 800 McLeod Trail S.E., Calgary, Alberta.
 41. Environmental Protection Agency, 1986. Permit Guidance Manual on Hazardous Waste Land
 Treatment Demonstrations.  National  Technical  Information  Service,  U.S. Department  of
 Commerce, Washington, D.C., U.S.A.
 42. Loehr and Overcash, 1985, op.cit.
 43. McKeague, et. al., 1979, op. cit.
 44. Dell, pers. comm., op.cit.
 45. McLeod, pers. comm., op.cit.
 46. Alberta Environment, no date. Interim Alberta Environment Quality Criteria on Deepwell
 Disposal of Wastewater. Alberta Environment, Edmonton, Alberta.
 47.  Alberta  Environment,  1973.  Gas Processing  Plants Waste Water Management Standards.
 Alberta Environment, Edmonton, Alberta.
 48. McLure,  S., 1990.   personal communication.  Head, Water Quality, Alberta Environment,
 Edmonton, Alberta.
 49. Alberta Environment,  1989.  Interim Guidelines for  Incineration of Hazardous  Wastes.
 Alberta Environment, Edmonton, Alberta.
 50. Fernandes, pers. comm., op.cit.
 51. Huang, R., 1990.   personal communication.   Senior Engineer, Industrial  Waste  Branch,
 Alberta Environment, 5  floor, 9820 106 St., Edmonton, Alberta.
 52. Rae, W., 1990. personal communication. Sales  Representative, HarCros (Canada) Ltd., 5711
 ISt. S.E., Calgary, Alberta.
 53. McKeague, et. al, 1980, op. cit.
 54. Monenco Consultants Ltd., 1987, op.cit.
 55. Ibid
 56. Ibid
 Acknowledgements:   I would like  to  thank  Environment  Canada, the Canadian Petroleum
 Association, the Energy Resources Conservation Board, Gulf Canada and Husky Oil for providing
 funding and resources for this project.
                                           589

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MINIMIZING  ENVIRONMENTAL   PROBLEMS  FROM   PETROLEUM   EXPLORATION  AND
DEVELOPMENT IN TROPICAL FOREST AREAS
George Ledec
Environmental Officer
Latin America and Caribbean Region
World Bank
Washington, DC  20433
United States
 Introduction

 Tropical  forest  areas  are  highly  vulnerable  to  serious   and  often
 irreversible   environmental  damage   from   poorly-planned  development
 activities.  However, if the proper environmental measures are adopted and
 rigorously  followed, petroleum exploration  and development in tropical
 forest  areas  need not cause major environmental damage.  Moreover, most
 of  these  environmental measures do not significantly increase petroleum
 production  costs; some can  even reduce costs.

 This  paper  outlines the basic measures needed to minimize  environmental
 impacts  from  onshore petroleum exploration  and development in tropical
 forest  areas.   The  paper  is  based  on the  author's  experience with
 petroleum development  in the Amazon region of South  America; however, the
 recommendations  provided here are likely to prove  useful for petroleum
 work  in tropical  forested countries worldwide.  The paper focuses  on the
 most  critical environmental issues involving  petroleum exploration and
 development in tropical  forest  areas;  it does not address certain  lower-
 priority  environmental problems (such  as carbon dioxide emissions  from the
 flaring of  natural  gas).

 Oil companies can help ensure that environmental measures such as those
 outlined  below are  followed by codifying them  (as specific policies and
 procedures) within an Environmental Manual.   Such a  Manual should specify
 the practices needed to minimize negative environmental impacts from each
 phase   of  petroleum  development,  including  seismic  investigations,
 exploratory and production  drilling,  pipelines, storage, refineries, and
 ports.  The Manual  should  be detailed and explicit, so that it would be
 clear when contractors or employees are (or are not) following  its  rules.
                                  591

-------
Road Construction

In most  tropical countries  (particularly in  Latin America),  the most
severe environmental impact from petroleum development is the colonization
and deforestation that  follows the  penetration of forested areas by  oil
industry roads.  Much of this colonization and deforestation takes place
on lands which are unsuited for sustainable agricultural development.   For
example, recent unofficial estimates by  a Bank mission in one Amazonian
country  indicate  that,  in the absence  of specific  measures  to control
colonization, each kilometer  of new road built by the oil industry through
forest results in the colonization of 400-2,400 hectares.

To minimize  deforestation, oil companies  therefore need to minimize  the
kilometers  of new  roads  constructed within most forested areas.    The
layout  of  any new  roads  through  forested  areas  should  be  carefully
planned, to  minimize their length.   In  some  cases, the supplemental  use
of  rivers  for transporting  supplies can reduce  the kilometers  of road
built.   Whenever economically feasible,  exploratory  drilling  sites  in
forested  areas should  be reached by using helicopters,  rather  than by
constructing access roads.   Perhaps most importantly,  new  production
drilling operations  in  forested  areas should construct cluster drilling
platforms  (as Conoco plans  to use  in Ecuador's  Yasuni National Park),
rather  than dispersed  individual wells.   This  can greatly  reduce   the
kilometers of  new roads needed.

Prior  to building new  roads  through forested areas with special legal
protection   (such  as National  Parks,   Forest  Reserves,  or  Indigenous
Reserves),  the responsible oil company  should  financially support a  24-
hour  roadblock  and a  regular  system  of  patrols  to prevent  illegal
colonization.  This can  be done through legal  agreements with the relevant
land management agency (Park  Service, Forest Service, Agrarian Institute,
or  other agency).   Locating  the oil  workers'  camp  just outside   the
entrance  to  the  protected  area  can also help  to  deter colonization.
Properly staffed roadblocks can also be used to  control  the transportation
of  illegally cut  logs,  wildlife  products, or  other  contraband  from  the
forest.  After they are  no longer needed  (such  as  when  petroleum reserves
have  been  commercially  depleted,   or  after  unsuccessful  exploratory
drilling), roads built through unpopulated, forested zones  should normally
be decommissioned (such as by removing the bridges).  This would greatly
reduce future  risks of colonization and deforestation  in the area.

Environmental Manuals should specify maximum widths for various types of
oil  roads  through  forested  areas.   In  some  cases  (especially  in flat
terrain), forest canopy  cover can be maintained, so that the  road need  not
be  a  barrier to the movements of monkeys and  other arboreal wildlife.
Environmental Manuals should also specify environmentally appropriate road
construction  materials   and  techniques  in  forested  areas.    Whenever
possible,  geo-textiles   or  geo-plastics  (woven  polyvinyl  chloride  or
polypropylene)  should  be used  as  road  construction  support  material,
                                592

-------
because they reduce the requirements for timber and gravel.  To the extent
that any timber is used  for the  road base,  it should come  entirely (or as
much as possible)  from trees that are  cut  for the  road right-of-way.  For
clearing the  road right-of-way,  trees  should  be  felled  with chainsaws
rather than bulldozers.    (Unlike chainsaws, bulldozers  disturb the soil
and tree roots; they also tend to damage many more trees outside the road
right-of-way.)  The Manuals  should also  indicate  under which conditions
gravel, heavy  oil,  or other  materials  can be used for  road surfacing.
(When oil is used  for  road surfacing,  some of it washes away  into streams;
however, gravel mining disturbs  river ecosystems.)

Roads constructed across streams should provide for proper drainage, such
as  through  the use of pipe or   box culverts.   This is needed to avoid
partially damming  small  streams, which blocks the migration of fish and
other  aquatic  life, kills  trees and  increases mosquito habitat upstream
of  the road,  and  reduces water  flow  downstream.   The  culverts or other
drainage systems require routine maintenance, so that they  are not clogged
with debris.

Some  oil  companies  (both  governmental  and  private)  have  "community
relations  funds",  which are used  to  finance  small-scale  development
projects in areas  near the oil  company  facilities.  These should not be
used for building or improving roads through forested or legally protected
areas.   Rural  roads  financed through these special  community programs
should be subject to the same environmental criteria as roads planned for
oil production purposes.
Management of Drilling Wastes

Spent  drilling  muds (which contain various  toxic  substances) should be
landfilled in dry  pits,  or  in sumps  from which the water has been piped
out.   The  landfill pits  should be lined with a suitable substance (such
as  plastic)  to  minimize  risks  of   groundwater   contamination.    The
landfilling should take place before  the site is abandoned, while on-site
bulldozers are  still available.

Formation water produced  from drilling operations is oily, often extremely
salty, and contains various  toxic compounds.  Whenever feasible, formation
water should be reinjected into the ground.  In any cases where this might
not be feasible,  the formation water  that is not  recycled  (such as to
formulate new drilling muds) should be  treated on-site,  prior to being
discharged  in   adjacent  waterways.    Simple on-site  treatments  include
aeration spraying  or cascading for oxygenation and cooling,  skimming of
surface  oil,  flocculation  and settling to  remove certain  salts,  and
dilution with  fresh water.   These treatments  should also  be  used  (as
needed) for water piped out of oil sumps.

While  they  are  in use  (prior  to  eventual  landfilling),  oil  sumps


                                 593

-------
(piscinas) should be screened from above with 2 cm (or finer) mesh nets,
to prevent birds, mammals, and larger insects from entering the sump  and
being trapped and killed by the surface oil.  Nets such as these are  now
legally  required  in  parts  of   the  United  States;  their  cost   is
insignificant, relative to the costs of drilling each well.
Prevention and Control of Oil Spills

Environmental  Manuals  should  specify  design  standards   for   any  new
pipelines  for  petroleum and  its  derivatives  (as well  as  natural gas).
These standards should indicate  the proper spacing and types of valves and
automatic  shut-off  mechanisms,  to minimize damage  from pipeline leaks.
Pipelines should often be buried for environmental reasons—for  example,
to  reduce  forest clearing for  the  right-of-way, or to  reduce  risks of
damage  from vehicle  crashes  along  highways.   To the  extent feasible,
pipelines  and  their associated  service roads  should be re-routed around
environmentally  sensitive  areas,  such as National  Parks and equivalent
reserves.

Oil  storage  tanks need permanent  earthen levees around them; the levees
should be  dimensioned  such that they can contain all of the oil  from the
storage  tanks,  in  case  the  latter  should  rupture.    Refineries  need
appropriate  water  pollution  control  equipment, proper  operational  and
maintenance  procedures for this  equipment,  and  staff  who know how to
operate  and maintain the equipment.    All  infrastructure  which holds
petroleum  or  its derivatives  (including pipelines, storage  tanks,  and
refineries)  should  have  a  precise  schedule  of  routine  maintenance,
including  periodic  replacement  of parts, to minimize risks of spills or
other malfunctions  due to poor maintenance.   Spent motor oil  and  similar
wastes  should be  collected  in barrels  and  burned  or landfilled--not
discharged into  streams, rivers, or lakes.  No washing of motor  vehicles
in  streams  and rivers  should be permitted.

Strict  adherence to  these measures  should minimize the  frequency  and
magnitude  of accidental oil spills.  However,  some accidental spills are
inevitable (such as when  Ecuador's  main oil  pipeline  ruptured  in 1987
after  a massive earthquake and resulting  landslides).   It is therefore
important  for  oil  companies  to  develop Oil Spill Contingency Plans that
encompass  all  of their pipelines,  storage tanks, refineries, ports,  and
similar   facilities.     Contingency   Plans   should  outline   specific
technologies  and  control  systems,  sites  where control  equipment  and
available  personnel are to be  based,  an adequate  budget  and source of
financing, the division of institutional responsibilities between the oil
company  and national and local Government  agencies,  and a schedule for
rehearsal of oil spill containment and clean-up operations.   Oil companies
should  also develop  efficient  administrative mechanisms for processing
legal claims for economic  damages resulting from oil spills.
                                  594

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Land Management at Petroleum Facilities

New  camps  built  in  forested  areas  should  not  use more  land  than is
required for buildings,  recreational purposes, and safety considerations.
Some oil company camps in Latin America occupy many more hectares of once-
forested land  than necessary,  due to  their huge lawns  and  overly wide
streets.

After  drilling or other  operations  which  involve land  clearing  or
excavation are terminated, all cleared land should be rehabilitated.  In
humid tropical zones such as Amazonia, simply spreading out the soil which
was originally scraped off during site preparation will generally promote
rapid natural revegetation.  In such cases, manual reforestation or other
intensive landscaping are usually not needed.

In  all  types of petroleum exploration and  development  areas (including
seismic  study  sites),   all non-biodegradable   solid  wastes  (such  as
plastics) should be deposited  in small,  on-site  landfills.   "Littering"
with any such wastes should be strictly prohibited.
Managing the Activities of Oil Workers

All  fishing  (especially with  dynamite  or poisons)  and hunting  by oil
workers should be strictly prohibited,  because  it greatly increases the
local environmental impact of seismic studies or  drilling activities.  Oil
companies  and  contractors  therefore   need to  transport  sufficient
quantities of food to their workers.

Whenever possible, firearms should be completely prohibited from remote,
forested oil exploration or production areas.   In countries where guerilla
groups are  nonexistent,  firearms are not  needed for  "protection".   In
those countries where  a legitimate need  for firearms may  exist  due to
local political instability, pistols  should  be  used (whenever possible)
rather than  rifles  or  shotguns  (because  they  are less  effective for
hunting), and  supplies  of ammunition should be  tightly  controlled and
monitored.

Mobility restrictions should be  enforced  for oil workers  in forested or
other environmentally sensitive areas.   In particular, oil workers should
not  be  allowed to  stray  from  camp in  areas anywhere near  indigenous
populations.  Also,  no alcohol should be permitted in such areas.

Oil companies should  specify (within their Environmental or other Manuals)
and  implement appropriate occupational  safety standards and procedures.
The World Bank's Occupational Health and Safety Guidelines  can be a useful
reference in this regard.
                                 595

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Institutional Aspects

Effective institutional mechanisms are needed to ensure that the rules set
forth in Environmental Manuals are actually followed in remote,  forested
areas.  For example, bidding and contracting documents should  explicitly
outline all necessary environmental protection measures (as  specified in
the Environmental Manual).   Financial penalties  (large  enough to serve as
effective  deterrents)  should be  specified for  all violations  of  this
Manual by  contractors  and  concessionaires  (including  transnational  oil
companies).   A transparent system  of  penalties  (fines,  suspension,  or
termination) should  also be established  for individual employees of  oil
companies or contractors, for  each type of violation of the Environmental
Manual.

Environmental Manuals  are  effective only to the  extent  that  sufficient
environmental staff are available to ensure their implementation.  It  is
therefore  important for oil  companies  to  hire  an  adequate  number  of
environmental staff, and  to establish some type of in-house environmental
unit.  Environmental Manuals should  indicate the number, specific duties,
and  necessary  qualifications  of on-site environmental  control officers
needed for  each  type of petroleum exploration  and development activity,
along with the approximate budget  allocations  needed to  support  these
staff in the field.   Besides operational  activities, some staff should be
responsible  for  routine,   on-site  environmental  monitoring  of  water
quality, aquatic life, and  other environmental indicators.

To ensure  that the  environmental staff of  petroleum companies are well-
qualified to carry out  their responsibilities, some type of environmental
training  is usually necessary.    Environmental training  options (which
should  be  tailored  to  the  specific  needs   of  each  oil  company's
environmental  unit)   include  short,   locally-organized   courses   on
environmental  assessment and  mitigation; working as  counterparts  with
environmental consultants on specific tasks  (such as environmental impact
studies  of proposed new  projects); participation  in overseas  special
courses (such as  those  offered by the Center for Environmental Management
and Planning of the  University of Aberdeen, Scotland) or conferences (such
as this  symposium); and  scholarships for master's  or other  degrees in
environmental sciences at national  or foreign universities.

Environmental Manuals should specify the  legal framework (including laws,
regulations,  and administrative decrees)   upon  which  they  are  based.
Ideally, the  Manuals should be public documents,  and copies  should be
readily available to interested non-governmental organizations and members
of the public.

In   Ecuador,   Petroecuador  is   currently  preparing   a   comprehensive
Environmental Manual for  its operations,  which take place  largely in the
ecologically   sensitive  Amazon  region.     After   it   is   complete,
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Petroecuador's Environmental Manual might possibly  serve as a model for
other petroleum companies interested  in  preparing or revising their own
environmental manuals.   However,  each  company's Environmental Manual will
differ somewhat, depending on the host  (or parent)  country's environmental
laws and institutions,  the portfolio of activites undertaken by each oil
company, and  the  types  of ecosystems   (forest or  non-forest,  onshore or
offshore) in which petroleum exploration or development takes place.

The World Bank has  recently adopted  detailed policies  on Environmental
Assessment and Wildlands.   The  Environmental  Assessment Policy requires
that  environmentally   sensitive   development  projects  have  detailed
environmental studies done prior to Bank  financing,  and that all feasible
modifications be made in the project's design and operation to minimize
any  negative environmental effects.     The  Wildlands  Policy seeks  to
minimize  the elimination of wildlands  (relatively unmodified  natural
ecosystems)  in Bank-assisted projects, and  requires the conservation of
wildlands in certain types  of  projects.   These  policies  are presently
being implemented in a number of  developing countries (including tropical
forested  ones)  where   the  Bank  is   assisting  the  development  of  the
petroleum and natural gas sector.
                                597

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          MOBIL WASTE MANAGEMENT CERTIFICATION SYSTEM
Walter A.  Steingraber
Mobil Exploration  & Producing U.S. Inc.
Dallas, Texas   75265, USA

Fred E. Schultz, Stephen E. Steimle, P.E.,  Ph.D.
Steimle &  Associates, Inc.
Metairie,  Louisiana  70001, USA
INTRODUCTION

The real  challenge for disposal of waste  from the  petroleum
exploration and production industry is not the "why"  nor the
"how"  but the "where"  to safely dispose in consideration of the
industries'  responsibilities  to  our  environment and  future
generations as well as  present  and future stockholders.   These
responsibilities are  in fact  one and  the same and can be
summarized in the words of Mr.  William Reilly, EPA Administrator:

     "Act toward the  future  in  such a way'that  you will  have no
     reason to regret the past"  (i).

There  are ever  increasing difficulties in  establishing  and
maintaining  sound waste handling  and disposal systems.  A
constantly changing and growing  regulatory  matrix  coupled  with
uneven enforcement  from state to state make the role of the waste
disposer a difficult one.

The lucrative nature  of the disposal business attracts numerous
investors and operators,  which  range  from strictly  honest to
"snake oil  salesman".    Such a diversity  of operators together
with the  fact that regulatory agencies often have difficulty
attracting and maintaining highly qualified and experienced staff
create the  potential  for  the continued  existence  of  inadequate
facilities which will manifest future environmental problems.

This potential  for inadequate  facilities for  offsite disposal
creates a situation where  the industry is  responsible to examine
its offsite waste  disposal options  in light of environmental
adequacy.   The importance  of these  evaluations is accentuated in
light  of  environmental  responsibility  legislation and  its
consequences.

The cost  to  implement  a  system to examine  offsite disposal
facilities is small when compared to Superfund site remediation
costs.    The cost to cleanup  a  Superfund  site has risen
dramatically over the  past  few  years.   The government  has  set
aside  nearly $30 billion to cleanup the approximately 1200 sites
                             599

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on the  National  Priority List  (NPL) which  averages around  $25
million  per site.  Initially when  the Superfund  program  was
established it was estimated  that the cost to  cleanup a site
would average $9 million.   Over the  years,  the cost of site
remediation has risen and now ranges between $21 and  $30 million.
With Superfund or similar (state)  cleanups,  generators  are  being
charged  a  second time  to  dispose of  waste they believed  was
adequately disposed of  long ago.  The disposal costs the  second
time around can be many  times higher than the  original  disposal
cost.   Though many potentially  responsible  parties (PRPs)  are
liable for cleanup costs, the  companies  with the  greatest  assets
are the ones who actually foot  the bill.   These staggering  costs
can  often be  avoided  if time  is spent  reviewing  a  disposal
facility's operations prior to shipping any waste.

DISCUSSION

Mobil's  Waste Management  Certification  System is  devised to
assist  the exploration and  producing division personnel  in
deciding where to send  waste  for treatment and/or disposal.   The
system  is  designed  to be  used  whenever  a third party  is
contracted for  treatment and/or  disposal of  Mobil's  waste
streams.

The  system consists of three basic steps:   1. gathering the
information about the  facility,  2.  comparing that information to
certain decision criteria and  3.  preparing the  summary report on
the  suitability of the  facility-   Other  components of the system
include  scheduling  revisits  of  facilities  and providing
information to the field personnel  for  coordinating  transport of
waste streams to recommended waste treatment/disposal facilities.

Information Gathering

The  first step is to gather as much pertinent  information on  the
facility as possible.    The information on a facility is divided
into  three  areas:   the  institutional aspects,  the  operational/
physical aspects  and the environmental  aspects.   Each of  these
aspects contributes to  the overall evaluation of the  facility.

Institutional information pertains to the description of the
facility as it conforms to the Federal, state and/or  local  agency
rules and  regulations that govern it.   This type of information
is obtained from files  in the Federal, state and local regulatory
agency  offices.   The  main  sources of  institutional  information
are  the facility's permit application,  regulatory files  and
permits.  Interviews with the  regulatory personnel familiar with
the  facility  are  informative and  provide  the  agency's  viewpoint
of the  facility  and  its operations.   A financial report on  the
facility is obtained to help determine the financial  stability of
the  company.  It  is  desirable to collect  and  review this
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information to have  a preview of the facility prior to the onsite
inspection.  If the  institutional information is complete and the
facility  complies with  the regulations,  then a  facility
inspection is scheduled.  Serious deficiencies discovered at this
point  cause  a  facility to  be  eliminated  from  further
consideration.

During the  facility inspection,  the  information pertaining  to
operational/physical aspects is collected.  A good source of this
type of  information is to interview  the owner/operator of  the
facility.   During the  interview the  treatment/disposal/recycle
techniques are discussed to provide an understanding of how  waste
is handled and  processed while at  the facility.  The  evaluator
should find out how  materials  are received  (ie.  manifests,  bills
of lading, etc.),  how  materials are processed or disposed and  if
any  portion  of the waste stream leaves the facility  (ie.
discharge, recycle,  etc.).   A tour of the  facility  is  necessary
to note and observe  the size and location of tanks,  ponds, pumps,
dikes,  filters,  laboratory  facilities,  storage  areas,  etc.
Monitoring well information, spill  response, safety  measures and
other pertinent information can be  discussed during  the  facility
tour.  Photographs are  important and are  taken,  when allowed,  to
record conditions  at the time of the visit and  remain  available
for future reference.   A checklist  is  compiled prior to  visiting
the  facility  which covers the  items  listed above,  but  is
expandable to cover other items at  the facility  and special
circumstances.   The  checklist should not substitute for  alert and
informed professional observation,  work and judgment.

The environmental  aspects  of  the  facility are  the third type  of
information collected.   Environmental  aspects  include the surface
hydrology, geology,  soils,  meteorology and groundwater hydrology.
Sources  for  this  information  include  published and unpublished
reports on the geology, hydrology,  soils,  as  well as,  site data
and data given in  the permit application.

The soils, hydrology,   geology and  air emission  (if applicable)
information  is very important since  it defines  the  degree  of
environmental protection afforded by  the  facility.   Review  of
monitoring well data provides  insight to groundwater conditions
and  shows existing  or  potential  groundwater  problems.
Meteorological information  is  necessary  for  performing  mass
balances  on  incoming and outgoing waste  streams  and for
determining the effect  of  the  weather on  the  facility and its
operations.

Even though some of  the information may not be site  specific,  it
can provide base information for area  conditions.  Development  of
original  data may  be necessary to supplement areas where little
or no data exists.
                           601

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Decision Criteria

After collecting all the available information on the  facility,
the  Decision Criteria is  applied to  the  information.   The
designations of "Acceptable",  "Acceptable With Problems"  or
"Unacceptable"  are  assigned to  the  facility  based  on sound
supporting data.   The  criteria  which  are  used  to evaluate the
facility are as  follows:

     1.  Knowledge  of the environment  and  the factors  affecting
        the environment,
     2.  Consideration of how  the waste processing method  affects
        the environment, and
     3.  Knowledge of how the environmental factors  affect the
        waste processing method.

The  evaluator uses the available institutional, operational/
physical and environmental information  as it applies to  the above
criteria.    He  also uses  his  knowledge  about  the  facility,  its
operations and type of  waste processed to make a recommendation
on the facility.

"Acceptable" facilities have complied  with the institutional
information aspects  and operate in a technically, environmentally
and  financially  sound manner.  These facilities generally have  a
simple  treatment/disposal process  and pose  a  low  risk  for
environmental contamination.  The owners/operators maintain their
equipment,  regulate their process and  comply with  applicable
regulations.

Facilities that  are "Acceptable With Problems" have deficiencies
in one  or more  of the informational aspects.    The  facility is
recommended  for waste  treatment/disposal,  but the  facility  may
exhibit a  variety  of minor environmental, operational or
regulatory problems.  The  problems are  not  severe enough to
reject using the facility,  but on  the other hand,  the problems
cannot be ignored  or overlooked.   These  problems are  highlighted
to warn of potential  environmental or regulatory  concerns.

The  evaluators must rely  on their knowledge  of the general
environment, the type of  process,  the  waste being processed  and
the  potential for  environmental  contamination to  make their
recommendation.  The  available information  is used to  support the
recommendation decision.

An "Acceptable With Problems" facility should  be monitored on  a
frequent  basis  to ensure  that  the site  doesn't develop more
serious problems which  could later render  it unusable  for waste
treatment/disposal.
                            602

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Facilities that are  "Unacceptable"  have deficiencies  in one  or
more of the informational aspects,  but the deficiencies are of  a
serious nature.   This type  of  facility is  not recommended  for
waste  treatment/disposal  because conditions exist  to  indicate
that the facility is technically, environmentally or  financially
unsound.  Though a facility  may  have  a valid permit to  operate,
conditions may be  present with  the potential  for  environmental
contamination,  regulatory violations,   or  improper treatment  and
handling  of  a waste  stream.  These  conditions could  lead to
future  liability  and adverse  publicity for  generators  sending
waste to the  facility.

Summary Reports

After  all  the  available  information  has  been reviewed  and the
facility  has been inspected,  a summary report is written to
highlight the  important  aspects  of the facility.    The  reports
include basic  information such as the name, address  and  phone
number of the facility,  as  well as  short  descriptions of the
process, regulatory history,  transportation modes, waste accepted
and technical acceptability.  The technical acceptability section
allows for the listing of  the reasons  for recommending a facility
"Acceptable", "Acceptable  With Problems", or  "Unacceptable".

The summary  report should also  include  a  permits matrix.    The
matrix lists the  permits issued  by Federal,  state or  local
agencies  for the  various  aspects of  the  facility's operations.
The date  issued  and  expiration  date  for  each permit  should  be
noted along with any  special  requirements or limitations  imposed
upon the facility.

Re-evaluation Frequency

The facility should be re-evaluated  on a  regular basis.   The
frequency of re-inspections is  dependent on  the  amount and type
of waste brought for  treatment/disposal and  the  proximity of the
facility to the waste  generating  site.

Repeat  reviews of  a  facility are scheduled  to  ensure that the
facility  continues to operate  in  the  manner described in the
previous summary report.   The revisit  inspection should note any
physical  changes  or  operational  modifications,  as  well  as any
changes  in management or ownership.    Periodic reviews of the
facility's  regulatory  files may yield important information
concerning  operational  modifications, closures,  or physical
changes to the facility.   Other facilities  in the area which are
acceptable for waste  treatment/disposal but  not used  should  be
re-inspected  periodically  to  maintain  a  list of available  back up
facilities should  the  primary facility have  problems.   Alternate
facilities should be  available to  keep pricing  competitive for
waste  treatment/disposal,  but  should   also  have  the  ability  to
                            603

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properly handle the waste stream.

Each time a facility  is re-evaluated  a  new summary  report should
be generated  listing  the new information and updating the
regulatory history.   The old summary report  should be  destroyed
to avoid confusion with the updated report.   The  summary reports
should be handled  by  one person or a small group of  people (waste
coordinators)  to maintain control  over  the facility review
system.   The waste coordinators  communicate with  field  personnel
regarding facilities  that have  been reviewed  or  need to be
reviewed.

Summary List

Aside from  the  Summary  Report, a  Summary List  should be
assembled.  The Summary List contains a brief description of the
facility,  its address,  phone  number,  waste  types  and its
technical acceptability with  some abbreviated supporting
information.    Only the  summary  list  information  is provided to
the field personnel  since they need to know  the  facilities that
are approved to accept their waste stream.

System Implementation and Operation

The Mobil Waste Management Certification  System was  implemented
in the  fall of 1988  for all Mobil Exploration  and  Production
wastes generated in the U.S.   Prior to that time, the system had
been operational on a pilot basis in several divisions.

The number of non-hazardous waste facilities approved  for use and
being utilized  for  disposal far  outnumber the hazardous waste
facilities.   Exhibit  1  presents a schematic of  the major
evaluation categories and elements in the system.   Clearly it is
not always sufficient to evaluate  only the  facility in question,
but related  facilities  which may  further  handle  by-products of
the subject  facility (eg:  waste  taken  to wastewater facilities
such  as  injection   wells  and  treatment  operations,  recycle
facilities,  landfills, etc.) must also be  reviewed.  Each step in
the web of  disposal must  be  evaluated  to provide  a  complete
environmental picture upon  which  an effective recommendation can
be made.  Exhibits 2a and  2b illustrate the  types or categories
of non-hazardous waste  facilities evaluated under  the  Mobil Waste
Certification System  and provides information  on the number found
to be Acceptable, Acceptable With  Problems  or Unacceptable for
each  category  of  facility.   The  number  of  non-hazardous waste
facilities  evaluated,  as  taken  from  Exhibits  2a and 2b,  is
approximately 215, with  33 Acceptable  facilities,  95 Unacceptable
facilities and 87  facilities Acceptable With Problems.

Exhibit 3 illustrates the types or categories  of  hazardous waste
facilities as well as the number of sites  found to be  Acceptable,
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Acceptable With  Problems or  Unacceptable for  each category  of
facility.'  Out of the  24 hazardous waste facilities there was  1
Acceptable facility,  13 facilities Acceptable With Problems and 9
facilities that were Unacceptable.

Exhibit 4 shows that 15  percent of the non-hazardous  facilities
evaluated were determined to  be Acceptable,  40  percent were
Acceptable With Problems and 45 percent were Unacceptable.  With
respect to  the hazardous  facilities  evaluated,  4  percent were
Acceptable,  with 58 percent Acceptable With  Problems  and  38
percent Unacceptable.

SUMMARY AND CONCLUSIONS

The Mobil Waste Management Certification System  has in the short
period of time since its  implementation proved  to be a valuable
tool in helping to answer the question  of "where" to dispose of
the company's petroleum  exploration and  production  wastes.  The
system as currently operated has  not  been manpower intensive or
overly expensive.   The expense  of operating  this  type of  system
has already been saved many times over as a  result of avoiding
just one Superfund site cleanup involvement that we are aware of
at  this  time.   The  key to success  is  diligence and  the acute
awareness that you are dealing  with a dynamic  rather  than a
static system.

REFERENCES

1. W.  K.  Reilly, What We Can Do, EPA Journal, 2,  1990, 32-34.
                            605

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                            EXHIBIT  1

MOBIL WASTE  CERTIFICATION  SYSTEM EVALUATION SCHEMATIC
                       TRANSPORTER
                        FACILITY
                        PROCESS
                                     TRANSPORTER
FACILITY
PROCESS
                                            TAKEN
                                            orr
                                            9TE
         INJECTED

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                   EXHIBIT 2a

   NON-HAZARDOUS WASTE FACILITIES
             NUMBER PER  CATEGORY
  •• INCINERATOR

  OHO MECHANICAL
INJECT WELL LMJ LANDFILL   SMS LANDFARM

OIL SALVAGE HH PIT DISPOSAL^ TRANSPORTER
  NUMBER OF FACILITIES
40-
30-
       ACCEPTABLE
     ACCEPTABLE W/
      PROBLEMS
                                   UNACCEPTABLE
             WASTE FACILITY CATEGORIES

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                  EXHIBIT 2b

  NON-HAZARDOUS  WASTE  FACILITIES
            NUMBER PER CATEGORY
    RECYCLER      HH TANK CLEANING  Oi SALTWATER RELEASE

    TRANSFORM STORE •• WASTEWATER FACILITY
  NUMBER OF FACILITIES
4-


3-


2-


1 -


o-
      ACCEPTABLE
ACCEPTABLE W/
 PROBLEMS
                                   UNACCEPTABLE
            WASTE FACILITY CATEGORIES

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                   EXHIBIT 3

     HAZARDOUS WASTE FACILITIES
            NUMBER PER CATEGORY
    INJECTION WELL

    PIT DISPOSAL
      MECHANICAL PROCESS

      RECYCLER
  NUMBER OF FACILITIES
6-

6-

4 -

3-

2-

1 -

o-
      ACCEPTABLE
ACCEPTABLE W/
 PROBLEMS
                                  UNACCEPTABLE
            WASTE FACILITIES CATEGORIES

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                          EXHIBIT 4

              RATINGS OF WASTE FACILITIES
                    PERCENT PER CATEGORY
g
                    NON-HAZARDOUS
        HAZARDOUS
           % (PERCENT)
        70-
        60
               ACCEPTABLE
ACCEPTABLE W/
 PROBLEMS
                                         UNACCEPTABLE
                    WASTE FACILITY CATEGORIES

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MODELLING OF TOLUENE MIGRATION IN  GROUND WATER

WITH THE USE OF  A MULTIPHASE SIMULATION  PROGRAMME
G. Pusch, R. Weber
Institute of Petroleum Engineering,
Division of Reservoir Engineering,
Technical University of Clausthal
D-3392 Clausthal-Zellerfeld,
Federal Republic of Germany
Introduction

During  the investigation of contaminated sites,  problems of ground water pro-
tection  for which the application of transport  models is plausible are frequently
encountered. If, for example, contamination of  the ground water has been  as-
certained, the evolution of the pollutant distribution can be predicted by nu-
merical  analysis. Furthermore, if information on the suitability of a  site  for the
disposal of hazardous waste  is required, the consequences of the potential mi-
gration  of pollutants can  be  appraised, and the  associated ris.
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Description of the simulation  programme For multiphase Flow
The  simulation  programme employed for the  analysis of multiphase flow  has
its origin  in  the  field of oil and gas reservoir  simulation. It  is capable of mo-
delling two liquid phases  and  one gas  phase.  Furthermore, the gas is soluble
in one of the two liquid phases. The mass transport is described by the Darcy
equation.  Diffusion processes are not considered. The partial differential equa-
tions which apply to  the fluid  transport  (see  figure 1) are transformed to finite
difference  equations  and solved by fully implicit procedures. The particular so-
lutions must describe the variations  in  pressure and saturation  as  well as  the
mass transfer for every  time interval in the  blocks  of the  model zone (6).
               f Vrk                  1
liquid l:       v[|^L_(VPl- y , V D) J - q, -
                                                            9
                                                            —
         gas:
Figure 1:        Fundamental equations of the simulation programme

Nomenclature:
        k       absolute permeability, m2
        kr       relative permeability
        B       bulk volume correction factor, as a function of the
                pressure and temperature
        H       dynamic viscosity, Pas
        p       hydraulic pressure, Pa
        y       specific weight, Nm~3
        q       pumping rate, mV1
        <&       porosity
        Rs       gas solubility in liquid, m3 gas / m3 liquid
        D       depth, m
        t        time, s
                                   612

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The  finite  difference equations  are formulated into  an algebraic matrix system
and  solved iteratively. The specification of defined initial  and boundary  condi-
tions is thereby  vital. Thus, a  prevailing, defined initial  pressure  distribution
may  either obey hydrostatic laws or  require additional hydraulic  pressure gra-
dients upon  extraction  or  injection  of liquid through  wells and  other fluid
supply sources. For  multiphase flow, an  effective permeability is  entered as
measured  value,  instead of the  absolute permeability.  Since  a finite interfacial
tension prevails  between  the  phases,  effects of capillary  pressure  have  to be
taken into account in the flow  model.  These data must  also  be provided from
laboratory  measurements.
Modelling  of the  aquifer

The next step leading from  the  basic mathematical model to the flow model
for appraising a  stratum which contains contaminated  ground water  comprises
the transformation of the geological  information  of the  model region under
consideration to  a block grid model.

In accordance with the geological description, the aquifer has  an average thick-
ness of about 30 m  and consists of a  Quarternary stratum of  coarse  sand to
gravel with a thickness of about 10  m, a permeability of 50 to 80 Darcy (5 to 8
•  10"  m/s), and  an  effective pore  volume of 25  to 40  per cent,  followed by
a Tertiary  intercalation  of silts, clays, and  sands  with a thickness of 20 m. The
ground water barrier is  situated underneath, the  cover  is a  layer of  soil fill
about  2 m thick.  A three-dimensional model 180 x 280 x 9 m in size has been
selected  for modelling a section of  the  contaminated terrain  and the adjacent
region (see figure 2).
                                                     toluene-contamination source
                  water well
      water-bearing stratum
               impermeable layer
                                                               9 m
Figure 2:
Grid model of the aquifer
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The  model is  illustrated with  grid subdivision in figure 2. For the first appro-
ximate analysis of the pollutant propagation, only the Quaternary aquifer stra-
tum  was considered. The fundamental  data  for the  two-horizons model are
compiled in table 1. The aquifer is  subdivided into seven layers  by  the  grid.
Table 1:
Basic data for the two-horizons model
Dimensions:
Stratigraphic dip:
Aquifer:
Porosity:
Permeability:
parallel with stratification:
perpendicular to stratification:
Connate water saturation:
Immobile oil saturation
Barrier stratum:
Porosity:
Permeability:
parallel with stratification:
perpendicular to stratification:
Average migration velocity of
ground water:
Contamination with toluene'
Location:
Quantity:
Surface area:
280 x 180x9m
2 per cent

40 per cent

5 • 10'4 m/s
2.5 • 10'4 m/s
5 per cent Vp
0 per cent

5 per cent

4 • 10'9 m/s
2 • 10'9 m/s

0.1 m/d

cross-hatched area
10001
25m2
                                    614

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Important basic assumptions  in  this case are the connate water saturation of
about 5 per cent, which is plausible for a coarse-grained porous sediment,  and
an irreducible  toluene saturation  of 0 per cent. This implies  that all  of the
free  toluene is regarded  as  mobile,  and that "droplet  transport"  is thus also
possible. Binding of toluene  by  adsorption  in the soil is not excluded. Special
computer programmes are available  for modelling processes of  this kind; how-
ever, they have not been employed here because of the  prime objective  of  this
study.

Two forces  are decisive for the transport of  toluene  in  ground water:

=»      the hydraulic flow of the ground water,  and

=>      the buoyancy force of  toluene, whose density is lower than that of water.

The  physical properties  of water and toluene, as employed in the calculations,
are presented  in the following table.
Table 2:
Physical data for the migration analysis
Density of water:
Viscosity of water:
Density of toluene:
Viscosity of toluene:
1000 kg/m3
1 • 10'3 Pas
881 kg/m3
6 • 10'4 Pas
The relative permeabilities of water and toluene are plotted  in  figure 3. The
curve allows a  high mobility for ground water and for toluene,  since the critical
phase  saturation has been  chosen as 5 and  0 per cent, respectively.
                                   0.2   0,4   0.6   0.8

                                    water saturation
Figure 3:
Relative permeabilities: toluene - water
                                    615

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Migration of toluene in the aquifer
On the basis of the  present ground  water flow velocity of 0.1  m/d, a balance
prevailed  between  the  buoyancy force of the  less dense toluene and the hy-
draulic forces of ground water  flow  in the downward direction. Consequently,
the zone  of contaminated  ground water  propagated  in  a  nearly  steady-state
manner. As a result  of water  extraction from  a  well  located at a distance of
about 50  m  from the  zone of toluene invasion,  the  contaminant stream  was
drawn in the direction of the well. After about 20 days of pumping, the toluene
had already reached  the well;  subsequently, several litres of toluene were re-
covered from  the  well. The production of the  well was  terminated  then.
By means of several  observation wells in  the surrounding area  further distant
from the source of pollution, checks  were  conducted in order to determine the
direction of propagation of the toluene by the groundwater flow.  The propa-
gation  of  toluene  about 1.5 years after the pollution  happened, that is, at the
beginning of the hydraulic  remediation, is depicted in figure 4, as calculated
with the  simulation  programme.  A  conspicuous  feature is  the fact  that  the
highest concentration of toluene is still located in the vicinity of the pollution
source, although  a streak of toluene has drifted  toward  the well.
  1-45
      65
   Contour interval: 5000 ppm

                          9:
                                                     1 PI
1 IQm
  162
  nao
  1©7
  21-4-
  2.31m
                                      Tol iiene - c ontamir ated ar la
Figure 4:
Migration of toluene in the aquifer,
concentration of toluene in the bulk stream
                                  616

-------
Hydraulic decontamination of the aquifer  with  different  well  configurations

Hydraulic decontamination  measures can  be implemented for remediation  of
the aquifer because of the excellent permeability of the water-bearing stratum.
Vital prerequisites for this purpose  are the  determination of optimal locations
for the  decontamination wells, on the one hand, and  the choice  of the  neces-
sary water pumping rate for complete  removal of toluene from the ground wa-
ter, on the other  hand. Two possible remediation  concepts with different
arrangements of the decontamination wells are illustrated in figure  5.
      r
                     102
        concept I    170
                     213
                     230 •
                                            '////M
                        eo
                     102
        concept II
         tolua

      •  water veil

      X  puling w.11
                     106
     213
                                        _za
                                                87
                                                                 1O5 •
Figure 5:
Different concepts for decontamination
In accordance with concept  I, four additional wells  are  drilled  in the  regions
surrounding the centre of contamination along an isoline  of  concentration of
toluene,  and water is recovered from each  well at a pumping  rate of 7 l/s (or
about 605  m /d). In contrast, concept II provides for  only two  supplementary
wells at the northern edge of the contaminated area, as well as  the use of the
existing well situated at a distance of about 50 m from the centre of contami-
nation for  the remediation.  The total water pumping  rate remains  the same;
hence, the  southern, more remote well  is operated at a water  pumping  rate of
14 l/s (or about 1210 m /d)  with concept II, which involves only three decon-
tamination  wells.
                                    617

-------
 Decontamination concept  I:

 The effect  of the  decontamination  concept involving four  additional wells  is
 shown in figure 6.  A decided  decrease  in the toluene concentration is  already
 evident in the vicinity of the contamination centre after ten days. At the  same
 time, a subdivision of the existing pollution area  into two sections  can be ob-
 served during  extraction of the contaminated water  by pumping;  that  is, two
 centres of concentration are  formed. After a further  period of twenty  days,
 that is, thirty days  after the beginning of the pumping test, only small amounts
 of toluene are still present in  the  ground water (see  figure 7).  After continua-
 tion of pumping for  additional twenty days, no toluene remains in the original
 centre of contamination. A slight residual concentration  is still  present only in
 the vicinity of the  well  located at  a  distance of 50 m to the south,  where the
 toluene mishap was  observed.  However, this residue, too, is  completely elimi-
 nated  by  pumping  after a  further period of  twenty  days. These observations
 can  be summarized by stating  that no  toluene is  present in the ground water
 after extraction of the  contaminated water  by pumping  for  seventy  days;  that
 is, the completed decontamination operation is successful.
      so
    contour interval: 2000 ppm

  69	    ra    	87
96
  1 62
  T79
  196
  21 .3    -
  2.30 m
I O5 m
Figure 6:
Pollutant concentration ten days after the beginning of
the pumping test in accordance with concept I
                                    618

-------
 145
 162
 179
     6O
     contour interval: 100 ppm

 69	78	87
 213
 230
                                                                 1O5 m
Figure 7:
Pollutant concentration thirty days after the beginning
of the pumping test for decontamination concept I
Decontamination concept II:

For remediation of the contaminated aquifer on the basis of concept II (three
wells), the scheme presented in  figure 8 can  be applied. Ten days after  the
initiation  of  pumpings, toluene concentrations considerably higher  than  those
for decontamination by concept I are still present. At the same time, however,
the existing pollution zone  is obviously not  subdivided,  but rather purged uni-
formly. Twenty days later, that is, at a time when only a very low concentration
of toluene still  prevails  with concept I,  considerably higher concentrations  of
toluene are still present (compare figure 7  and 9) with concept II. Neverthe-
less, it is obvious here, too, that  the removal of toluene from the ground water
proceeds decidedly more uniformly. Thirty days later,  that  is,  after a  total  of
seventy days  after  the beginning of the  pumping,  no toluene was present  in
the ground water with  decontamination concept  I, whereas a small  residual
quantity is still present with concept II (see figure  10); this residue is  comple-
tely eliminated only after a  further period of thirty days.
                                  619

-------
       60
                    contour interval: 2500 ppm

                 88	78	SZ_
                                                es
   1 62
   T79
   196
   21 3
   230m
                                                           1Qg m
Figure 8:
                Pollutant concentration ten days after the beginning
                of the pumping test for decontamination concept II
       6O
   1 02
   T79
   186
   21 3
   23O m
                     contour^interval: 2500 ppm

                 68	78	87
                        \
                             H±
                             ±TT_V
                                   A\v
                                  AN
                                                86
                                                           1O5 ra
Figure 9:
               Pollutant concentration thirty days after the beginning
               of the pumping test for decontamination concept II
                                  620

-------
145 60
102
179
136
213
230 m
contour interval: 200 ppm
69 78 87 96 IO5 m
-
-
•


.
-
•
—

.
_
-
_
-
i
































•







S
& ^
ffi
0
^





^
^
\\
\. V
^ \
\







	 	 -^
\^^\
/A\
(
U )
,W
\_-
"V 	
^" IK—




•

"N
\ V.
XX X
\>
\ ^
) ''
' J
— -V










\


jrf*
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Figure 10:       Pollutant concentration seventy days after the beginning
                of the pumping test for decontamination concept II


The results for decontamination concept  II can be summarized  as  follows: After
100 days,  the  removal of the toluene  is  complete, and the decontamination of
the originally  polluted ground  water is thus successful. A comparison with de-
contamination concept I indicates  a time  difference of 30  days  for successful
remediation. However, only two supplementary  wells are  necessary  for concept
II, whereas concept  I requires four additional wells. Moreover, concept  II ob-
viously results  in a  considerably more uniform decrease  in the  pollutant con-
centration, whereas  with concept  I the existing  pollution  zone  is  subdivided
into several smaller  concentration  zones, which are then eliminated in succes-
sion.  In a  heterogeneous aquifer  the  disintegration of the  contaminated zone
could be the cause  for an ineffective  remediation of the pollutant.


Conclusions

A multiphase  flow model has been introduced with the aim of treating  hydro-
geological problems  of multiphase  migration. The programme, which has been
developed m the oil and gas industry,  is  capable of simulating  the simultaneous
flow of water,  a  hydrocarbon phase, and a gas phase.  Gravitational effects re-
sulting from the  difference in  density among the  phases involved in the flow,
as well as  capillary  effects, are thereby  taken into account.
With  the  use  of a practical  case as the analysis  of ground water pollution by
a toluene spill has been demonstrated by applying a  2-phase  flow  model.  The
propagation of the  toluene  was first  analyzed by taking the flow  velocity of
                                    621

-------
the ground water  and the buoyancy force of the  less dense toluene into con-
sideration. Subsequently, two  concepts for decontamination  were proposed,
compared, and appraised. One  decontamination concept provides for drilling a
pattern of four wells  for the purpose, whereas only two additional wells in line
are drilled, and one existing well is utilized with the other concept. It has been
shown that the remediation concept involving two supplementary wells  and the
existing well results in complete decontamination of the ground water originally
polluted with  toluene after one hundred days.  This approach requires a decon-
tamination period  which exceeds that for the other remediation concept  by thir-
ty days; on the basis  of the model calculations, however, the  extraction of the
polluted ground water by pumping evidently proceeds considerably more homo-
geneously than that  with  concept I.
On the basis  of the example presented, the principal applicability  of the pro-
posed multiphase simulation programme in the field of hydrogeology is evident.
Many problems of environmental pollution involve processes of multiphase flow
which  cannot  be  correctly treated with the use of  conventional single-phase
programmes for hydraulic transport. The consideration of viscous and capillary
driving forces, as  well as  gravitational  segregation of several phases is  feasible
only with the  application of a  multiphase simulation programme.


Acknowledgements
The authors wish  to thank Exploration Consultants Limited for the willingness
to  place the ECLIPSE simulation  programme at their disposal for  the model
calculations.
 References
 1.      W. Kinzelbach , Numerische Methoden zur Modellierung des Transports

        von Schadstoffen im Grundwasser, Schriftenreihe gwf Wasser-Abwasser

        Band 21, R. Oldenhourg Verlag. Miinchen, Wien, 1987.

 2.      J. Bear, A. Verruijt, Modeling Groundwater Flow and Pollution, D. Reidel

        Publishing Company, Dordrecht, Boston, Tokyo, 1987.

 3.      H.F. Wang, M.P. Anderson, Introduction to Groundwater Modeling -

        Finite Difference and Finite Elemente Methods, W.H. Freeman and

        Company. San Francisco, 1982.

 4.      J.C. Parker, Multiphase Flow and Transport in Porous Media, Reviews of

        Geophysics. 27, 3/August 1989, 311 - 328.

 5.      U. Kubitz, Mathematische Modellrechnungen zur Untersuchung von
        Altlaststandorten, Bergbau 3/90. 104 - 106.

 6.      N.N., ECLIPSE User Manual, Exploration Consultants Limited. Henley

        on Thames, UK, 1989.
                                    622

-------
MONITORING IN  THE VICINITY  OF OIL  AND GAS PLATFORMS:
ENVIRONMENTAL STATUS  IN THE NORWEGIAN  SECTOR IN  1987-
1989.
T. Bakke,
Norwegian Institute for Water Research
P.O. Box 69, Korsvoll
0808 Oslo 8, Norway.
J.S. Gray,
Biology Institute, University of Oslo
P.B. 1064, 0316, Blindern
Oslo 3, Norway.
L.-O. Reiersen,
Norwegian State Pollution Control Authority
P.B. 8100 Dep, 0032 Oslo 1,
Norway.
Introduction

It  is  a  widely  held  view  that  the  impact   of  oil
activities on the  benthic  fauna in the North Sea   extends
only  to a  1  km  radius  from  the  installation,   (1).
However, data reported to the Norwegian State Pollution
Control Authority (Statens forurensningstilsyn,  SFT) as
part  of the  obligatory  monitoring undertaken  by oil
companies within  the  Norwegian  sector  suggested  that
effects could  be  measured as far out  as  5 km from one
platform,  Stat fjord  C  (2) . Much controversy was generated
by presentation of this data with the counter-claim being
made that  the  effects observed were merely due to  natural
variations and  were not due to oil-related  activities.
Recently,  Gray  et al  (3)  have  shown conclusively  that
effects of oil-related  activities  on the benthic fauna
around the oldest  oilfield in the North Sea,  Ekofisk, in
1987 can be  found  out to a 3 km radius from the platform.
This is despite the  fact that at Ekofisk up to 1987 much
                         623

-------
less oil  had been  discharged than  at  Statfjord,  (see
Table 1).

SFT has the  responsibility of  safeguarding  the marine
environment  from  unnecessary pollution  and  can impose
regulations on oil companies if the environmental effects
warrant such  action.  It is clearly  necessary that any
impositions or restrictions of  activities  are based on
sound  analyses  of  the  data  reported.  The  reporting
procedures themseves have been analysed in detail and a
set of guidelines  developed by Norway was adopted at the
Paris Commission.  The guidelines have been used for three
years and  this paper reports on the experience  gained and
on further evidence that the effects of oil activities on
the benthic fauna  confirm the  suggestions put  forward by
Reiersen et al.  (2).
Methods

Monitoring of the conditions around oil and gas platforms
in the Norwegian sector of the North Sea is obligatory,
with annual  chemical monitoring  and biological  surveys
conducted every 3  years  (6 years  for gas platforms). The
data  from the  1987-1989 reports  (Table  1  shows  the
fields) allows us  to assess general characteristics over
several fields  rather  than  extracting data  for  single
areas. Gray  et al (3)  identified  a number  of  species
which were suggested  as being highly sensitive  to oil
and/or a tracer of oil-based  drilling muds,  the  barium
content  of  the  sediment,  (see   (2)  for  correlations
between total hydrocarnon content of sediment and barium
content). In  order to test the  hypothesis that abundances
of  these  species  were  responding  to   oil   related
activities abundances  were  plotted  against the  total
hydrocarbon  concentration, THC  and barium  content for
fields other than Ekofisk.  Zero  abundance values, i.e.
where  the species is  not present in  a  sample,  were
excluded from the analyses.

In  order  to assess  the statistical  significance  of
changes in abundance the oil  (THC) and barium values were
divided  into  arbitrary  logarithmic  classes  and  an
analysis   of   variance   was   performed  on  the   Iog10
transformed abundances.  In the following text significant
refers  to statistical  significance as  tested  by the
analysis of variance.
                         624

-------
Results

Table  1  shows  the  data  on  the  discharges  of  drill
cuttings and  oil  up  to  1989. For most  fields  there has
been a marked decrease in the amounts of oil and cuttings
discharged inn the period 1986-1989 despite the fact that
the  number  of holes drilled  has  increased  in  the same
period.
                        TABLE 1
           Discharges of oil contaminated  drill cuttings from
           selected platforms in the  Norwegian sector of the
           North Sea from 1983 to 1989 (tons).
Platform
EKOFISK
STATFJORD A
STATFJORD B
STATFJORD C
VALHALL
ULA
OSEBERG
TOTAL NORWAY
Year
83-85
86
87
88
89
83-85
86
87-89
83-85
86
87-88
89
83-85
86
87
88
89
83-85
86
87
88
89
-87
88
80
-85
86
87
88
89
83-85
86
87
88
89
No.
wells
7
0
2
9
8
16
1
0
20
5
0
1
12
11
7
2
3
18
7
3
5
5
0
3
6
1
6
4
1
4
59
30
26
37
43*
Discharges
Cuttings Oil
903
0
1.120
3-364
2.768
5-203
1.199
0
13.066
3-166
0
432
10.008
8.839
4.954
2.383
1.361
9-016
1.854
224
2.483
1.543
0
1-323
1.313
521
3-776
1.952
281
2.495
>4l.OOO
18.988
13-777
19.486
12.562
129
0
39
286
185
2.243
196
0
2.520
305
0
26
1.239
876
487
230
115
887
13*
13
157
82
0
120
96
61
416
204
19
223
8.268
2.030
1.256
1.705
953
         * For three wells all the cuttings were taken ashore.
                            625

-------
Table 2 shows the concentrations of THC measured in the
sediment at selected fields.. The data  show that the area
affected   is   largest  where  discharges   are   highest,
(Statfjord and  Valhall).  Table  2  shows  clearly  that
background levels for the  Norwegian sector of  the North
Sea are in the range 2-5 ppm and is even  independent of
the analysis  method used.  Values that are above 10 ppm
are judged, by the laboratories analysing the hydrocarbon
data, to be significantly contaminated. Background values
for barium content were more  difficult to obtain but were
between 100-200 ppm.
                       TABLE 2
 Concentrations  of total  hydrocarbons (THC)  at outer  sediment
 stations around  selected Norwegian oil fields in the  North Sea
 (mg pr. kg dry weight).
FIELD
Distance (
STATFJORD
A
B
C
5000
7000
10000
15000
5000
7000
12000
15000
5000
7000
10000
15000
VALHALL

2000
3000
4000
5000
6000
10000
15000
m)
1979 1980 1981 1982
15-3 16-3 12-3 10
- <1.0 4.6 3
1.2 2.0 0.8 2
1.0 3
1
<1.0 1
.2
.2
.0
• 3
.7
.4
.0
1983* 1984* 1985
15.1 27.0 37
- 13
3-0 4.0 5
.0
.0
.7
YEAR
1984 1985
30.1
21.2
17-5
9-4
5-5
3-5
* 1986
78.1
26.0
13.8
6.5
31.4
18.3
7-9
21.6
-
1986 1987
45-
22.
27-
13-
51-
23-
1.
* 1987*
67-5
8.0
8.8
4.7
8 58.
2 36-
41.
6 30.
6 8.
13-
28.
8 86.
7 8.
6 13-
1987
85.8
10.0
11.2
5-9
9
8
7
0
6
8
5
6
5
7
1988
18
15
7
7
19
9
14
10
17
17
3
2
.2
• 5
.5
.7
.5
.8
.2
• 5
.0
.0
.2
.8
1988

78.
30.
13-
8
3
3
5
1989
41.9
9-7
13.6
5-8
28.8
6.6
5-0
1989
65.0
14.0
7-0
5-0
5.9
  ULA	1984  1987 1988  1989
1000
2000
4000
6000
4.0
3-0
4.0
3.0
6.1
5-6
-
4.2
13-9
4.6
-
3.7
8-9
5-9
3-7
3.2
   Before 1984 2000m.   * mg pr. kg wet weight.
                           626

-------
Tables 1 and 2 also show that once discharge declines so
does  THC at  the  outermost  stations.  For  example  at
Statfjord A at 5000m values  decline  dramatically within
one year from 1987 and  from  1986  at  B.  For  Valhall  from
2000m and further distant THC values decline  from 1988.

The data for the  species were found to fall into distinct
patterns. Fig  1.  shows data  for  the bivalve   Abra  (cf
prismatica).
    40-
    30.
    20.
     10.
                                40.
                                30-
                                20-
                                 10.
              2    3

               log THC
2    3

 log Ba
Fig.  1.  Abundances of  Abra cf  prismatica at Valhall,
Gullfaks,  Oseberg and  Ula oilfields,  N.Sea.  a)  total
hydrocarbon content (THC)  of sediment,  ppm
b) barium content  of sediment, ppm.

Fig  1 (a)  shows  that  there is  a gradual decline   in
abundance  starting at a  Log10  THC  level  of 1.2  (15.84
ppm).  There  is a  statistically significant difference
between abundances at THC  concentrations  between 37  and
100  ppm  and  below 15  ppm.  No  Abra  were  found  at
concentrations  higher  than 400  ppm.    Abra  showed  a
similar gradual  decline in numbers with  barium  content
(fig 1 b) beginning at concentrations over 200 ppm,  but
only at concentrations above 700 ppm were the abundances
significantly different  from those  at background level.
An  almost  identical pattern occurs   for  the crustacean
Eudorellopsis  deformis  (Fig  2  )  with  a reduction  in
abundance beginning at 10 ppm THC (2 a), but due  to high
variance within classes the changes are not statistically
significant.  A dramatic  and  statistically  significant
increase in  abundance  occurs  at barium levels over  250
                          627

-------
ppm and a significant decrease again over 2000 ppm.

The  polychaete  Goniada   maculata  shows  a  slightly
different pattern  (fig 3  a)  with  first  a significant
increase in abundance from background THC levels and then
a significant decrease in abundance over 100 ppm  THC.  (L_
maculata shows  a  similar response  to  barium  as  to THC
(fig 3 b) with a significant increase  in abundance from
background levels  of  barium  (300  ppm) up to  1000 ppm
barium followed by a decrease in abundance.
   60,
   50.


   40.


   30.


   20-


   10.
            2    3

             log THC
50-
40-
1 30-
C
20.
10-
0-
i •
•
•
• • •
• •
• 4 • •
• •
•
•
• ~
* •
• •
-.".."
• •• •• *
012345
log Ba
Fig.  2.  Abundances  og  Goniada  maculata at  Valhall,
Gullfaks, Oseberg  and  Ula oilfields, N.  Sea.  a) total
hydrocarbon content of sediment, ppm.
b) barium content of sediment, ppm.

Nephthys lonqosetosa (not shown)  shows a closely  similar
pattern to G.maculata with maximum abundances at  10 ppm
THC.  A decline in abundance occurs at THC concentrations
above  10 ppm.  For barium N.  lonqosetosa  shows  maximal
abundances at 1000 ppm,  and  a steep decline in abundance
with  increasing  barium  concentrations.  The   maximal
abundance at 1000 ppm barium  is  significantly different
from abundances at higher and lower  barium content.

A  species  that has  often been  suggested shows  higher
abundance  with organic  enrichment  is the  polychaete
Chaetozone  setosa  (4  and  5).  Fig  3 shows  with this
species  there  is  a large increase in abundance  at THC
                         628

-------
concentrations above  10  ppm but there is no  decline in
abundance at higher concentrations as with Abra  and G^.
maculata. Abundances  over THC  concentrations  of 700 ppm
are significantly different from those below 10 ppm. The
response to  barium is similar to  that  to  THC with an
increase in abundance at concentrations over 500 ppm and
maximum abundances  at concentrations  over 6000 ppm with
no  decline  in  numbers.  The  increase  in abundance  is
however, gradual and variances within barium classes are
high  so that  there  is  no  statistically   significant
difference  between  abundances  at highest  and  lowest
barium content.
   1000.
   BOO.
   600-
 •o

 - 400-1
   200.
                               1000.
                               800.
                               600.
~ 400.
                               200.
     012345

              log THC
    012345

             log Ba
 Fig.  3  Abundances  of Chaetozone setosa  at  Valhall,
 Gullfaks,  Oseberg and Ula oilfields,  N.Sea.  a)  total
 hydrocarbon  content  (THC)  of  sediment,  ppm
 b)  barium  content of sediment,  ppm

 Another  commonly recommended   indicator  species  for
 organic enrichment is the polychaete Capitella capitata.
 Here  C.  capitata  showed  a large  increase  in abundance
 beginning   only   at   over  300  ppm   THC   and  rising
 continuously with maximal  abundances  occurring  at THC
 concentrations  of almost  10,000 ppm. Abundances  at the
 highest  THC  concentration are  significantly different
 from  at all other  concentrations.  So far  from being
 useful as  an indicator species  C.  capitata is merely an
 indicator  of grossly polluted conditions.
                           629

-------
The polychaete Aonides pauchibranchiata shows a decrease
in abundance from a THC of 10 ppm with total absence  over
100 ppm THC but  shows no  clear response to barium  with
neither an increase at concentrations over backgound nor
a decrease at  concentrations  of  up to 1000 ppm. Due  to
high variance within classes  (THC and barium) there are
no statistically significant differences between highest
and lowest abundance classes.
Discussion

The most obvious pattern to emerge  from figs 1-3 is that
for  three  species  Abra,  Eudorellopsis,  Nephtys  and
Aonides there is a maximal abundance at approximately 10
ppm. As  THC concentrations  increase  over  lOppm  these
species  show   declines  in  abundance   and  very  few
individuals are found at over 100 ppm. With Goniada and
Nephtys  there   is  an  increase  in  abundance   from
backrground THC  levels  to  10-100 ppm and  thereafter a
decline.

Chaetozone and Capitella show increases in abundance with
increased THC content,  but Chaetozone begins to increase
in abundance at  30 ppm whereas for Capitella the increase
begins above 100 ppm.

For barium a conservative lower limit for effects for all
species is  500  ppm.  Whether  or  not the response  to THC
and barium are  independent or simply represent responses
to  the  same gradient  remains  to  be  studied. Only  A.
pauchibranchiata  shows  a  response  to  THC  which  is
different to the response to barium.

The lowest threshold of  response  from field observations
is  10 ppm  THC  and for the studied fields  the distance
from  the   platforms  that  such  concentrations  are
equivalent  to  (Table  2)  is  as  far  as  7000-12000m
(Statfjord) and 6000-15000m  (Valhall). In the absence of
any measures to control dischargess of oil then one can
expect significant changes in the species composition of
benthic communities  out to   10000m and perhaps beyond.
Thus the suggestion in Reiersen et al  (2), that effects
of oil-related activities at  the  Stafjord C field out to
5000m could be related  to  such activities,  which was
hotly disputed at the time, appears to be confirmed from
the present data.
                           630

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New  regulations  for  discharge  of  oil  contaminated
cuttings were introduced  in 1988  by SFT. The operators
were asked to reduce  the  discharge of oil-contaminated
cuttings. The effect of this change in policy can be seen
both both in the reduction of  totals  tons discharged and
on  concentrations  measured  in  the sediment   at  the
outermost stations.  Despite the increased number  of wells
drilled  in  1989 discharges were  reduced compared with
1988, (Table 2)  .

From 1st January 1991 the discharge of oil contaminated
cuttings will be banned in the  Norwegian sector of the
North Sea.  Exceptions will be  allowed  for  safety and
geological reasons and the discharge  limit will  be 10 gm
kg ~x compared with today's limit  of 100 gm kg -1.  For
existing fields there will be a transitionary period up
to  1st  January  1993,  (60  gm kg ~x) .  It is  unlikely,
therefore, that the effects on the fauna at levels down
to 10 ppm found with the use of new analysis techniques
(3)  and  in this  paper,  will extend  out to  10000m  or
beyond.

At the Calgary Drilling Wastes Conference in 1988 a set
of guidelines drawn up by SFT for use in the Norwegian
sector were  presented.   In spring  1988  the guidelines
were  adopted  by  the  Paris  Commission  for  general
application.   Prior  to   the  guidelines being  adopted
within Norway the mandatory monitoring  programmes were
done by independent consultant companies and universities
which used methods most convenient to  themselves  and with
no  compatibility  between  methods.     In  Calgary  we
presented an evaluation of  sources  of variation in the
monitoring programmes  (2)  which  clearly showed that such
variations did not reflect differences between fields but
was largely^due to methodological differences.  Thus it
was  difficult to compare  trends  in  contamination over
time.

The   introduction   of  the   guidelines  has   led   to
standardisation  of  methods  for  sampling,  extraction,
storeage, analyses,  reporting  and  quality assurance such
that data are much more reliable and it is now possible
to make comparisons between surveys both around one field
and between different fields.

The  monitoring  data are  presented  in a report and  in
addition the raw data has  to be presented on a computer
diskette, which simplifies SFT's overall assessment and
                          631

-------
allows statistical analyses to be done rapidly-  e.g.  this
report.

The  methods   and   procedures   adopted  by  the  Paris
Commission Guidelines are applicable to many point source
monitoring  situations  such as  industrial  and sewage
discharges.    By  suitable  adjustment  of  the   sampling
stations the  Guidelines can serve in a  wider control
function.

The  Norwegian  experience  can  be summarised as  the
imposition of  tighter guidelines for monitoring has led
to more reliable data on environmental conditions around
oilfields.   The, now, high guality of the data obtained
by  the oil  companies  has allowed  new   techniques  of
biological  effects  assessment  to be  applied.   These
techniques show  effects at THC  levels down  to 10  ppm.
This in turn has led to  tightening  of the legislation on
discharge  from oil platforms in the  Norwegian sector.
With imposition of  the new  legislation rapid improvement
of environmental conditions has been observed at stations
distant from the platforms. Thus rather than a conflict
between environmental control  authorities and  the  oil
companies,  a mutually beneficial state has been reached
wher   the   oil   companies  conduct   state-of-the-art
monitoring  which   the   SFT  then  can   ensure   that
unacceptable environmental damage will not occur.
References.

1.   J.M.   Davies,   J.M.  Addy,   R.   Blackman,   J.R.
     Blanchard,   B.C.   Moore,   H.J.   Somerville,   A.
     Whitehead, T. Wilkinson.  Environmental  effects of
     oil based drilling mud cuttings. Mar. Pollut.Bull..
     15, 1984, 363-370.

2.   L-0.  Reiersen, J.S. Gray,  K.H.  Palmork,  R.  Lange.
     Monitoring   in   the  vicinity  of  oil   and  gas
     platforms; results from  the norwegian sector of the
     North Sea and recommended methods  for forthcoming
     surveillance. In  Drilling Wastes   (F.R.Engelhardt,
     J.P-   Ray,  A.H.   Gillam  Eds.)  Elsevier  Applied
     Science, 1989, 91-117.

3.   J.S.  Gray, K.R.  Clarke, R.M. Warwick &  G.  Hobbs.
     Detection of  initial effects of  pollution on marine
                         632

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     benthos:  an example  from the Ekofisk  and  Eldfisk
     oilfields,  North Sea.  Mar.  Ecol. Progr. Ser.  (In
     press).

4.    T.H.  Pearson, R. Rosenberg. Macrobenthic succession
     in relation to  organic enrichment and pollution of
     the marine  environment.  Oceanogr.  mar,  biol.  A.
     Rev.  16,  1978,  229-311.

5.    T.H.Pearson, J.S. Gray, P.J. Johannessen.  Objective
     selection  of  sensitive  species   indicative   of
     pollution-induced change  in benthic communities. 2.
     Data  analyses.  Mar.  Ecol. Progr.  Ser.  12,  1983,
     237-255.
                         633

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NATURE,  OCCURRENCE AND  REMEDIATION OF  GROUNDWATER  CONTAMINATION  AT  ALBERTA  SOUR
GAS PLANTS
P.E. Hardisty,  T.L. Dabrowski,  L.S. Lyness,
Piteau Engineering Ltd.,  Calgary, Canada

R. Scroggins
Environment Canada, Ottawa,  Canada

P. Weeks
Husky Oil Ltd., Calgary,  Canada

Abstract

A study of subsurface contaminant monitoring and remediation data from 55 Alberta
sour  gas  plants  was  undertaken through sponsorship  of  the Canadian Petroleum
Association and Environment Canada.   Data  for  the  study  consisted of monitoring
reports collected by Alberta Environment pursuant to the Alberta Clean Water Act.
Study  objectives  were  to determine the most  frequently occurring groundwater
contamination situations, classify them by  contaminant type, source,  and geologic
host,  and evaluate  the  level  of  remediation  technology  being  applied  in the
province.

Some form of impact on groundwater quality  was  detected at  all but one of the gas
plants reviewed.  In  the majority of  cases contamination was  locally restricted
and did not appear to have moved off-site, however data did not allow an evaluation
of the seriousness of contamination situations.  Process water ponds were a source
of  contamination  at over two thirds of the plants.   Other  important sources of
contamination were process areas, on-site landfills,  and  sulphur block. The most
common contaminants were chlorides, and dissolved organics.  Free phase condensate
was  present at  several  facilities.    The majority  of  contaminated saturated
horizons  were  of  moderate  hydraulic  conductivity  (10"5  to lO"8 m/s), typically
sandy  till deposits common in  Alberta. Groundwater contamination situations in
many cases relate  directly to plant waste management practices, past and present.

Currently, Alberta Environment  data indicate that groundwater remediation systems
are  operating  or  are  being installed at  three plants.  All  are pump and treat
schemes, and deep well injection is  the  favoured method for disposal  of recovered
contaminated groundwater.

Introduction

Much  of  the natural gas  produced in the province  of  Alberta  is  associated with
varying  concentrations of hydrogen sulphide gas (H2S).  Sour gas plants remove
hydrogen  sulphide from  the  natural  gas stream through  a  variety of  processes,
producing  elemental  sulphur,  sales  gas,   and hydrocarbon  liquids.  There are
                                 635

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presently more than one hundred and  fifty  sour  gas plants operating  in Alberta,
ranging in capacity from as little as 11,000 nr/day to more than 17,000,000 m /day
of raw gas (Oilweek, 1987).  The oldest facilities have been in operation since the
early 1950's,  and several new complexes  are now in the  design stage.  This fact is
reflected in the wide range of process types and  plant designs present in Alberta.

Due to the nature of the processes involved in sour gas processing and the wastes
and by-products  produced,  sour  gas  plants  pose a  potential  threat to  local
groundwater quality.  Substances which may  impact groundwater quality at sour gas
plants include free phase and dissolved hydrocarbon products (such as condensate),
process water  and chemicals (such as amines,  glycols,  and degradation products),
produced waters (brines, saline and brackish water),  solid wastes and sludges,
seepage waters,  surface runoff  (from sulphur blocks, process and loading  areas),
and active or  abandoned landfills on site.

Recognizing the need to protect groundwater from deleterious effects resulting
from plant activities, the Canadian Petroleum Association,  in conjunction with
Environment  Canada,  sponsored  a  study  into  subsurface  contamination  and
remediation at Alberta sour gas  plants.  The main objectives of the study, on which
this paper is  based,  were the compilation of knowledge of sour gas plant  related
subsurface contamination situations, the  determination of  the  most  frequently
occurring contaminant situations present at these  facilities, and a review of the
groundwater remediation projects currently  underway in Alberta. Subsequent phases
of this work are to include design and implementation  of one or more remediation
technology demonstration projects at Alberta sour gas  plants.

Available Data

The study was based  on  data provided by Alberta  Environment,  and consisted of
documents submitted to the Standards and Approvals  Division by plant operators
pursuant to the Alberta Clean Water Act.  In all, information was obtained for 54
Class B sulphur-recovering sour gas plants.

The quality and completeness  of information  contained in the reports  were quite
variable.  In  some  cases basic  hydrogeological  data  such as  groundwater flow
directions, geological  logs and piezometer  locations, were not available.   Of the
54  plants considered,  sufficient  data for  adequate appraisal  of   subsurface
contamination situations  were available  for  32. Information  from  13  of the
remaining plants allowed partial  contamination assessment only.

The variability in  data reporting reflects  to a large extent  the  lack  of detailed
groundwater monitoring  and data reporting  guidelines  for  sour  gas  plants in
Alberta.  Alberta Environment is presently  working on a new set of guidelines for
groundwater monitoring at  industrial  and  waste disposal  facilities  in the
province, although  at this  time it is uncertain when these will  be available.

Methodology

Assessment of Contamination

The available  data  for each gas  plant were reviewed and where possible groundwater
                                636

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contamination situations identified.  No  assessment  of  the seriousness of the
various contamination situations was undertaken,  as  in  the majority of cases,
insufficient data  were available  for  this  task.   "Seriousness"  of  a given
contamination situation, or in other words the perceived need for abatement or
remediation, will  depend on a number of factors including:

            plant location with respect to other groundwater users, water courses,
            population centres, and areas  of especial environmental concern;
            nature, types  and  concentrations of contaminants;
            rates of contaminant transport;
            analysis of the fate of contaminants,  risk assessment;
            regulatory guidelines and considerations.

 In the majority of cases,  these types of data  were not available in the  reports
 provided by Alberta Environment for this study.  Current guidelines do not  specify
 provision of evaluations of the fate of contaminants by operators.

 Classification of  Findings

 Wherever  sufficient data were  available,  the  source, type  and geologic  host of
 contamination were determined  for each contamination situation.  From these three
 pieces of information Contamination Situation Classifications,  or CSC  s, were
 assigned, according to the categories shown in Table 1.   For the purposes of this
 study, a contamination situation  is defined  as:  "an occurrence of  subsurface
 contamination  at  a given sour gas plant, distinct from other occurrences at the
 same plant  in that it has a different source,  or the contamination is found  in  a
 different hydrogeological unit)".
TABLE 1
CONTAMINANT SITUATION CLASSIFICATION SYSTEM
SOURCE
1 . Process Area
' 2. Sulphur Block
3. Surface Runoff
4. Process/Produced
Water Ponds
5. Product Loading
Facility
6. Landfill
7. Injection well
8. Other
9. Unknown


TYPE
A. Free Hydrocarbon
B. Dissolved Organic
C. Main Ions
D. Sulphur Products
E. Metals
F. Other
(e.g. TKN.
priority pollu-
tants, etc.)




ZONE
I. Unsaturated Zone
soils, surficial
material, bedrock

Saturated Zone
II. High Hydr. Cond
K>10E-5m/s

III. Moderate K
10E-5>K>10E-8m/

IV. Low K
K<10E-8m/s
                                    637

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It is possible  for  several  CSC's to  exist  at a given plant.   For example,  a
facility may have a small sulphate plume in the uppermost groundwater bearing zone
(a sandy clay till  layer of low hydraulic conductivity) extending from the_sulphur
block area, and a larger plume consisting  of high concentrations of chlorides  and
dissolved organics  (high TOC  and  sulfolane  identified  in trace organics  scan)
originating from the  evaporation  pond, in another part  of  the same uppermost
aquifer,  but  also  found  in  a  deeper bedrock  aquifer of  moderate hydraulic
conductivity.

Consulting Table 1,  three CSC's could be developed for this scenario:

2 D IV:      sulphur products from sulphur block in low K zone;
4 BC IV:    ions and dissolved organics from evaporation pond in a low K zone;
4 BC  III:   ions-and dissolved organics  from  evaporation  pond in a moderate K
            zone.

Once so classified,  contamination situations at various  gas plants were compared
and grouped with the assistance of a computerized database system developed for
the study. In this way, common trends in subsurface contamination at Alberta sour
gas plants were  identified.

There exists in the  data a  slight correlation between  the  completeness  of the
monitoring data available for a given facility and the  number of contamination
situations identified there. Small monitoring networks  which did not cover all
areas  of possible  contamination  may  have  failed to  detect  all  groundwater
contamination present.  In light of this, the data presented  as  a result of this
review should not be taken solely as an indication  of the relative care with which
plants have controlled and disposed of plant wastes and  by-products, but also of
the  relative  degree  to  which they  have attempted  to assess  the  subsurface
contamination present at their sites.

 Groundwater Contamination

Of the  45 plants  for which  information  allowed  assessment  of  the presence  of
groundwater contamination, only one showed no  signs of impact  of  plant activities
on groundwater quality.   Table 2 shows  the number of plants at which one or more
CSC's were determined.  Two  or more contamination  situations were identified at
36 of the 45 plants.

Sources of Contamination

There  were  sufficient  data available at  42 plants to  determine  sources  of
groundwater contamination.   Table 3 shows the number of  plants  with at least one
contamination situation originating  from each of  the  source  categories. Thirty-
three  of the  42  plants  (78.5%)  had  at least  one  contamination  situation
originating from the  process  water/evaporation  pond.   Other common sources of
groundwater contamination were process areas  and  on-site  landfills. The sulphur
block area was  also identified  as a  frequent  source of  contamination.   Other
sources of contamination which were  identified included general surface runoff,
injection wells on-site, and product loading areas.
                                  638

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TABLE 2
NUMBER OF CONTAMINATION SITUATIONS
DETERMINED AT GAS PLANTS
(Total of 45 Surveyed)








Number
of CSC's
per Plant
4 or more
3
2
1
none
Number of
Plants

10
12
14
8
1
Cumulative
Number of
Plants
10
22
36
44
45








TABLE 3
SOURCES OF GROUNDWATER CONTAMINATION
Number of Plants with
at Least one Contamination Situation
Originating from the Given Source
(Total of 42 Surveyed)
Source

Ponds
Process Area
Landfill
Sulphur Block
Number of
Plants
33
23
20
16
Percentage
of Plants
78.6
54.8
47.6
38.1
Types of Contamination

There were sufficient data  available at 44  plants  to determine the  types  of
contaminants  in groundwater.  Main  ions and dissolved organics  were  the most
commonly identified  groundwater contaminants.  Impact on groundwater quality by
sulphur products,  notably sulphate and in some cases acid seepage waters, were
identified at  17 of the 45 plants.
                                  639

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Free phase condensate contamination was identified at five plants.  Although this
number represents only  about one-tenth of  the  plants surveyed,  the Relative
concern attached to  this  type of contamination makes it of particular interest.
Free phase .hydrocarbon contamination is difficult and expensive to remediate^and
very low levels of hydrocarbon render water  unfit for human or animal consumption.
Table 4 shows the number of plants with at least  one  contamination situation
involving each of the six major contaminant groups.

Contaminants  in  groundwater often occurred in  combinations.   For  instance  a
particular plume emanating from an evaporation  pond  may  have contained main ions
such  as  chloride and  sulphate,   dissolved  organics,  and  metals.   All  such
combinations were recorded during the data review phase.  Table 5 shows  a breakdown
of the occurrence of the more common combinations.  Among gas plants in the study
set,  half  had at least  one situation where  groundwater was contaminated by
dissolved organics and main  ions.
TABLE 4
TYPES OF GROUNDWATER CONTAMINANTS
Number of Plants where the
Indicated Contaminant type
was Identified at Least Once
(Total of 44 Surveyed)
Type

Main lone
Dissolved Organice
Sulphur Products
Free Hydrocarbon
Melale
Number of
Plants
42
41
17
5
3
Percentage
of Plants
93.3
91.9
37.8
11.1
6.7
TABLE 5
CONTAMINANT COMBINATIONS
Number of Plants where the
Indicated Combinations were
Identified at Least Once
Combination
Main Ions + Diss. Organics
Main Ions + Diss. Org. + Other
Sulphur Products Only
Main Ions Only
Number of
Plants
22
19
15
13
                                  640

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It must be noted that findings are affected by the analytical schedules which the
various operators chose to run on their groundwater samples.  If more comprehensive
analysis  of groundwater quality had been done,  additional contaminant types may
have been identified.

Zone of Contamination

Data with which the location of groundwater contamination could be determined were
scarcest in the reports provided by Alberta Environment for this study.  All of
the 13 plants for which only partial CSC's could be generated lacked sufficient
data to classify the zone of contamination.  In most instances, borehole logs or
piezometer construction details were not available, making it very difficult to
determine which  groundwater-bearing zone was  being sampled.   As  a result,  the
nature and hydraulic properties of the geologic  host of groundwater contamination
could be determined at only 32 of the 54 plants in the study group.

Zones  were classified  according to their  average hydraulic  conductivity,  to
provide  some  indication of  the  ability  of contamination  to  migrate  away from
 source.   Unsaturated   zone  (soil)  contamination  was  provided   a  separate
 classification (Type I). Table 6  shows the number of plants at which contamination
 occurs  in each of  the  three saturated  zone classifications.  The majority of
 groundwater contamination  situations at Alberta sour gas  plants seem to occur in
 zones of moderate hydraulic conductivity (10E-5 < K < 10E-8 m/s), represented by
 such materials  as  inter-till clayey sand and  silt layers and fractured bedrock
 common in Alberta.
                                 TABLE 6
                         ZONES OF CONTAMINATION
                         Number of Plants with at Least
                         One Contamination Situation
                         Occurring in the Indicated Zone
                            (Total of 32 Surveyed)
                       Zone
  Hydraulic
 Conductivity
 Range (m/s)
Number of
  Plants
                        IV
   >10E-05

10E-05-10E-08

   <10E-08
    7
   20
    6
                                  641

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Although directly related to the surficial geology of Alberta, this breakdown does
serve to confirm that most groundwater bearing zones which are impacted by sour gas
plant operations  are  not  extremely hydraulically conductive. Twenty-six  of 32
plants had contamination in groundwater bearing zones  whose hydraul ic conductivity
was less than 10E-5 m/s.   This helps  to put the  situation at Alberta  sour gas
plants  into  perspective.    In  the  majority of  cases,  the estimated  advective
transport  rates   of  groundwater  contamination  were  not  very  high,   however
consideration must  also  be given  to the  influences of fracture  permeability,
contaminant-matrix interactions and the accuracy of  hydraulic  conductivity data
provided in  reports.   Detailed analysis of contaminant transport  rates at  the
various gas plants was beyond the scope of this study.

Discussion

The sources and types of groundwater contamination identified at Alberta sour gas
plants  in many cases relate directly to the waste management practices followed
at the  plants.   Process water/retention ponds at  plant sites may  receive  water
which  has  been used  in plant  processes, surface  runoff from process areas  and
sulphur storage  blocks,  produced  brines,  and miscellaneous waste-water.  This
water  may  contain elevated concentrations of  dissolved  salts,  sulphate from
sulphur block runoff, organic process chemicals  and  dissolved hydrocarbons.

Many  of these  impoundments, particularly  at older plants, were excavated into
surficial material and were either left unlined  or were provided with compacted
natural clay (till) liners. The  results of this survey indicate that such ponds  are
the single most  common source  of deleterious impacts on groundwater quality at
sour  gas plants.   Improvements in  construction  and lining of new  and existing
wastewater  retention  ponds are being  implemented throughout the  industry,  and
should  help to reduce future problems.

On-site landfills were also identified as  a  common source of contaminants in
groundwater.  At many older gas plants,  landfills  have been used to dispose of a
variety of  wastes,  including   sulfinol  filters, scrap,  construction debris,
sulphur,  waste  oil   and   condensate,   amines and  catalyst.    Proper  siting,
construction,  capping and abandonment of  on-site landfills  will  also help to
reduce  impacts on groundwater.

The plants reviewed all engage in recovery of elemental sulphur, which  is  often
stored  on-site  in  large  blocks  to await  shipment.    Impacts  on  groundwater
attributed  to  sulphur include  elevated sulphate  concentrations and acid  water
seepage.  Although the data reviewed identified  the  sulphur block as a source of
groundwater  contamination  at only  16 of 42 plants, it is likely that the actual
number  is much higher.  At many of  the plants reviewed, no monitoring points  had
been establ ished'down-gradient  of sulphur storage areas. Whenever such monitoring
wells  were  installed,  impacts on  groundwater  quality were  detected.    It is
recommended that groundwater monitoring down-gradient of sulphur storage areas be
stipulated as a requirement in  future Alberta Environment guidelines for sour gas
plants.
                                642

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A correlation was found in the data between the number of contamination situations
occurring at a given plant, and the age of the plant.  This is attributed in part
to the longer periods  available  for  contaminant introduction and migration at
older plants, and  is also seen as a function of  improvements  in waste management
practices at newer plants.

Groundwater Remediation

Data Available

Information was  obtained describing subsurface remediation programs at  five sour
gas plants in Alberta.  Of these, two were primarily soil  remediation operations
(plant decommissionings), and three were groundwater  remediation schemes  currently
installed  at operating facilities.    To  date,  no  other  data from remediation
programs at sour gas plants has been submitted to Alberta Environment.

Case History

A groundwater remediation program at Plant P-192 was initiated by plant  personnel
in 1986, in response  to discovery of  a free-phase condensate  plume downgradient
of the plant site.  During this year  four  114 mm OD diameter wells were  installed
to recover condensate and  contaminated groundwater  originating from the process
area and evaporation ponds.  These attempts at using single conventional pumping
wells to extract LNAPL met with very limited success.

Subsequently, a more  detailed hydrogeological  study of the  plant  site  and
surroundings was completed.  This study refined understanding of groundwater flow
patterns  at the  site  and  the  distribution  and  properties  of  the various
hydrogeologic units at the  site, and  accurately delineated  the  extent of the
plume.  The condensate plume was found to  extend about 1.5 km  downgradient of the
plant, attaining apparent  thicknesses of  up to 1.5 m (Figure  1).

The  new information  indicated the  need  for an  improved contaminant   recovery
system.  At that time,  the  source of condensate was identified  as a  leaking buried
condensate line in the plant process area.  The  leak was  repaired,  but may have
been active for  several years.  Subsequently, all buried condensate lines in the
plant area were  replaced by overhead  lines.

In 1989, five 130 mm test  wells were placed downgradient  of  the plant,  near the
down-gradient edge of the  condensate plume.  These  wells  were tested to provide
information on the hydrogeologic properties of the contaminated aquifer, which
consists of interbedded fractured shale, siltstone and sandstone bedrock overlain
by  and in hydraulic  connection  with  glacio-fluvial  sands   and  gravels.   The
recovery wells have been fitted with  dual  pump systems designed expressly for the
recovery of light  non-aqueous phase liquids (LNAPL)  from the groundwater surface.
An integrated groundwater recovery,  treatment and disposal program is  now being
designed and tested for implementation in  1991.An area of muskeg approximately 750
m down-gradient  of the plant site was also found to have condensate contamination.
An interception trench is  planned for 1990/91 to contain the  plume in this area.
                                643

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The site characterization and remediation programs conducted at Plant  P 192 were
found to be some of the most thorough and advanced of all plants involved in tne
study.
       RECOVERY WELLS —i

       MUSKEG AREA
                    gt SOURCE OF
                    -V CONDENSATE
                                                       PLANT
                                                       PROCESS
                                                       AREA
                      RETENTION!/
                      POND
  PROPOSED
  INTERCEPTION
  TRENCH
OLD
SULPHUR
BLOCK
        APPROXIMATE EXTENT OF
        CONDENSATE PLUME
             _   APPROXIMATE SCALE
            500m           	
         PLANT  P-192
         SITE PLAN
                                FIGURE 1
 Discussion

 Subsurface remediation efforts at Alberta  sour gas plants to date have  included
 a variety of techniques. Where geologic conditions were suitable, large  diameter
 passive collection  systems have been used to recover free-phase  hydrocarbon.
 Attempts to recover  free phase condensate in more permeable aquifers using single
 well  pumping schemes  have,  not  unexpectedly, been  relatively  unsuccessful.
 Application of dual-pump scavenger-type systems to recover free phase condensate
 and groundwater separately is  being considered at several facilities. Traditional
 pump  and  treat  methods are being applied  for  the recovery of groundwater with
 dissolved contaminants, and the control of plume migration.  Deep well injection
 is the  favoured method for disposing  of contaminated groundwater.

 The number  of plants  at which remediation operations  are known to be presently
 underway  is  relatively small.  In many cases, remedial action has been deemed
                                  644

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unnecessary due to geologic conditions and relative isolation of plants,  far from
any nearby  groundwater  users,  water  courses  or population centres.   In some
instances, remediation has been deemed impractical due to 1 imitations of available
technology. However,  rapid advances  in the understanding of processes governing
contaminant migration in heterogeneous geologic media, and new developments in
remedial  technologies should improve our ability to remediate difficult sites.
One consideration  to date  has  undoubtedly  been  the  relatively  high  cost  of
subsurface remediation  and the fact  that  at present no  regulations  or guidelines
are available for these operations in Alberta.

The need  for  clean-up  must also be determined.  Risk  analysis and contaminant
transport  modelling  techniques provide  ways of  assessing the  likelihood  of
contamination impacting  the public  or the  environment.  Results  of  the  risk
analysis can then be  provided to regulators to ensure a case-by-case assessment
of the need for remediation  at sour gas plants.  Gas processing  facilities in the
province are found  in such diverse locations, and represent such a  wide  range of
hydrogeological  and climatic conditions, that application of a single set of rigid
criteria to determine the need  for clean-up is not recommended.  A case-by-case
consideration of  facilities would help  to ensure the economical application of the
limited resources.   Operators could  then  direct  available  funds toward  the most
serious problems.

Once  contaminated,   aquifers  are  very  difficult to  remediate,   and  clean-up
operations are expensive.  Clearly, the best  answer to groundwater contamination
problems  is to prevent  the movement  of contaminants  into the groundwater.  Good
waste management practices are the cheapest and surest  aquifer  protection.

Conclusions

The most common  sources of groundwater contamination at Alberta sour gas plants
were process water  ponds and on-site  landfills.  Dissolved organics and main ions
were  the  most common contaminants,  although  free  phase  condensate  LNAPL  was
present at several plants,  and  is  seen  as being of particular  concern.   Most
contamination  occurs  in   geologic   horizons   of   relatively  low  hydraulic
conductivity. In many instances, negative  impacts on  groundwater quality at sour
gas  plants can  be Jinked  to the waste  management  practices followed at  the
facility.

The number of Alberta sour gas plants at which remediation  programs  are  underway
is  relatively small.   It  is recommended  that industry and government  consider
jointly developing  a set of guidelines  for  the design  and  implementation  of
remediation programs.

Disclaimer

The opinions  expressed  in this  paper do  not  necessarily  reflect those of the
project sponsors, the Canadian Petroleum  Association and Environment Canada.

References

Oilweek,  1987.  Gas Processing Plant   Capacities. Jan  26,  1987 Issue.
                                645

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A   NEW   PIPELINE  LEAK-LOCATING   TECHNIQUE   UTILIZING   A  NOVEL
ODOURIZED  TEST-FLUID  (PATENT  PENDING)   AND  TRAINED  DOMESTIC  DOGS.
L.R. Quaife
Senior Environmental Scientist
Esso Resources Canada Limited
Calgary,  Alberta,  Canada
K.J. Moynihan
Environmental Scientist
Esso Resources Canada Limited
Calgary, Alberta,  Canada


INTRODUCTION
Pipeline  leaks  continue to plague industries which construct,  operate  or
move  products  through such  facilities.  The  problem is compounded by  the
fact  that many existing pipelines are  nearing  the end of their  intended
service  and  are therefore more  susceptible  to  failure. Accordingly,  the
incidence of pipeline  leaks  has been  increasing.  For example,  over  the
last  eleven  years,  the incidence of  leaks  in Alberta alone  has  steadily
risen from  421 in  1978  to 913  in  1988   (1).  The  economic penalties
associated  with  such leaks  can  be  particularly  onerous,  involving
substantial  product  loss,  line down  time, fines  resulting  from regulatory
non-compliance, and  remediation  of environmental  impacts.  Notwithstanding
the  direct economic penalties,  there  is growing public expectation  for
corporations to become more proactive in  minimizing any environmental
impacts resulting from their operations.

A  review  of the literature revealed  that  more than  thirty different
pipeline  leak-detection systems  are  presently in use  (2) but  despite  the
plethora  of  available  detection methods,  many systems  have  distinct
handicaps which limit  their usefulness. Most techniques  are  limited  by
being prohibitively expensive, by their requirement for incorporation into
a  pipeline at  the  time of  construction, or by  having  application to  a
relatively small range of  pipeline diameters.  Because of  the  lack  of
dependability of some of these methods,  many pipeliners continue to  locate
leaks by  cutting failed lines in half and hydrostatically pressure-testing
both  sections. Sections  which   subsequently  fail the  pressure  test  are
halved  again,  and after numerous successive cuts and  pressure  tests,  the
leak  is  eventually located,  often  after   substantial costs  have been
incurred  due to labor,  equipment-standby and  lost  production.

Another  pipeline leak-detection technique  in  common  use  involves  the
injection of odourized air  or hydrostatic  test-fluid into leaking  lines
and  attempting to detect the odourant  at the soil surface above a  leak.
Traditionally, one of several thiols  (mercaptans)  is used as  the odourant.
Although  this method has enjoyed  some success  (3,4), it has a number of
                                   647

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technical shortcomings. For example, when  a  thiol  is  used in an air-test,
safety considerations usually limit  pressure testing to approximately 700
kPa.  Air-testing  pipelines  at  higher  pressure  risks  the  safety  of
personnel,  as  well  as  substantial  line  damage which  could  result from
localized line rupture or even catastrophic failure. These safety concerns
clearly  preclude  the use  of thiol-based  air-tests on  most  pipelines
because the  majority of lines require  testing at much  higher pressures.
Concerns also exist where thiols  are used in the liquid phase. When thiols
are introduced into  hydrostatic  test-fluid,  they align  strongly with the
test-fluid water and  consequently  disperse underground  within the aqueous
phase.  Accordingly,  precise  location  of  pipeline  leaks  is  severely
compromised when  using either  of  these techniques.

Because of  the  limitations of available  leak-detection technology,  Esso
Resources Canada Limited  (ERCL) embarked on  a  research  program to develop
an effective, more  precise  odourant-based leak-detection system.  A major
focus of the research was to  develop a  test-fluid  which  could be injected
into  leaking pipelines  and which,  after leaking into  the soil,  would
release an  odourant  which  would  migrate directly to the  soil  surface for
detection. A critical technical challenge  involved with  the  development  of
this  fluid  was  to maintain minimum solubility of  the  odourant  in  other
test-fluid constituents, while at  the same time ensure the  odourant  would
remain in phase during the procedure. This consideration  was particularly
important because, if the  odourant came out  of phase and rose  to  the top
of a  pipeline, then  any test-fluid  flowing from a  leak on the  bottom of a
line  would  contain  no  odourant  and therefore could not   be  accurately
located.

STUDY  OBJECTIVES
The objectives of the program  were  threefold:
a) To identify an odourant  for incorporation  into the leak-detection test-
fluid having the  following  characteristics:
          -  strong,  identifiable odour
          -  sufficiently high  vapour pressure to migrate  vertically through
            at  least  2 m of soil  (ie. good soil penetrability)
          -  relative  non-solubility  in water
          -  non-toxic when used in  low concentrations
          -  relative  non-reactivity  with soil constituents,  with pipeline
            materials, or with products transported in pipelines
          -  readily available
          -  readily identifiable by  a portable detector;
b) To identify a  detector  that was portable, could operate  in  real  time,
and could detect the  above-mentioned odourant  at very low concentrations,
and;
c) To evaluate the overall  test-fluid  / detector system  under  controlled
conditions,  and subsequently on actual pipeline leaks.

PRE-TRIAL   CONSIDERATIONS
Prior  to conducting field  tests,  preliminary work  was  undertaken to
identify  the optimal odourant,  incorporate  that  odourant  into a  leak-
detection  test-fluid, and  identify a  detector  capable of meeting the
established  study  criteria.  The  following  section  describes   that
preliminary research effort.
                                  648

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 Odourant  Selection   And  Test-Fluid  Considerations
 A review of the literature was conducted in order to generate a short list
 of odourants  which satisfied the criteria outlined above. As  a  result of
 this  review,  a number  of  odourant families were identified and appropriate
 representatives  from each  family  were  then  evaluated. (As   of  this
 conference,   the  test-fluid  chemistry  has  "patent pending"  and  "trade
 secret"  status.   Accordingly,   the  following  section   provides  a
 "generalized" discussion  of  the work leading to development of  the test-
 fluid:  specific details of the chemistry will  not be addressed.)

 Figure  1 shows Candidate A has  a  human odour threshold equal to  or less
 than  most  most other  odourant candidates,  and approximately  one  fifth the
 human detection threshold for hydrogen sulphide (a compound well  known for
 its low detection  threshold).  The  relative  vapour pressures  of the short-
 listed  odourant candidates are  compared in  Figure 2. These data  show that
 only  Candidate B  is appreciably more  volatile than  the  prime Candidate A.
 Solubilities  of the odourant candidates in water are summarized  in Table
 1. This table shows that  the  prime odourant candidate meets the solubility
 requirements  stated above.

 Analysis of  the  data presented in  Figures  1  and 2,  and in  Table  1,
 indicate  that odourant  Candidate   A  (hereafter  referred  to   as  "the
 odourant")   possesses   the  best   overall  complement   of  physical
 characteristics consistent  with  the requirements  of  the leak-detection
 procedure. In  order   to  combat  the   tendency of  the chosen  odourant  to
 separate from the  test-fluid mixture, it was determined  that  incorporation
 of the odourant  into a binary azeotrope  involving  one of the  other
 essential test-fluid  components was possible.  The  odourant-containing
 azeotrope was  found  to  possess  an  acceptable  vapour  pressure,  a  high
 odourant mole-fraction in the vapour  phase,  and  sufficient miscibility in
 the remaining test-fluid components.

 Choice  Of  Detector
 Choosing the definitive detector for the new  leak-location method proved
 to be  a  difficult  exercise  and  involved  the evaluation  of   several
 different  technologies.  Catalytic   combustion  detectors  ("sniffers"),
 although effective for detecting  some compounds,  were ineffective  for the
 selected odourant,  and in any event  could not operate  continuously along
 an extended  pipeline right-of-way. Infared spectrophotometers  proved
 equally  impractical  due to the  ease  with  which they are  affected
 negatively by flammable vapours  or water  contamination.  Several  different
 gas  chromatographs were  evaluated,   and  although  some showed detection
_thresholds  of 0.1  ppm  for the odourant,  none were sufficiently  portable to
 enable  their use  in  the field  (despite  manufacturer's claims  to  the
 contrary). However,  subsequent review of  a  widely-distributed body  of
 literature  ultimately  suggested that  domestic dogs were  capable of meeting
 the detection sensitivity needs of  the  program,  and were  clearly  able to
 fulfill the "portability"  criterion as well.

 An overview  of this   literature revealed   that  domestic  dogs have  been
 trained to detect  exceedingly low  concentrations  of  a  wide  variety  of
 chemicals,   many  of   which   are   associated   with   problems   of
 substantialeconomic significance. For example, dogs have been  used by the
 United  States Department Of  Agriculture  to detect the egg cases of insects
                                  649

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                   n   o   tn
FIGURE 1. COMPARATIVE DETECTABILITIES OF
         ODOURANT CANDIDATES
         Cylinder
                        Hok AnftR* tato Gram*
 FIGURE 3. EXPERIMENTAL APPARATUS FOR
          LEAK DETECTION TESTS
                                                           > tonom-nox
FIGURE 2. COMPARATIVE VOLATILITIES OF
         ODOURANT CANDIDATES
                                                      lioooo


                                                    | 100000


                                                    | 90000


                                                    jj 80000


                                                    2 TOOOO


                                                    § 60000


                                                       50000
       0730081509001000 110012001330 15301645
              Clock Time of Swnplin|


  FIGURE 4. TEST FLUID COMPONENTS
           PARTITIONING ANALYSIS

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                     TABLE 1.

AQUEOUS SOLUBILITIES OF ODOURANT CANDIDATES


           ODOURANT    AQUEOUS
           CANDIDATE    SOLUBILITY
               A         insoluble
B                       slightly soluble
                       slightly soluble
               D       slightly soluble
               E       slightly soluble
               F         insoluble
               G         insoluble
               H       slightly soluble
               I          insoluble
               J       slightly soluble
               K         Insoluble
               L         insoluble
                    TABLE 2.

ODOURANT CONCENTRATIONS IN AIR SAMPLES TAKEN AT

"GROUND LEVEL" FROM THE EXPERIMENTAL APPARATUS



              TIME     ODOURANT CONC.

              (hours)         (ppm)

               1             O2

               2             32.4

               3             15.1
                     651

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responsible for  defoliating vast  tracts  of American  forest (5,6).  Dogs
have also  been trained to  locate  locust infestations  in American  homes
(7) , identify  seventeen different  chemical  accelerants used by  arsonists
(8),  find explosives  (9),  detect the  presence of  drugs  and firearms
(8,9,10), locate breaks  in  underground power cables  (11),  and to  detect
certain products leaking  from  buried  pipelines  (3).  Researchers from the
Department  of  Forensic Medicine  at  the  University  of  Leeds  are  using
trained  dogs  to check  /  calibrate  a prototype  machine which  is  being
developed to identify criminals by  matching  the  scent  on  articles found at
crime scenes with that from suspected felons  (12) .  Similar work is  being
conducted by  police  agencies in   the  Neatherlands   (13).  The   U.S.
Environmental  Protection Agency and the New  Jersey Institute  of Technology
use dogs to "sniff  out"  toxic  chemical leaks which could  not  as quickly or
effectively be detected  using conventional  instruments  (14) .  However,
although dogs  have been used successfully to detect low  concentrations of
various chemicals,  past technological restraints have limited our ability
to quantify the limits of a dog's  olfactory system.  Despite this lack of
precision,  some  researchers have  "estimated"  that  dogs are  capable of
detecting certain chemicals at  levels  of  1  part per trillion  (15,16,17).
However,  controlled  laboratory  tests  have  shown that  the  absolute
olfactory threshold  of  dogs   is  substantially  less  than  1  ppt.  Two
independent  research  efforts  using operant   conditioning  (18),  and
electroencephalographic and behavioral olfactometry  (19),  have  measured
the minimum sensitivity of  dogs to specific compounds at 10-15  to 10-18
molar.

Once a  suitable odourant  had been  chosen  and  dogs  were identified  as the
best available detector,  a  number  of experiments were  conducted to test
the  feasibility  of the overall leak-detection  technique.  The  following
section summarizes  that work.

EXPERIMENTAL   PROCEDURES   AKD  RESULTS
Laboratory  Leak-Detection   Experiment
Experimental Design.  Prior to  field testing  the  new leak-detection method,
a  laboratory  experiment  was  conducted to  evaluate  the ability  of the
odourized  azeotrope  to dissociate from  other test-fluid components and
percolate to the  soil surface.

A schematic representation of the apparatus used for this  test is shown in
Figure  3.  The  test-fluid  was  transferred to an empty  propane  tank which
was then  inverted  and  pressurized  to 345 kPa with nitrogen.  As  nitrogen
was released from  the  system,  test-fluid  was  forced through a 6 mm  PVC
and steel tube to a small  section of pipe  having a hole 0.4 mm in diameter
drilled  through  one end. This assembly  was  placed at  the bottom  of a
container  formed by  welding 2  oil drums  together,  and  then filled with
finely crushed rock  (3-6  mm diameter). As test-fluid was allowed to flow
through the apparatus,  it was  subsequently forced through the hole  in the
buried  pipe and  into  the  surrounding gravel.  The  test apparatus was
designed to allow 16 litres  of the  fluid to flow into the barrel within a
2-hour  period.  Air samples were taken at  one-hour  intervals  above the
barrel using a small  air pump  and Tedlar bags. Samples were later analysed
using gas chromatographic  techniques.
                                  652

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Test Results.  One hour after commencement of the experiment,  a faint odour
of could  be  detected  (by  the human nose)  at the top  of the  container.
Approximately  one half  hour later,  a  strong  odour was  evident,  which
persisted.

Table  2   shows  odourant  concentration,  as  measured  by  the   gas
chromatograph, in  samples  collected over a  three  hour  period. A  barely-
detectable concentration  (0.2  ppm) of  the  odourant  rose  to the  "soil
surface" within the  first  hour.  Surface concentrations  peaked  during  the
second hour (32.4 ppm)  and decreased by the  third hour to  approximately 15
ppm.

Test-Fluid  Partitioning  Test
One final consideration relevant to the  test-fluid needed  to  be addressed
before full-scale  field trials  could be conducted.  For  the test-fluid to
be  effective,  the odourant  must remain in-phase within  the  test-fluid
throughout the testing procedure.

Experimental  Design.  To  test the  degree of partitioning of  test-fluid
components, a  container of the  fluid was prepared.  Homogenization  of  the
mixture  was  accomplished  by vigorously agitating  the container  for a
period of 5 minutes using a Red Devil paint  mixer. Grab  samples  were taken
from the top and  the bottom of the  container  over a period of  nine  hours,
and  then  analyzed for  odourant  concentration  using  gas  chromatographic
techniques.

Test  Results.  Results are  summarized in  Figure  4.  Although  a  certain
degree  of odourant migration occurred within the  test-fluid mixture,   it
was evident that the  odourant  did in fact remain in phase.

Training  Of   Leak-Detection Dogs
Before  full-scale  field  trials   could  be  conducted,  dogs   needed   to
be   obtained,  evaluated  for their  suitability  to the  task of leak-
detection, and then  trained  to  detect the  odourant. Esso solicited  the
help  of  personnel  from   the  Interdiction  and  Intelligence  Branch   of
Canadian Customs to procure and train a single dog to test  the  feasibility
of  using  animals  as  leak detectors. It soon  became evident that dogs were
capable of detecting the odourant,   and of working through  a  concentration
gradient  of vapour ("cone  of  scent") to  indicate areas  where the odourant
was  found rising from the soil surface.  Once the effectiveness of using
dogs  was established,  a  private   firm,  Command Dog  College  Ltd.,   was
contracted to  purchase, evaluate and  train  a number  of  animals for  leak-
detection work.  Training was  conducted over a period of approximately  10
weeks. Once this program was complete,  the dogs  were  capable  of  "tracking"
the odourant   along  open rights-of-way as well  as in partially-backfilled
trenches.  They were  also  trained  to exhibit strong digging behavior  at
those  sites  where they  detected the  highest  concentration  of odourant
exiting  the  soil  surface.  In  addition  to being trained to  track  the
odourant, dogs were  physically  conditioned  to ensure they would have  the
stamina required to work for long periods in the rough terrain  encountered
along pipeline rights-of-way.

Full-Scale  Field  Trials
After the training of the  leak-detection  dogs was complete,  two full-scale
                                  653

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field trials were designed to evaluate the capability of the overall leak-
location technique.

Experimental Design. In total, nine  leaking  pipelines  were fashioned from
15-20 cm  long sections of  114 mm   pipe,  welded shut  at both  ends.  The
apparatus employed in these tests was  similar  to  that  utilized during the
laboratory experiments described earlier  (see  Figure 3).  To mimic leaking
pipelines,  ports measuring  0.8  mm  in diameter were  drilled into  brass
plugs which  were then  threaded into the  end caps of each  pipe.  The flow
rate of test-fluid  from each orifice was calibrated in the laboratory to
ensure  all  the test-fluid  would  leak   from  the  apparatus within
approximately 2.5 hours.

To minimize excavating extensive  sections of  pipeline trench,  one site was
constructed  so  as  to  "simulate"  right-of-way conditions.  This  was
accomplished by  augering  20  holes  to a standard pipeline  burial  depth  of
1.2  m.  Spaced at 10 m intervals,  the holes functioned  as a 200 m long
right-of-way.  Of the 20  holes augered, 5 were  prepared  as  experimental
(leak)  sites,   and  15  were  prepared as  controls.  The  position  of
experimental-versus-control  sites  was  established using  a random number
generator  and neither  the authors  nor the  dog  handler knew  which  sites
contained  the  leaks.  To  avoid the dogs equating the presence of surface
equipment  with the  presence  of leaks,  all experimental and control  sites
were made to appear  similar.

The  second site was prepared somewhat  differently.  Here, a 400 m  long
trench  was  excavated  to  a  depth  of  approximately 1  m  and holes  were
augered into the bottom of the trench.  Prepared in this  manner, the second
site allowed  dogs to become  accustomed to working  in partially-backfilled
trenches,  a  condition not uncommon where new pipelines  are being pressure
tested.  Four experimental leaks were  prepared at this site: three  were
buried to a depth of 1.2 m;  the fourth  was buried at 3.7 m.

To prevent plugging of the leaks  with soil, paper towelling was taped over
the  orifice in each section of pipe,  and a  small quantity of gravel was
placed  at  the bottom of  each,hole.  A  length of 6 mm carbon-steel tubing
was  fitted to the sections of pipe  prior to  lowering  them  into the augered
holes. Additional gravel was then placed so  as to barely  cover each  pipe,
and  all  holes  were  then backfilled with native material.   The  ends of the
tubes extending  from buried pipes at the experimental sites were  connected
to propane cylinders containing 16  L of test-fluid,  and the tanks  were
placed 3 m from the  holes.

All  equipment  used  at  experimental locations was  cleaned  and  subsequently
rinsed  with water  so as  to  remove any traces  of odourant  which  may  have
contaminated these  sites.  To ensure  consistent  treatment  of   all  test
facilities, equipment at  the control sites was purposely contaminated with
test-fluid and then decontaminated  using the  same procedure as employed  on
experimental sites.

To begin the  field  tests, nitrogen was forced  into the  cylinders of  test-
fluid  (see Figure  3)  at  a  specific pressure calculated to  achieve the
desired  flow rate  of test-fluid. The  leaking  pipes  were  left to release
test-fluid into the  surrounding soil  for a period of approximately 2.5
                                 654

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hours. Two  hours after  all the  test-fluid had  been expelled from  the
cylinders,  a dog was introduced to  the  site and challenged to  locate  the
leaks. Prior to, and  directly after working the  dog along the  simulated
pipeline  rights-of-way,  grab samples of air were collected in Tedlar bags
above each  experimental  site. These  samples  were later  analysed in  the
laboratory  for  odourant concentration.
     Results.  During the first field-trial,  the  dog correctly  indicated
the presence of the odourant at four of the five experimental  sites.  This
result was  initially  seen  to represent  a success  rate of  80 percent;
however,  subsequent mass-balance determinations performed  on the  cylinders
of test-fluid confirmed that one of  the  experimental  sites had  in fact not
leaked.  The dog  had  therefore  correctly  "indicated"  on  all  5  sites.
Results  from the second  field trial were  similar,  with  dogs  correctly
indicating four out of four leak locations, including the leak buried 3.7
m subsurface.  (The latter leak was not detected in the initial trial  run;
however,  a  subsequent  series  of  runs spaced  several hours  apart,  showed
the dogs  capable of detecting the leak after 48 hours.)

Of the nine leaks  presented to the dogs, GC  analysis  was able  to detect
only two (airborne odourant concentrations were  measured at  19 and 2.5
ppm) .

DISCUSSION
The experimental  data presented above  clearly demonstrate that the new
leak-detection  procedure  met  all  the technical challenges  identified at
the  onset  of  the  research program.  The test-fluid mixture  performed
according to design,  with  no  undesireable phase  separation  encountered
during  any  of the  tests.  Similarly,  the dogs  trained  to   detect  the
odourant  exceeded all expectations.  These animals  proved to  be  easily
trainable  to  detect  the  odourant and  were  shown  to be  capable  of
accurately pin-pointing the location of subsurface leaks. As noted, dogs,
on occasion, even "informed" research personnel of the failure of certain
test apparatus, and  easily  out-performed  gas  chromatographs  in  detecting
the odourant .

Since  completion  of  the  experimental portion  of  the  leak-detection
program,  the technique has been utilized on six actual pipeline leaks. One
of these incidents  involved a 10  year  old produced-water line which had
been buried  to a depth of 2.1  m  in  compacted  clay soil.  Another incident
involved a  glycol  pipeline which had been  in service for 28  years.  The
leak  in  the  produced   water line  was  detected   under  particularly
challenging  soil  and  weather  conditions  (in  clay-rich  soil,  in  frozen
ground, after a lengthy period  of minus 40 C temperatures) .

CONCLUSIONS
Results  collected from  a series of  studies   conducted  over  a  two-year
period confirm the feasiblity  of using an  odourized test-fluid  and trained
domestic dogs  to accurately locate  pin-hole  leaks  in buried pipelines.
Using  the  detection methods  described,  leaks  as small  as  0.8 mm were
detectable to a depth of 3.7 m. During the  leak-detection program, the new
technique was  tested on nine experimental leaks and  six failed pipelines.
All  fifteen leaks were  successfully  located.  Additional  research is
planned  to  better define odourant  percolation rates under various soil
conditions,  to more precisely  define the physiological detection  threshold
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of the dogs for the test-fluid, and to establish the overall limits  of  the
technique.

ACKNOWLEDGEMENTS
The  authors   gratefully   acknowledge  the  enthusiastic  support   and
contributions of  a  number  of people. Special  thanks go  to J. Szarka,  Dr.
M.  Moir,  K.  Corry,  R.  Heater,  and  Dr.  A. Kendall   of the  Research
Department  of Esso Resources Canada Limited, who helped design and conduct
many of  the experiments  leading to development of the final leak-location
technique.  T.  Gollanger   and  K.  Adams  of  Canadian  Interdiction   and
Intelligence provided yeomen  service  in  training the first leak-detection
dog in record time on short notice. The extra  efforts of  J. and G. Bissell
of Command  Dog  College Ltd.  in procuring, evaluating and training dogs,
contributed in  a  substantive way  to  the overall success of  the program.
Dr. E. Crichlow of  the Western College  of  Veterinary Medicine, University
of Saskatchewan,  Canada,  was a willing  and  friendly soundingboard  during
initial  stages of the program and provided valuable information on  canine
olfactory physiology. Finally, Dr. L.J.  Myers, Director  of the Institute
For Biological Detection Systems,  University of Auburn,  Alabama,  was most
helpful   in  providing  relevant  data   and  electroencephalographic
olfactometry expertise to quantify the dog's  olfactory sensitivity.

REFERENCES
1   Energy  Resources Conservation  Board,  Calgary, Alberta, Pipeline
    Statistics,  1978-1988.

2   L.W.  Whitmer,  "Leak Detection  1983,  Methods, Suppliers, Applications",
    Esso Resources Canada Limited,  Production Research Division, Report
    IPRT TP 83 23, December,  1983.                           __

3   G.R.  Johnson,  "The Pipeline Dogs"  Off-Lead, pp 10-15,  May 1975.

4   G.R.  Johnson,  Tracking Dog Theory  and Methods, Arner Publications Inc.,
    New York.  1977.

5   G.R.  Johnson,  "Gypsy  Egg Detection Dogs", Off-Lead,  pp 8-11, October,
    1976.

6   W.E.  Wallner and T.L. Ellis, Olfactory  Detection of Gypsy Moth Phermone
    and Egg Cases  by Domestic Canines, Environmental Entomology, pp 183-
    186,  February, 1976.

7   The Calgary Herald, Calgary Alberta,  September 18, A2, 1989.

8   U.S.  Department  of Treasury, Bureau of  Alcohol, Tobacco and Firearms,
    and Connecticut  State Police,  Canine Acceleration Detection Program,
    1988.

9   J.  Bissell,  Command Dog  College Ltd., Calgary Alberta,  (pers.  comm.),
    August,1988.

10  T.  Gollanger,  Canadian Interdiction and Intelligence,  Customs and
    Excise,  (pers. comm.), June.. 1988.

11  G.R.  Johnson,  "Canine Trouble  Shooters", Gazette, pp 43-45,
    March,1984.
                                 656

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12  B.  Sommerville and M. Green, The  Sniffing  Detective,  New Scientist, pp
    54-57,  May,  1989.

13  H.  Pringle,  "Collars and Scents",  Equinox,  p 29, November / December,
    1989.

14  Chementator,  Chemical Engineering, pp 9-10,June 23, 1986.

15  M.D.  Pearsall and H. Verbruggen (MD.),  Scent,  Training To Track,
    Search, and Rescue,  Alpine Publications Inc.,  Loveland Colorado,
    U.S.A., 1982.

16  H.C.  Lee and D.A. Messina, Evaluation  of Arson Canine Testing Program,
    Connecticut State Police Forensic Science Laboratory,  1988.

17  W.  Clyde,  "Arson Dog", Law and Order, pp 40-42, 1988.

18  D.G.Moulton,  E.H.  Ashtomn, J.T. Bayers. 1960.  Studies  in Olfactory
    Acuity. Relative detectability of N-Aliphatic  Acids By The Dog. J.Anim.
    Behav.  8:117-118.

19  L.J.  Myers, R. Pugh. 1985. Thresholds Of The Dog For Detection Of
    Inhaled Euganol And Benzaldehyde  Determined By Electroencephalographic
    And Behavioral Olfactometry.  Am. J. Vet. Med.  46:2409-2412.
                                  657

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OIL FIELD BRINES:  ANOTHER PROBLEM FOR LOUISIANA'S COASTAL WETLANDS
Virginia Van Sickle
Secretary, Louisiana Department of Wildlife and Fisheries
Baton Rouge, Louisiana
C. G. Groat
Director, Louisiana Geological Survey
Baton Rouge, Louisiana
Introduction

The rapid rate of loss  of coastal wetlands in Louisiana has become a major  issue
with economic, political,  and  technical  components.   With 40% of the nation's
coastal wetlands  disappearing  at a rate of  approximately 40 square miles per
year,  the  impact on commercial fisheries, trapping,  recreational use and the
people who live there is a major concern of residents,  politicians  and scientists
(Fig. 1) .   Attempts  to understand the causes of wetland loss have produced a long
list of natural  processes and  human  activities that have  contributed to the
problem.   Coleman  and  Roberts (5) have  provided a  comprehensive  summary  of
factors contributing to the loss of deltaic  coastal wetlands.

It  is  generally  accepted by the scientific  community,  although  not  generally
appreciated by the  public,  that wetland  loss is a natural part of the deltaic
processes  that have built south Louisiana.   As delta  lobes are abandoned  by
avulsion upstream,  distal  wetlands subside by  compaction, are invaded by  salt
water  from the Gulf of Mexico, and are eroded  by  wave  action.   There is  also
general agreement that human activities have  contributed significantly to  marsh
loss.   Flood-control  levees  along the  lower  Mississippi and control  of the
channel for navigation have robbed the downstream  marshes of sediment.  Canals
dredged for navigation, for access  to oil and gas drill sites, and for  pipelines
have interrupted  the normal hydrology and fostered saltwater intrusion.   There
is  also concern  that  some  marsh  management  programs,  intended to  increase
productivity,  may actually contribute to wetland loss in some settings.

A substantial  body  of  literature documents  the stress that  increased salinity
places  on  marsh  plants  adapted to  lower-salinity regimes.   Although  there has
been discussion  o'f  the role of  saltwater intrusion  in marsh loss,  relatively
little  attention has been paid  to  the role of the  discharge  of salt water into
marsh  areas  as a result of human  activities.   Oil and gas  operations are the
chief human contributors of saline waters to the Louisiana coastal area.   This
paper describes  these discharges,  summarizes the effects of  increased salinity
on marsh vegetation, and discusses the implications  for  marsh deterioration.
                                     659

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             Legend
      Fresh and Intermediate Marsh
      Brackish and Saline Marsh
       Brine Discharge Point
        SCALE
10   0   10   20  30 MILES
                                      10 0    20    40    60
                                                          KILOMETERS
Fig.   I.     Louisiana coastal wetlands
    and brine  discharge  points.

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Background

The fluid produced from oil wells normally consists of oil, gas liquids, and salt
water.    The  salt water produced  along with the crude  petroleum is  generally
called "produced water"  or  "oil  field brine"  by  the  petroleum industry  and
regulatory agencies.  Produced  water  is  the highest-volume waste generated by
oil  and  gas operations.   It  contains both  dissolved  and  suspended  solids,
(including such dissolved salts  as sodium  chloride) dissolved hydrocarbons,  and
trace metals.

From 2  to 99%  of  the total fluid produced from an  oil well  is  salt water;
produced  water constitutes  an  average  of 85%  of the fluids  produced  from
Louisiana oil fields (20).  Higher percentages  of produced water  are associated
with older fields (6, 19).

The  three alternatives for disposing  of  produced water are (1)  injection  into
disposal wells (90% of U.S. produced waters are injected), (2) storage  in tanks,
pits, or other containers,  and (3)  discharge  into  surface  water.   The U.S.
Environmental  Protection Agency (EPA) reported a statewide  ratio  of produced
water injected per volume of oil production in Louisiana of 5 bbls  of water/1  bbl
of oil (bbl=barrel=42 gallons)  (20).   Most produced water in north Louisiana is
reinjected for enhanced recovery or disposal onsite  or  at a commercial  facility.

Between  1901, when the first  oil well was drilled near  Jennings, and 1953, state
regulations allowed the discharge  of produced waters into most surface  waters.
In  1953  the Louisiana Stream Control  Commission  required that  oily  waste  be
removed  from salt water before  it could be discharged.   The State Department of
Conservation promulgated  regulations in 1965 governing the injection of produced
water to prevent the  pollution  of freshwater  supplies.   In 1968 the  Louisiana
Stream Control Commission altered its  regulations governing oil field  brine  and
prohibited discharges in freshwater bodies and their drainage areas.  However,
these regulations state that "salt water may be disposed of in normally saline
waters,  tidally affected waters, brackish waters or other waters  unsuitable  for
human consumption or other purposes."  This has resulted in the  discharge  of a
large volume of produced  water  into fresh  and brackish marsh  areas.  Additional
exemptions to the restrictions against discharges in freshwater  bodies  are given
for  the  Mississippi  River  and  its  distributaries  south of  Venice  and  the
Atchafalaya River south of Morgan  City.

Since 1968  there have been  no  changes to further restrict  the  discharges  of
produced water  in Louisiana's coastal  zone.   In 1985  the Louisiana Department
of Environmental Quality  (DEQ) promulgated regulations that required permits for
all  oil  field wastewater discharges.  A DEQ survey of oil and gas operators in
1986 revealed  that oil field brines were being discharged to surface  waters at
698 different locations in Louisiana's coastal  parishes, with a total  volume of
2.64 million barrels per day.

Produced water  can  contaminate   soils  or  surface  waters  and can  destroy
vegetation, aquatic organisms,  and agricultural productivity    Produced water
                                    661

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may contain many  toxic  substances and, therefore, can be  considered hazardous
under the definition  of the federal Resource Conservation and  Recovery Act of
1978.  Most instances of damage from produced waters in Louisiana relate to its
high  chloride  content   and its  "virtually  permanent"  damage  to  soils  and
vegetation (20) .

The primary  sources  of  data used  to  identify and characterize produced water
discharges and their effects were  DEQ,  the Louisiana Geological  Survey, the U.S.
Geological Survey,  and  EPA.  Documentation  of  the impacts of  the  exposure of
wetlands  to  pollutants  commonly  found in produced water  was  obtained  from  a
review of published and unpublished literature.

Produced Water  Disposal Practices

Oil production operations generally include the gathering of the produced fluids
(oil, gas liquids, and water) from a well or  group of  wells, and separation and
treatment  of the fluids.   As oil  is depleted  from  the  producing  formation,
pressure  differentials  cause water to flow in from adjacent  formations.   As a
result, water-to-oil  ratios increase  with the production  life  of an oil well.
Stripper  wells  (i.e., those that  produce less than 10 barrels  of oil  per  day)
may produce more  than 100 barrels  of  salt water  for each barrel of  oil.

State  regulations prohibit  the surface discharge  of  oil field brine  in areas
north of the coastal zone.   Injection is the most  common method of disposal where
discharges to surface water are not allowed.   Louisiana oil field operators and
commercial disposal companies injected 794,030,000 barrels  of produced water in
1985  (20).  This  figure was derived from injection well reports  required by the
Louisiana Department  of Natural Resources.

In 1986 DEQ notified state oil and gas  operators that existing discharges of oil
field waste must be reported and ultimately receive a permit.  Responses to  this
request for information through November 1987, identify the location and volume
of 698 point source discharges of produced water.  The total reported volume of
produced  water  discharged into coastal surface waters in  1986  was  962,682,498
barrels  (Table  1)

These  reports indicate  that  70% of the produced water  from  oil field operations
in  Louisiana  is discharged into  surface   waters.    Virtually  all  of these
discharges  are  located in   the coastal  zone.   The volume  of  produced water
discharged  in  each coastal parish is presented in Table  2.   In addition to
produced  water from over  300 onshore fields, coastal  oil and  gas  facilities
process  oil  and  salt water  produced  from the federal Outer  Continental Shelf
(OCS)  and state offshore waters (Fig.  2).  A recent study conducted by the  U.S.
Minerals  Management Service indicated  that 23% of the  produced water discharged
into  the  Louisiana state coastal waters is transported onshore from the federal
OCS  (4) .  The volumes of these discharges are reflected in the industry reports
summarized  in  Table  1.

Total  discharge of produced water from 14 onshore fields  in  1986 is  presented
                                      662

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                                   TABLE  1
      Recent estimates of Louisiana produced water volumes  and disposal
       practices from three  independent sources
Total Annual
Volume (barrels)
Disposal
Methods
Data
Source
  794,030,000
Inj ection
Injection well Reports
for 1985, Louisiana
Department of Natural
Resources
1,346,675,000
  962,682,495
Undifferentiated,
includes injection
Discharged to
coastal surface
waters
Indus t ry S urvey,
American Petroleum
Institute, 1985 (24)

Industry Survey,
Louisiana Department
of Environmental Quality,
1987
                                    TABLE  2
    Reported brine discharged to Louisiana coastal waters,  by parish (21)
                  Parish

                  Terrebonne
                  Plaquemines
                  Jefferson
                  Lafourche
                  Iberia
                  St. Bernard
                  St. Mary
                  Cameron
                  Vermilion
                  Calcasieu
                  St. Charles
                  Orleans
                  St. Martin
                  St. Landry
                                    Barrels/Year

                                    314,272,847
                                    271,440,967
                                     82,472,881
                                     65,798,258
                                     61,228,750
                                     53,829,835
                                     49,150,535
                                     27,002,335
                                     22,780,088
                                      7,613,535
                                     6,828,237
                                       147,825
                                       100,375
                                         8,030
                  TOTAL
                                    962,682,498
                                     663

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       TEXAS
LOUISIANA
COASTAL
 ZONE
     Ml
Fig.  2.    Louisiana  coastal  and offshore oil and gas fields.

-------
in Table 3.  These  are  representative  major  fields  located in the  coastal zone;
all but one was discovered before  1970.   The total volume of brine  discharged
from these 14  fields in 1986 was 150,660,190 barrels.

Chemical Composition of Produced Waters

While most oil field brine is believed to be of marine origin, the composition
and ionic ratios of these waters is quite different from that of seawater.   The
chemical properties of oil field brine are the result of physical and chemical
changes before, during, and  after  sediment  consolidation.   The composition  of
the  interstitial water deposited with marine  sediments changes  as  the  water
reacts with rock.  The most dramatic chemical change results from the dissolution
of halite (6).

The salinity of oil field  brine  is  generally much higher than that of the  water
originally deposited with marine sediments and commonly ranges from  50 to more
than  150  ppt.   The  dissolution of salt  diapirs,  which have  migrated upward
through Gulf Coast  sediments,  is the primary and ongoing source of high salinity
levels in Louisiana oil field brine (11,  17, 30).

Oil field brine is  often close to saturation with sodium chloride.  The removal
of  all  chlorides  would virtually  desalt  the brine.   An  examination  of U.S.
Geological Survey  records for 178 brines  sampled  in Calcasieu and St.  Charles
parishes revealed that  chloride concentrations varied widely,  but on the average
exceeded the chloride  concentration of seawater (18,980 ppm) by  a factor of 3
to 4  (Table 4).

Ions  in greatest concentrations  in  produced  waters  other than chloride (Cl) and
sodium  (Na+) are  calcium (Ca*2) ,  magnesium (Mg+2) , and potassium (K+) , listed  in
decreasing order of abundance (6).

In addition to chemical constituents naturally occurring in  subsurface brines,
produced water often contains substances associated with oil  field drilling and
production  practices   at  the well  site.    These   include  chemicals used for
acidizing the  producing formation (e.g., acetic,  formic,  and hydrochloric acid),
corrosion   inhibitors,  surfactants,  friction  reducers   (primarily  organic
polymers), ethylene diamine tetracetic acid  (EDTA) to dissolve pipe  corrosion,
and  cleanup additives  to  remove reactor products  and  reagents.   Although the
formation may  retain some  of these fluids,  most are eventually  pumped to the
surface at the well head with brine or oil (20).

Sampling conducted by  EPA in  1986  identified several chemical constituents  in
oil  and gas extraction waste  streams in "amounts greater  than  health  based
numbers multiplied by  one thousand."  Of  these  constituents, benzene,  barium,
lead, and phenantherene were found in exceeding amounts in produced  water tank
bottoms  (20).   The organic  constituents  from the EPA "List  of  Concerns"   or
"Priority Pollutant List" include the hydrocarbons,  benzene, napthalene, toluene,
phenanthrene,  bromodichloromethane, 1,2 trichloroethane and  pentachlorophenol.
The inorganic constituents of concern identified by EPA include lead, arsenic,
                                    665

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                                    TABLE 3
Produced water discharges reported for 14 fields in coastal Louisiana  in 1986
               (Source: DEQ and Louisiana Geological Survey).
                                 Parish                     Barrels/Year

   Caillou Island             Terrebonne                     6,533,135
   Lake Washington            Plaquemines                   13,848,100
   Lafitte                    Jefferson                     13,301,330
   West Bay                   Plaquemines                   11,816,875
   Garden Islands             Plaquemines                    5,884,530
   Lake Barre                 Terrebonne                       648,970
   Leeville                   Lafourche                      1,657,100
   Weeks Island               Iberia                        24,382,000
   Point-a-la-Hache           Plaquemines                    4,577,100
   Eloi Bay                   St. Bernard                    6,296,250
   Half Moon Bay              St. Bernard                   31,641,120
   Lapeyrouse                 Terrebonne                    19,942,870
   Bayou Penchant             Terrebonne           '              1,460
   Quarantine Bay             Plaquemines                   10,128,750
      TOTAL                                                150,660,190
                                    TABLE 4
         Chlorinity values for produced waters  in two  coastal  parishes
          (Source:  U.S. Geological Survey, Bay St. Louis, MS)

                                                               Ratio  of
                                                               Produced Water
            Number of         Chlorine Concentration           Chlorinity
          Produced             in Produced Water  (ppm)          to that of
 Parish	Waters Sampled	High	Low	Average	Seawater	

 Calcasieu     127             195,776    3,800     62,645      3.3

 St. Charles     51             136,110      360     74,570      4:0
                                    666

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bariuin and antimony.  Table 5 presents results of analyses  conducted by EPA of
produced water discharges from four south Louisiana facilities.

Ecological Impacts of Increased Salinity

The  most widespread  and  frequently  reported problems  associated  with  the
discharge of oil field brine in Louisiana involve damage to local plant life and
soils.   When brine  is  discharged  into freshwater  areas  and  uplands  severe
salinity problems  for organisms intolerant of  increased salinity may  result.
Estuarine and marsh habitats can also be impacted by the unusual ionic  components
and ratios in produced water.

Even the most salt-tolerant plant species are unable to withstand natural marine
salt concentrations above 50  ppt  (18).   The natural zonation of marsh  grasses
in fresh to saline environments  indicates the limits of ability of these  species
to regulate  salt content.

The effects of excess  salt and high salinity on dominant wetland plants are  well
documented.   High salinity  affects plant growth  1)  osmotically, 2)  by  direct
toxicity, and 3)  by creating  a  nutrient imbalance (15).  Panicum hemitomen.  a
common grass in freshwater marshes,  for example, will die within four  days after
exposure to 10 ppt salinity, which is roughly one-third the salinity of seawater
(35 ppt.) (13).

Pezeshski et al. (12)  found that bald cypress (Taxodium distichum) seedlings can
tolerate and recover from short-term exposure to salinity levels less than 3  ppt.
Above  that  level  they cannot  acclimate  and  ultimately  die  from  reduced
photosynthesis  and metabolic  stress.   Even  the slightest increase in salinity
causes leaf  injury and  root damage  to bald cypress seedlings  (14).

In studies designed to simulate salt stress  resulting from exposure to seawater
and brine discharges  associated with oil and gas operations, Pezeshski  et al.
(13)  found  that photosynthetic  rates in P.  hemitomen declined between  20% and
67%  within  one  day of  saltwater exposure.   Gas exchange  rates were  reduced
between  55%  and 80% within one day.

Pezeshski et al. (14)  found that photosynthetic rates and biomass production of
Spartina patens were  strongly and adversely affected by increases in salinity
Net photosynthesis was  reduced  by  43%  as soil salinity  increased from  0 to 22
ppt.   S. patens is  the domiant  vegetation  type  in the  brackish  marshes  of
Louisiana's  coastal zone.  Studies show that brackish marshes are deteriorating
faster than  any other wetland type  in Louisiana  (10,  1,  20).

Spartina alterniflora is the most common saline marsh  grass in Louisiana and also
the  dominant plant species  of  the  backbarrier marshes of  Louisiana's  barrier
islands.  Backbarrier marshes play an important role  in binding eroded sediment
which would otherwise  be lost  during the landward migration of these islands  (8)
Parrondo et al.  (15) found that S_.  alterniflora seedlings grew best at  salinities
of 5-10  ppt  and that  root  and shoot growth was inversely related to substrate
                                      667

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                       TABLE 5
     Analytical results of sampling conducted by
U.S. Environmental Protection Agency at end points of
  four  produced water  discharges  in  south Louisiana.
   Asterisk denotes EPA "priority pollutant" (22).
>
(D
1-1
p>
OQ
rt>
203
685
1,846
2,339
47

2,126
8,923
4,165
2,010,000
882
30
253,250
17,555
38,400,000
48,275
18
111
47,980
28,825
217
1,439,750
154
165,275
Sun Exploration and Production r^
Co. , Sweetbay and Bateman Lake ^
Tank Battery
St. Mary Parish, La.
809
1,849
1,510
0

3,207
1,090
2,080
80,100
280
0
120,000
29,800
14,300,000
25,000
0
404
12,000
37,000
90
468,000
133
12,100
Tidewater Canal o
o
Leeville fi
Lafourche Parish, La.
1,504
3,520
6,334
33

2,880
9,390
8,940
130,000
1,240
0
341,000
22,300
45,600,000
140,000
49
0
84,600
40,700
440
1,400,000
307
279,000
Texaco, Inc. o
Leeville ^
Lafourche Parish, La.
160
1,061
153
20

1,180
2,010
0
6,600,000
1,500
0
257,000
7,320
13,000,000
18,000
0

2,120
11,600
243
401,000
108
370,000
1— 1
^6
s
(U

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salt concentrations over 8 ppt.  Produced water, which generally averages more
than 50 ppt in Louisiana can have  a major  impact on this  important marsh grass.

Salt tolerances  of 14 common species  found  in coastal Louisiana are presented
in Table 6.  Even the most salt-tolerant species are unable to withstand exposure
to salinity in excess  of 50 ppt.

Most of Louisiana's  coastal  wetlands  are subsiding  as  a result  of sediment
dewatering and compaction.   Marshes of  coastal Louisiana remain intertidal or
above sea level by vertical  marsh accretionary processes.   A large portion of
the  organic  matter produced  by marsh plants  is  fixed  in  these accretionary
processes  (9) .    Reduction  in  the  primary  productivity of  marsh  plants  by
increased salinity will  affect  carbon cycling,  which  is  important to vertical
marsh aggradation.  Reduction in the vertical  accumulation  of organic matter
results directly  in wetland deterioration and habitat change.   Disruption of
organic accretionary processes  is especially  damaging to wetlands  that do not
receive mineral sediment (13, 9).

Fresh and intermediate (slightly fresh) marsh plants fix carbon at approximately
twice the  rate  of major species of plants found  in brackish  and saline marsh
(i.e.,  Spartina sp.)   (7).    Thus,  fresh  and  intermediate  marshes are  less
vulnerable to subsidence and submergence  as  long as  they are  not  stressed by
other factors, such as increased salinity.  Studies of  marsh loss in Louisiana's
Barataria  Basin by Sasser  and  others  (19)  showed that  marsh  loss  rates  were
"highest where fresh water marshes have been subject  to salt water intrusion."

Although there have been many studies  documenting  the  effects of salt stress on
wetland vegetation, few  have  documented the direct  effects of increased salinity
on the chemical and microbial properties of wetland soils.

High salinity may reduce water absorption by clay minerals, reduce biologically
available soil water supply,  eliminate or reduce important soil  fauna and flora,
and  retard the  oxidative activity of various soil microorganisms  (18).   The
unusual ionic  components and  ratios  characteristic   of  oil  field  brines  can
directly affect the oxidation and reduction processes of wetland  soils.   For
example, increased levels of  ferrous and manganous  compounds affect the activity
of facultative anaerobic bacteria in the process of soil nitrification (2).

Discharges  of calcium  and  sodium-rich  oil  field  brines  can  contribute  to
increased  calcium and  calcium  salts  in  the  soil profile.   These  salts  are
responsible for high pH, which alters the natural oxidation/reduction potential
in the soil (2).

The  direct  impacts of brine pollution on wetland plants can  be observed over
periods ranging from a few days  to several months.  The impacts  on wetland soils
can  continue beyond the  time  required to  destroy  the  vegetation and culminate
in the "virtually permanent" damage to soils attributed to brine discharges and
spills by EPA (20) and the U.S. Fish and Wildlife Service (18).
                                      669

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                                                       TABLE 6
                          Salinity tolerances  of some  typical  plant species found in coastal
                           Louisiana,  modified from  U.S.  Department of the Interior (1978).
             Species
                            Common Name
                                Bay or marsh type           Salinity (ppm)
                               where normally found   Low        High      Average
1
Ruppia maritima

Spartina alterniflora

Distichlis spicata

Juncus roemerianus

Scirpus robustus

Spartina patens

Scirpus olneyi

Alternanthera
         philoxeroides
Phragmites communis

Vigna repens

SaEJttaria falcata

Cladium iamaicensis

Panicum hemitomon

Eichornia crassipes
Widgeon grass

Cordgrass

Saltgrass

Black rush

Salt marsh bullrush

Salt meadow cordgrass

Olney bullrush

Alligator weed

Common reed

Wild cowpea

Sythefruite arrowhead

Jamaica saw-grass

Maidencane

Water hyacinth
Brackish Hypersaline       0     45,000

Salt                   5,500     40,000

Salt/Brackish          5,000     50,000

Salt/Brackish          1,000     45,000

Brackish               6,000     39,000

Intermediate/Brackish      0     39,000       9,600

Intermediate/Brackish  5,000     17,000       9,200

Intermediate               0     15,000       1,400

Intermediate/Fresh         0     20,500

Intermediate/Fresh     2,000     12,000

Intermediate/Fresh         0      9,500       2,300

Fresh                      0      3,000

Fresh                      0      1,000         900

Fresh                      0        500

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Role of Produced Water Discharges In Wetland Loss

It  is  clear  from the  literature that  the  dominant wetland  plant species  in
Louisiana coastal marshes  are adversely impacted  by  significant  increases  in
salinity. The impacts include reduction in plant vitality,  decrease in vertical
accretion of organic  detritus,  and  deterioration  of  soil  properties  and
processes.   Intrusion of  saline Gulf waters  can produce  these  undesirable
effects, resulting in the death of marsh plants, marsh break  up,  and  increased
rates of marsh erosion by waves and currents.  Likewise,  increased salinity from
the discharge of produced water  with total  dissolved solids  3-4  times greater
than sea water can have comparable or worse effects.

Examination  of  the  locations of produced water  discharge  points  in  Louisiana
coastal marsh areas shows a correlation between large numbers of discharge points
in  the Barataria Basin and  adjacent areas with rapidly deteriorating marsh.
Receiving waters  (canals, streams,  and water  bodies)  may dilute many of  these
discharges and  others  may,  because  of their density,  sink  to  the bottom  of
receiving waters under "normal" conditions.  However,  storm waves  and  currents,
periods of low rainfall and runoff, and tides can distribute produced waters into
vegetated areas.  Depending  on the frequency of these processes,  plants can  be
killed or suffer long-term chronic  effects.  Combined  with  subsidence,   these
effects  can  accelerate natural marsh loss  rates  and initiate vegetation loss  in
more stable, healthy marshes.

Figure 3 depicts the loss of  wetlands in the Lafitte  Oil Field  in  Jefferson
Parish.  The field currently produces  about six barrels  of brine  per  barrel  of
oil.   Industry reports  indicate that  in 1986 up to 13.3 million barrels of  brine
were discharged into  surface waters in the area shown.   The average chloride
concentration  of the produced  water  in  this  field  is  73 ppt.   The average
chloride concentration of the receiving water is less than 5  ppt.   Roughly  30%
of  the wetlands within  a 6-mile radius around the field disappeared between 1956
and 1978.

There  have not  been  sufficient field studies  to quantify the role  of produced
water  in marsh loss.    The  coincidence  of  high  rates  of  marsh  loss   with
concentrations  of brine discharge points in general and  around  oil fields with
high volume  discharges of produced water in particular is,  at  a minimum, strong
circumstantial  evidence that produced waters  are a significant contributor  to
marsh  loss in coastal Louisiana.
                                     671

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Fig.   3.    Marsh  loss  in Lafitte  field.    Shaded area  shows  marshland area
            converted to open water between 1956 and 1978.
                                   672

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                               ACKNOWLEGEMENTS

      The original manuscript was typed by Paula Callais and typed in final form
by Sally Bollich.   Illustrations  were prepared under  the  supervision of John
Snead.   Drafts  were reviewed by  David Soileau and  Fred Dunham.    Syed Haque
compiled some of the  discharge  information.   The  Department  of Environmental
Quality (Lynn Wellman and Dale Givens) provided access to  the dishcarge data.
Our thanks to all of these people.
                                     673

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References
1.    Adams, R. D., Barrett, B. B., Blackmon, J. H.,  gane,  B. W.,  and Mclntire,
      W. G. ,  1976.  Barataria Basin: Geologic processes  and framework.  Louisiana
      State University, Baton  Rouge.   Sea  Grant publication LSU-T-76-006.

2.    Becking, I. R. Kaplan and D. Moore.  Limits of the natural environment in
      terms of pH and oxidation-reduction potentials.   Journal of Geology.  Vol.
      68, p. 243.

3.    Bennett,  S.  S.  and  Hanor,  J.  S.  1987.  Dynamics   of  subsurface  salt
      dissolution  at the Welsh  Dome,  Louisiana  Gulf  Coast.   In:   Dynamical
      Geology  of Salt and Related Structures.   Academic  Press,  Inc.,  New York.
      p. 653-677.

4.    Boesch,  D. F., Rabalais,  N. N.,  Milan, C. S., Henry,  C. B.,  Means,  J.  C. ,
      jambrell,  R.  P.  and Overton, E. B.  1988.   Impacts of Outer Continental
      Shelf related activities  on sensitive coastal habitats.  Volume II.  Draft
      Final  Report prepared for the  U.  S. Minerals  Management   Service,   New
      Orleans, LA.   167 p.

5.    Coleman, J.  M.  and Roberts,  H.  H.,  1989, Deltaic and coastal  wetlands.
      Geologie en Mijnfouw, 68.  1-24.

6.    Collins,  A.  G.  1975.    Geochemistry of  Oil Field Waters.    Elsevier
      Scientific  Pubishing  Company.  New York.   496 p.

7.    DeLaune, R. D.  1986.  Role of plants in  accretionary processes.  Chemical
      Geology. 59:315-370.

8.    DeLaune,  R.  D. , Smith,  C. J.,  and  Patrick, W.  H.   1986.  Sedimentation
      patterns in  a  Gulf  Coast backbarrier  marsh:    Response to  increasing
      submergence.   Earth Surface Processes and Land  Forms.  Vol.  II, p.  485-
      490.

9.    DeLaune,  R.  D. , Smith,  C.  J.,  Patrick,  W.  H. and Roberts, H.  H. 1987.
      Rejuvenated marsh and bay bottom accretion on the  rapidly subsiding coastal
      plain  of  U.  S.  Gulf Coast:    A  second-order  effect  of   the  emerging
      Atchafalaya  Delta.   Estuarine,  Coastal and Shelf Science, 25:   381-389.

10.   Gagliano,  S. M. and Van Beek,  J.  L. 1980.  Geologic and geomorphic aspects
      of deltaic  processes, Mississippi  Delta  System.   Hydrologic and Geologic
      Studies  of Coastal Louisiana, Report 1.   Center  for Wetland Resources,
      Louisiana  State University, Baton  Rouge.

11.   Hanor,  J.  S.,  Bailey, J. E., 1983.   Use  of  hydraulic head  and hydraulic
                                      674

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      gradient to characterize geopressured sediments and the  direction of fluid
      migration   in  the  Louisiana  Gulf  Coast.    Transactions,  Gulf  Coast
      Association of Geological Societies,  83:  122-155.

12.    Pezeshki,  S.  R. , DeLaune,  R.  D. and  Patrick,  W. H. 1986.  Gas exchange
      characteristics of bald cypress  (Taxodium  distichum L.):   evaluation of
      responses  to  leaf  aging,  flooding  and salinity.   Canadian  Journal of
      Forestry Research,  16:   1394-1397.

13.    Pezeshki,  S.  R., DeLaune, R. D. and Patrick, W.  H.  1987a.  Response of the
      freshwater marsh species, Panicum hemitomen Schult. , to increased salinity
      Freshwater Biology,  17:   195-200.

14.    Pezeshki,  S.  R., DeLaune, R. D. and Patrick, W. H. 1987b. Response of bald
      cypress (Taxodium distichum L. Var.) to increases  in flooding salinity in
      Louisiana's Mississippi  River Deltaic  Plain.  Wetlands. 7:   1-10.

15.    Parrondo,  R.  T., Gosselink,  J. G., and Hopkinson,  C. S.  1978.  Effects of
      salinity and  drainage on the growth of three salt marsh grasses.  Botanical
      Gazette,  139 (1):   102-107.

16.    Sasser, C. E. ,  Dozier,  M.  D. , Gosselink,  J.  G.,  and  Hill^ J.  E.  1986.
      Spatial and temporal changes in Louisiana's Barataria Basin Marshes, 1945-
      1980.  Environmental Management, 10  (5):   671-680.

17.    Seni, S. J. and Jackson, M. L. 1984.  Sedimentary record of Cretaceous and
      Tertiary  salt  movement, East  Texas Basin.   Texas  Bureau of  Economic
      Geology,  Austin. Report  of Investigations No. 139  89 p.

18.    U.S.  Fish  and  Wildlife   Service  1978.     Ecological  implications  of
      geopressured-geothermal   energy  development,   Texas-Louisiana  Region.
      Washington, D. C.   FWS/OBS-78/60.  March 1978.

19.    U.S. Environmental Protection Agency 1986.  Interim report:  wastes from
      the exploration, development and production of crude oil, natural gas and
      geothermal energy.  U. S. Environmental Protection Agency, Office of Solid
      Waste.  Washington,  D.  C. 1,262 p.

20.    U.S. Environmental Protection Agency and Louisiana Geological Survey 1987
      Saving Louisiana's coastal wetlands.   EPA   230-02-87-026,  Washington D.
      C. 102 p.

21.    S. Haque,  1989,  Personal Communication, Louisiana Geological Survey, Baton
      Rouge.

22.    Chadwick,  Dan, 1987.  Personal Communication, Large Volume Waste Section,
      U.S. Environmental Protection Agency,  Washington, D.C.
                                     675

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OIL FIELD DISPOSAL PRACTICES IN WESTERN KERN COUNTY, CALIFORNIA
S. C. Riser
Vice President, Project Development
WZI Inc.
Bakersfield, California, U.S.A.
M. J. Wilson
President, Chief Executive Officer
WZI Inc.
Bakersfield, California, U.S.A.
L. M. Bazeley
Manager, Geology
WZI Inc.
Bakersfield, California, U.S.A.
Abstract

Produced water disposal  in western Kern  County,  California, has
been by injection and  infiltration  from spreading ponds into the
unsaturated  zone,  which  is  typically hundreds  of  feet  thick.
Regional geologic and engineering studies performed in western Kern
County, California have evaluated the  movement of waste water in
the hydrogeologic environment.  The west  side of Kern County was
then ranked,  based on relative safety of ponding and/or injection
of waste water.

Criteria for ranking is defined by  hydrogeologic setting and the
physical  laws governing  fluid  flow   in vadose   and  saturated
subsurface formations.

The hydrogeologic setting  in  western Kern County is  comprised of
Pleistocene  to  Recent   sediments.     These   formations  have
traditionally  been  described  as  unconsolidated  sediments  of
continental origin  which are difficult  to  nap  as separate units in
the subsurface.   However,  within  areas  of  adequate subsurface
control, as  in the west side oil  fields, lithofacies  have been


                               677

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identified which are based on texture,  mineralogy and electric log
expression.

Fluid flow in the unsaturated zone is governed by two basic physical
laws;  that the movement of water is predominantly in the vertical
direction and that clays that have been elevated above the saturated
zone for long  periods,  as in a semi-arid or arid  environment,  do
not behave as  an  effective barrier.  Fluid flow in  the  saturated
zone is stratigraphically  controlled.

Oil operators  in western Kern County have used these studies  as a
general framework for  discussions with the agencies  on  area-wide
management practices and for future disposal planning.

Introduction

Western Kern  County  is the  location  of  many large oil  fields
(fig. 1) .   The California Water Quality Control Board Plan for the
Lower  West  Side  Kern  County  (1) , contains  strict guidelines
regarding locations which may be permitted for oil  field  sumps and
the qualities of waste water which may  be  contained therein and/or
discharged   therefrom.      An  amendment   to   the   Basin   Plan
(October 22, 1982)  relaxed  the  restrictions  somewhat  on  the
stipulation that it has been demonstrated  that the  "discharge  will
not substantially affect water quality nor cause  a violation  of
water quality  objectives".

Many geologists  (2)  have interpreted that subsurface inflow  from
the west side  of  the Valley provides up to 200,000  acre-feet per
year of recharge and degradation  of groundwater conditions.   This
interpretation has its basis in the inappropriate incorporation  of
water level and water quality data in a computer model which assumes
a continuous aquifer.

Because of  the possibility of  groundwater  degradation,  a  better
understanding  of the disposition  of waste water was needed.  The
Pleistocene to Recent sediments contain useable groundwater and  in
other  areas  they are  used  as  water  disposal  zones.   One  must
understand how these sediments were deposited in order to  provide
the necessary geotechnical framework for the proper  management  of
the groundwater resources  in the  San Joaquin Valley.

Historical Background of Waste Water Disposal

According to the California State Department, Division of  Oil and
Gas records, the Midway Sunset Oil Field was discovered  in "about
1890".   The requirements to add parentheses to the discovery  date
says a lot about the adequacy of historical records regarding  this
important natural resource.
                               678

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The first recorded water production  in the Midway Sunset field was
in 1901 and in 1915 in the Buena Vista Field.  In 1910, the famous
Lakeview Gusher made so much oil that a  dam was built in Section
34, T.32S., R.24E., not only to attempt to save  as much of the oil
as possible,  but also to prevent its  flowing  into, and damaging the
Buena Vista Lake Basin.  This catch basin was  to  be the first of
many such sites which were later used to trap oil,  and aid in the
percolation of waste water which had been discharged into natural
drains in the area.

The bulk of the early oil production was  of a low API gravity which
was commonly accompanied by  a substantial "cut"  of formation sand.
The universal method of dealing with this problem and cleaning up
the oil  in preparation  for  shipment to  sales,  was  to produce the
mixture into an earthen pit or sump.  There, the  sand settled to
the bottom and the oil was skimmed off the top.  This method also
had the fortuitous advantage of allowing the  water to percolate out
the bottom.  Thus,  every operator and every property had its own
water disposal system, which served until it  finally filled up with
sand, and/or plugged up with silt.  This was rectified by cleaning
out the sump, or by abandoning it in place and digging a new one.
When viewed from  the air,  it is readily apparent that the entire
field,  particularly the Maricopa area,  is  honeycombed  with old
sumps which are no longer in use.   When water quantities exceeded
the percolation capacity of the sump,  the excess was siphoned off
and discharged into the nearest  natural drain.  This  method was
prevalent  until  well into  the  1930's  when better  sand  control
methods started being utilized and  the  tank and boiler method of
treating gained general acceptance.

In  addition  to  Lakeview,   numerous  other  catch  basins  were
constructed, usually on a cooperative basis by several operators.
The major ones were the Midway Basin, which  stretched for a length
of about two  miles near the terminus  of Buena Vista Creek just east
of Valley Acres,  and the Sunset Basin,  which was  on Sandy Creek,
just off the extreme southeast end of the Buena Vista Hills.  Around
1931, after a particularly bad storm which washed out the dams at
many of the basins, the operators decided that they no longer wanted
to maintain the basins  on  an informal basis.   A  cooperative was
formed which became the Valley Waste Disposal Company.  Some time
during  the  1930's,  Valley  Waste constructed several additional,
major percolation and evaporation facilities.

By the early 1950's increasing water quantities were not only taxing
existing facilities to  the  limit,  but also their  locations were
such as  not to afford adequate protection against eventual migration
of percolated waters into the Buena Vista Lake Basin.   In 1953 a
study of the systems determined the origins and  destinations of the
various sources of  produced water  in the area.  The Rickett and
                              679

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Reaves report  (3)  proved invaluable in helping to fill  the great
void of factual data and information up the middle of the century.
This report  also served as the basis  for locating sites  for the
facilities which now comprise the bulk  of  the Valley Waste system
in the Midway Valley.

In the Midway  Sunset and Buena Vista  Oil Fields, the  cumulative
gross water production associated with the withdrawal of oil through
1986 was 3,178,000,000 barrels (4).   The disposal of  that water is
by  injection,   treatment  and  re-injection,   percolation,   and
evaporation.  Percolation from surface  impoundments is responsible
for 2,328,000,000  or 73%  of the historical  total  (4).

Geology

The  Pleistocene to  Recent sediments   in  San  Joaquin  Valley  of
California comprise  the non-marine fill of the  basin.   Page  (5)
summarized and described the  lithologies  of the Pleistocene  to
Recent  sediments.    Page also  recognized  the  same   depositional
environments identified by Lennon  (6) , but did  not discuss  the
criteria for recognition of lithofacies in 'the subsurface.   Lettis
(8) also  described the  different depositional  environments in a
regional  framework in  northern  San Joaquin Valley, subdividing
lithofacies by composition and texture.

In different regions of the basin  the  sediments have been given
different formation names.  In western  Kern County, the  units  are
referred to  as Tulare Formation and Alluvium.   Detailed  studies
done  for  Valley  Waste  Disposal  Company (4)  documented   the
stratigraphic  relationships  of the Pleistocene  to  Recent units
south of Elk Hills.  One cross  section from that effort is presented
in fig. 2.

The Alluvium mapped  by Dibblee (9, 10, 11) widely conforms with
work done all along the  west side (12, 13) .  In the subsurface this
unit can be traced easterly towards Buena Vista  Lake.  It includes
the fresh  water aquifer and an interval identified  as  Tulare  by
Frink and Kues  (14),  in their "type description" of  the Corcoran
Clay, subsequently widely adopted in groundwater studies of the  San
Joaquin Valley.  However, Frink and Kues did not  correlate back to
the surface,  thus setting the  stage for decades  of water resources
work  which does not recognize the mappable delineation in  the
surface and  subsurface  between the aquifer containing  the fresh
groundwater sources in the San Joaquin Valley and other Pleistocene
rocks.

The Tulare and  Alluvium can be subdivided  into  lithofacies based
on well log responses and petrographic  data. Figure  3 illustrates
the typical  well  log  in the Midway  Sunset and  Buena  Vista  Oil
                              680

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Fields, where:  (1) the Alluvium is predominantly silty to clayey
alluvial fan/alluvial plain;  (2)  the Upper Tulare is dominantly
sandy alluvial fan/alluvial plain  with some deltaic lithofacies;
and (3)  the Lower Tulare is lacustrine to deltaic.  In other areas,
the Alluvium,  Upper Tulare  and Lower Tulare do not necessarily have
these same lithofacies.  The  typical  well log characteristics of
the various lithofacies are dependent upon what is filling the pore
space  (air, fresh  water,  salt water,  or  oil).   By utilizing the
density/neutron log in combination  with the resistivities and core
information the lithology  can be determined.   When air is in the
pore space (due to the "gas effect") the apparent neutron porosity
is much lower than the apparent  density  porosity,  resulting in a
"cross-over" of these two porosity curves.  However, when the sands
are fluid-saturated,  the density and neutron porosities tend to have
similar apparent porosities.   Fresh water and  oil/tar sands are
highly resistive, whereas saline water sands have low resistivities.
Because of this, the resistivity contrast between moisture-deficient
sands and saline water sands,  coupled with neutron/density log gas
effects allows  for an accurate determination of the  water table
elevation.  Examples of this determination are shown in the Lower
Tulare portion of fig.  3, and on cross section A-A1 (fig.  2).

There  are a  number  of obvious  factors to  keep  in  mind  when
discussing paleogeography of the Pleistocene to Recent.

1.   Structures influenced depositional patterns.
2.   The systematic unroofing of pre-Pleistocene rocks of the rising
     Temblor Range resulted in areal differences in texture.
3.   The sedimentation rate has generally exceeded the subsidence
     rate  resulting  in  almost  complete  progradation of  Recent
     alluvial deposits over the Pleistocene lake.

The proximity of the rising Temblor Ranges to the axial trough of
the valley restricted the alluvial  fan/plain deposits of the Lower
Tulare to a narrow band on  the west side.  During the emergence of
the Temblors  in the  Pleistocene,  there  were  several cycles  of
lacustrine transgression and regression.   The  approximate extent
of four of these lacustrine transgression in the southwestern San
Joaquin Valley is  shown in fig.  4.

The alluvial fan/alluvial plain deposits are characterized by poorly
sorted sheet flow  deposits which have been eroded and reworked by
streams.  The  Alluvial  fan/alluvial plain  deposits encroached upon
the lake as shown  on the block diagram of Midway Valley in fig. 5
during Mid-Tulare and the Present.  The deltaic sands are shoreline
deposits fed by fluvial systems which interfinger with lacustrine
silt and clay basinward.
                              681

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The  present day  basin  is characterized  by  extensive  alluvial
fan/alluvial plain deposits which have completely encroached upon
the  lacustrine  deposits.   The texture  of the  Recent  sediments
directly corresponds  to the texture  of  the adjacent  outcropping
formation as shown by the  generalized texture map of  the surface
Alluvium (fig. 6) .  For example, the distribution of clayey alluvial
fan deposits in  the  alluvium are adjacent  to the Monterey  shale
outcrop and sand alluvial  fan  deposits are adjacent to  the  Point
of Rocks sandstone.

Ranking of West Side Kern County for Relative Ponding  Safety

The Ponding Categories which  can be used to  rank west  side  Kern
County are defined by hydrogeologic setting and the physical  laws
governing fluid flow in vadose  and saturated subsurface formation,
schematically summarized in fig. 7 and are described as  follows:

     Category I ponding areas  are  characterized by the  existence
of  Tulare  outcrop  exposure and/or  topographic  and   sedimentary
depressions which channel  ponded water deep into the  unsaturated
Tulare Formation.

     Category II ponding areas are the most dependent  on physical
fluid  flow  in  the  vadose  and  saturated  zones.     They  are
characterized by moisture-deficient alluvium over unsaturated Tulare
where monitoring  may prove valuable  for future  continuation of
current practices.

     Category III ponding areas are characterized by the  existence
of fluid saturated Tulare overlain by moisture-deficient  alluvium.
In these areas water may eventually find a pathway to  the western
central valley within the assumptions made in this report.

Applications

The ability to  subdivide and the recognition of the lithofacies in
the Tulare  and the Alluvium has important applications in  petroleum
exploration and reservoir evaluation;  waste disposal and regulatory
compliance;  and water resources management practices.

1.   As described by Lennon (5), commercial  steam  soak  projects in
     the Tulare are restricted to the deltaic lithofacies.   Steam
     soak  projects  in  the  other  lithofacies  have  not   been
     successful.
2.   The Alluvium  and  Tulare  is commonly  used for  waste water
     disposal,  therefore  the  relationship  between waste water
     disposal units  and units containing drinking  water must be
     understood.
                               682

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3.   Also,   from  the  standpoint  of  managing  the  groundwater
     resources,  the proper geologic  framework in which to evaluate
     water  use  is  necessary  to properly identify sources  of
     recharge,  overdraft and pollution.

References

1.   California State Water Resources Board, Central Valley Region
     (5) ,  Water  Quality Control Plan Report Tulare Lake Basin (5D),
     1975.

2.   Kern County Water Agency Water Annual Report 1986,  May 1987,
     66p.

3.   Rickett, W. and Reaves, J.,  Midway Sunset District Report of
     Oil Field Waste Water Products, Quality and Disposal;  Summer
     and Fall of 1953, prepared for Valley Waste Disposal Company,
     1954, 64p.

4.   Wilson, M. J., S. C.  Kiser, R. N.  Crozier,  E.  J.  Greenwood,
     Hydrogeology and Disposal of Oil Field Waste Water,  Southwest
     Kern  County,  Phase  1:   report  prepared  for  Valley  Waste
     Disposal Company, 1988.

5.   Page, R. W., Geology of the Fresh Groundwater  Basin  of  the
     Central Valley,  California, Regional Aquifer-System Analysis,
     United States  Geological  Survey Professional  Paper 1401-6,
     1986, 54p.

6.   Lennon, R.  B., Geological Factors  in  Steam-Soak Projects on
     the West side of the San Joaguin Basin,  in Journal of Petroleum
     Technology, Vol. XXVIII, 1976,  p.  741-748.

7.   Lettis, W.  R., Late Cenozoic Stratigraphy and Structure of the
     Western Margin of the Central San Joaquin Valley, California,
     United States Geological Survey Open-File Report 82-526, 1982,
     203 p.

8.   Lettis, W.  R.,  Quaternary Geology of the Northern San Joaquin
     Valley.  in Studies of the  Geology of the San Joaguin Basin,
     Pacific Section SEPM, Book  60,  1988,  p.  333-351.

9.   Dibblee, T. W., Jr.,  Geologic Map of the "Maricopa" Quadrangle,
     California, U.S.G.S., 1942-1950.

10.   Dibblee,  T. W. , Jr., Geologic Map  of  the  "Taft" Quadrangle,
     California, U.S.G.S, 1966-1967.
                              683

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11.  Dibblee, T.  W., Jr., Geologic Map of the "Fellows" Quadrangle,
     California,  U.S.G.S., 1971.

12.  Woodring, W. P., R.  Stewart,  and R. W. Richards, Geology  of
     the  Kettleman  Hills  Oil  Field,  California,  United  States
     Geological Survey Professional Paper 195, 1940,  170  p.

13.  Maher, J. C., R. D. Carter, and R. J. Lantz,  Petroleum Geology
     of Naval  Petroleum Reserve No.  1,  Elk  Hills,  Kern  County,
     California,  United States Geological Survey Professional Paper
     912,  1975, 109 p.

14.  Frink, J. W.,  and Kues, H. A., Corcoran Clay - A  Pleistocene
     Lacustrine Deposit in the San Joaquin Valley, California in:
     American Association of Petroleum Geologists, 1954, Volume 38,
     p. 2, 357-2, 371.
                              684

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Figure 1 :  Oil Field Location Map
                                                     Figure 2 : Regional Cross Section A - A
                                         685

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      Figure 3 :  Type Log
                           I "
Ł>I—..
                                                   Figure 6 : G«n«rml2*d l«im™ map ol th« turt«ca AAuvunv
                                                      B
                   Flgufe 4 & 5 : Lacustrine distribution:
                               A) Corcoran Clay and Upper Tulare
                               B) Intermediate Tulare Clay Zone and Lower Tulare
                                             686

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s
                           PONDING
                         CATEGORY
                                                                                                     PONDING
                                                                                                   CATEGORY  3
  PONDING
CATEGORY  2
            INJECTION

             WtL1>ONO A
                 I   I   MOISTURE DEFICIENT  SEDIMENTS


                 ^•b.   TULARE TAR ' OIL DEPOSIT
                 nn
             ow   v   V
               UOCCIUtE
PERCOLATION PATH OF PONOEO
WATER (SIZE OF ARROW CORRESPONDS
TO HTORAULIC CONDUCTIVITY)
                          CLA» LAYER ICREY)
                          MOISTURE  • DEFICIENT EQUIVALENT OF
                          CLAY (UNCOLOREO. DASHED) WHERE
                          LAYER DOES NOT  ACT AS BARRIER
                                                                                                                                  Figure 7 :  Percolation Model

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OIL WASTE ROAD  APPLICATION PRACTICES AT THE ESSO
RESOURCES CANADA LTD., COLD LAKE PRODUCTION PROJECT
Alan J.  Kennedy,  P. Biol., Environmental Affairs  Manager,
Lancecelot L. Holland, P. Eng., Project Engineer, and
David H.  Price, District Maintenance  Planner

Esso Resources Canada Ltd.
Amisk  Headquarters
Service  No.  15
Grand  Centre,  Alberta, Canada
TO A 1TO
Abstact

Esso  Resources  Canada Ltd. operates  the Cold  Lake Production Troject,
which produces  approximately 14,000  m^  per day of bitumen  (heavy  oil)
through cyclic  steam stimulation  technology. The  Cold Lake Production
Project  is located 300 kms. north-east of Edmonton in Alberta,  Canada.
During  the  process  of bitumen production  about 6000 m^  of oil sand waste
per year is  also  produced.  The majority  of  this waste material can  be
characterized as  a liquid  sludge consisting of bitumen, fine sand and  water.
The  waste by-product is  collected from  plant  vessels, tank bottoms,  and
through surface lease cleanup activities.  The  oil  waste by-products are
then stored  in  self contained pits on  site. When inventory  builds in the pits
material is  selectively removed  and  prepared  for  road  surfacing.

The  Alberta Energy  Resources Conservation  Board (ERCB)  states in
information  letter IL 85-16 that  road application  as  a disposal  technique
for oily wastes is not a long term solution. As  a result of this position the
ERCB  has  initiated a process  to formulate acceptable practices   for the
disposal of  oil  wastes  on  roads  through  a  joint  industry/government  task
force on oil waste disposal. The  task force  has identified road application  of
oil  wastes as a  high priority topic in need of further  discussion.
                                 689

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The  Cold Lake Production  Project has  developed   procedures to prepare oil
waste for road  surfacing  and then apply  it to major access roads within the
project  area  to  make  a solid  all weather  road  surface. The  purpose of   this
paper is  to describe the characteristics of the oil  waste material,  the
methods for preparing the  material for road  surfacing   and  the application
of the material  to form the  road  surface. Further,   data on the  chemical and
physical properties  of the  material   are reviewed  from an  environmental
perspective  and  comments  are  given on the  need  for  environmental
management procedures  in  the application of road surfacing materials.
Conclusions  are  offered  on the advantages  of this  procedure for road
building.

Introduction

Oil  wastes  are  an  unavoidable  by-product of  oil sand  development and
production operations.  In  the early  stages  of  heavy  oil and  oil  sands
operations in Alberta methods for collection,  storage and disposal of oily
waste  material  were  ad-hoc  and  not applied  consistently  throughout the
industry.  This led  to  problems from an  environmental  perspective in  that
wastes  became  difficult  to  manage in  terms  of  their distribution  and
potential  toxicity.  Additionally, a  potential health  hazard to  workers exists
with  indiscriminate oil waste  storage procedures.   Further, disposal
methods such  as improper  road oiling  were  potentially unsafe  for motor
vehicle  operators.

The  Alberta Energy Resources Conservation Board  (ERCB)  recognized the
potential  difficulties with  oily  wastes  and  published an information  letter
(IL  85-16)  to all oil  sand operators  giving  guidelines to the  storage,
handling, and disposal of oily wastes (1). These guidelines  gave the  first
credibility to the option  of disposing of oily  wastes through  application of
the  oily waste  material on  a municipal road.  The  information letter was
clear  in stipulating what types of roads were suitable  for  surfacing  with
oil  waste in that no private roads could  be  surfaced and only under  special
situations would lease roads be allowed to be surfaced. The  guidelines also
specified  the  chemical parameters of concern  to  the  ERCB  and that the
operator must quantify these parameters  prior to  using the  road disposal
option.  A format  for application to the  ERCB for a oil  waste management
program was also provided at this  time.  Since 1985 however, still more
questions have  risen over the  road oil  disposal  method. In  May,  1988  the
ERCB issued a letter (2)  from the chairman  to all  oil sands operators stating
that  road oil application would in the future  be limited to  situations  in

                                   690

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 which the "operator  can satisfy the ERCB that no alternate clean up or
 disposal  technique  are available".

  The most appropriate application techniques for what  has come to be
 termed  road  oiling  remain elusive and  inappropriate methods  are  still
 problematic  from  an environmental  impact  stand  point. The most  recent
 initiative  (1989) in the road oiling area  is a task  force of  government,
 (ERCB, Alberta Environment)  petroleum industry, and  researchers  (Alberta
 Research Council)  to  investigate  the  most  appropriate and environmentally
 sound road oiling  procedures.  The initial findings  of  this task force indicate
 that  there  are  three  major considerations  that  require clarification  in the
 development  of appropriate  road  oiling  technology. These  include;  proper
 characterization  of  the oily  waste material  prior to use,  appropriate road
 surfacing  procedures,  and  environmental protection plans  for  surface
 roads.

 Esso Resources  Canada Ltd. (Esso) has been involved  with road oiling  at its
 Cold Lake Oil  Sands Production Project  for  more than a decade  and  has
 during  that  time developed techniques for applying   oil waste  to roads  that
 are  pertinent to each  of these road  oiling information needs.   The  purpose
 of this paper is to  describe the work done on road  oil application at Esso
 with particular attention to waste characterization,  application  of oil  to
 road surfaces,  and the environmental  implications of road  oiling.

 The  Cold Lake  Production  Project

 The  Cold Lake Production Project (CLPP) is located in  north - east  Alberta,
 Canada near the  Saskatchewan border,  approximately  300 kms north-east
 of Edmonton, the  capital city  of Alberta. Experimentation  and pilot
 operations have been  occurred  at  Cold Lake since  the  mid 1960's,  however
 it was  not until the late 1970's  that the  Cold Lake Project  was envisaged as
 an oil  sands  mega-project.  An  application was made to the ERCB for the
~mega-project in 1979  and  it  was subsequently  approved in  1980.
 However, changes to  the Canadian and  world energy markets  in the  first
 part  of the  1980's forced  a new  development strategy  for  the project. That
 is, certain aspects of  the mega-project were discarded and  the  project  was
 initiated  on  a phased  development planning  basis.  In 1983 the CLPP
 construction was initiated  and to  date six "phases" have been  completed
 and are operating.  Each "phase" is to tap into specific portions of the oil-
 bearing sands within  the original ERCB approved  mega-project
 development  area. Currently the  CLPP is  producing  14,000 m3  per day  of
                                 691

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bitumen production  that  reports  to markets mainly in  the  north-eastern
United  States.
Oil Waste  Characterization

During  the process of bitumen  production   about 16m3 per  day or 6,000
m3 per year of oil  waste is  generated. The  oily wastes  at CLPP come from
two  sources,  as a  by-product  of bitumen  production from  the reservoir,
and from  surface lease clean-up activities. The majority of the oil waste is
recovered  from  storage  tanks  and plant process  vessels and has  the
general characteristics  of a  liquid  sludge consisting  of bitumen,  fine sand
and  water.

Oil waste  by-products  are stored on site in  self  contained  cement lined pits.
When  inventory of none recyclable  oil  wastes builds during  the  summer
months, the material  is  selectively  removed from the pits  for  road
surfacing.  The  oil waste  material is  first characterized  for  its  chemical
constituents.  The samples  for chemistry analysis  are  taken at each oil
waste  pit.  The  sampling  is  unique in  that  the  waste pits themselves
comprised  of two  sub-pits,  one for liquid phase waste and  one for solid
phase.  The solids pit is  above grade in  comparison to the  liquid  pit and
heat is applied to both pits  to encourage liquids  movement to  the lower  pit.
Liquids are  then recycled through the plant facilities.   Grab samples are
taken  on a grid across  both pits and  averaged to obtain a representative
value.

The  typical chemistry of Cold  Lake oily  waste is  given  in Table 1. The
nature  of  the  material can be  summarized  as a  viscose hydrocarbon
material mixed with varying,  but  small, amounts  of organic and  mineral
debris.  The  environmental implications of the content  of metals and
organic chemicals  is discussed later  in this  paper.
                                  692

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Table  1.  Chemical characterization  of Cold Lake  oil wastes used in road
         application.
Parameter                                 Value
                                           (yearly  average)
Physical  Properties

Oil(%)                                       13.0
Liquid (%)                                     7.5
Solid (%)                                     79.5
Inorganic Chemicals (PPM)

Chlorides                                      780
pH
                                              6.9
Metals

Boron                                         0.01
Cadmium                                      0.001
Chromium                                     0.066
Mercury                                      0.0001
Manganese                                    0.03
Lead                                         0.05
Vanadium                                     0.05
Nickel                                         0.008

Organic Chemicals (PPM)

Phenols                                       0.035
                             693

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Road Application  Techniques

Material  Preparation

The  first step in road  application is to prepare  the  road surfacing  materials
properly.  Initially  all the  free  bitumen  and water  mixture in  the  oil  waste
ponds is  skimmed off and  pumped out  of  the  pit.  Steam coils  have been
installed in the  oily waste pits  to increase heat  circulation and enhance  the
separation of components  in  the oil  waste matrix.  The steam  and  hot water
also  make the  material  less  viscose, decrease  chloride content and assists
in adhesion of  the  oil waste  road surfacing material. Removal  of the  fluid
phase of the  oil waste  is  now  possible using  permanently  installed pumps
and  vacuum trucks.  As  mentioned previously,  it  is  also possible  to recycle
the liquids  through the  plant facilities  and add to  oil  production  levels. The
remaining  oil waste  mixture is tested   for  its  chemical composition  and if
the material is  within regulatory specifications  it is ready  to  be used  in  the
road surfacing  process.  Gravel  is  also  included in  the  road surface  material
mix. Gravel  is  brought to the oily waste pits from borrow areas on  the site
and  is  then mixed with  the oil  waste in the pit.  The desired  composition
depends on the  type of  road  bed  and specific  quality of the oil waste, but
from  previous experience a 1:1  mixing ratio  of oily  waste to gravel has
proven  most  successful.  The  oil sand  road material is  now  ready for
placement. Using a front end  loader  it is  lifted onto trucks  and hauled to
the road  construction  work site.

Road Surfacing

The  second stage in the oil waste application is the "working in"  of the
material into  the road-way. Wind-rows  are made on  the road  surface by
blading loose road  bed  material into the center of the  road  and adding
available  gravel. It is  desirable  to avoid including topsoil, vegetation,  or
clay  soil  into
the wind-row as these materials negatively affect  the  integrity of  the road.
It is also important  to avoid ripping the road  bed  with  the  grader  blades as
this  action  will  liberate  subsurface clay from the road  bed and also have a
negative  affect   the integrity  of the road-way.  Parallel wind-rows  are then
                                  694

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completed  using these techniques  that in essence  form  a trench between
the wind-rows.

When the oil waste material arrives  from the pits  it is placed in the trench.
The actual application rate  will depend on  the  road bed  size  and oil/gravel
characteristics.  We have  found that a rate of 250 m3  of  oil waste mixture
per km  of road has been effective  at CLPP  to provide  about 0.05 m  of
elevation  to  a  9m wide  road. Immediately after  applying  the oily  sand   the
mixture should  be graded and dried.  The amount  of drying depends  on the
initial water  content of the material and  the weather  conditions at the time
of application. Grading and mixing takes place  directly behind the
unloading  truck. The  grader then  moves  the windrows together until  both
have been combined into a  large single row.  Then  the row  is  rolled  across
the road  a number of times to  ensure that  a consistent mixture is  obtained
and all  excess moisture  is removed. Attention is then  paid  to ensuring  that
the mixture  is dried  while  maintaining  the  proper  consistency.  This  is
achieved  most easily  in dry  weather conditions and  with experienced
equipment operators.  If the mixture  does become  wet from  rain  it may
take a number of  days to complete the rolling  and mixing  process.

It is critical  to pack  immediately  following  the  grader leveling. For the best
results we have  found that  packing  should  be  continuous for  several days
between  the  oily  waste lifts.  It  is  also important to ensure  that sufficient
packing  occurs  at  the road  edges.  Further compaction  is  then accomplished
with a grader  placing  it's blade almost horizontal to the  road  surface and
driving  over  the road causing surface compression.    The final  stage of
packing  consists of using a smooth  drum vibrating packer to  complete  the
road-way.

Quality Control

The finished road  will be all  weather and have a  smooth, well compacted
surface  able  to  with stand  traffic and heavy  loads.  The road surface is
raised to  form a "crown" to ensure that runoff is possible. Ditch lines are
cleaned after the  road is completed to remove debris and excess oil waste.
Roads  built to these criteria should last for  a minimum of two  years of
normal  use  without  maintenance.
                                  695

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Table 2.     Oily  waste  road  application  troubleshooting  chart.
Road  criteria

Mixture  Quality
Description

Good  mixture
                        Too  much  bitumen
                        Not  enough  oil
                        (mixture too  dry)
                        Mixture  too  damp
Compaction
Good  compaction
                        Insufficient   compaction
Indicators

- does not stick  to tires  or  boots

- no  runoff  or  leaching  to
  landscape
- even, dry, consistent  road
  surface

- will puddle
  will flow into  ditch
- appears  slick  and shiny
  will stick to surface of  boots &
  tires
- does not roll off grader blades
  evenly  or  smoothly
  grader  and mixers  loose  traction
- vehicles will  deform  road surface

- coloration  of road  surface mixture
  not   consistent
- mixture not a  dark color  (brown,
  not  black)
- patches of dry dusty  sand or gravel

- no  cohesion  of mixture
  leaching takes  place
  road surface  will  break down
  readily
- mixture is  dark in color

  road  surface  hard,  packed
  tightly
  consistent  color
- no  loose  material  or  free  standing
  liquid
- no  indents  left in road after vehicle
  traffic  passage
- should not be  able to  grind boot heel
  into  surface

- road edges break  after a short
  period  of use
- heavy  vehicles deform road surface
  outwards
- loose mixture  on   road  surface
- ripples  develop on road  surface
                                      696

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Following several years of experience  using  oily  waste as a road  building
material  Esso personnel have developed  a list of common  problems  to
recognize in  preparing a sound  road-way.  Table  2  provides this list  as  a
summary  of  points  to aid in troubleshooting oil  waste road construction
projects.

Environmental  Considerations

From  an environmental perspective,  there  are three  important components
to the road application  of oil wastes.   These include; consideration  of
hazardous chemicals in the oil  waste, proper  application  procedures  of  the
road  oiling material,  and protection of the  environment from  run-off from
oiled road-ways. The following discussion provides  some insight into each
of these areas based  on experience with  road application practices at the
Cold Lake Production  Project.

In order  to  avoid  the release of hazardous  chemicals  into  the environment
it is  important to ensure that the oil  waste is  analyzed for  its-chemical
constituents.  At Cold Lake samples are taken  from  the oil  waste pits  before
each  road oiling program  is  initiated  and because  we  understand  the
nature of the  materials from previous experience  the  samples  are  closely
scrutinized for pH,  chlorides  and phenols. We  require a Ph  from 6.9 to 7.2,
a chloride content  of under  1000  ppm and  phenols  under 0.005. If these
chemicals  are  within this  acceptable  range  then  the road surfacing material
is released to  be  used  in the road  application program. It should be  noted
that  at Cold  Lake  we  have observed a large variability in  the  results  of the
chemical  analyses from the  oil  waste  pit. This can  be  problematic  to  the
road  oiling program as there may  be  delays caused by inconsistent
analyses.  Experience has  shown  that most often the reason for  the
variation  in  data is  due tp the  difficulty in obtaining  a representative
sample at the oil  waste pit. The major difficulty in  sampling the pits  is
finding the most appropriate  depth in  the pit  and obtaining a
representative sample of both the solid  and  liquid  phase  waste material.
The  joint industry  and government task  force mentioned  previously  is
currently  looking  into the  sampling problem  and  has  devised  an initial
sampling  guidelines  for the  petroleum  industry  that may  alleviate this
problem.
                                 697

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A  second environmental concern relating to road oiling  oil wastes involves
the assurance  that the oil  waste on the road-way is an  acceptable, non-
hazardous material and  will not contribute to a pollution incident.  As a
means  to understand  the chemistry of the road material  used  at Cold Lake,
four core samples of a completed road-way  were taken, batched  and
analyzed for  major chemical constituents.   A similar  sample of asphalt  was
also taken for comparative purposes. The results of the analyses are  shown
in  Table 3.

Table 3.   Comparative chemical analyses  of  oil waste  road  material from
           Cold  Lake.
Parameter        Oil Waste          Asphalt
                    (ppm)            (ppm)
Arsenic             0.04              0.10
Boron              0.1               0.38
Cadmium           0.001             0.01
Chromium          0.6               0.16
Lead               0.057             0.63
Zinc                0.14              0.99
Mercury            0.0001            0.0001
Selenium           0.0017            0.0002
Barium             0.55              2.80
Copper          ~  0.06              0.36

Phenol             0.035             0.024
The  data  suggest  that the levels of the parameters measured  were at most
often lower in  the oil waste samples than  in  the Asphalt samples.  The pH
of both asphalt and  oil waste samples averaged 7.2 at which point most of
these metals  are not  mobile (3).  The phenol content  in  the oil waste  sample
                                698

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was recorded  at a  slightly  higher  level than the asphalt indicating a
liberation  of these materials  in that  particular sample.
These types of tests  are  important  to  preform  in oil  waste road disposal
programs  as  they  provide  a  basis  for  evaluating  the  environmental  impact
of the program.

An important  environmental concern  regarding  road  oiling  is that of run-
off contamination  of  soils caused from road oiling programs.  The
environmental  impact  of  oil to soil is  well  understood and documented
from  a  physical and  chemical perspective  (4,5,6,).  Briefly  stated,  the
hydrocarbon component,  if in a sufficient quantity can impact  the
microbiological populations in the  soils and  also alter the  chemical  balance
of the soil matrix.'Further, if  chemicals reach  high enough levels, toxicity to
vegetation may occur.

Samples have  been taken  from the ditch surrounding the  road-way
following  road application at  Cold  lake. The samples consisted of  cores  and
were  batched  and analyzed for the chemical make-up. The results of the
analysis is provided in Table 4.

Table 4.    Results of  soil  samples adjacent to oil waste road-ways
Parameter                                    Value (mg/kg)
pH                                              8.2

Chlorides                                       42.67
N03                                            39.67
S04                                            41.00

Mg                                             38.33
CA                                            103.67
NA                                             81.00
K                                              11.33

SAR                                             1.73
*Average of three grab samples
                                 699

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Parameters  of  particular concern  are those that could  affect the  nutrient
exchange  capacity  of the soil  such as essential nutrient levels and sodicity
(SAR).  Additionally,  salt build-up that  may contribute  to  potential toxicity
is  very important and is measured by chloride  content.  The results  of
these  samples show clearly  that  following careful road application
techniques there is  no evidence of elevated levels of the  chemical
parameters.

As a final  point on environmental considerations  in  road  oil application,
special    environmental needs  arise  when  application  procedures  are
carried  out in  wet  conditions. Precautions  to  protect  sensitive areas such  as
water  courses   from excessive run-off are required.  Wind-rows are
doubled,  and placed at the  high  side of the road  bed  to prevent water from
running off. If run-off accumulates it will  require collection and  removal
with  a  vacuum truck.  During these conditions at Cold Lake  constant
observation and monitoring  for a  "no sheen" ( no oil)  run-off is  carried out.

Conclusion

Experience  and experimentation at   Cold Lake  have resulted in  the
development of  an oil waste road application technology  that provides  a
cost  effective,  environmentally sound solution to  a waste  disposal problem.
Roads surfaced with oil  waste at  Cold Lake are high  quality, all weather
roads  capable  of handling  traffic  exceeding 400 vehicles per day  and loads
up to 35 tonnes.

References  Cited

1.     Energy  Resources Conservation Board.  1985. Storage, handling and
      disposal  of oily  wastes. Information letter  il-85-16. ERCB   Calgary,
      Alberta,   Canada.
2.    Energy  Resources Conservation  Board. 1988. Oily sand disposal.
      Letter to heavy oil and oil  sands operators. ERCB Calgary,  Alberta,
      Canada.
3.    Williamson. N.A. M.S. Johnson  and A.D. Bradshaw. 1980.  Mine  wastes
      reclamation.  Mining  Journal Books. London, England.
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4.     Godwin, R., and Z. Abouguendia.  1988 Potential  effects  of  oily waste
      disposal on  the terrestrial environment-an overview. SRC Publ. NO. E-
      902-8-E-88.
5.     Anonymous.  1983.  Sask./Alberta  waste disposal  guidelines.
      Saskatchewan/Alberta Oil Cooperative. Calgary,  Alberta,  Canada.
6.     Danielson, R. and N. Okazawa.  1988. Disposal of oil field wastes by
      land  treatment: effects  on  the  environment  and  implications for
      future  land  use.  Canadian  Petroleum  Association/Environment
      Canada. Calgary,  Alberta, Canada.
Acknowledgements

The  authors thank Esso  Resources for logistical support in conducting this
work. Ms. A. Paradis assisted in typing the  manuscript.
                                701

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                   ONSHORE SOLID WASTE MANAGEMENT IN
                 EXPLORATION AND PRODUCTION OPERATIONS
Introduction
The American Petroleum Institute (API) initiated a project  in  1988  to
develop environmental guidelines for management of solid waste in oil
and gas exploration and production (E&P) operations.

As a result of this effort, API published its Environmental Guidance
Document in January, 1989.

The document provides guidance for management of drilling fluids,
produced waters,  and other wastes associated with E&P primary  field
operations:

     1)  gas plants,
     2)  field facilities,
     3)  drilling,  and
     4)  workovers.

The following paper describes the content and recommendations  con-
tained in the API document and its use as a tool for environmentally
sound management of exploration and production wastes.  Also included
is information on how the document is being used and can be used for
environmental training within the oil and gas industry.


Background

The federal government's increasing interest in potential environ-
mental and human health impacts associated with exploration and
production of crude oil and natural gas arose from a two-year  study
of E&P waste and their associated waste management practices by the
Environmental Protection Agency (EPA) in 1986 and 1987.  The results
of that study were documented in a December 1987 Report to Congress,
which was required by the 1980 amendments to the federal Resource
Conservation and Recovery Act (RCRA)  which requires EPA to regulate
the management of solid waste.  Based on findings of its Report to
Congress, oral testimony and written comments received during  public
hearings in the spring and summer of 1988, EPA, on June 30, 1988,
decided not to recommend to Congress federal regulation of E&P wastes
as hazardous wastes under Subtitle C of RCRA.

EPA's June 30, 1988 Regulatory Determination did state EPA's intent
to promulgate tailored criteria for nonhazardous waste management of
exploration and production wastes.   Existing RCRA Subtitle D regula-
tions for nonhazardous wastes establish minimum federal criteria and
require states to submit solid waste management plans for EPA  ap-
proval.  The Regulatory Determination called for a three-pronged
approach aimed at filling "gaps" in existing State and Federal
regulatory programs by:
                               703

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                                 -2-
     1)   "Improving Federal programs under  existing authorities in
     Subtitle D of RCRA, the Clean Water Act,  and Safe Drinking Water
     Act ;
     2)   Working with States to encourage changes in their regula-
     tions and enforcement to improve some  programs; and,
     3)   Working with the Congress to develop  any additional statu-
     tory authority that may be required."

The API prepared its Environmental Guidance Document to support EPA's
activities by providing guidance to industry and  regulatory agencies
by;

     1)   Defining environmentally-sound operating and waste manage-
     ment practices;
     2)   Identifying conditions and areas where these practices are
     appropriate;
     3)   Supporting development by state agencies of area  or state-
     wide waste management plans required by RCRA based on these
     practices;  and,
     4)   Describing how these plans should  be  prepared,  including a
     suggested outline of their contents.

The basic premise of API's approach is the  development by  state
regulatory agencies of formal plans based on environmentally-sound
waste management practices.

Area or statewide plans are endorsed because the  exploration and
production of oil and gas is conducted in a wide  variety of environ-
mental settings, making nationwide standards impractical.   Fundamen-
tal differences exist from state to state,  and within regions within
a state, in  terms of climate, hydrology, geology,  economics and
method of operations which impact the manner in which oil  and gas
exploration, development and production is  performed.   The recom-
mended waste management plans should encompass all  wastes  that  will
be generated and addresses factors such as  surface  and subsurface
geology as well as meteorological conditions.  Provisions  should be
included for state approved site specific plans where deviation from
standard practices are justified by special or unusual circumstances.
In these instances, state regulatory agencies  should ensure that
alternate procedures are equally protective of the  environment.

API does not recommend that redundant or duplicate  regulations  be
developed in states where adequate protective  measures currently
exist and are being enforced.  API does endorse the enforcement of
all existing state and federal plans, regulations,  and requirements
and believes these should form the basic building blocks of the non-
hazardous waste management plans required by RCRA.

The intent of the Environmental Guidance Document is also  to aid in
explaining pertinent facts of exploration and  production operations
to the public and government agencies, and  to  assist in identifying
major environmental legislation and their associated regulatory
programs governing E&P waste management.
                               704

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                                 -3-
It is the  intention of API to update its Environmental Guidance
Document periodically as new scientific information becomes available
concerning the waste management and disposal practices discussed, and
as new practices are identified.  Cooperative efforts between federal
and state  regulatory agencies, industry and other interested parties
are expected to continue generating much useful information in this
area over  the next several years.

Following  is a discussion of the content of API's Environmental
Guidance Document.


Section 1:  Summary of Environmental Regulations

The first  section of the Environmental Guidance Document summarizes
the large  body of federal, state, local and lease statues and regu-
lations pertaining to E&P waste management and disposal practices.
These requirements impose responsibility and liability for protection
of human health and the environment from harmful waste management
practices  or discharges.  The following specific statutory and
regulatory requirements are summarized in Section 1:
     -  The Resource Conservation and Recovery Act
     -  The Safe Drinking Water Act
     -  The Clean Water Act
     -  The Comprehensive Environmental Response,  Compensation,  and
     Liability Act
     -  Federal Land Management Regulations
        State Environmental Performance Regulations
     -  Oil and Gas Lease Agreements


Section 2:  The E&P Exemption from RCRA Subtitle C Regulations

Congress recognized the special nature of oil and gas E&P wastes, and
exempted them from hazardous waste regulation under RCRA Subtitle C,
subject to the previously discussed EPA study.  This study, and the
June, 1988 Regulatory Determination that followed, concluded the
exemption  is appropriate and should be continued for E&P wastes
associated with primary field operations.

The Environmental Guidance Document describes EPA's hazardous waste
criteria,  provides EPA's definition of solid waste and identifies
wastes that have been designated by EPA as exempt and nonexempt from
hazardous  waste management requirements.  A discussion of the meth-
odology EPA used in developing its lists is included as well as these
methodologies applicability to wastes not specifically addressed by
EPA.  Section 2 also addresses the manner in which these definitions
can complicate management and disposal of nonexempt wastes.

In simplest terms, a solid waste is any material that is discarded or
intended to be discarded.  According to RCRA, solid wastes may be
either solid, semi-solid, liquid, or contained gaseous material.
                              705

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                                  -4-
Specifically excluded are point  source  discharges subject to NPDES
permits under the Clean Water Act.   EPA has  also determined that
produced water injected for enhanced recovery is not a waste for
purposes of RCRA Subtitle C or D,  since produced water used in
enhanced recovery is beneficially  recycled as an integral part of
some crude oil and natural gas production processes.  Commercial
products are also not wastes unless  and until they are discarded.

The Environmental Guidance Document  addresses in depth those waste
management practices that are unique to E&P  operations and wastes
that were determined by EPA to be  exempt from the hazardous waste
management requirements of Subtitle  C of RCRA.   These wastes include
drilling muds and cuttings, produced water and associated waste.
Waste management practices that  are  uniformly regulated by RCRA
hazardous waste management requirements as well as management of
general industrial wastes such as  solvents,  off-specification chemi-
cal, commercial products, household  wastes and office refuse are not
addressed by these criteria.

These criteria also do not address disposal  of produced water by
injection or surface discharge —  waste management practices that are
regulated by EPA or by the states  under authority of the federal Safe
Drinking Water Act and federal Clean Water Act,  respectively.
Disposal of produced water in pits,  by  land  application or commercial
disposal facilities is addressed.

For perspective, nearly 21 billion barrels of produced water — or 98
percent of all E&P wastes — were  generated  in the U.S.  in 1985,
according to API figures.  Most  of that produced water was disposed
by injection, with much smaller  volumes discharged to surface waters
or disposed in pits, by land application or  commercial disposal
facilities.  Drilling wastes (i.e.,  drilling fluids and cuttings)
accounted for about two percent  of all  E&P wastes generated in 1985,
totaling 361 million barrels.

Many nonexempt wastes are generated  during maintenance of production
equipment as well as transportation  (pipeline and trucking)  activi-
ties.  These wastes, while nonexempt, are not necessarily hazardous.
They are subject to the same provisions as any other industrial or
municipal waste.  The general provisions of  testing whenever there is
reason to believe nonexempt waste  may exhibit a hazardous waste
characteristic, the prudence of  segregating  non-exempt waste from
exempt waste, and special requirements  posed if these wastes are not
segregated or tested prior to mixing with exempt waste are discussed
in the Environmental Guidance Document.


Section 3;  Wastes Generated in  E&P  Operations

Section 3 of the Environmental Guidance Document discusses the four
activities associated with primary E&P  operations:  gas plants,
production facilities, drilling  and  workover operations.  It dis-
cusses operational and design aspects of E&P equipment and processes
                            706

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                                 -5-
as well as the wastes generated.  Companies differ in their  engi-
neering design and operational practices, but they generally all
utilize elements of the technology discussed and generate the wastes
discussed in this section.

Natural gas plants provide centralized dehydration, compression or
sweetening facilities necessary to place natural gas in marketable
condition and to extract natural gas liquids such as ethane, propane
and butane.  Individual wastes generated in the five extraction and
treatment processes performed in gas plants are listed and discussed.
The five processes are:

     1)  Inlet separation and compression  where wastes generated
     include produced water, pigging materials, inlet filter media,
     corrosion treatment fluids and small amounts of solid material
     such as pipe scale, rust and reservoir formations materials.
     2)  Dehydration processes necessary to remove the water vapor
     present in all natural gas to pipeline specifications.  Wastes
     include glycol based fluids, glycol filters,  condensed water and
     solid desiccants.
     3)  Sweetening/sulfur recovery wastes from process steps neces-
     sary to remove naturally occurring impurities such as hydrogen
     sulfide or carbon dioxide contained in natural gas to meet
     specifications for sales pipelines.  Wastes include spent amine,
     used filter media, spent iron sponge, spent caustic solution,
     spent catalyst and molecular sieve.
     4)  Natural gas liquid recovery process wastes including spent
     absorption oils, waste waters and boiler blowdown waters.
     5)  Compression and plant utility operations necessary to
     operate and maintain gas plant processing equipment where wastes
     largely consist of nonexempt waste material such as used oils,
     rags, sorbents and equipment filters.

Waste generated from field facilities and descriptions of the facil-
ities generating these wastes are also described in Section 3.   Field
facilities include equipment used to collect oil and gas from the
well and to prepare it for sale.  Well fluids are often a complex
mixture of liquid hydrocarbons,  gas water and solids.  A primary
function of the production process is to separate the constituents of
the mixture and remove those that are not merchantable to meet
purchaser standards.

Wastes generated from the following field facilities in the produc-
tion process are described:  wells, flow lines, separators, free
water knockouts, heater treaters/electrostatic treaters, oil stock
tanks, NPDES produced water discharges, centrifugal desanders,
produced water tanks, filters, gas flotation vessels, produced water
injection systems, steam generators and associated water softening
facilities, compressors, dehydration and sweetening units, produced
gas and fuel gas scrubbers, methanol injection and line heaters and
drilling operations.
                               707

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                                  -6-
Section 4:  Environmental Guidance for Waste Management By Waste

Section 4 of the Environmental  Guidance Document provides guidelines
for the management of production  wastes in an environmentally sound
manner.  Although special circumstances may exist warranting regula-
tory approval of other specific practices, waste management should
generally adhere to the criteria  described in this section.

Due to operators' limited control over wastes received and financial
viability of commercial facilities that may lead to CERCLA, correc-
tive action requirements under  RCRA or other liabilities,  it is
recommended that operators minimize potential liabilities associated
with offsite waste disposal by  keeping records of types,  volumes,
analytical data, destination, and haulers  of waste fluids transported
to offsite facilities.  It is also recommended operators  periodically
inspect offsite facilities used.

Section 4 also describes the physical  properties of concern with
management of specific wastes and describes applicable practices for
produced water, drilling waste, reserve pit waste,  drilling rig
waste, workover and completion  waste,  tank bottoms,  emulsions,  heavy
hydrocarbons, contaminated soils,  used oils and solvents,  dehydration
and sweetening waste, oily debris and  filter media,  gas plant process
and sulfur recovery waste, cooling tower blowdown,  boiler  water,
scrubber liquids, steam generator waste, plus downhole and equipment
scale.


Section 5;  Environmental Guidance for Waste Management and Disposal
By Practice

Section 5 describes available waste management practices  for E&P
wastes.  It describes these practices,  their potential environmental
impacts and the waste and waste characteristics for which  they  are
appropriate.  Although special  circumstances may exist warranting
regulatory approval of other specific  practices,  management of  wastes
should generally adhere to these  criteria.

As in any aspect of waste management,  there are some general, sound
practices that should be employed.   These  sound practices  not only
serve to protect human health and the  environment,  but also tend to
protect an operator from long term liabilities associated  with  waste
disposal.  As a general rule-of-thumb,  the choice of a waste manage-
ment option would be based upon the following hierarchy of prefer-
ence:

     1)  Source Reduction - reduce the quantity or relative toxicity
     of waste generated;
     2)  Recycling - reuse or reclaim  as much of the waste generated
     as possible;
     3)  Treatment - employ techniques to  reduce the volume or  the
     relative toxicity of waste that has been unavoidably generated;
                             708

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                                 -7-
     4)   Proper Disposal - utilize environmentally-sound methods  to
     place waste generated into the environment in a way that mini-
     mizes its impact and protects human health.

Viewed in this manner, the following general guidelines should be
followed:

     1)   Check all applicable regulations (federal, state and local)
     and lease provisions;
     2)   Consider notifying the landowner and state agency with
     authority over the waste or practice;
     3)   Consider the likely fate of the waste and its constituents
     over the long term;
     4)   When wastes are disposed in offsite commercial facilities,
     keep records that document the type and quantity of the waste,
     method of disposal, location of disposal, date of disposal,  and
     any other pertinent information that could prove useful in
     subsequent investigations to assess liability.

Waste minimization means the reduction, to the extent practical,  of
the volume or relative toxicity of liquid or solid wastes that are
generated and subsequently treated and require disposal.  Waste
minimization focuses on source reduction, recycling,  and beneficial
treatment to allow for reuse.

Opportunities to achieve significant waste volume reductions in
exploration and production operations are limited because E&P waste
volumes are primarily a function of activity level and age or state
of depletion of a producing property.  For example, the volume of
produced water and associated emulsions, number of workovers, fluid
handling equipment, etc.  typically increases as fields deplete.
Also, the volume of drilling muds generated is generally a function
of the number of wells drilled and their depth.  Thus, the waste
minimization method with the greatest potential benefit is onsite
recycling of hydrocarbons including waste oils, hydraulic fluids,
oily sump waters,-etc.  Recovery of hydrocarbons from tank bottoms
and separator sludges can be accomplished at onsite production
facilities or offsite commercial facilities.  Oil-based drilling mud
should be returned to the vendor for reprocessing where practical.
Other than onsite recycling, the most promising application of this
concept is through thoughtfully developed area waste management plans
which can incorporate locally available recycling capabilities and
facilities in addition to accounting for chemical product availabil-
ity.

Waste management criteria are discussed for roadspreading, burial or
landfill, onsite pits including reserve pit construction,  operation
and closure, production pits including blowdown and emergency pits,
workover pits, basic sediment pits, percolation pits,  unlined skim-
ming or settling pits, produced water pits,  evaporation pits, annular
injection of reserve pit fluids, underground injection wells, NPDES
discharges, open burning and incineration and offsite commercial
facilities.


                              709

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                                  -8-
 Section  6:   Guidelines for Developing Area Specific Waste  Management
 Plans

 Section  6  of the Environmental Guidance Document contains  guidelines
 for  developing area-specific waste management plans followed by an
 example  plan required by the California Waste Management Board for
 oil  field  operations in Kern County.

 This section recognizes that because the Environmental Guidance
 Documents  provides a national baseline or standard of performance,
 it requires translation into regional or area plans to be  useful to
 operators  for their day to day operations.  A generalized  methodology
 for  this transformation is included in this section.


 API  Communication Activities

 With completion of the Environmental Guidance Document in  1989, API
 commenced  an extensive communications program to publicize and
 encourage  use of the document.

 The  Environmental Guidance Document was initially distributed to all
 E&P  members of API and bulletins were sent to local API chapter
 organizations who were offered speakers and encouraged to make its
 presentation the subject of a local chapter meeting.  Many chapters
 incorporated these presentations into meetings centered on environ-
 mental protection.

 Copies and speakers were provided for regional trade association
 meetings in Texas, Oklahoma, Michigan, Wyoming, Colorado, Louisiana
 and  Kansas.

 The  document was publicized by the Independent Producers Association
 of America and made available to its members at no cost.

 Presentations were also made to the EPA, Department of Energy (DOE),
 Congressional staff, the Interstate Oil Compact Commission, numerous
^state  oil  and gas regulatory agencies and copies furnished national
 environmental organizations.

 To date, over 5000 copies have been distributed.


 Usage  of The Environmental Guidance Document

 Evidence of Environmental Guidance Document usage has occurred by
 incorporation as a basis or reference by state oil and gas agencies
 in modifying their regulatory frameworks, usage by the Interstate Oil
 Compact  Commission as a reference in its regulatory work for the EPA
 and  usage  by a number of operators in development of environmental
 training and auditing programs.
                          710

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                                 -9-
In the area of audit programs, the Environmental Guidance  Document
has provided a starting point for training and assessing compliance
with federal,  state and local laws and regulations in addition to
quantifying API environmental policies and principles endorsed by all
member companies.   The Environmental Guidance Document has accom-
plished this by:

     1)  Providing management and line personnel education, a train-
     ing plan and basis for improved communications between all
     levels regarding performance expectations.
     2)  Identifying and dealing with potential outstanding compli-
     ance issues and improving environmental practices.
     3)  Increasing management and regulatory staff involvement in
     day to day environmental activities.
     4)  Identifying information to be collected and maintained
     useful in assessing potential impacts of environmental perfor-
     mance and developing legislative and regulatory initiatives.
     5)  Developing baselines for continuous improvement in environ-
     mental practices and performance.

In addition, numerous operators have translated the Environmental
Guidance Document into regional drilling or production facility waste
management manuals or plans including specific wastes, practices and
disposal sites allowed to be used by their company personnel or in
inspection criteria to be used for disposal sites.  API has also
charged its E&P training committee with responsibility to develop a
workshop to be held for operators and recorded on videotape covering
how to develop these individualized plans.


Plans  for Revision

API recognizes the need to keep the Environmental Guidance Document
evergreen and build upon the experience of user and regulatory
groups.  To this end, a survey of these groups was made and ideas for
improvement solicited from EPA, state regulatory agencies,  operators,
and national environmental organizations.  Following are areas that
may be included in an update targeted for publication in 1991:

     -  A consistency review with the IOCC Committee on Regulatory
     Needs Report establishing regulatory technical and administra-
     tive criteria for E&P waste management programs.
     -  An expanded waste minimization section
     -  Guidelines for field sampling and analysis of oil field
     wastes
     -  A description of EPA's revised hazardous waste toxicity
     characteristic (TC) and associated laboratory test (TCLP)
     including compliance guidance
     -  Naturally occurring radioactive material management guide-
     lines
     -  Incorporation of land disposal criteria for metals
        Incorporation of land disposal criteria documentation for
     salt, hydrocarbon and pH
                            711

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                                  -10-
     -r  Expanded criteria  for annular disposal of drilling muds
     -  Training guidelines  for development of area waste management
     plans to translate the  general national criteria into site
     specific plans
     -  Development of waste management facility environmental audit
     practices and checklists
     -  Expanded waste characterization activities

To date, the following work  has been completed and is available froa
API:

     1)  API Production Bulletin -  Evaluation of Limiting Constitu-
     ents Suggested for Land Disposal of E&P Wastes by L. E.  Deuel.
     This bulletin contains  criteria for salt,  hydrocarbons and pH.

     2)  Guidance on  interpretation and compliance with the current
     EPA hazardous waste toxicity test.

The remainder of the  work  is underway and should be completed in
1991.

Longer term development of a corrective action  section dealing with
site and spill remediation levels,  procedures and technology  has been
approved and a work plan is  presently under development.
References:

U.S. Environmental Protection Agency,  1987.   Report to Congress:
"Management of Wastes from the Exploration,  Development,  and Produc-
tion of Crude Oil, Natural Gas, and Geothermal  Energy."  EPA Office
of Solid Waste and Emergency Response  (Washington,  D.C.),  December
31, 1987.

U.S. Environmental Protection Agency,  1988.   "Regulatory  Determina-
tion for Oil and Gas and Geothermal Exploration,  Development and
Production Wastes."  53 Federal Register, pages 25446-25459,  July 6,
1988.

API Environmental Guidance Document, 1989.   "Onshore Solid Waste
Management in Exploration and Production Operations."  American
Petroleum Institute, 1220 L Street, N.W., Washington, D.C.

IOCC, 1990.  "Council on Regulatory Needs Draft Report."   Interstate
Oil Compact Commission, 900 N.E.  23rd  St., Oklahoma City,  Oklahoma,
73152

API Bulletin pn E&P Waste Management,   1990.  "Evaluation of Limiting
Constituents Suggested for Land Disposal of  E&P Wastes" by L. E.
                               712

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                                 -11-
Deuel,  American Petroleum Institute, 1220 L Street,  N.W.,  Washington,
D.C.
                                713

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AN  OVERVIEW  OF  PRODUCED  BRINE  INJECTION  PRACTICES  IN
KENTUCKY
W. Mann, R. McLean
U.S. Environmental Protection Agency
Groundwater Protection Branch
Atlanta,  Georgia 30365
The  U.S.  Environmental  Protection  Agency  (EPA),  Office  of
Drinking Water,  is  responsible  for  regulating the
Underground  Injection Control  (UIC)  Program.   The program
was  authorized by  Congress in the Safe Drinking  Water Act
(SDWA) to protect the underground sources of drinking water
(USDW).   Five classes of injection  wells  are regulated  by
the  UIC  program.   Well  classification is based on the type
of  fluid  injected  and the  relationship  between the
injection  zone  and   the lowermost  underground  source  of
drinking  water.   Class  II wells are  used  to inject  fluids
associated with the production of oil and  gas or fluids and
compounds  used for  enhanced  hydrocarbon  recovery.   These
wells  normally  inject  below  the  deepest USDW except  in
cases where  the  USDW contains producible  quantities  of oil
and  gas.   Class  II  wells are classified  II-D if they are
disposal wells or II-R if they are enhanced recovery wells.
Approximately  6000  Class  II  injection  wells  exist  in
Kentucky.   The majority of  these  wells  are operated  in
conjunction with  stripper  well production  in mature
fields.    Brine production  has steadily  increased  over time
while  oil production has  decreased.   Disposing  of  this
brine in  a legal and  cost  effective way  has been  critical
to  the  continued operation of these  fields.   Prior to the
passage  of  several  environmental acts,  namely  the  Clean
Water Act and the  Safe Drinking Water Act, the disposal of
brine  in  Kentucky  was  virtually unregulated.    Surface
discharge of  brine  into  streams, injection of brine  into
sinkholes and  using  unlined  evaporation  pits  were all
common practices.    In  fields where  injection wells  were
being used,  the  construction  of  the  well  and the injection
operation was  unregulated.   With  the new environmental
programs  being strictly  enforced,  operators have  been
forced  to use injection  wells to  dispose  of their brine in
a  legal  and  environmentally  safe manner  or  shut-in
production.
                            715

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The UIC regulations are multi-faceted.  Along  with  defining
the  regulatory  framework  for  the Federal  and State
programs,  the  regulations set  forth  technical  criteria and
standards  for injection  wells.  This portion of the program
has  had the  largest  impact on  the Kentucky  oil  and gas
industry.   EPA,  Region IV, responsible  for  administering
the UIC program in Kentucky,  has issued several  guidance
documents  in  order  to clarify  its  position  on  minimum
acceptable  construction  standards that will  provide
protection  against contamination  of  USDW's  by Class II
wells.   Documents outlining  casing and cementing, plugging
and  abandonment and  financial responsibility  requirements
have  been developed  and  distributed  to operators of
injection  wells.   A series of  outreach programs were  held
in  Kentucky  to explain  the  UIC regulations  to  the
operators.   Field inspectors held  public meetings  and met
with individual operators to discuss   problems related to
injection  wells.   UIC  permit writers gave seminars  on  how
to  obtain  a  UIC  injection  permit  and  have  developed
alternatives  to corrective action  requirements  for wells in
the area  of review.   As  a  result  of  this  ongoing
interaction  between  the  EPA  and the  oil  industry in
Kentucky,  the injection  of brine   into properly  constructed
wells has  become an environmentally safe and effective way
to dispose of this oil  field waste.
                            716

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AN OVERVIEW OF TREATMENT TECHNOLOGIES FOR REDUCTION OF HYDROCARBON
LEVELS IN DRILL  CUTTINGS WASTES
Dennis Ruddy
U.S. Environmental  Protection Agency
Office of Solid Waste
Waste Management  Division
Washington, D.C.

Dominick D. Ruggiero
Harold J. Kohlmann
Kohlmann Ruggiero Engineers, P.C.
New York, NY


Introduction

Drill cuttings are  one  of the major wastes associated with oil  and
gas drilling operations.  When oil-based  drilling fluids are used
for  drilling operations,  the drill  cuttings become contaminated
with  substantial  amounts  of hydrocarbon material  and may require
treatment prior to  disposal, whether disposal is to surface waters
or  at an approved   land disposal  site.    This  paper  presents  an
overview of some  recently developed treatment technologies for  the
reduction of the hydrocarbon levels in the  drill cuttings.  It will
generally acquaint  the reader with some of the  basic technologies
and  treatment  performance   capabilities.    However,   it  is   not
intended to provide in-depth coverage of  the design and operation
of   the  technologies.     This   paper   also   highlights   some
environmental, cost, energy, maintenance,  and safety aspects which
should be considered in the design and operation of such systems.

The separation of drill cuttings from drilling fluids is typically
accomplished  using  mechanical  apparatus   such  as  shale shakers,
hydrocyclones, and  centrifuges.   Such equipment can produce either
continuous or  intermittent  discharges of  hydrocarbon-laden drill
cuttings.  However,  substantial amounts of hydrocarbon and drilling
fluids  can remain   with the drill cuttings after this  type  of
mechanical separation.  Typically,  the drill cuttings contain about
20 weight percent of hydrocarbon.
Opinions, conclusions and recommendations presented in this paper are solely those of the authors and are not
to be construed as U.S. EPA policy. Mention of trademarks, trade names, and patented processes does not
constitute endorsement by the U.S. EPA.
                                717

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Current Technology

Historically, hydrocarbon-laden drill cuttings were either disposed
at the  drilling  site  (whether  discharged to  surface waters  or
stored and disposed in pits) or, where required, were treated using
cuttings washer technologies prior to disposal.   Cuttings washers
use either high pressure water sprays or immersion of the cuttings
with agitation in a vessel with water and  detergent to remove the
hydrocarbon and drilling fluid.  The cuttings washer technologies
typically  reduce the  hydrocarbon content from  about 20  weight
percent to about 10 weight percent of residual hydrocarbon on the
cuttings.  Most  of the cuttings washer vendors claimed  that the
discharge to  surface waters  of cuttings treated by  washers would
result  in no visible  sheen,  which  is EPA's  indicator of  "no
discharge of  free oil" to surface waters.  However,  few if any  of
the  vendors   appear  to  still  be  in the  business  of  supplying
cuttings  washers.   This  is  due partly to the  inability  of the
technology  to   achieve   sufficiently  low  levels   of  residual
hydrocarbon   and   also   because  of  waste  management  problems
associated    with   the   resulting   water/detergent/hydrocarbon
solutions.                                          ~

New Technologies

Newer technologies  for  reducing the hydrocarbon content  of drill
cuttings  are  being developed  by several commercial vendors.  The
remainder of this paper describes to the reader two general classes
of  these newer  technologies  — thermal  processes  and  solvent
extraction processes.

Thermal Processes

Thermal processes  use  a  temperature- and  air-controlled,  thermal
distillation  step to vaporize water and  hydrocarbon from cuttings.
This may by followed by an oxidation or  combustion step to achieve
additional hydrocarbon removal.  The thermal distillation process
exposes the cuttings to controlled heat  sufficient to vaporize the
residual hydrocarbon and water.  The hydrocarbon  and water vapors
are then  condensed and either disposed  or they may be reused  in
drilling fluid systems.   If an oxidation step is used, the cuttings
are  subjected to  a second pass of controlled heat  and air  to
combust additonal residual hydrocarbon.  The treated cuttings are
reduced in volume and emerge from the process as  a  relatively dry
granular or clay-like material.

Following are descriptions of  some of the systems  available from
vendors that  use thermal processes.
                              718

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Thermal Process 1 - Electrical Thermal Distillation

Thermal Process 1 treats drill cuttings in a continuous mode
to remove  hydrocarbon material with  the  processed cuttings
reportedly  suitable  for  discharge  to   surface waters  or
disposal at  a land disposal  site.   The  drill cuttings are
exposed to controlled heat generated by electric resistance
heaters that  is  sufficient to vaporize residual hydrocarbon
and any water on  the cuttings.  The processed cuttings  are dry
and granular in appearance.  The water and hydrocarbon vapors
and off gases are carried from the process  chamber by nitrogen
gas.  They are directed to a water-cooled condenser  and the
condensed  water  and  hydrocarbon  are  then  separated.   The
hydrocarbon may be suitable for return to the  drilling fluid
system if it meets the drilling operator's specification for
hydrocarbon additives.  The condensed water is discharged if
it   meets   the  appropriate  discharge   standards.     Non-
condensables and off-gases from the unit are  passed through an
activated  carbon filter and then vented  to the atmosphere.
The   processing   units  are  provided  in   a  skid-mounted
configuration.   A schematic   diagram of the this  type of
thermal system is presented in Figure 1.

The  process efficiency of  the unit is reported by the vendor
to be superior to cuttings washers.  A field sampling  program
was  performed for the EPA on a full-sized  unit  to obtain data
on  the residual hydrocarbon  content of  the  drill  cuttings
treated by this process.  The results  of the sampling  program
indicated that the untreated drill cuttings had a hydrocarbon
content ranging from 5.1 to 8.7 weight percent and the  treated
cuttings contained from 0.23 percent to 3.8 weight percent of
residual hydrocarbon.

The  estimated cost for this system based  on equipment rental
for  a 35 day drilling campaign and operating 24 hours  per day
is  approximately  $165,000 (1988  dollars).    This  estimate
includes   equipment   rental,   operating   labor,   energy
requirements, and setup and teardown expenses.  If the  unit is
to be used at an  offshore platform, the cost  would increase by
approximately  $10,000 to  cover the  equipment and personnel
transportation costs, platform living expenses for operating
personnel, and shore  support.

Thermal Process  2 - Thermal Energy Distillation

Thermal Process 2 is a process for the continuous  treatment of
drill cuttings and recovery of hydrocarbon.   The  raw cuttings
are  routed to the drying  section  of  the  process unit where
water and hydrocarbon are driven off by thermal energy  from an
                          719

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external heat supply.   The unit providing the external  heat
can be  fired  by waste oil, diesel  oil  or natural gas.   The
water and hydrocarbon vapors that are driven from the cuttings
are passed  through water-cooled condensers.   The  resultant
condensate  is  directed  to  a  separator  to  separate   the
hydrocarbon from the water.   The  hydrocarbon  is placed  in
storage for reuse or for further processing, if required.   The
water, still containing substantial amounts of finely divided
oil in  suspension,  is passed  through a two-phase process  to
effect  additional  separation  of hydrocarbon from the water.
The unit is skid mounted for use both onshore or at  offshore
operations  either on  a mobile  drilling unit,  platform  or
barge.  This process  is shown schematically in Figure 2.

According to the manufacturer, a prototype demonstrator  unit
has achieved residual hydrocarbon levels in drill cuttings  of
less than 0.5 weight percent.

Using the prior example of 35  operating  days and  24 hours per
day operation, the estimated cost on a rental basis  for  this
system  is  about  $80,000   (1988  dollars).   This   estimate
includes   equipment   rental,   operating   labor,   energy
requirements, and setup and teardown expenses.  If the unit  is
to be used at  an offshore platform, the cost would increase  by
approximately $10,000 to cover the equipment and personnel
transportation costs, platform living expenses for operating
personnel, and shore  support.

Thermal Process  3 -  Indirect Thermal Distillation

Thermal Process 3 is  a continuous thermal distillation process
that uses an external heat source to provide indirect heat for
hydrocarbon and water removal.  Cuttings are fed  to a blender
where a homogenous slurry is made by the addition of  water  to
the cuttings.   The added water  facilitates handling of the
cuttings  feed stream to  the system.  The slurry is  fed  to a
jacketed   processing  vessel.      During   normal   drilling
operations,  the  blender  accumulates  the solids   and  the
processing unit needs to operate only about half  of the time.
A closed liquid  heat transfer system circulates hot oil around
the processing unit to provide the indirect heat to drive the
water and hydrocarbon from the cuttings.  The heating oil  does
not contact the  materials being treated.  On  land locations,
the heat required  for  this process  is provided by an oil
heating unit.   The hydrocarbon and water vaporized  from the
cuttings   are  condensed   and  recovered.     At   offshore
installations  the heat  source  can be  waste heat  that  is
recovered  from  the  rig generator exhaust.     This system
reportedly produces a dry,  free flowing solid,  free of visible
                           720

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             THERMAL  PROCESS  1
          SCHEMATIC FLOW  D  AGRAM
           ELECTRIC
          RESISTANCE
           HEATER
       DRILL
      CUTTINGS
  HEAT ING

 CHAMBERS
                                                 HYDROCARBON


                                                 UASTEWATER
                                     NON-CONDENSABLE
                                       VAPORS
                                                 FIGURE
             THERMAL  PROCESS 2
          SCHEMATIC  FLOW  D  AGRAM

                             EXTERNAL
 DRILL
CUTTINGS
DRYER
                  TREATED
                  CUTTINGS
                               HEAT

                              VAPORS
                        NON-CONDENSABLE
                          VAPORS
                                CONDENSER
                                        LIQUIDS
                                 SEPARATOR
                          WASTEWATER
                      HYDROCARBONS
                                                 FIGURE 1
                        721

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     hydrocarbon.  A schematic  diagram of the system is presented
     in Figure  3.   The  system  is  supplied  in  a  skid  mounted
     configuration.

     Results from tests on a pilot-plant scale by the manufacturer
     indicate that the process can achieve a  residual hydrocarbon
     content of 6 weight percent or less  on the  treated cuttings.

     Due to incomplete information being available at this time, a
     current cost estimate for this system was not made.

Solvent Extraction Processes

Solvent  extraction  technology uses  a  solvent  to  extract the
hydrocarbon from the cuttings.  Extracted hydrocarbon material is
separated from the solvent  and either disposed or recycled.  The
treated cuttings emerge  from these processes in a relatively dry
granular  form.    Following are general descriptions of  solvent
extraction  systems  which  have been  constructed  and  tested by
manufacturers.

     Solvent Extraction Process 1 - Dual Stage

     Solvent  Extraction  Process   1   is  a  continuous   solvent
     extraction system using CFC-123  (dichlorotrifluoroethane) as
     the  solvent.    The  drill cuttings  are  first slurried in  a
     fluidizing holding tank  with  oil or water,  depending  on the
     application,  to facilitate  pumping of  the  cuttings.   The
     slurried cuttings are fed to  the  first of two  extractor units
     where the slurry is contacted with the solvent.   The  mixture
     is then directed to a hydrocyclone where the  solvent  and the
     cuttings are  separated.   The hydrocarbon-solvent mixture is
     sent to the solvent and oil separation system.   The cuttings
     are then directed to  the second  extraction unit  where clean
     solvent is contacted with the cuttings.   The mixture from the
     second extraction unit  is directed to a second  hydrocyclone
     for  separation of  the  cuttings  and solvent.    The  liquid
     mixture removed by-the second hydrocyclone is  directed to the
     first extraction unit and the treated drill  cuttings are sent
     to a drying  system.   The solvent and hydrocarbon separation
     system consists of an extractor and a separation column where
     the  hydrocarbon,  water  and  solvent  are  separated.   The
     hydrocarbon phase flows to the fluidizing holding tank and the
     solvent  is  recycled  to  the  second  extraction  unit.   The
     manufacturer reports that the system  is  completely closed to
     preclude vapor  emissions to the atmosphere.   This process,
     which is skid mounted, is shown schematically in Figure 4.

     The  manufacturer indicates that  the system  is designed to


                               722

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                   THERMAL PROCESS 3
                 SCHEMATIC FLOW  DIAGRAM
                           WATER
     DRILL    	
   CUTTINGS
    NON-CONDENSABLE
    VAPORS
   CONDENSER
                VAPOR
HYDRO-
CARBON
WASTEWATER
                BLENDERS
               JACKETED CENTRAL

               PROCESSING UNIT
 TREATED

CUTTINGS
                      EXCESS
                     CAPACITY
                       HOT 0 IL
                      RECIRCULATING
                       SYSTEM
 HEAT

SUPPLY
                                                    FIGURE 3
               SOLVENT  EXTRACTION  PROCESS
                 SCHEMATIC FLOW DIAGRAM
                           SOLVENT/OIL
                            723

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operate on an  around-the-clock basis.  However,  it could be
operated in an intermittent mode with a short  time required
for start-up and shutdown.   The  process  is  designed to treat
drill cuttings to achieve a  hydrocarbon level of less than 0.8
weight percent.   This  technology has been tested  on drill
cuttings although it has not yet been applied on a full-scale
basis for treating drill  cuttings.   This technology has been
applied on a full-scale basis for the treatment of oily steel
mill scale and various petroleum refinery slop oils, sludges,
and tank  bottoms (EPA hazardous waste  numbers K048  through
K052, Code of Federal Regulations, Title  40, section 261.32).

The manufacturer reports  that  approximately 99.92 percent of
the solvent is recovered.   The manufacturer reports that the
capital  cost  of  the  system  is   between  $1,600,000 .and
$2,500,000 (1990 dollars) and  would  require one operator per
shift.  This  cost includes  all  equipment,  materials,  piping
and  valves,   electrical  design,  engineering   design  and
fabrication,  and process warranty fees.    Land installation
including  engineering,   labor,  and materials   costs   an
additional $250,000  (1990 dollars.)

Solvent Extraction Process  2 - Closed Loop

Solvent Extraction  Process  2  is a  closed  loop,   continuous
solvent  extraction   system.     This  process ' operates   at
essentially atmospheric  pressure and temperature and  uses a
non-flammable, chlorinated  hydrocarbon solvent.   The  process
has  three  separate  subsystems — cutting   feed  system,
extraction system and solvent recovery system.  Each subsystem
is individually skid mounted.

The cuttings feed system is  an integral part of a  proprietary
extraction system and could be  installed  on the  extraction
skid.    However,  to provide  flexibility  to  the  drilling
operator,  it  is provided on a separate  skid.  The  cuttings
feed skid  contains  some  feed  surge  capacity and a means  of
transporting the cuttings to the extraction system.

After use, the solvent is  pumped  from the extraction system to
the  solvent  recovery  system where it  is  separated  into
solvent, hydrocarbon, and water  fractions using distillation
technology.    Clean  solvent  is  recycled  to the  solvent
extraction  system and  hydrocarbon  may  be  returned to  the
drilling  fluid system.   Reportedly,  the water  fraction from
the  solvent  recovery system is suitable for discharge.  A
schematic diagram of this system is  presented in  Figure 5.

According to the manufacturer, this system can clean cuttings


                          724

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            SOLVENT  EXTRACTION  PROCESS  2
                SCHEMATIC  FLOW  D  AGRAM
DRILL CUTTINGS
               EXTRACTION

                SYSTEM
                            CLEAN SOLVENT
                         OILY SOLVENT
                                               NON CONDENSABLE VAPORS
                                               TO ELEVATED VENT
                    TREATED
                    CUTTINGS
 SOLVENT
RECOVERY
 SYSTEM
                                                       STEAM
                                                  RECOVERED HYDROCARBONS
     WASTEWATER
                                                            F I GURE  L»

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     with a hydrocarbon content up to 20 weight percent to a level
     of less than 1 weight percent.

     The system requires the following utilities:  energy source of
     low  temperature  heating  media,  steam  for  drying  treated
     cuttings and for solvent recovery, electricity, cooling media,
     instrument air, and solvent.   The manufacturer estimates that
     the energy requirements for  a unit capable of processing 11
     tons per hour  is  5.0 MMBTU/HR heating media and  180  KWHR of
     electricity-    Half  of  the  required heat  can  usually  be
     provided  by  low-temperature waste  heat  available  at  the
     drilling facility.

     Cost  estimates for  the  operation  of this  system  are  not
     currently available.

System Design and Selection Considerations

When developing, selecting or planning the use of a system to treat
drill cuttings  for hydrocarbon reduction,  the following  factors
should be given consideration:

>•    Methods and modes of operation -  The method or mode by which
     the  system operates  should not  interfere with the drilling
     operation.  It should require few if any operating personnel.
     The system should be compact so that minimal space is required
     at the drilling site, especially at  offshore  facilities where
     space is often very restricted.  Ideally,  it would be provided
     on a turnkey basis.

»•    Hydrocarbon reduction efficiencies - The system should achieve
     a consistent  level of  hydrocarbon removal.  It appears that
     the many of the vendors of the newer technologies  are striving
     to achieve residual hydrocarbon  levels of  less than 1 weight
     percent.  ~

>    Waste and  By-Product

          Treated  cuttings   should have  a residual   hydrocarbon
          content  acceptable  for disposal,  whether  to  surface
          waters or  by land disposal.

          Wastewater discharging from the process would ideally be
          of  a quality  not requiring further  treatment  before
          disposal.

          Hydrocarbons  discharging   the  process   should   be   of
          reusable  quality  or else  be capable  of upgrading  for
          recycle or reuse.
                               726

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     •     In the  case  of the  solvent  extraction  process,  the
          solvent  loss  to  the  atmosphere  should  be  minimal.
          Substitutes for chlorofluorocarbons (CFC's) used in these
          technologies should be sought.

     Materials Handling - The handling of the cuttings in and out
     of the  process units should  be kept  simple and  should be
     automated.  The cuttings should be  conveyed directly from the
     drilling system using, for example,  a mechanical or hydraulic
     system.   Interim storage should be supplied  to buffer high
     cuttings generation rates during periods of drilling when peak
     volumes of cuttings are produced.

     Energy requirements  should  be kept to a  minimum.   Emphasis
     should be given to using waste energy sources available  at the
     drill site.

     The  system  should be  relatively  maintenance  free.    Any
     required maintenance should be such that it can be performed
     in  short  order during  periods  when  drilling is  not  in
     progress.

     Safety is  an  important  consideration.   The  system should be
     designed with safety in mind and should be free of ignitable
     and  explosive  materials.   Solvents should  be  used  only in
     closed systems.  The use of hazardous chemicals or materials
     should be avoided.  System design will involve 'consideration
     of numerous safety  requirements  when  the  equipment  is to be
     operated at drilling sites.
 Summary

 The manufacturers of most of the drill cuttings treatment processes
 discussed  in  this paper indicate  that their systems  will treat
 cuttings  containing  a nominal  20  weight  percent of  residual
 hydrocarbon a  level of 1  weight percent,  or  less.   All  of the
^manufacturers  contacted during  the  preparation  of  this paper
 indicated  that  the treated cuttings  from their  process  will be
 acceptable for discharge to surface  waters or for land disposal.
 However, most of the processes discussed are not  presently in full-
 scale  operation  at any drilling sites or  treatment or disposal
 sites.

 These  newer technologies can be  assembled and operated at active
 drill  sites, whether  on land or at offshore drilling  facilities.
 Moreover, these technologies may  hold promise for their use  in site
 remediation  work  to  treat a  variety  of  oily wastes at waste
                               727

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storage, treatment, or disposal facilities.

When selecting  a system to  process drill  cuttings,  a number  of
logistical and design factors should be  considered.   The  capacity
of  a  system,  including  feed  buffering   capacity,   should  be
sufficient that during peak  drilling times the system  can handle
any cuttings that must be processed and there should be  sufficient
power so that the system can  be  continuously operated.   Provisions
should be made to  enable an  operator to operate and maintain the
cuttings treatment system on an  offshore rig.  Since offshore rigs
have limited deck space,  size and weight should also be  taken into
account when selecting a  cuttings treatment system.  Safety aspects
should  be  carefully considered,  as should  normal operation and
maintenance activities.  Last but not least,  the treatment system
should have the  demonstrated ability to consistently achieve the
reguired environmental control levels, including reguirements for
treated waste as well as by-product wastes such as air  emissions,
wastewater, and waste hydrocarbons.
                               728

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References

1.   U.S.  Environmental Protection Agency "Development Document for
     Proposed Effluent  Limitations Guidelines  Standards  of the
     Offshore Segment of the Oil and  Gas Extraction Point Source
     Category",  July 1985.

2.   "Report on the Results of Field Sampling of Thermal Dynamics
     Thermal Distillation Unit to  Treat  Drill  Cuttings on Conoco
     South Pass 75  Platform",  Kohlmann  Ruggiero  Engineers P.C.,
     February 1988.

3.   "A  Review  of  drill   Cutting  Discharge  Technologies  and
     Regulations from Offshore  Platforms",  By Maurice Jones and
     Robert Evangelisti.

4.   "Report  on  Treatment  Technologies   for   Drill  Cutting".
     Kohlmann Ruggiero Engineers,  P.C., March 1988.

5.   Technical Data from  Thermal Dynamics, Inc. on the TDI Thermal
     Distillation Unit.

6.   Memorandum in Support of Thermal  Dynamics,  Inc's Motion for
     Stay  Pending  Review of  the  EPA  Region  VI  General  Permit,
     August 1986.

7.   "The  Process and Technology  for Recovery of  Drilling Muds,
     Fluids and Cuttings",  presented  by  RMD International, Inc.,
     December 1987.

8.   Technical Data from  Envex Corporation on the Envex Processing
     System.

9.   Technical  Data  from  CF  Systems,  Inc.  on  their  Solvent
     Extraction Process.

10.  Technical Data  from Conoco  Specialty Products,  Inc.  on the
     Solvtec Process.
                               729

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PATHWAY  EXPOSURE  ANALYSIS  AND  THE  IDENTIFICATION  OF  WASTE DISPOSAL
OPTIONS  FOR PETROLEUM PRODUCTION  WASTES CONTAINING NATURALLY  OCCURRING
RADIOACTIVE MATERIALS
H. T. Miller and E. D. Bruce
Chevron Environmental Health Center
P. 0. Box 4084
Richmond, CA. 94804-0054
                                ABSTRACT

It  has long been recognized that the occurrence of petroleum and natural
gas deposits have been associated with the presence of members of the 238
Uranium  decay chain,  principally  226 radium, 222  radon and daughters.
Some  of  these  radioisotopes  accompany  the produced  fluids into  the
production  tubing  and  surface  processing  equipment  where  they  are
precipitated  or deposited  as  barium, calcium ,   strontium compounds of
sulfate  or carbonate  that  form a very  hard and insoluble  cement-like
coating.  These  compounds  are  also  brought  to  the surface  with the
production sand that is entrained in the produced fluids.

While these materials do not represent a serious external exposure hazard
to employees,  they are sufficiently active, ranging from a few picocuries
per  gram to several nanocuries per gram, to require careful handling and
disposal.  This  paper  presents  the  steps followed  by one  company to
identify  potential disposal options,  and outlines the  exposure pathway
analysis  used to quantify the  potential exposure and risk.  Conclusions
are  made  with  respect  to  the  environmental  acceptability  of  each
management option studied.

                              INTRODUCTION

The  identification of  disposal  options and the  establishment of their
overall  suitability for use is  a complicated process. It  begins with a
thorough  understanding of the operation or  process generating the waste
material.  This understanding leads to  the definition of  scenarios  for
disposal  and   the  identification  of  the  pathways  of exposure  to be
studied.  The  completed analysis results in either an estimate of risk or
an estimate of the effective dose commitment for the disposal option. The
calculated risks or the calculated effective doses are compared with what
                                 731

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is thought to be acceptable, and the basis  for a  risk management decision
is constructed.

Other  social, economic, and  political factors also   impact  on any  risk
management  decision  concerning  radioactive  materials.  These concerns,
while  recognized as being often more important than  scientific analysis,
will not be discussed.

It is the purpose of this paper to describe  the exposure  pathway analyses
used  to  evaluate  options  considered  for  the  disposal of   petroleum
production   wastes  that  are  contaminated   with   naturally   occurring
radioactive  materials (NORM). These NORM contaminants are members  of  the
238 U and the 232 Th decay chains.

The  objectives  of  this paper  are to  identify  those  waste  management
options   for  naturally  occurring  radioactive   materials   (NORM)  that
potentially   offer  environmentally  acceptable   alternatives   for  site
remediation or disposal; perform pathway exposure  analysis to support  the
finding  of overall environmental acceptability and to determine which of
the  dose performance criteria usually cited offer  the highest  degree of
safety to the general public.

This  paper will discuss the origin of  NORM in petroleum  operations, why
the  deposition of NORM presents a waste  disposal problem for  production
operations, the type of sites, equipment and location where NORM deposits
are  found,  what  are considered  the viable  disposal options,  and the
pathways studied. Results of analyses are presented and conclusions made.

                           THE NATURE OF NORM

The production of crude petroleum is a curious process.  Large  quantities
of  water are brought  to the surface  for processing,  the  products are
extracted,  and  the  water  discarded.  The products  are crude oil and
natural  gas. The water  is called produced  water and is  usually pumped
back into the producing formation or into a zone below the USDW (Drinking
water aquifer).

Whether  or not a given production  well brings NORM  to the  surface is a
matter  of geology and formation chemistry.  The   accumulation  of NORM in
petroleum  bearing strata is probably the result of marine deposition and
evaporation.  The petroleum is  generally assumed  to  have migrated to  a
position  of minimum hydraulic potential in  the reservoir  rock,  which may
or  may not be derived from the same source deposits  as the petroleum. In
general, the uranium is resident in the crude oil  and  in pellets of solid
hydrocarbon,  the radon distributes itself   in the oil, gas  and water in
that order of preference, and the radiums are found in the produced water
and the solid crusts or scales. In general the decays series are found to
be in extreme disequilibrium (NCRP,1975).

The  NORM  exists on the  surface in at least  two forms.  The first  is a
heavy,  dense,  cement-like  mixture  of  barium,  strontium    and  radium
                                  732

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sulfates.  This material  is  precipitated in  the  production  tubing,  the
well tree and the flow lines. It also tends to settle out  in low parts of
the line and in the gas-liquid and the oil-water separators. Some of this
hard,  scale-like material is also trapped in  the waste water  tanks,  pond
and  sump bottoms and in  filters and in the  well bore of  the   well that
returns  the produced water to the producing   formation. Some water  flood
and steam flood operations such as those in the North Sea have  been  noted
to  have enhanced scale production (Smith, 1985).  These scales  can  range
from  mostly barium to mostly radium though the mostly radium variety  are
thankfully  very rare. Chevron's analyses of  scale average approximately
5484  plus or minus 9727 pCi/gm  with a range of less  than 50  to greater
than 30,000 pCi/gm.

The second kind of NORM-contaminated material is thought to be carbonate/
silicate  material and is  usually referred to  as formation sand.   These
materials  can settle  out  in any place  in the system  when there  is  a
decrease  in flow rate, change of direction and is usually found  in  thick
loosely consolidated deposits in the bottoms of tanks, separators, heater
treaters  and  in  the  bottoms  of ponds  and sumps.  Chevron's  analyses
suggest  that this type  of material averages  approximately 115  plus  or
minus 56 pCi/gm total radiums, range 0 to 250 pCi/gm.

Both  of  these  types  of  materials can  be found  in the  oily, watery
deposits found in tank bottoms usually referred to as bottom sediment and
water  (B.S. and W.), and in filters  and other water treatment equipment
used to clean up the produced water prior to discharge.

Contamination  of the soil in the immediate  area of production wells and
the  clean outs on tanks and equipment has  also been noted. These appear
to  average approximately 310 plus or minus 685  pCi/gm,  range 0  to 2,000
pCi/gm total radiums.

                        POTENTIAL NORM LOCATIONS

It  is extremely difficult to describe a generic production site  and site
layouts depend upon terrain,  land use patterns, and population densities.
It  can  be  stated,  however,   that oil  wells and  crude oil  collection
stations  or tank batteries are removed from  people. A typical well site
is  at least 100 feet by  100 feet while a typical  collection station is
about 200 feet by 300 feet.

Oil  wells are usually  spaced  one to a quarter  section (160 acres) for
newer  fields and  somewhat  closer for older  fields. In some  locations
where  the surface land  access is restricted  for agriculture etc.,  one
well  site may contain several pumping units.  The procedure for closing a
well  site and returning it to  the lease holder for unrestricted  use is
first  to  plug  and   abandon  the well  and then  to remove  the surface
structures  and piping,  fill  in the  well cellar,  and return the  site to
grade  using a grader or by hand  work.  A well is plugged and abandoned by
squeezing  and cementing shut  the  perforations in the producing zone and
and  setting a  ten  foot concrete plug  above and below  each USDW.  The
                                733

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casing  is cut off below  plow depth, usually  four   feet,  and a ten  foot
concrete  plug set at the top of  the casing.   The final step is to weld a
cap on the casing and fill in the excavation around  the well.

A  typical  collection  station  or  tank   battery   usually contains  one
separator,  one heater treater, two to   three  oil tanks and at  least one
waste water tank. Pumps for the movement of oil  and  the disposal of water
as  well as gas compressors for the movement   of the natural gas may also
be  included. The procedure for closing a  tank battery  is  similar to that
for  closing a well site. All surface  structures and piping are removed,
the  berms surrounding the tanks are leveled to  grade and  the site graded
to match the local terrain. Sometimes upon  closure material from the tank
bottoms are buried on the site.

All  oil  field  operations are  supported by  equipment yards  where new
material is stored and old material placed before being renovated  or sent
to scrap. These facilities are usually several hundred  yards in width and
length  and are usually located  in or near the  small  town or camp  that
supports  the field. These facilities  are closed by removing  structures
and fences and grading to blend in with the natural  terrain.

Pits containing drilling muds and scrapings are  usually left in place and
present   no  environmental  hazard.  Production   pits containing  oily
materials  require a  different method.  Closure of   these  pits requires
dewatering  and the removal of the oily  sludges from their bottoms.  This
material  is land spread or buried,  diluted with clean soil at  the site
with  owners permission, or taken  to a licensed oil  field disposal site
for  burial. The pit is  then filled and capped  with four  feet of   clean
soil and  graded to blend with the surrounding terrain.

                        POSSIBLE DISPOSAL OPTIONS

Previous  papers presented by the  senior author at  the the HPS meetings
and  an  API  study  (API,1989)  have demonstrated   that the  exposure of
employees  to  external  radiation  is  of little  concern  except   for an
extremely  limited  number  of  cases.   The  real  problem   seems   to be
associated  with the disposal of tank bottoms  and other waste materials.
Most  of  this  material  is  just  barely  radioactive. Philosophically,
disposal  by  dilution  at the  site of  NORM generation  seems the  most
desirable  option. The collection and accumulation of large quantities of
radium  in a single location is more distasteful since  it tends to  create
an external radiation hazard and  produce a potentially copious source of
radon.  Collection of material  in containers at  a  central location can
also  lead  to  problems  with   contamination   due   to drum  filling and
handling  and the  eventual  deterioration of  the  drums and repackaging.
Disposal  at the site of generation  also has  the advantage that  it will
have  little  impact  on existing  industry practice  to dispose  of most
non-radioactive oil field waste at the site of generation.

The  disposal  options  suggested here  for scales,    formation sands and
sludges  emphasize the reduction of the accumulation  of radium,  limit the
                                 734

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external  gamma ray hazard and  minimize the production  of   point  sources
radon.  These options include are shown below.

1.  Surface  spreading   with  and without  dilution with   clean soil  at
    depths of 1, 3, 10, and 20 centimeters.

2.  One-,  two- and  three-foot  layers of buried  materials  covered  with
    three feet of clean and compacted fill (sludge pit).

3.  Burial  of four feet of material covered with  four  feet  of clean and
    compacted fill (production pit).

A.  Burial  of thin layers of material;  3, 6, and 9 centimeters;  with  7
    feet  (213 centimeters), 10 feet  (305 centimeters)  and 15  feet  (457
    centimeters) of cover.

5.  Placement in a plugged and abandoned (P and A) well.

                         EXPOSURE PATHWAY LIMITS

The  analyses reported in this  paper were performed using  four criteria
that  potentially could be applied  to the management of  NORM. These  are
summarized in the first table.

It  is also important to ensure that ground  water levels of  total radium
do  not  exceed  that specified  by the  National Primary  Drinking Water
Regulations (NPDWR), 5 pCi/1  226 Ra plus 228 Ra.

The  exposure limit for the intruder is 100  mRem per year effective  dose
for all  pathways including radon.

                    SURFACE SPREADING WITHOUT  MIXING

NORM  materials can be spread without mixing  or dilution using equipment
or  by hand. The material  is placed upon the  ground and spread in   thin
layers.  The limit of spreading using hand methods is about one half  inch
(approximately  one centimeter).  A   good equipment operator  can spread
material   to  the  closest  one   tenth  of  a  foot    (Approximately  3
centimeters).  Spreading without mixing can  also be used on  lease roads
within production fields.

                          SPREADING WITH MIXING

Spreading  with mixing  or  dilution involves the  uses  of a  dozer,  road
grader  or a deep disk plow.  The material is placed on  the  location  and
spread  by hand  and then  mixed with  clean soil  using equipment.   Road
equipment  can provide mixing to  depths of approximately six  inches  (15
centimeters) and a deep disk plow to eight inches (20 centimeters).
                                735

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                             SHALLOW BURIAL

The  shallow burial method of  disposal utilizes  an  existing  pit that is
being  closed  or  a  pit  dug usually  for  that   purpose.  Such  pits are
approximately 10,000 square feet  but some can  be larger.  The method here
is  to open the pit, place  the Norm material in   lifts   mixed with clean
soil  or other NORM-free wastes of  one foot or 31 centimeters  and cover
the material with a foot or more of clean soil.

                               DEEP BURIAL

Deep  burial is  similar  to shallow  burial  except  that  the  top of the
buried  material is  at  least three  feet  below the  level   of a typical
residential cellar or at approximately eight or nine  feet  from grade.

                       PLUGGED AND ABANDONED WELLS

The  plugged and abandoned well offers  unique  disposal opportunities  for
the  disposal of NORM  below USDW. For this  disposal  option,  the NORM is
made  into slurry  and  pumped into the  well.  The USDW  are  protected as
described above and the well is capped and sealed  as before.

                      EXPOSURE PATHWAYS CONSIDERED

External  radiation exposure  pathways  for residents  and  intruders were
evaluated  by integrating the radiation  flux above a  finite   flat  plane.
Exposure  rates were  calculated  for exposure  outside  of the houses,  a
house  with a cellar, a house built on a concrete  slab and a  house  with a
crawl space. The occupied levels in the house with a cellar and  the house
with  a crawl  space  were assumed to  be one foot  or thirty  centimeters
above  grade. The occupied spaces of the house  on  a slab was  estimated to
be  ten centimeters above grade and  the concrete  slab was assumed  to be
four  inches thick. In all cases, it was  assumed  that the exposure takes
place  at the geometric center of the site. Sites  and  houses  were assumed
to  be circular to  reduce the time  of computation. Exposure   times were
estimated  to be one year less two weeks vacation  (or  8424 hours) with 25
percent  of  that  time  spent  outside the  home  for  the resident.   The
exposure  time for intruders  was estimated to  be six hundred  and forty
hours or approximately 80  working days.

The  generation of radon and  resulting radon exposures were   analyzed in
part using the methods presented  by Rogers (NUREG,1984). Radon  emanation
rates  were  calculated  to  determine  the  surface   releases  into   the
atmosphere  and into the substructure of the house with a crawl  space.  No
reduction  in radon emanation was claimed for the  slab of  the house built
on  a slab.  Radon  concentrations within the   crawl space  assumed   a 53
cubic  meter volume and three air changes  per  hour. Radon breathing  zone
concentrations  for the house with a  crawl space  were assumed to  be  one
half of those noted in the crawl space. Breathing  zone concentrations  for
the  house on a slab assumed a 352 cubic meter  volume  and two  air changes
per  hour. Radon rates  were calculated separately for the house  with a
                                 736

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cellar by using the area of the band intercepted by  the  excavation  as  the
area  source. The breathing zone  concentrations for  radon  in   the  cellar
were  calculated assuming diffusion into a 352 cubic  meter  space  with  one
air change an hour. Breathing zone concentrations in  occupied  portions of
the house were be assumed to be one half of  those in  the cellar.  Exposure
times were assumed to be the same as in the  external  exposure  pathway.

The  airborne dust exposure pathway  was analyzed assuming  that   the dust
concentrations   was 100 micrograms per cubic meter for  the residents  and
200  micrograms per cubic meter for the  intruder. Ventilation  rates used
are   those  for  the  ICRP  (International  Commission  on  Radiological
Protection) reference man.

The  ingestion of soil materials was assumed to be one hundred milligrams
per  day  for  residents  and  two  hundred  milligrams per  day  for   the
intruder.

The specific activity of the soil was assumed to be the same as the final
surface specific activity achieved by the disposal method.

The  water pathway  assumed  that the well  was located at  the geometric
center  of the disposal site, that  the material was  in contact  with  the
drinking  water aquifer of approximately 10 meters  in thickness and that
all  the water used on the site came  from that well. (In actual practice
the  drinking water sources  would be protected  from NORM contact.)  The
method  of calculation followed that presented by Till and Meyer,  (NUREG,
1983),  and assumed times short with respect to the physical half life of
226  Ra. The  calculation  assumed an effective  soil porosity of   .35, a
total  porosity   of  .4  and  a  distribution  coefficient of  2500.  The
magnitude  of  the release was assumed  to be the quantity of  Radium put
into solution by one year's rainfall and watering.

The  calculations for  the food  ingestion pathway    followed the  method
presented  by  Till  (NUREG,  1983a)  and   the  National  Commission  on
Radiation  Protection and Measurement  (NCRP,1984) with modifications  to
adjust  the calculations for spread material, wet  and dry deposition not
being  a factor. -The depth of the root zone  was assumed to be no greater
than twenty centimeters.  The concentration ratio used in the calculations
for  vegetable crops and forage was .001 pCi/kg plant per pCi/kg soil and
a  crop yield of one kilogram per square  meter was assumed. The transfer
factor  for meat  and  milk were  also  assume to be  .001 in appropriate
units.  The animals used  for  meat and milk were  assumed to drink water
from  the well on site and consume forage grown  on the site at the rates
specified by the NCRP-

It  was also  assumed  that 50 percent  of the vegetables,  meat and milk
products  consumed by  residents on  the site  were raised  at the  site.
Annual consumption figures for the exposed individuals were assumed to be
two  hundred kilograms of vegetable foods,  one  hundred kilograms  of meat
                                737

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and  meat products, and  three hundred  liters   of  milk and  milk products
(NCRP,1989).

                                 RESULTS

The  completed analysis for each disposal/remediation  option offers much
reason  for optimism with respect   to the environmental acceptability  of
on-site  NORM management. Final  maximum levels  in  the NORM layer  after
application  of the management option are presented  in tables 2 through 7
for  each case covered. Data for   the P and A well  case is not presented
because  there was no specific activity for  which this management option
produced a significant or measurable surface dose.

In  summary, land spreading appeared to  be an environmentally acceptable
option for rates of application less than 8,300  pCi/ft2.  This application
rate  is calculated by converting   the  final specific activity,   SA,  at  a
depth  d, to specific activity  per square centimeter (SA*d=  SA/cm2)  and
multiplying that number by 929 square centimeters  per square foot.

Similarly, shallow burial at three  feet appears  to be acceptable  when  the
application  rates  are  less than  9,200 pCi/ft2  for  a   one-foot  layer,
17,500  pCi/ft2 for a two foot layer and 25,000  pCi/ft2  for a three-foot
layer.

Burial of four foot of waste with  four feet of cover  as  in the closure of
a  production pit appears acceptable when application rates  are less  than
45,000 pCi/ft2.

Deep  burial does  not  appear to  be  as acceptable as  shallow burial at
depths less than 15 feet (457 centimeters). The maximum application rates
at  seven feet  (213  centimeters) of cover  are 1,100, 2,000,  and 2,400
pCi/ft2  for 3,  6,  and 9 centimeter  layers, respectively.  The  maximum
rates  of application with 10  feet (305 centimeter)  of   cover are  2,400,
4,700,  and 7,000 pCi/ft2 for  the same thicknesses of  application while
those for 15 feet are 11,000, 22,000 and 33,000 pCi/ft2.

The plug and abandon option for wells has been reviewed and  it is hard to
envision  any population dose  even  at the highest of  specific  activity
found once  the plug and cap are in place.

Review of the data in tables 2 through 7 indicates that  the  dose  criteria
that  most severely limits the acceptable final specific  activity and  the
maximum acceptable application rate is the 100 mRem from  all routes case.
The  dose plus  radon  case appears to  apply only for  cases where Radon
emission is maximized.
                               738

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                               CONCLUSIONS

These  analyses support the following conclusions with  respect  to  the  on
site management of NORM.

1.  All  the  management  options  studied  appear to  be environmentally
    acceptable.

2.  The use of the P and A well appears to be the most desirable disposal
    option.

3.  Surface spreading appears to be a viable option for site remediation.

4.  Shallow  burial  as  in the  remediation of  production pits  appears
    viable   in  humid  environments  but   of  limited  value  in   arid
    environments.

5.  Deep  burial is  not  a desirable option  where construction practice
    includes cellars.

6.  The use of the 100 mRem total dose criteria from all routes including
    Radon appears to offer the highest assurance of safety.
                                 739

-------
(API,1988)



(E&P.1986)

(NCRP,1975)


(NCRP,1984)


(NCRP,1984)


(NCRP,1989)


(NUREG,1983)


(NUREG,1983a)


(NUREG,198A)


(Smith,1985)
               REFERENCES

American Petroleum Institute Report, A  National Survey of
Naturally  Occurring Radioactive  Materials  in  Petroleum
Producing and Gas Processing Facilities,  7/89.

E & P Forum Report No  .6.6,127, 12/86,  Figure 2.

National Council on Radiation Protection  and  Measurements
Report 45, 11/75, p. 53.

National Council on Radiation Protection  and  Measurements
Report 76, 4/84, Chapter 4.

National Council on Radiation Protection  and  Measurements
Report 76, 4/84, Chapter 2 and Tables 2.12 and  2.13.

National Council on Radiation Protection  and  Measurements
Commentary No. 3, 1/89 Revision, Table  6.

NUREG/CR  3332,  Radiological  Assessment, A  Textbook on
Environmental Dose Analysis, 9/83, Chapter 4.

NUREG/CR  3332,  Radiological  Assessment, A  Textbook on
Environmental Dose Analysis, 9/83, Chapter 5.

NUREG/CR  3533,  Radon  Attenuation Handbook  For Uranium
Mill Tailings Cover Design, 4/84,  pp 2-1  to 2-4.

Smith  A.  L.,  OTC  5081,  Radioactive Scale   Formation,
presented   at  the   17th   Annual  Offshore   Technology
Conference, Houston, May 1985,  p.  3.
                                 740

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  TABLE 1: DOSE ENDPOINTS USED FOR STUDY
        25 mRem per year, internal plus external
             exposure excluding Radon.

     Time Weighed Average Annual Exposure to Radon
                 less than 2 pCi/l.

          Linear Combination of the Above:
        TOTAL DOSE/25 + RADON CONC/2 <*l

          100 mRem per year including Radon.
TABLE 2: IMPACT OF MANAGEMENT OPTIONS ON
    FINAL PERMISSIBLE SPECIFIC ACTIVITY
DEPTH
(CM) HUMID
(pCi/gm)
1
3
10
20
LIMITED
BY:
8.1
3.3
1.0
0.5
DOSE
SLUDGE
ARID
(pCi/gm)
8.7
3.3
1.0
0.5
& RADON
SCALE
HUMID ARID
(pCi/gm) (pCi/gm)
9.5
4.9
2.9
2.2
FOR 1 cm
9.6
4.9
3.0
2.2
SLUDGE
                FOR 1, 3,  and 10 cm SCALE
            100 mREM FOR ALL OTHER CONDITIONS
     SURFACE SPREADING OF SCALE AND SLUDGE
                741

-------
TABLE 3: IMPACT OF MANAGEMENT OPTIONS ON
     FINAL PERMISSIBLE SPECIFIC ACTIVITY

    DEPTH OF    SLUDGE           SCALE
    MATERIAL HUMID     ARID    HUMID     ARID
    (FEET)   (pCi/gm) (pCl/gm)  (pCI/gm)  (pCl/gm)
1
2
3
LIMITED
BY:



12.6
5.9
4.0

100
mREM
TOTAL
DOSE
0.34
0.31
0.30

100
mREM
TOTAL
DOSE
48.3
25.4
17.2

100
mREM
TOTAL
DOSE
1.50
1.35
1.31

100
mREM
TOTAL
DOSE
    BURIAL OF SCALE AND SLUDGE. 3 FEET OF COVER
TABLE 4: IMPACT OF MANAGEMENT OPTIONS ON
     FINAL PERMISSIBLE SPECIFIC ACTIVITY
    DEPTH OF     SLUDGE
    MATERIAL  HUMID    ARID
    (FEET)   (pCl/gm)  (pCi/gm)
          SCALE
       HUMID     ARID
      (pCl/gm)   (pCi/gm)
              3.03
0.40
13.1
1.75
LIMITED
BY:


100
mREM
TOTAL
DOSE
100
mREM
TOTAL
DOSE
100
mREM
TOTAL
DOSE
100
mREM
TOTAL
DOSE
    BURIAL OF SCALE AND SLUDGE, 4 FEET OF COVER
                 742

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TABLE 5: IMPACT OF MANAGEMENT OPTIONS ON
     FINAL PERMISSIBLE SPECIFIC ACTIVITY

    DEPTH OF     SLUDGE           SCALE
    MATERIAL  HUMID    ARID   HUMID    ARID
    (CM)   (pCl/gm) (pCl/gm) (pCl/gm) (pCl/gm)
3
6
9
LIMITED
BY:



4.5
3.9
3.7

100
mREM
TOTAL
DOSE
0.39
0.36
0.34

100
mREM
TOTAL
DOSE
19.3
16.9
16.2

100
mREM
TOTAL
DOSE
1.7
1.6
1.5

100
mREM
TOTAL
DOSE
   DEEP BURIAL OF SCALE AND SLUDGE, 213 CM COVER
TABLE 6: IMPACT OF MANAGEMENT OPTIONS ON
     FINAL PERMISSIBLE SPECIFIC ACTIVITY

    DEPTH OF     SLUDGE           SCALE
    MATERIAL  HUMID    ARID   HUMID    ARID
    (CM)   (pCl/gm) (pCl/gm) (pCl/gm) (pCl/gm)
3
6
9
LIMITED
BY:



136
135
135

100
mREM
TOTAL
DOSE
0.66
0.84
0.84

100
mREM
TOTAL
DOSE
186
186
185

DOSE
ft
RADON

3.8
3.7
3.7

100
mREM
TOTAL
DOSE
   DEEP BURIAL OF SCALE AND SLUDGE. 305 CM COVER
                743

-------
TABLE 7: IMPACT OF MANAGEMENT OPTIONS ON
     FINAL PERMISSIBLE SPECIFIC ACTIVITY

   DEPTH OF    SLUDGE          SCALE
   MATERIAL HUMID    ARID   HUMID    ARID
    (CM)    (pCi/gm) (pCi/gm) (pCl/gm) (pCl/gm)
3
6
9
LIMITED
BY:



188
186
184

DOSE
&
RADON

3.9
3.9
3.9

100
mREM
TOTAL
DOSE
184
183
183

DOSE
&
RADON

17.1
17.1
17.1

100
mREM
TOTAL
DOSE
  DEEP BURIAL OF SCALE AND SLUDGE. 457 CM COVER
            744

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PILOT BIOREMEDIATION OF PETROLEUM CONTAMINATED  SOIL
Julian  M.  Myers
Michael J.  Barnhart
Waste Stream Technology,  Buffalo, New York

ABSTRACT

Bioremediation of various petroleum hydrocarbons   occurred during
a four  month period at the Carlow Road, Port Stanley  site.
Intensive   biological  and  physical  operations   resulted  in  a
decrease of all contaminants which were  monitored including BTEX
compounds,  Oil  and Grease,   and Polycyclic Aromatic   Hydrocarbon
compounds.   Percentage reduction  of 2 and 3  ring, 4 and  5  ring
PAH1s decrease as molecular weight increased.

is_  INTRODUCTION

The  Carlow  Road site  is  located within  the   Village   of Port
Stanley, Ontario,   Canada and is  a former oil  gasification site
utilized from the  1920's to the 1950's. A  by-product  of  the oil
gasification process was a tai—like material  (oil  tar) which was
stored  in   two open pits  on site.  In  1970, these  two  pits were
filled  in   with material  dredged from Port  Stanley  Harbour  and
subsequently resulted  in the spreading of the  oil tar over site
surface soils.

Approval from the  Ministry of the Environment  (MOE)  for  a waste
processing  site at  the Carlow  Road property  was based   on the
pilot-scale, on-site  remediation  of approximately   4,800  cubic
meters  of  oil tar contaminated soil.

The purpose of the pilot project was to demonstrate that:

1) during   bioremediation, all emissions  from the  site  could be
controlled to acceptable levels;

2) the  PAH concentrations  could be reduced to acceptable   levels
(through  visual  inspection,   analytical  testing  and  leachate
extraction testing);

3)  bioremediation could  be undertaken in a  reasonable time
frame;  and

4)   bioremediation could  be undertaken in  a cost effective
manner.

A three  party consortium was  assembled to address   the project.
Conestoga   Rovers  -and  Associates  (CRA  -  Waterloo, Ont. )   was
retained by  the client to  provide engineering   services  and  to
provide a   technical  review and  performance  assessment  of  the
biodegradation   technique.        Sevenson   Environmental    Ltd.
                                  745

-------
(Burlington, Ont.)  provided all  construction,  health and safety,
and associated services.  Waste Stream  Technology,  Inc.  (Buffalo,
N.Y.)  provided bioremediation technology  and  expertise.

The pilot  scale bioremediation construction  commenced  in August
1988   and  consisted  of   securing  the   site,   preparing  the
bioremediation area to accept contaminated  material,  excavating
the contaminated soil and biological  treatment  and  tilling of the
oil tar contaminated soil.

The  contaminants  identified  at  this   site  include   Benzene,
Toluene,   EthyIbenzene,  Xylene   (BTEX),    Oil   and  Grease,   and
Polycyclic  ftromatic Hydrocarbons  (PftH's).  ft  complete analysis of
a "pure" oil tar sample Mas performed by  Ecology and  Environment,
Inc.

   Review of Literature - Biodegradation  of Polycyclic ftromatic
                           Hydrocarbons

ft   large  volume   of  literature    exists  pertaining    to   the
environmental fate and  biodegradation  of  PflH's, with  Petroleum
Microbiology  (1984, Macmillan  Publishing  Co.,  New  York,   NY)
representing one of the most  recent  and  comprehensive reviews of
information available on  work in this  area. The author  reviews
the  biodegradation  of  aromatic hydrocarbons,   emphasizing   the
enzymatic  mechanism used  by microorganisms,   and  indicates   the
similarities  and differences  between  microbial   and —mammalian
metabolism of aromatic hydrocarbons,  shared by  most microbes  that
have been studied.

Bacterial degradative pathways  for aromatic  hydrocarbons  ranging
from benzene to  benzo(a)pyrene  are presented in this reference.
Extensive  lists of  bacterial  species   having  demonstrated   the
capability to degrade aromatic hydrocarbon  to various degrees  are
also provided, and the  information available shows that  various
genera   and  species  of   bacteria  are  capable   of  complete
mineralization of PftH' s. In  all cases, biodegradation rates   are
shown  to  be  proportional  to  solubility,  with  growth   on   an
alternate substrate required for degradation  of   the  higher,  more
hydrophobic ring structures.

II.  METHODOLOGY
                          Mobi1izat i on

The 500'   by  200' biotreatment  facility  was  constructed using
three 15  cm lifts of clay compacted  after  each  lift  resulting in
a permeability of 10  to the minus seven  cm/sec.  Clay faced berms
surrounded   the  biotreatment  pad   completing   the   containment
facility, ft total  of 7,536 cubic meters  of clay was used in  the
construction  of  the clay  liner.  ft clay  dike was  erected to
provide a water  storage area for site dewatering (100'  X 200').
                                    746

-------
The on  site   presence of Waste  Stream personnel  began  on August
22,   1989.   fit   this  time   the  WST  trailer  containing   four
bioreactors  Mas positioned parallel to the treatment  area.

Necessary  Mater  and  electrical  supplies  Mere   connected  and
application  of   odour suppressant began as soil   Mas  added to the
containment/treatment facility on  August 26. Initial  application
of bacteria  Mas made on August 30.

                       Grid and Zone Layout

The clay bioremediation area (400' X 200')  Mas   delineated using
wooden  stakes  placed at ten foot intervals  along  the berm.  This
resulted in  800 grids.  Twenty  zones Mere established  by  grouping
40 grids in   each,  to facilitate  soil sampling and   to represent
the  area.   The  zones  Mere  grouped  into  four   quadrants   for
convenience  of  bacterial application.

                        Health and Safety

A health  and safety  plan  designed to  provide a  safe   working
environment  for on site personnel and to prevent the  migration  of
potentially    contaminated   soil   from   the   excavation   was
implemented.  Prior to  hazardous excavation  activities,  "clean"
areas and  "work" areas were  designated.  Within the   confines  of
the "work" areas, a full health and safety program was  in  effect.

                          ftir monitoring

The air monitoring  program was instituted  to ascertain the  air
quality   at  the  site   during  excavation   and  treatment   of
contaminated  soils.  The  program  consisted  of  real time  air
monitoring,  and air quality sampling and analysis. For  evaluation
purposes,  the  Ministry  of Labour   (MOD   Air Quality  Threshold
Limits  were  used. Five  air monitoring stations were   established
in, around,  and downwind of the bioremediation area.

                            Excavati on

Excavation of the oil tar contaminated soil began at   the  western
most portion of a  pit closest to the  biopad.  The material  was
marbleized in  appearance  and  pockets of  "free   product"   were
encountered.   Excavation  proceeded  to the  water   table   (clay
layer)  at  approximately 17'.    The material  Mas transferred   in
lined dump trucks to the biopad.
                                    747                       uwsnsnom

-------
                       Sanpling  Procedure

The sampling regime was  relatively  intensive as a  demonstration
effort under the  pilot program.   There was an  initial sampling
round after approximately  4,800 cubic meters of  soil was placed
in the bioremediation facility,   prior to  any nutrient/bacterial
application.  There  were  four   subsequent  sampling  rounds  at
approximately  two  week   intervals.   Sub-samples  were collected
randomly within each  grid zone,  by   using  nodes,  and  at various
depths within  the soil column   to form composite  samples.  Round
one consisted  of 63 composite soil  samples  and round 4 included
20 soil samples. Round  1ft was composed of 11 grab samples,   and
rounds 2  & 3 contained 39 samples each. Samples were taken  using
a split  spoon sampler.  The  sampler   was thoroughly  rinsed,  and
dried, so that no soil remained   on  the sampler.  The samples  were
chopped and kneaded to ensure as homogeneous sample  as possible.
It was then properly stored and  preserved,  recorded on  the  chain
of custody  log, and shipped to the appropriate laboratory.

               Nutrient and Bacterial  Application

The excavated  soil was prepared for  bacterial application by  the
addition of nutrients, ft nitrogen source for bacterial growth  was
applied  to  supplement  the   nutritional   requirements  of   the
bacteria  being used. This was usually applied by  dissolution in
400   gallons of  water  (dictated by   soil  moisture  levels),  and
sprayed on  the soil. Nutrient was applied,  as dictated by results
from  soil tests throughout the treatment period.

The   bacterial  suspension    was prepared   including   nutrients
sufficient  for  their  rapid    growth.  Bacterial   batches  were
generally   started on  one day,   with  populations   brought up   to
application  levels overnight,   and   applied  the  following  day.
Bacteria  was applied approximately   four days  a week throughout
the treatment period. This application consisted  of 1200 gallons
of  bacterial suspension, which   consisted  of approximately  one
third cell  mass yield. The suspension  was applied through a high
pressure distribution system  to  the  soil.

                         Soil Conditioner

Soil  conditioner was applied  as  an odour suppressant as  soil  was
placed into  the containment/treatment facility.   The conditioner
was   also  used   as  a   contaminant emulsifier   in  nutrient
applicat i ons.

                              Till ing

The soil was tilled on a daily basis  to promote homogenization of
                                    748

-------
the soil  and  to  increase the amount  of  oxygen  available to  the
nicroorganisms.  The equipment achieved  a total  tilling depth  of
24".   This  achieved  a more favorable   soil  matrix   by increasing
porosity  and  decreasing aggregate size. The  depth  of the  soil in
the facility   rose  from 25"  when it   was first   leveled in  the
facility  to 33" as a result of the tilling operation.  The tilling
also achieved  a  high degree  of  mixing the  nutrient/bacterial
applications.  These  factors combined,  resulted  in  an  environment
favorable  to bacterial  growth,   maturation,  reproduction,   and
subsequent  degradation of the waste.

III.  DATA
                     Soil Nutrient Test Data

Soil  testing  for  macronutrients  available  in   the  soil   was
performed.  Data  was  collected for  six  macronutrients and   pH:
nitrate  nitrogen,  phosphorous,    potassium,  ammonia  nitrogen,
calcium,  nitrite nitrogen.   fill of these  nutrients  are vital   to
the growth  of the bacteria and are thus carefully monitored.  Soil
sampling  began as early as Hay 27, 1988.  Weekly  sampling began on
August 31,  1988 and  the final soil test  sample  was  collected on
January 10, 1989.

             Summary of Bioremediation  Work Performed

Each day  on site was recorded in a daily  log, along  with the  work
performed on the  site. Work categories   and the total   number of
each are: samples collected (245), bacterial  colony counts  (32),
soil  tests (53),  27  bacterial  applications   (35400  gallons),
nutrient  applications  (15), times tilled  (28) and other site  work
performed such as mobilization and excavation.

                    Analysis of Soil Samples

Analysis   of soil  samples for  BTEX  compounds was  performed by
Novalab,  Lachine, Quebec, using EPA Method 8240.

Analysis   of soil  samples for  oil and   grease was  performed by
Waste Streams in-house laboratory using EPA Method  9071.

Analysis  of soil samples for PAH's was  performed primarily by
Flow laboratory, McLean,  Virginia,  using EPA Method 8310 and by
Novalab using Method 8270.

Extraction   of  selected  soil   samples  was  performed  by    an
independent engineering firm using Ontario's Regulation 309.
                                                             UMSTESTPEdni
                                     749

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IV.  . RESULTS
                   Initial Statement  of  Results

Application  of  the  soil  conditioner   agent   resulted  in  the
immediate    suppression   of     odours    emanating    from   the
containment/treatment facility.

P qualitative but  significant  observation can  be made  about the
progress of the  bioremediation  of  the  soil.  Visual appearance of
the  soil in  the bioremediation  area  progressed  from black  to
brown  during  the  treatment   period   and  olfactory   detection
decreased markedly.

                   Soil Nutrient  and  pH  Levels

Graphs were produced which represent  macronutrient   and pH levels
over  the length of  the treatment  period.   Results indicate that
all soil nutrient  levels were  sufficient   and  utilizable by  the
bacteria for rapid and sustained  growth.

The pH  levels fluctuated between 6.0 and   7.5,  the average  being
7.0. This is optimum pH for bacterial growth  and maturation.

                     Soil Temperature Profile

Soil temperature (at  a depth of  0.62 m) dropped  from 19 degrees
Celsius to 12 degrees in the period of 35  days.  This is important
information   when  interpreting    the   bacterial   growth   (and
Mortality)  curve.   ft  direct   correlation  nay  be made   as  the
temperature decreases, so does  the  bacterial  population.

                     Bacterial  Colony Growth

Graph  1 illustrates the  establishment  and  subsequent growth of
the microbial organisms in the  soil matrix.  This graph represents
successive additions of bacteria  throughout the treatment period.
Each data  point is an average   of  four  soil  samples  checked for
bacterial presence and enuneration.  The bacterial  population was
firmly established  by early September and reaching  a maximum of
3.39  X 10  to the  forth colonies  per  ml  of  solution,   in soil
samples taken on September 23.

This  curve  is  very  similar   to  the  classic Monod  bacterial
population  growth curve, rising  exponentially,  peaking  and then
decreasing   exponentially.  This   indicates  that   the  entire
remediation  area   exhibits  typical   bacterial   colony  growth
characteristics. The decline in  the level  of biological activity,
in this case, was clearly due to  the decrease in soil and ambient
temperature.
                                                             UMSII
                                      750

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                   Volatile Aromatic Compounds

Twenty  -  two   samples    were  analyzed  for  volatile    organic
compounds.  Relatively  low levels of these compounds were  present
at   the  onset   of  bioremediation,   however,   this   class   of
contaminants was  greatly  reduced by the end of the  project.

                    Oil and Grease Levels

Twenty  samples were analyzed for round one and twenty samples  for
round four.  Initial  maximum levels exceeded 5,000  ppm.  The test
method  used   includes   extraction  of  biological   lipids   and
therefore was not  an  accurate indicator of degradation.

          Total  Polycyclic aromatic Hydrocarbon Levels

Graph 2  represents the Total PftH levels  from the  initial to  the
final sampling.  The  graph illustrates four sampling rounds and  a
minimum of 20  samples  per round. Initial Total PAH levels in  the
soil  samples  were  measured  prior  to  the  beginning   of   any
bioremediation effort.  Maximum levels exceeded  3,000 ppm  (TPAH).
Round four samples indicated an average level of approximately 45
ppm. TPAH compounds.

                     Two  and Three Ring PAH's

Graph 2 also  illustrates  the biodegradation of two and three ring
PAH1 s.  Two ring  compounds include  Naphthalene, Acenaphthylene,
ftcenaphthene,  and  Fluoranthene.  Three  ring  compounds  include
Phenanthrene,  Anthracene,  and Fluorene.  Maximum levels of these
compounds approached two  thousand ppm. initially and were  reduced
by more than 90* during the bioremedation period.

                         Four Ring PAH's

Four ring compounds include Pyrene, Chrysene, Benzo(a)anthracene,
Benzo (b) fluoranthene,   and Benzo(k)fluoranthene.   Maximum  initial
levels  were one  thousand  ppm. for round one  and decreased by  80S
in the  soil samples analyzed in round four.

                         Five Ring PftH's

Five ring compounds  include Indeno(1,2,3)pyrene, Benzo(a)pyrene,
Dibenzo(a,h)anthracene,     and     Benzo(g,h,i)perylene.    These
contaminants were reduced by approximately 65S over the  course of
the bioremediation project.
                                                             UMSTESTREdm

                                        751

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                      Benzo(A)Pyrene  Levels

Benzo(a)Pyrene  was   of  particular    concern  because   of  its
persistent nature and toxicity.   Initial  maximum levels of  B(a)P
approached 70 ppm. This compound  exhibited a reduction of greater
than &0S which coincides with the  degradation of other  five ring
PAH' s.
                         Leachate  Results

The results  of the analysis of water  samples prepared,using the
leachate  extraction procedure in   Regulation 309  of the Ontario
Environmental Protection Act, indicated that there  were no B(a)P
contaminants present  in  the extract.  This  indicates that  any
B(a)P,   which may have had the potential   to leach from the soil,
apparently did not.

V._  DISCUSSION
                        Summary of  Results

Biodegradation of various petroleum hydrocarbons  occurred during
a 4 month period at the Carlow Road,  Port  Stanley site.  Intensive
biological and  physical operations resulted in  a decrease of all
contaminants  which were monitored  including BTEX compounds,  Oil
and Grease, and  Total PAH compounds.  Percentage reduction of 2
and 3 ring,  4 and 5 ring PAH1s decrease   as molecular weight  and
number  of rings increases.

        Review of Purpose of Bioremediation Pilot Project

This  section addresses  the four  points   pertinent  to  the pilot
bioremedlation.

1)  During  bioremediation can  all   emissions from   the   site be
controlled to acceptable levels?

Excavation of oil tar contaminated  soil resulted in  localized  air
quality   impact  within  the   immediate   work   space.   Volatile
compounds Benzene and Naphthalene  were measured  above Ontario  MOL
threshold   values.   Workers  were   protected    by  appropriate
respiratory equipment. Bioremediation  of  the soil did not impact
air quality within the work area above the limits.  Activities  did
impact  on-site air quality  as demonstrated  by sampling  results
for dust,  BTEX1 s,   and PAH's which  were  all below  MOL threshold
levels.

2) Can  the PAH concentrations be reduced  to levels as established
by  the MOE  including visual  inspection,  analytic   testing,  and
leachate extraction testing?
                                                             UWSTI

                                    752

-------
Criteria  set  forth in  the MOE letter   of  concurrence was met  as
presented:
                     MOE Criteria             ftnalytic Results

Total  PftH in  soil        100 ppm                   45.4 ppm

B(a)P  in  soil               10 ppm                  3.8 ppm

B(a)P  in  leachate          <0. 1 ppb                  ND  (0.01)

3) Can bioremediation be undertaken  in  a reasonable time frame?

Yes, contaminant  levels were reduced by an  average of  65S during
the four  month treatment period.

4) Can bioremediation be undertaken  in  a cost  effective manner?

It appears  that  bioremediation  can  indeed  be   done in  a  cost
effective  manner.  It  is  a  technology   which  is  economically
attractive as compared to other  options such  as  landfilling  and
incineration.  Bioremediation offers  a  permanent   solution to  an
environmental hazard.
                                                             UMSTESTDEdm

                                      753

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                           REFERENCES
Aaronson, Sheldon  1970. Experimental Microbial  Ecology.  Acedemic
     Press. New York.

Atlas,  Ronald  M.    1984.  Petroleum   Microbiology.  Macmillan
     Publishing Company. New York.

Sergey's Manual of Systematic Bacteriology  Volumes  I & II.  1984.
     Editors: Noel R. Krieg and John G. Holt. Williams *  Wilkins,
     Baltimore.

Brown, K.W.,  Evans, G.B. Jr., and Frentrup, B.D.   1983. Hazardous
     Waste Land Treatment. Butterworth Publishers, Boston.

Dragun, James   1988. The Soil Chemistry of Hazardous Materials.
     Hazardous Materials Control Research Institute, Maryland.

HANDBOOK of CHEMISTRY and PHYSICS  1972-1973.    53rd Edition. The
     Chemical Rubber Company.

HANDBOOK of MICROBIOLOGY  1987.  2nd Edition. Volume I: Bacteria.
     Editors: Allen  I. Laskin,  Ph.D. and Hubert A. Lechevalier,
     Ph.D. CRC Press, Inc. Boca Raton, Florida.

Hattori, Tsutomu   1988.  The Viable Count: Quantitative and
     Environmental Aspects. Science Tech Publishers, New  York.

Keith, Lawrence  H.  1988.  Principles of Environmental Sampling.
     American Chemical Society Professional Reference Book.

Manual of  Industrial Microbiology and Biotechnology  1986.
     Editors: Arnold  L. Demain  and Nadine  A.  Solomon.  American
     Society for Microbiology, Washington, D.C.

Particulate  Polycyclic  Organic  Matter    1972.    Committee on
     Biological  Effects  of  Atmospheric   Pollutants.   National
     Academy of Sciences, Washington, D.C.

Pucknat,   A.W.     1981.    Health Impacts of Polynuclear  Aromatic
     Hydrocarbons. Noyes Data Corporation.

Rochkind-Dublnsky, M.L.. Sayler, G.S., Blackburn,  J.W.  1987.
     Microbial Decomposition of Chlorinated Aromatic Compounds.
     Marcel Dekker, Inc. New York.

Verschueren, Karel  1977.    Handbook  of  Environmental   Data on
     Organic Chemicals. Reinhold Company, New York.
                               754

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 Bacterial Growth  in Port Stanley)
1BOT	
    8/31 9/09 9/16  9/23  9/30 10/07 10/14 10/21
                     Date

                    g RAP ft 2
  Polycyclic  Aromatic Hydrocarbon
           Reduction in Foil Stanley
                13
                Days of Treatment
Total PAH
Ring  -»~ 4 Ring PA
5 Ring PA
                    755

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POLICY AND REGULATORY IMPLICATIONS OF COAL-BED METHANE DEVELOPMENT
IN THE SAN JUAN BASIN, NEW MEXICO AND COLORADO


Chris Shuey
Director, Community Water Quality Program
Southwest Research and Information Center
Albuquerque,  New Mexico, USA


Abstract

An upsurge in the development and production of coal-bed methane in the San Juan Basin of
northwestern New  Mexico and  southwestern Colorado  has  coincided  with the discovery of
extensive natural gas contamination of an alluvial aquifer in the Animas River valley of the basin.
Studies conducted by state and federal agencies in the past 18 months indicate that the production
of natural gas from deep coal  seams is at least  partially  responsible  for  the presence of
thermogenic gas in private domestic water wells, in alfalfa field seeps, at the surface casings and
Bradenneads  of gas-producing wells, and in cathodic protection holes in a 25-mile stretch of the
river valley. This paper summarizes the scientific data that implicate the production  of coal-bed
methane in the contamination of fresh waters in the area. Water quality ana  gas composition  data
reported by state and federal agencies ar€  reviewed. Methods used to identify the stratigraphic
origin  of the migrating gases are summarized. The mechanism by which coal-bed  methane
migrates upward nearly 3,000 feet to ground water is  described. The scientific evidence is
correlated with local residents' accounts of the onset of "gassy" water in domestic wells in the
region. Regulatory actions taken by state and federal agencies to address the gas-migration
problem are reviewed. Volumetric and chemical characteristics of water produced from the coal
seams of the Upper Cretaceous Fruitland Formation are reported and compared with similar  data
for conventional sandstone gas reservoirs in the basin.

New policies and regulatory initiatives are needed to prevent further gas migration and to address
the unique problems posed by production of natural gas from  coal seams. Multijurisdictional
planning,  cumulative environmental  analyses, cementing of existing gas-producing  wells,  pre-
lease environmental audits, and temporary moratoria on new leasing are suggested. A corrective
action  and compensation  fund  to remediate contaminated ground water  and to compensate
property owners for damages is recommended.

Introduction

Development and production of coal-bed methane has increased dramatically in 13 major geologic
provinces in the United States in the  1980s.(l) Once considered a "nuisance" by drillers(2) and a
lethal hazard for coal miners, coal-bed methane today is sought for its energy potential  and
because it qualifies for federal tax credits as a nonconventional fuel.(3) Two-thirds of the nation's
coal-bed methane resources are located in five Rocky Mountain states. (Table  1) With an estimated
88 trillion cubic feet of coal-gas  resources, the San Juan Basin  (Fig. 1.) of northwestern New
Mexico and southwestern Colorado leads the nation in  coal-bed methane reserves. The expiration
of the tax credits on December 31, 1990, coupled with the opening of gas markets in California and
the Pacific Northwest, has fueled extensive  exploration and development  programs by several
major gas  producers in the San Juan  Basin in the past  decade. Between  October 1987  and  May
1990, more than 900 coal-bed methane wells were permitted on  U.S. Bureau of Land Management
(BLM) lands in the New Mexico portion of the basin.(4)  State  and federal officials estimate  that
1,200 wells will be approved by regulatory agencies in New Mexico in 1990,  with approximately 700
wells being completed this year alone.(5) Several hundred more coal-bed methane wells have been
approved lor drilling or are planned on private, state, federal (BLM and U.S. Forest Service), and
Southern Ute Indian lands in the Colorado portion of the basin.(6)
                                           757

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                                         TABLE 1

                            Coal-bed methane reserves of the UJ3.
                            (in trillions cubic feet of natural gas)

              San Juan Basin (northwestern N.M.-southwestern Colo.)         88
              Piceance Basin (northwestern Colo.)                            84
              Northern and Central Appalachia                              66
              Powder River Basin (northeastern Wyo.-southeastern Mont.)      39
              Green River Basin (southwestern Wyo.)                         31
              Western Washington Basin (Wash, state)                        24
              Illinois Basin (northern Illinois)                                21
              Black Warrior Basin (western Ala.)                             20
              Raton Mesa (northeastern N.M.)                                18
              Arkoma Basin (southeastern Okla.-southwestern Ark.)            4
              Wind River Basin (central Wyo.)                                 2
              Uinta Basin (northeastern Utah)                                 1

              Source: Oil and Gas Journal. October 9,1989, 50.


Natural gas from coal seams of the Fruitland  Formation was first tapped on an experimental
basis in 1952. Thirty different coal-gas pools were created in the basin before 1980, but large-scale
development of the Fruitland gas  reserves never materialized in that  three-decade period.(7)
During that time, coal-bed gas was virtually ignored because of its low heat content, its propensity
to cause gas-well blowouts, and the fact that nundreds of thousands of barrels of produced water
must be pumped off the coal seams before production of the gas can reach profitable levels. By the
mid-1980s, a handful of companies began coal-bed methane development programs in order to take
advantage  of the tax credits that were authorized by the  Crude Oil Windfall Profits Tax Act of
1980.(8) The amount of the credit  escalated each year, and  by 1987 had reached 78 cents per
thousand  cubic feet (MCF) of natural gas. Today, in an era of surplus natural gas, coal-bed
methane producers receive more income from the tax credit than from the sale of the gas.(9)

Coincidental with the upsurge in coal-bed methane production in the basin in the 1980s was an
increase in the number of complaints of water contamination among residents of Cedar Hill, New
Mexico, and Bondad, Colorado.  (Fig.  1.) Those complaints led officials  of the New Mexico Oil
Conservation Division (NMOCD) to collect water samples from private wells in the transboundary
area. The  presence of organic vapors  in  about 30 percent  of  the  water samples and the
identification of Fruitland coal gas in three private wells in  Bondad  confirmed that deep-formation
gas had  migrated into the shallow alluvial aquifer of the  river valley.  These findings have
prompted citizens groups in the area to request cumulative environmental assessments of coal-bed
methane development prior to further leasing actions by state and federal agencies.(lO)

Summary of the Scientific Data

The scientific evidence  that links coal-bed methane development to contamination of fresh ground
water in the Animas River valley includes:

•      Analytical data for more than 250 samples of water from nearly 200 different domestic
       water wells in the region;
•      Chemical and carbon isotopic  composition data for 48 gas  samples collected from water
       wells, gas seeps in  fields and in the Animas River, the  surface casings and Bradenheads of
       gas-producing wells, and cathodic protection holes adjacent to producing  wells; and
•      Previous studies on the genesis  of natural gas and  the techniques For identifying the
       geologic origin of natural gases.

Interviews with 15 different long-time residents of the communities of Aztec  and Cedar Hill, New
Mexico, and Bondad, Colorado, were conducted to obtain anecdotal accounts of the presence of gas
in the alluvial river valley. Information from those interviews supplements the scientific data.
                                         758

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Fig. 1. Map of the San Juan Basin showing major structural elements and population centers. Coal-bed
methane production is concentrated in the northern flank of the basin around Ignacio and Bayfield in
Colorado, and Cedar Hill and Navajo Lake in New Mexico. Adapted from Rice, etal. (1989).


WATER QUALITY DATA. Analytical data for water samples collected by NMOCD from private
water wells in the Bondad-Cedar Hill-Aztec area since early 1985 were gathered from the agency's
files and assembled for this paper.(ll) Table 2 shows a statistical analysis of the results. About 30
percent of the samples (57 of 187) tested positive for organic vapors. Of those, 47 samples (or 25
percent of the total) exhibited concentrations greater than 10 parts per million (ppm). Twenty-two
samples from 17 different wells had concentrations of organic vapors of 1,000 ppm or greater. Four
of 32 wells tested for explosivity registered 100 percent of the lower explosive level.  As shown in a
map of the study area (Fig. 2), most of those wells are located in a 10-mile stretch of the river valley
between Bondad and Cedar Hill. Trace to parts-per-billion levels of aromatic volatile organic
compounds (VOCs) were detected in 27 of 79 samples; the highest single concentration was 31 ppb
of benzene in a well in Cedar Hill.

GAS SAMPLE ANALYSES. Nearly 50 samples of gas were collected by state and federal agencies
from a variety of sources and sites in the Cedar Hill and Bondad areas in 1989. NMOCD collected
24 gas samples in the Cedar Hill area from the Bradenheads (annular spaces) on 10 gas-producing
wells, from nine  cathodic protection holes, at the surface casings of two gas wells, from a tank
discharge value, a river seep, and a seep in an alfalfa field. Personnel from the U.S. Geological
Survey (USGS) and Colorado Oil and Gas Conservation Commission (COGCC) collected 24  gas
samples in the Bondad area from the wellheads at 10 gas-producing wells, from the Bradenheads
at five gas wells,  from five domestic water wells, from a seep in the Animas River, from a  gas
pipeline, from a seismic hole, and from an abandoned gas wen.  Results  of chemical and isotopic
analyses for the 48 gas samples were reported by USGS petroleum geologist Dudley D. Rice in
letters to COGCC and NMOCD.(12),(13)
                                          759

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                                         TABLE2

                         Statistical summary of water quality results,
                       Animas River valley, New Mexico and Colorado
                                         1985-1990
             (all samples and results from files of N.M. Oil Conservation Division)

Total number of samples collected, both states                                            254
Total number of water wells sampled, both states                                         195
Number of wells sampled in New Mexico                                                 173
Number of wells sampled in Colorado                                                     32
Number of wells sampled at least once for organic vapors, both states                       187
Number of wells testing positive at least once for organic vapors, both states                  57
New Mexico wells testing positive at least once for organic vapors                            48
Colorado wells testing positive at least once for organic vapors                                9
Number of samples showing organic vapors                                               70
Mean organic vapor concentration, in parts per million (n=70)                       447.91450.7
Range of organic vapor concentrations, in ppm                                       1 to 1,450
Number of wells with organic vapor concentration >1,000 ppm                               17
Number of wells with organic vapor concentration 10 ppm < x < 999 ppm                    30
Number of wells with organic vapor concentration <10 ppm                                 10
Number of samples screened for aromatic VOCs                                          79
Number of samples testing positive for aromatic VOCs                                     27
Range of aromatic VOC concentrations, in ppm                                       0.2 to 31
Number of wells tested for explosivity, both states                                         32
Number of wells testing positive for explosivity                                            10
Number of wells testing >5% lower explosive limit                                          7
Number of wells testing 100% lower explosive limit                                         4


For  the  gas samples collected near Cedar Hill,  Fruitland  Formation  coal-bed methane was
identified as the gas in  four of the 10 annular spaces, in three of the nine cathodic protection holes,
at the surface  casing  of one gas-producing well,  and in one tank discharge. All of the wells
identified as being charged by Fruitland gas produced from  the deeper Mesaverde and Pictured
Cliffs formations. Hydrocarbon chemical compositions of gas  seeps from an alfalfa field and from
the banks of the Animas River were suggestive of coal-bed methane, but  the  carbon isotopic
compositions of the gases were lighter than those typically  associated with Fruitland coal gas.
Gases from the Mesaverde and Pictured Cliffs sandstones were found  in four cathodic  protection
holes, in the annular spaces of four wells that produce gas from those deeper formations, and at
the surface casing of a Mesaverde well.(14)

For the gas samples collected near Bondad, Fruitland Formation coal gas was identified in three of
five domestic wells. (Fig. 2.) A combination of different thermogenic gases which may have been
altered by bacteria in the alluvial aquifer was detected in two domestic wells on the same property.
Fruitland coal-bed methane was detected at the Bradenhead of one producing Mesaverde well.
Deeper formation gas was identified  in the annular  spaces of the four other producing wells, in the
abandoned gas well, and in a seep from the Animas River. The origin of gas in the seismic hole
was not identified.(lS)

GENESIS OF THE GAS.  The geologic origin of natural gases can be determined by analyses of the
chemical and carbon isotopic compositions of gas samples. In the past decade, extensive research
has been conducted to identify the chemical and isotopic  signatures of natural gases in the
northern  San Juan Basin(16),(17) The  methods  used can  determine with a  high  degree of
confidence the thermal  maturity of the gas and its geologic host rock.

Gases from  the Fruitland Formation coal beds has been interpreted to be thermogenic, having
intermediate to high levels of thermal maturity.(18) They tend to be dry, i.e., the ratio of methane
(CH4) to heavier hydrocarbon gases is usually greater than 0.99. This ratio is called the "methane
fraction" and is denoted by the expression Ci/Ci.5, which is the concentration of CH4 divided by the
                                          760

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      ANIMAS  RIVER VALLEY

   NEW  MEXICO  AND COLORADO
                              b Durango
                                             COLORADO
                                                         BONDAD
    11W
 10W
                                     _i_       33N

                                 9W   8W    32N
           Southern Ute
          Indian Reservation     ,

           12W '  11W
                                                US55CT
                                                         33.

             10W
                                                                  9W
 NEW MEXICO
                                                                            Navajo Lake
                                                       CEDAR HILL
              -f-
                                                        32N
                                                        31N
     N\
                                            Scale: 1 Inch
                                           equals 2.9 miles
                          /J
        FLORA VISTA
                          AZTEC
NM44
 • <100 ppm organic vapors

 • 100-999 ppm organic vapors

 • >1000 ppm  organic vapors

Q 700%  of lower explosive level

Q/so/op/c composition Indicates coal-bed methane
                                                                                     31N
                                                                                     SON
Fig. 2. Map of study area depicting 50 of 57 domestic wells that show indications of contamination by
natural gas. Well locations are not exact. Map based on U.S. Geological Survey 7.5-minute quadrangles.
sum of the concentrations of methane, ethane IX^He], propane [CaHg], butane [C4Hio], and pentane
[CsHi2). "Wetter" gases have  a methane fraction between  0.85 and 0.95 and usually are
accompanied by much larger volumes of liquid hydrocarbon condensate. Coal-bed methane, on the
other hand, is accompanied  by little or no liquid hydrocarbons,  especially in the northern part of
the basin where the Fruitland Formation coal beds are deeper, have higher thermal maturities,
and are  under greater pressures. Coal-bed methane from the Fruitland also contains significant
amounts of carbon dioxide, often  as much as 6 percent.
                                          761

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Carbon isotopic compositions also are used to identify natural gases. Microbial, or biogenic, gases
consist primarily of CH4 that is depleted in the carbon isotope, 13C. Gases in ground water in
southern Weld County in north-central Colorado were found to be enriched in the  lighter carbon
isotope, 12C, meaning  they have  been generated as a  result  of biological  and  microbial
decomposition processes at low temperatures and pressures.(19) Thermogenic CH4  is heavier, i.e.,
it is enriched in the  13C isotope. Stable carbon isotope ratios are expressed in S-notation per
thousand  (ppt) deviations, relative to the Peedee belemnite marine  carbonate standard.(20)
Biogenic gases generally have A13Ci (21) values that are more negative than -55 ppt; thermogenic
gases have Al3Ci values in  the range of-55 ppt to -35 ppt.(22) Gases from the coal seams of the
Fruitland  Formation have Al3Ci values ranging from -40.5  ppt to -43.6 ppt.  Figure 3  shows the
relationships between gas thermal maturity, methane fraction, and carbon isotopic compositions
and  graphically depicts the  nature of coal-bed methane  as  a  dry, isotopically heavier, arid
thermally mature gas.

Based on these factors, gases detected in domestic wells,  alfalfa fields, river seeps, cathodic
protection  holes, and annular spaces of gas-producing wells  in Bondad and Cedar  Hill  were
interpreted as thermogenic.(23) About half of the gases detected in domestic water wells and in
field and river seeps were reported to originate from the Fruitland coal beds.(24) Fruitland gas also
was found to be charging the Bradenheads and surface casings of several deeper gas wells.
                       IT
                       UJ
                                                               •20
                                                             0.7
Fig. 3. Graph depicts the relationships between gas thermal maturity, methane fraction, and carbon
isotopic compositions. Adapted from Rice et al. (1989), 611.
ANECDOTAL ACCOUNTS OF LOCAL RESIDENTS. The communities of Cedar Hill and Bondad
are populated by multigenerational families, many of which have  depended on farming and
ranching for economic sustenance. Several of the families are headed by "old-timers" who were
born in the  area or  moved there shortly after the turn of the century. Interviews were conducted
earlier  this year to obtain the residents' accounts of gas migration in the Cedar Hill-Bondad
area.(25 The following is a summary of those accounts.
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Most of the residents agreed that their observations of gases in the Animas River, in seeps in
alfalfa fields (observed during application of irrigation water), and in water in their private wells
began relatively recently. None could remember observing gas bubbles in the fields, seeps, or wells
before  1980 or 1981. A former county extension agent said ne never received complaints of "gassy"
water in 22 years of service through the mid-1980s. Four residents in their 70s said the gas in the
'fields,  seeps, and water wells does not have the  characteristic rotten eggs odor of the "swamp gas"
they often encountered  while digging or drilling shallow water wells in the alluvial sediments in
the 1930s, 1940s, and 1950s. Several residents recounted  an incident in Cedar Hill in which a water
well caught fire after a match was tossed into the borehole. And members of one Cedar Hill family
said flames roared from a water well after an individual discharged a firearm into the borehole in
hopes of opening the perforations at the bottom of the well.

Residents'  observations about the newness of gas migration can be correlated with the scientific
findings. Rice's studies showed that the  Fruitland coal gas generally has been  confined to the coal
beds and has not migrated to adjacent reservoirs, either above or below the Fruitland.  NMOCD
scientists have concluded, based on their understanding of the gas migration problem and the
regional geology, that natural fractures or other tectonic avenues did not contribute to release of
the coal gas prior to depressurization of the coal beds upon their development as gas pools.(26)

Mechanism for Gas Migration

Figure 4 depicts how Fruitland Formation coal-bed methane  is believed to be escaping its host rock
and migrating into overlying fresh-water zones,  such as the surficial alluvial  aquifer  in the
Animas River valley. (The diagram is based on  an original  drawing prepared by NMOCD's Aztec
District staff.) Gas migration as depicted in Fig. 4 occurs as a result of the combination of several
factors. The gas is freed from its host rock after the formation pressures are lowered following the
installation of gas-producing wells and the pumping off of large  volumes of produced water. The
gas migrates from the coal bed into overlying strata via the  uncemented portions of producing gas
 wells that penetrate the Fruitland Formation. Once inside the alluvial aquifer, the gas can invade
 cathodic protection holes or domestic water wells as shown in Fig. 4.(27)

The gas-migration theory was developed  by NMOCD geologists based on a  combination of the
previous water quality studies, pressure testing on gas wells,  isotopic  analyses of the migrating
gas, and their own personal  observations and insights.  In response to results of the water quality
 sampling program conducted in and around Cedar Hill  and Bondad, NMOCD  in the fall of 1989
 conducted  pressure tests on the surface casings and Bradenheads of producing gas wells in the
 area. Gas was found to be charging up the casings and annular spaces, indicating that gas either
had migrated into the surficial alluvial soils or nad escaped the production tubing of producing
wells via casing leaks. About the same time, migrating gas was suggested as the cause of two gas-
well blowouts and flowing gas and water from two cathodic protection holes in the Cedar Hill and
Navajo Lake  areas. (Fig. 2.) Having indications that  some of the errant gas may have been
migrating from the Fruitland Formation  coal beds, NMOCD began looking at construction
methods used on gas wells that penetrate the Fruitland. It was  then that the agency  discovered
that many deeper gas  wells were not cemented through the surficial alluvial aquifer or opposite
the Fruitland coal seams. The gas chemical and isotopic composition data subsequently reported
by USGS confirmed that Fruitland coal-bed methane  was present at the surface casings and
Bradenheads of nine different Mesaverde and Pictured Cliffs wells in the Cedar Hill-Bondad area.

Regulatory Responses to the Gas-Migration Problem

To prevent further migration of coal-bed methane, NMOCD in November  1989 ordered gas
operators in the Cedar Hill  and Navajo Lake areas to apply  casing cement to all existing gas wells
that penetrate the Fruitland Formation.(28) The agency  also also has continued to conduct
pressure tests on producing wells in areas where gas  wells or cathodic holes are blowing out.
BLM's Farmington Resource Area office in February approved a notice to lessees that requires full
cementing through fresh-water zones above  the gas-producing intervals.(29) By the end of May,
NMOCD reported that two major coal-bed methane producers in  the Cedar Hill area had plugged
 11 wells and were conducting remedial  cementing on more than 20 wells. One cement workover
was credited with stopping gas seeps in Ditch Canyon, three miles east of Cedar Hill.  A cathodic
protection hole that was flowing gas and  water at the surface also  was plugged.(SO)
                                           763

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                           MECHANISMS FOR MIGRATION OF NATURAL GAS

                             TO AN OVERLYING FRESH-WATER AQUIFER
Cathodic
Protection   Deep Gas Wei
  WeD
                                             Shallow Water Well
 Coal-bed
Methane Well
                Pathway
                tor Gas  ^
                  Cement
                            W
                                        NONCOAL BEDROCK (UNDIFFERENTIATED)
                                Cement
                                            GAS-BEARING SANDSTONE
Fig. 4. Diagram shows two mechanisms for the migration of thermogenic gas to a shallow water well and to
a cathodic protection hole. The thick arrows indicate how natural gas escapes the coal formation via the
uncemented portion of a deep gas well that penetrates the coal seam. The thin arrows show how gas
might migrate into the shallow alluvial aquifer from leaks in the casing of the deep gas well. Vertical scale is
exaggerated from actual depths.
Characteristics of Coal-Bed Methane Produced Water

Fruitland coal beds were known to produce a  distinctive  sodium-bicarbonate connate water.
Sampling and  analyses of coal-bed produced water  by NMOCD in mid-1989  showed that the
bicarbonate ion made up 50.6 percent to 96.2 percent of the  dissolved solids in  four samples.(31)
Total dissolved solids concentrations in four samples ranged from 10,568 mg/L to 35,728 mg/L. The
coal-bed water was consistently low in aromatic VOCs, ranging from nondetectable to less than 10
ppb. Barium was the only trace metal to show elevated concentrations, ranging up to 45.7 mg/L in
the four samples. Gross alpha radioactivity and radium-226 + -228 exceeded federal drinking
water standards  (15 pCi/L and 5 pCi/L, respectively) in all four samples. Maximum gross alpha
activity was 120 pCi/L; the maximum concentration of radium-226 + -228 was 34.3 pCi/L.

Produced water volumes reported by operators to NMOCD confirmed that the Fruitland coal beds
generate much larger volumes of waste water than do conventional sandstone gas reservoirs. In
1989, 4.5 million  barrels of water were produced from 323 Fruitland coal-bed wells, or about 38.4
barrels per well per day (BWD). By comparison, only  652,257 barrels of water (or 0.2 BWD) were
                                          764

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produced from 8,281 gas wells that tap the Basin Dakota and Blanco Mesaverde pools. Those wells
comprised 59 percent of all gas wells in  the New Mexico portion of the basin and produced 40
percent of the gas in  1989. The 323 Fruitland wells comprised only 2 percent of all gas-producing
wells  in  the New Mexico, but  generated 82  percent of waters produced from gas-bearing
formations.(32) Through the first three months of 1990, 400 Fruitland coal-bed methane wells  had
already produced 4 million barrels of water, or about 112.1 BWD. These large volumes of potentially
corrosive water are likely to be even greater, given that only 35 percent (125 of 359) of coal-gas wells
that produced gas in March reported water production volumes to NMOCD.(33)

The upsurge in coal-bed methane production in the San Juan Basin has stretched waste water
disposal capacity and necessitated the installation of hundreds of miles of new produced water
pipelines. Permitted  surface disposal capacity in the New Mexico portion of the basin was 1.25
million barrels in mid-1989.(34) About 80,000 barrels of that capacity is temporarily unavailable
because the receving  facility was shut down by NMOCD recently as a result of a hydrogen sulfide
release.(35) In the three-month period of December 1989 through February 1990, 33 active injection
wells  disposed of 3.4 million barrels  of water.(36) Together, commercial and centralized surface
disposal facilities and injection wells located in New Mexico had barely enough capacity to handle
the water that was generated from the coal beds alone during the first quarter of the year.  Some
operators shut in a few  of their coal-gas wells until new disposal capacity is constructea.(37)

In the Colorado portion of the basin, 13 injection wells were  operating on Southern Ute  Indian
lands as of May 30. Another 22 were under construction or pending permitting by the U.S.
Environmental Protection  Agency.(38) One facility was recently permitted to discharge coal-bed
water treated by reserve osmosis to a tributary of the Animas River.

Policy and Regulatory Implications of Coal-Bed Methane Production

That the pace of gas development in the San Juan Basin has picked up considerably in the past 18
months is readily apparent to most residents, and even to frequent visitors to the area. Drill rigs
are more numerous in  the Bondad, Cedar Hill  and Navajo Lake areas. Produced water  trucks
pound the major highways and dirt roads of the gas fields in numbers  not seen since the oil and
gas boom period of the early-1980s. Trenches for new gas and produced water pipelines are cutting
ribbons across the pinon and juniper highlands. The flurry of development is directly related to  the
gas industry's desire to drill and complete coal-bed  methane wells  before the tax credit  for
nonconventional fuels expires at the end of the year.

The rapidity of coal-bed development in the San Juan Basin has forced regulatory agencies to
prioritize processing of  applications to drill at the expense  of ongoing compliance and enforcement
activities or environmental protection programs, such  as  well plugging and abandonment. BLM
officials in Farmington  have said they cannot conduct compliance and process APDs at the same
time. They also say that the agency's policy is not to defer action on new coal-bed gas leasing until
the backlog of permitting and compliance tasks is whittled down.(39)

The emerging  evidence that implicates coal-bed methane  development and production  in  the
widespread contamination  of ground water in the San Juan Basin demonstrates  the urgent need
for new policies and  regulatory programs to prevent additional natural gas pollution of ground
water and to remediate existing contamination. The evidence also points to the need for state and
federal regulatory agencies to take immediate and stringent preventive actions while the problem
continues to be studied. As such, citizens groups and public-interest organizations are calling for
a wide range of new policy and  regulatory initiatives to address the consequences of coal-bed
methane development.  While the suggested initiatives that follow are predicated on  conditions
prevalent in the San Juan Basin, many  may be equally applicable to operations and impacts
occurring in other parts of the nation where coal gas is being produced:

•MULTIJURISDICTIONAL PLANNING AND  COOPERATION. State and federal  regulatory
agencies must cooperate  and communicate more frequently and  regularly on  matters that
transcend political, geographic, or jurisdictional boundaries. The impacts  attributed  to natural
gas development in general and  to coal-bed  methane production  in  particular cut  across
boundaries in the basin. Yet some agency officials in Colorado appear to be acutely unaware of  the
scientific basis for the actions and orders of their  counterparts in agencies in New Mexico.
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 •CUMULATIVE ENVIRONMENTAL STUDIES. Cumulative, basinwide environmental analyses
 should be conducted by a multijurisdictional team. To date, there are no firm figures on how many
 coal-bed methane wells are likely to be completed and producing by the end of the year on private,
 state, federal, and Indian lands in the basin. Neither is  there  a clear understanding of the
 cumulative impacts this  development will have. Environmental impact statements currently are
 being prepared by separate units of BLM and the Forest Service are not likely to consider coal-bed
 methane development impacts that occur outside of the jurisdictions administered by the agencies.
 While statutory changes may be needed to grant federal agencies authority to enter into cooperative
 environmental studies with states and Indian tribes, agencies should adopt policies that promote
 and implement such cooperative studies now, rather than wait years for the law to be changed.

 •CEMENTING OF EXISTING GAS WELLS. Gas wells that penetrate the  Fruitland coal beds
 should be cemented throughout the basin. Cementing should  also be continuous through the fresh-
 water zones that overlie the gas-producing  formations. Such remedial actions are relatively
 inexpensive and are being implemented by operators in the New Mexico portion of the basin.
 Remedial cementing of this type has not been ordered by agencies in Colorado.

 •PRE-LEASE  ENVIRONMENTAL AUDITS.  In the  absence of  cumulative,  basinwide
 environmental analyses,  comprehensive environmental  audits should be performed for all new
 coal-bed methane leases. Such audits should consider  the complete range of potential impacts
 from produced water disposal,  gas migration, emissions of  greenhouse  gases like CO2, and the
 construction of roads and river  crossings.

 •MORATORIA ON NEW LEASING. A moratorium on new leasing would be a prudent and useful
 step, especially for state and federal agencies which have authority to temporarily suspend a lease
 on lands that are within  their jurisdictions.  A moratorium would allow the regulatory  agencies to
 catch up on other permitting and compliance activities at the same time that the impacts of coal-
 bed methane  development are assessed. Plugging of abandoned oil and gas wells and  integrity
 testing of gas-producing wells could be program priorities during the period of a moratorium.

 •CORRECTIVE ACTION AND COMPENSATION  FUND. Residents whose wells have been
 contaminated are faced with an impossible burden of proof in sustaining a private cause of action
 against a  particular gas-well operator  or a cadre of operators. Even  when a private party is
 successful in  a damage  case in court,  the  award does nothing to remediate the contaminated
 ground water. A fund needs to be created to compensate residents for polluted water supplies and
 damaged croplands. The fund  could also finance research and remedial actions to reduce or
 eliminate  gas contamination of fresh  ground  water.  The  fund would logically come from a
 surcharge  on revenues generated from the production of natural gas.

 •ONGOING PRIVATE WELL TESTING. As long as natural gas is being detected in private wells
 in the  Animas River valley,  periodic  free  testing of domestic  water should be  continued.
 Community water fairs  should have the capability of testing for  organic vapors and aromatic
 VOCs.  State and federal agencies should pool  their resources to  insure that gas samples can
 continue to be analyzed by USGS for chemical and isotopic composition.

 •LOCAL LAND-USE CONTROLS. Local governments  should exercise their land-use authorities
 to regulate aspects of oil and gas operations that are not covered by state or federal regulations.
-Surface disturbance and land-use incompatibility are two relevant issues for local governments.

 •PRODUCED WATER  MINIMIZATION AND  DISPOSAL ASSURANCE.  Requirements for
 producers to minimize or reuse  water produced from coal beds should be incorporated in pre-lease
 audits or in applications to drill. At a minimum, agencies should require operators to demonstrate
 that adequate disposal capacity is  available prior to gas-well completion. Permitting of produced
 water haulers also is necessary to prevent illegal dumping when disposal space is unavailable.

 •DISCONTINUATION OF THE TAX CREDIT. The tax credit for coal-bed methane development
 should  not be extended, at  least not without concomitant requirements for the assessment of
 environmental impacts. The purpose of the credit — to spur development of domestic sources of
 energy — is  no longer  served in  an era of surplus natural gas. The credit also encourages
 development that otherwise would not occur under normal market conditions.
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The contamination of alluvial ground water in the Animas River valley of New Mexico and
Colorado by thermogenic natural gas is related in part to the recent upsurge in the drilling for and
production of coal-bed methane. Gas from the coal seams of the Upper Cretaceous Fruitland
Formation has migrated nearly 3,000 feet into domestic water wells and cathodic protection holes
and has charged up the surface casings and Bradenheads of producing gas wells. The gas has
migrated upward via the uncemented portions of gas wells  that penetrate the Fruitland. The
extent to which  leaks in the casings of either Fruitland wells or wells that produce from deeper,
sandstone formations, or both, nas not been determined. Remedial  measures ordered by
regulatory agencies are limited to workovers of gas wells that penetrate the coal seams. The large
volumes of water produced from the coal seams vary  greatly in dissolved solids content, are rich in
bicarbonate and sodium, and exhibit concentrations of barium, gross alpha radioactivity, and total
radium that  exceed drinking water standards. Produced water  from coal beds in the basin is
stretching the available disposal capacity and forcing some operators to shut in their Fruitland
coal wells. New policies and regulations, such as basinwide environmental analyses, moratoria
on new coal-bed methane leasing, establishment of a corrective action and compensation  fund, are
needed to address the impacts of coal-bed methane development.

Acknowledgments

The author appreciates the ongoing access he has to  the files,  data, and personnel of the New
Mexico Oil  Conservation Division. And he is especially grateful for the cooperation, assistance,
and perseverance of residents of the  Animas River valley. Finally, he wishes to recognize the
valuable assistance of SRIC administrator Don Hancock in the review of this paper.

References and Endnotes

1.     V. A. Kuuskraa and C. F. Bradenburg, Coalbed methane sparks a new energy industry,
       Oil and Gas Journal. October 9, 1989, 49-54.                            ~

2.     T. A. Dugan and B. L. Williams, History of Gas Produced from Coal Seams in the San
       Juan Basin, in Geology and Coal-Bed Methane Resources of the Northern San Juan Basin.
       Colorado and New'Mexico (J. E. Fassett. ed.). Rocky Mountain Association of Geologists.
       Denver, 1988,1-10.

3.     P. M. Soot, Non-Conventional Fuel Tax Credit, in Fassett (ed.), 247-252.

4.     U.S. Bureau of Land  Management,  Fruitland Coal-Gas  Update, USBLM Farmington
       Resource Area, May 1990, 3.

5.     C. Shuey, Bald Alfalfa  Fields and "Gassy" Water: Coal-Bed Methane Premiers in Cedar
       Hill  and  Bondad,  The  Workbook.  Southwest Research and  Information Center,
       Albuquerque, XV:2, Summer 1990, 59.

6.     B. C. Boyce and L. C. Burch, The Southern Utes: An Economically and Socially Successful
       Indian Nation Building upon its History and Challenging the Future, in Fassett (ed.), 11-
       20.


7.     Dugan and Williams, 1, 6.

8.     U.S. Internal Revenue Code, §29(f)(i).

9.     Western  Organization  of Resource Councils, Coal Bed Methane Fact Sheet, WORC,
       Billings, Mont., May 1990, 3.

10.     See, for instance, San  Juan Citizens Alliance, Report to the  San Juan Basin Oil and
       Gas Coordinating Committee, May 31, 1990.
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11.     Samples collected by NMOCD from private wells were analyzed by the New Mexico State
       Laboratory Division, Albuquerque, or by Inter-Mountain Laboratories Inc.,  Farmington.
       N.M. Samples collected by local residents were analyzed by personnel of NMOCD and
       the New Mexico Environmental Improvement Division at community  "water fairs" on
       April  6,  1989, and  June 6, 1990. General chemistry, trace metals,  volatile organic
       compounds and organic vapors were  measured in most of the samples. The analytical
       reports are on file at NMOCD's Santa Fe offices; copies are in the possession of and may be
       obtained from the author. Information  on the analytical equipment and sampling
       techniques used is available from David Boyer, NMOCD; tel. 505-827-5812.

12.     D. D. Rice (Branch of Petroleum Geology, USGS, Denver), Summary  of chemical and
       carbon isotopic composition data for gas samples collected in July 1989 in the Bondad,
       Colo., area, August 3,  1989; letter to E. Busch, N.M. Oil Conservation Division, Aztec,
       N.M., transmitting  chemical  and carbon isotopic composition  data  for gas samples
       collected in August, September, October, and November 1989 in the Cedar Hill, N.M., area,
       June 25, 1990. (Copies of the analytical results for these gas samples may be obtained from
       the author.)

13.     While those results have not been published in the scientific literature, Mr. Rice told the
       author (personal communications, June 22 and 27, 1990) that the results will be described
       in an upcoming USGS publication. He said the data are reliable and  indicate that
       natural gas has migrated from deep formations as a result of either natural conditions or
       activities associated with drilling and completing gas wells.

14.     Rice (June 25, 1990), 1 and attached data compilations.

15.     Rice, August 3, 1989,  1 and attached data compilations.

16.     D. D. Rice, C. N.  Threlkeld, A. K. Vuletich, and M. J. Pawlewicz, Identification and
       Significance  of Coal-Bed  Gas,  San  Juan  Basin,  Northwestern  New Mexico and
       Southwestern Colorado, in Fassett (ed.). 51-60.

17.     D. D.  Rice, J. L. Clayton,  and M.  J. Pawlewicz,  Characterization  of coal-derived
       hydrocarbons and  source-rock potential  of coal  beds, San Juan Basin, New Mexico and
       Colorado, U.S.A.,  International Journal  of Coal Geology, 13,  Elsevier Science Publishers
       B. V., Amsterdam, 1989, 597-626.

18.     Rice (1989), 612.

19.     D. D. Rice and C.  N. Threlkeld, Occurrence and origin of natural gas in ground water,
       southern Weld County,  Colorado, U.S. Geological Survey Open-File Report 82-496, Denver,
       1982.

20.     Rice (1989), 603.

21.     The delta (A) symbol is used in this paper in place of the more conventional Greek notation
       for the letter delta.

22.     Rice (1989), 603 and 606.

23.     Rice (August 3, 1989), 1.

24.     Rice (June 25, 1990), 1.

25.     Interviews  with local residents were conducted by the author on January 9, February 8,
       March 11, May 25, May 31. June 3, and June 20, 1990. Local residents interviewed were:
       Dippery, Hank (Cedar  Hill); Hottel, Jake (Aztec); Hottell, Willard (Cedar Hill); Leeper,
       Benson (Cedar Hill);  Leeper, Ruby (Cedar Hill); McEwen, Thelma (Cedar Hill); McEwen,
       Wright (Cedar Hill); Moss, Bill (Cedar Hill); Scott, Jack (Aztec); Temple, David (Bondad);
       Temple, Pati (Bondad);  Utton. Orion (Cedar Hill); Welch,  Maxine (Cedar Hill); Welch, Roy
       (Cedar Hill); and Weston, Carl (Bondad).
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26.    Shuey, 57-58.

27.    This explanation of the mechanism for gas migration was gleaned from interviews with
      NMOCD and BLM scientists, technicians, and regulatory officials on  12 different dates
      between November 9, 1989, and June 22, 1990. Note 4 of Shuey (1990) contains the names of
      those officials and the dates of the interviews.

28.    New Mexico Oil Conservation Division, Memorandum 3-89-309 and Minutes of Fruitland
      coal gas operators meeting, November 21, 1989; Aztec District Office, November 28, 1989.

29.    U.S.  Bureau of Land Management,  Notice  to  Lessess  (NTL/FRA 90-1), Farmington
      Resource Area Office, May 1990.

30.    F. Chavez, Aztec OCD Report to SJBOGCC, New Mexico Oil Conservation Division, Aztec
      District Office, May 31, 1990.

31.    New Mexico Scientific Laboratory Division, Analytical reports RC-89-0138, RC-89-0159, RC-
      89-0161, and RC-89-0170, Albuquerque, July 24,  1989.

32.    New  Mexico Oil & Gas Engineering Committee, Annual  Report, Volume II, Northwest
      New Mexico, NMOGEC-Hobbs, 1989.

33.    New  Mexico Oil Conservation Commission, Monthly Statistical Reports (Volume IV and
      IVA)  for Northwest New Mexico for January, February and March, 1990, Santa Fe.

34.    New  Mexico Oil Conservation Division, OCD Approved Produced Water  Evaporation Pits
      — Northwest New Mexico, NMOCD, Santa Fe, June 1989.

35.    W. J. LeMay (director, NMOCD), letter to J.  Sandell and D. C. Turner (Basin Disposal
      Inc.), June 29, 1990.
36.     NMOCC (1990); see Northwest Salt Water Disposal Systems sections in each of the three
       monthly reports cited in Note 44. (The figures for produced water disposed by iniection well
       does not include produced waters that are automatically reinjected in waterflood projects.)

37.     F. Chavez (NMOCD/Aztec), personal communication, July 9, 1990.
38.     U.S. Environmental Protection Agency, Status of Injection Wells — Southern Ute Indian
       Reservation, USEPA/Region VIII, Denver, May 30, 1990.

39.     J. Farrell (acting assistant area manager, USBLM/Farmington Resource Area), personal
       communication, June 11, 1990.
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THE POTENTIAL FOR SOLAR DETOXIFICATION OF HAZARDOUS WASTES
IN THE PETROLEUM INDUSTRY
Kenneth M.  Green, Energy Policy Analyst
Dinesh Kumar,  Senior Analyst
Meridian Corporation
4300 King Street
Alexandria, VA  22302
Abstract

The  generation  of  hazardous  waste  from industrial  processes  is  a national
problem.   Due  to  the  incidence  of  impacts  on  the public  health  and the
environment,  the  importance  of  appropriate  hazardous  waste  treatment has
experienced an increasing level of attention over  the past two decades. Although
significant advances have been achieved in the disposal and destruction of  these
wastes,  there remains  significant  room for  improvement in  the destruction
efficiency  of   waste  detoxification   technologies,  their   cost,   and  the
environmental  impacts of waste detoxification processes themselves.   Currently,
the  U.S. Department  of  Energy through its national laboratories  is  performing
R&D  in the use  of  solar  energy to detoxify  hazardous  wastes.   This  paper
discusses  the process  of  solar  detoxification  of  hazardous  waste  and the
potential for utilizing this process  in  the  petroleum industry.


Introduction

The  U.S. Environmental  Protection Agency (EPA) recently released the data for
its Toxic Release Inventory (TRI)  for 1988.   During the year,  19,762  industrial
plants  in  the U.S. released 4.57  billion pounds  of  toxic chemicals into the
environment.  The  bulk  of  this  (53.2%)  was  released to the air,  the remaining
was  injected to underground wells,  released  to  landfills  or dumped into  rivers,
lakes, streams and other bodies of water.   In  contrast to  chemical releases  to
the  environment, 0.57 billion pounds were transferred to  wastewater treatment
facilities  and  1.10  billion  pounds were transferred to  other treatment and
disposal facilities.1

The  chemical  industry (SIC  28)2  is by far the  largest producer  of toxic waste,
generating roughly 50% of those chemicals reported  on the TRI.   Other  industries
which produce  large quantities of toxic wastes include the metals industries (SIC
33,  34),  rubber and  plastics  industries (SIC 30),^ and  the  paper  and allied
products industries (SIC 26).  The petroleum industry (SIC 29)  is among  the top
                                     771

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10 generators  of toxic waste  in the  U.S.   The  EPA,  TRI reported  that total
releases for SIC 29 during 1988 were 109,344,966 pounds, or 2.5% of total toxic
releases in the U.S.3

Without proper treatment, toxic emissions  can  produce  serious  consequences.
Air pollution  has become  an  increasing health  and environmental hazard in many
of the nation's urban areas.   In some regions of the nation, water pollution is
jeopardizing marine  life and  depressing local  industries.   The  pollution  of
groundwater with toxic or cancer-causing chemicals has,  in some extreme cases,
forced residents to obtain drinking  water elsewhere.   In several  tragic cases,
when residents were  unaware  of  the  contamination and continued  consuming  the
contaminated water, they  suffered serious health effects.

In 1976, the Resource Conservation and  Recovery Act (RCRA) was passed to provide
an  initial  set  of guidelines  and   regulations  to improve  the treatment  and
disposal of waste.   In  1979,  however,  EPA estimated that  still  only 10% of
hazardous wastes produced in the U.S.  were  managed in  an environmentally  sound
manner. Subsequently, Subtitle C of  RCRA was developed to  establish  a "cradle-
to-grave" management system for hazardous waste to  ensure that mismanagement did
not continue.   Subtitle  C set  forth  a  program  to: identify hazardous waste;
regulate  generators  and  transporters;  and  regulate  and  permit  owners  of
treatment,  storage and disposal facilities.  The Subtitle C program constituted
one of the most extensive  and comprehensive  set of  regulations that EPA had ever
developed.  It is within this program that U.S. industries generating hazardous
wastes must operate.

Waste  treatment and  the  level  of  destruction  efficiency  has  improved  since
institution of the RCRA.   However,  the waste  disposal or  treatment  techniques
used  by various  U.S. industries,  such  as landfilling  or  incineration have
sometimes provoked as great a concern as the hazardous wastes themselves.  Waste
treatment processes can often be highly energy  intensive resulting in extensive
levels  of  pollutants during  the transfer,  treatment,  and disposal  processes.
Solar  detoxification, however,  presents a relatively  clean  option   which can
augment future hazardous  waste treatment activities.

The following  is a brief overview of  specific types of hazardous  wastes produced
in the petroleum industry and current treatment techniques being utilized. The
solar  detoxification  process  is   then  described as   is  its  potential for
applications in the petroleum  industry.


Hazardous Waste in the Petroleum Industry

Petroleum  industry processes encompass  a broad  range of  activities including
exploration  and production,  refining,  storage,  and distribution.   Throughout
these  process, wastestreams  are generated  --  many of which are  classified as
hazardous.   These wastestreams  can  be in the  form of wastewater, acids, tank
bottoms, separator and  cooling tower  sludges,  and other process  wastestreams.
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Many of the hazardous wastes generated in the refining segment of  the  industry
are also present in other segments of the industry as well.

These hazardous wastes typically  contain  metals  such as  lead and  chromium,  or
chemicals such  as  chloroform,  toluene, 1,2-dichlorethane  or cyanides, making
them toxic and potentially harmful to both human health and the environment  if
not properly managed.   Table 1  below,  lists wastes from refining process, which
are classified  as  hazardous under the RCRA.  These  wastes are also generated
throughout other stages of petroleum industry processes.
                                    Table  1
             Appendix VIII Constituents found in Refinery Wastes
     Antimony                              2,4-dinitrophenol
     Arsenic                               Di-n-octylphthlate
     Benzene                               Fluoranthene
     Benzo(a)pyrene                        Hexachlorobenzene
     Beryllium                             Lead
     Bis(2-ethylhexyl)  Phthalate           Mercury
     Cadmium                               Naphthalene
     Chloroform                            Nickel
     2-Chlorophenol                        4-nitrophenol
     Chromium                              Pentachlorobenzene
     Chrysene                              Phenol
     Cyanides                              Selenium
     DDE                                   Silver
     1,2-d i chloroethane                   Tetrachloroethylene
     Dichloroethylene                      Toluene
     Diethyl Phthalate                     Vanadium
     2,4-dimethyl  phenol                   Zinc
     4,6-dinitro-o-cresol
     Source: The Land Treatability of Appendix VIII Constituents Present in
            Petroleum Industry Wastes, American Petroleum Institute Pub. No.
            4379.
The above toxics,  found  in petroleum process wastes,  are  among the chemicals
ordered  by  the  EPA's  Toxic  Release Inventory  (TRI)  and  contribute  to the
industry's portion of total U.S. TRI releases.  Table 2 below shows the breakdown
of petroleum industry  (SIC 29)  releases to the environment  as  well  as wastes
transferred out,  for 1988.  The same data are shown for the total  U.S. inventory.
In all, the petroleum  industry accounted for 2.4% of toxic chemical releases to
the environment.


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                                     Table 2
                         Releases and Transfers of All
                  Toxic Chemical Release  Inventory Submissions
                                     (pounds)
                    Total U.S.

    Air  Releases- 2,427,570,103
    Discharged
    to Water-       361,594,238
    Underground
    Injection-    1,215,343,908
    Releases
    to Land-        561,556,882
    Total
    Releases-     4,566,065,131
     Discharged  to:
     Municipal Waste-
     water  Treatment
     Facilities-    570,551,308
     Other  Treatment
     and  Disposal
     Facilities-  1,104,414,307
Petroleum (SIC 29)

 69,118,376

  4,147,541

 30,299,195

  5,779,854

109,344,966
 13,887,417
 10,826,337
% of Total U.S.

      3.0%

      1.2%

      2.5%

      1.0%

      2.4%
      2.4%
      1.0%
     Source: 1988 Toxic Release Inventory, Releases and Transfers by Industry,
            Environmental Protection Agency, April 1990.
Of total TRI generated wastes by SIC 29 companies, roughly 82% was released to
the environment.  Of this  amount,  about  63% was released to the air and about
28% released  through underground  injection.   The  remaining releases  to  the
environment were in the form of releases  to  land (5.3%)  and discharges to water
(3.8%).  This pattern of toxic releases  in the petroleum industry  follows similar
patterns as those for U.S. industry in general.

The remaining 18% of petroleum industry  generated wastes were transferred-out
either  to  municipal  wastewater  treatment  facilities,  or  other treatment  and
disposal facilities.   However,  transfers-out  by  the  petroleum  industry  are
significantly  lower  than  the national  norm.   On  the whole,  U.S.  industry
transferred-out roughly 27% of TRI wastes to treatment  facilities.
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Although  "releases to the  environment"  may imply  indiscriminate  emissions or
waste dumping, most of the wastes generated by the petroleum industry are managed
via approved treatment and/or disposal processes.  These processes, when properly
administered  and managed, are designed to reduce or eliminate the environmental
and health  threats posed by specific hazardous wastes.  Treatment and disposal
processes utilized by the petroleum industry include:

      Landfllling- Landfills store wastes in constructed or natural excavations.
      They use a combination of liners and leachate-collection systems to control
      the migration of the wastes or their byproducts.   When  a landfill is full,
      it  is covered with impermeable material  such as  compacted clay.

      Incineration-   In this process,  wastes are  burned  (oxidized) at  high
      temperatures in enclosed  chambers.

      Deep-well  Injection-   This  process  isolated hazardous  wastes in  deep
      underground  reservoirs surrounded  by impermeable rock.

      Surface Impoundment-   In this method, wastes are deposited in open  basins
      that have  been excavated  in the ground.    The  basins  are lined  with
      impermeable  materials. In most cases, surface impoundments are used only
      for  temporary  storage or  as treatment  areas  for  wastes  that will  be
      disposed of  through other means.

      Chemical Treatment-   Chemical processes can  change  the composition  of
      certain hazardous wastes --  such  as  acids  and sludges --  rendering them
      non-hazardous.   Chemical  treatment processes include:  neutralization (pH
      adjustment),    precipitation,     oxidation,     and    chemical
      fixation/solidification.

      Land Treatment- The most widely-used treatment and disposal process, land
      treatment entails  spreading wastes over the soil  surface allowing the soil
      and  natural  soil  organisms  to  break  down hazardous  wastes.     It  is
      considered a treatment and disposal  method since a fraction of the waste
      does not decompose, but instead becomes immobilized in the soil.

None of  these techniques is  suited for  each  type of hazardous  waste generated
in the petroleum industry.  Most facilities use a combination  of these techniques
in managing hazardous waste/  Each of these techniques requires  constant site
treatment, monitoring  and   if necessary remedial action,  to remain a  viable
alternative for the industry's  waste disposal  options.


Solar Detoxification Technology

An  interesting waste treatment  option  is  undergoing  R&D  at the  Department of
Energy.   In  the  past six years,  solar  detoxification  of  hazardous  waste and
contaminated water has  been  successfully tested  and in the  near  future  may be
able to augment current  petroleum  industry hazardous waste treatment processes:
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Solar detoxification can offer a clean and effective option for decontaminating
volatile organic compounds (VOC) in drinking water supplies or chemical wastes.
It will not require the intense use  of  energy  necessary for some current waste
treatment  and  disposal technologies and  it  should  be available  for on-site
applications,  depending  on  the  type  of  waste  as  well  as  other  relevant
conditions.

For the past  six years,  the  U.S. Department  of Energy  (DOE) has  been funding
solar detoxification R&D at the Solar Energy Research Institute (SERI) in Golden,
CO and Sandia  National Laboratories  in Albuquerque,  NM.  Because  of  a recent
reorganization  of  the DOE  Conservation  and  Renewable  Energy Program,  this
technology area is now under the lead of the Waste Material Management Division.
The solar detoxification program was  initiated due to the growing hazardous waste
problem both within U.S.  industry and U.S.  Government facilities  as well  as to
provide a possible  alternative to existing  detoxification techniques.

Two solar detoxification processes are being investigated -- solar detoxification
of wastewater  and  destruction of  hazardous chemical waste.  The primary  drive
behind the solar detoxification technology and introducing it to the marketplace
is its added advantage over  conventional  technologies.   For example:

•     When augmented with existing techniques,  solar detoxification can enhance
      the volume and quality of waste destruction  capabilities.

t     Tests have achieved 99.99999%  dioxin destruction  at 750°  -- exceeding the
      destruction  efficiency  of conventional   technologies  as  well   as EPA
      destruction   efficiency  requirements,    while  requiring   far   lower
      temperatures.

•     The solar detoxification process destroys  the waste completely rather than
      transferring  it to another medium  (i.e. air or water emissions, landfills,
      etc.).

t     Solar detoxification of contaminated wastewater is faster than conventional
      technologies.      Demonstrations    have    achieved   85%   oxidation  of
      trichloroethylene (TCE)  in a single pass  (2.5 minutes) at 27 gpm. TCE is
      the most commonly found contaminant  in almost  10% of  U.S. drinking  water
      supplies.

•     Solar  detoxification  systems   can  be  mobile  and utilized  on-site  at
      industrial or government facilities.

•     Solar detoxification  does not  require the intensive use  of  fossil  fuels
      or  chemicals  as do   other  methods  such as   incineration  or  chemical
      treatment.

The solar detoxification processes for wastewater treatment and  chemical wastes
utilize  a combination of  high-energy photons  providing  a quantum effect and
infrared photons providing thermal energy resulting in effective destruction of
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chemical wastes.   Many industrial solvents  have  been  destroyed and preliminary
testing has indicated that solar detoxification may also remove some heavy metals
from water.5

      Solar  Wastewater Decontamination-   The DOE  solar detoxification program
has established solar water decontamination as one of its major priorities.  In
this process, sunlight is  focused on a reactor  through which the contaminated
water is flowing.  Ultraviolet  (UV) energy in the  concentrated beam activates
a catalyst in the waste stream.  This results in the formation  of very aggressive
oxidizers  known as free  radicals, which in turn break  down  the organic wastes
into treatable nonhazardous products  such  as  carbon dioxide or dilute hydrogen
chloride.

Figure  1  below   is  an  illustration  of  a  solar detoxification system  for
groundwater  which would  utilize Sun-tracking parabolic troughs.   Contaminated
water would  enter a UV glass  tube placed  at the  focus of this concentrator, at
one end of a trough containing  the  photocatalyst,  and exit at the opposite end
of the trough as processed decontaminated water which could then be transferred
to  municipal  reservoirs.  Solar  detoxification  systems developed at  SERI and
Sandia  have successfully  destroyed  TCE  at  a   faster  rate  than  conventional
processes and at lower temperatures.  Current plans are  to address  system scale-
up issues,  assess competitiveness, and to  have commercially-ready systems by the
mid-1990's that will  be  capable  of processing water  containing solvents, dyes
or  pesticides.
                 Contaminated
                 groundwater
                              Parabolic trough
                              solar concentrator
Photocatalyst
mounted in a
porous matrix
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A significant advantage of this process over conventional  processes is  that this
process destroys the  contaminants in a single step without  the need  for first
removing them from the water.  Once cost-effective, solar water decontamination
systems should  be  commercially marketable and have far less environmental  and
energy costs than conventional  wastewater treatment  technologies.

      Solar Destruction of Chemical Wastes-  The solar destruction of  hazardous
chemicals  is  similar  to conventional  incineration.   The  solar detoxification
process occurs  in  two steps within  a  reactor of a concentrating solar energy
system -- such as parabolic dish, central receiver, or a solar furnace reactor.
In a typical  application,  a toxic waste is exposed to  a  focused  beam of solar
energy concentrated  1,000 or more times  the  intensity of normal  sunlight  and
heated to  700° to 1,000°C.   Part of the solar beam provides  low-energy photons
in the infrared and visible  parts  of the  spectrum to  heat the chemical wastes.
A second part  of the  beam provides a quantum component or high-energy photons
in the UV  region to break  the  chemical  bonds  and  destroy the molecules.

The  combination of  thermal  and quantum  energy results  in  a more  complete
destruction  of the toxic  chemicals  at  lower  temperatures than those  required
using conventional  incineration.  For example,  in  1989 tests to destroy a dioxin
(1,2,3,4-tetrachlorodibenzo-p-dioxin)   achieved  a   greater   than   99.99999%
destruction  efficiency at  750°C.   Conventional  incinerators, however,  would
require  temperatures  above  1,000°C  to  achieve the same level of destruction
efficiency.  Plans are for having commercially-ready systems by the late-1990's
which are capable of destroying low-Btu and hazardous  chemicals such as dioxins
and PCB's.6

Once  commercially  viable,  solar  hazardous  waste detoxification systems for
chemical  waste  and   contaminated  water,  will   have  several  advantages over
conventional technologies.  For example, the solar detoxification process reduces
temperature  requirements  by 300° to 400°C over those required  in conventional
incinerators.   In  addition, the photolytic process reduces  the toxic  products
of  incomplete combustion  remaining  in the exhaust  stream and eliminates the
emissions  generated by  burning fossil  fuels.

Moreover,  mobile detoxification  units are  being researched for solar  water
decontamination.   These  mobile units, depicted  in  Figure  2,  can  be trailer
mounted systems that could be utilized at various industrial or remediation sites
to  perform  decontamination  testing  and evaluate  the  potential  for  solar
decontamination in a variety of situations.  By performing the process on-site,
the costs  and  environmental  impacts  associated  with off-site transfer are also
eliminated.   In addition, the  mobile  units  can function  to  educate potential
users about solar detoxification technology.  Eventually, the mobile units should
be commercially available  to perform full-scale decontamination services.
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          Photocatalyst
          mounted
          in a porous
          matrix
                 Parabolic
                 Trough
                 Technology
Importance  to  the  Petroleum Industry

Ongoing testing  has  proven  that   a  number  of hazardous  chemicals  can  be
potentially handled in an effective manner utilizing  solar detoxification.  Table
3 lists the most common  toxic  and  noxious  chemicals found  in  groundwater which
are both known toxins and where decomposition by natural sunlight in conjunction
with a catalyst has  been   proven.   Several  of  these  toxics  are  generated  in
refinery process  wastestreams (Table  1).   These   include  1,2-Dichlorethane,
Chloroform, Toluene,  and Phenol.   Most  of  these  are on the EPA's priority list
of toxic wastes threatening the nation's groundwater.   They are also among the
Solar Detoxification Program's list of priority toxics.   In  addition  to the
wastes listed  in Table 3, there are numerous other toxics (chemicals and metals)
found in petroleum industry wastestreams which can potentially  be destroyed using
solar detoxification.  These include: cyanides and benzene as well as metals such
as lead, nickel,  beryllium, cadmium, chromium,  mercury,  vanadium,  zinc,  and
selenium.

Not all wastestreams generated in the petroleum  industry will be  viable for
treatment using the solar detoxification process.  However,  solar decontamination
of water as well  as  solar detoxification  of hazardous chemical  wastes should
present viable options for treatment of  refinery  wastewater, waste  streams which
may otherwise end  up  as stormwater  run-off silt,  as well as  other hazardous
liquid wastes  which may otherwise be  chemically treated, incinerated or injected
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                                     Table 3
         Toxics Found in Petroleum Industry Wastestreams with  Potential
                      for Treatment  by Solar Detoxification*

    1,1-Dichlorethane         1,2-Dichlorethane       Carbon Tetrachloride
    Trichloroethylene         Perchloroethylene       Ethylene Dibromide
    Dichloromethane           Chloracetic Acid        Chloroform
    Ethylene Glycol           Toluene                 Chlorobenzene
    Salicylic  Acid            Phenol & Chlorophenol   2,4,6, Trinitrotoluene
    * Those toxics which are both: 1) listed by API  as  found  in petroleum
      refining waste streams;  and  2)  listed among the priorities for  the
      Solar Detoxification Program.
underground. Moreover, the ability to provide mobile or on-site solar wastewater
decontamination can also prove to be an asset for refineries and other industry
facilities which may not  have  cost-effective  access to conventional  treatment
or disposal facilities.

Current program goals are to have commercially-ready solar water decontamination
systems  in-place  by 1995  with throughput  costs  of  $0.40  -  $1.00  per 1,000
gallons.   In  the  area  of solar  detoxification  of hazardous  chemical  waste,
program goals  are to have  the  technology commercially  viable by the late 1990's
with a cost of $300 - $500 per ton.7
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Endnotes


1.     "EPA  Announces  1988  TRI  Figures",   Environmental  News.  Environmental
      Protection  Agency,  April  19,  1990

2.     Federal  Standard Industrial  Classification  (SIC)  codes:   SIC  code 28-
      Chemical  and allied products  industries; SIC 33- Primary metal industry;
      SIC 34-  Fabricated  metal  products,  except  machinery  and  transportation
      equipment;  SIC 30-  Rubber  and miscellaneous plastics  products;  SIC 26-
      Paper and   allied  products;  SIC  29-  Petroleum refining  and  related
      industries.

3.     Environmental  Protection Agency, 1988 Toxic Release  Inventory.  Releases
      and Transfers  by Industry,    April  1990.

4.     American  Petroleum Institute,  Environmental  Affairs  Department,  Land
      Treatment:  Safe and efficient disposal of petroleum waste.

5.     U.S.  Department of Energy, Office of  Conservation  and  Renewable Energy,
      Solar Thermal  Program Summary: Fiscal  Year 1989.

6.     Solar Energy  Research  Institute,   "Solar  Detoxification  of  Hazardous
      Wastes",  SERI  Highlight,  1989.

7.     U.S.  Department of Energy,  Solar Detoxification and Hazardous Waste Fact
      Sheet, Domestic Status.
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A PRACTICAL APPROACH TO ENFORCEMENT OF HEAVY OILY  WASTE DISPOSAL
DAVID DEGAGNE,  C.E.T.,  AREA SUPERVISOR
ENERGY RESOURCES CONSERVATION BOARD
WAINWRIGHT,  ALBERTA, CANADA
W. (BILL) REMMER, P. ENG., MANAGER, FIELD OPERATIONS
ENERGY RESOURCES CONSERVATION BOARD
CALGARY,  ALBERTA-, CANADA
ABSTRACT

Heavy  Oil Production  Operations  in Alberta  have  become  quite
efficient at  coaxing  viscous crude  from  the  earth.   One  problem
which has remained  constant, however, is  the  need to remove  and
dispose of  the reservoir  sand  produced  in association with  the
heavy oil.  This paper looks closely at the role  enforcement  plays
in  heavy  oil waste management  practices  within the province  of
Alberta.  As part of this we will examine the size and dimension of
sand production; where it is typically found within the production
chain; various sand cleaning methods; handling and storage systems;
as  well  as  some selected  disposal techniques.   A review of  key
legislation and  policy  used  by  the Energy Resources  Conservation
Board will  center on  characterization  (toxicity) of the waste,
environmental impact,  hydrocarbon reclaiming and continued need for
research  into  new  technology.    Also   addressed  will  be  the
application process which Heavy  Oil Operators  must follow in  order
to  meet the  requirements  for satisfactory disposal of this  waste
product.

This paper will  also  look  at various mechanisms used to maintain
and upgrade the guidelines that  are in effect.  The views of  local
Government Authorities (County and  Municipality Districts) and the
general public will be presented as each plays an important role in
gauging any  apparent or  perceived consequences  related  to  oily
waste disposal practices.

The  primary  goal of  this  enforcement  policy  is to provide  an
effective yet practical  approach in dealing with this problem.  The
workability of this system will  be briefly illustrated  in
examples which demonstrate the  positive aspects  and  commitment to
an  acceptable system by all concerned parties.
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INTRODUCTION

There is an old saying that for some dogs, their bark  is worse than
their bite.  Unfortunately this often  is the case facing government
departments or legislative regulators when trying to perform their
duties as  administrators  of the public interest  in areas such as
resource  development,  manufacturing  and other  heavy  industry.
Mountains  of acts, regulations,  edicts or other policy directives
are little comfort to society and all too often the environment if
their enforcement  cannot  be performed in an  effective and timely
manner.

In the Province of  Alberta,  the Energy Resources Conservation Board
(ERCB),  with over fifty  years of experience as a regulator  and
enforcer  of The  Energy  Industry,  long  ago  realized that  full
compliance of  any  legislation must be accompanied  by a practical
and  reasonable enforcement  program.   Without question,  a  large
proportion of  the  success and reputation earned by the ERCB over
its history  is  attributable to the way in which it  is structured.
There are  eight statutes or acts which give it broad powers but it
is  the process  which is  undertaken   to  interpret  these  various
statutes used  to  formulate a policy which provided the basis  for
industry and public acceptance.

The ERCB is structured as a quasi judicial government  organization
funded jointly by industry and government. Its main purpose is  the
regulation of  Alberta's   Energy Industry.    Its  mission is  to
facilitate and regulate  the  responsible  development  and  careful
conservation of Alberta's energy resources in the public interest.
With a key role as  a facilitator,  being that the crown which is  the
province,  owns the vast majority of the energy resources,  the ERCB
and  industry often share  the same goal  when it comes  to energy
development.  In so doing, the ERCB attempts to bring fairness  and
a sense of balance to the often times, conflicting needs,  concerns
and perceptions of the people of Alberta,  their government and  the
energy industry.

The ERCB is  headed by  professionally  qualified Board  members,  six
at the present time, each  appointed by  the Alberta Cabinet, usually
from within the organization but not always.   In order  to carry out
its responsibilities,  the Board employs a staff in  excess of 700,
including  engineers,  geologists,  economists,  field  inspectors  and
many other kinds of technical experts and support staff.  The ERCB
staff  is  divided into 16  departments located in the ERCB's Head
Office  in  Calgary, with  about  sixteen percent of  the compliment
situated in eight field offices throughout the province where much
of the actual  enforcement takes place.
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The  factors  which  have   a  role  in  converting   a   formal   and
generalized  statute,  into  an effective and practical  enforcement
policy will  be  examined later.   Prior to this, it is important to
focus on  one small isolated case to provide the background  in  how
this process occurs and why it appears to be an obvious  and natural
one.

HEAVY OIL PRODUCTION

A  small  but  important part  of Alberta's  extensive oil  and  gas
industry   is  the  heavy   oil   sector   situated  mostly  in   the
northeastern portion  of the province.   There  are about 50  active
operating companies, however,13 of  these  are responsible for 90 to
95 percent of the total heavy oil production.   At peak production
the major companies were operating over  2100  individually  tanked
wells.  These wells simply  pumped their effluent directly to tanks
at each well site with production then trucked  to central treating
facilities.   Added to  these are over 1400 flowlined wells,  wells
which are pipelined to one of approximately 63 treating batteries
and satellites.

Heavy oil is of  course  referred to as heavy  because  of  its high
viscosity and low gravity which range anywhere  up to  22  degrees  api
or  in metric  units this  relates to a  density greater  than  920
kg/m3.  With such  a wide variance in gravities or density, industry
has had  to  become very creative  and innovative in its  recovery
techniques.   These have involved exotic tertiary recovery schemes
such as  firefloods, steamfloods,  solvent floods,  electromagnetic
stimulation  and in the oil sands area it is  actually  open pit mined
although   we will  not  be  including  the  oil  sands   or  bitumen
production--into this  discussion.   In the fifties,  there  was even
talk of setting off a  nuclear device in some reservoirs to  create
instant caverns of heated  heavy oil.   For some reason  this  method
did not get  approval.

Regardless of which recovery method is used there seems to  be  one
inherent  common problem that operators must deal with on an ongoing
basis.    This  is  of course the produced reservoir  sand  which  is
carried with the  thick heavy oil to surface  and settles out  within
a number of  points throughout  the  production  and treating  chain.
To compound  this  it appears  from statistics  that  the individual
average sand production per well increases throughout  the life  of
that well so any  hopes that in  time this volume would  diminish  as
the wells and fields mature is  certainly an incorrect  assumption.

The majority of the reservoir  sand tend  to settle  in the storage
tanks at  the individual well sites and  in  treater  vessels  at  the
central treating  batteries and satellites.  At  peak production this
would be  approximately 55,000 and 20,000 cubic yards (40 and 15  103
m )  per year respectively.   This material  by  far constitutes  the
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largest problem heavy oil  operators and in part regulators have to
deal with not  only  from the point  of  removing this material from
the production chain but more critically its appropriate disposal.
With each well producing an average of 20  cubic yards  (15 m3)  of
sand each  year, tank  cleaning operations  are a very  common and
highly scheduled occurrence  within the heavy oil patch (Fig. 1)

SAND RECOVERY.  TANK CLEANING

Cleaning  tanks  is  almost  an   industry  in  itself  and  quite
competitive at that  with a number  of  commonly used tank cleaning
methods.    Probably   the  most   common  of  these  goes  by  the
unflattering name  of the  "goon  spoon" tank cleaning method.   In
this method the tank is first emptied of as much fluid as possible
then a large bell hole  is  dug  with a backhoe immediately adjacent
to the manhole access of the storage tank.  A metal drum or tub  is
lowered into the bellhole so that when the access plate is removed
the contents of the tanks  will drop into the tub where the fluids
and solids are gathered by vacuum  trucks and  hauled  to a central
storage area known as an ecology pit.  The "goon spoon" originally
got its name from a specialized attachment to the backhoe arm which
resembles a large spoon which is  inserted into  the tank to pull out
the sand  sitting at the base  of the tank.   Today.- more commonly
used is a wash water, usually warm production water, which helps  in
flushing the sand from the tank and making a  slurry that the vacuum
trucks  can  more  easily  handle.   This method  is  used  quite
extensively  because   once  the   tank   is  cleared  of  the  sand
accumulation  it allows  for entry into  the tank by  maintenance
personnel  to  inspect the  fire tube or any  other  obvious  defects
within the  tank's  interior.   When the operation is  complete the
cover plate is put  back into place, the  tub removed  and the hole
filled in.  The entire  job takes about three hours.

The second most common practice is  the use of a stinger apparatus.
Prior to removal of the sand in this case the tank is flooded with
warm produced  water, injected  near the tank's  base.  This helps  to
lift the  majority  of the  oil  in the tank above the  level of the
sand.  The oil is then  drawn  off and transported  to the  central
treating  facility-   With most of the oil removed  from  the tank a
probe is inserted into a specially designed receptor at the base  of
the tank.  The probe which is  usually   a 4  inch pipe also has a 1
inch, high pressure water  nozzle inserted through it.  Using high
pressure water jets the sand is then made into a slurry and pumped
out through the annular space  between  the 4 inch probe and 1 inch
wash nozzle directly into a vacuum truck.   Here  again the vacuum
truck  would  then  take the  contents  to  a  central  battery  or
processing  area for storage,  under proper  conditions,  until the
sand can be disposed of at a  later date.  Normally with this method
the sand  is a  much cleaner product than what is gathered from the
"goon spoon" method and is often piled on an apron adjacent to the
                               786

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ecology pit.  This will allow any leachate to flow into the ecology
pit itself.  Although this  is  a  less manpower intensive method,  it
does not facilitate  the  inspection of the internal components  of
the storage tank itself.
An additional  method of  tank  cleaning  is  by  using  specialized
mechanical equipment  built solely  for  this purpose.   After all
excess liquids  are  removed  from  the tank  this system uses  a number
of augers and water jets to remove  the sand directly into  a sealed
tank truck.  This equipment is able to move up to the  storage  tank
and seal itself around  the open manhole  access  without having  to
dig a bellhole.  Again, because  access to the inside of the tank  is
through the manhole,  an  inspection of the tank  interior  and  fire
tube can take place.   The waste sand recovered from  the  tank  is
again  transported  to the  ecology  pit for storage prior to its
disposal.

SAND STORAGE

As noted earlier,  most  of  the  sand recovered from the well  site
tanks and also process vessels at the treating facilities is stored
in ecology pits  or desand  tanks.  The ecology  pit is a  concrete
lined  structure   that   must  meet  strict  guidelines   for  its
construction and monitoring.    The design  must  accommodate  an
unloading area and have the ability to clean the solids   from the
pit by mechanical means if necessary.  Monitoring  is  accomplished
primarily with  observation wells which  intersect  a weeping  tile
loop.   The wells must be  sampled  regularly  and analyzed  for not
only  oil and  grease but  for  total  organic carbon, electrical
conductivity,  pH and major  ions such as calcium,  magnesium,  sodium,
potassium, nitrate,  sulphate  and chloride.   The results of these
analyses must then be submitted the ERCB.

One of the great mysteries  seems to be why it was called an ecology
pit as usually  its  content  seems to belie its name.   This structure
is often used for not only collecting the produced  sand retrieved
from  storage   tanks  but  also   oil   spill  material   and debris
associated with lease clean up and housekeeping operations.

The desand tank on  the other hand is an intrical part  of the heavy
oil operations  treating  systems.  Most vessels and tanks within the
production battery  treatment  process are  equipped with  internal
flushing systems which  are regularly  used to clean away  any  sand
build up that may be occurring within those  vessels to the desand
tank.  Free liquids  are frequently skimmed from the desand  tank and
reintroduced into the process system.   The sand and  other solids
are  then subject  to the   same disposal  considerations  as  the
contents of the ecology pits.
                               787

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SAND DISPOSAL

When it comes to disposal techniques there are as many as  there are
tank  cleaning  methods.    The  most  commonly  used  ones  in  the
northeastern part of Alberta  is  to dispose of the oily sand waste
material to municipal  or county roads where  it  is used as a dust
suppressant  or  road  surfacing  material.    Another  alternative,
depending on  the quality of  the  sand,  might be  to use it in the
actual  construction of  a  new road  bed  or in monitored landfill
situations.   A novel practice  that is gaining  popularity is the
downhole injection  of  the sand as a slurry  to  a present or past
producing horizon.  Some work is also progressing on the use of new
salt caverns which are created and used to dispose of the produced
sand  bi-product  simultaneously.    There  also   continues  to  be
research and development into various processes  which will remove
virtually  all of the  hydrocarbons  and  chlorides from  the waste
leaving a relative clean, environmentally friendly sand which would
have a  number of potential uses in  other  industries  where a fine
silica  sand,  similar to this sort  of material, is  needed.   The
income  that  may be  generated by  this new market  would offset  in
part the high  cost  of  transporting and processing the sand.

With this background now covered we will  focus on the-road disposal
techniques only at  this time because it  is  at  present  the  most
common  practice  and  of the greatest concern  to the  ERCB  and
industry  in  as much as  the potential impact it may have  on  the
public  or the  ecosystem.

The  biggest  hurdle   operators  face in dealing  with  the  produced
sand is its disposal.  By  far the disposal of choice  for a number
of reasons over the years has been  to use  the material as a dust
suppressant  or a sort of  cold  paving mixture in road surfacing.
The popularity for this method stems from the  proximity of roads to
the  oily  sand storage areas  as well  as  the  high demand by  some
local   governments   (counties,   municipalities   or   improvement
districts) for this  free  material,  its perceived economic advantage
to  operators  and lack  of  any  other  viable  technology  for  many
years.  It is a perceived economic advantage because there were no
other methods  to compare it against and  operators felt they could
live with the  costs of disposal  related  to this  method.

APPLICATION AND  APPROVAL PROCESS

Let us now examine how the ERCB's enforcement program works within
this  small  specified area.   In  this  situation  as in  almost  all
areas  regulated  by the ERCB,  the application for   approval  to
conduct almost any  operation  is the  backbone  of  a policy which has
a  high  degree  of  compliance  and  certain  assurances  that  all
requirements  will be met.
                                788

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In order for a company to get approval for the disposal of the oily
sand waste  it  must follow  a well  defined  application  process
outlined  in   the  ERCB's   Informational  Letter  IL85-16.     This
informational letter, as is  the  case with many others,  clarifies
and  consolidates  the   ERCB's policy  regarding  the  matter  of
handling, storage and disposal of oily wastes as referenced in its
regulations.   From the  onset  this document makes it clear that the
ERCB has reservations  about  repeated disposal  of oily wastes  by
application to  Municipal  or  other roadway surfaces and believes
that this disposal technique is not the long  term  solution to the
disposal problem.   Not withstanding this,  and  knowing full  well
that other technologies are limited, even more so in 1985 when this
IL  was  written,  the informational  letter goes  on  to list  the
conditions that must be met when using  the material  as  a  dust
suppressant or  as a road  surfacing  material.   The criteria  and
characterization requirements are very general  and, as  such  there
were no  specified limits  on  each of  these elements as standards
were not well defined or even in  existence (Fig.  2).   Variances  in
quality of the  material could  then be handled on a site specific
basis with the responsibility resting with the  company  to  outline
an  environmentally  safe disposal  technique.   The ERCB  would  then
evaluate  the  application  on its merits  and may  then add  as a
condition  of approval,  any  additional  mitigative  measures  as
further safe guards.  An estimated total volume to be disposed  of
and location of  the disposal, must also be provided.   In addition,
once the oily waste is approved  for  disposal,  the operator  must
provide the appropriate ERCB  Area Office with consent  of the  local
authority (Municipal District,  improvement district, County,  etc.)
accepting the waste. Ensuring proper application operations  would
then become the  responsibility of the local authority with most,  if
not all, of the costs borne by the oil company.

Each application  not only  addresses  the reasonable environmental
impact of the disposal  technique through  the characterization  of
,the  material  but will  also  require  the  company  to  address  its
future disposal requirements.  The operator must show that a real
and -concerted  effort  is  being made  towards alternate forms  of
disposal to replace  the roads as the primary  end point for  their
wastes.   This  is  important  because  it  allows  for  a   natural
progression of  having   to  follow through  with new  research  and
development while continuing to allow a relatively easy access  to
an outlet for the waste byproduct.  Overall the application
process is well  defined yet uncomplicated  enough so that it can be
dealt with at  the local level and  with  a minimum of  turnaround
time.  This is important because of the relatively narrow window of
opportunity that exists for the proper application of  the material
to  road  surfaces, usually late  May  to late June.   Enforcement
therefore, is highly reliant on  this application process  and the
clear  understanding of operators  and  regulators  for what  is
require.


                               789

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In the  very rare case  of non-compliance,  the penalties  for not
fully meeting  the requirements may  seem mild to  more litigative
minded individuals yet it proves to be very effective nonetheless*
Prosecutions  through the  court system  have  never  been  a  truly
effective alternative used by the ERCB in its enforcement programs.
Instead the Board has chosen to follow other punitive measures for
which it has a greater control.  As  an enforcement and regulatory
body,  the ERCB's main advantage through  its statutes is to also be
the  licensing  and approval agency within  that industry.  A much
greater threat to a delinquent corporation would be the suspension
of operations  at the offending facility.  Resumption  of activity
and  production  would  only   take  place  once  specific  criteria
outlined by the ERCB were met.  This  may  involve  remedial measures
such as  new equipment and or detailed procedures for conducting
certain practices.   Inefficient time consuming legal  battles with
uncertain results take a tremendous toll on the resources and  moral
of staff,  consequently  it is  our  opinion  that our  enforcement
process is more  effective.

CHANGING POLICY  AND  ENFORCEMENT PROGRAMS

When  problems   or   shortcomings   do  occur   with  a   particular
enforcement program, as it has in this case,  it is not so much due
to non-compliance by  any particular  operator  but  more  through
deficiencies or restrictions which exist  within the policy itself.
In our  Informational letter  IL85-16  two of these were eventually
brought to the ERCB's attention by public interest groups no  less.
One  concern was  the method  in which the  oily  waste was  being
applied to  road  surfaces  and the  other had to do with the use of
this  material for  private country  residential  purposes.    This
presented quite  a contradiction and  paradox as on one hand  there
was a sector of the public  concerned with the way this material was
being put on roads and any potential  adverse  environmental effects
while another group was lobbying very hard to get access to it for
their own private use.  The group objecting  to the widespread use
of this  material on secondary  roads reacted because  of  improper
practices in an  isolated area.

Normally, there  would have only been a single  application of oily
waste material to a  stretch  of road  in the same year,  however in
some areas  repeated  applications  were being put on the same road
within the  same  year and very often  over consecutive  years.   This
heavy road  application would  repeatedly  cover  up low  spots in the
road with quite a thick layer of the oily waste which tended to rut
quite badly from heavy truck traffic.   The oily waste material,
unless very careful preparation steps are taken,  does not have the
type of  consistency which gives  it  a good  durable quality  as a
paving material.   Local landowners therefore  driving  up  and down
these municipal  roads find these ruts particularly dangerous and
damaging  to  their  vehicles.   The  generalized  nature  of our
                               790

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characterization for the waste, approving it for road  disposal as
specified in the Informational  Letter IL85-16,  did not  take  into
consideration repeated applications  of  waste over the same area.
Damage to the local ecosystem  in  these  instances could  then  be a
very  real  possibility  with  this   unexpected   increase  in   the
leachable elements of the waste.

In the other situation the Informational Letter states very clearly
that private driveways  and parking areas will  not be allowed  as
disposal  areas  for the  oily waste  materials.    Therefore,   when
private landowners requested their  local government to  undertake
some form of dust  suppression  on  the municipal roads in  front  of
their homes,  it was  often  done  with  this oily  waste   material
donated by  a local oil company.  Some  individuals saw this  as  a
real benefit, and   wondered if they  could  surface their  private
lanes from the municipal road to their homes and outer buildings.
They could  not  understand the  logic in why the  ERCB  would  deny
these requests when its  saw  fit to  approve  the material  to go  on
the municipal road immediately  in front of  their homes.    It  soon
became clear to the public, local authorities, heavy oil operators,
and the ERCB that some refinement of the policy outlined by IL85-16
was  required.   The  first  step therefore,   was to  survey local
government authorities and the  various private interest groups for
what they felt would  be reasonable,  the ERCB  then struck a  task
force to look at rewriting the informational  letter and  updating it
to the concerns outlined  by the interested parties.  The task force
was eventually made up  of  key  industry  personnel specializing  in
environmental matters,  other  government of Alberta departments  with
expertise in this  area such  as Environment and Transportation,  as
well  as  highly   respected  representation   from   the  scientific
community and of course a number of  appropriate  senior ERCB staff.
The overall objective was to cover two main  areas,  the  first being
of  proper characterization of  the  waste so that  if an  analysis
showed the material met the analytical criteria  this  would mean it
would be sufficiently safe and benign so that it might be used  in
any road application situation  whether it were local  government or
private.  The second point was to develop guidelines in appropriate
methods and frequency of surfacing roads with this  material and to
also deal with  the issue  of liability  for  the  waste  during  and
after its disposal to the road surface.

All of  the data  that  had been collected from  earlier  years  of
disposal  following the original guidelines  set in  informational
letter IL85-16 was felt to be unusable by the scientific  sector of
the  task force because  of  the  inconsistencies in  sampling  and
analyses  methodology  which  took  place  in  the  past.   The first
recommendation was to  develop a single  appropriate  protocol  for
sampling  and  analysis  to  be  used  by  all  operators   so   that
consistent and meaningful data  could be  generated to  indicate  what
were  the predominant  components  found  in the  oily waste.  In
                              791

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developing the analytical protocol  it  was felt that before ruling
out the need to look for certain elements,  it was necessary to know
if they were even present,  at least in large enough concentrations
to be of concern.   The decision was to cover areas related to the
physical parameters,  inorganics  and organics  (Fig.  3).   The ERCB
then took on the  responsibility for  contacting  all operators in the
heavy oil sector and informing them of this protocol requirement
and explain  why  this was required.   The  next step  was  to gather
existing road surfacing techniques  being  used  by operators around
the area as well as good engineering practices endorsed by Alberta
Transportation and tabulate these,  assess them, and  develop  one
preferred method.   This method would  then be discussed  with  the
local municipal governments who were active in using this material
on the roads as well as the majority of operators in the heavy  oil
area, note  their comments and suggestions and then  finalize  the
technique.   The  operating companies felt  that  liability  regarding
the waste would always lie with them and therefore,  as a  condition
of approval  for disposal,  the operator  must  supervise  the road
surfacing  program.  In  this way    conformity    to  the  preferred
technique would be assured if for some reason the local government
or contractor wanted to deviate from the  program.

This  entire exercise,  in  which  participation came  from a wide
variety of responsible and concerned parties will  result  in  a  new
informational  letter  which must  include an effective  set  of
guidelines with responsibilities and requirements clearly defined.
The application and approval  process will provide enough checks  and
balances along with the open willingness of industry for compliance
with  the  policy.  Any problems which  may develop will more than
likely  be the result of a  change  in perception by  any of  the
interested parties or new  data regarding this process.   For  now
the  public's  needs  and  concerns  will  have  been  met,   local
governments  can  still realize considerable savings to their  own
maintenance  programs, industry's  very real  need to  responsibly
handle  their wastes  met and the ERCB will have a  practical  and
almost self  administering enforcement  program  in place.
                               792

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Gravity of Heavy Oil                  22.2° API or greater

Number of operating companies                      13

Percentage of total Heavy Oil production           90 - 95%

Number of wells with tanks                        2 100

Number of wells with flowlines                     1 400

Number of batteries with treaters                      63
                                              o
Sand production from wells with tanks         55 000 yd /yr.

Sand production from wells with flowlines      20 000 yd3/yr.

Average sand production per well               21 yd3/yr.

                  FIGURE 1
       SAND PRODUCTION IN HEAVY
              OIL OPERATIONS
(a) The waste must not contain significant amounts of free
   salt water, fracturing acids, or other non-hydrocarbon
   contaminants, halogenated hydrocarbon, or
   other manufactured oils.

(b) The oil in the oily waste must be of relatively high density.

(c) An analysis for free water content and chlorides is required

(d) Hazardous chemicals and the volumes injected during
   production must be identified.

(e) An estimated total volume to be disposed of and location of
   disposal must be provided.

                   FIGURE 2
DUST SUPPRESSION CHARACTERIZATION
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1.  Bulk density of the sample
2.  Composition - percentages of oil, solids and water will be conducted on
   the whole sample.

3.  Specific gravity of the oil phase is required.

4a. Flashpoint
4b. Viscosity of the oil phase.

5.  Total Chlorides, mg/l, in the sample phase and extract
   from solid phase required. SAR (Ca, Na, Mg) and E.G. also required.
   Free water phase must not be present for total chlorides determination.

6.  pH.

7.  Total heavy metal content:
   - Boron      - Chromium   - Lead        - Nickel
   - Cadmium    - Mercury     - Manganese   - Vanadium

8.  teachable heavy metals (mg/l):
   - Boron      - Chromium   - Lead        - Nickel
   - Cadmium    - Mercury     - Manganese   - Vanadium

9.  Leachable Phenols:
   The committee agreed to analyze during the summer testing program on a
   representative number of wells to assess whether phenol determination
   is required in the final guidelines.

lO.Organic solvents:
   - Benzene     - Ethylbenzene
   - Toluene      - Xylene

11.Chlorinated Organic Screen Test:
   This will be qualified similarly to Leachable Phenols.

12. Aromatic Hydrocarbons:
   - Acenaphthene        - Anthracene           - Benzo (a) pyrene
   - Acenaphthylene      - Benzo (a) anthracene    - Benzo (b) fluoranthene
   - Benzo (ghi) perylene   - Chrysene             - Fluorene
   - Benzo (k) fluoranthene - Fluoranthene          - Naphthalene
   - Phenanthrene        - Indeno (1,2,3-cd) pyrene - Pyrene
   - Dibenzo (a,h) anthracene

                      FIGURE 3

   NEW ANALYTICAL REQUIREMENTS
                               794

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PRS TREATMENT AND REUSE OF OILFIELD WASTEWATERS
Mr.  Ernst Schmidt
V.P. Technical Services
Preferred Reduction Services, Inc.
San Clemente,  California
(714) 498-8090
Ms. Shirlee Jaeger
Chemical Engineer
Preferred Reduction Services, Inc.
San Clemente, California
Abstract

PREFERRED REDUCTION SERVICES, INC.  (PRS) used a three phase
program to develop and demonstrate an economical alternative  for
treatment and reuse of oilfield wastewaters.  Scrubber blowdown,
produced waters from steam flooding, and non-dispersed water-
based drilling muds were used in the program.  Identical
physical/chemical treatment equipment was used for each waste,
however, each waste required a different treatment scheme.  Each
treatment scheme resulted in environmentally acceptable liquid
and solid products suitable for reuse.

Phase I sampled and characterized the wastewaters resulting from
production and exploration activities.  Phase II involved bench-
scale treatment testing for the samples collected.  The results
provided data predicting the expected efficiency of full-scale
demonstrations.  Phase III field tested full-scale
physical/chemical treatment equipment.  Average removal
efficiencies for total suspended solids, chemical oxygen demand,
and oil & grease were greater than 95 percent.  Operating costs
and water reuse options were also determined.

Treated scrubber blowdown was of suitable quality to be reused as
an oxygen scavenger.  Treated produced waters were suitable for
reuse in boiler feedwater pretreatment.  Treated drilling muds
were suitable for reuse in drilling operations.  The solid
residues produced were suitable for reuse in cement block and
asphalt manufacturing.
                                795

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The demonstration conducted by PRS showed that  treatment and
reuse options can be both viable and economically beneficial.

Background

Historically, drilling fluids, produced waters  and other wastes
associated with crude oil or natural gas production have been
exempted from Federal and State Regulation.  Management of these
wastes have occurred in surface impoundments and  underground
injection wells.  Due to the nature and quantity  of these wastes,
and growing environmental concerns, impoundment and injection  are
becoming less attractive.

Since 1982, all crude fired steam generators in Kern county,
existing and new, were required to have scrubbers to reduce air
emissions.  Wet sulfur dioxide scrubbers are predominantly used
as air pollution control devices.

During use scrubber waters are contaminated by  constituents in
the gas stream.  Oilfield scrubber wastewater consists  of sodium
sulfite, sodium bisulfite and sodium sulfate.   The pH of the
scrubber water will vary depending on the type  of scrubber used.
Contaminated scrubber water is typically shipped  off-site for
disposal, or treated to remove fly ash and deep well injected.

Secondary oil recovery is very common in Kern County, California
and in other heavy oil producing areas of the United States.  In
secondary oil recovery, water is pretreated, fed  to a boiler,
superheated and dispersed to well heads via feeder lines.   From
the well head the steam is injected into a formation to loosen
crude deposits.  The steam and loosened crude are brought to the
surface where the oil is skimmed and refined.   The byproduct of
this activity is wastewater, referred to as produced water.  This
produced water is contaminated with oil, minerals and other
natural substances.

Drilling mud is circulated through a well bore  during drilling to
remove cuttings from down-hole and to lubricate and cool the
drill pipe and bit.  During drilling a portion  of the mud is
rejected and jetted out into a reserve pit.  Reserve pit drilling
muds vary in salt, metal and oil concentration.   High
concentrations of salt and metals in the pits can complicate and
limit closure options.

PRS designs, builds, manages and operates specialized central use
facilities.  PRS also provides either mobile or fixed treatment
capability.  To expand the applications of mobile units, PRS
conducted a three phase program on the treatment  of production
wastewaters.  The goals of the program were to:

     1.  Characterize samples of oilfield wastewaters,
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    2.  Develop  a treatment scheme for each waste,
    3.  Evaluate full scale treatment equipment and
        schemes,
    4.  Investigate reuse options, and
    5.  Determine if treatment and reuse are economically
        viable.

Among  the  mobile  equipment available, a packaged in-line
physical-chemical (PC) unit and a 1-meter belt press were chosen
for consideration in the demonstration program.  The PC unit  was
selected due to inherent flexibility and reliable treatment
efficacy.   The mobile belt press is considered a useful tool  for
dewatering of high solid content sludges.  The PC unit has also
been used  in combinations with the belt press for secondary
treatment  of filtrate and backwash water, resulting from press
dewatering.

Process Description

PRS's  Physical-Chemical technology, PC, is proven on a full-scale
basis  for  the treatment of waste streams generated by the metal
finishing, electrical and electronic, paint formulation, battery
manufacturing and timber production industries.  The PC system is
capable of performing any of the following processes:

     pH Control                         Neutralization
     Skimming                           Emulsion Breaking
     Detoxification                     Adsorption
     Chemical Fixation                  Coagulation
     Flocculation                       Filtration
     Precipitation/Co-Precipitation
     Chemical Oxidation and Reduction

The PRS PC systems typically reduce the volume of waste by 95%.
The products of the treatment process are treated liquid effluent
and solid  cake.  The effluent is of suitable quality for further
treatment  and reuse or discharge under Federal pretreatment
requirements.  The solid cake can either be recycled, reduced in
toxicity,  rendered nonhazardous, landfilled or incinerated.  A
summary of tests conducted to validate the processing
capabilities are available from PRS.

The PRS PC systems are designed to achieve tertiary treatment in
one step,  while producing manageable sidestreams.  Substantial
removals,  > 99%,  are thus economically achieved by employing this
technology.

Briefly, the PC systems use chemical and physical means to
separate and concentrate contaminants in a waste.  A complete
cycling of influent is typically done in less than 45 minutes,
and sometimes as low as 5 or 10 minutes.  This process maintains
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certain chemical process patents.   Controls and filtration
techniques are of proprietary nature.

Additional characteristics of the  PC  systems are; 1)  the
materials of construction provide  for ideal corrosion protection;
2) the system allows for "add-on"  chemical  addition systems; 3)
the control system is designed to  provide feed-back or feed-
forward control of chemical addition;  4) the control  monitors
adjust the addition rate of chemicals;  5) the microprocessor
controls allow for fail-safe, unattended operation; and 6)  the
system operates on a demand basis  which conserves power for
intermittent wastestreams.

Wastewater Characteristics

In Phase I the wastes were characterized and bench test
parameters were determined.  A literature review  and  sampling was
conducted.  Samples were collected from oil  fields in Kern
County, California.  Generally, the chemical characteristics of
concern for scrubber wastewater are pH, toxic metals,  total
suspended solids  (TSS) and total dissolved  solids (TDS).

Produced waters are generally contaminated  by conventional
pollutants.  Specifically, Chemical Oxygen  Demand (COD), Total
Suspended Solids  (TSS), Oil & Grease  (O&G)  and trace  metals.

Drilling fluids are contaminated with high TSS, high  TDS and
salt, drilling lubricant additives, COD, metals and trace
organics.

Tables 1, 2 and 3 show expected characteristics of scrubber
blowdown, produced water and drilling mud.
                             Table 1
                        Scrubber Blowdown
Constituent
Boron, B
Chloride, Cl
Calcium, Ca
Copper, Cu
Chromium, Cr
Iron, Fe
Potassium, K
Magnesium, Mg
Nickel, Ni
Sodium, Na
Sulfur, S

PH
Conductivity
  mg/1
  35.0
2130.0
  31.0
   0.49
   0.16
  95.0
  42.0
  29.0
   0.29
2060.0
   0.0

   6.89
9270 /imho/cm
Constituent
Vanadium, V
Zinc, Zn
Silica, SiO2
Sulfite, SO3
Sulfate, 804
Bicarbonate, HC03
Carbonate, C03
Hydroxide
Calcium Carbonate
Sodium Chloride, NaCl
TDS
TSS
    ,0
    ,0
   mg/1
   31.0
    0.20
  150.0
32500.0
   67,
 2324,
    0.0
    0.0
  367.0
 4953.0
5950.0
 540.0
                               798

-------
                             Table 2
                          Drilling Mud
rnnatituent
Arsenic, As
Barium, Ba
Cadmium, Cd
Chloride, Cl
Copper, Cu
Chromium, Cr
Iron,  Fe
Lead,  Pb
Nickel, Ni
Vanadium, V
Zinc,  Zn
 mg/1
  2.0
 45.0
  0
530.0
 11.0
 10.0
100.4
 15.0
 12.0
 18.0
 47.0
58
Constituent
PH
% Solids
TSS
Specific Gravity
C.O.D.
Conductivity
            Benzene
            Ethyl Benzene
            Toluene
            Xylenes
  ma/1
   8.3
  19.25
 540.0
   1.004
 550.0
3335 /imho/cm

  ttg/kg
   15
   23
   91
  240
                             Figure 3
                          Produced Water
               Constituent
               pH
               Conductivity
               Chloride, Cl
               C.O.D.
                 mg/1
                   8.3
                3335.0
                 530.0
                 550.0
 Bench-Scale Testing
 Phase II bench-scale treatment investigations were conducted  on
 samples collected.  The purpose of bench-testing was  to  determine
 the proper treatment scheme for each waste.  These schemes  would
 be used in the full-scale demonstration.  Cost estimates were
 also prepared to estimate the economic viability of treatment.

 Coagulants, flocculants, polymers, metal precipitation and  rotary
 vacuum filtration were used in the treatment.  Precoat filtration
 was used for scrubber blowdown and produced water.  Conventional
 rotary vac and belt press dewatering were used for non dispersed
 drilling muds.  The results of bench testing are detailed in
 Figures 5, 6 and 7.

 Scrubber samples used for bench scale testing were supplied to
 PRS by the generators.  The generator verified them as
 representative.  Treatment consisted of temperature adjustment,
 coagulation, flocculation and precoat filtration.  Precoat
 filtration was simulated on PRS's bench scale treatment  system
 (.4 square feet of filter area).  This precoat filter results in
 submicron removal of particulates.  The treatment resulted  in >
 99 % removal of total suspended solids.  The treatment did  not
 result in any sidestreams which required further treatment.   The
                                799

-------
filter cake had a solids content  of  >  65  % (dry weight) and was
easily manageable.

                             Table 4
             Bench Scale Results on Scrubber Slowdown
Parameter
Arsenic, As
Barium, Ba
Cadmium, Cd
Chromium, total
Copper, Cu
Iron,  Fe
Lead,  Pb
Mercury, Hg
Nickel, Ni
Zinc,  Zn
Sulfide
Chloride, Cl
Sulfate, 804
Sulfite, 863
TSS
PH

All  units are ppm.
Influent  Effluent
ND<0.001
ND<0.1
ND<0.005
ND<0.05
   0.11    <0.08
   7.0     <0.34
ND<0.1
ND<0.2
ND<0.04
ND<0.005
ND<1.00
          100.0
       <10000.0
       <35000.0
          <10.0
6-9       6-9
Filter Cake
 ND<0.001
 ND<0.1
 ND<0.005
    7.99
 ND<0.02
 8493.0
 ND<0.1
 ND<0.2
 ND<0.04
  230.30
% Removal
   27.27
   95.14
 For  drilling mud, bench  test  samples were  obtained  from three
 randomly  selected reserve pits.  All but one  of  the samples were
 water  based, and non-dispersed.  Treatment studies  involved
 flocculation jar tests and mechanical dewatering by different
 techniques.  The mud  and water phases were treated  together.

 It was determined that at high solids content (>15%),
 flocculation of particles was difficult.   The most  effective
 polymers  tested were  nonionic and moderately  charged anionic
 types.  One sample  required significant amounts  of  flocculant to
 overcome  the effects  of  dispersants.  The  separation achieved,
 however,  was very fragile.

 A filter  leaf  with  a  septum of 5 micron retention was determined
 to be  the most effective in dewatering studies.   Dewatering of
 polymer treated muds  resulted in solids capture  > 99%.   The
 resulting cake was  35 %  solids by dry weight. Through the use of
 additional body-fed filter-aids, cake solids  content increased to
 48 %.   The filter-aids also increased dewatering rates, prevented
 blinding  of the septum and provided solidification/stabilization
 of metals.
                               800

-------
                             Table 5
              Bench Scale Results  on Drilling Muds
Parameter
Arsenic, As
Barium,  Ba
Cadmium, Cd
Chromium,  total
Copper,  Cu
Iron,  Fe
Lead,  Pb
Mercury, Hg
Nickel,  Ni
Zinc,  Zn
Benzene (jxg/1)
Toluene (/zg/1)
Ethyl Benzene
Xylene  (/ig/1)
0 & G
COD
Conductivity
Chloride,  Cl
TSS
Total Solids
PH
Influent
ND<0.001
ND<0.1
ND<0.005
0.19
0.11
100.4
ND<0.1
ND<0.2
0.13
4.22
11.55
12.47
Mg/1) 31.90
6.73
Effluent
-
-
-
ND<0.05
0.04
<0.03
-
-
ND<0.04
0.38
ND
ND
ND
ND
Filter Cake
ND<0.001
5.20
ND<0.005
50.30
24.40
415.5
ND<0.1
ND<0.2
24.30
85.90
ND
ND
ND
ND
                                                        Effluent
                                                        % Removal
                                                           73.68
                                                           63.64
                                                           99.97
                                                           69.23
                                                           91.00
                                                           99 +
                                                           99 +
                                                           99
                                                           99
                               <150
                              <800 /imho/cm
                              <1000
19
 8
.25%
.72
0.16%
7.0
                                                           99.17
All units in ppm unless otherwise indicated.
ND = not detected

For produced waters,  samples were taken and verified  as
representative by oilfield personnel.  The samples were  labelled
as produced water and multimedia filter backwash water resulting
from the treatment of production waters.  The treatment  scheme
used was identical to that used for scrubber waters,  but included
pH control and a different coagulant.  This coagulant also
exhibited oxidization properties.

The treatment consisted of pH adjustment, coagulation,
flocculation and precoat filtration.  The same filtration media
was used as with scrubber waters; 1 micron retention  septum with
2 inch precoat.   The  influent samples were relatively free of
arsenic, barium,  cadmium and chromium, therefore removal
effectiveness could not be determined.  It is predicted  that the
removal of these metals will be greater than that achieved for
scrubber water since  pH was controlled.  The PC-M30 has
consistently shown 99+ % removal for these metals in  dilute
wastewater.

The treatment did not produce any sidestreams which required
further treatment. The filter cake was > 40 % solids (dry
                              801

-------
weight).  The filtrate was suitable  for return  as  boiler
feedwater.
                             Table  6
              Bench Scale Results on Produced Waters
Parameter
Arsenic, As
Barium, Ba
Cadmium, Cd
Chromium, total
Copper, Cu
Iron Fe
Lead, Pb
Mercury, Hg
Nickel, Ni
Zinc, Zn
COD
Conductivity
Chloride, Cl
TSS
TDS
Influent
ND<0.001
ND<0.1
ND<0.005
ND<0.05
0.49
0.33
ND<0.1
ND<0.2
0.49
0.20
550.0
3335.0
530.0

Effluent
ND<0.001
ND<0.1
ND<0.005
ND<0.05
ND<0.02
<0.03
ND<0.1
ND<0.2
ND<0.04
0.26
175.0
2500.0
230.0
7.0
1343.0
          % Removal
             95.92
             90.91
             91.84
              0
             68.18
             25.04
             56.60
All units in ppm unless otherwise indicated.
                                802

-------
§
CO
                                                         FIGURE 1
                                        PC-M30  TREATMENT FLOW  DIAGRAM
                                                    OILFIELD WASTES
                                Optional Dry     Dry Clicmical
                               Chemical Feeder      Feeder
        EFFLUTNT
pi! Monitor/
Controller
           FILTH? CAKE
                                                                          o

                                                   Flocculating Concilia ting
                                                      Agwit       Agent
                                         Process
                                          Pump
                           O
                                                                                                           WASTE
                                                                                                           INFLUENT
          Acidifying     Oxidizing
            Agent
                                                                                   Preferred Reduction Services,  Inc.

-------
               FIGURE 2
PRS PHYISCAL/CHEMICAL TREATMENT UNIT
               (PC-M30)

-------
yield Demonstration

Phase III field tested the bench-scale treatment  schemes.   The
full scale demonstration was conducted in Kern County,  California
by PRS.   The PRS PC-M30 (Physical Chemical Treatment  unit)  was
transported to the oilfield on a single semitrailer.  Setting up
the demonstration equipment involved hookup to waste  and power
supply.

The demonstration was conducted on scrubber blowdown  and produced
waters only.  Permission to treat drilling muds onsite  could  not
be obtained from the generator in time to be included in the
demonstration.  The generator also retained the demonstration
data on the produced water.

The demonstration was conducted over a three day  period.  In  that
time, 6500 gallons of scrubber blowdown and 15000 gallons of
produced water were treated.  As a result of bench scale work,
minimal optimization was required.  The PC-M30 proved to be quite
adaptable to each of the different streams tested.

                             Table 7
               Field  Treatment  of  Scrubber  Blowdown
Parameter
Chromium, tot
Copper, Cu
Iron, Fe
Nickel, Ni
Vanadium, V
PH
TSS
Total Solids
Influent  Effluent  Filter Cake
  0.16
  0.18
  7.56
  8.84
 36.75
  6.8
15400
0.08
0.04
0.34
0.65
2.45
6.6
3.0
  48.70
   9.73
2063.0
1739.0
1635.0
                       68.0%
% Removal
     50.00
     77.78
     95.50
     92.65
     93.33

     99.98
 * All units are in ppm.
The scrubber blowdown generator's only objective was to evaluate
the degree of suspended solids removal and filter cake moisture.
As a result, no attempts were made to remove soluble metals.  In
the demonstration higher removal efficiencies were achieved for
copper and iron than in bench tests.

The treated scrubber water was suitable for return use in boiler
feedwater pretreatment.

Due the organics contained in produced water and drilling muds,
carbon adsorption is recommended for future installation.
                              805

-------
Conclusions and Results

PREFERRED REDUCTION SERVICES, INC. proved  that the treatment of
scrubber water, produced water and drilling  mud was not only
feasible, but economical.

The residual sodium sulfite from treated scrubber blowdown can be
effectively reused as an oxygen scavenger  in boiler feed waters.
The treated scrubber effluent can contain  between 2.3-5.5% sodium
sulfite and sodium bisulfite.  In using the  treated scrubber
effluent as an oxygen scavenger cost savings are realized from
reduced sodium sulfite purchases and steam generator feedwater
quality is improved.

The drilling mud and produced water effluents  were of good
quality for reapplication in field operations.   With further
treatment these waters, primarily for salts, could be made
suitable for irrigation and potable uses.

Treating these oilfield wastes provides several  benefits:
1)   Environmental liability associated with land  application,
     impoundment, and underground injection  is minimized,
2)   Potential migration from impoundment  and  injection  is
     minimized,
3)   The esthetics and public perception of  oilfield activities
     can be increased by decreasing the use  of impoundments,
4)   Cost saving can be realized from reuse  of the treated
     effluents.

Several options exist for management of treated  water.
Specifically, reuse in the production field, deep  well injection,
sewering, NPDES discharge, or use as irrigation  with further
treatment.  Since many large fields are located  in semi-arid
climates, the potential benefits of water  recycling are great.

The filter cakes generated were high in solids content, therefore
required no further solidification prior to  landfilling.   The
land disposal treatment standards may require the  cakes to be
treated by stabilization or metals recovery  prior  to land
disposal.

An outlet discovered for the reuse of filter cake  is in cinder
block and asphalt manufacturing.  In order to make the filter
cake a viable substitute in either of these  applications,
considerable quantities are needed by the  manufacturer.  The
quantities of wastewater produced in oilfield activities is
sufficient to meet this need.  Use of the  filter cake as a
substitute for raw materials is the preferred method of cake
management.  Management of this type eliminates  disposal
headaches for the generator and reduces costs for  the
manufacturer.
                               806

-------
in conclusion,  proper treatment of wastewaters  resulting from
oilfield activities are waste specific.  Laboratory  treatment
diagnosis is required to establish monitoring criteria  and to
avoid potential problems when specifying treatment equipment.
It is important to identify how interacting processes may affect
one another when selecting a treatment train.

Proper planning can reduce reserve pit problems.  Specifically,
lubricating oil, trash, and completion work brines should not  be
placed in the reserve pit.


Bibliography

Lueterman, A.J.J., Jones, F.V. and Candler, J.E.  "Drilling
Fluids and Reserve Pit Toxicity."  Proceedings  of the Third
National Conference on Drilling Muds.  May 1987.

Jones, F.V., Moffitt, C.M. and Lerterman, A.J.J. " Drilling
Fluids Disposal Regulations; A Critical Review."  Drilling,
March/April 1987.

Hanson, P.M. and Jones, F.V.  "Mud Disposal; An Industry
Perspective."  Drilling, May, 1986

Williams, R.L. and Harris, A.  "Use of Scrubber Waste as  an
Oxygen Scavenger in Thermal Water Plant Operations."  SPE
California Regional Meeting, April, 1987.

Environmental Protection Agency.  "Technical Report Exploration,
Development, and Production of Crude Oil and Natural Gas.  Field
Sampling and Analysis Report."  1987, 530-SW-87-005.
 f: \gencor\ogpaper
                               807

-------
           A RAPID METHOD FOR THE DETERMINATION OF THE  RADIUM
                 CONTENT OF PETROLEUM PRODUCTION WASTES
H. T.  Miller and E. D. Bruce
Chevron Environmental Health Center, Inc.
P.O. Box 4054
Richmond, CA  94804

and L. M. Scott
Center for Energy Studies
L.S.U.
Baton Rouge, LA  70868

                                Abstract

A  rapid assay method that can identify, with a high degree of assurance,
if  the  Naturally  Occurring  Radioactive  Materials  (NORM)  present  is
deminimis  or  if  certain levels  warrant concern,  is essential   to  the
successful  and  cost  effective  management  of  NORM  wastes  and  NORM
contaminated   equipment.   This  paper  addresses   the  measurement   of
radiation fields around equipment at  the work site and demonstrates that
under rigidly controlled conditions of sample geometry, it is possible  to
reliably  estimate the  specific  activity of NORM  material contained  in
sample bottles and in drums.

The  results of field instrument  assays for laboratory spiked  materials
containing  226  Radium,  for  laboratory  samples generated  by diluting
assayed  samples of scales and sludges and for  an assemblage of 50 field
samples  of  varying  sample weights  are presented.   These results  are
compared  with  theoretical  calculations  and  are found  to be  in good
agreement.    Similar   results   are  presented   for  drum   materials.
Theoretical  calculations made  for  tubing containing scale  also  appear
consistent  with field sample results reported for the United Kingdom and
those performed in the United States.

Recommended  sample correlations are presented for bottled samples, drums
and tubing.

Introduction

The safe handling of production generated Naturally Occurring Radioactive
Materials  depends upon methods of  identifying where such materials  are
found, quantifying the level of NORM present and having options available
                                 809

-------
to manage the materials in an environmentally  safe  manner.   226 Radium is
easily found with hand held survey meters  and  the results of such surveys
have  been widely distributed by  the American Petroleum Institute  (API)
and  others.  Experience with the management of Uranium mill tailings and
phosphate  fertilizer  production  waste,  as   well  as  studies  in  the
petroleum   industry  suggest  that  there are a   number   of  available
management technologies that can be employed.

The main problem facing petroleum operators is  the  lack of  proven sets of
rapid  methods for reliably and conservatively  estimating the quantity of
Radium present.

The  State  of  Louisiana has  partially addressed   this  issue  in recent
emergency  regulations.   It  specified  that   any   site  where  radiation
exposure  levels exceeded 50 uR/hr must be registered with  the Department
of  Environmental  Quality.   It  did  not,  except  by   implying  that a
radioactive  assay be  conducted, specify  how  to   determine  whether   the
Radium present was deminimis.

Radioactivity assays are expensive.   (They cost between 50  to  150 dollars
per  sample depending upon the total numbers of samples submitted and  the
complexity  of the assay.)  The sample turn around  time can be as long as
ninety days.  It would greatly improve operational  efficiency  and overall
productivity  if a simple screening method could be  used  to determine  the
need  for a more elaborate analysis or to present a  conservative  estimate
of content to expedite waste management decisions.

It  is the  purpose  of this  paper  to describe some  simple methods for
estimating  the quantity  of Radium  present and  to suggest  measurement
methods and correlations for field operator use.

Materials and Methods

The  first problem that had to be resolved  in  the development of  a rapid
screening method was the identification of standard geometries to  be used
in  making the measurement.   Most  of the equipment in   the oil  patch is
non-standard  in shape and size and is selected to meet field conditions.
There  are some fairly standard  items such as production  tubing, sucker
rods,   fifty-five  gallon  drums  and  sample   bottles.   The   standard
geometries identified as offering the best promise  for the development of
a  screening method were production tubing,  fifty-five gallon drums, and
completely  filled wide-mouthed,  one-liter polyethylene   sampling  bottles
(Fisher Scientific or equivalent).

The hand-held survey meters selected for use in this study are typical of
those currently in use in the industry.   The survey  instruments used were
the Ludlum Model 19 Micro R meter (one by one Sodium Iodide detector with
a  rate meter readout, sensitivity 180-200 cpm per uR/hr.) and the Ludlum
                                  810

-------
Model  97-3.   The Ludlum  97-3 is a  Model  19  that   has been modified  to
accept  an input  from an  external detector   as  well  as its  internally
mounted scintillation detector.

The  use of a portable sealer/single channel   analyzer  (Ludlum model 2221
using  a Ludlum Model  4410  two by two Sodium Iodide  detector)  was also
evaluated as a measurement tool.

The  hand-held survey instruments used  in  this study were   calibrated at
Ludlum's  Sweetwater,  Texas  facility  using  a  137  Cesium  source  to
calibrate the zero to 5 mR/hr range and to  determine  the  ratio of cpm per
uR/hr.  A pulse generator was used to calibrate the other ranges.

This  calibration  method  was  selected  instead  of  comparison with  a
pressurized   ionization  chamber,  because  the  manufacturers   standard
calibration  was the one most likely to be  consistently used  by the  field
operators.   The portable  sealer was  calibrated in  accordance  with  he
manufacturer's instructions.

It   was decided to   take measurements with  the instrument placed at the
following locations:

      1.  Resting  at the center  and in contact  with the tops  of filled
         drums;

      2.  With  the most sensitive part of the  instrument in  contact  with
         the  center of  the bottom  and at  the sides  of filled  sample
         bottles; and

      3.  Where  possible,  at  the  center  lengthwise,   of   a  piece  of
         production  tubing (joint).

Samples  were  also  collected  for  gamma  ray  assay  by  Controls   for
Environmental Pollution (CEP) of Santa Fe, New Mexico in  order to provide
correlations between field measurements and the specific  activity present
in   the  vessel,  sample bottle,  or joint  being examined.    Each sample
provided  to CEP contained between  800 to 2100 gms   of material  (average
1383  gms plus  or  minus 83 gms).   Measurements were  also   taken at the
bottom and around the circumference along the vertical  center  line before
sending the sample to CEP.

CEP   was instructed  to hold all samples  until equilibrium with the Radon
daughters  was reached and to report the  measured specific activities  of
226   Radium, 228 Radium  and daughter products.   Sample  weight was   also
reported.

In   conjunction with  the  collection of field  samples,  standard samples
consisting  of Louisiana  Chalk  spiked with NBS  traceable quantities  of
                                 811

-------
Radium  solution or  actual  assayed  production scale  and sludge samples
diluted  with New  Mexico  sand  were  prepared.    The tare weight  and the
sample  specific activity  were   recorded  for each  sample.  Measurements
were  taken on these samples   using  the  hand held  survey instruments and
the  portable sealer with  the window open  and with the  window centered
over the .609 kEv photopeak of 214 Bismuth.

Theoretical  correlations  derived  using  simple  computer programs  were
prepared  and were compared with the  results  of field measurements.  The
correlations  for the  top of drum  and bottom of sample bottle  assumed  a
point  detector and  calculated  the   radiation  from  each one  centimeter
layer  for a range of  densities.  Correlations derived for  pipe and the
side-on  measurements  of sample  bottles  assumed that  all the material in
the  container was concentrated  in a  plane parallel to the surface of the
detector  and that a   point detector  was   positioned one radius  from the
geometric center of the plane.   Correlations were prepared for pipe  which
were  two, two and one half, and three inches in inside diameter and with
varying thicknesses of deposit and material  densities.

Results

It  was clearly  evident, as   demonstrated by .Figure  1,   that  the   total
quantity  of radium present correlated well  with the readings  of the hand
held  survey  meters   and the  portable  sealer.    It  appeared   that  small
deviations  in  sample  geometry,  wide  variations   in  sample size and
differences in sample  density  did not  effect  the overall  result.

The best correlations  were noted for  the case of bottled  samples.  Figure
2  shows the results   of the field  measurements normalized for  density.
Figure  3 shows the calculated   response for  the same   samples.   Figure 4
shows  the results  for  the New Mexico  and  Louisiana  spiked   materials,
while  Figure  5  shows  the   agreement  between   the field  and predicted
results  at the same density.  Figure  6  shows the  confidence  interval for
the fit of the regression line.

The  results  of  measurements using   spiked  materials   and the  portable
sealer  are shown in   Figure   7  and the  results   using  the  single channel
analyzer mode are shown in Figure 8.

Theoretical and experimental correlations  for drummed  materials are  shown
in Figures 9 and 10.

Theoretical and experimental correlations  for tubing are  shown  in Figures
11 and 12.
                                812

-------
Conclusions

Material  contained in full wide-mouth, one-liter  sampling bottles can be
assayed using hand-held survey meters, portable sealers  or single channel
analyzers  with reasonable accuracy.  The single channel analyzer appears
to  offer the highest degree of accuracy  and sensitivity.   The hand-held
survey instrument is the least accurate and sensitive.

The  hand-held survey  meter  was noted to  be sufficiently sensitive  to
estimate  specific activities  in  excess of 20  to 30 pCi/gm,   with high
assurance  (in the  order of  98%) that  the quantity  estimated will  be
greater than that found in the sample container.

The  contents of drums can  also be reliably estimated   using a hand-held
survey  meter at levels of  approximately 40 pCi/gm and   above.   Our data
does not permit the estimation of a numerical confidence interval,  but  it
should be at least as good as that of the sample bottles.   This statement
is  supported,  in  part,  by  the similarity  in  the  derivation of  the
theoretical  response to drums  and bottles.  It   is strengthened by  the
good agreement between theory and experiment shown in Figure 5.

It  does not appear reasonable to place much reliability on  the estimates
made   for tubing with hand held  equipment shown in Figure  12   since only
four experimental results were available for comparison.  The results are
presented for range finding purposes only.

Recommenda t i ons

It  is recommended that the initial screening of field material  contained
in   drums  and  filled  one-liter  polyethylene   bottles   with   specific
activities above approximately 25 pCi/gm be accomplished  using  the  Ludlum
Model  19 or the Ludlum  Model 97-3 hand-held survey  meter.  This  screen
can  be performed by trained field operators.  The portable sealer  in  the
single channel analyzer mode should be used to accurately determine  lower
levels  of activity when necessary.   The single channel  analyzer  method
should  only be  performed  by persons specially   trained  to perform  the
analysis.  Survey instruments should not be used to estimate the specific
activity  of  material  contained  in  production  tubing,  without  first
collecting and placing the scale in a one-liter bottle.

The estimation of the'level of Radium contained in waste drums  and  sample
bottles includes the following steps.

     1.  Determining the background.

     2.  Checking the instrument's response.

     3.  Making the measurement.
                                 813

-------
     4.  Estimating the specific  activity  of Radium present.

The  background level used  in making  the   estimate of specific  activity
should  be measured in a location well  removed  from sources of radiation.
Background  should be measured at waist  height.    Four readings should be
taken  with  the  instrument  parallel   with the  cardinal points  of the
compass.   The reference  background level   used in  making the  estimate
should be the average of the four readings  taken.

This average should be compared with other  background determinations.   If
it  is significantly different  from other  similar   measurements  (greater
than   plus  or  minus  25%)  then  the  cause   of   deviation  should   be
established.

Instrument  response should be checked using the 137 Cesium check  source
purchased with the instrument.  The check source should  be placed against
the  most sensitive part of the instrument   and  the  reading recorded.   If
this  measurement is  not  within plus or   minus 15# of   those  previously
recorded then the cause of the deviation should  be  determined.  It  may  be
necessary to replace the batteries and/or recalibrate the  instrument.

For  the case of  sample bottles, measurements   should be  taken with the
detector  as close to the bottom  of the bottle as possible.   Measurements
should  also be  made  with the   bottle  lying on it   side.   The detector
should be held at the longitudal  and vertical center  of  the  bottles.  The
bottle should be rotated through  360 degrees and a measurement  made every
90  degrees.  The  average of  the five  measurements  should  be used  in
estimating  the specific activity of the sample.   This  average should be
background corrected.

In the case of the drum, the drum should be  removed  from other  sources of
radiation  that  might  interfere  with  the measurement.   The hand-held
survey  meter should be placed with the detector directly  over  the center
of  the  drum  and  in  contact   with  the   top.   The reading  should be
background corrected.

Estimates  of specific activity are then made using  Figures  13  and 15 for
bottles and Figure 14 for drums.   The results should  be  reported as being
less  than  the  quantity  shown  on the  appropriate  chart   in units  of
pCi/gm.
                                 814

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IMPACT. TOTAL AMOUNT OF RADIUM PRESENT
 USING LUDLUM MODEL 19 OR MODEL 07-3
     (1X1 SODIUM IODIDE DETECTOR)
 TOTAL RADIUM PRESENT (uCI)
         INSTRUMENT READING (uR/hr)
                 Figure On*
      SAMPLE BOTTLE CORRELATIONS
RELD MEASUREMENTS NORMALIZED BY DENSITY
1000 ML WIDE MOUTHED POLYETHYLENE BOTTLE
 SPECIFIC ACTIVITY IN BOTTLE
         INSTRUMENT READING (lA/ftr)
     SAMPLE BOTTLE CORRELATIONS
 •mEORETICALLY DETERMINED BY DENSITY

 SPECIFIC ACTIVITY IN BOTTIE (nO/gm)
            400    000     000
         INSTRUMENT REAOtNQ
                               VOO
                figure Three
                  815

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   COMPARISON OF LOUISIANA (LA) AND
    NEW MEXICO (NM) SPIKED SAMPLES
 INSTRUMENT READING (uR/tv)
       W>     100    000    400    §00
     SPECIFIC ACTIVITY IN SAMPLES (pO/gm)
               • LA

              -- IA
                         — MI H*T m
                Flgur* Four
     COMPARStON OF CORRELATIONS
THEORETICAL AND EXPERIMENTAL RESULTS
FOR SAMPLE BOTTLES WEK3HNG 1300 QMS

SPECIFIC ACTIVITY (nCt/gm)
         INSTRUMENT READING^ uR/hr
                FlgwvFh*
   FELD MEASUREMENT CORRELATIONS
         ENVELOPE OF BEST FIT
        SURVEY M8TRUMENT DATA
 MEASUREMENTS (uR/hr)
        N      40
          SPECIFIC ACTIVITY
     FKL0MO*
                      	MVUCL 	MtLCt.
                 Figure «*
                  816

-------
140
1*6
 40
 M
           USE OF A 8CALER TO
    DETERMIME TIC QUANTITY OF RADIUM
  CORRECTED COUNT RATE (ttKMMndt/mkO
          o     m      MO     *
           SPECIFIC ACTIVITY (pCt/gm)
                                      MO
      ••OttMAMM*
     • m*i rrr mot
 USE OF A SINGLE CHANNEL ANALYZER TO
   DETERMIME THE QUANTITY OF RADIUM
 CORRECTED COUNT RATE (ttwuMnfe/nrin)
        wo      too      too      '
          8PEORC ACTIVITY (pCt/gm)
MO
   CORRELATION FOR DRUMMED MATERIAL
       EXPERIMENTALLY DETERMMED

  SPECIFIC ACTIVITY M DRUM (pCI/gra)	
 •0
  e        to        «e       «o       too
     REAONQ AT CENTER OF DRUM TOP (tf/Hr)
                          — tertrn j
                  Figure Nta
              817

-------
        THEORETICAL CORRELATIONS
          FOR DRUMMED MATERIAL
          NORMALIZED BY DENSITY

   SPECIFIC ACTIVITY IN DRUM (pO/gm)
1MO
         •O     MO      tOO     40(
          INSTRUMENT READING (uR/hr)
                  Ftojn Tfcn
   THEORETICAL CORRELATIONS FOR PPE
        2. 2 and 1/2 and 3 Inchea L D.
        Scale TNckneaa 0.0125 inchea  •

  SPECIFIC ACTIVITY OF SCALE (nO/flra)
             400    (00    iOO
          INSTRUMENT READtNO (uR/hr)
                  • t VI k. l&
                             IMA
     E»EWMEHTM1V OETEBMWED FOR
   CORRELATION OF INSTRUMENT READMG
     AND SCALE IN PPE (NO D STATED)

  SPECIFIC ACTIVITY OF SCALE (nO/gnO
          M8TRUMENT B6AWNQ (uR/lv)
                   aia

-------
      RECOMMENDED CORRELATIONS
          FOR SAMPLE BOTTLES
 SPECIFIC ACTIVITY IN BOTTLE (nd/gm)
      MO
         INSTRUMENT READING
                  •uou/oc
               FlauraTMrtMn
       RECOMMENDED CORRELATION
            DRUMMED MATERIAL
  SPECIFIC ACTIVITY IN DRUM {pCl/»n)
         •       v      •      to
          INSTRUMENT READING (ifl/hr)
       RECOMMENDED CORRELATIONS
           FOR SAMPLE BOTTLES
      97.6 % of faults will exceed actual
  SPECIFIC ACTIVITY IN BOTTLE (pCI/gm)	
lie
wo
M
M
40
10
 o
       f    W     •    M    M
          INSTRUMENT READING (uR/ttr)
                819

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A REGULATORY HISTORY OF COMMERCIAL OILFIELD
WASTE DISPOSAL IN THE STATE OF LOUISIANA
Carroll D.  Wascom
Assistant Director
Injection and Mining Division
Office of Conservation
Department of Natural Resources
Baton Rouge, Louisiana
 Introduction

 During the late 1970's and early  1980's  emotions  in the Louisiana oil patch
 were running high on both sides of  the arena.   Oil  and gas  interests  were
 experiencing a boom of sorts as the  number  of  drilling  permits  issued  by
 the Louisiana Department of Natural  Resources,  Office  of Conservation  rose
 from 3707 in 1977 to a high of 7631   in   1984.    Concerned  citizens  were
 awakening to the possibility that current oilfield  waste disposal practices
 were polluting the soil and grqundwater  and fouling the air.     Nationally,
 the Environmental Protection Agency  (EPA) had  proposed to regulate  certain
 categories of oilfield waste as "special wastes"  in  the  hazardous  waste
 regulations of December 8, 1978 (43   FR  58946).     Oil  and   gas  industry
 lobbying efforts resulted in the  Resource Conservation and Recovery  (RCRA)
 amendments of. 1980  which  exempted   most   oil  and  gas  wastes  from  the
 hazardous waste requirements of Subtitle C  until  the   outcome  of  further
 study by EPA.

 Back in Louisiana, the Vermilion  Association  for  the  Protection  of  the
 Environment (VAPE) was moving forward under  the  leadership   of  Mrs.  Gay
 Hanks and Mr. Lloyd Campisi to stop  the  construction  and  operation  of  a
 growing number of commercially operated  and non-regulated oilfield disposal
 pits in Vermilion Parish.  This close-knit  rural  community in south central
 Louisiana was concerned about the types  of   waste  being  dumped  at  these
 sites and the truck traffic at all hours of the night.  Therefore,  at  the
 request of his constituents, Representative  Sammy   Theriot  of  Lafayette,
 Louisiana, drafted and  sponsored  House Bill  No.  481  during  the  1980
 Louisiana legislative session.

 Passed as Act No. 804 in August of  1980  the new law amended  Section  4  of
 Title 30 of the Louisiana Revised Statutes  of  1950.  Title 30, Section 4(1)
 then required the Commissioner of the Office of Conservation  to  promulgate
 rules, regulations,  and  orders  as necessary  "to  control  the  offsite
 disposal at commercial facilities of drilling  mud,   salt  water  and  other
 related nonhazardous wastes generated by the drilling and production of oil
 and gas wells".   The  rules  were   to   provide  for  a  new   and  complete
 regulatory program   for  the  permitting,   siting,   design,  operation  and
                                   821

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closure of commercial offsite disposal  facilities.

Initial Rule Promulgation

In July 1980, one month  prior  to  passage   of  Act  804,  the  Office  of
Conservation published a revision of  existing  oil  and  gas  regulations,
Statewide Order No.  29-B:    the   first   attempt  to  regulate  commercial
oilfield waste disposal operations  in Louisiana.   Section XV, Paragraph  13
of 29-B defined a "commercial facility" as "a waste treatment,  storage  or
disposal facility which receives, treats,  reclaims, stores or  disposes  of
waste drilling muds or salt water for a fee  or other consideration".    The
new rule identified oilfield waste  as oil  base and  water base drilling muds
and cuttings and salt water (produced brine)  and   provided  guidelines  for
construction and operation of earthen pits.   Most notable  aspects  of  the
rule are as follows (1):

     1.   Pits were not to be located in a flood  zone according to  federal
          guidelines and flood insurance maps.

     2.   Documentation was required  to   show  that  an  impermeable   clay
          barrier existed below the pit.

     3.   At least one monitor well had to be  installed  down gradient.

     4.   Disposal operations could  be  conducted   during  daylight  hours
          only.

     5.   A manifest system was implemented  to document  waste shipments.

     6.   Facilities  were  required  to   submit   funding  to  provide   for
          adequate closure.

     7.   Financial responsibility  (bonding/insurance) was to  be   provided
          for any  liability for damages which  might be caused by the escape
          or discharge of any waste from the  disposal facility.

Existing  facilities were granted interim permits   and required to comply
with, the new rule within 90 days of passage.    A  field  and  file .search
resulted  in the discovery of thirty-one existing  sites.    Sixteen   operated
closed  systems with  above-ground   storage   tanks  and   saltwater   disposal
wells.   Fifteen   sites  utilized   earthen   pits   for storage/disposal  of
drilling muds, cuttings and salt water.  Interim  permits were converted  to
final   permits  when  existing  facilities   cpmplied  with  the applicable
requirements of Paragraph 13.    Only   eighteen  facilities  ever   received
final  approval to  continue operating.   Of  these,  thirteen  are   still  in
existence.  Thirteen  facilities  lost  interim  permits  and  discontinued
operations.  Although a few sites were  cleaned up and pits closed,   several
others  have never  been properly closed.  At  least two sites  in   Vermilion
Parish  eventually  became EPA superfund  sites.
                                  822

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1983  Amendments

The 1980 commercial facility regulations were not perfect,  but  they  formed
a firm foundation upon which to build.  Except  for a  1982  amendment of 29-B
dealing with injection (saltwater disposal) wells in  conjunction   with  EPA
approval of the Louisiana Underground Injection Control  (UIC) program,   the
commercial facility regulations were  not  changed  until   1983.     Citizen
groups in various Louisiana parishes were demanding   that   strict   location
and design criteria be added to the requirements  for  commercial   oilfield
waste sites.  Review of monitor well data indicated that saltwater  storage
pits were  leaking  into  shallow  water-bearing  strata;   such  pits   were
condemned.  Drilling fluid  pits  were  filling  up  and  more  were   being
constructed.   Housekeeping  practices  at  existing  facilities   were   not
protective of the environment.  A new means of  treating waste  was  needed,
since pits appeared to be a less desirable  disposal  option.    Therefore,
Paragraph 13 was amended extensively in  1983   to  take  these  facts   into
consideration.  The following is a summary of the major aspects of  the  1983
amendments (2) :

      1.   Facilities utilizing pits for storage of  oilfield  waste  solids
          were required to submit and have approved a plan of  disposal  of
          pit solids prior to July 1, 1984.  In effect,  these  sites  were
          told that disposal (storage) of waste in pits was a practice  that
          was  no  longer  acceptable.     New   treatment   and    disposal
          technologies were encouraged.  It is  interesting  to  note   that
          this requirement was located in a new section outlining   criteria
          for  operation  of  land  treatment   (landfarm)  systems.     Such
          criteria included the following:

          (1)  Soil type and permeability requirements for treatment cells;

          (2)  pH was to be maintained at 6.5;

          (3)  If necessary, underdrain systems were  to  be  installed  in
               cells to maintain the water table at least 36  inches  below
               the zone of waste incorporation  to  maintain  aerobic   soil
               conditions in the treatment zone;

          (4)  The electrical conductivity (EC) of the treated waste  could
               not exceed 10 mmhos/cm;

          (5)  The sodium adsorption ratio (SAR) of the treated waste could
               not exceed 10;

          (6)  Organics (oil and grease) had to be kept  to  a  minimum  in
               order to maintain plant growth (no limit provided);

          (7)  An unsaturated zone monitoring system was required;  and

          (8)  An independent consultant was required to perform  necessary
          monitoring.
                                  823

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          Primarily,  these criteria were derived  from standards  applicable
          to  agricultural settings.  The idea was  to   return  the  site  to
          some  form of beneficial land use at the  end  of   the  operational
          life  of the facility.

     2.    New commercial facilities could not be  located in certain  areas,
          as  indicated below:

          (1)  Within 500 feet  of  a  residential,   commercial  or  public
               building unless a waiver was granted;

          (2)  Where subsurface geology was not suitable   for   disposal  of
               waste in a saltwater disposal well;

          (3)  Pits could not be located in a flood zone unless  levees were
               built at least one foot above the 100  year  flood  level; and

          (4)  Where other conditions existed which in  the  determination of
               the Commissioner of Conservation  would  pose   a   threat  of
               substantial, adverse effects on the environment.

     3.    Certain design  criteria  were  added  to   prevent   environmental
          impact from facility operations.

     4.    Each load of waste received by a commercial facility  had  to  be
          tested for pH, conductivity, and chloride   (Cl)   content  and  an
          eight ounce sample maintained for 30 days.  Except  for  pH,  this
          attempt to screen waste receipts  fell  much  too  short  of  the
          intended goal.

These  amendments  greatly  impacted  the  operations  of   many   existing
commercial facilities.  The handwriting was on the wall:  pits were soon to
be a thing of the past.  Facilities were now required to move   forward  and
devise alternate treatment and disposal methods.  New facilities  could only
be located in areas suitable for waste treatment and  disposal.    Existing
facilities had to be retrofitted  to  comply  with  regulations   which  had
become more protective of the environment and in concert with   the  desires
of Louisiana citizens.

1984 Amendment

The 1983 amendment of the rule was a positive  step   in  the   direction  of
improved regulatory control of offsite oilfield waste  disposal   practices.
However, as with all regulations, there still remained gaps  that  needed  to
be addressed.  Some facilities were receiving questionable  wastes.    Land
treatment facility operating requirements were  vague.     Pits  were  still
operated at many sites, while others were closed.  Financial responsibility
(insurance) and closure funding requirements were of  concern.   The resource
conservation and recovery (reuse) of treated  nonhazardous  oilfield  waste
                                 824

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was a  new idea  yet  to be proven.  In response to these issues, Paragraph  13
was amended  again in 1984.   The highlights of this amendment are as  follows
(3):

     1.    As required by Act of 804 of 1980, but  never  addressed,  "other
          related  nonhazardous  wastes  generated  by  the  drilling   and
          production of oil and gas wells" were identified.    Nonhazardous
          oilfield  waste was defined as "waste generated  by  the  drilling
          and production of oil and gas wells and which is not regulated by
          the provisions of the Louisiana Hazardous Waste Management  Plan"
          as  administered   by  a  sister   agency,   the   Department   of
          Environmental Quality (DEQ).  Such wastes included, but were  not
          limited to the following:

          (1)   Oil base or water base drilling mud and cuttings.
          (2)   Salt water  (produced brine).
          (3)   Drilling, workover and completion fluids.
          (4)   Produced oily sands and solids.
          (5)   Production  pit sludges.
          (6)   Production  storage tank sludges.
          (7)   Nonhazardous natural gas plant processing  waste  which  is
                commingled  with produced formation water.
          (8)   Produced formation fresh water.
          (9)   Washout  water  generated  from  the  cleaning  of  vessels
                (barges, tanks, etc.) that transport nonhazardous  oilfield
                waste and are not contaminated by hazardous waste.
          (10)  Rainwater from ring  levees  and  pits  at  production  and
                drilling facilities.
          (11)  Pipeline  test  water  which  does   not   meet   discharge
                limitations established by the appropriate state agency.
          (12)  Pipeline pig water, i.e., waste fluids generated  from  the
                cleaning of a pipeline.
          (13)  Washout pit water from oilfield related carriers  that  are
                not permitted to haul hazardous waste.
          (14)  Waste from  approved salvage oil operators who only  receive
                waste oil (BS&W) from oil and gas leases.
          (15)  Material used in crude oil spill clean-up operations.
          (16)  Wastes from approved commercial Class II storage, treatment
                and/or disposal facilities.

      2.   Although provided for in the 1983 amendment,  land  treatment  of
          oilfield waste was not defined until 1984.   Land  treatment  was
          officially considered "a dynamic process involving the controlled
          application of nonhazardous  oilfield  waste  onto  or  into  the
          aerobic  surface   soil  horizon   by   a   commercial   facility,
          accompanied by continued monitoring and management, to alter  the
          physical, chemical, and biological state of  the  waste.     Site,
          soil, climate, and biological activity interact as  a  system  to
          degrade and immobilize waste constituents thereby  rendering  the
          area suitable for the support of vegetative growth and  providing
          for beneficial future land use".
                                   825

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    3.   Land  treatment  operational requirements were expanded to   require
         a   conservative  limit of five percent in the amount of  oil  and
         grease  in  a  cell.   This limit was set because  research  (4)  had
         shown that oil  and  grease  values  of. ten  percent  or  more   in
         oilfield waste  needed  special  treatment  if  waste  was  to   be
         degraded within a reasonable amount of time.

    4.   The resource conservation and recovery  of  treated  nonhazardous
         oilfield waste  was  permitted on a case-by-case basis  only  after
         sufficient testing  was performed.  However,  no testing parameters
         or  criteria  were  promulgated.  The primary reuse proposal at  the
         time  was   for  daily  cover  at  municipal  or  industrial  waste
         landfills.  One pilot project was  undertaken  by  Newpark  Waste
         Treatment  Systems,   Inc.   (now  Newpark  Environmental  Services,
         Inc.) as  treated  solids were transported to  a BFI  landfill  east
         of  New  Orleans, Louisiana.

     5.   Insurance  policies  submitted  in  compliance   with   financial
         responsibility  criteria  were  required  to   provide  sudden  and
         accidental pollution coverage (spills) as well  as  environmental
         impairment  (absolute/seepage)  liability  coverage  for  obvious
         reasons.

     6.   Companies  could still use earthen pits under—the 1984  amendment.
         However,  soil permeability testing was to be performed with water
         as  well as  potentially  stored  fluids  as   the  permeants.     A
         combination  of  synthetic and natural materials could be   utilized
         to  construct the  required liner.   Levees had to be tied  into  the
         impermeable  barrier (keyed) to prevent lateral migration.

     7.   The last   reference  to  "good  housekeeping"  requirements  were
         replaced  by  specific operational  criteria.

1986 Amendments
Subsequent to the 1984 changes in the rules,  the oil and gas industry began
to feel the national push toward improved  regulation  of  exploration  and
production  waste  management  practices.    The  Alaska  Center  for   the
Environment sued EPA in 1985 to force the federal environmental  regulatory
agency to implement the oilfield waste study  mandated  by  the  1980  RCRA
amendments. In Louisiana, environmentalists continued efforts  to  transfer
the regulation of oilfield waste from the Office of  Conservation  to  DEQ,
the agency responsible for solid and hazardous waste  regulatory  programs.
It became necessary to close gaps in the commercial facility regulations in
the areas of reuseable materials,  onsite/offsite  waste  management  docu-
mentation, location criteria, application completeness, insurance,  closure
funding  and  others.    The  major  changes  to  the  commercial  facility
regulations in 1986 are  discussed below (5):
                                 826

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L.   Definitions  of  key words were added or amended:

    (1)   "Offsite"  was added^ in  order  to  identify  the  difference
          between onsite treatment  and  disposal  of  oilfield  waste
          (where  generated) and offsite disposal. Waste hauled offsite
          for  disposal  was  required  to  be  taken  to  a  permitted
          commercial facility.

     (2)   Nonhazardous oilfield waste was given the acronym "NOW"  and
          certain waste stream definitions were clarified.

     (3)   Reusable  material  was  defined  as  "material  that  would
          otherwise  be classified as nonhazardous oilfield waste,  but
          which is capable of resource conservation and  recovery  and
          has  been processed in whole or in part for reuse.    To  meet
          this  definition,  the  material  must  have  been   treated
          physically,   chemically,  or   biologically   or   otherwise
          processed  so that  the  material  is  significantly  changed
          (i.e.,   the   new  material  is  physically,  chemically,   or
          biologically distinct  from  the  original  material)",  and
          meets the  applicable criteria of the rule. However,  specific
          testing criteria and guidelines were not added until  1986.

2.   Over the  years,  several  instances  had  been  documented  where
     generators  had  contracted  for  offsite  disposal  of  NOW   at
     commercial facilities and vacuum truck  operators  had   illegally
     disposed  of the waste at other locations.   As a result,  the   1986
     amendment contained at least three requirements to prevent future
     occurrence of these acts:

     (1)   Operators  were required to report any unauthorized  disposal
          of NOW when  discovered.

     (2)   A specific statement that the "unpermitted  or  unauthorized
          storage,  treatment,   disposal  or  discharge  of    NOW   is
          prohibited"  was added.

     (3)   Oil  and gas  operators were required to document  the  amount
          and  types  of waste (NOW) generated during  the  drilling   or
          workover of  each well in the state  and  certify  that   such
          waste was  .disposed of in accordance  with  applicable  rules
          and  regulations of the Office of Conservation.

3.   Because of concern over loss of environmentally fragile wetlands,
     new commercial  facilities were no longer  permitted  to  be   con-
     structed  in U.  S. Corps, of Engineer designated wetlands.

4.   Although  not specifically defined,  a  new  application  was  now
     required   when   existing  facilities  intended  to  make    "major
     modifications".  Such modification was intended  to  mean  adding
     new  waste  streams,  changing  or  adding  new   NOW   treatment
                            827

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technologies, or expanding beyond  previously  permitted  property
boundaries.  The 1986 amendment  gave  the  public an opportunity to
review and comment on proposed major  facility changes  at  public
hearings conducted in the local  affected  community.

Until 1986, all commercial facilities were  required   to  carry  a
$1,000,000 environmental impairment (seepage/absolute)  insurance
policy.  Because of the inability  to  obtain  affordable  environ-
mental impairment insurance coverage  for  smaller  companies  with
reduced  liability,  insurance   requirements  were   changed   as
follows:

(1)  Facilities utilizing earthen  pits  for  temporary   storage  of
     NOW  were  required   to    continue    obtaining    $1,000,000
     environmental impairment insurance coverage.

(2)  Facilities which accepted   NOW   solids   and   conducted  land
     treatment,  incineration  and  physical/chemical    treatment
     methods were required  to   provide   a   $500,000   sudden   and
     accidental pollution liability policy  as  it   was   determined
     that the level of monitoring  at these   facilities   was  such
     that environment impairment coverage was  not  warranted.

(3)  Closed NOW fluid (salt water, etc.)  disposal  systems  were
     required  to  provide  a  $250,000   sudden  and    accidental
     pollution liability policy  for the same  reasons.

(A)  Transfer stations were required to provide a  $100,000  sudden
     and accidental pollution liability policy.

Although provisions for adequate closure  (bonding) of   commercial
facilities did not see any appreciable change  in 1986,  the  Office
of Conservation had begun to provide  operators  with   guidelines
for  the preparation of closure plans and  cost  estimates.    These
plans and  estimates  were  to   be  prepared   by   a  third  party
(consultant, etc.) and approximate the  amount  of  funding  that
would be needed to adequately return a permitted site   (as  close
as possible) to  its  original   condition.     As   expected,   some
facilities appeared to  "low-ball"  their   estimate  while  other
estimates approached  more  reasonable  amounts.    In   order  to
address  this  issue  satisfactorily,  an   Injection  and   Mining
Division engineer began reviewing  recent  facility  closure  plans
and  cost estimates.  This work   provided  much higher   estimates
than previously calculated.  Such  scrutiny   resulted   from  steps
taken  to  close  two  previously  permitted   but  now   abandoned
facilities.

In both  cases,  it  was  determined  that   the  closure  funding
provided would not approach the  real figures needed to  adequately
close the sites.
                        828

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7.    A 1986 amendment to only permit the use of  temporary  storage pits
     for NOW solids marked the end of an era.  As  of  early  1990,  the
     last operational earthen pit utilized by  a   commercial   facility
     was closed.   At present, no  existing  commercial   disposal   site
     operates an earthen pit,  although  the  rule  provides   specific
     construction  (liners,  etc.)  and   operation   guidelines    for
     temporary storage (receiving) pits.  Such pits may  not   exceed   a
     design capacity of 50,000 barrels and will only  be  approved  for
     temporary storage of NOW in connection with a permitted  treatment
     system  (i.e.  land  treatment,   chemical    fixation,    physical
     dewatering,  incineration, etc.).  Commercial  pits were no longer
     approved for the permanent disposal of NOW.

8.   Detailed application requirements for land treatment  systems were
     added for the first time.

9.   Detailed application requirements for transfer stations were also
     added.  These guidelines stemmed from past  attempts  by  out-of-
     state companies to set up barges for receipt and transport of NOW
     to other states (for disposal) without having met requirements in
     Louisiana.  Transfer stations for temporary storage (30 days)  of
     NOW by companies with in-state treatment and disposal  facilities
     could be permitted administratively  without  a  public   hearing.
     Transfer  stations  to  be  operated  by  out-of-state    disposal
     facilities must be permitted like  any  other  in-state   disposal
     company, including a public hearing in the seat  of  government for
     the affected parish.

 10".  Monitor well testing parameters for pits were expanded to include
     oil and grease, As, Ba, Cd, Cr, Pb, Hg, Se, Ag and  Zn in  order to
     be  consistent with new land treatment criteria.

 11.  Monitoring requirements for land  treatment   facilities   were  in
     need  of  change  in  1986.    Three  years  of  experience   led
     Conservation to require more proof of  environmental  protection.
     As  a  result, the following criteria were added:

      (1)   Specific limits  for  the  concentration  of   the  following
           metals  in the treatment zone: As, Ba, Cd, Cr,  Pb,   Hg,  Se,
           Ag, and . Zn.

      (2)   The concentration of measured constituents  in  any  monitored
           shallow groundwater aquifer could not  significantly exceed
           background water quality data.  While this  requirement  was
           not definitive, it  provided  the  needed   flexibility  when
           determining whether or not remedial action  is  warranted.

      (3)   Baseline land treatment  cell  and  monitor  well  data  was
           required prior to the opening of a new facility  or cell.

      (4)   Detailed monitoring programs were required  to  determine  the
                             829

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               extent  of waste degradation and accumulation  of  metals  in
               the  waste treatment zone, the unsaturated  zone  beneath  the
               cell,  and  ground water.

          (5)   Specific soil (cell) sampling protocols were outlined.

          (6)   Closure and post-closure maintenance and monitoring programs
               were to be submitted for review  and  approval.       Closure
               criteria for soils in the treatment zone and surface  runoff
               water  were set.

     12.   Detailed  guidelines and testing criteria for the  reuse  of treated
          NOW  were  provided  to  encourage  alternatives    to    disposal;
          however,   very  little  material  has  been  approved   for   reuse
          projects  since the rule was promulgated.  Most  reuse material was
          either stockpiled or utilized to construct  levees  of   new   land
          treatment cells in expansion  programs  at  existing  facilities.
          Reuse criteria was more restrictive than land treatment  criteria.
          Specific  leachate testing was an additional requirement.  Treated
          NOW may not be offered for reuse until first shown  to comply with
          the land  treatment criteria of 29-B.

Current (1990) Issues

Since 1986,  no amendments to the commercial facility regulations have  been
promulgated.  However, several issues presently  under  consideration  were
the subject  of a public hearing conducted on June 6, 1990.  A  rule  change
ii expected  to be published on August 20, 1990.    Three  of  the   proposed
changes are  presented below:

     1.   A change  in the testing protocol for barium (Ba)  analysis  and  a
          corresponding increase in the land treatment and  reuse   criteria
          for Ba are being considered.  NOW studies by B.   D.  Freeman  and
          Dr. Lloyd E. Deuel, Jr. (4) served as the basis   for  setting  Ba
          limits in the 1986  regulations.    Studies  by   K.  W.   Brown  &
          Associates in 1987 (6) discussed the geochemistry  and   potential
          environmental impacts of Ba.  In  1989,  Deuel  and  Freeman  (7)
          provided  technical justification and recommended  modifications of
          the Ba criteria in 29-B in a paper presented by Dr. Deuel at  the
          SPE/IADC Drilling Conference in  New  Orleans,  Louisiana.    The
          Environmental Protection Agency (8) is proposing  to exempt barium
          sulfate  (a major component of drilling fluids)  from the  reporting
          requirements  for  toxic  chemicals  under  section  313 of  the
          Emergency Planning and Community Right-to-Know  Act  of 1986   based
          on EPA's  review of available data on the health and environmental
          effects  of barium sulfate.  These and other documents  have  been
          placed into the hearing record as documentation of  why Ba limits
          should be increased.
                                  830

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         Specific land treatment management  practices  are also  addressed.
         Waste loading will be limited to   15,000   barrels/acre  during  a
         three month application phase.  Waste must be   actively  treated
         and brought  into  compliance  with applicable   criteria  within
         twelve months of the end of the  application  phase.     Treatment
         zone monitoring guidelines will require sampling in specific soil
         horizons.  These and other changes  attempt to prevent overloading
         of cells while allowing companies  to  maintain   individual   waste
         management techniques.

         New regulations will require generators of NOW who   are   not  oil
         and  gas  operators  of  record  (i.e.,   service,   trucking,   and
         pipeline companies, etc.) to document  how and   where  waste   is
         generated before being approved for disposal  at  permitted  sites.
         History has shown that much of  this  waste   does   not  meet   the
         definition of nonhazardous oilfield waste  and cannot  be   accepted
         for disposal by.  The Office of Conservation  presently   requires
         such companies to provide information in  writing before   approval
         is granted.  An inspection will be  performed  if  deemed necessary.
         Table  1  (Exempt/Nonexempt Wastes)  of the  December 1987 EPA  Report
         to Congress is presently reviewed  in addition to   existing 29-B
         requirements to determine whether  or not  to approve   requests   to
         dispose of questionable wastes.
Conclusion

Primarily, the development of  the   commercial   facility   regulations   since
1980 has  been spurred by  the need  to plug  regulatory  gaps when  discovered,
by efforts of Louisiana citizens concerned  about  the  environment   in   which
they live, and by  the oil and  gas  industry's concern  about  future  liability
and the uncertainty of the outcome  of  the  EPA  oilfield waste  study.    The
Louisiana Office of Conservation   can  be   proud   of  its   achievements   in
transforming a regulatory concept  in 1980  into a   full-scale  environmental
program dedicated  to the  protection of human health   and  the   environment.
Many have suggested that  Statewide  Order No. 29-B, Section  XV,  Paragraph  13
will serve as a model regulation for other  states  to  follow if  future EPA
guidelines require state  oilfield  environmental programs  to  be   improved.
Readers are invited to contact  the  author  to receive  a copy of  the current
or past regulations discussed  herein or to  discuss   specific   requirements
for commercial disposers.
                                  831

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References

1.   State of Louisiana, Office  of   Conservation,   Amendment  to  Statewide
     Order No. 29-B, Section XV, Paragraph  13,  July 20, 1980.

2.   State of Louisiana, Office  of   Conservation,   Amendment  to  Statewide
     Order No. 29-B, Section XV, Paragraph  13,  May 20,  1983.

3.   State of Louisiana, Office  of   Conservation,   Amendment  to  Statewide
     Order No. 29-B, Section XV, Paragraph  13,  May 20,  1984.

4.   B. D. Freeman, L. E. Deuel, Jr., Guidelines  for Closing Drilling Waste
     Fluid Pits in Wetland and Upland Areas,  Parts  I,   II,   and  III,   2nd
     Industrial Pollution Control Proceedings,  7th  Annual   Energy  Sources
     Technology Conference and Exhibition,  New  Orleans,  1984.

5.   State of Louisiana, Office  of   Conservation,   Amendment  to  Statewide
     Order No. 29-B, Section XV, Paragraph  13,  January  20,  1986.

6.   W. Crawley, J. F. Artiola,  J. A. Rehage,   Barium  Containing  Oilfield
     Drilling Wastes:  Effects On Land Disposal, Proceedings of  a  National
     Conference on Drilling Muds, University  of Oklahoma, Environmental  and
     Ground Water Institute, Norman, 1987-

7.   L. E. Deuel, Jr., B. D.  Freeman,  Amendment   to  Louisiana   Statewide
     Order 29-B  Suggested  Modifications   for  Barium   Criteria   (SPE/IADC
     18673), SPE/IADC Drilling Conference,  New  Orleans,  1989.

8.   Federal Register, Barium Sulfate; Toxic  Chemical   Release  Reporting;
     Community Right-to-Know, Proposed Rule,  February 12,   1990,   Vol.  55,
     No.  29, pp 4879-4881.
                                   832

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REGULATION OF NATURALLY-OCCURRING RADIOACTIVE MATERIAL  IN LOUISIANA
L.  Hall Bohlinger
Louisiana  Department of Environmental Quality
Office of  Air  Quality and Radiation Protection
Baton Rouge, Louisiana
Introduction

For  quite  some  time,  work  has  been underway  nationwide  to provide
guidance in dealing  with low-level  radiation from naturally-occurring
radioactive material (NORM) in  the  environment.   However, progress  has
been slow for  a  variety of reasons.   One key reason  for this lack  of
regulatory control for NORM in  the  past  is the limited  jurisdiction  by
the federal government,  and,  by default,  the responsibility was passed
on to the states  which  typically did not have adequate, programs or  staff
to deal with the additional problem.  Recently though, there appears  to
be a  resurgence  of  interest  by  the  EPA,  the Conference of  Radiation
Control  Program  Directors,  and several affected  -state  agencies.    In
Louisiana we first  started evaluating the NORM problem in 1972 at natural
gas processing plants,  oil refineries, phosphate,  bauxite and lignite
facilities. With the help  of  the EPA Las Vegas facility  and the Eastern
Environmental  Radiation  Laboratory  we had a  fairly  good handle on  the
NORM content at these facilities.

Of particular  interest  to Louisiana at present, however,  is the problem
related  to the  NORM  content  of produced  waters  and  the   resultant
contamination  of equipment and  facilities in the oil and gas production
and support industries.   The accompanying waste brine associated with  oil
and gas production  which  typically contain from 19 to 2800 pCi/1 of  total
radium.  This  occurrence has been documented  for  well  over 30 years.   Of
the  several theories on the  origin of radium  in the  brine,  the most
widely accepted is that the occurrence results from the  leaching-out  of
the surrounding uranium-bearing rock  from  which  the oil  and associated
formation waters are drawn.   It has been  shown  that  the radium can  be
easily  extracted leaving  the  mineral  intact.    These  waters flowing
through  drilling  tubulars,  pipes,  and other related  components,  over
time, result  in  the  deposition of inorganic  chemical  compounds.   This
scale,  as  it   is   termed,   restricts  production,  causes   equipment
inefficiency,   impedes  heat transfer,  and is very  time-consuming  and
expensive  to  remove.    The   scale  problem  is  estimated to  cost  the
petroleum companies over a billion dollars each year.  Recently another
problem with the scale  formation has surfaced—the radioactivity,  which
may exist in concentrations up to 100,000 pCi/gm, possibly more.

Our  experience has  shown that not all scale is  radioactive,   the  scale
thickness and radium concentration  vary  from location to location,  and
                                 833

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there's no accurate way to predict  radiation levels.  We know there are
very large volumes  of scale  produced; in  one  large oil-producing state
alone,  the annual production is estimated by  a  recent study to be over
35,000 cu. meters.  A related problem is the contamination of soil which
occurs  at pipe  yards  and  pipe  cleaning  facilities.   The  cleaning
operation involves a reaming, rattling,  or  other  process which causes the
dislodged  scale  to fall  from the  pipe  ends  to  the ground.   It's  not
uncommon at facilities which have  operated for several years to observe
concentrations of radium  in  soil of over 8000  pCi/gm.

Examples  of how  this  problem got our attention  included  oil field pipe
setting  off  radiation alarms  in  scrap  yards   and metal  reclamation
facilities.    These  monitors   were  originally  installed  to  detect
radioactivity in scrap metal which  began to  show  up as  a result of a Co-
60 contamination incident which occurred in Mexico a  few years ago; but,
as  it  turns  out,   they're   also   quite   effective   in detecting  pipe
contaminated  with radium scale.  When this  happens,  it results  in  the
entire  load  being diverted to  a  yard  that  doesn't have a  monitor
installed.   Quite often we  are  notified by the  original  yard,  but  its
usually  impossible to locate the   material  once they  have  been  turned
away.  Another incident which occurred two years  ago  involved a lost  Cs-
137  oil-well  logging source  in the Southwest  portion of  the state.  We
requested the assistance of the Department  of Energy  in  locating the lost
source.  They  responded with a  helicopter  equipped  with  very  sensitive
radiation detection instruments and began scanning a  sixty-mile wide area
along  1-10 between the cities of Lafayette and Lake Charles.  They never
found  the cesium source, but had no trouble at all locating several oil-
field  brine pits  in the area.  In  addition reports  of contaminated pipe
used in  construction  of  bleachers,  school  and   public park playground
equipment, and as  work material in welding classes  at Vo-Tec schools in
the  State have all  added to a  growing  awareness in  Louisiana  of more
detrimental  consequences of the many  years  of  oil production  in  the
State.

For  four  consecutive days, beginning Sunday,  December 11, 1988, the Baton
Rouge,  Louisiana,  Morning  Advocate  carried  front-page  articles  with
titles such as "Brine Flowing in Louisiana  waters is Radioactive," "Pipes
Handled by Oil Workers  Discovered to be Radioactive,"  "Oil Field Brine
Radioactivity New Concern,"  and "Radioactive  Playground  Equipment Torn
Down."  Needless to say, this issue has received  unprecedented attention
over the past year and a  half,  resulting in positive action being taken
by the regulatory agency  of  the State.


 Health and Safety Concerns

 First, and most  importantly, is  the element  involved—radium.  When this
 presentation was  given  to  our  Joint Legislative Committee on Natural
 Resources,  a  great  deal   of  elaboration  on  radium  toxicity  and
 characteristics  was provided which I don't really feel is necessary for
 this audience.
                                  834

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We are concerned that workers employed in the area of cutting and reaming
oil-field  pipe and equipment  may be exposed to potential  health risks
associated with inhalation and/or ingestion of.dust particles containing
elevated levels of alpha-emitting radionuclides.

The potential exists for  Ra-226 to enter  both aquatic and terrestrial
food chains  leading to human  consumption,  due to previous  lax disposal
requirements for  production waters.

The environmental consequences and health risks associated with disposal
of NORM-contaminated oil-field wastes  (e.g.,  incineration, land farming,
and down-hole injection)  are largely unknown.

Because of its long half-life,  sites  contaminated with elevated  levels
of  Ra-226 will  be  of concern for centuries.   Many of these  sites,
especially the pipe  yards,  are within city  limits and could  easily  be
used for residential or commercial purposes  in the  future.  If  buildings
were to be constructed over radium-contaminated soil, the resulting radon
emanation could pose a health threat.

Contaminated piping has been  found in  downstream usage in  both private
and public sectors—bleachers,  gym sets,  fences,  welding materials, etc.

Literally billions of gallons  of produced water are released annually  to
the  environment   in  coastal  Louisiana  with  very  little   information
available on  the  fate  of  the radioactive  components.   Based  on  sample
analysis and calculation,  we estimate  over 10 Ci  of Ra-226 were released
into SW Louisiana marshes  from one oil  field alone over  a  several year
period!

There are some very  difficult  questions concerning  potential liabilities
for transfer of contaminated land for unrestricted  use, worker  exposure,
and necessary remedial measures.

It is not uncommon to encounter pieces of oil or gas industry  equipment
or scale deposits that produce readings of 5-10 mrem/hr.  Thus exposure
to  such  materials for only  a couple of  hours could  exceed the  level
established as a criterion for regulatory concern by the  NRC.

Regulatory Status

Prior to September 20,  1989, there were no  specific regulations in place
at the state or federal level to deal with identification,  handling,  or
disposal of NORM-contaminated materials.

The  NRC,  under  current   Atomic  Energy  Act  authority,   is  limited  to
regulation  of source,  special  nuclear,  and byproduct materials.  The
Conference of Radiation Control Program Directors  on numerous  occasions
has urged that the NRC seek legislative  authority to regulate NORM.  The
latest effort has resulted in  a referral  to  the Committee  on Interagency
Radiation Research and Policy  Coordination  (CIRRPC) for  evaluation and
a request for response back to NRC in 18 months—early 1990.   The scope
                                 835

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however,  is  limited to  discrete  sources  of Naturally-Occurring and
Accelerator-produced Radioactive  Material (NARM)  which usually  includes
only those products to which natural or accelerator-produced isotopes are
purposely added for  their radioactive properties.

The EPA, in 1978, proposed that any  industrial by-product that  contains
greater than  5 pCi/gm Ra-226  be classified  as hazardous waste,  but the
rule was never promulgated.  Then, in 1988, they  stated that wastes such
as produced water,   sands, drilling  muds, and cuttings were  not  to be
classified  as hazardous waste.   More recently a level of  50 pCi/1 of
radioactivity in liquids has been proposed as a criterion for hazardous
waste.   In EPA's proposed LLW rule,  discrete NARM  and  diffuse  NORM is
included when the concentrations  of  radioactivity exceed 2000 pCi/gm.

The CRCPD Part N Committee on regulations has developed a set of proposed
Suggested  State Regulations for NORM,  now in its  7th draft.  If adopted
following  the state  and federal review process, it will be available for
states  to  use at their  option.   If  adopted by all  states,  this  would
ensure  uniform  regulations,  however  not  all states  feel they have  the
necessary  enabling legislation to regulate NORM, and  it is unlikely that
all provisions would be acceptable by all agencies concerned.  This rule
sets  a  regulatory limit  of 5 pCi/gm.

OSHA,  in  a recent  communication  to the LA DEQ, has  indicated that they
are considering mailing a health hazard alert to their Regional and Area
offices concerning  oil-field wastes.

The LA  DEQ in October 1988, released  an  Interim Policy on the handling,
storing and disposing of scale or soil contaminated  by  the  cleaning of
pipe.   It  included  a   background discussion of  the  problem,  worker
protection guidelines,  NORM storage options,  and  it  prohibited transfer
of  contaminated items  to other  individuals.  This  guidance preceded
release of an Emergency Rule  on  February 20,  1989,  which amended the
Louisiana Radiation Regulations by adding a chapter entitled,  "Regulation
and Licensing of  Naturally-Occurring Radioactive Materials  (NORM).  It-
was distributed to over  1200 potential licensees in the State.  Following
several months  of  review by  technical committees, two rounds  of public
hearing and  comments,  and a  favorable   vote by  the House and Senate
Committees  on Natural  Resources,  the permanent  Rule was adopted, and
Louisiana  became the first state  to promulgate NORM regulations.

Scope of the  Regulation

The exemption criterion initially used in the case of the Emergency Rule ,
was radium concentrations less than  30 pCi/gm. This number was  derived
from  the  Appendix  A,   Table  II,  Column   2 of  the  Suggested  State
Regulations  for  unrestricted  release  of  insoluble  Ra-226  to water,
assuming soil or scale and water have  approximately the same density,  and
changing ml to gm.   This was done for lack of a better number and is  not
entirely  appropriate; nor  is it easily determined in the field.  It was
necessary  to obtain a  sample of material,   and  run  a  time-consuming,
complicated,  and   somewhat  costly  laboratory  procedure.     This was
                                   836

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particularly  burdensome to  the smaller,  independent producers  who  had
absolutely  no familiarity  with radioactivity.  Based on this problem and
the many comments we  received,  the decision was  made to change from a
concentration level to a  radiation  exposure level of 50 urem/hr.   This
change  would  facilitate   field  measurements  for  the   hundreds   of
potentially  affected  locations  and  equipment,  lower  the  cost   of
determination of applicability,  and still provide an  acceptable level of
radiation protection for  workers.   This level of exposure,  if received
continuously, would not  exceed  the  500  mrem/yr figure.    To  assure
ourselves that we chose a  proper dose  level,  we are analyzing scale from
the large  number of  tubulars  that  have  been screened and fall  into
category of bkg-50 urem/hr and which would not normally  require cleaning
under the exemption  criterion.  We should have this information available
by early summer.

Other exemptions include the phosphate fertilizer industry  products  and
by-products,  and bauxite processing, since these are  already covered by
existing LA regulations.   Also retail  distribution of natural gas,  crude
oil,  and their  products  were exempted,  as were produced waters,  since
these are being  regulated  by the Water Pollution Control Division of DEQ.
Any person not exempted under one of the criteria automatically  becomes
a  general  licensee  of  the State,  subject to all applicable  portions  of
the Louisiana Radiation Regulations.  In many  cases,  a  specific  license
will  be  required, particularly  for pipe  cleaning  and decontamination
operations.

Other Requirements

In order to determine applicability, a radiation survey must  be performed
within 180 days  of  the effective  date of the Regulation.   It  specifies
that  the instrumentation used be capable of  measuring 1 urem/hr  through
at  least .500 urem/hr, and  be calibrated  semiannually  and  at energies
appropriate to use,  with accuracies  within +/- 20% of the true  radiation
level.

The Rule prohibits release of  NORM-contaminated facilities and equipment
for   unrestricted   use,   and   it   requires  that  decontamination   and
maintenance  of  such  equipment  be  performed  only  by   specifically
authorized persons whether  conducted on or off-site.

Also  prohibited  is  the   unrestricted  transfer  of  land  where   the
concentration of Ra-226 in soil, averaged over any 100 sq meters,  exceeds
the background level by more than  5  pCi/gm averaged over the first  15  cm
of soil and 15 pCi/gm averaged over  15 cm thick layers of soil more than
15 cm below  the  surface.   This  requirement was already in  our existing
regulations,  but it was repeated here because  of its  applicability with
respect to NORM contamination.

Finally, an  initial fee and an  annual maintenance fee  of $100,  payable
for  each  NORM  General  Licensee location,   were  incorporated  in  the
regulations.
                                  837

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Surveys

I had  hoped to  be able  to provide  data -on  surveys  conducted by the
Division, as well as by licensees,  but,  due to  the delays  in promulgation
of the Rule, none are  available  at this time.

Conclusion

One impact  of  the  new Regulations which  is  readily observable has been
the emergence  of  a new growth industry in the State—the pipe cleaning
business.   We  have authorized five  companies to operate thus far, and
expect several new applicants in the near  future.   The problem is that
we  continue to receive reports  of clandestine  operations across state
lines, out  of  our  jurisdiction,  and reports of companies not willing to
comply until confronted face to face.  I think the eventual outcome will
be  compliance,  as a result  of  legally operating companies  learning of
their  illegal  competition and reporting  such  actions to the regulatory
authorities.

On  a  positive  note,   we  have  received  funds to  run the  program,
established several  new  positions,   distributed  the  Rule  and  other
information  to  most"  of  the affected industry,  and  are receiving a
satisfactory response.

We  have  recently completed and distributed  a  NORM  Regulatory Guide for
use   in   conducting   confirmatory   surveys   for    general   licensure
determination  and for use  in  cleanup operations and closeout surveys.
We  would be pleased to provide copies to any interested states.  We have
also  prepared a  licensing  guide  for  use  by  applicants for  specific
licenses to conduct NORM decontamination and maintenance  operations. We
have  authorized  five  (5)  companies  to  perform pipe  de-scaling as a
service  to oil and gas industries,  but have not yet issued  a specific
license.    We are  inspecting  these  operations and evaluating  their
performance to determine what license  conditions are  appropriate.  We
want to see if any build up of radioactive material in the system occurs
after  several  months  of operations and what concentrations  are present
in  the filters and process  waters.

Ultimate  disposal of  the residue  is  a major problem at  present.   Pipe
cleaning facilities are required to collect  and  return all removed scale
and residue to the customer where it  is stored indefinitely  in DOTD-
approved and permanently  marked  drums.   So far only a limited number of
shipments  have been made to  Envirocare,  the NORM  disposal  facility in
Utah,  but  we  expect to see more as the volume grows,  long term storage
becomes  burdensome, and pooling  of the waste by the major oil producers
is  accomplished.

Other  disposal options that have been  reviewed  on  a case by case basis
 include  down-hole  disposal  of  contaminated  tubulars  and   sludge in
abandoned  wells and incineration  of  contaminated soil  and  reserve pit
 residue  followed by dilution with uncontaminated fill.  The State Office
 of  Conservation  has a requirement that .all  oil  production reserve pits


                                 838

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in the coastal zone be closed out by 1993.v The closure criteria require
adherence to  our NORM Reg Guide.  We are adding  a  chapter to the Guide
requiring that  final radium concentration in  the closed pit not exceed
30 pCi/g.
                                 839

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REGULATIONS AND POLICY  CONCERNING
OIL AND GAS WASTE MANAGEMENT
PRACTICES IN INDIA
G D Kalra
Sr.  Mineralogist
National  Council of
Applied Economic Research  (NCAER)
Parisila  Bhawan, 11  I.P.  Estate
New Delhi 110 002
jnt roduc t i on

Petroleum Products

The demand  for petroleum  products in India  is estimated  to increase
from 58 million tonnes  at  present to 127 million  tonnes  by 2004-05.
The  domestic crude production would rise from 35  mi Hi on  tonnes at
present to  75 million  tonnes  by 2000.  This speaks  of  the  magnitude
of  enhancement of generation of waste due  to (i)  exploration,   and
(li) exploitation for  domestic production,  (iii)  refining of crude
oil of both  indigenous  and imported origin  and (iv)  consumption  of
petroleum products in  the  down stream industries.

Natural Gas

Today,  natural  gas  reigns  supreme in Indian energy   scenario   and
Indian  future economy  is  planned to be decidedly  gas  based.    The
shift  is  envisaged   in  favour of growth of gas-based   low  energy
intensive  - high  value  added as against high energy  -  low   value
added  industries.

It  has been established  that the petrochemicals have  the highest
value addition in the  use  of  natural gas as is demonstrated through
the figures presented  in  Table 1.

                               Table 1

             Ualue Addition  in the Use of Natural  Gas

                                                   (In Rupees)*

   Gas to                  Per NM      Per tonne      Per  tonne  of
                           of  gas      of gas         product/MUJH


1. Petrochemicals          8.21         8,932            11,328


* 1 US* - Rs.17.25
                               841

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2. Petrochemicals           3.60          3,914             6,106
   (o 1 i f in stage
   only)

3. Power generation         2.08          2,268             613.5

4. Fertilisers              1.42            767            600.00

5. Fuels                    1.15          1,255            1,255
This has,  obviously,  moved priority  in  favour of use of natural gas
in the manufacture  of petrochemicals.

Production  of   natural gas is expected  to  grow five  folds   faster
than  oil.    A   long  term production  and  utilisation plan has  been
prepared   for  the  optimal consumption  through a National Gas  Grid.
This  would  reduce  regional imbalances  by inter-connecting the  low
demand  -  high  supply areas to the high  demand - low  supply  areas
thus   meeting    the   requirements  of   various   industries   like
petrochemicals,  fertilisers, power and  a  host of others besides -its
domes tic use .

This  future  plan   for gas exploitation  and  utilisation  is  amply
supported   through   the  ever-swelling   reserves  of, natural  gas.
Against prognostica1ed resources of 63.15 billion  m  gas_in  1966,
the established  reserves of present are  1103.58 billion m  - avail-
able both  as free  and associated gas.

                                       Reserves of  Natural Gas
                                           (billion m )

                     1966                      63.15
                     1970                      62.48
                     1975                      87.67
                     1980                     351.91
                     1985                     478.63
                     1988                    1103.58

The  continued  increased usage of natural gas is taking the  weight
off  the   demand for  imported petroleum  products.   It   has  helped
bring  about a  saving of Rs.16,270 million  in foreign exchange  per
year  during  the   period  1986 to 1988.    With  new  thrust  being
 imparted   to production and utilisation  of  natural gas,  the  total
 foreign  exchange   saving  during 1989-90 is  expected  to  touch  a
 record  of  Rs.20,000  million.    Such   a   phenomenal   growth   is
 attributed  to   replacement of naphtha/fuel  oil and solid fuels  as
 feedstock  and fuels in various sectors  such  as:

  i . Feedstock                         l l l . pol/Jer

    Fertilisers/Petrochemicals:           Captive:
                                842

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i i
   Cracker  grade naphtha,  fuel
   •oil,  coal
    Industrial  (e.g. sponge  iron):

    Fuel  oil, diesel, coal
    LPG,  kerosens, coal,  diesel,
    wood

    Stationery Engine:

    Diese 1
                                           Diesel (HSD)

                                           Peak & Base Load:

                                           Diesel, coal,  fuel  oil
                                           (LSHS)

                                       iv.  Transpo rt

                                           Buses/Cars:

                                           Pet ro 1 , d lese 1

                                           Diesel Locomotives:

                                           Di ese 1
Tbe present rate  (1988)  of  production of natural  gas  is  40   million
m /day and the committed  consumption is for only  38 million m /day,
segregated as below:
Present commitment  for  use
of natural gas  (rich  gas)
                                                 Million m /day
Users along HBJ pipeline

Consumption at Bijapur/Swaimadhopur

Consumption at Auraiya

Others
                                                      17. 1

                                                       6.4

                                                      10.7

                                                       3.8

                                                      38.0
 On  an  annual  basis  it  works  out  to 13,870 million   m    or   13.87
 billion  m /year.   This   accounts   for only 1.25K annual   rate   of
           of  established reserves of qas and this   is   considered
depletion   of   established reserves of gas  and  this
quite  low  by any standard.
 The   country's  gas   production  level  is  projected  _to   go    up
 significantly  to  reach  a  level  of around 120 million m  a  day  from
 the  present figure of 40  million m  a day (1990-91).    From  these
 data,   it   is  evident   that  a  major focus  and  attention   towards
 planning of  integraded field  development,  large national gas   grid
 and  optimal  utilisation   of natural gas  resources  have   assumed
 national priority.

 The  present (1990-91) broad  pattern of gas use favours   fertiliser
 Indust ry:
                               843

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                                              (Percent

          Fertiliser  industry               i    45

          Power generation                       35

          Internal  use                           17

          Industrial  &  domestic fuel             3

                                                100
Over the past  few  years,  a number of commitments  have been made for
the  power sector  and  some more are likely  to  materialise.   It  is
thus  possible   that  share of power sector   would  increase  during
Eighth Plan  (1990-91  to  1995-96) while that  of  the  fertiliser would
go  down.    However,   these sectors would continue  to have dominant
share of the  natural  gas  used in the country.   The  use of gas  for
sponge   iron  and gas  based petrochemical complex,  would be the new
features of  future usage  of qas.   Nagothane gas-base petrochemical
complex  of  Indian  Petrochemicals Corporation Ltd.  (I PCD and Hazira
Sponge   .Iron   (0.8  million tonnes annual capacity)  of  ESSAR  Ltd.
based    on    natural   gas  have  already  gone    into  'production.
Experiments   are also  in  advanced stage for  use of  natural  gas  in
transport.    Taking  these  aspects  into   consideration,   the  use
pattern  of gas  is  expected to undergo a change  and  that will change
the pattern  of  generation of waste due to the  use of  natural gas:

                                              (Percent)

                     Perti1iser                  33.50

                     Power                       41.30

                     Industry                    12.00
                     (Petrochemicals,
                     sponge iron etc. )

                     Transport                   9.80

                     Domestic                    3.40

                                                100.00
 Uaste  Generated by Indian Oil & Natural  Gas  Industry

 Flaring of Natural Gas

 Ever   increasing  volumes  of  gas  continue  to  be  flared  up  as
 indicated in Table 2.
                                844

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                              Table 2

                        Gas Flared in India
                                             (Million  m /year)
               Gujarat       Assam        Off-shore         Total
1970-71
1974-75
1979-80
1984-85
1987-88
1989-90
155
121
178
85
288
290
607
830
616
1,074
735
812

-
170
1,893
2,439
2,575
672
951
964
3,054
3,442
3,677
This   is   attributed  to (i) short lifting of committed  supplies   of
gas   by   consumers   and (ii) delay in  commissioning  of   gas-based
power, petro-chemicaIs and fertiliser plants.

Steps Suggested  for  Economical Usage of Gas Flared

The   measures  proposed to reduce gas flaring include  (i)   reducing
crude oil   production  (ii)  setting up  of  more  facilities   for
processing   natural   gas  and (iii) a new gas  use  policy.   These
options  are  evaluated in the light of following  justifications:

     (1)   It  is  estimated that India will have to reduce crude   oil
          production   by  about  3 to 4 million  tonnes  or   by  11.6
          million   tonnes over a three year period  if it   wants   to
          completely   stop gas flaring by March  1993.   This  would
          mean  that   crude  oil  imports will go up  by   the  same
          quan t i t y.

          The   option appears hard due to the lean  position of   the
          present   foreign  exchange  resources  of,  the    country.
          Prevention   of flaring of 11.03 billion m  of gas over   a
          period  of  3 years valued at Rs.30,000  million,  appears
          sound  on  the domestic front.

          In  the   event of above option,   Indian   Oil  Corporation
          (IOC)   which is the canalising agency  for import  of crude
          oil  and petroleum products may go for  a bridge  loan  from
          international commercial sources  for import of additional
          crude   oil   to make up for the reduction  of 11.6 million
          tonnes  of  domestic production.  The interest  charges on a
          loan  like  this work out at 8 to  10 per cent.    But   loan
          saves   gas   valued  at Rs.30,000  million  over   3  years
          per iod.

     (2)  The   time   between  now and March 1993   is  proposed   for
          setting  up of processing facilities and down  stream units
          to utilise the gas.
                               845

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     (3)  A  new   gas  utilisation   policy  which   permits  greater
          utilisation  of  gas  needs  to  be  formulated  now.   At
          present,   gas  is  reserved  for fertiliser  plants  taking
          into  account  their  requirement for  30  years.   It  is
          suggested  to reduce this  period to 20 years.   Such a step
          will  spare gas for other  far more needy  industries.

Exploration and Exploitation of Oil  and Natural Gas

The  main  waste   generated during  exploration  is  drilling  fluid
effluent.

International   statistics show  that  1m  of drilling  fluid effluent
is produced on  an  average for every  metre drilled.  A good quantity
of it  is evaporated  in normal process  particularly during  summer  in
a tropical country like India.   During monsoon when evaporation  is
less,   the  problem   of accumulation of waste  water  becomes   more
discernible.

The  problem  is encountered in  three ways (a) recycling  of  mud  pump
coolant  water,   (b)  recycling of effluent water for preparation and
Cc)  treatment  of  effluent water for  re-use.

Contribution of Refineries in Generation of  Waste

The  refinery at Digboi in Assam commissioned in 1901 is  perhaps the
oldest  operating  refinery in the world.    However this was  the  only
refinery   in   India  till mid-50s.    Between  1954  and  1982  eleven
refineries  were  commissioned which  enhanced the refining   capacity
from 0.3 million  tonnes per annum  (MTPA) to  51.9 MTPA by 1989.

The    refineries   have  been  providing  the  pollution    abatement
facilities  right   from  the  design   stage   itself.   However  the
facilities  provided  in  the various  refineries differ  from   each
other  since these  are governed  by concurrent

          - regulations
          - technologies available  and
          - operating parameters.

As   for   instance  the last refinery  commissioned in 1982   has   also
tertiary  treatment  in addition  to effluent treatment plants  having
physical, chemical  and biological  treatment  facilities.

wastes  Generated  and their Treatment in Refineries

The  waste  water  generated at  the  different stages of refinery   is
treated   in  accordance  with   the  well   laid  down  procedure  and
similarly   there   are  standard prescribed for  the  air   pollution
(Table  3 ) .
                                846

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                               Table 3

     Oil Refineries - Emission  Standards for Sulohur  Dioxide
     Process                                SCL Emission Limit


(a)  Atmospheric and vacuum                  0.25 kg/tonne of feed
    distillation

(b)  Catalytic  cracker                       2.5.kg/tonne of feed

(c)  Sulphur recovery unit                   120 kg/tonne of
                                            sulphur  in  the feed

The   solid  waste  generated   in Indian  refiniries  are  of  great
concern.  These solid waste  are:

        - Sludge formed  inside  crude storage tanks.

        - Chemical sludge  generated from effluent  treatment  plants
          containing mostly iron sulphides.

        - Biological    sludges   from  activated  sludge  units   of
          effluent treatment  plants.

Refineries  adopt  melting   pit  system to  recover   oil  from  oily
sludge.   The  residual   sludge  is stored  in an open quarry  inside
refinery premises.

Some   refineries have  adopted hot  gas oil  circulation  in crude  oil
tanks  to dissolve  oil  in the  sludge as much as possible and then to
process  in units.

Side Entry Mixers  are  being installed in all crude  tanks in  phased
manner to prevent  sludge formation  in tanks.

At  present there  are  no regulations governing generation,  use and
disposal  of   sludge  in  India.    These are  urgently  warranted  at
present .

Development   of  a  process to  recover useful components from  sludge
will   help  to   avoid   the  problem of sludge   accumulation  in  the
ref i ne ry.

Fert i 1 i ser/Pe trochemical Industry

Naphtha,  fuel  oil  and  natural gas  are used as  feedstock as we 11 as
fuel   in   the  ferti1iser/petrochemica1s  industries  of   India.   No
waste  as such is  generated in  the  fertiliser  industry through  the
consumption   of   naphtha/fuel  oil/natural  gas   since   the  entire
                              847

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feedstock  which  is  hydrocarbon  is  totally broken  (by  burning) into
Co',.  Co^ ,  H9}   inert gas etc.    however, conversion of  these gases
into  ammonia   and   then  to  urea   does  generate  wastes  due  to
processing and  use  of chemicals  in  process and  in  utilities.

The main sources  of  generation of  liquid effluent  are

         -  Ion Exchange Columns and
         -  Cooling Tower Slowdown.

Both  these   types  of effluent are  totally recycled in the  captive
phosphatic plants.

The pollutants  in the atmospheric emission is very much within  the
specifications   of  the consented  limits  and  recovery of these  minor
quantities are  beyond economic consideration.

                               Table  4

              Fertiliser Plants - Emission Limits for
                  Particulate Matter and  Flurides
    Product         Process          Pollutant       Emission limit
                                                       (mg/k cu.m)


 (a) Urea            Prilling         Particulate           50
                    Towe r

 (b) Phosphatics     Acidification    Fluorides             25
                    of rock
                    phosphate

 (c) Phosphatics     Granulation      Particulates         150
                    and grinding

 The solid  waste  like  spurt catalyst is disposed  off by   sale.    The
 buyers  retrieve  the metals ICu, Zn, Ni) content  in the  catalyst.

 Petrochemicals  Industry

 Petrochemicals   in  India is also based on  naphtha/fuel   oil/natural
 gas   as   feed.    In this case also no waste  is   generated  as  such
 through   the  use  of hydrocarbons.   Chemical  waste is generated  in
 the process.

      It   is  suggested by the industry that  for  the safe disposal of
 chemical   waste,   it   will  be necessary  to  have   land   fill  areas
 designated by the Government and/or providing  incentives to private
 sector  to  set  up  large commercial  incinerators.
                                848

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adequacy of Indian Law  to Check Generation. Storage
and  Disposal of Waste of  Oil and Natural  Gas Industry

The   Appendix  1  furnishes  the salient   features   of   the  Indian
legislation governing the industry  to  operate within   the  standards
prescribed.   A perusal  of these legislation does not  spell out any
specific  provision  devoted to generation,   storage  and  disposal of
waste  of oil and natural gas  industry.    This is a  serious  matter
and   deserves attention  in view of  the  phenomenal increase   in   the
consumption  of  oil  and  natural  gas   anticipated   in   future  as
discussed earlier  in  the  paper.
References

1.
2.
Tata Energy Research Institute,   TERI  Energy Data Directory  &
Yearbook - 1987,  1988 and 1989.

Oil  and Natural  Gas Commission  CONGO,   Pollution Control   of
Drilling Fluid  Effluent and  Its  Implementation, 1990.
3.   Oil  and   Natural  Gas Commission  (ONGC),   Perspective  Plan   On
     environmental  Management, Seventh  Plan (1985-86  to  1989-90).

4.   Oil and Natural  Gas Commission  (ONGC), Workshop  on  Environment
     In Oil  Industry  :  A Course  for  Corporate  Managers,  1989.

5.   Government   of India (GDI),   Water  (Prevention and  Control   of
     Pollution)  Act 1974 with Amendments  made  in 1988.

6.   Government   of  India (GO I ) ,  Air  (Prevention and   Control   of
     Pollution)  Act 1981 with 1987 Amendments.

7.   Government  of  India (GDI),  Environment (Protection) Act  1986.

8.   Marpol  Convention, Five Annexures.
                               849

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                                                          Appendix  I
Green Arm of  the Law and  its  Adequacy

Three   important  Indian  legislations presently enjoin  industry  to
remain  within  the poltution control standard  set  by the Government.

1 .    Water   (Prevention   and  Control of Pollution)  Act  1974.  uiith_
     amendments made in 1988.

         - Following the 1988  amendments permission  is necessary  to
          set   up any industry  which is 'polluting'  - one that uses
          or  discharges any poisonous, noxious  or  polluting matter.
          Standards must  be those set up by state  pollution boards.
           Industries  set up  prior to the amendment  need to  obtain
          clearance within three  months of  its  coming into force.

         - State  Pollution Control Boards (PCB)  have  the  power  to
          obtain    information    regarding     the     construction
           installation or operation of any process  of the industry.

         - After the 1988  amendments,  the PCBs  can  issue directions
          or  orders for closure or stoppage of  electricity or water
          supply  if  standards are not being met by  the  polluting
           industry.

         - Penalties  for  non-compliance  have   been   increased  to
          Rs.10,000  for  defaulting  and  Rs.5,000   per  day   for
          continued default.

2 .   Air  (Prevention and Control of Pollution)  Act  1981 with  1987
     Amendmen t s

         - The definition  of air pollutant  was extended from harmful
          solid,  liquid  or  gaseous  substances   present   in  the
          atmosphere to include noise pollution.

         -  Unlike  the  practice  earlier,   now   all   air  polluting
           industries  must  have  the sanction of   their   respective
          PCBs.

         -  After amendments,   power have been  given  to PCBs  to issue
           directions for  stoppage of electricity etc.  for violation
           of  standards set.

         -  Penalties are as those  in the LJa t e r Act.

 3.   Environment (Protection) Act CEPA) 1986

         -  The  Central  Government has the power  to  take  all  such
           measures   as    it  deems  necessary   or   expedient   f°r
           protecting the  environment.
                                850

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       - Section  of 3 of EPA empowers the Central  Government to

          (a)  restrict  areas  in  which  any   industry,   operation,
               process  or  class  of  industries can  be  carried  out
               under certain safeguards.

          (b)  lay   down   procedures  and  safeguards    for   the
               prevention    of    accidents    which     may    cause
               environmental  pollution  and remedial measures  for
               them.

          (c)  lay   down   procedures   for   handling    hazardous
               subs t ances.

          (d)  examine manufacturing  processes and  materials  and

           (e)  wide-spread  inspection powers.

As  in   other  two  actsj   the EPA gives the centre   wide   powers   to
direct   closure,  prohibition and  regulation of any  industry  if   it
contravenes  the acts provisions.

In addition,   the  Marpol  Convention,  pertaining to  marine  pollution
control,  was  drawn up by  the  International Maritime  Organisation,  a
United  Nations  agency and ratified by India  in 1978.

The  five Annexures of this convention deal with (a) prevention   of
oil  pollution,  (b)  prevention   of  pollution  by   noxious   liquid
substances   in  bulk,   (c ) prevention  of pollution by noxious  packed
substances,  (d) pollution from  sewage and (e)  from garbage.

The  Indian  Government has  ratified only the first   two   Annexures.
Thus a  vessel  can  be penalised  for oil or chemical pollution.    But
the remaining  forms of pollution are  unchecked.
                               851

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A REVIEW OF STATE CLASS  I I UNDERGROUND  INJECTION CONTROL PROGRAMS
Jeffrey S.  Lynn
Marathon Oil  Company
Findlay, Ohio
Richard L. Stamets
UIPC Consultant
Santa Fe, New Mexico
 Introduction

 Over the past  few years, the Underground  Injection Practices  Council  and the
 Underground Injection Practices Council  Research  Foundation have entered into
 a series of  individual  grant  agreements   with   the   U.S.   Environmental
 Protection Agency, the U.S. Department of Energy  and the  American  Petroleum
 Institute.  These grants   were   obtained   to   evaluate  and  assess  state
 underground injection control (UIC) programs   as   to  their effectiveness in
 protecting underground sources of drinking water  (USDWs)  from  contamination
 resulting from the  operation of  injection wells  related to the production of
 oil and gas (Class II injection wells).   Class   II   injection wells are used
 for the injection  of  fluids  into  oil  reservoirs  for   the   purpose  of
 stimulating or furthering their production when natural  production mechanisms
 decline or cease  (enhanced  recovery  wells); and for the disposal of waters
 produced  in conjunction with the production  of oil  and gas (disposal  wells).
 If  improperly constructed, operated, maintained,  or abandoned,  such wells may
 allow contaminants to enter USDWs, potentially depriving the public of needed
 current or future water supply resources.

 Six state Class II UIC programs have been reviewed to date.   In their review
 order they were  California, Texas, Louisiana, Ohio, Oklahoma  and Kansas.  Of
 the approximate universe of 177,000 Class   II  injection wells  nationwide, the
 states reviewed regulate over 120,000 of these wells or approximately   68% of
 all Class II wells.  The six state programs examined were those where  primary
 enforcement authority had   been  delegated  to   the  states  by  EPA,  under
 provisions of the Safe Drinking Water Act and  EPA regulations.

 All state program  reviews  were  conducted    in    a   similar   manner.    An
 investigative team of  two "peer" state  UIC directors comprised  each   review
 team along with  a  UIPC'  consultant,  who  is a  former  state  oil  and gas
                                      853

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director, and the  UIPC  Technical  Director.   The UIPC Technical Director and
the UIPC consultant were present  at each  of  the six state reviews to provide
continuity and assure  investigative integrity for the project.   The state to
be reviewed was  required to complete a comprehensive questionnaire detailing
inportant aspects of   its  Class   II  UIC  program.   This  questionnaire  was
designed to yield an in-depth  description of  the seven key  program  elements
ccmnon to all  state  Class   II   UIC  programs.    Those  seven  basic program
elements were as  follows;  (1) permitting and  file  review  programs,  (2)
inspection programs, (3)   mechanical    integrity   testing   programs,   (4)
compliance and enforcement  programs,   (5) plugging and abandonment programs,
(6) inventory and data management programs, and (7) public outreach programs.
After the state's  completion  of  the questionnaire,  an  on-site,  week  long
review was scheduled,  whereby the  review team questioned  employees  of  the
state UIC regulatory  agency   extensively  about the operation of the various
Class  I I program elements for  which they were responsible.

Preliminary results of the review teams  investigations were orally presented
to the state program managers  at  the end of the on-site review.    These  were
followed by a  formal  written review team report for each state.  The review
teams's corrments reflect their judgement  as   to whether or not the state UIC
program effectively protects USDWs  from contamination by  Class  I I  injection
wells.  Additionally, state program strengths,  as well as reccnrnendations for
areas of improvement, were included in the final  reports.

Goals

The purposes and  objectives   of  the  Class   I I   peer  review  project   were
multifold.  As previously stated, the  major   objective of  the project was to
examine the effectiveness  of  each  state UIC  program to  protect  USDWs   from
contamination by oil and gas related injection wells.   Secondly,  this  process
provided an  increased   knowledge  of  specific   state  Class  I I   regulatory
programs and operations for review  by  other   state UIC programs, the  EPA and
for the review participants.   Additionally, the  peer review  project   enabled
the states and  the  UIPC to prepare for the  EPA Mid-Course Evaluation of the
state Class  II UIC program.  Lastly,  this project provided the states with an
independent evaluation, separate  from  EPA oversight,  and an opportunity to
examine and consider  the  recorrmendations of  this  review   for  potential
implementation into their present program.

Process

The six state  Class  II UIC program reviews were all conducted using the same
review questionnaire workbook.    The   workbook   consisted  of  a  series of
detailed questions (153  in  all)   pertaining  to  the  seven  basic  program
elements described earlier.    To  assist the  states in understanding the type
of response desired, each series  of questions  was  preceded  by  a specific
objective which defined  and   clarified  the   intent of the  questions.   The
review questionnaire was  furnished  to  the   state  Class  I I   agency   to be
completed by state UIC program personnel  well   in  advance  of  the  on-site
                                     854

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review.

Upon selection,  the  review  team  was   given  copies  of the completed state
workbook,  for examination prior to traveling   to  the  state  being reviewed.
The week long on-site review consisted of  using the completed  workbook  as a
guide while questioning  state  Class  II UIC  employees about the operation of
the various program areas as outlined  in the  workbook.   An initial background
briefing on the  state's  geology,  hydrogeology  and  standard  UIC  program
procedures was provided by the host state  prior to review  team  questioning.
Additionally, the review team received a complete tour of the UIC offices,  in
order to evaluate workflow and output.

The review team  assessed  the written workbook responses,  the oral  responses
to additional questions posed during  the   on-site  review,   and  the various
documents supplied by  the  state prior  to summation of an  initial   list   of
program strengths and  concerns.   This  sum-nation was delivered to  the State
UIC Director, UIC staff, regulatory agency management,  and interested parties
at an exit interview on the final day  of   the on-site review.   This exchange
of  information and opinions was integral to the success of  the  peer  review
process.   It was  this  discussion  of   program  strengths  and  concerns,  as
 identified by the  review  team,  which  provided  input  for  the  state   to
potentially acknowledge program areas, through which minor enhancement,  could
make the program more efficient and effective.

Subsequent to the  on-site visits, review  team members  wrote  more  extensive
reports of their  findings  and  conclusions.   These reports were reviewed  by
the contractor and the UIPC Technical Director and submitted to the  state for
final corrment.  The review team reports  were  arranged  in  the same order  as
the questionnaire and  each  of the seven  program areas  was  followed  by  a
 listing of any  strengths  or  other  considerations identified by the review
team.  The review team conclusions relative  to  the  effectiveness   of that
portion of the  state's UIC program to protect USDWs followed  the  strengths
and other considerations  discussion.    An executive  sunrmary  preceded each
state specific report along with a general  program corrments and observations
section.   In the  general  ccnrments  section   each  state   was  provided   an
opportunity to list  any program accomplishments since acquiring EPA approved
regulatory authority (primacy).  The final  written  reports were printed and
published for dissemination to interested  parties.   These detailed individual
state reports are available through the  UIPC  office.

          jrt Overview

The  following is a brief sum-nary of the  review team reports  for  each  state
 reviewed, beginning with the initial California report and continuing through
each subsequent state  reviewed  in  its  order of occurrence.   State program
highlights or strengths identified by the   review teams are presented as well
as  any other considerations suggested by each review team.
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The California Division of Oil  and Gas LMC Program

The review of the California  Division of Oil and Gas Class  I I UIC Program was
conducted in Sacramento,   in  March,  1988.  The Division's UIC program  is much
more decentralized than most  state programs  with  permitting,  file reviews,
and most compliance   functions   handled  at the district office  level.   The
overall UIC program   coordination  between  the  districts and the Sacramento
office  is excellent.

The review team found good permitting  procedures,  qualified personnel, good
availability of technical  expertise  and  resources,  excellent  cooperation
between the Division   of   Oil   and  Gas  and  other concerned state and local
jurisdictions, and continuing   oversight   of   ongoing   operations.     The
permitting portion of the  UIC program was determined by the review team to be
protective of USDWs.   A minor concern with long term financial responsibility
for noncommercial  injection   wells  was  noted by the review  team.     It  was
suggested that this program area be given continued monitoring and study,  not
necessarily any  in-mediate  action.

The Division  inspection  program  was  determined  to  be  very strong. Well
defined inspection strategies,  use of  well  qualified  field  personnel,  and
continued job related training  opportunities  provide   the  basis  for   an
effective UIC  inspection   program.    This  program area was determined  by  the
review  team to provide good to  excellent protection of USDWs.

The review team  determined that the overall frequency of mechanical  integrity
testing, reliance on   mechanical   logging  techniques,  technical   procedures
employed and well trained  personnel  in this program area  result  in superior
protection of USDWs.   A   minor concern was expressed relevant to a perceived
extended period  of permitted  shut-in for  injection  wells  which have  failed
their mechanical  integrity test.   A reasonable time limit  was  suggested  for
such wells to  be  repaired   or  plugged to ensure they do not threaten fresh
waters  or USDWs.

The policies and procedures employed by the Division to handle compliance  and
enforcement  issues are reasonable and  responsible.   The  Division  uses  a
staged  enforcement approach which generally achieves voluntary compliance  but
which  can advance to  formal enforcement and fines as necessary.    The  review
team concluded that   the   Division  has  structured  its  UIC  compliance  and
enforcement program to provide  good protection to USDWs.

The California Division of Oil  and Gas plugging and abandonment practices  are
conducted  in  a   manner protective of fresh  waters  and  USDWs.    Essentially
every  injection  well  is  inspected during the plugging process and setting  and
tagging of 80  percent of the  most  critical plugs is witnessed  by   state
 inspectors.

The Division  has  and uses appropriate data management techniques to provide
better  program management  and inventory  data.  This information is available
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in the district   offices  as  well as the Sacramento office.   The review team
determined that  the use of the Division  data  management  system enhances the
protection of USDWs.

The review team   found  the  Division  to be operating an   aggressive  public
outreach program to  promote  public  awareness of  injection operations.   The
program makes use of pamphlets, video tapes and public appearances to promote
public exposure  of the program.  The public  outreach program  as practiced by
the California Division  of  Oil  and  Gas  was deemed highly  effective   and
supportive of the protection of USDWs.

The Texas Railroad Cocrmission Oil and Gas Division  UIC Program

The review of  the  Texas  Class  II  UIC program was conducted  in Austin,  in
July,  1988.  The Texas UIC program is the  largest  UIC program in the country
covering over  15,000 operators and 53,000 injection wells.   The  UIC Section
of the Oil   and   Gas  Division  is  solely  responsible  for permitting,  file
reviews, mechanical integrity test scheduling  and  evaluation,  and reporting
to the  EPA.   The  UIC  Section coordinates with other Division   sections   on
matters  related  to   budgeting,   personnel,   mapping,  records,   compliance
hearings,  and  inspections.  There is an  excellent  degree  of  cooperation  and
coordination of  efforts  between  all  of the various Oil   and  Gas  Division
sections which  ultimately promotes the protection of USDWs.

The review team  found  good  permitting  and  file review  procedures, highly
qualified  personnel, good  cooperation   between    state    water    protection
agencies,  and  good  post  permitting  oversight.    With   a   single   concern
expressed  relative to  the  examination  of  area of review wells,  the review
team found the  permitting program element protective of USDWs.

The review team  concluded  that  the   state   UIC inspection   program  was
facilitating protection of  USDWs.    Inspections  are  performed   by  state
employees  operating from  district  offices.    Inspection   personnel  are well
trained and  well equipped to perform their tasks efficiently and effectively.
The review team did note that due to  program  size,  the   injection   well  to
inspector  ratio was  approximately 1720 injection wells  to each  inspector,
which was  considered high.

Texas utilizes  annul us   pressure   tests  and  annul us  pressure  monitoring
combined with  the  review  of  cement   records   for   mechanical  integrity
determinations.   The review team determined that this portion  of  the Texas
program was  being conducted in a manner protective  of USDWs.

The Texas  Railroad  Conmission has a sophisticated  compliance  and enforcement
program which  is  logical,  well  defined   and  effective.    Written policy
provides inspectors with  specific enforcement procedures   to  clarify their
role in enforcement  actions.   The  enforcement  and  compliance  program as
conducted  by the Conrmission is highly effective  in achieving  compliance with
state rules.  The  review  team  acknowledges this  level  of   excellence   and
                                      857

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considers this program  area to be very  effective, in achieving compliance and
facilitating protection of USDWs.

The Texas state plugging requirements  should result in all  Class II injection
wells being plugged in such a manner as   to  isolate and/or  protect all usable
quality water zones, oil, gas and geothermal  zones, and USDWs.   Although the
review team indicated  a  desire  to   have a greater number of injection well
pluggings witnessed, it  concluded  that  the   state  plugging  program  is
protective of USDWs.

The Texas Class   II  UIC  program  operates  a highly sophisticated  UIC  data
management system that  provides  an excellent management tool for the 53,000
injection wells in  the  state.  The review   team  concluded  that  the  data
management program element  of the Texas Class II  UIC program  readily  lends
itself to the support of the protection  of USDWs.

The review team  believes  the  Corrmission   has   established a reasonable and
effective public outreach program.  The   Corrmission is responsive to specific
public concerns through direct visits  and presentations by   appropriate staff
on an "as needed" basis.

The Louisiana Department  of  Natural  Resources   Office of Conservation UIC
Program

The Louisiana Class  II UIC program review was conducted  in Baton Rouge,  in
October,  1988.  The   Injection  and  Mining   Division  of   the   Office   of
Conservation has overall   responsibility   for    permitting,  file  reviews,
mechanical  integrity test scheduling   and evaluation,   compliance  hearings,
field  inspections of corrmercial disposal  wells and reporting to EPA.

The Division's permitting  program  is clear,  concise and easily  understood.
Permit applications are  quickly  entered into the UIC data management system
and tracked to  expedite  permit  determination.     Qualified  personnel   are
employed  to assure  permitting  operations   are   smooth and  efficient.    The
review team concluded  that  the  permitting  portion  of  the UIC program is
conducted in a manner which  is protective of USDWs.

The Louisiana Class   I I  inspection    program  places  a  high  priority  on
witnessing mechanical  integrity tests, with  less  emphasis  placed  upon  well
construction and  remedial  work   inspections.    Inspectors  are well qualified
with a minimum of three years of oil and gas related field experience and 6
months of on the  job training with an  experienced inspector.  The review team
determined that given  the number of inspectors  (32 for noncommercial   wells)
the  inspection program  element   is  carried  out  in  a manner that provides
protection of USDWs.  However,  it was  suggested   that any  action which would
result  in the   increase  in  number of inspectors and UIC  inspections  would
enhance this program area.

The Louisiana UIC mechanical  integrity  testing program is  designed to assure
                                      858

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all wells are   tested  as  required  with  a high  level  of  state supervision.
Based  upon these measures, the review team concluded  that this portion of the
state  UIC program is conducted in a manner which  is protective of USDWs.

The compliance and enforcement program element  is  a strength of the Louisiana
overall  program.  The Injection and Mining  Division   has   the  authority  to
administratively assess monetary  fines  and  this authority   provides    an
effective  deterrent to  non-compliance  by  operators.    Inspectors are given
broad ranging authority  to  seal or  shut-in   wells   found  to  be  in  non-
compliance.   The review  team determined that the  compliance  procedures   and
policies used by the Division are conducive to  the protection of USDWs.

Louisiana witnesses about  90%  of  all  injection well plugging operations,
giving the Division good oversight of  this  program   element.    All  plugging
procedures must be approved by the state.  Plugging requirements  may  differ
for nearby production  wells,  leading to a concern on the  part of the review
team as to a  lack of uniformity in the required setting  of  plugs in abandoned
production wells versus  injection wells.

The Class II UIC program  in Louisiana  makes  good use  of   data  management
systems to enhance  its  ability  to record, retain,  and retrieve  well   and
permit data in  a timely and complete manner.   The data  management system and
practices of the Division greatly enhance the protection of  USDWs.

The level of public outreach by the Louisiana   Injection and Mining Division
 is appropriate to current needs and in no way diminishes the  protection of
USDWs.

Ohio Department of Natural Resources Division of Oi1  and Gas UIC Program

The fourth Class   II  UIC  program  review  was conducted   in  Columbus,   in
February, 1989.  Permitting,   file    reviews,    data  management,    formal
compliance, hearings and program administration are handled from the Division
office.  Field activities  are  conducted  from four field   offices.    The
Division makes no  distinction  between  the  definition of  fresh water and
USDWs.

Ohio permits three types of injection  wells:   conventional  disposal  wells,
enhanced recovery wells and annular disposal wells.   All  wells  in the state
operate under permits.  The review team found good permitting and file review
procedures and qualified personnel with the necessary technical expertise and
resources to assure permit applications are properly  handled.  Minor concerns
were expressed relative  to  long  term  financial  assurance  and the use of
prepared clay as a sealant behind surface casing.  With  these exceptions, the
review team concluded that the permitting  portion of  the  UIC  program  is
protective of USDWs.  The use of prepared clay  has recently  been banned  as  a
 surface casing sealant for annular disposal wells.

One statewide UIC  Field  Operations  Supervisor oversees all UIC inspectors.
                                    859

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Conventional disposal and   enhanced  recovery  wells  are routinely  inspected
every four to six weeks.  The  review team determined that the  inspection area
of the UIC progran  is providing an excellent degree of protection for USDWs.

Ohio utilizes positive  pressure tests,  annul us pressure monitoring and cement
record evaluation for mechanical  integrity  determinations.  All conventional
injection well mechanical  integrity test are witnessed by  state  inspectors.
Mechanical  integrity tests   are  now  required  prior to initial injection in
annular disposal wells.  The mechanical  integrity testing portion of the Ohio
UIC progran is being conducted in a manner  which  is  highly  protective  of
USDWs.

The compliance and  enforcement program of the Ohio Division of Oil  and Gas is
a multi-level, staged   approach,   with  a variety of enforcement  actions  to
handle violations.  Fines r must  be  sought  in  the  courts through civil  or
criminal  actions.   The   review  team   concluded   that  the  compliance  and
enforcement program area is effective and being administered  in  a manner  to
achieve  protection  of USDWs.

Well  plugging and   abandonment  must  be  conducted  in  a manner approved  by
either the Division of  Oil  and Gas or the Division of Mines.   The Division  of
Mines oversees plugging in coal bearing  townships.   While  the  review team
would like to see the state amend the split plugging authority  to   allow for
 joint plugging of   injection  wells  they felt the plugging regulations being
enforced are designed to be protective of USDWs.

At  the time of the  Ohio review the Division's  data  management  systems were
under extensive  revision.   The revised system will allow more ready access  to
UIC data,  manipulation   of  data  and more efficient program  administration.
The review team   concluded  that  the new data management system will enhance
the protection of USDWs.

The Ohio public   outreach program is  strengthened  by  the  high  degree  of
 personal  contact with   the  regulated ccnmunity through frequent  inspections
 and presentations.  The   review   team   concluded  that  Ohio  conducts  an
 appropriate and  effective public outreach program.

 The Oklahoma Corporation Corrmission Oi1  and Gas Division UIC Program

 The Oklahoma Class  II UIC program review  was  conducted in Oklahoma City,  in
 March,  1989.  The UIC Department of the Corporation Corrmission  is completely
 responsible for  permitting,  file  reviews, mechanical integrity testing, and
 reporting to the EPA.   The Department  coordinates  with  other  Oil  and Gas
 Division sections on  matters  related  to  budgeting,  personnel,    mapping,
 records, hearings,  and   inspections.   There  is a good degree of cooperation
 and coordination of efforts between all   of  the  branches of the Oil and Gas
 Division leading to acccmp1ishment of the protection of USDWs.   The Oklahoma
 Class II  UIC program was the first such program approved in the country.
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The review team  found   good permitting and file review  procedures,  qualified
personnel and  improving post permitting  oversight. Use  of  data processing to
track permit application flow facilitates this process.  Minor   concerns were
expressed relative  to  the  adequacy  of cement thickness above the  injection
zone and procedures followed on file reviewed  wells  when  the  surface casing
did not extend to or through the base of the USDW.  With the  above  mentioned
concerns the review team concluded that the permitting portion  of  the program
is being carried out in a manner that is protective of USDWs.

Although there is   a  relatively  high  injection well to inspector  ratio the
review team determined that the state's  inspection program is  providing good
protection  to  USDWs.  This effectiveness results in large part  because of the
focus on matters  which can provide the greatest degree  of USDW  protection
including attention to   water   flows,   well   construction,   plugging  and
abandonment, mechanical integrity  testing,  citizen  complaints  related  to
pollution and  illegal activities.

The procedures used  in  Oklahoma  to  establish  mechanical    integrity  are
protective  of  USDWs.   The  state  utilizes annul us pressure tests and cement
record  review  as the predominant means  for determining  mechanical integrity.
A major  effort has been underway to complete the required  pressure   testing
for pre-primacy wells.

A variety of    multi-level   enforcement   tools  are  available to   achieve
compliance, from simple field inspector  notification through formal  hearings
and fines.   The review  team concluded that the compliance and enforcement
portion of  the Oklahoma UIC program is structured and implemented  in  a manner
that is more than  adequate for protection of USDWs.

At the time of the on-site UIC program review the data  management system was
being modified.    The UIC Department has now completed an extensive effort to
computerize essential files and records.   The  computer system  is   used to
track permitting,  mechanical   integrity  test  scheduling   and  reporting,
 inspection  documentation, compliance   monitoring  and   EPA reporting.    The
review team concluded that the data management  system being used at  the time
of the review  would facilitate the protection of USDWs and  that the  proposed
data management system   enhancements,  now  in  place,  would   substantially
enhance the protection of USDWs.

The Oklahoma public outreach program  is  designed  to   reach   and inform the
regulated corrmunity and interest groups as well persons  directly affected by
any particular permit.    The  review  team found this portion of the  Oklahoma
program to  be  appropriate and lend itself to the protection of  USDWs.

Jhe Kansas  Corporation Comnission Conservation Division  UIC Program

The sixth state UIC program review was conducted in Wichita,
 in January, 1990.   The Conservation Division  of  the  Kansas Corporation has
 regulatory  authority for Class II injection wells in Kansas.  The Division  is
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responsible for UIC permitting, file  reviews,  general  data management, formal
compliance, hearings, program adninistration and field inspections.

UIC Unit procedures, permit application  reviews, and data resources available
are sufficient to  assure  that   injection   well  permit applications receive
proper evaluation.  The UIC staff  is  knowledgeable  and  experienced.   Minor
concerns were expressed relative to financial  assurance,  the lack of specific
detail in the  required public notification  of proposed injection  wells  and
the lack of  clearly defined standards for minimum cement thickness above the
injection zone.  Overall, the review  team   determined  that  the  permitting
portion of the  Kansas  UIC  program  is  being  conducted and  supported  in  a
manner protective of USDWs.

Field inspections are  performed   by  40 state inspectors operating from four
district offices.   Inspectors are  well   qualified with a minimum of two years
of related field experience required.   Inspection priorities are logical  with
contamination events as the highest priority.   The review team concluded that
this portion of the Kansas program is providing good to excellent  protection
of USDWs.

Kansas primarily uses  positive  pressure tests,   positive  annulus pressure
monitoring and cement record evaluations for  the demonstration of  mechanical
integrity.  Mechanical integrity test notification and follow  up  procedures
are clearly defined  and  assure   all  wells are tested.   A minor concern was
expressed that a new mechanical integrity test  after  a  workover  is not a
requirement unless the packer is reset at a  different  depth.    With  only the
expressed concern, the  review  team  concluded  that   the  Kansas  mechanical
integrity testing program provides an excellent degree of USDW protection.

The Division use a variety of both formal and  informal  enforcement  actions to
maintain  injection well compliance.  The compliance  and enforcement program
operated by the Division is sufficient to enforce compliance  with  UIC permit
conditions and state rules and provide USDW  protection.

Standard plugging requirements  are  designed  to isolate  and protect all  oil,
gas, fresh water and USDWs.  Cased hole   pluggings  are  a  high priority for
field inspector witnessing.  The plugging portion of the   Kansas UIC program
was determined to  be  conducted   in a manner  that is  effective in  protecting
USDWs.

The Division effectively  uses  a  combination  of  manual  and  computerized
systems for managing data, program tracking  and enforcement.   The review  team
concluded that the  Division  data management  system  is  facilitating   and
enhancing the protection of USDWs.

The Division conducts  an appropriate public outreach  program which keeps the
regulated community and the general public   informed.    This  program area is
being adequately carried out to facilitate protection  of  USDWs.
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nope]usions

Although the states   may  operate  their   individual  UIC programs and program
elements differently, the  overall  consensus    for   the  six  state  reviews
completed to date   is  that,  with  only  minor  exceptions,   the  states  are
maintaining efforts  to  effectively protect USDWs  from contamination by Class
II injection wells.   Many of the state  programs take different approaches to
permitting,  inspections, mechanical   integrity  testing   and   enforcement,
however, each  state   program  ultimately  provides the  framework  for  USDW
protection.
 References

 1.   UIPC, The  California Division of  Oi 1   and  Gas   Underground  In.iaction
     Control Program:  A Peer Review. 1989.

 2.   UIPC, The  Texas  RaiIroad  Conrmission Oil and Gas Division  Underground
     In.iection Control Program:  A Peer Review. 1989.

 3.   UIPC, The   Louisiana   Department    of   Natural   Resources   Office  of
     Conservation In.iection and Mining Division Underground  In.iection  Control
     Program:  A Peer Review. 1989.

 4.   UIPC, The Ohio Department of Natural  Resources  Division  of  Oi1  and Gas
     Underground In.iection Control Program:   A Peer Review.  1989.

 5.   UIPC, The  Oklahoma  Corporation  Cormnission  Oi 1    and   Gas  Division
     Underground In.iection Control Program:   A Peer Review.  1989.

 6.   UIPC, The    Kansas   Corporation   Comnission   Conservation  Division
     Underground In.iection Control Program:   A Peer Review.  1990.
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Simple Injectivity Test  and Monitoring Plan for Brine Disposal  Wells
Operating By Gravity Flow
1.  Meyer
Underground Injection Control Program
U.S. Environmental Protection Agency, Region IV
Atlanta, Georgia
Introduction

The injection of produced brine waste-water from oil and gas operations  into
disposal wells  in  the  United States requires a permit from the Underground
Injection Control  (UIC)  Program of the U.S. Environmental Protection Agency
(EPA).  In the  application for a UIC permit, oil and gas operators must
demonstrate proper construction of the injection well and any nearby wells,
termed  area of  review  (AOR)  wells, that will be affected by the injection.
Proper  well construction protects any underground source of drinking water
(USDW)  from contamination by the injected brine.  If the injection well  or
AOR wells are improperly constructed or if any AOR wells have been improperly
plugged and abandoned, then corrective action requirements to remediate  these
problems are necessary prior to EPA injection authorization.

This paper assumes that the injection well itself is properly constructed but
that the AOR wells are in need of corrective action.  The usual cause of
corrective action  requirements in AOR wells is inadequate casing or cementing
in production wells and improperly placed plugs in abandoned wells.  AOR
wells must be constructed or abandoned so that there are no pathways for
migration of brine into a USDW.

Implementation  of  corrective action requirements by an operator for a UIC
permit  might result in new casing and cement for production wells, plugging
and abandonment of production wells, and even the replugging of previously
abandoned wells.   The  expense involved for any of this work is often
prohibitive for operators of stripper wells, these are wells that produce
less than ten barrels  of oil per day (BOPD).  Since brine disposal options
other than underground injection are limited, many stripper well operators
are forced to either shut-in production or dispose of their brine by illegal
underground injection  or surface dumping. Shut-in production may result  in
the loss of the mineral lease if there is a non-production clause in the
lease agreement while  illegal disposal may result in degraded surface water
and/or  USDW's.
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Another problem arises  should the AOR for the injection well extend on to
another operator's  lease where there are wells in need of corrective action.
In this case the operator  is  faced with two additional problems, the expense
of corrective action on another operator's lease and permission to access the
other lease in the  first place.   UIC regulations cannot force the second
operator to allow access to his lease for well workovers by the operator
seeking approval for the injection well.   If the corrective action in this
case cannot be performed,  then the UIC permit cannot be issued.

The objective of the UIC Program is to protect USDW's while having as minimal
an economic impact  on the  oil and gas industry as possible.  Stripper well
production in the conterminous United States during 1988 was 1.2 million BOPD
from 454,150 wells  (1).  This amounted to 24% of the lower 48 states's
onshore production.  As an critical energy source for this nations economy,
it is important to  maintain this production while at the same time preserving
water quality in the nations  USDW's.

As an alternative to expensive corrective action requirements for AOR wells,
this paper presents a cost-effective,  easy-to-use injectivity test and
monitoring plan for brine  disposal wells  operating by gravity flow which  can
be used to demonstrate  that no endangerment to USDW's exists when applying
for a UIC permit with EPA  Region IV (Atlanta,  Georgia).   The test is  also
less expensive and  easier  to  implement than multiple well pressure transient
tests, especially when  the porosity in the injection zone is very
heterogeneous which makes  selection of appropriate observation wells
difficult.

Iniectivity Test and Monitoring Plan Criteria

The gravity flow injectivity  test and monitoring plan have been incorporated
into UIC permits issued by EPA Region IV.   Injectivity tests have been
successfully completed  as  conditions to the permits and routine monitoring
operations have commenced. As a result,  stripper well operators who were
shut-in because of  expensive  corrective action requirements have been  able to
restart production  on their leases.

The gravity flow injectivity  test and monitoring plan are performed on the
injection well itself and  are applicable only to disposal wells that  operate
under gravity flow  conditions.  This precludes disposal wells and enhanced
recovery wells that operate with a positive pressure at the wellhead.  The
test was developed  where the  use of separate observation wells was
impractical, however, the  test could be used for any gravity flow injector
under the appropriate conditions.

The injection well  for  which  the test was developed injects into a dolomite
where the porosity  is very heterogeneous.   The effects from injection on  an
AOR well would be greatest if the AOR well were linked by a highly porous
zone directly to the injection well.   The injectivity test therefore  assumes
a worst case scenario in which the greatest possible effect on an AOR well
from injection would result in AOR well fluid levels equal to the operating
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fluid level in the  injection well.  If the operating  fluid  level within the
injection well can  be demonstrated and maintained at  a  safe level below the
lowermost USDW,  then corrective action on AOR wells can be  waived provided
long term operating fluid level monitoring is performed.

EPA Region IV has been using a depth of 100 feet below  the  lowermost USDW as
the critical depth  above which the operating fluid level  in the  injection
well should not  rise.  This is used as a safety factor  for  changes in fluid
levels  between monitoring events and also for variables such as  depth
variation  for stratigraphic horizons between AOR wells  and  differences in
static  fluid levels between AOR wells.  The gravity flow  injectivity test is
not applicable to  injection wells with a limited geologic section between the
lowermost  USDW and  the injection zone since this safety factor cannot be
incorporated  in  the test.  Also, the static fluid levels  in  these wells are
probably too  high  to begin with.

Prior to the  injectivity test, the static fluid level in the injection well
should be recorded.  If the static fluid level in the injection  well  is above
the highest  safe operating level, then the well obviously does not qualify
for using the  injectivity test.  To ensure the static level  is similar within
the AOR, the  static fluid level should be measured in at  least one other
well.  Static  fluid levels in the injection and AOR wells  should  be similar,
but if they are  not the critical depth mentioned above can be adjusted.   If
the wells to  be  measured have been active, they should be shut-in long enough
to obtain static conditions.

Operating conditions regulated by a UIC permit include  injection  pressure,
fluid volume,  and injection rate.  Injection pressure is  limited  to gravity
flow.  Fluid  volume is the number of barrels of brine to be  disposed  of
daily.  Injection rate determines the period in the day over which the fluid
volume is disposed.  The injection rate that works best is barrels per hour.
This rate ensures relatively even disposal over the course of a  day  and can
be accomplished by the operator staggering the timers on production well
pumps.

To perform the injectivity test, the operator must have a sufficient  volume
of water available to demonstrate that the volume of brine to be produced on
his lease can be safely reinjected.  This could be accomplished  by obtaining
an appropriate-sized 'Stock tank and filling it with either  fresh or  produced
water; or, it could be accomplished by using a water truck  for a supply at
the site.  Using produced water actually allows the operator to  perform the
test without disrupting production operations.

The gravity flow injectivity test uses the same well  for  both injection and
monitoring.   Brine is injected through tubing in the well casing. This
isolates the injectate from the tubing/casing annulus.  Fluid levels  are  then
recorded through the tubing/casing annulus.  Packers are  prohibited  in the
well so that there is an unrestricted fluid level in the  annulus.
Centralizers on the tubing help keep the tubing centered  in  the  casing but
must be placed below the operating fluid level in order not  to obstruct the
operation of the water level indicator.
                                      867

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A good fluid level recording device is a battery-powered water level
indicator.  The indicator  consists of a probe and cable which are attached to
a reel.  Fluid levels  are  recorded by hand-lowering the probe and cable
through the wellhead and down the tubing/casing annulus until the operating
fluid level is reached or  at least until a predetermined safe distance below
the lowermost USDW has been reached.   The isolated tubing/casing annulus
prevents a premature fluid level reading from the water level indicator.

The expense of the water level indicator is minimal ("$500 to $1200) when
compared to the expense of corrective action requirements.  The indicator ie
good  for depths up to  1000 feet which is the maximum cable length.  For cases
where deeper readings  are  needed, an echo meter will work well but the cost
 (~$10,000)  is more prohibitive for stripper well operators.  This device is
attached to the wellhead and employs an energy source consisting of
compressed  gas or a blackpowder charge.  The echo meter records the two-way
travel time of sonic waves reflecting off the fluid level's surface.  The
two-way travel time is then converted to depth.

A simple  schedule for  performing the injectivity test might consist of the
 following:  an hourly  fluid level reading for six to eight  hours during the
 first day,  a daily reading the remainder of the first week, and a weekly
 reading during the remainder of the month.   If the readings indicate that the
 operating  fluid  level  is at a safe distance below the lowermost USDW,  then
the  injection well is  considered to have successfully completed the
 injectivity test. Further fluid level recordings are then required under
 routine monitoring requirements incorporated in the UIC permit.   Routine
 monitoring  frequency  for operating fluid levels would normally be performed
 on a weekly or monthly basis.  This monitoring can be performed concurrently
 with other  monitoring  activities required in the UIC permit.

 Case Study

 The  injectivity  test  was developed for an injection well located in Mell
 Ridge Field, Green County, Kentucky (Figure 1).   The operator had shut-in
 production  on  his lease since early 1988 due to expensive corrective action
 requirements needed on AOR wells.  Especially problematic was the fact that
 an unplugged abandoned well in the AOR was within another operator's lease
 where access was  denied.

 Oil  production  from the Mell Ridge Ridge Field occurs from porosity zones
 within the  Cambrian Knox dolomite.  These porosity zones occur irregularly
 within the area  and  are difficult to predict.  From the operator's experience
 of production  history in the field, he could establish no interconnectability
 of the porosity  zones between the wells.  As a consequence, the use of a
 multiple well  pressure transient test with separate injection and observation
 wells was impractical and  expensive.  All wells would have to be equipped
 with expensive monitoring  equipment including the well the operator could not
 get access to.   Because of the irregular porosity, simply monitoring a few
 selected AOR wells and demonstrating no effect from injection would not prove
 that other AOR wells  were  not being adversely effected by the injection.
                                       868

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                                        Figure 1
00
8
                                    Mell Ridge Field
                                 Green County, Kentucky

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             Figure 2
   LEMUEL ROBERTSON #6-A
  GREEN COUNTY, KENTUCKY
 WATER LEVEL-
  INDICATOR
 7" CSG

5 1/2" CSG

6 1/4" OH
    2 3/8" TBG
FLOW LINE
                        USDW
                      OPERATING FL 760'
                      STATIC FLU 00'
                     INJECTION ZONE
              TD 1833'
                870

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The injection  well for this study is the Lemuel Robertson 16-A well
(Figure  2).  This well has a total depth of  1833  feet  from surface with 5 1/2
inch casing  set at 410 feet from surface.  Internal  casing diameter is
approximately  5 inches.  There is 1250 feet  of 2  3/8 inch tubing with 2 7/8
inch couplings within the wellbore.  This leaves  an  annular space between the
casing and the tubing couplings of 1 1/16 inches.  The probe diameter of the
water level  indicator is 3/8 inch so there was limited space to lower the
probe down the annulus.  The open hole below the  5 1/2 inch casing is 6 1/4
inches in diameter.  This leaves a tubing/wellbore annulus of 1 11/16 inches.
The test had originally been devised for the 2 3/8 inch tubing  inside  of 7
inch casing which had been set at 406 feet below surface, but leaks  detected
in the 7 inch casing necessitated installation of the 5 1/2  inch  casing.   The
injectivity test was attempted even with the limited casing/tubing annulus
because the operator was faced with the imminent loss of his lease due to
non-production for over a two year period.

The lowermost USDW in the injection well was determined to be the base of the
MiBeissippian Salem-Warsaw limestone (undifferentiated) which is  at  a  depth
of 125 feet from surface.  The highest allowable operating fluid  level within
the injection well was set 100 feet below the USDW at a depth of  225 feet
from surface.  The static fluid level in the Lemuel Robertson #6-A well  was
measured by bailer at 1100 feet below surface (-160 feet, 1927  North American
datum). The static fluid level measured in an AOR well, Lemuel  Robertson  #8,
was 1060 feet below surface  (-185 feet, 1927 North American datum).

The operator used a 210 barrel tank as his water supply for the injectivity
test.  The operator was allowed to use produced brine to fill the stock  tank,
resuming production just prior to the test.  Initial production from
recommencing operations on his lease was 15 BOPD from four wells.  To
maintain a constant rate and supply of water, the operator staggered pump
timers on the four production wells.

The injection rate for the injectivity test varied between 9 and  10 barrels
of brine per hour.  During the first week of the test, the operating fluid
level as measured in the casing/tubing annulus by a water level indicator was
between 760 and 769 feet below surface.  This was over 500 feet below  the
predetermined safe operating level of 225 feet below surface.   As a
comparison to the operating fluid level, a water level reading  was taken
within the tubing immediately after stopping injection and disconnecting  the
flow line.  This reading showed that the water level had already  fallen to
911 feet below surface.  While not critical in this case, this  illustrates
why it is important to measure the operating fluid level.

At the end of the first week of the injectivity test, the cable of the water
level indicator became stuck in the limited casing/tubing annulus and
separated.  The operator continued injection and at the end of  the second
week pulled tubing in an attempt to retrieve the indicator.  The  water level
                                     871

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indicator was retrieved  from the end of the tubing and the water line on the
tubing indicated the operating  fluid level had fallen to about 950 feet below
surface.  The operator completed the test with a back-up 300 foot long water
level indicator.  This did  not  allow the actual operating fluid level to be
recorded but did ensure  that it did not rise above 225 feet below surface for
the remainder of the test.

Smaller tubing possibly  can eliminate the problem of a restricted
casing/tubing annulus if disposal volumes can be maintained.   Another
possible alternative would  be to inject through the casing/tubing annulus and
monitor through the tubing.   This method may be attempted with a couple wells
currently being reviewed for UIC permits by EPA Region IV.   However,  EPA
Region IV requires new brine disposal wells to inject through tubing  during
routine operations.  This presents a problem after the test in that routine
operating fluid level monitoring is required on at least  a  monthly basis.
For each monitoring event,  disposal operations would need to  be shut  down to
switch the  flow line from the tubing to the casing/tubing annulus and then
the operating fluid level would need to be re-established.

Summary

The gravity flow injectivity test and monitoring plan allows  for injection
through tubing and monitoring through the casing/tubing annulus of the same
well.  The  test is only  applicable to injection wells that  operate by gravity
flow.

The injectivity test assumes a  worst case scenario in which the fluid levels
in AOR wells are assumed to be  as high as the operating fluid level in the
injection well.  If the  operating fluid level in the injection well is
determined  to be at a safe  level below the lowermost USDW then brine
injection is allowable even if  AOR wells are not properly constructed or
plugged and abandoned.   The test allows operators to avoid  expensive
corrective  action requirements  on AOR wells while also protecting USDW's.  As
a consequence, some operators of stripper wells who where shut-in because of
the expense of corrective action requirements can now economically produce
oil and dispose of their brine  in an environmentally safe manner.

The gravity flow injectivity test is less expensive and complicated than a
multiple well pressure transient test with separate injection and observation
wells.  The gravity flow test also allows for routine production operations
to continue during the test.

While this  test was developed for a carbonate reservoir with  unpredictable
porosity zones, the test could  also work for clastic reservoirs especially if
an extra well was not available for monitoring purposes.  Also, while this
test  was developed for EPA  permits to protect USDW's, it  could be used
anywhere there  is stripper  well production with gravity flow  disposal.

Reference

1.  L.F. Ivanhoe, Liquid Fuels  Fill Vital Part of U.S.  Economy,
    Oil & Gas Journal. April 23, 1990,  106-109.


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SOLIDIFICATION OF RESIDUAL WASTE PITS AS AN ALTERNATE  DISPOSAL PRACTICE IN
PENNSYLVANIA
S. J.  Grimme,   J.  E. Erb
Bureau of Oil  and Gas Management
Department of  Environmental Resources
Harrisburg, Pennsylvania
Introduction

Regulations  adopted in 1989  by the Pennsylvania Department   of  Environmental
Resources  (the  Department)   require  that  oil and  gas  operators    contain
pollutional  substances and  wastes from their activities   in  tanks or  in pits
constructed  according to  standards which protect  ground  water.  If the pits
are  also to be used  for waste disposal,  additional ground   water protection
standards  apply.  An operator wishing to  apply an alternate  practice  for the
disposal  of  wastes  may request  approval  from  the Department  to   use the
practice.  Several  operators have explored  solidification of pit contents as
an  alternate waste  disposal practice.  This  paper summarizes   some of  those
efforts.
 Summary of Requirements

 Pennsylvania  regulations  establishing  environmental  protection   performance
 standards  for oil and gas well operations are  found at 25  Pa.  Code §§  78.51  -
 78.63.  These  regulations contain a general  provision that  the operator  must
 control  and dispose of fluids,  residual waste and  drill  cuttings,  including
 drilling  fluids, drilling  muds, stimulation   fluids,  well  servicing  fluids,
 oil,  and production fluids, in a manner  that  prevents pollution  of  ground or
 surface  waters.  The control and disposal procedures are to  be contained  in  a
 plan,  developed and implemented  by the operator, which is  subject  to review
 and  approval by the state regulatory agency,   the Department of Environmental
 Resources.

 Pollutional substances and wastes from well drilling, alteration or completion
 are  to  be contained   -in tanks  or  pits.  Such   tanks   or pits must  meet
 requirements  relating to capacity, freeboard,  and structural stability.   Pits
 must  also meet  standards  for impermeability,   construction,  and  depth to
 groundwater.  Site  reclamation, including  tank removal or pit closure, is to
 occur  within nine months of completion of drilling.  The free  liquid fraction
                                      873

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is to be removed and disposed in an approved manner.   The solid residual waste
remaining  is to be buried on site or applied  to  the  land surface according-to
prescribed standards.

Pits   used  for  the  disposal  of  residual   waste  must  satisfy  numerous
restrictions  designed  for  the  protection   of   ground  water.   Only  wastes
generated  at  the well site  may be disposed   in the  pit.  The  well  must be
properly  permitted  and bonded.  The  pit must  be at least 200   feet from an
existing  building, at least  100 feet from a  stream   or wetland, and at least
200  feet from  a water supply.  The  bottom   of  the   pit must be  at least 20
inches  above  the  seasonal   high  ground  water table.   The   pit must  be
structurally  sound and impermeable.  The  pit must be  lined with a synthetic
flexible  liner  that  is at least  30 mils  thick.   The  liner material  must
satisfy the compatibility of EPA Method  9090 (1).  The pit must be constructed
and graded so that the liner will not be torn  or  punctured during use.   If the
pit  bottom or sides consist of any material   that may cause the  liner  to  fail
and  leak, a six-inch subbase material  must be installed over the pit  area to
protect  the liner.  Prior to use, the liner must be  inspected for damage,  and
repaired  if  necessary.  During  closure,  the free   liquid fraction  must be
removed  and the liner folded over or an  additional  liner added  to completely
cover  the waste.  Puncturing or perforating the  liner is prohibited.   The  pit
must  be backfilled to at  least 18 inches over the   top of the liner,  and  the
surface area must be graded to prevent ponding and be revegetated.

The  regulations  further specify  reporting requirements  and limitations to
wastes  which may be disposed in this  manner.  The waste limitations preclude
the disposal of hazardous wastes at well sites.

Operators may request approval to use solidifiers or  other alternate practices
for residual waste disposal from the Department.   The request must demonstrate
that  the practice provides equivalent   or superior ground water  protection to
the standards contained in the regulations.
 Solidification  Proposals

 Since   the  regulations went  into  effect,  gas well  operators  have  expressed  the
 most   concern and   interest  in  obtaining   an approved  method  for  solidifying
 wastes.   The  typical   gas   well   being  drilled  in  the  areas   requesting
 solidification   of  pit wastes are approximately  5000 feet  deep and  are  drilled
 using   air  rotary drilling  systems.   Some  of  these systems  require the use of
 drilling  muds and other additives to bring the well to completion.

 Concentrations  of parameters normally seen in  the  wastes from  these wells were
 high   enough  for the Department  to  be concerned with  ground  water protection
 when   writing   the  new regulations.   Thus,    the standards   imposed   in  the
 regulations were meant to address those concerns.
                                      874

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Several   operators have requested approval  from  the  Department to use various
products   or materials for  pit solidification or stabilization.   The  reasons
for these requests varied.

After   removal  of the  free liquid fraction  of pit wastes,   the  remaining pit
contents   usually still contain approximately 30Z water.   Operators found that
backfilling  these  residual waste  pits often  did not demonstrate  stability
compatible with adjacent  land areas.  This  would result  in complaints from
surface  owners, particularly  those engaged  in  farming.   Soft  spots in farm
fields were not acceptable.

In  some  gas  fields,  operators  were not able  to land apply residual  wastes
because  of the high salt  content.  The use of pits   then became  the disposal
method of choice.  But due to the unacceptability of  soft  spots in fields,  the
availability  of using pits for disposal at these  locations became  limited.

Also,  operators were concerned with the 30 mil liner  thickness  requirement  for
disposal   pits.  They felt that 30 mil liners would cause  operational problems
because  of the liner  weight and the additional   equipment   and manpower that
would  be necessary  to properly install  the liners.  They   also  believed  the
liners were too expensive for routine operations  and  were  not justified  in  all
instances.

After  reviewing these items, operators began to  look toward  solidification as
a   possible  answer  to their  concerns.  The   addition   of  a  solidifier   or
stabilizer  would  remedy the soft  spots in fields.   They also   felt that if
proper   solidification could be accomplished,  pollutional constituents  in  the
residual  waste would be bound in the solidifier  matrix, and  equivalent  ground
water  protection would be afforded.  This could  lead to a Department approval
of  the use of an alternate liner system.

Thus,  requests  for solidification   or stabilization  of pit contents were
submitted  to the Department for approval.  Pit solidifications of wastes from
oil and gas  exploration  and development  had been   completed previously   in
Pennsylvania and in other states.  However, an apparent lack  of available data
existed  to evaluate the effectiveness  of various solidifiers  in stabilizing
the waste, the  ratio of waste material to solidifier  necessary, the methods by
which  adequate  mixing  could be  accomplished,   and the   characteristics   of
leachate  expected  from  the solidified  mixture.  Literature    searches  and
contacts  with  other  states  in the  region were unfruitful.  The  need to
generate data through demonstration projects was  evident.
 Demonstration Projects

 In  developing a solidification process proposal, operators  considered  systems
 that  would provide  ground water protection,  achieve  land   stabilization,  be
 workable  at the well site, be able to overcome the  operational  constraints  of
                                     875

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handling  a 30 mil   liner,  and be cost  effective.  Originally,   two  proposals
were explored.

The  first proposal  involved  using a solidifier and  pit content mixture  that
would  be binding or impermeable  enough to prevent  the leaching of  potential
pollutants  from the solidified mass.  This  mixture would also be hard enough
to  provide pit  stability.   In this  case, to assure  complete  mixing of the
wastes  with  the solidifier,  the liner  would be destroyed  during the mixing
activity.  Since  solidification  would prevent the leaching  of pollutants to
the  ground water system,   a thinner liner could be  used for protection up to
the time  of solidification.

The  second proposal  involved maintaining  the integrity of  the pit liner to
provide  ground water protection, while utilizing the solidification process to
provide  physical  stability to the pit contents.

Following discussions  regarding which  system was best suited  to accomplish
the  goals of the  industry and the Department,  several sites were proposed as
demonstration projects.

Proposals for approvals  using the first concept described above were submitted
by  four operators.   The use  of solidification mixtures  from three servicing
companies were   included in the  proposals.   One  servicing company  had been
performing   bench  tests  on pit contents  and solidifier mixes to determine the
proper amounts of  ingredients for the solidifiers and the appropriate waste to
 solidifier   ratio  to accomplish the goal of providing ground water protection.
After   consideration of  this  bench testing,  original  approval was granted by
 the  Department    to utilize  the  solidification   process  with  a waste  to
 solidifier  ratio  of  10:1 for the demonstration projects.

The  approvals for  the use of the solidification  process were granted subject
 to several  conditions.  One of the major conditions was that each operator was
 required  to  select  a site that would be  suitable to be used for ground water
monitoring.   On  this  site,  the  ground  water monitoring   system  would be
 installed  prior   to  the start  of drilling  the  oil or gas  well to  obtain
 predrilling   samples of  the existing ground water quality.  Then, when the pit
was   ready to be  closed, samples  of the solid fraction  of the residual waste
 after   mixing with the solidification  mixture would  be tested and the ground
water   would  be tested  for effects from  any leaching from  the pits.  Ground
water  monitoring  would continue for the months following solidification.

 For   the solid fraction  mixture,  the parameters  evaluated  would be:  by EP
 toxicity  test (2)  - arsenic, barium, cadmium, chromium  (total), and lead; and
 by  ASTM A leachate  test (3) - chloride,  sodium, calcium, magnesium, bromide,
 MBAS,  sulfates,  and strontium.  For the ground water, the following parameters
 would   be evaluated:  arsenic,  bromide,  barium, calcium,  chloride, chromium
 (total),  copper,   magnesium.  MBAS,  iron (total),  oil  & grease,  lead, pH,
 nickel, sodium,  strontium,  sulfates, specific conductance, and total dissolved
 solids.
                                      876

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Other conditions  of  approval included providing at least  48-hour notice to the
Department  prior to  the  date  of  the pit  solidification,     providing  a
description of  the consistency of the mixed pit material  after  24 and 48 hours
setting   time,  using a minimum  10 mil thick liner,  and  submitting a standard
report   to the  Department  within  30 days of  pit closure   or with  the well
completion report.

One  trade association in  Pennsylvania has recently  proposed  a demonstration
project   involving  a  system that would  be utilized to provide  pit stability
within   a 10  mil  liner.  This  proposal  intends to protect   the liner system,
rather   than  destroy it during mixing,  while using a solidifier material that
would provide extensive savings to the industry.
Results

Immediately  following the  effective date of the Department's   regulations,  a
major  demand was put forth by the industry  to utilize pit  solidification for
disposal  of residual waste  in pits.  Several problems  became  evident  rather
quickly.

As  the first  sites were  being solidified,  operators  considered   and tried
different  methods of adding the solidifier  mix to the pits and of mixing the
solidifier  with the pit contents.  The  initial method used to  add the  mix to
the  pits was for a worker to hold the  discharge hose and manually direct the
mix  to different  areas of the  pit.  This method  was extremely dusty (thus
considered  hazardous  to the health  of the worker)  and was not adequate in
achieving a uniform distribution of the solidifier over the  pit.

Following  the addition of the mix, a trackhoe operator with a toothed backhoe
bucket would incorporate the mix into the pit.  This method  of mixing was time
consuming  because the operator had to load the bucket at the edges of the pit
where  the solidifier  was placed and move  this drier material   to the  wetter
portions of the pit to achieve complete mixing.

Pit  construction  methods also  caused some problems.  Some  pits  had  nearly
vertical,  jagged sideslopes or did not have sufficient subbase  to protect the
liner  prior to solidification.  Some  pits  were constructed  deep and  narrow
which  did not allow adequate room for  a trackhoe arm to mix properly.   Other
pits  were constructed in  such a way that the middle  of the pit could  not be
reached for mixing.

Also,  the setup time of the  solidified pits varied  considerably.   Some pits
took  2 or more days to harden.  Other pits were able to be  walked on within 6
to  8 hours of the completion of the solidification  process.  The reasons for
these  extremes  appeared  to be the result  of several  items including:  the
inability  to  accurately  estimate  pit  volumes  in order  to  calculate  the


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required  waste to mix ratio;  the  amount of free liquid remaining in the waste
following  decantation  of   the  liquid  fraction;   the type  of well  and the
resulting   drilling  system  used;   and the over-ordering   of solidification
material by some operators  to  be certain of hardening.

Several  of these problems  were easily  resolved through the cooperation of the
operators  and their willingness to  complete the process in the proper fashion
and  to make the  system work.  Within   the period   of  a few weeks,   operators
devised  a mixing  device constructed  of metal  tubing resembling  a "slotted
spatula"  which could be attached  to the trackhoe   bucket.  This device could
then  be moved  back and  forth through  the  pit contents  to assist  in more
complete  mixing.  At  about this  same  time,  operators decided  to  attach the
discharge  hose from the solidifier  truck  onto this mixing device which would
allow the mix material to be added anywhere within  the  reach of the  trackhoe.

Pit  construction  methods  also  were changed to protect the liner   by making
the  pit sideslopes  flatter and providing  subbase material,  and to make the
pits  easily  accessible  for  the  trackhoe to  operate  properly and  provide
complete mixing.

A  solution to the problem  of  determining  the proper time for closure was not
as  easily found.  Establishment   of performance  standards appeared  to be a
solution  to obtain  a required hardness  or other  measure  to demonstrate the
time  for closure.  But  since environmental  protection was  one of the  major
goals   of  the demonstration  projects,   a  decision  on what  to include as
performance  standards could  not  be made until results  from the ground  water
monitoring could be evaluated.

Regarding  the testing being performed,  EP toxicity testing was required  to be
performed  on the solidifiers  from each  servicing  company.  Thus far,  none of
the  solidifier material samples have been found to exhibit characteristics of
EP  toxicity.  The highest  value -reported  for any  of the tested parameters in
the  solidifiers was for lead.  The   lead concentration  of one solidifier was
reported  at 13.22  of the  maximum  allowable  concentration.  The  only  other
parameter  reported  at  a  value greater  than  10Z of  the  maximum   allowable
concentration  was for total  chromium.   Again, one solidifier  had  a chromium
concentration  reported at   12Z of the  maximum.  The majority of the reported
values  were 12 or less of the  maximum allowable concentration.

Once  an  operator  received  approval   from  the Department   to utilize  the
solidifier  from a particular  servicing  company, the operator had thirty days
to   submit EP toxicity and  ASTM A  leachate  test results of the combined waste
and  solidifier  mixture  to  the  Department.  The    EP toxicity  testing  was
requested  to obtain information on  whether  any reactions or compounds formed
from  the mixing of the waste  and  the solidifier may cause environmental harm
or  degradation.  The  results of  the EP  toxicity  testing  indicated that the
solidifier  and  waste  combinations did not  exhibit  characteristics   of EP
toxicity.  Only  one parameter from one pit had a  reported  value higher than
102  of the maximum allowable  concentration.  Total chromium was reported at
                                      878

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12.9Z  of the maximum   in this  instance.  A few  of the values   were reported
between 1Z and 10Z of  the maximum, but most were 1Z or less.

The  ASTM  A leachate   testing  was  requested  to obtain   concentrations   of
parameters  in the residual  waste that  would normally be  expected to leach.
These  parameters  would serve  as indicators  of potential   pollution  to the
ground  water system if they would begin  to appear in elevated  concentrations
in the monitoring  samples.

At  the four sites selected for ground water monitoring, monitoring  wells were
drilled down to  the  interception with the ground water table.  At three of the
four  sites,  two  monitoring  wells  were  drilled.  All  wells   were  placed
downgradient,  5  to 10 feet  from the  edge of the  pit, at  a location  where
Department  hydrogeologists   believed  effects  from  any  leaching  would be
observed.  On  the   fourth  site only  one downgradient   monitoring  well was
drilled.  Following  the completion of the monitoring wells, samples  were taken
of  the ground water for background information.  Samples were also  taken from
the   wells on  the days that  solidification  took  place.  Following  the pit
solidifications,  samples  were  taken from the  wells on a monthly   basis for
three months.

Because  the  study  is ongoing, only a limited number of monitoring samples have
been   taken   to  date.  Results   obtained  at  one  of the  sites   indicated
increasingly  elevated results  in arsenic, iron, copper  and barium,  although
visible  increases  in the indicator parameters were not observed.   Samples from
one   other  site  indicated a slight increase in the results of iron.   The other
two  sites have  not  indicate elevated concentrations  of any  of  the  parameters
tested.
 Conclusion

 The  purpose of this paper is to provide  an introduction to the demonstration
 projects  performed  in Pennsylvania utilizing  solidification  as  a method  of
 protecting  the ground water.  Insufficient  data exists at this time  from the
 monitoring wells to make a determination of whether the systems described  have
 accomplished the goals.  Samples will continue to be taken at these monitoring
 locations  to observe if more time is required for any leached constituents  to
 reach  the ground water tables and if any of the elevated results in parameter
 concentrations can be attributed to season variations.

 Tabulated results of all of the sampling completed will be made available  upon
 request.  A  report will be given at a later date regarding the determinations
 of the successes or failures of the projects.

 As  pit solidifications continue, further improvement on the individual  phases
 of  the process should be pursued, for  example, if a better mixing method can
 be developed or if a lower waste to solidifier ratio is necessary.
                                     879

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One  other concern that has surfaced in recent months  is whether operators  can
satisfactorily  complete the solidification  process during  the winter months.
Temperatures  in  Pennsylvania   typically  can be  at or  below  zero  degrees
Fahrenheit  in the  winter.  Freezing temperatures  cause  problems   in dealing
with  the  free liquid  portion  of the  wastes and  affect   the hardening  or
stiffening  properties  of solidifiers.  Some  servicing companies   have begun
work to create a solidifier mixture that will alleviate this  problem.
                                      880

-------
References

1.  U.S.   Environmental Protection Agency, Method 9090: Compatability Test for
    Wastes   and  Membrane  Liners, Test  Methods  for Evaluating  Solid  Waste
    (SW-846),   Volume  1C: Laboratory  Manual Physical/Chemical   Methods, 3rd
    Edition, Revised December, 1987, 9090-1 to 9090-16.

2.  U.S.   Environmental Protection  Agency, Method 1310:  Extraction Procedure
    (EP)   Toxicity Test Method and Structural Integrity Test, Test Methods for
    Evaluating  Solid Waste (SW-846),  Volume 1C: Laboratory  Manual Physical/
    Chemical Methods, 3rd Edition, Revised December, 1987, 1310-1 to 1310-18.

3.  Proposed  Methods  for Leaching  of Waste Materials,  Annual  Book of ASTM
    Standards. Part 31, 1979, 1258-1261.
                                     881

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STATISTICAL  ASSESSMENT OF FIELD SAMPLING  PROJECT DATA ON PETROLEUM EXPLORATION
AND PRODUCTION WASTES

Charles  Winklehaus, Ph.D., P.E.; George L.  Clark;  and Robin Pomerantz, MS
SRA Technologies, Inc.
Alexandria,  Virginia, U.S.A.

Introduction

As part  of the study mandated by Section  8002(m)  of  the  1980 Amendments to the
Resource Conservation and Recovery Act, the U.S. Environmental Protection Agency
(EPA) sampled the wastewaters of  a  diverse group of  Petroleum Exploration and
Production facilities across the U.S. EPA undertook  the  Field Sampling Project
to develop statistically representative data that would  describe  the  range and
concentrations of  waste  constituents from  drilling  and production operations
nationwide [l].   SRA Technologies, Inc. was tasked by EPA's Office of Solid Waste
(OSW) only with evaluating the statistical  validity  of the  resulting  database;
while, evaluation of the  quality assurance/quality control aspects of  the  field
sampling and laboratory analysis were  assigned to others by EPA.   Thus,  SRA's
study had three main objectives: (1) to independently assess, from  a statistical
standpoint, the strengths and limitations of the data  then available from the EPA
Field Sampling Project;  (2) to investigate issues such  as  weighting and  the
treatment of  censored data;  and (3)  to make  recommendations about additional
sampling—if required—to augment the current  Field  Sampling Project  database.

There were six major  conclusions reached  in this  statistical assessment,  among
them, the  following  standout:   the  EPA  study  is  consistent with the  similar
American Petroleum Institute (API)  study; more sampling would be advisable to
improve representativeness;  and many of the inorganic substances had waste liquid
concentrations that exceeded drinking water  standards.  The study noted that  all
of the production and drilling  sites had at  least one key analyte  that  exceeded
water quality standards.  In addition, for many of the key analytes, substantial
proportions of the sites exceeded  10 times  the water quality standards and in
some instances sites  exceeded the standards by 1,000  times.

Project Background

The  facilities sampled in the  Field Sampling  Project  included  21 production
sites, 22 drilling sites,  5 central pits, and 2 centralized treatment facilities;
these units  are listed in Table  1, which identifies the site type of the facility
and  lists the geographic basins in which  they  are located.   Table  1 also  lists
similar information from a number of Alaskan  sites  units that were added at a
later date to the Field Sampling Project database for study purposes. The states
were  clustered  in   eleven  zones   based  on  physiographic  similarity   and
statistically "stratified" samples were taken  of production  endpoint  liquids,
drilling pit liquids,  and drilling pit solids.   Most such samples were taken from
randomly selected sites,  but some—and the  few samples taken from central pits
and  centralized  treatment facilities—were taken from  non-randomly   selected
sites.  Samples of drilling pit solids were chemically analyzed both directly and
by the Toxicity Characteristic Leachate Procedure (TCLP) test. The  locations of


                                    883

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TABLE 1.
List of Basins and Sites Sampled  (Lower  48  States)  a
Site
1
2
3
4
5
6

7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
Type b
D,P
D,P,CT
D,P,CP






CP c

P.CP


D,P


D

D,CP
2D.5P



D,P


Basin
Anardrko Basin
Appalachian Basin
Arkoia Basin
Black Warrior Basin
Central Nebraska Basin
Central Oklahoma
Platform
Cincinnati Dome
Coast Range Basin
Colorado North Basin
Crazy Mountain Basin
Dalhart Basin
Delaware Basin
Denver Basin
Dodge City Embayment
East Texas Salt Basin
Eocene Basin
Forrest City Basin
Great Basin
Green River Basin
Gulf Coast Basin
Hardeman Hollis Basin
Hanna Basin
Hugoton Embayment
Illinois Basin
La ramie Basin
Las Vegas Basin
Site
27
28
29
30
31

32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
Type


2D.P



D,P
P

D,P

D,P
P,CP



•



D,P
D
D
D,P
D


Basin
Llano Basin
Marfa Basin
Michigan Basin
Mississippi Basin
Mississippi Salt Dome
Basin
Paradox Basin
Permian Basin
Piceance Basin
Powder River Basin
Raton Basin
San Joaquin Basin
San Juan Basin
San Luis Basin
Snake River Downwrap
South Alberta Basin
South Florida Embayment
South Park Basin
South Texas Salt
Tucumcari Basin
Tyler Basin
Unita Basin
Ventura Basin
Washakie Basin
Williston Basin
Wind River Basin
Wyoming Big Horn Basin
 TABLE  1.        List  of  Basins and Sites Sampled  (Alaska)
1
2
3
4

D.P.CT


Bethel Basin
Cook Inlet Basin
Copper River Basin
Galna Basin
5
6
7


2D,P


Royukuk Basin
North Slope Basin
Yukon Kandik Basin

 Key for  Site  Types:   D-Drilling, P=Production, CP=Central Pit, CT-Central Treatment

 a.   U.S.  EPA,  April  30,  1987  [2]
 b.   U.S.  EPA,  January 31,  1987  [l]
 c.   Landes,  1970,  pp.  380.  385  [3]
                                                884

-------
the basins and units sampled  and the  zones  into which they have been placed for
the purposes  of  this  study are also shown in Figure  1.
Statistical  Analyses

The evaluation  of statistical  validity addressed:  sampling plan design and  data
collection;  representativeness of the  samples  vis-a-vis the petroleum bearing
basins;  weighting of data to reflect wastewater flows from the  various basins;
and precision of  the resulting data.   A comparison was also made with  data  from
a parallel survey and study by the API.
The evaluation focused on a group of 11 inorganic and 5 organic "key" pollutants
that were selected based primarily on (1) expected presence in a large proportion
of the samples, (2) inherent toxicity. and (3) significantly high concentrations.
The principal selection procedure used is  one  developed by EPA/OSW for use at
"Superfund" sites [4].


The substances selected as key pollutants using the EPA/OSW procedure (and the
number of times they were analyzed for and detected) were:
Inorganics
Barium
Fluoride
Chromium
Nickel

120/115
81/80
120/68
120/60

Cadmium
Lead
Arsenic


120/52
120/46
120/36


Organics
Toluene
Benzene
2-Butanone ( 'MEK')
Phenol
Phenanthrene
112/61
112/44
112/31
113/25
113/21
 Four additional substances were  also included  as key pollutants based mainly on
 their known potential to damage vegetation.  These substances were antimony,
 boron, chloride and sodium.
 Substances passed over as key pollutants using  the EPA/OSW procedure (and the
 number of times they were analyzed for and detected) were:
Organics
bis-(2-Ethylhexyl) Phthalate
Naphthalene
Ethylbenzene
1 , 1 ,2-Trichloroethane
113/59
113/52
112/39
112/6
Bromodichlorome thane
Pentachlorophenol
Anthracene
112/4
108/3
113/0
                                    885

-------
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Varying proportions of the data sets for  the  different analytes/pollutants are
listed  as "below the  limit of  detection".   These  are also  termed  "censored"
values.   The  detection  limit  is a  function  of  both  the  sensitivity  of the
laboratory analytical  technique and of the  presence of interfering substances in
the sample matrix.   It is  important  to  recognize that  the  notation  "below the
limit of  detection"  is an indication  that the  field sampling and  laboratory
analysis  were inconclusive; it could indicate that the analyte is present at some
concentration  below  the  detection  limit,   or   that   the  analyte  is  absent
altogether.    When  the  detection limits  are  lower  than potential  regulatory
limits,   interpreting   the  results  is  relatively  simple.    However,  if  the
proportion of censored  values  is high, the manner  in which  censored  data are
treated can have a  significant impact on  the study results.  Three  difficult
issues related to detection limits were addressed;  these were:

(1)  Because  the detection limits were close to potential regulatory limits,  the
choice of how to impute  data  for censored values (e.g., treating the  censored
values as zero,  half the detection limit,  equal to the detection  limit, or  as a
statistically-imputed  value)   can affect  whether  the  estimates of analyte
concentration exceed potential  regulatory  limits.


 (2)   Censoring  was  particularly  frequent with  organic compounds.    From a
statistical perspective, a high proportion of censored  data makes it  difficult
to reliably  extrapolate  below  the  limit of  detection based  on  the  small
proportion of observed values.


 (3)   For many analytes  of  interest  in  this  study,  detection  limits  were
determined by sample dilution and other procedural artifacts that were  inherently
different for each run and were determined  individually as part of  the analytical
procedure. As a consequence, the range of detection limits often overlapped  the
range of detected values.  This makes interpretation  difficult because samples
with higher detection limits have a greater latitude  for containing undetected
contaminants. These problems were most frequently encountered in sampling  solids
directly (both for  inorganics and organics) and in measuring  organic analytes in
liquids.


To assess the effect of  censored data  on  estimates  of analyte concentrations,
this study compared means  in data where  censored observations were treated as
zero, as half  the  detection limit, and as equal to  the detection  limit.   In
general, the  influence of censored data was modest when less than  half  the  data
were missing (e.g., estimates of  the mean were generally less than 10 percent
higher when censored values were treated as half the  detection limit rather  than
zero). However, when more than half of the data were  censored—as  was  frequently
the  case with  organic  analytes—the  estimates  of  the  mean   could  change
substantially (e.g., 100 percent or more),  depending on the method used to treat
censored values.
                                     887

-------
This study explored two methods to statistically impute values for censored data,
based on  the  distribution of observed  data.   The first  method was termed the
"linearized  extrapolation  method"  and was  similar  to  the   "log-probability
regression" method that was strongly recommended by Gilliom and Helsel  [5] after
thoroughly exploring several alternative techniques  for handling censored water
quality data.  During preliminary analyses, the statistical-distributions of the
data on selected analytes were examined both by plotting various  transformations
of  the  data  and by  computing their  skewness  coefficients.    These  analyses
demonstrated that, of the common distributions, most of the data sets were best
fitted by the lognormal distribution. The detected values were assumed  to be the
upper end of the data set and the non-detected values the  lower  end of the data
set.  Using a computer program, the detected values were figuratively plotted on
a  logarithmic  ordinate   versus  probability  abscissa.    Use  of these  scales
linearized the lognormal data, and a  straight  line was fitted by  "least  squares"
to the transformed detected values.  This straight line was then extrapolated to
allow a direct  estimate  of  the logarithmic mean, standard deviation,  and  other
summary parameters, as well as imputed values for the non-detected values.   The
values of the  summary parameters  and of the imputed values for the  non-detects
appeared  to be reasonable  representations in all cases  of  the (hypothetical)
uncensored data sets with a uniform detection limit,  including cases with greater
than 50 percent censored  values.   On the other hand, where the detection limits
varied for  each data  point  in a  data set—as they did for many of  the  organic
chemicals—the  results were more  ambiguous.


Thus, the linearized extrapolation method was fairly straightforward when applied
to  inorganic  chemicals,  which generally have a detection  limit  that is either
constant  or has only two  or three set values caused by different dilutions used
during  sample preparation  for laboratory  analysis.   In contrast,  the method
worked  poorly with some  of the  materials, particularly  the organic analytes,
where the range of detected and estimated non-detected values overlapped either
partially or completely  with the range of detection limit  values.   In this
situation,  a  non-detect  data  point may  result from  an unusually high detection
limit for the sample, masking a relatively  high value for the sample.   It could
also  result  from  a  low  value  for  the   sample,   but   there  is  no   way  of
distinguishing  these  two cases.   That is,   overlapping ranges  for the  detected
values  and the  detection  limits  confound the  estimation of  values  for the
non-detects  and makes the values  difficult or impossible to estimate.


As  an extension of  the first  method, this  study also developed a  set  of
statistical procedures to impute  values for censored data in a weighted data set.
This  second method  entailed  fitting—and  assessing the  fit of—a lognormal
distribution to the distribution  of uncensored values above the detection limit.
Based  on  the parameters  defined  by  this  best-fitting distribution, data were
imputed  by equally sprinkling values below  the  detection limit for  censored
observations  along the  cumulative density function  defined by  the lognormal
parameters.
                                     888

-------
When different detection limits were encountered for different observations, this
imputation procedure  was repeated for  each detection limit.  This was  done  by
first  imputing  values  for  the  higher detection  limit  value  (based  on  all
uncensored observations  above  that level),  and subsequently imputing  values for
censored data below the lower detection  limits, using all uncensored observations
above that level as a basis for imputation.  Despite a number of advantages, two
limitations of this second method of statistical imputation should be  mentioned.
A few censored samples had detection  limits that were substantially higher than
the observed  values in the data  set.  The  values of  those  data  points could not
be reliably  estimated by this method.  Hence, no effort was made  to  impute the
value  for a  censored  observation where the detection  limit was  higher than the
mean of the observed values;  in those  cases, the censored observation was  treated
as missing data.   A second  limitation was  that  the  statistical  imputation
procedures were  not applied  when there  were too few uncensored  values to ensure
an adequate  estimate  of the lognormal parameters.  As a result, the  method was
not applied to  analytes where more  than  about  half  of  the  observations   were
censored. When  there  were sufficient observed data for this latter statistical
imputation method to  be used, the estimates of means were a little higher  than
estimates in  which censored  data were treated  as one-half  the detection limit.
 Presentation of Results

 The data  from the  EPA Field Sampling  Project were  reviewed as  to sampling
 adequacy,  data quality,  and priorities for  further study.   These  issues are
 discussed  in  detail for production  and drilling sites.   The issues  are not
 discussed  in  detail  for  central  pit  and  centralized  treatment  facilities,
 however, because  the small number of such sites, and  their non-random selection,
 did not permit detailed statistical analysis.  Issues considered in the review
 of sampling adequacy included sampling precision and the adequacy of weights used
 to generate  national estimates.  Aspects of sampling precision considered were:
 (1) stratification and site  allocation,  (2) number of samples  analyzed, and (3)
 variability of sample  results.


 A detailed assessment  of the  QA/QC aspects of the  laboratory methods used was
 made by others.  This study explored the statistical  aspects related to censored
 data below the limit  of detection.   This study also  checked for instances of
 inconsistencies and discrepancies in the  study results  as  they relate to data
 quality.


 Finally, this study attempted  to provide a preliminary  assessment  of the current
 Field Sampling Project  in  terms of  its implications  for  further  study.   For
 instance,  this study identified  analytes and  areas of the country where further
 sampling might be warranted.   It also  suggested many analytes  that may not need
 to be included in analyses of these additional samples.
                                     889

-------
Produced waters comprise most  of  the  wastewaters from the exploration for, and
production  of,  crude  oil  and natural  gas.   Recent  surveys  by  the American
Petroleum Institute  [6] and EPA  [2] estimated produced waters to be 98 percent
and 83 percent,  respectively,  of  the total.  The  difference can be attributed to
API's method  of estimation, which  assumes a  higher ratio of water-to-oil  in
Texas,  Oklahoma,  and  Louisiana  production  sites.   Conversely, EPA's  method
assumes  substantially  larger  volumes  of  wastes  in  typical  drilling  pits,
however, both estimates indicate  the  importance  of production wastes.


National estimates based on the  current  EPA Field Sampling Project database of
production  sites  are highly dependent  on the values  observed  in  three  large
production sites in the Texas/Oklahoma, Pacific Coast, and Gulf zones.  This is
because  these  regions were underrepresented  in  the survey, relative  to  their
production.  This study reviewed  the  weights  (wastewater volume  estimates as a
proportion of the industry total  for  the  whole country) that  were developed by
EPA for use with production sites and compared these with weights developed by
API.   The  relative  distribution  of  weights among  zones was  similar for  both
weighting  methods.    Moreover,  mean  estimates  of  analyte  concentrations in
production liquids were generally comparable whether. EPA or API sampling weights
were employed.


This study  estimated the sampling precision provided by  the current  EPA  Field
Sampling Project.   The confidence  intervals  around the estimated means  were
typically around ^30 percent.  However,  sampling precision varied from analyte
to analyte and, it should again be noted, the  estimates are  strongly influenced
by the  values from a small number of  heavily  weighted production sites.


Drilling wastewater  data were also studied in some detail.  The weights  used by
EPA were dependent on estimates of the size and distribution of different  sized
drilling pits and on the proportion of drilling wastes that were  liquid.   These
estimates were based on a limited number of samples or on estimates obtained from
state officials, (which were difficult  to verify).   Data now available from an API
survey  [6]  provide  a  larger database  from which  to  develop sample  weights.
However, estimates  of mean  analyte  concentrations  using API  rather than  EPA
weights were  generally comparable.


The  major  limitation of   the   drilling  wastes  data  is   that  sites   from
Texas/Oklahoma were  seriously underrepresented, as only two drilling sites were
randomly selected from the  Texas/Oklahoma zone. Thus, the estimates of national
means  and  percentiles  are highly  dependent  on the values observed at  those two
sites.  This degree of dependence on two heavily  weighted drilling sites raises
concerns about the stability of the national estimates regarding drilling wastes.
The  sampling  precision associated  with  the  current statistical protocol  was
estimated.  The confidence  intervals around the  estimated mean  concentrations
were  typically  +30  percent for drilling  liquids and +.15 percent for  drilling
solids.  However, the sampling precision varied  considerably  among  analytes.


                                      890

-------
To establish priorities for further action or investigation, this study attempted
to place  into context the  information  on the wastes associated  with  petroleum
exploration and  production.   This  was done in  three ways:   First,  the  study
summarized and   compared  mean  and  median  analyte  levels   to  water  quality
standards; second,  the study  described the proportion of wastes  that  exceeded
water quality  standards  and  various multiples  thereof;  and third,  the  study
estimated  the  proportion  of  sites in which  the  concentrations  of  analytes
exceeded water quality standards and  various multiples thereof. Tables 2 through
5 list the latter two  proportions  for both production  sites and  drilling  pit
liquids,  respectively,  and for  the  11  inorganic  and 5 organic analytes  of most
concern.   Drilling pit solids' TCLP  leachates were generally of less concern  and
tables for these have been omitted.  Note that  EPA Water Quality  Standards were
used only as a risk-based datum for  comparison and were not directly applicable
to these production and drilling  wastewaters.
TABLE 2.
         Percentage of Production Endpoint Liquids Exceeding Water Quality Standards
Analyte
Inorganics
Barium
Fluoride
Chromium
Nickel
Cadniun
Lead
Arsenic
Antimony
Boron
Chloride
Sodium
Organ its
Toluene
Benzene
2-Butanone
Phenol
Phenanthrene
No. No. WQ Std.
Sam. Det. mg/1

25 22 1. a
22 22 4. b
25 6 0.05 a
24 4 0.5 c
25 7 0.01 a
25 4 0.05 a
25 9 0.05 a
25 7 0.01 c
25 25 1. d
22 22 250. b
25 25 250. e

22 17 10. a
22 17 O.OOSa
22 6 2. c
22 11 1. c
22 5 0.002f
Est. Low High

50.5 33.1 67.8
3.9 1.4 9.5
20.0 8.0 40.0
0.0 0.0 0.0
24.0 4.0 24.0
100.0 1.0 100.0
70.0 52.0 88.0
50.0 1.2 56.0
99.2 97.6 99.8
99.9 99.6 100.0
76.1 60.2 87.7

<0.1 0.0 0.1
99.9 99.9 99.9
9.1 0.0 18.2
0.1 0.0 0.4
100.0 100.0 100.0
	 lOx 	
Est. .Lt>vi High

15.8 7.3 29.0
0.0 0.0 0.0
4.0 0.0 12.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.8
0.0 0.0 0.6
41.9 25.7 59.7
81.7 67.5 91.2
39.7 23.9 57.5

0.0 0.0 *0.0
96.5 91.1 98.8
0.0 0.0 *0.0
0.0 0.0 0.0
9.1 0.0 22.7
- 	 lOOx 	
Est. Low High

2.2 0.7 5.8
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 0.4
0.0 0.0 0.4
0.2 0.1 0.8
9.1 3.7 18.7
10.9 4.7 21.8

0.0 0.0 0.0
34.2 19.1 52.2
0.0 0.0 0.0
0.0 0.0 0.0
0.0 0.0 9.1
 footnote ley
 a.
 b.
 c.
 d.
 e.
 f.
 t
National Primary Drinking Water Regulation, 40  C.F.R.  Part 141
National Secondary Drinking Water Regulation, 40 C.P.R Part 153
Based on an EPA reference dose for systemic toiicity
Based on a vegetation toxicity level, Sanks and Asano, p. 218 (1976) [7]
Assumes same criteria used in chloride
Based on an EPA, Characterization Assessment Division  unverified reference dose
Percentages )0.0 but <0.05
                                       891

-------
TABLE 3.       Percentage of  Production Sites  with Production  Endpoint Liquids  Exceeding  Hater
               Quality Standard             ,
Analyte
Inorganics
Bariun
Fluoride
Chroniun
Nickel
Cadniun
Lead
Arsenic
Antimony
Boron
Chloride
Sodiun
Organics
Toluene
Benzene
2-Butanone
Phenol
Phenanthrene
No. No. HQ Std.
Sam. Det. mg/1

25 22 1. a
22 22 4. b
25 6 0.05 a
24 4 0.5 c
25 7 0.01 a
25 4 0.05 a
25 9 0.05 a
25 7 0.01 c
25 25 1. d
22 22 250. b
25 25 250. e

22 17 10. a
22 17 O.OOSa
22 6 2. c
22 11 1. c
22 5 0.002f
Est. Low High

27.5 8.0 47.1
29.0 8.6 49.4
21.7 3.6 39.8
o.o 	
28.5 8.2 48.8
13.4 0.0 28.8
44.3 21.9 66.6
0.5 0.0 3.8
100.0 	
73.7 53.9 93.5
65.9 44.6 87.2

o.o 	
81.3 64.2 98.4
o.o 	
3.5 0.0 11.6
43.6 21.3 65.9
	 lOx 	
Est. Low High

3.4 0.0 11.3
2.0 0.0 8.3
o.o 	
o.o 	
10.1 0.0 23.7
10.2 0.0 23.8
6.2 0.0 17.0
o.o 	
56.8 34.5 79.1
56.3 34.0 78.6
60.7 38.7 82.6

o.-o 	
80.4 63^.0 97.8
o.o 	
o.o 	
43.6 21.3 65.9
	 lOOx 	
Est. Low High

2.9 0.0 10.3
o.o 	
o.o 	
o.o 	
o.o 	
o.o 	
3.5 0.0 11.8
o.o 	
4.3 0.0 13.4
17.8 0.0 35.0
22.9 4.0 41.8

o.o 	
15.8 0.0 31.8
o.o 	
o.o 	
38.1 16.3 59.9
 TABLE  4.        Percentage of  Drilling Pit Liquids Exceeding Water Quality Standards
Analyte
Inorganics
Bariun
Fluoride
Chroniun
Rickel
Cadniun
Lead
Arsenic
Antinony
Boron
Chloride
Sodiun
Organics
Toluene
Benzene
2-Butanone
Phenol
Phenanthrene
No. No. HQ Std.
San. Det. ng/1

19 19 1. a
19 19 4. b
19 16 0.05 a
19 17 0.5 c
19 14 0.01 a
19 13 0.05 a
19 8 0.05 a
19 2 0.01 c
18 17 1. d
19 19 250. b
19 19 250. e

18 7 10. a
18 2 0.005 a
18 6 2. c
17 3 1. c
17 4 0.002f
	 li 	
Bst. Low High

54.3 35.7 72.0
11.3 4.6 23.1
98.9 99.6 99.7
50.0 31.7 68.3
99.7 98.9 99.9
99.9 99.8 99.9
63.2 42.1 84.2
52.6 1.0 60.5
90.3 79.0 96.3
86.4 73.4 94.2
90.5 79.8 96.3

0.0 0.0 *0.0
80.6 69.4 91.6
0.0 0.0 *0.0
0.0 0.0 *0.0
100.0 100.0 100.0
	 lOi 	
Bst. Low High

6.3 2.3 14.7
<0.1 <0.1 0.1
69.3 50.0 82.9
0.6 0.1 2.2
52.3 33.8 70.3
80.6 65.2 91.0
0.0 0.0 5.3
0.0 0.0 10.5
3.0 0.9 8.1
52.5 34.0 70.5
50.7 32.3 68.9

0.0 0.0 *0.0
27.8 16.7 38.8
0.0 0.0 *0.0
0.0 0.0 *0.0
58.8 35.2 76.4
	 lOOx 	
Bst. Low High

0.1 <0.1 3.6
0.0 0.0 0.0
8.6 3.3 18.7
<0.0 0.0 <0.1
0.3 <0.1 1.2
4.6 1.5 11.3
0.0 0.0 *0.0
0.0 0.0 5.3
<0.1 0.0 <0.1
16.6 7.4 31.0
10.1 4.0 21.1

0.0 0.0 0.0
0.0 0.0 *0.0
0.0 0.0 0.0
0.0 0.0 0.0
11.8 0.0 35.3
                                              892

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TABLE 5.      Percentage of  Drilling  Sites with  Drilling .Pit Liquids Exceeding  Water Quality
           Standards
Analyte
Inorganics
Bariun
Fluoride
Ghroniun
Nickel
Cadniun
Lead
Arsenic
Antinony
Boron
Chloride
Sodiuit
Organics
Toluene
Benzene
2-Butanone
Phenol
Phenanthrene
Ho. No. HQ Std.
San. Det. mg/1

19 19 1. a
19 19 4. b
19 16 0.05 a
19 17 0.5 c
19 14 0.01 a
19 13 0.05 a
19 8 0.05 a
19 2 0.01 c
18 17 1. d
19 19 250. b
19 19 250. e

18 7 10. a
18 2 O.OOSa
18 6 2. c
17 3 1. c
17 4 0.002f
Bst. Low High

53.6 30.6 76.6
28.6 7.7 49.4
77.9 58.8 97.1
56.1 33.1 79.0
77.7 58.0 96.7
71.1 50.2 92.1
33.2 11.4 54.9
5.3 0.0 15.6
94.1 83.2 100.0
82.6 65.1 100.0
98.8 93.7 100.0

o.o 	
3.4 0.0 11.9
o.o 	
o.o 	
33.3 10.2 56.3
	 lOx 	
Est. Low High

4.5 0.0 14.1
4.5 0.0 14.1
57.9 35.1 80.7
4.4 0.0 13.9
57.6 34.7 80.4
67.3 45.6 89.0
o.o 	
o.o 	
11.0 0.0 25.5
61.1 38.6 83.6
71.0 50.0 92.0

o.o 	
o.o 	
o.o 	
o.o 	
33.3 10.2 56.3
	 lOOx 	
Est. Low High

4.5 0.0 14.1
o.o 	
27.0 6.5 47.5
o.o 	
6.9 0.0 18.6
4.5 0.0 14.1
o.o 	
o.o 	
o.o 	
26.3 6.0 46.6
7.7 0.0 20.1

o.o 	
o.o 	
o.o 	
o.o 	
31.8 9.0 54.6
 All of  the  production  and  drilling  sites  had at  least one key  analyte  that
 exceeded water quality standards.  For the production sites,  the key analytes  in
 greatest excess were benzene  at  46 percent  of the sites and phenanthrene at  41
 percent.  For the  drilling pit liquids,  the  key analytes in greatest excess  were
 either chloride or sodium in 67 percent  of the sites  and chromium at 23 percent;
 for drilling pit solids' TCLP leachates, the key analytes in greatest excess  were
 sodium at 50 percent of  the sites,  lead at 35 percent, and cadmium at 11 percent.
 For many key analytes, substantial  proportions of the sites exceeded 10 times the
 water quality  standards and in some instances  sites exceeded the standards  by
 1,000 times.   Noteworthy in this  regard are:  for  production sites, benzene,
 barium,  chloride,  sodium, and boron;  for drilling  pit liquids,  phenanthrene,
 benzene,  lead,  chromium,  cadmium,  chloride,  and sodium; and for  drilling pit
 solids' TCLP leachates, lead.


 Several  limitations,  however should  be mentioned regarding these statistical
 analyses:

 (1)  The analyses  are limited to national estimates.  The samples  within states
 and regions were  too small  to  produce reliable sub-national estimates.
                                     893

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(2) The estimates are limited to:  (a) production endpoint liquids; (b) drilling
pit liquids; and (c)  TCLP leachates from drilling pit solids.  Again, the number
of samples were too small to provide reliable estimates of analyte concentrations
in  drilling  muds,   tank  bottoms,  central  pits,  or  centralized  treatment
facilities.  Finally, drilling pit solids  were  excluded from these statistical
analyses because analyte concentrations in solids (typically measured in mg/kg)
are not directly comparable to water quality standards  (typically measured  in
mg/1).


(3)   A  final  issue concerns  the  appropriate water quality  standards for
comparison.  In making comparisons in terms of  human health effects,  a primary
drinking water standard or toxicity reference  dose  was selected.  In the case  of
boron, chloride,  and sodium, water quality  standards  were selected based  on
potential damage to vegetation.  The boron limit is a toxicitybased value  [8];
the chloride limit is based on salinity considerations  [9]  and  is  approximated
by the secondary drinking water standards;  and the  sodium limit  is  equated with
the chloride limit as a  reasonable approximation.


A major issue concerns  the effects of  dilution as  the effluent flows from the
drilling pit or  production endpoint into the receiving waters. Without detailed
modeling of individual site  characteristics, the effects of this dilution can not
be  estimated.    Nevertheless,  multiples—ranging  from 10  to  1000—times  the
relevant water quality standard were used  to  demonstrate the potential  effects
of dilution.  Because of space limitations, Tables  2 through 5 herein only show
the 10 and  100 multiples  of the  standards.


Because the detection limits  were very  close  to  the  relevant  water  quality
standards  for  many  of   the  analytes,  estimates  of  the  proportion  of  the
wastewaters that exceed  the water quality standards  are heavily influenced by the
method that  is used  to impute values for censored  data.  However,  estimates of
the proportion  of wastewaters  exceeding   10  and  100  times  the  water  quality
standard are much less affected by alternative  methods of handling censored data;
thus, much  of the discussion focuses on these multiples.


Conclusions  and Recommendations

There were  six major conclusions  reached in this statistical assessment:

(A)   The EPA study  is consistent  with  the similar API  study;

(B)   More  sampling  would be advisable  to  improve  representativeness;

(C)   The detection  limit and censorship issues are manageable;

(D)   A potential for serious environmental contamination is shown  by the data;
                                     894

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(E)   Many of  the inorganic  substances  had waste liquid  concentrations  that
     exceeded drinking water standards.  Of the set of substances  selected for
     evaluation, there were more instances of  inorganic compounds exceeding the
     standard than there  were  for organic compounds.

(F)   Brines from  the oil  and gas extraction  industry are  potentially a major
     threat because  of their potential capacity to damage vegetation.
Five major recommendations were made, three regarding additional sampling and two
regarding  the statistical  analysis;  these were, respectively:

(1)  Any  supplemental  sampling should  be conducted  in the regions  that are
underrepresented in the earlier survey.  Such sampling  should be conducted until
no single  site  accounts for more than 10 percent  of all sample weights.  This
could be done  by  randomly sampling eight additional production sites (four in
Texas/Oklahoma, two in the Plains region, and one in the West Coast region) and
six additional drilling  sites  (five  in Texas/Oklahoma and  one  in  the  Gulf
region).


(2)  In any  further  studies,  replicate samples should be taken from production
endpoints and from drilling pits.  These would help to assess sample reliability.
Increasing the number of samples might also increase the number of observations
above the  limits of detection and  thereby improve the ability to statistically
impute values  for  censored observations.


(3)  To reduce the costs of additional sampling and laboratory analyses, a much
shorter list of analytes/pollutants that one could realistically expect to find
in wastewaters  from  the target industrial facilities should be used.


(4)  Information  from a recent survey by the American Petroleum Institute [6]
that offers  a larger database  from which to develop zone weights should be used
in statistical analysis of  the  wastewater data  from this EPA Field Sampling
Project.


(5)  Statistical imputation techniques that use the information available from
observed values to provide estimates for  "censored" values should be utilized to
substitute for values  that are missing because they  are  below the  limit  of
detection.   Where  there are too few observations  above  the  detection limit to
allow such statistical  imputation,  either of two approaches are suggested: (a)
for estimating the proportion  of wastewaters that exceed a particular contaminant
concentration, non-parametric estimates—which do not require imputation—should
be used;  or  (b) censored values  should be treated as if they were one-half the
detection  limit  (rather than  zero).
                                     895

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References

[1]   U.S. EPA, Office  of Water and  Office of Solid  Waste,  Technical Report^
      Exploration.  Development,  and Production  of Crude Oil  and Natural Gas^
      Field.  Sampling  and  Analysis  Report.  EPA  530-SW-87-005,  U.S.  EPA,
      Washington, DC  20460,  124p,  January 31,  1987

[2]   U.S. EPA, Office of Solid Waste, Wastes from the Exploration. Developmentt
      and Production  of  Crude Oil.  Natural Gas,  and Geothermal Energy. Interim
      Report,  Part  I: Oil  and Gas,  U.S.  EPA,  Washington,  DC   20460,  1550p,
      April, 30 1987

[3]   Kenneth  K.  Landes, Petroleum Geology of the United States.  John Wiley  &
      Sons, New York, 571p,  1970

[4]   U.S. EPA, Office  of Solid Waste and Emergency Response,  Draft  Superfund
      Public  Health  Evaluation  Manual. OSWER  Directive  9285.4-1,  U.S.  EPA,
      Washington, DC  20460,  139p+Appendices,  December  1985

[5]   Robert  J.  Gilliom and  Dennis  R.  Helsel,  Estimation of  Distributional
      Parameters  for  Censored Trace  Level Water  Quality  Data:  1. Estimation
      Techniques,  and  ...2.  Verification  and  Applications,  Water  Resources
      Research 22,2,135-146  and 22,2,147-155, respectively,  1986

[6]   Paul  G.  Wakim,  Draft  API   1985  Production  Waste   Survey—Statistical
      Analysis and  Survey Results.  American Petroleum  Institute, July 1987

[7]   R.L. Sanks, T.  Asano,  and A.M.  Ferguson, Engineering Investigations for
      Land Treatment  and Disposal, in  R.L.  Shanks and  T.  Asano  (eds.), Land
      Treatment and Disposal of Municipal and Industrial  Wastewater. Ann Arbor,
      Ml:  Ann Arbor  Science,  pp.  213-250,  1976

[8]   P.M. Eaton and L.V. Wilcox, The  Behavior of Boron in Soils. USDA  Technical
      Bulletin 696, 1939

[9]   Calvin  V.  Davis,   The Handbook  of  Applied Hydraulics  (2nd   edition),
      McGraw-Hill,  Inc.,  1952
                                      896

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STATE OIL AND GAS AGENCY ENVIRONMENTAL REGULATORY PROGRAMS -
HOW SUCCESSFUL CAN  THEY BE?
David G. Boyer
Hydrogeologist/Environmental Bureau Chief
New Mexico Oil  Conservation Division
Santa Fe, New Mexico
Introduction

State oil  and  gas  regulatory  agencies  historically have  dealt  with  non-
environmental   rulemaking.    The  traditional  issues  included  allocation  of
production  among  competing interests  and  regulation  of  production rates  to
prevent  unrestricted and wasteful withdrawal of the finite  resource.   Programs
to restrict disposal of  produced water  came  later  after realization,  especially
in arid  states, that uncontrolled dumping of large volumes  of  salt water  posed
serious  threats to limited fresh water supplies.

In the late 1970's  the  Federal  Safe  Drinking Water Act  set minimum  national
standards for state underground injection control (UIC)  programs.  With injection
well permit review  and  approval, and  enforcement  of  cementing and  mechanical
integrity testing programs, UIC became the first nationwide environmental program
regulating  disposal of oil and natural gas production  wastes.  Most  states  now
have  primary  enforcement  responsibility  for  oil  and gas UIC  programs  and
implementation is  done through the state oil and gas agency.

State regulation of  other  methods of produced water disposal  or of oil  field
sludges  and solids  varies  among  the  states.   Some states  essentially have  a
single agency  regulating waste disposal (e.g. Louisiana, New Mexico, Texas, West
Virginia) while other states have split jurisdiction between onsite and  offsite
disposal (e.g.  Kansas),  while  still  others may  have two or more agencies having
regulatory  jurisdiction  over the same waste (e.g. California, Colorado, Wyoming).
The  placement  of  a  particular  state's  regulatory program  is  likely due to  a
combination of events such as  the existence of similar regulatory programs  in
state departments  of health  or  environment,  and  the political  climate  and
influence of the oil and gas industry at the time the environmental programs were
initiated.

Now, as  the states  face  additional federal regulatory requirements for  oilfield
waste disposal., it  is  important that a  single state  regulatory  agency have
jurisdiction  over oilfield waste.  Single  agency  jurisdiction for onsite  and
offsite  waste  disposal  will allow  the most efficient processing of  industry
permits  and avoid dual  jurisdiction and the conflicts that often arise  among
completing  agencies.

However, to be  effective and to demonstrate environmental commitment,  an oil  and
gas agency  administrating an environmental  regulatory  program should have,  in
addition to comprehensive  regulatory authority,  an adequate  number of technical
staff with a  mix of  environmental  and industry  expertise, and a  management
structure  within  the  agency  that will  provide a   focus  for  oil  and  gas
environmental  activities.   These  may  include  permitting,  preparation of  waste
management  procedures, contamination investigation, and coordination  with  other
agencies,  industry,  environmental groups and the public.
                                     897

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This paper presents the case for administration of oilfield waste management and
disposal programs by the state oil and gas agency while recognizing that in some
states  statutory  and   political  constraints  may  not  make   such  programs
practicable.

Differing Program Jurisdictions

In 1988,  there  were  16 states listed  by  the  Interstate Oil Compact  Commission
(IOCC)  as  being in the  top ten  for  one  or more  of  the following statistical
categories:  Oil production, gas  production, producing  oil wells,  and producing
gas wells (Table 1).  The IOCC collected information  for these and other states
as part of their 1989 survey of waste management  in oil and gas  exploration and
production  operations.   This  paper  utilizes that  information  and includes
information  on  refineries  and  natural gas processing  plants.   Jurisdictional
issues  involving federally  managed or Indian lands were not examined.

Elements  of the IOCC  waste survey included  onsite and offsite regulation of
landfarming, roadspreading, pits,  surface water disposal, waste haulers, burial
or landfilling, disposal wells  and enhanced oil recovery injection wells.   The
states  listed  in  Table  1 were  contacted  to obtain information  on natural gas
plants  and  refineries  for this  paper.

Examination  of  the  IOCC waste survey results  (Table  2)  shows  a  wide  variation
among  states in  both the  agencies regulating  the wastes  and  the  number of
agencies  within a  state that have jurisdiction.   For  example,  Louisiana,  New
Mexico, North Dakota, Oklahoma, Pennsylvania,  Texas and West Virginia have  most
or all  of their exploration and production waste  program within the oil and gas
agency.  Alaska, California and Kentucky  have  all programs except the Class II
injection  program  in state health,  environment,  or water agencies.   For  some
disposal  practices  in these  three states, two or even three non-oil  and  gas
agencies  are involved in state  regulation.   Additionally,  local  governmental
bodies  also  may be involved.

The  remainder of the  states listed in Table 2  have split jurisdiction with the
oil  and gas  agency  usually  regulating onsite disposal  while  other agencies
regulate offsite hauling and disposal.  Non-oil and gas agency regulation is  most
common  for sludges and solids placed into waste pits; onsite and offsite disposal
of produced  water, especially by  injection,  is most commonly under the  oil  and
gas  agency.

For  most  states listed  in Table 2, natural gas processing  and oil  refining  are
under  state  health  and waste management agencies.  The  exceptions for  natural
gas  processing  are Louisiana, New Mexico, Texas and West Virginia.  Oil and gas
agency  jurisdiction  over  refineries  is  even more  limited.   New Mexico  has
jurisdiction over  non-hazardous  wastes   at   refineries  while  in  Louisiana,
hazardous and non-hazardous wastes disposed of in injection wells are  under the
oil  and gas agency  while disposal of other hazardous or solid wastes is under
the  jurisdiction of  the  state environmental agency.

Organizational  Structure

At  least   three key  elements  must  be present  for a  state to  have a basic
environmental   regulatory  program.   These  are  requirements  for  permitting,
compliance  evaluation and  enforcement.   However, to be comprehensive  several
additional program requirements are necessary.   As identified by  the IOCC in the
June 1990  draft  report  of the  Council   on  Regulatory Needs,  these  include
contingency   planning,  financial  assurance,   waste   tracking  and   hauler
certification,  data  management,  and  public participation.   The  draft  report
discusses  these requirements  in some  detail.
                                      898

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To most successfully implement  a  comprehensive oil and gas agency environmental
regulatory program,  an agency's  organizational  structure must be  modified to
provide an in-house group where  environmental activities can be focused and which
can  complement  the traditional petroleum  engineering and geological  services
groups.   The establishment  of  a designated  environmental group with  specific
permitting and environmental response  capabilities that reports directly to the
agency supervisor  demonstrates  an agency's commitment  to  environmental  issues.

As  oil  and gas waste  issues and the  regulations surrounding them  become  more
complex,  specialized  expertise  can  be  maintained  only  through  a  group  of
professionals permanently assigned  to  these tasks. With the  possible  exception
of UIC permitting  (which  is not limited to waste disposal but  includes  injection
for  secondary  and  tertiary  oil recovery),  waste disposal activities  should be
separated from the traditional production permitting activities such as pooling,
unitization,  gas  proration,  correlative  rights  and  resource conservation.
Indeed,  many traditional staffers  may resent  the addition of environmental
considerations  especially if their workload is  increased and  complicated  by
requirements not directly related  to  production.  In this respect  the  critics
of oil and gas  agency environmental  programs are correct:  Some separation should
be  maintained   between   production activities   and   environmental  regulatory
activities within  an agency.   Therefore, the solution is a separate environmental
group  with  responsibilities  which   include   a  statutory  and  regulatory
responsibility  to  manage these wastes  in  a manner that protects public health
and the environment.

The main benefits  of an  oil  and  gas agency environmental group are to provide
a focus  for  agency environmental efforts including  1)  waste disposal permitting
(landfarming, pit  disposal of water and solids, pond design engineering review),
2) permit  review of gas processing and compression facilities,  3) review of oil
and  gas  spill  reports  to   evaluate   fresh  water  pollution  potential,    4)
development  of additional environmental rules  and requirements  in response to
demonstrated need  or to  additional  governmental  mandates (e.g.  Congress, EPA,
State legislature),   5)  to  require, conduct,  review  and/or  coordinate  ground
water or waste contamination investigations and remedial actions, and 6) acting
as a liaison for the agency with other  agencies, industry,  environmental groups,
and  concerned  citizens  with  respect  to  oil and  gas  related environmental
problems.   In New Mexico, all  these functions  are performed  by the New Mexico
Oil Conservation Division (NMOCD) Environmental Bureau with the liaison function
between the  agency and the public taking on an increasing importance.

A  designated  environmental   group  within   the  agency  also provides increased
environmental  awareness  by  being   able  to  advise other  staff and  industry
operators on environmental aspects  of  existing or proposed rules.  For example,
New  Mexico's  Environmental  Bureau provides written  guidance documents  for
preparation  of  permits   for  commercial surface  disposal facilities,  clay or
synthetic lined  surface  impoundments,  natural gas processing  plants, geothermal
facilities and oil-field service  companies.  More recently, the  bureau has been
disseminating  information to operators  on the scope of the oil and gas exemption
to the Subtitle  C  (Hazardous Waste)  provisions of the Resource Conservation and
Recovery Act (RCRA),  and advising   them of upcoming  changes  in the types  and
amounts of wastes  managed under RCRA.   Similar information is provided to other
agency staff,  and  bureau personnel  provide training and technical expertise to
district field  offices,  especially in collection  and preservation  of  water
samples.

Technical Staffing Needs

Adequate technical expertise must be maintained both at the central office and
district levels  in order  to  properly evaluate permits  and  respond to reports of
suspected or actual contamination.   The number of experts necessary depends on
the complexity  of  the  program and types of facilities regulated.  For  example,
NMOCD review of  permits  for  underground injection, commercial surface  disposal
facilities,  natural gas  processing  plants and refineries  occurs  in Santa Fe and
                                     899

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requires  staff  with  both engineering  (environmental  and/or  petroleum)  and
hydrogeological  expertise.

For non-UIC permits, engineering aspects reviewed include process and wastewater
streams, and  treatment areas to identify  likely areas for spills  or equipment
leaks (such as from valves or pump seals), demonstrate underground pressurized
and gravity pipe  integrity,  and verify proper containment/storage  of chemicals
and drums.  All  solid  and liquid process streams and wastestreams  are included
in the review as  well as evaluation of engineering adequacy of any proposed waste
pond  liners   or  treatment  systems  (especially   aeration   systems  for  H2S
elimination).

A staff hydrogeologist will  evaluate ground water contamination potential from
any clay or unlined pits or surface impoundments receiving or proposed to receive
non-hazardous  liquid or  solid wastes.   In  New Mexico, especially,  fresh water
supplies  are  scarce and  in some  areas non-existent.    OCD-approved surface
disposal  into unlined facilities  continues to be authorized in areas without
fresh water, but hydrogeologists carefully  evaluate  each request.   Requests for
land treatment of wastes  are reviewed for location suitability and  application
rates.  At existing facilities,  closure of unlined ponds is  accompanied by review
of  past practices,  and remedial  action, if necessary, is  initiated to remove
floating  product and  dissolved hydrocarbons threatening  adjacent  fresh  water
supplies.

At  the district office   level,  at  least  one staff  person  should  be trained
specifically in environmental matters including knowledge of compositional makeup
of  oil  and gas wastes, current approved  practices for disposal, local geologic
and hydrologic conditions so that spills can  be  properly  mitigated, and  waste
and water  sampling  methodology to  provide  proper  response  to  complaints  and
potential  ground water contamination.  This environmental staff person would act
as  a direct liaison with  central office  staff reviewing environmental permits.

To  attract  and   retain  adequately  educated and  trained  professional  staff,
salaries  must be commensurate with similarly trained professionals.   It  is
critical  that  this  be accomplished.  Government must  not be the employer of last
resort,  taking only those who can't find jobs elsewhere.   The area of oil  and
gas environmental regulation is becoming increasing  complex.   The  survival  of
the oil and  gas  industry in  the  United  States is  dependent  on  rulemaking,
implementation and  enforcement  that is  scientifically sound,  environmentally
responsible and  that is applied in a fair, even-handed manner.  Payment of less
than adequate  salaries is  unlikely to result in staff with adequate credentials
to  perform tasks (especially permitting) in an efficient  and effective manner.

Building  Citizen Confidence:   Accountability and Public Interaction

The most  difficult challenge  facing  a state  oil and gas agency that administers
an  environmental regulatory program is to convince a  skeptical public, including
environmental  groups and  legislators, that  a  real commitment to environmental
protection exists and  the agency does not merely reflect  industry desires.

The location  of  the oil and gas agency within state government framework can be
important  in this regard.   While individual state government organization varies,
many  if not most states  have a cabinet  system in the executive branch similar
to  that  of the  federal  government.   In this  system the  responsibility  for
implementing  laws  rests   in  the  office  of  the governor  with clear  lines  of
authority existing  between  that  office  and individual departments and lessor
governmental  divisions.   Department heads and division directors are appointed
and responsible  to the governor for  their actions.  State executive departments
such as health and environment,  environmental quality, natural resources, energy
and minerals,  etc. are represented in the cabinet with this system.
                                      900

-------
The director of a state oil and  gas  agency located within a  natural resources,
or energy and minerals department, will be as equally responsible to the governor
for administrating environmental laws pertaining  to  oil and gas waste as will
the director of an environmental  agency, and equally subject to ouster if his/her
performance  is  not  adequate.    This government  system,  plus  state  statutory
authority  requiring the  oil and agency  to regulate  waste disposal  to protect
public health  and  the environment, is  the  most effective means to  assure
accountability for administration  of environmental regulations.

Similar lines  of executive authority are  present in states that have oil and gas
commissions with the chairman and most members directly appointed and responsible
to  the governor.  However, the  system may be more tenuous  if the  oil  and gas
commission members are appointed to serve staggered  terms and are  required by
law to be  representative  of one  political  interest or another.

State  oil and gas  agencies that  are divisions  of  elected  state  corporation
commissions  or similar agencies are outside the control of the executive branch.
The elected  commissioners may or may not be interested in environmental issues,
or they may be secondary  to other  regulatory concerns.  In this instance  clear
legislative direction should be  given to  require that environmental  protection
be addressed in oil and gas waste  disposal permits.

The past experience of an  agency's  environmental professional staff  can assist
in allaying public fear of industry control  of  an oil and gas agency  program.
Staff with previous  experience in state  environmental agencies complement  other
staff with industry experience by being able  to communicate and work with  their
counterparts  in  the   state's  environmental  agency.    The  cooperation  and
coordination  between  agencies  becomes  critical  if  some  onsite   and offsite
oilfield  waste  management  programs continue  to remain in  separate   state
government departments.

 Oil and gas agency environmental staff must  be able to work directly with  both
 the public and with environmental groups.  The form and extent  of agency  response
 to public concerns over oil and  gas  exploration and production, or  to disposal
 of wastes will  shape  the  public's  view of the  agency.   Having technical  staff
 with prior environmental  agency  experience can help in this regard.  Involving
 the public by  requiring public  notice and considering  public comment  on proposed
 disposal facilities and other  major  permit actions may seen time consuming  and
 counterproductive until the time and expense  of lawsuits is considered.

 Having staff  trained  to respond to public complaints  will  alleviate the image
 of  an  industry  dominated  agency.   In   New Mexico,  money  is  budgeted   for
 investigative  water  quality  sampling,   and  OCD  has  cosponsored  with   the
 environmental agency free  water testing in areas where  large number of complaints
 of contamination have been reported.  Near the Colorado border over 200 ground
 water samples have been tested since April,  1989,  and discovery of significant
 natural gas contamination  of domestic wells  in one area  has  led to additional
 gas well completion  requirements and to well workovers for many older gas wells.
 In this case  having the ability to effectively  respond  to complaints and  take
 action to begin remediation of the  problem reduced public outcrys for a halt to
 drilling activity and  for  EPA and Congress to take action to require additional
 environmental studies  and  controls.

 Although  national and  local environmental  groups  are considered  nuisances or
 worse by many  traditional oil and gas agencies (and  even some state environmental
 agencies),  it   is   crucial   that   agencies   open  a   dialogue   with   these
 representatives.  Irrespective  of whether  one  agrees or disagrees with the  level
 of activism, the political realities  are that  these groups are attaining greater
 political influence  in state and local government affairs, especially in states
 that have diverse economies (i.e. California).
                                    901

-------
Those  oil  and gas  agencies (and  those producers)  that  believe  environmental
issues are only todays fad, or  that superficial  environmental rules will suffice
will likely be rudely awakened  since the solution generally sought in these cases
is to  enact  strict  inflexible statutory remedies  and place the program  in the
state's environmental agency.   In  fact, the  threat of the state  environmental
agency assuming  jurisdiction or,  worse yet (from their viewpoint),  the  federal
government setting strict regulations, has been enough to cause many oil and gas
agencies to  rewrite  rules, revise  programs and focus on environmental  issues.

The on-going debate  on these matters  will  continue to direct  attention  on these
issues for  at least  the next  several years.    State  oil  and gas agencies that
already  have  successfully  incorporated  environmental  programs   into  their
traditional activities and remain responsive to public concerns will be required
to make the  least adjustments  to  future requirements.

Conclusions

To be  successful with both the industry regulated and with the public,  oil  and
gas agency environmental regulatory programs must be efficient and effective in
permitting  and in other duties (e.g.  contamination investigation, information
activities),  and be  responsive to public concerns about possible contamination
and remedial  action/cleanup  of known  problem sites.  A combination of a  central
office environmental  group and field office specialists provides  the best method
to accomplish this.   The  environmental group  should include a mix of engineers
and  hydrogeologists,  and  salaries should be  structured  to  hire  and  retain
experienced  staff.    Field office  staff should  have knowledge  of  the types of
wastes, local geology/hydrogeology, and waste  and water sampling methods.

The more  difficult  challenge  of  convincing the  public  that the agency  has a
genuine concern about environmental matters can be attained by holding the agency
accountable for its environmental  program.  This  is accomplished through statutes
and regulations  that  require waste disposal be conducted to protect human health
and the environment,  and through holding senior  agency officials responsible  for
carrying  out  their  duties.    Additional  confidence-building measures  include
having staff  with  previous experience in the  state environmental agency,  being
responsive  to  citizen complaints  and  inquiries,  issuing  public notice  and
receiving  public comment  on major permit actions,  and entering into a dialogue
with  state  and local environmental representatives.

Those  agencies with programs in place  that  follow the guidelines presented above
are the least likely  to suffer serious disruptions  due  to additional oil  and  gas
environmental regulations,  and will best serve  the public and the industry they
regulate.

Acknowledgement

I gratefully  acknowledge the assistance of William R. Bryson, Intergovernmental
Coordinator/Technical  Director,   Conservation   Division,   Kansas  Corporation
Commission  who discussed at length with me  some of the concepts  I  present in
this  paper.

Reference

Council  on Regulatory  Needs,  Draft  Report  on Regulation  of  Exploration  and
Production  Wastes.  Interstate  Oil Compact  Commission,  June, 1990.
                                     902

-------
                             Table 1:  Top Ten State Production  and Operating Statistics, 1988
8
co
Oil Production
lx
2.
3.
4.
5.
6.
7.
8.
9.
10.
Texas
Alaska
Louisiana
California
Oklahoma
Wyoming
New Mexico
Kansas
North Dakota
Utah
31
23
13
11
3
3
2
1
1
1
.1Z
.4
.4
.7
.9
.5
.2
.8
.4
.0
Producing Oil Wells
Texas
Oklahoma
California
Kansas
Ohio
Louisiana
Illinois
New Mexico
West Virginia
Pennsylvania
191
73
47
44
29
27
18
16
15
13
,424
,846
,852
,546
,625
,433
,563
,636
,865
,255
Gas Production
Texas
Louisiana
Oklahoma
Wyoming
New Mexico
Kansas
California
Colorado
Alaska
Utah
35
26
10
4
4
2
2
2
2
1
.8Z
.3
.4
.12
.06
.9
.54
.53
.35
.44
                                                                                        Producing Gas Wells
Texas
Ohio
West Virginia
Pennsylvania
Oklahoma
New Mexico
Louisiana
Kansas
Kentucky
Colorado
50,316
34,116
30,189
29,000
19,308
16,488
16,075
12,013
 9,505
 6,180
              Source:  Interstate Oil  Compact Commission

-------
                                                          TABLE 2.   AGENCY JURISDICTION  BY ACTIVITY
                                                             AND FEDERAL STATUTE IMPLEMENTATION
                                                  ALASKA
                                                                                         CALIFORNIA
                                                                                                                                      COLORADO
ACTIVITY

1.   Landfarming

2.   Roadspreadlng

3.   Pits

».   Surface Water
       Disposal
S.   Waatehaulers
    Burial or Landfill
    Disposal Wells
     (Class II)
    Enhanced Oil Recovery
     Injection Wells
    Natural Gas
     Processing Plants
10. Refining (Hazardous
     Wastes)
11. Refining (Solid
     Wastes)

Federal Statute Implementation

1.  Safe Drinking Water
     Act (UIC - Class II)
2.  Clean Water Act
     (NPDES)
3.  RCRA - Subpart C
     (Hazardous)
4.  RCRA - Subpart D
     (Non-hazardous)

Notei  OfcG • Oil and Gas.  Numbers In parenthesis are
      to reduce overlapping responsibilities.
On-Slte
OIG
Agency Other
X(2)
X
X X(2)
X
-.
X
X
X
..
--
--
Off-Site
OIG
ARenCT Other
X<2>
X
X X(2)
X
X
X
X
X
X
X
X
On-Site Off-Site
OIG OIG
Agency Other AiencT Other
X(2) X(2)
X(2) X(3)
X(2) X(2)
X(2) X(2)
X
X(2) X(2)
X X
X X
X(2)
X(2)
X(2)
On-Site Off-Site
OSG 0(6
AaenCY Other Aiencr Other
X X
X X
X XX
X X
X
X XX
X X
X X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
                                                            °f
                                                                       ' 8"
                                                                                      h"Vln8 dUal *'*•«"*»•  Men.or.ndu,,, of agreement MT be in effect
Sources:  Interstate Oil Compact Conml salon, 1990| New Meiico Oil Conservation Division.

-------
                                                         TABLE 2.  AGENCY JURISDICTION BY ACTIVITY
                                                             AND  FEDERAL STATUTE IMPLEMENTATION

                                                 ILLINOIS                                 KANSAS
KENTUCKY


ACTIVITY
1. Landfarmlng
2. Roadspreading
3. Pits
4 . Surface Water
Disposal
5. Wastehaulers
6. Burial or Landfill
7. Disposal Wells
(Class II)
8. Enhanced Oil Recovery
Injection Wells
9. Natural Gas
Processing Plants
10. Refining (Hazardous
Wastes)
11. Refining (Solid
Wastes)
Federal Statute Implementation
1. Safe Drinking Water
Act (UIC - Class II)
2. Clean Water Act
(NPDES)
3. RCRA - Subpart C
(Hazardous)
4. RCRA - Subpart D
( Non-hazardous )
On-Slte Off-Site
OtG OtG
Agency Other Agency Other
Prohibited Prohibited
Prohibited Prohibited
X X
X X

X
X X
X X

X X

X

X

X


X X

X X

X X

X X

On-Site Off-Site
OtG OtG
Asency Other Aeency Other
Prohibited Prohibited
X X
X Prohibited
X X

-- -- XX
X X
X X

X X

X

X

X


X X

X X
•
X X

x x

•~ On-Site Off-Site
OtG 0(6
AeencT Other AeenCT Other
X X
X X
X X
X X

X
X X
EPA EPA

EPA EPA

X

X

X


EPA EPA

X X

X X

X X

Note: OtG - Oil and Gas.  Numbers in parenthesis are number of non-oil  t  gat  agencies having dual  jurisdiction.  Memorandums  of  agreement may be in effect
      to reduce overlapping responsibilities.

Sources:  Interstate Oil Compact Commission, 1990; Nev Meiico Oil Conservation  Division.

-------
OJ
                                                                          TABLE  2.  AGENCY  JURISDICTION  BY ACTIVITY
                                                                             AND FEDERAL STATUTE IMPLEMENTATION
                                                                LOUISIANA                                NEW MEXICO
                                                                                                                                                   NORTH DAKOTA




ACTIVITY
1.
2.
3.
4.

5.
6.
7.

8.

9.

10.

11.

Landfanning
Roadspreading
Pits
Surface Water
Disposal
Wastehaulers
Burial or Landfill
Disposal Wells
(Class II)
Enhanced Oil Recovery
Injection Wells
Natural Gas
Processing Plants
Refining (Hazardous
Wastes)
Refining (Solid
Wastes)
On-SIte Off-Site
OIG OIG
Agency Other Agency Other
X X
Prohibited Prohibited
X X
x x

X
X X
X X

X X

X

----XX

X

On-Site
OSG
Aeency Other
X
X
X
X X

--
X
X

X

	 	

--

--

6Ff-site
OIG
Agency Other
X
X
X
X X

X
X
X

X

X

X

X

On-Site
OtG
Aaencv Other
Prohibited
Prohibited
X
X

--
X
X

X

	

	 	

--

Off-Site
OIG
Aaency

Other
Prohibited
Prohibited
X
X

X




Prohibited
X

X











X

x

x

Federal Statute Implementation
1.

^.

3.

k .

Safe Drinking Water
Act (UIC - Class II)
Clean Water Act
(NPDES)
RCRA - Subpart C
(Hazardous)
RCRA . Subpart D
(Non-hazardous )
X X

X X

xxx

X X

X .

X

X

X

X

X

X

X

X

x

x

x

x









x

x



                Note
                    :  OSG -  Oil  and  Gas.   Numbers  in parenthesis are number of non-oil i gas agencies having dual jurisdiction.  Memorandums of agreement  mar hr in fffrrt
                      to reduce  overlapping responsibilities.                                                                                     °           '       =i«.»«-i.
                                     applng respo


                Sources:   Interstate  Oil  Compact  Connission,  1990;  New Meilco Oil Conservation Division.

-------
                                                  OHIO
                                                         TABLE  2.  AGENCY JURISDICTION BY ACTIVITY
                                                             AND FEDERAL STATUTE IMPLEMENTATION
                                                                                          OKLAHOMA
                                                                                                                                   PENNSYLVANIA






ACTIVITY










CD
5
-J




1.
2.
3.
4 .

5.
6.
7.

e.

9.

10.

11.

Landfarming
Roadspreadlng
Pits
Surface Water
Disposal
Wastehaulers
Burial or Landfill
Disposal Wells
(Class II)
Enhanced Oil Recovery
Injection Wells
Natural Gas
Processing Plants
Refining (Hazardous
Wastes)
Refining (Solid
Wastes)
On-Site
OIG
Atencr Other
Not Authorized
X
X
Not Authorized

--
X
X

X

- _

_-

__

Off-site
OIG
ARency Other
Not Authorized
X
X
Not Authorized

X
X
X

X

X

X

X

On-Site
OSG
ARency Other
X
X
X
X

--
X
X

X

_ _

	

__

Off-Site
OIG
ARencT Other
X
X
X
X

X
X
X

X

X

X

X

On-SIte
O&G
AaencY Other
X
X
X
X

-.
X
EPA

EPA



-_



Off
OiG
AaencT
X
X
X
X

X
X
EPA

EPA







-Site

Other











x

x

x

Federal Statute Implementation








1.

2.

3.

4.

Safe Drinking Water
Act (UIC - Class II)
Clean Water Act
(NPDES)
RCRA - Subpart C
(Hazardous)
RCRA - Subpart D
(Non-hazardous)
X

X

X

X

Note: OIG - Oil and Gas. Number! in parenthesis are
to reduce overlapping responsibilities.
X

X

X

X

number of non-oil
X

X

X

X

( gas agencies having
X

X

X

X

dual jurisdiction.
EPA

X

X

x

Memorandums of agreement
EPA

x

x



may be in






y
A
effect
Sources:  Interstate Oil Compact Commission,  1990;  New Mezico oil  Conservation  Division.

-------
                                                          TABLE  2.  AGENCY JURISDICTION  BY ACTIVITY
                                                             AND FEDERAL STATUTE IMPLEMENTATION
                                                                                            UTAH
                                                                                                                                  WEST VIRGINIA




ACTIVITY
1.
2.
3.
t .

5.
6.
7.

8.

9.

10.

11.

Landf arming
Roadspreading
Pits
Surface Water
Disposal
Was tehaulers
Burial or Landfill
Disposal Wells
(Class II)
Enhanced Oil Recovery
Injection Wells
Natural Gas
Processing Plants
Refining (Hazardous
Wastes)
Refining (Solid
Wastes)
On-Slte
OtG
Agency Other
X
X
X
X

--
X
X

X

_ _



__

Off-Site
OSG
ARency Other
X
X
X
X

X
X
X

X

X

X

X

On-Slte
OtG
Agency
X
X
X
X

--
X
X

X



—

-_


Other
X
X
X
X

--
X




	

—

__

Off-
OIG
Aaency
X
X
X
X


X
X

X







Site

Other
X
X
X
X

X
X




X

X

X

On-Site
O&G
Aaencv Other
X
X
X
X

--
X
X

X

	

	

__

Off
OtG
AitencT
X
X
X
X

X
X
X

X

X





-Site

Other













x

x

Federal Statute Implementation
1.

2.

3.

4.

Safe Drinking Water
Act (UIC - Class II)
Clean Water Act
(NPDES)
RCRA - Subpart C
(Hazardous )
RCRA - Subpart D
(Non-hazardous)
X

X

X

X

Note: DIG - Oil and Gas. Numbers In parenthesis are
to reduce overlapping responsibilities.
X

X

X

X

number of non-oil
X







I gas agencies


X

X

X

having
X









X

X

X

dual jurisdiction.
X

X

x

x

Memorandums of agreenx
x







>nt may be in


X





effect
Sources:  Interstate Oil Compact Commission. 1990; Nev Mexico Oil Conservation Division.

-------
                                                         TABLE 2.  AGENCY JURISDICTION BY ACTIVITY
                                                             AND FEDERAL STATUTE IMPLEMENTATION
                                                  WYOMING


ACTIVITY
I . Landf arming
2. Roadspreading
3. Pits
4. Surface Water
Disposal
5. Wastehaulers
6. Burial or Landfill
7. Disposal Wells
(Class II)
8. Enhanced Oil Recovery
Injection Wells
9. Natural Gas
Processing Plants
10. Refining (Hazardous
Wastes)
11. Refining (Solid
Wastes)
Federal Statute Implementation
1. Safe Drinking Water
Act (UIC - Class II)
2. Clean Water Act
(NPDES)
3. RCRA - Subpart C
(Hazardous)
It. RCRA - Subpart D
(Non -hazardous )
On-Site
OIG
AnencT Other
X
X
X X
X X

--
X X
X X

X

	 	

_-

_-


X X

X

X

X

Off-Site
OIG
ARencr Other
X
X
X
X

X
X
X X

X

X

X

X


X X

X

X

X

Note: O&G - Oil and Gas.  Numbers in parenthesis are number of non-oil fc gas agencies  having dual  jurisdiction.   Memorandums of agreement may be In effect
      to reduce overlapping responsibilities.

Sources:  Interstate Oil Compact Commission, 1990; New Mexico Oil Conservation Division.

-------
STATE REGULATORY PROGRAMS FOR DRILLING FLUIDS RESERVE PIT
CLOSURE: AN OVERVIEW
Fredrick V. Jones
M-I Drilling Fluids Company
Houston, Texas
Arthur J. J. Leuterman
M-I Drilling Fluids Company
Houston, Texas
 Abstract

 In 1985 the Environmental Protection Agency began a study to evaluate drilling fluid waste
 disposal practices in the oil and gas industry. As a part of this study, a review of state
 agencies was conducted to determine the methods used and approved for disposal of
 drilling fluids and reserve  pit contents. The data provided was in summary form and
 provided a good overview of the issue. In 1989 we developed a questionnaire sent to states
 in which the bulk of the drilling operations occur. The purpose of the questionnaire was
 to provide a more detailed review of disposal methods and to determine the major concerns
 of the state agencies about  drilling fluid and reserve pit disposal practices. Questionnaires
 were also sent to federal agencies that control lands within various high oil producing
 states to determine their concerns. Drilling companies were also contacted about both their
 concerns and the current methods used for waste disposal. The data were  evaluated in
 regards to disposal methods being tested by the drilling fluid service industry to determine
 if these methods were addressing the primary concerns about  disposal practices.

 Data showed that the methods of disposal of  drilling wastes had not changed in the past
 few years for the majority of producing states.  Some new regulations have been developed,
 but most new regulatory programs are under  development and not yet promulgated. The
 driving forces changing  disposal  methods are future liability, landowner concerns and
 public awareness of the problem. It is hopeful that this review will provide a summary of
 disposal methods and associated problems, as well as an overview of the major concerns
 expressed by the various state and federal agencies, and the oil industry.
                                        911

-------
Introduction

In 1980, Congress amended the Resource Conservation and Recovery Act (RCRA) and
temporarily exempted several types of solid wastes from regulation as hazardous wastes
(1).  Among  the  wastes  exempted  were  wastes  associated  with  the exploration,
development, or production of crude oil, natural gas or geothermal energy. Under RCRA,
the Environmental Protection Agency (EPA) was to submit to Congress  a report on these
wastes  by 1982.  EPA  did not meet that  deadline,  and the  Alaska Center  for the
Environment sued. In December 1987, EPA submitted the final report to Congress (2). In
this report EPA surveyed the various states for drilling activity, state regulatory programs,
waste disposal programs and various problems associated with these activities. The final
conclusions of the study recommended continued exemption under RCRA. Further studies
on this  subject are ongoing at this  time.

Drilling fluid waste and disposal became a major topic of discussion in the oil and gas
industry. Studies by various industry and state agencies are underway to determine the
nature and extent  of the problem.  Methods of disposal and treatment of drilling wastes
have been reviewed (3). Although a great many studies are being conducted, no summary
of disposal methods and problems  associated with them has been developed. This paper
discusses such a survey. We attempt to summarize both state and industry involvement in
disposal practices,  problems found  and future concerns.

Survey  Report

The survey was  sent to eleven states in which major drilling activity occurred (Table 1).
State and federal agencies and  industry in each state were contacted. The survey sheets
sent to  the various state and federal agencies asked six major questions (Table 2). Over
90% of the survey sheets sent out  were completed. Industry was contacted through our
area offices for responses to the same questions. Each area office was requested to survey
their  respective customers and supply information about  disposal  methods used and
problems associated with their activities. All the offices surveyed responded to some degree.
Produced  water disposal was not an item discussed in the survey.  However, most of the
respondents included a discussion of the disposal of this waste stream.

Results  of Survey

Most  of the states  contacted have regulations dealing with the holding and containment
of drilling fluids and cuttings  waste. Guidelines are general in nature  for many of the
states. Some have  specific requirements which deal with the construction of the  pit and
containment  of  the waste.  Alabama is considering having pit construction approved by
engineers before use. Several states have strict regulations  dealing with the disposal of
waste with both a chemical and toxicity test required before disposal. Most states, however,
                                       912

-------
only require that the method of disposal prevent the contamination of surface or ground
water sources. In some western states they also add protection of wildlife and livestock.

The major concern of all the states contacted was the integrity of the reserve pits, including
construction and final closure. Other treatment concerns expressed were salinity (primarily
high chloride) contamination,  toxic  additives  or  heavy  metals,  and  hydrocarbon
contamination. Regulations, however, in most states only superficially addressed these
concerns. The exception to this rule is California which has both a chemical and a toxicity
requirement. Louisiana requires a detailed chemical analysis which relates to the method
used for disposal.

The report developed by  EPA  for  the  RCRA exemption discusses  the various state
regulations and summarizes various state activities. Thus, we will not  repeat their report
in this paper. For a thorough discussion of each state's regulations contact the state office.

Table 3 provides a summary of disposal methods used in the states surveyed. Percentages
do  not add up to 100% for each state.  In many  instances, more than one  method  of
disposal is used for the same waste stream. The waste stream is frequently separated into
liquid and solid portions for disposal. Rather than average the responses, percentages are
given in ranges. Between 70-98% of the reserve pit contents were treated by dewatering
the liquids and burial of the solids. Liquids  were removed either by evaporation  (the
primary method in dry areas) or removal offsite and injection downhole.  Flocculation  of
the solids from the liquids was also used in some areas. Liquids were treated in some areas
and then discharged.

Landspreading of waste material is used in Louisiana and Oklahoma, and to a lesser extent
in California and Texas. Landspreading of residue is used frequently in  many of the states
but was not clearly  stated as such in the survey. Landfarming, either offsite or onsite,  is
used in Louisiana and Canada. Landfarming differs from landspreading in that the mixture
is tilled more often,  analysis of the waste is conducted to determine correct mixture ratios
for  treatment,  and fertilizer is added to assist in degradation of the waste. Solidification is
frequently  used in  Michigan and Oklahoma  and  to  a  lesser  degree  in  California  and
Louisiana.

Treatment and discharge of the liquid phase is used in Louisiana and  California and has
limited use in other areas. Offsite disposal of waste is used in most states but at a low level
(usually less than 10% of the time). Biodegradation  is being tested in many areas but used
commercially,  to any extent, only in Louisiana. Injection of the drilling  fluids and cuttings
is being used in several areas. Either the liquid portion of the material  is injected or both
the cuttings and fluid are injected down the annulus. In California, mud and cuttings are
used to pack off closed wells. Produced waters are usually removed and injected downhole.
                                      913

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In some western states produced waters are used for irrigation and, if possible, livestock.
Oil muds are usually recycled and in some areas water-base muds are being recycled.

As noted in the survey, several methods are usually combined to dispose of drilling fluids
and cuttings. Typically the liquids in the reserve pit are allowed to evaporate and the solids
are buried onsite. If the area has a high rainfall, the liquids are hauled offsite and injected.
In some instances flocculation chemicals are added to reduce the solids in the liquid phase
before offsite disposal. In other instances the liquids are treated further and discharge while
the solids may be solidified.

In some cases, the solids  and some of the liquids are landspread and tilled into the
surrounding lease area. Another typical method of disposal is injection of the waste down
the annulus. In California,  muds and cuttings are occasionally injected down a well that
is being plugged and abandoned. Other systems are removed and recycled for further use
in the same drilling area. Offsite disposal consists of landfills, landfarming, incineration, or
treatment and disposal in commercial sites.

Summary of disposal technologies

Treatment offsite

Most offsite treatment systems process the mud and cuttings by solidification and burial.
Some landfarm the material to degrade the organics and allow dilution to reduce the salt
and metal loading. Some companies take all their mud and cuttings to incineration systems.
The cost for this process is high;  however, liability is reduced significantly and the site will
never come back to haunt you. A few companies biodegrade the material before burial or
landfarming while other companies recondition the mud offsite to  be reused.

Treatment onsite

Offsite treatment is sometimes required by law. However, where possible operators prefer
to treat the waste onsite to reduce costs. Treatment systems vary from simple discharge,
dewater/backfill or injection operations to  complex recycle operations. Treatment onsite,
of mud and cuttings to reduce the size  of the pit and recycle as much material as possible
is appealing to operators for environmental and economic reasons. The following discussion
details some of the methods discussed in the survey by industry, government, and oil field
service companies.

Discharge

Before the 70's, many drilling operations would discharge the water portion of the drilling
fluid  after completion of the well into a local stream or river. This practice was particularly
                                       914

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prominent where rainfall reduced the chances of the liquid evaporating in a short period.
Some states still allow the discharge of produced waters, if the water is of low enough salt
content, to allow its use for livestock and irrigation. Some states still allow the discharge
of treated reserve pit liquids if local water quality standards are met. Most states however
have banned the discharge of drilling fluid liquids directly into streams or rivers. In Texas,
Louisiana, and California a minor discharge permit must be obtained to allow discharges.
In Louisiana, the discharge of produced waters is still allowed under certain conditions.
Many western states still allow the discharge of produced waters with low chloride and
hydrocarbon content for irrigation purposes.

Dewater/backfill

The oldest and most common method of closing a reserve pit  is dewater/backfill. In the
most simplistic scheme the water in the pit is evaporated and the solids are covered with
the reserve pit wall and packed down.  Excess water can be absorbed by adding straw or
dirt to remove free liquids before the top soil is placed back on the pit. This is still the
primary method of closure. Liability for these sites is  under question.  No extra attempts
other than the clay and the  drilling fluid, are  made  to stop leaching of free metals  or
hydrocarbons. Dewater/backfilling is cost effective. Reserve pits with low weight muds, no
oil, and low heavy-metal content are dewatered/ backfilled with little or no impact to the
environment. If the mud system uses bentonite, the sealing capacity of the clay material
can reduce leaching from the site. Studies conducted on closed reserve pit sites, even on
weighted muds systems, show little or  no migration out of the pit (4).

Landspreading

Results of the survey indicated that in most states, low salt, non-oily muds are sprayed
from  the reserve pits out over the ground and allowed to  soak into the soil. In many
instances the farmers do not object to this treatment because they get added irrigation; and
the low weight mud system can  even  help condition  the  soil. If the salt content, oil or
heavy metal content  is too  high, this  method  of disposal may not be applicable. This
method usually requires the farmer's written consent. The solids are normally tilled into
the soil. In some areas the reserve pit is first treated by biodegradation to remove excess
oil  before a landspreading application.

In  Louisiana,  under 29B,  strict regulations  are now  in place which  control  the
landspreading of drilling fluids. Both onsite and offsite facilities have standards on heavy
metals, salt content and oil content which must be met before a  landspreading operation
may begin.

Landspreading of the water and solids is cheap, requires little investment in equipment and,
if properly conducted, can be very effective. The operator may have to hold on to the lease


                                      915

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for a longer period to allow the solids that will biodegrade to do so before returning the
property to the landowner. If the solids contain excessive salt, oil or heavy metals the area
may not be able to support plant growth and the area must be reconditioned. In the worst
case, contaminants from the landspreading operation can leach into groundwater sources
and possibly contaminate local drinking water supplies. In this event the cost of the drilling
operation will go up significantly.

Annular injection

When  a drilling operation is over and no commercial amount of oil or gas is found the
operator can inject the used mud down the annulus for disposal. One concern noted in the
survey, in using this method is that the casing protecting  any ground water source can
crack and expose the aquifer to the mud system. In some northern areas both the mud and
cuttings are injected downhole. The cuttings are first ground into a fine powder for easy
pumping, a  zone is found that is fractured and the mud and cuttings are pumped into the
zone  for disposal.  This is  a  relatively new  method of  disposal and the possible
environmental implications are as yet unknown.

Another use of injection systems is for produced waters. In most states this is the primary,
or only, method of disposal for produced waters. Injection systems are widely available and
produced waters  are  routinely transported off  site to  these  facilities. Most  injection
operations are regulated through the Underground Injection Control (UIC) program.

Solidification

In areas where dewatering the pit is not practical and hauling offsite for disposal is not
viable the operator  often turns to solidification. This process, first called thickening,
necessitated the used of straw  or dirt to stiffen the solids. Initially used to de-liquify the
reserve pit,  it became clear early on  that this method also resulted in the reduction of
heavy metals leaching from the pit. The operator has several choices for the reserve pit.
He can dewater as much as possible and solidify the remaining amount or solidify the
whole system. Solidification material  can be  cement agents, fly ash, kiln dust and/or
Portland cement. Several companies have developed polymers that can be used to solidify
the reserve  pit contents.  The earliest solidification  systems could not handle high oil
content or high salt content. Several  newer systems with mixtures of solidifying agents
with polymers can handle much higher levels of these contaminants.

This method can  be  expensive depending on the agents used and the size of the pit.
However, the advantages of being able to  leave the material on site  is appealing. The
process used is simple but to fix the more complex mud systems the solidification process
can become more  difficult and  more expensive. Oils and  salt can still inhibit the mixture
and allow leaching to occur at a greater rate  than desired. The solidified material can have
                                       916

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higher than normal pH levels which can impact plant growth when left onsite. This method
is used in California to develop a fixed granular pellet that is used as land cover in local
landfills. The material has also been used for road beds and pot hole fill. In South America
some companies are making bricks out of the material for foundation work.

Mobile Water Treatment - Flocculation

One of the methods of treatment of reserve pit waste is the use of polymer flocculation to
dewater the pit contents. The method has been used in the past. Earlier pits were built to
act as settling basins  allowing the solids to fall out and the water to be recycled. As in
water treatment systems, alum (aluminum sulfate) could be added to enhance the settling
properties of the solids. Later, polymers were added to do this job. Now treatment systems
are moved near the pit and recycle the solids through them. The polymer is added and the
mixture is processed using centrifuge equipment. The mud  systems need  to be watched
closely to prevent excess polymer from getting into the active mud system and flocculating
the solids while drilling.  This process of recycling for water is being used today in the
Rockies, South East and North Central areas.

Another use of the flocculation process  is to help in the dewater/backfill operation. In
Michigan, high salt content mud systems are dewatered using polymer flocculation. Salt
in the system will migrate to  the water phase during this process thus reducing the salt
content of the solids.  This allows the operators to bury the solids on site while removing
the high salt content water for disposal offsite.

Solids Control

One of the best methods to control and reduce the loss of mud and cuttings is through the
use of good solids control equipment. These devices reduce the need for treatment of the
solids and reduce the makeup mud needed to conduct the drilling operation. Solids control
will be discussed again in the waste minimization section and under oil muds.

The cost of oil muds is high, thus good solids control equipment on oil mud systems is of
great benefit. If properly used, the oil remaining on the cuttings can be reduced to less than
15%. Using this type  of equipment in conjunction with a good landfarming program can
be very effective in reducing the environmental impact.

Landf arming

Landfarming differs from  landspreading in that the ratio of waste to soil is  calculated and
measured for maximum processing. The soil is usually conditioned and fertilized to enhance
biodegradation of the organics. The soil/waste mixture is tilled more than once to increase
oxygen uptake in the  soil. Landfarming is used extensively in Canada and Louisiana. New
                                      917

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landfarm sites in Louisiana are not being developed and this method may see limited use
in the future.

The landfarming of oil mud  cuttings has been evaluated and tested in the U.S. since the
1950's.  The concept is to allow natural bacteria in the soil to degrade the  oil on the
cuttings thus  reducing any  environmental impact. In Canada the primary method of
disposal of oil based cuttings has been landfarming. Several concerns are the area of soil
needed to dispose of the volume of cuttings and the level of oil on the cuttings. The type
of oil, the internal  phase, and any salt  concentration. If the wrong ratios are used the
reclamation of the soil to allow plant growth can take upwards of 3-4 years. This is a long
time to  hold onto a lease area.

Waste Minimization

Waste minimization is becoming a key phrase in EPA. The government is researching new
and better ways to  reduce waste production.  Several waste minimization activities have
been introduced by the oil field service  companies.  Products are developed that are less
hazardous and more  environmentally sensitive thus reducing the need for treatment or
concern over disposal  (5). Operators are using fewer products for the job, and maintaining
the integrity of the  remaining products to enhance their ability to return unused product
to the supplier. According to the survey, the trend is to order only the amount of the
product needed. This  reduces oversupply at the rig site and the possible  need to dispose
of damaged product. Every attempt is made to use those materials at the rig site to reduce
waste buildup. Solids  control equipment  is used to reduce the amount of waste going into
the reserve pit. This reduces  the size of the pit and thus the overall reclamation of the site
when drilling is over. Operators are beginning to segregate the waste  material during
drilling by building reserve pits in segments. Each segment can carry a different type of
mud system. By doing this the least toxic mud systems can be landfarmed on site at a low
cost and the more toxic mud systems can be treated or removed offsite.

Oil fluids and cutting  disposal

Only 10-15% of the  muds used today are oil based. The possible problems of contamination
due to improper disposal are greater when using oil muds. Several  new technologies are
being tested and researched  on the disposal of oil based muds and cuttings.

Operators traditionally have used diesel based  oil muds for onshore  operations. The
operator now has the  ability to choose low toxicity oil based  muds,  e.g.mineral oil based,
or synthetic hydrocarbons. Unique internal phases  that are adapted to  low salt or ion
content that have  less impact  on plant growth are also being developed. These mud
systems can play a  major  role in allowing landfarming or other treatment methods that
otherwise would not be permitted.
                                       918

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Cuttings Washing

This method of cleaning oil-base cuttings prior to discharge is being used in the North Sea
today. The method has several adaptations, including washing with diesel, solvent rinses,
select washing, high power washing, etc. This method removes all but 10% of the oil on
the cuttings. However, newer regulations reducing the oil loading on the cuttings to less
than 10% are being proposed. Newer cuttings washing devices and mud systems are being
developed to meet this requirement. This technology can also be applied to  landbased
operations where the reduction of oil on the cuttings may be helpful. One of the problems
observed in the survey was what to do about the dirty wash water and how best to dispose
of this waste.

Distillation

By using an electric or a gas fired furnace, drill cuttings can be heated to high temperatures
thereby forcing the oil to vaporize. If the vapor is then placed into a condenser the oil is
returned  to a  liquid state  and reused in the  active mud- system. Water vapor can be
condensed and sent offsite for disposal, or if properly treated discharged under a limited
permit. Residual  emulsion and oil mud additives can also be separated in some of the more
advance units  for possible reuse. The solids are discharged into a  container for later
disposal.

The process is "off-the-shelf technology which has not  been applied to the problem of
drilling fluid treatment. The units, if not correctly built for drilling fluids, can be costly and
have a low efficiency. High salt contents of the fluids can  cause equipment corrosion,
particularly at  high temperatures. The high temperature  and water/oil vapors are a fire
hazard. Air emissions can be a problem and a permit for emissions may be required. If the
temperatures are not  controlled  the  oil can crack and the condensed material becomes
useless as a mud re-additive. The solids which remain can be concentrated with heavy
metals and may need further treatment to prevent environmental impact. The system, if
used correctly, can reduce mud bills, recycle expensive oil  and reduce the  volume of waste
generated. Several companies are now in the process of researching this technology and
one company has developed a unit for use offshore.

Critical Fluids

Critical fluids technology is based on  the same principle as the distillation unit. Instead of
heat to strip the oil off the cuttings it uses a gas under pressure. The gas at elevated
pressure becomes  a liquid  and washes the oil  off the  cuttings. Then, by releasing  the
pressure, the oil  is separated and is recycled  while the solvent becomes a gas  and is
recycled again. The process is expensive but eliminates  the high temperatures and air
emission problems.


                                          919

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Biodegradation

The biodegradation of oil and organics in a mud system has been going on for a long time.
Landfarming and the fertilization and  aeration of reserve pits are two forms of basic
degradation processes. Recently because of the 29B regulations dealing with oil content,
the use of in-situ biodegradation has increased. The latest technology is the development
of a treatment system where the temperature, oxygen, oil, cuttings, bacteria and nutrient
loads are all controlled. Under this process the oil content can be reduced very quickly to
levels as low as 1%. The primary problem then is the removal of the dirty water and solids
for disposal.

Bacteria may be inhibited in a high salt environment. Air emissions  should  not be a
problem but under intense culture this  may not be true. Under intensive culture a large
volume of water may be required. Excess need for water may prohibit the use of this
method in  some areas. In some instances this method may result in changing the disposal
problem from that of oil base cuttings to high volumes of dirty water disposal.

Incineration

Although this technology is very expensive, many operators are saying, "burn it." Future
liability is  reduced if the material is burned. The ash  is usually solidified to prevent the
leaching of any hazardous residue. In the long run this method may prove to be the least
expensive.  The cost of remediation of sites has increased dramatically over the past few
years.

Summary

The traditional method of disposal of drilling fluids and cuttings is dewatering and burial.
This was true when EPA conducted their study and is still true today, three years later.
However,  the increased attention to this problem has brought about a great deal of
research and  testing of newer methods of disposal  and will eventually lead to more
environmentally acceptable methods of  disposal. Environmentally safer products are also
being developed that will alleviate the disposal problem, both  in water-base and oil-base
mud systems.

One of the  primary concerns noted in  the survey  is the construction  and possible
breakdown of the reserve pit during drilling operations.  Survey responses indicate a high
degree of concern over this issue and we foresee imminent regulatory changes in the next
few years which will address this issue specifically.

An issue not addressed in this paper but noted during the survey is the increased awareness
and response to drilling operations by landowners and the public. Except for Louisiana,
                                        920

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new laws and regulations were not the major or even minor driving force in change.
Changes were occurring because landowners were becoming more aware of disposal
practices and requiring operators to adjust their methods  to meet future  land  use
requirements. Both industry and government noted the need to address this issue in a
realistic manner that both  protects the environment while limiting the cost on drilling
operations.

References

1.    Environmental  Protection Agency,  Hazardous Waste  and  Consolidated  Permit
      Regulations, Federal Register. 45, May 19, 1980.

2.    Environmental Protection Agency, Report to Congress: Management of Wastes from
      the  Exploration,  Development, and Production of Crude Oil,  Natural Gas, and
      Geothermal Energy,  EPA 530-SW-88-003, 1987.

3.    Hanson, Paul M. and Jones, F.V.,  Mud Disposal, an Industry Perspective. Drilling.
      47, May 1986,  16-21.

4.    Leuterman, Arthur J.J. et  al,  Drilling Fluids and Reserve Pit Toxiciry,  Journal
      Petroleum Technology. 40, November 1988, 1441-1444.

5.    Jones, Fredrick V. and Leuterman, A.J.J., Use of Less Environmentally Toxic Drilling
      Muds. PetroSafe. 89, October 1989, p 265-277.
                                    921

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                         TABLE 1:  STATES SURVEYED
                        Alabama
                        Alaska
                        California
                        Colorado
                        Kansas
                        Louisiana
                        Michigan
                        New Mexico
                        North Dakota
                        Oklahoma
                        Texas
                        Wyoming
                       TABLE 2:  SURVEY QUESTIONNAIRE


1.     Briefly discuss your state/federal restrictions dealing with reserve pits, drilling fluids
      and cuttings disposal.

2.     What are the major concerns in your state dealing with the disposal of drilling fluids
      and cuttings and reserve pits closure?

3.     May we have a copy of your regulations dealing with disposal operations?

4.     What methods of disposal are practiced in your state?

5.     Please describe the major problems you have noted with disposal practices in your
      state.

6.     Does your state plan in the near future to change disposal regulation in any way?
      If so, please described the changes proposed.
                                      922

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TABLE 3. DISPOSAL METHODS USED IN VARIOUS STATES BY PERCENT
METHOD
Dewatering/ backfill
Landspreading
Landfarming
Solidification
Discharge of Liquid
Flocculation
Off site Disposal
Biodegradan'on
Injection
Recycle
Other
AL
95
1-10
1



3-10

95


AK
80-95


1
1

1-5

10
(mud)
95
(liq)
1-5
1-10
CA
24
5-10

5-10
18
20-30
10-20

56
5-10
40
CO
98





1

1


LA
10
10
40
10
20-50
10

5
50
5

MI
50-90


25-90

1
10

90-100
(liq)


NM
98
1




1




ND
92


2


4

1
1
1
OK
60-85
<40

< 25
<]

5-10

1-5 mud
80-100
liq
10

TX
85
2
1
1

1
10


10

WY
70-95

<1
2-5
5-10
5
15

15
<1
<]
                         923

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THE STATES' REGULATION OF EXPLORATION AND PRODUCTION WASTES


Jerry R. Simmons
Director of Production Services
Interstate Oil Compact Commission
Oklahoma City, Oklahoma


The Interstate Oil Compact Commission has established a Council on Regulatory Needs to review the
states regulation of exploration and  production (E&P) waste.  As guardians  of the resource and
obligated to oversee its proper development and production in an environmentally sound manner, the
producing states are committed to the success of the Council's investigation of E&P waste management
practices and regulations.

The Interstate Oil Compact Commission (IOCC) is the organization of oil and gas producing states
dedicated to resource conservation, authorized by Art.  1, Sec. 10 of the United States Constitution and
ratified by Act of Congress.  The IOCC represents 35 states, 29 member and 6 associates, working
together in a program of waste prevention (fig. 1).  Individual state'legislatures have voted to become
an IOCC member which gives the Governor a vote on the Commission. The Governor may appoint an
official representative to the Commission to exercise that state's vote in the Governor's absence.

The IOCC  derives the bulk of its funds from the states; it does not receive any funds from petroleum
industry. Each member state contributes to the support of the Commission.  The IOCC further  is
engaged  in various specific projects in cooperation with  state  and federal agencies such as the U.S.
Environmental Protection Agency and the U.S. Department of Energy. It accepts funds from the federal
government in support of this work.  It also receives miscellaneous funds from seminars, professional
meetings, and publication of books.

The IOCC has been assisting states in developing their oil and gas regulatory programs since 1935.
More than  99 percent of the oil and gas produced in the United States is produced within the borders
of and is regulated by member states of the IOCC.

In January, 1989, the IOCC formed the Council on Regulatory Needs to  assist the EPA in determining
where the states' regulation and enforcement of existing programs could be improved.  The Council  is
comprised of 12 state regulatory  agency members. The  Council is supported  in its efforts by a nine
member advisory committee, of whom three represent state regulatory  agencies, three represent industry,
and three represent public-interest/environmental groups.  The Council is assisted by five representatives
of EPA, two from the U.S. Department of Energy, and two from industry, who act as official observers.
Governors George Sinner of North Dakota and Carrey Carruthers of New Mexico are co-chairs of the
Council (fig. 2).

An organizational meeting  of the  Council was held in February, 1989 in Denver, Colorado.  At that
meeting, a  committee structure  was formed with  the Technical  Committee consisting of three
subcommittees; Pits, Land, and Commercial,  and the Administrative Committee consisting  of  four
subcommittees; Personnel and Resources, Organization and Coordination, Statutory Authority, and State
and Federal  Relations.   At the Council meeting in June, 1989,  in Reno, Nevada,  the  Technical
Subcommittees submitted initial  criteria  for  discussion by the full Council.   The  Administrative
Subcommittees presented their first draft reports to the Council at its meeting in Tulsa, Oklahoma in
December  1989.
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In early 1990, the separate committee reports were revised and combined into a single document. This
document was presented as a draft final report at the June, 1990 IOCC meeting in Bismarck, North
Dakota.  From June,  1990 until August, 1990, final changes were made to the document so that the
council could present  its final report at the December, 1990 IOCC meeting in Phoenix, Arizona.

The purpose of the Council is to recommend effective regulations, guidelines, and/or standards for state-
level management  of oil and gas production wastes.  EPA has concurred in this purpose, stating that"
.  . . IOCC is leading an effort . . . that will use ... information gathered by EPA to develop IOCC
guidelines for state oil and gas waste management regulations"  (Lowrance 1989).  The technical and
administrative criteria proffered by the Council on Regulatory Needs will be published and disseminated
to the states as examples of the range of "elements" necessary for effective state regulatory programs for
E&P wastes.  The criteria by themselves are not intended to form the sole basis of any future federal
statutory or regulatory authorities that  may be sought by EPA for oil and gas production wastes.

The Council's criteria address waste management  practices that are unique to E&P operations and
wastes that were determined by EPA to  be exempt from the hazardous waste management requirements
of Subtitle C of RCRA.  These narrowly defined wastes include drilling muds and cuttings, produced
water  and associated waste.   Wastes that  are  uniformly regulated by RCRA hazardous  waste
management  requirements as  well as general industrial wastes such as solvents, off-specification
chemicals, commercial products, household wastes and office refuse are not addressed by these criteria.

These criteria do  not address disposal of produced water by injection or  surface discharge -- waste
management practices that are  regulated by EPA or by the states under authority  of the federal Safe
Drinking Water Act and federal Clean  Water Act.

An effective program for  the regulation  of E&P  wastes should  include,  at a minimum:  statutory
authority which adequately details the powers and duties of the regulatory body; statutory authority to
promulgate appropriate rules and regulations; statutes and implementing regulations which adequately
define necessary terms of art; provisions to adequately fund and  staff the program; mechanisms  for
coordination among the public, government agencies and regulated industry, and technical criteria  for
E&P waste management practices.

An effective state program should contain a clear statement of the program's goals and objectives. Such
goals  should include, at  a minimum, protecting  human health and  the environment  from the
mismanagement of E&P wastes while maintaining an economically  viable oil and gas industry and
encouraging  waste minimization as a means of achieving such a  goal.

These criteria are intended to provide guidance to the states in the formulation, development and
evaluation of oil and gas environmental regulatory programs.  Fundamental differences exist from state
to  state, and within regions within a state, in terms of climate, hydrology, geology, economics and
methods of operation which may impact on the manner in which oil and gas exploration, development
and production is  performed. State oil  and gas programs can, and should, vary from state to state and
within portions of a state.

The process by which these criteria are  incorporated into state programs is a function of and within the
discretion  of the responsible state agency. It is recognized that  state programs must vary in order to
accommodate differences in climate, hydrology, geology, economics,  and methods of operation or to
accommodate individual  differences in  state administrative procedures or law.  Furthermore,  in some
instances,  in  order to accommodate  regional, areal, or individual differences within a state, it is
appropriate for site-specific waivers or  variances to be allowed for good cause shown.
                                             926

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Basic Administrative program requirements for E&P waste should, at a minimum, include provisions
for permitting, compliance evaluation and enforcement.  The report further explains that:

"A state  must have a regulatory mechanism to assure that  wastes generated  during oil  and gas
exploration and  production operations are managed in an environmentally responsible manner.  A
program to achieve that objective may rely on one or more mechanisms, including issuance of individual
permits, issuance of permits by rule,  establishment of regulatory requirements by rule, issuance of
general permits, registration of facilities, and/or notification of certain  activities undertaken pursuant
to general regulations. The regulating state agencies should have authority to refuse to issue or reissue
permits or authorizations if the applicant has outstanding, finally determined violations  or unpaid
penalties, or  if a history of past violations demonstrates the applicant's  unwillingness or inability to
comply with permit requirements. Individual permits for specific facilities or operations should be issued
for fixed terms. In the case of commercial or centralized facilities, permits generally should be reviewed,
and revised if necessary,  no less frequently  than every five years.  Where similar requirements are
mandated by two or  more  regulatory programs being administered by the same  state agency, those
requirements should  be combined, in a common permit or otherwise, to assure  that the regulatory
process is made as  efficient as practicable."

State programs generally  should contain the  following compliance evaluation capabilities:

Procedures for the  receipt, evaluation, retention, and investigation for possible enforcement action of
all notices and reports required of permittees and other regulated persons.  Investigation for  possible
enforcement action should include determination of failure to submit these notices and reports.

Inspection and  surveillance procedures that are independent  of information supplied by regulated
persons  to determine compliance with program requirements, including:   the  capability to make
comprehensive surveys of facilities and activities subject to regulation in order to  identify a failure to
 comply with program requirements by  responsible parties; the capability to conduct  periodic inspections
 of regulated facilities  and activities at a frequency that is commensurate with the risk to the environment
 that is presented by each facility or  activity;  and the authority to investigate  information obtained
 regarding violations of applicable program and permit requirements.

 Procedures to receive and assure  proper consideration of information submitted  by the public about
 alleged violations and for encouraging the public to report perceived violations.  Such procedures should
 not only involve  communications with the public to apprise it  of  the process to be followed  in filing
 reports or complaints, but also how the state agency will assure an appropriate and timely response.

Authority to enter any regulated site  or premises in which records relevant  to program operation are
 kept  in  order  to copy records, inspect, monitor  or  otherwise  investigate  compliance  with permit
 conditions and other  program requirements.

 Investigatory procedures that will produce an appropriate paper trail in support of  evidence admissible
 in an enforcement proceeding.

 An effective state program should provide that a  state permit does not relieve  the  operator of the
 obligation to comply  with federal, local or other state permits or regulatory requirements.

 With respect to violations of the state  program, the Council believes that the state agency should have
 the authority to take  some or all of the following enforcement  action:  issue a notice of violation with
 a compliance schedule; restrain immediately and effectively any  person by order or  by suit in state court
 from engaging in any impending  or continuing unauthorized activity which is causing or may cause
 damage to public health or the environment; establish the identity  of emergency conditions which pose
                                              927

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an imminent and substantial human health  or  environmental hazard that would warrant entry and
immediate corrective action by the state agency after reasonable efforts to notify the operator have
failed; sue or cause suit to be brought in courts of competent jurisdiction to enjoin any impending or
continuing violation of any program requirement, including any permit condition, without the necessity
of a  prior revocation of  the permit; require by administrative order or  suit in state  court, that
appropriate action be undertaken to correct any harm to public health and the environment that may
have resulted from a violation of any program requirement, including but not limited to establishment
of compliance schedules;  revoke or suspend any permit upon a determination by the state agency that
the permittee has violated the terms and conditions of the permit, failed to pay an  assessed penalty, or
used false or misleading information or fraud to obtain the permit; or assess administrative penalties or
seek in court civil penalties or criminal sanctions,  including fines and/or imprisonment.

In  some states, enforcement  remedies  include  authorities  to cause  cessation  of  production  or
transportation of product,  seizure of illegal product,  and bond forfeiture.

Additional  Administrative program requirements  of  an  effective  state  program  would include:
contingency planning;  waste hauler certification; waste tracking; location of closed disposal sites; data
management;   sufficient  numbers  of  properly   trained  personnel; legal  support;  technical and
administrative support; properly trained field inspectors; adequate funding; formal agreements between
state agencies with E&P waste management responsibilities; and maintain coordination between state
and federal agencies involved.

The Council has recommended that the  following  technical criteria be a part of an effective state
program.

   •    Facilities and sites used for the storage or  disposal of wastes derived from the exploration and
       production of oil and natural gas should be operated  and managed at all times to prevent
       contamination of water, soil  and air, protect public health, safety and the environment, and
       prevent  property damage.

   •    Facilities and sites operated for the storage or disposal of E&P wastes should not receive, collect,
       store or dispose of any wastes that are listed or defined as hazardous wastes and regulated under
       Subtitle C of RCRA, except in accordance with  state  and federal hazardous waste laws and
       regulations.

   •    Technical criteria for siting, construction and  operation of E&P waste disposal facilities should
       be  flexible  enough to address site-specific or regional conditions, based  on findings by the
       regulatory agency.

   •    Disposal of untreated produced water, drilling muds, drilling fluids, and tank bottoms in municipal
       solid waste landfills should be prohibited. Low volume E&P wastes, such as oily rags and drained
       filters, and any other E&P wastes that are similar in composition to routine municipal solid waste
       streams may be disposed of in municipal  solid waste landfills.

   •    As in any aspect of waste management, there are some general, sound practices that should be
       employed.  These practices, which include waste minimization, not only serve to protect human
       health and the environment, but also tend to protect waste generators from  long-term liabilities
       associated with waste disposal.  As a rule-of-thumb, the choice of a waste management  option
       should be based upon the following hierarchy of preference:

            Source Reduction -- reduce the quantity and/or toxicity of waste generated;
                                              928

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          Recycling — reuse or reclaim as much of the waste generated as possible, and whenever
          possible, hydrocarbons should be combined with crude oil, condensate or natural gas liquids;

          Treatment — employ techniques to reduce the volume or the relative toxicity of waste that
          has been unavoidably generated;

          Proper Disposal - dispose of remaining wastes in ways that minimize adverse impacts to
          the environment and that protect human health.

  •    Nothing in these criteria mandates onsite testing for every hazardous constituent that may be
      present in E&P wastes. Rather, these criteria call for appropriate onsite testing of E&P wastes
      prior to disposal for such characteristics as organic content, pH, salinity, hydrogen sulfide content,
      and ignitability-the chemical characteristics that are thought to be the primary constituents of
      concern in E&P wastes. The Council recognizes, however, that waste management practices and
      regulatory requirements, would be improved by obtaining a more complete knowledge through
      testing and analysis of the range of hazardous and toxic constituents in E&P wastes.

The states are encouraged  to establish  and implement specific performance standards  and design
specifications based on site-specific or regional differences in geology, hydrology, climate and waste
characteristics.

The Council has made specific recommendations on  reserve,  production  and special purpose  pits
regarding permitting, siting, construction,  operation, and closure.  The Council's recommendation
identifies those items it feels each state should consider necessary for the states to properly regulate pits.

Those elements necessary for an effective state program to regulate, landspreading, burial and landfilling,
roadspreading, and commercial and centralized facilities are also included in the Council's report. Each
of these practices have been examined and specific technical, siting, construction, operating, and closure
requirements have been recommended.

The Council also recommended five items to consider for future  work:

 •     The Council encourages industry and individual states to increase their efforts to characterize
      chemical constituents of exploration and production wastes.

 •     The Council encourages research by industry, the federal government, state-affiliated academic
      institutions, and public-interest groups into effective ways of minimi/ing and reusing wastes
      generated in the nation's oil and gas fields.

 •     The Council recognizes that contamination problems exist from  the use of past management
      practices and from violation of regulations and laws.  As such, it recommends that IOCC, EPA
      and the states work together to evaluate and recommend remediation approaches.

 •     The Council recommends that IOCC review and act upon EPA's recommendations that may
      result from the agency's mid-course review of state UIC programs. IOCC should incorporate in
      these technical criteria any changes that may be needed to address problems or improvements
      in state-administered UIC programs.

 •     The Council encourages the state and federal governments to examine the benefits and economic
      and energy impacts of changes in E&P waste managements requirements.

 Finally, the Council issued the following implementation strategy:
                                            929

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This report represents lOCC's initial effort to help the states and EPA improve E&P waste management
programs. This report:

  •   Demonstrates the commitment of the  governors of oil and gas producing states, EPA, state
      agencies, environmental groups and  industry to work together for environmental change and
      improvements;

  •   Serves as a model for future efforts and substantiates lOCC's position as an appropriate forum
      to  develop  comprehensive  approaches to  multifaceted and  complex oil  and gas related
      environmental issues; and

  •   Establishes a baseline of performance that can be used for both the administrative and technical
      aspects of E&P waste management.  This baseline is  useful to federal and state regulators,
      legislators, and oil and gas operators.

To achieve successful implementation, the Council recommends the following strategy:

  •   Secure grants to provide adequate funding for implementation of follow-up recommendations and
      continued active participation of all affected parties.

  •   Communicate the criteria of this report to  EPA, state agencies, operators, and other interested
      parties through direct contact, at E&P waste management conferences and symposia, in a series
      of one-day workshops hosted by state agencies and involving regional EPA offices, state and tribal
      agencies,  oil and gas operators, trade  associations,  environmental groups,  and through  other
      mechanisms as may be appropriate.

  •   Continue  to build consensus and  improve  this  document. To this end, IOCC plans to widely
      circulate it to federal agencies (EPA, DOE, DOI), state oil and gas agencies, state environmental
      agencies,  and  national and regional  trade associations, seeking  endorsement  as  qualified
      endorsement. The Council further recommends updating this document every two years.

   •   Use this document as a basis for conducting IOCC coordinated peer reviews  of state E&P waste
      management programs and as a basis for  peer review of federal agency programs.  Teams of
      senior regulatory personnel should visit agencies and review programs using this document as a
      baseline of performance and for making recommendations for improvement.

      Use IOCC  as a  clearinghouse for changes and revisions to state and federal regulatory and
      legislative programs.

   •   Pursue improvements in data management, waste characterization, and other areas.

The IOCC has just begun work with the EPA on a state review program, a training program, and a data
base management program.

In  conclusion,  the  Governors  and  Official Representatives  of the IOCC  are committed to
environmentally  sound  practices regarding E&P wastes  and continue to support the Council on
Regulatory Needs  as a unique forum where interested parties can work together for improvement in
environmental regulation.
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Membership of the IOCC
                  I • I  Member Slates
                  fc< - -;•)  Associate Member Slates
       Fig.1
       931

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                          IOCC  COUNCIL ON REGULATORY NEEDS

                                                Council Memben

Member                              Snbco"""'ncC                                                    Affiliarin.,
Donald B. Basko 	Pits	Wyoming Oil & Gas Conservation Commission
J. Patrick Batchclor  	Administrative Committee Chairman  	 Louisiana Dept. of Natural Resources
William R. Bryson  	Technical Committee Chairman	Kansas Corporation Commission
Tom Edmondson 	Land	 Illinois EPA
James E. Erb	Organization and Coordination . . . Pennsylvania Dept. of Environmental Resources
J. Edward Hamrick  	Pits	West Virginia Dept. of Natural Resources
Mike Bates	Land	  Arkansas Pollution Control and Ecology
Jack Badgett  	Commercial	  Oklahoma Industrial Waste Division
Jeff Mach	Pits	Alaska DepL of Environmental Conservation
M.G. (Marty) Mefferd 	State and Federal Relations	California Dept. of Conservation
Jerry W. Mullican	Organization and Coordination	  Texas Railroad Commission
                                                 Advisory Panel

Patti Saunders  	Land	Alaska Center for the Environment
Randolph C. Bniton	Statutory Authorities 	TIPRO
James W. Collins  	Commercial	  American Petroleum Institute
Charles D. Davidson	Personnel and Resources	  Oklahoma Corporation Commission
David M. Flannery	Statutory Authorities 	  Appalachian Producers
Philip M. Hocker	Statutory Authorities 	Mineral Policy Center
Terri Lorenzon	Organization and Coordination	Wyoming Environmental Quality Control
Michel J. Paque	State and Federal Relations 	 UIPC
Chris Shuey  	Commercial	 Southwest Research and Information Center
William R. Smith  	Pits	  Colorado Oil &. Gas Conservation Commission
                                                   Observers

Bill Hochheiser  	Pits	Department of Energy
Nancy Johnson	State and Federal Relations	Department of Energy
Harold W. Yates  	Land	  American Petroleum Institute
Joel H. Robins	Pits	  American Petroleum Institute
Charles W. Perry  	Commercial	  Environmental Protection Agency
Dave Bussard	  Environmental Protection Agency
Mike Fitzpatrick	  Environmental Protection Agency
Bob Tonetti	  Environmental Protection Agency
Melissa Ward	  Environmental Protection Agency
                                                 Committee Members

J. Patrick Balchelor, William R. Bryson, Tom Edmondson, James E. Erb, David M. Flannery, Philip M. Hocker, Terri Lorenzon.
Chris Shuey, Bill Hochheiscr, Nancy Johnson, Harold W.  Yates

                                               Fig. 2
                                               932

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A STUDY OF THE LEACHATE  CHARACTERISTICS OF SALT CONTAMINATED DRILLING WASTES
TREATED WITH A CHEMICAL  FIXATION/SOLIDIFICATION PROCESS
L.  Roberts, Mobil Exploration & Producing U.S., Inc.
G.  Johnson, PhD., Oklahoma State University

Introduction

Geologic evaporite  and salt deposits are often encountered during oil and gas
drilling  operations.   Because  of  the deleterious  effect  of  salt to  the
surface  biological  environment (e.g.  soil  and  vegetation)  the  disposal  of
salt is closely  regulated by state and federal agencies and must be carefully
undertaken.

Generally,  salt  contaminated  drilling wastes  are typically  either injected
into an approved  disposal well;  disposed of  offsite in  commercial surface
impoundment  facilities;  contained  and  eventually  (by  evaporation  or  CFS
treatment) buried  in onsite noncommercial reserve  pits or  drilling sumps;  or
spread  in calculated amounts over the land,  as in soil farming.

The burial of  salt  contaminated drilling wastes  is  a common  practice and one
of  the most  cost  effective  methods  for disposing  of these type  wastes.
However, concerns have been raised  in  recent years  related to this method of
disposal  by environmental groups,  as well  as  soil  conservation  and  water
quality control  agencies.

Of particular  concern is  the  effect these salt  contaminated  pit  wastes have
upon soil productivity (in the near proximity to the pit burial site) as well
as the  potential for  migration of the salt  out  of the buried mass  and into
nearby  ground water sources (aquifers).

While ~it  is generally  accepted that  salt  contaminated  wastes which  are
covered with  an insufficient  layer of top  soil  or overburden material will
inhibit or, in some cases, totally prevent root development and plant growth,
the  potential   pollution  of  adjacent  freshwater  shallow  aquifers  is  a
complicated issue and the subject of continuing debate.

The oil and gas  industry must be committed to the care and safekeeping of our
environment and  work toward the development of technologies and methods aimed
at minimizing, recycling,  and disposing of wastes generated in the process of
exploring and developing our nations energy resources.

In keeping with  that commitment, Mobil began, in the early 1980's, to examine
new and better  methods for  disposing of  drilling wastes at the  site upon
which those wastes were  generated  as opposed  to hauling  the   same  wastes
off site to commercial disposal facilities.

A technology which  lends itself to this onsite disposal practice is a process
commonly known as  "Chemical Fixation and Solidification", (CFS).
                                    933

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While this technology  has been in  commercial existance for more  than twenty
years,  only  in  the  last  ten   years  has   it  attracted  the  attention  of
environmental  scientists  and  engineers,  regulatory  officials,  and  waste
generators.

The CFS process  involves  the  adding and mixing of a chemical  agent(s)  to the
waste material  for the purpose of  fixating,  stabilizing, and  solidifying the
waste  material.  These terms  are  used  interchangably by the  industry  to
describe  the  treatment  of  semi-solid  wastes  to  form  a   "quasi  monolithic"
solid -relatively  impermeable to  percolating  surface water.

While the solidified waste does not result  in a mass with the  characteristics
of  concrete  or  rock,  such   characteristics  as   compressive  strength  and
physical  stability are manifested  to a  significant degree.  The sequence  or
method by which  the  CFS material  is added and blended can  be  as important  as
the chemical agent(s)  selected.
                             r
If rain or other surface waters cannot penetrate the treated waste  mass,  then
the soluble salts  contained  within the waste mass  will not provide a  source
of groundwater or  other environmental contamination.

The  following  study  was  undertaken  to determine the  effectiveness  of a
commercially  available  solidification process,  SOLI-BOND (R),  a patented
process developed  by the  Soli-Tech Corporation, in controlling the amount  of
salts  and  selected  ions that   could  be  leached  from carefully prepared
drilling waste  samples.  The effect of a  plastic cover  (raincap) as a  barrier
to percolating water was also examined.

Methods and Materials

An indoor lysimeter study was initiated in  September, 1989  to  study the  effect
of percolating water on the movement of soluble salts from prepared drilling
wastes treated with a  solidification process  called SOLI-BOND.   The study was
conducted at Mobil's Stillwater,  Oklahoma research  facility.

Twenty  four  lysimeters  were  fabricated  from  55  gallon steel  drums.   Cone
shaped galvanized  sheet  metal funnels were installed in the drums 12  inches
above  the  bottom.  The cone tapered to two inches  where it was  welded to a
steel pipe bib  in  the  center of the barrel's  base.

The barrel lysimeters  were  elevated off  the  floor  to accomodate three  quart
capacity  plastic  trays to  collect  the  drainage solution  (leachate).   Each
barrel was lined with  a  heavy duty plastic  to provide an impervious interior
surface to the barrel  lysimeters.

River sand, thoroughly washed and cleaned,  was placed in the  lysimeters  to a
level  two inches  above  the  top  lip  of  the  interior  cone.  Tap  water  was
sprinkled  into  each lysimeter  to  settle the sand  and  the excess water  was
discarded.

The simulated drilling waste material was prepared  by mixing a 100  pound sack
                                     934

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of dry gel  (bentonite) with water  into which had  been dissolved five  pounds
of granular table  salt  (NaCl).   Mixing  was achieved using  a  conventional
mortar mixer and  adding enough freshwater to  form  a thick gel material.   The
calculated  salt concentration  for all samples was  35,000  ppm on  a dry  weight
basis.

Fourteen  batches  of  the prepared  gel were  mixed  and stored  in bulk  until
treatments  were  imposed.   Treated  samples  were  prepared  by  mixing  the
chemical  solidifying  agent  at  three different concentrations on a pound/cubic
foot basis.  The  actual concentrations used are not disclosed in  this report,
in  agreement  with,   and  being  the  intellectual property  of  the Soli-Tech
Corporation, owners of the  patented process.

For the  purpose  of this  study,  the three treatment  levels  were described as
"A" (being  the lowest treatment level), "B" (being the next highest treatment
level),   and   "C"  (being  the  highest  treatment   level).   Control  samples
receiving no  solidification treatment were also prepared making  a  total of
six sets  of four  treatment  levels (0, A, B, & C).

In  addition to the  chemical solidification agent, each  treatment was  mixed
with sieved,  moist clay  loam  soil  to duplicate  a  technique  developed by  the
Soli-Tech Corporation to reduce  the treatment and  closure  costs  of drilling
sumps in Kern  County, California.

The mixture used  consisted of  one  part soil  material  to  five parts drilling
waste material.   Each  treatment  was mixed  individually,  by  hand, using five
gallons   of prepared  drilling   waste  material,  the  designated weight  of
the CFS  material,  one  gallon of  soil  material,  and fresh  water added  as
needed to develop a  thick paste consistency.

The final  mixed  samples  (treatments  and controls) were  each  transferred to
wooden forms which  had been placed  on top of  the sand which partially  filled
the barrel  lysimeters at  this point  in the  experiment.  The wooden   forms
represented a  cube without a top or bottom of 1 ft. X 1  ft.  XI  ft.  (inside
demensions).   The  mixtures were  then carefully  packed  into  the forms  to
prevent  air pockets   or  voids  in   the  resulting solidified  cubes of   waste
material.

The space between the inside  wall  of  the lysimeter and  the  outside  wall of
the forms was then  packed  with  wet sand so  that  the forms  could be  raised
after each sample of  the prepared waste material was  properly  placed  in  the
forms.

This block forming and placement technique resulted in the creation of  a cube
shaped block  which  would be  totally encased in  an inert washed river sand
media.  In this manner, six complete sets of  the four  sample treatment  levels
were prepared.

The wooden  forms were removed  from the  lysimeters  after a 30  day "curing"
period had been  observed in which the blocks were allowed to set  up.   The
remaining space  in the lysimeters was then filled with washed river sand to
                                     935

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the top edges of  the  blocks.  At this point,  both treated and control samples
were  randomly  selected  to  receive a plastic  covering   ("raincap").   The
raincaps were evaluated as  a  part  of the study protocol.

Pieces of 4 mil plastic were  placed over the top and extended two inches down
the sides of  12 randomly  selected sample blocks (treatments and controls) to
result in three replications  of  treated and control samples, with and without
raincaps.

After  the  raincaps were  installed,  the barrel  lysimeters were  filled  with
washed river  sand to  within  two  inches of  the  top  of the  lysimeters.   See
"fig. 1" for  an illustration  of the barrel  lysimeter  design,  functional  use,
and placement of  the  sample blocks.

On the same date  that  the preparation of the lysimeters and sample blocks was
completed,  the  addition  of  "simulated rainfall"  was  commenced.   This  was
achieved by placing a  plastic water reservoir tray on top of the sand in  each
of the lysimeters and  applying two separate one inch irrigations.

The plastic reservoir  trays were prefabricated with 1/2 inch holes drilled in
their  center  to allow the  water to escape  the trays into  the  sand  directly
above  the  buried  sample blocks.   The  one  inch irrigations drained from  the
reservoirs over an approximate two day  period.

Following  each  two-inch irrigation,  and just  prior  to the next  irrigation,
the  drainage  solution (leachate)  was collected,  the  volume measured, and a
sub-sample retained for  laboratory analysis.  Each set  of  leachate  solutions
was  analyzed  for electrical  conductivity  (E.G.) as  well  as chloride  (Cl),
Sodium   (Na),   and   Calcium   (Ca)  concentrations.   Calcium   analysis   was
discontinued  after   the   eighth   two   inch  irrigation  set  because   the
concentration  in the leachate  was  not   significantly  greater  than   the
background irrigation  water (tap water).

Analysis  were performed  by  Oklahoma State  University's Agronomic  Services
Laboratory.   Results   of  the  E.C.  analysis  were  converted to  total  soluble
salt  values  (TSS)  by  the standard conversion  (660  X E.C.)  expressed in
micromhos/cm.   The  total  amount  of  salts  and  specific ions collected  from
each   irrigation  was  adjusted  by  subtracting  the  calculated  amount of
background  salts naturally  ocurring  in the  tap water  used  for  the  test
irrigations (448  ppm  TSS,  191 ppm  Cl, 80 ppm Na, and 32 ppm Ca).

Treatment  effects were evaluated  statistically by comparing  treatment  means
to  a  calculated  least   significant difference  (LSD)  after  performing an
analysis of variance  for  a 2  X 4  X  12  (including time)  factorial arrangement
of treatments.

Results and Discussion

Soluble Salts:   Salts leached from  the sample blocks  (treated  and  controls)
for  each  irrigation  are  reported in "table  1".  These values show a  very
large  initial quanity  of  salts leached  from the control blocks with the first
                                      936

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two (combined)  two-inch  irrigations.   This  occurred  even  for  the control
sample  blocks  with  protective  raincaps.   The  results  of  the  successive
irrigation applications are graphically illustrated in  "fig. 2".

By comparison,  very small amounts of leachate were collected from the treated
sample  blocks until  after four  inches of  water  had been  added.  Apparantly
a slight  movement of water into  the  treated blocks occurred during the first
two irrigation  sets  as  the  dry exterior  surface  of  the  treated  blocks
adsorbed  the free  water across  their  surface.  A negative value  for the  "B"
treatment  with   the   raincap  is a  result of  this   initial  "wetting   up"
phenomenon.

This effect is not, however,  an artifact of the  experimental  procedure.  It
should  also  be  expected   to   occur   in  field  applications  of  chemical
solidification  and  represents  a  positive  aspect  of  the  solidification
process.

Subsequent irrigations continued to cause significantly large amounts of salt
to leach  from the  control blocks until after  a total of  16 inches  of  water
had been  applied (8th irrigation  set).  After  this  point, the  amount of salt
leaching  from all the blocks (treated and controls) was small and significant
differences (0.75%) were found for only the highest treatment rate "C".

The amount  of  salt  leached from the  treated  blocks was  consistantly  less
than the  control blocks both with and without raincaps after each irrigation.
The cumulative effect of  treatment  is  shown by the percentage  totals  at  the
bottom  of "table 1".   These  values clearly  show  the beneficial affect  of  the
CFS process on reducing salt leaching from salt contaminated drilling wastes.
Even the   lowest  treatment  level  "A" resulted  in  approximately  a  100 %
reduction   in   salt   movement.    Higher  treatment   levels   resulted   in
progressively greater reduction in salt movement, as might be expected.

Covering  the waste sample blocks with a raincap  significantly  reduced  salt
leaching  by an overall  average of 10  % of  the total salt  leached  (27  %  vs.
17 %).  The "C"  treatment was the most effective when combined with a raincap
which reduced salt leaching from the  waste mass  from  46 % to 9 %, a  five
hundred  percent   decrease   in   salt   movement.    "Figure  3"   graphically
illustrates the  cumulative  effect  of treatment   versus non-treatment   and
further illustrates the data provided in  "table 1".

Chlorides:  The  major  concern   in disposing of  salt  contaminated  drilling
wastes  is usually focused on chlorides because the chloride ion is relatively
easily  leached into groundwater  under certain  conditions (groundwater  lying
in  near   proximity  to   the  pit,   permeable   underlying  soils,   fractured
underlying  soils   or  rock).   When  this  happens, groundwater use may  be
affected  and responsible parties may be required to clean up the contaminated
groundwater at great  expense.

Results of chloride analysis -of leachate  from the lysimeters show a trend  for
Cl  leaching  similar  to  that  described  for  soluble  salts with  regard  to
treatment effect.   It should be noted,  however, that Cl measurements were


                                     937

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direct  analysis  whereas   soluble   salts  were  estimated   from  electrical
conductance of the leachate.

The greatest amounts of Cl were removed  from  the  drilling waste sample blocks
with the  first  irrigations leaching through  the  lysimeters. Each  subsequent
irrigation  usually  resulted  in  less   Cl  leached  than  for  the  preceding
irrigation.  Effectiveness of treatments is  clearly seen  by  comparison of
percentage Cl leached in the first few irrigatiom sets  and percentage totals.

Without any  CFS  treatment, 31.9  %  of  the chloride  initially present in the
control sample blocks was  leached out  after  24 inches of  irrigation  or  about
one-third  of the  total  available  for   leaching.   Placing  a  raincap  over
sample blocks significantly reduced  the  total percentage of  chloride leached
to about two-thirds to one-half of that  of the unprotected blocks.

The greatest reduction  in chloride  leaching  resulted from CFS treatments at
all levels applied in the  study.  The lowest  treatment  rate,  "A",  cut in half
the amount of  chloride  leached from the waste blocks,  with and without the
existance of raincaps.   Higher levels of treatment  further reduced  chloride
leaching, but the change was not  as  dramatic.

Chloride leaching approached a zero  level with the final  irrigation  sets for
all lysimeters  yet 85  to 95  %   of  the  initial  Cl  was  still  available for
leaching  in  the treated  blocks.   This  85  to 95 % represents  an  excellent
control factor on  the migration  of  chloride  out  of  the treated waste  mass,
which is one of the primary objectives of pit waste CFS  treatment.

A  logical explanation  for  this excellent   fixation/stabilization  property
exhibited in the treated blocks is  that  as  a result of  the solidification of
the waste mass, water cannot physically  percolate through  the treated blocks,
but rather passes across the top  and down along the sides  of  the block.

In such  a process,  the only Cl  leached  from the buried solidified waste is
that which  diffuses  across the  side  surface  exterior  and is  then washed
downward in percolating water.  This process would also  occur for  Cl  movement
from the surface exterior of the  top of  the blocks without raincaps.

Since  Cl  migration by  diffusion would  appear to be  limited  to the  outer
exterior  of  the block  surface,   once  Cl from this  outer exterior had  been
removed by the  erosion  process,   additional irrigations  would be  ineffective
(as was  subtantiated  by the test data).  Subsequent coring  and analysis of
the  sample  blocks  confirmed  the  fact   that the  migration of  Cl  occurs,
primarily, along the extreme outer exterior of the block.

Diffusion  is  dependent   upon  a  carrier   medium;   in  this   case water.
Unsolidified drilling wastes present the  best medium  for diffusion  because
they  are  solution  saturated.    By comparison,   the   treated  blocks  were,
initially  unsaturated and had  a much lower  free water content  due to the
chemical  reaction  of the  CFS process   and  the  formation  of  cementitious
structures which takes place during  the  curing process.
                                     938

-------
Sodium and Calcium:  The percentages of  sodium and calcium  leached from  the
blocks was observed and tabulated.  These data are very similar to that  shown
for the  chloride ion  and do  not  provide any  additional  insight  into  the
leaching  mechanism or effectiveness of the treatments evaluated.

Summary and Conclusion

The compressive  strength  of  the  treated blocks  appear  to  be  more  than
adequate  to  support the  bearing loads  associated  with post  drilling,  well
head activities (e.g., well completions and equipment installation).

Solidification of salt contaminated drilling wastes using this CFS process at
three  different  concentrations  was  effective in reducing  leaching  of  salt
two to five hundred percent.   Without treatment,  46 % of the salt was  leached
from  the  blocks  after 24 inches  of  simulated  rainfall  was  applied.  With
treatment, the salt leached was  reduced to 17 %.

With the  lowest treatment level  of  "A",  the  leached salt was reduced to 23.6
percent of the total salt available for leaching.  The next highest treatment
level  "B" ,  further  reduced salt  leaching  but the reductions  were  not  large
and only  the  highest treatment  level  "C" was statistically better than the
"B" in reducing salt leaching.
Adding a raincap or plastic cover over the treated and control blocks further
reduced the percentage of  salt leached.   The effect of  a  raincap on the "A"
treatment reduced the salt leached to  17.5  % of the total salt available for
leaching. Adding a raincap to the "B" treatment reduced  the salt  leached to a
dramatic 10.5 %.  Salt leaching was reduced  to 9 % in the  "C" treatment.

Of  equal  importance  to  total  leachabilty  control  is  the  rate  at  which
leaching occurs.  If a constituent  (e.g.  salt)  contained within a waste mass
is  released  to  the  surrounding   environment  at   a  slow  rate  and  low
concentration,  it  presents no harmful  affect  to  soil  productivity  or  the
quality of groundwater.  Such  a leaching process  tends to lessen the harmful
impact of buried wastes over time.

This  study  clearly indicates that  the  use  of  this   particular  chemical
solidification process, does in fact reduce  the amount and rate at which salt
will migrate out of a salt contaminated waste mass treated with the  process.

Using sand as  the  soil media  in  which  to bury the  sample blocks provides a
very  realistic  and  severe environment  in  which  to  test any  CFS  process.
Sand, unlike  more  typical  soils  provides  no appreciable  impermeability  or
obstruction to the free flow of percolating  fluids.

The use  of plastic covers  (raincaps)  was found  to be  an  effective tool in
further reducing the amount and rates  of salt leached. Likewise, without the
early compressive  strengths provided by  chemical  solidification, the proper
and  timely  installation  of   a  plastic  raincap  would  be  difficult  or
impossible.


                                      939

-------
                                TABLE  1
      Effect of solidification and raincap treatments on total  soluble
      salts* leached from prepared drilling waste by 12 successive two  -
      inch irrigations^	
                                  Treatments***
Soli-
Bond
Irr.**
Set
2
3
4
5
6
7
8
9
10
11
12
Totals




11
7
3
4
3
6
2
2
1
1
1
46
0



.8
.29
.38
.26
.44
.13
.46
.15
.78
.87
.52
.1
A
Mr\ v
-— no r


1.25
3.37
1.63
2.97
2.37
4.53
1.71
1.56
1.53
1.45
1.28
23.6
B
aincap


0.
2.
2.
2.
2.
4.
1.
1.
1.
1.
1.
22.
o.

20
81
37
74
06
97
68
66
41
49
20
6
C

0

of initial tc
0.18
1.98
1.40
1.96
1.79
3.85
1.60
1.16
0.95
1.60
1.23
17.7
9.88
3.57
1.40
2.30
1.78
5.06
1.72
1.53
1.48
1.63
1.12
31.5
A
- With
•»+• = 1

1.71
1.87
1.27
1.94
1.49
3.20
1.24
1.24
1.14
1.18
1.19
17.5
B
raincao


^ •
1.
0.
1.
0.
2.
0.
0.
0.
0.
0.
10.


21
18
75
27
93
70
97
83
65
77
63
5
C



0.37
0.75
0.44
0.91
0.92
2.35
0.72
0.58
0.55
0.76
0.67
9.0
   * Values  are an average  of  three replications.  Least
significant  difference for  comparison of values for each
irrigation  is 0.76 and for  Totals is 4.12 at the 0.05  probability
level.

 ** Two-inch irrigation set.   Set one and two were combined.

*** Numbers  after the heading  Soli-Bond refer to the multiple
treatment  levels of Soli-Bond.
                                  940

-------
                    FIGURE 1
Design features and functional  use of the barrel lysimeter.
                            H2O Leachant
           \> i^^^^^^'^^^^^^W^^^''^/.''^^^^^^1
 H2O
   +
 Nacl
                Waste
               Sample
                Block
•
         • 0
       H2O
                               /Washed River
                                 Sand Media
                                 Leachate
           LC. Roberts, 1990
                        941

-------
                            FIGURE 2
   Effect of solidification and raincap treatment on the percentage of
   the total salts leached from prepared drilling waste by 24 inches of
   simulated rinfall.	__»_———~_
SALT LEACHED FROM  PREPARED DRILLING  WASTE


/

s* .'
/ /
/
s / A
- //

:/ ^
F=*
	 v
	 '/,
\ 	 Y'
	 :/
^=4
L.C-. Roberts. 1990








!
1
1 If
i
'/ ...
* *•
> 	 •—
9 . 	

4
=ai

pn

/
/
^
^
/
it!


iJ/
ou
45
40 .-,
35 o
30 o
._/
?r>
20 o
15 ^e
in
"J 0
— 0 IJ1
/L5D
\lo Fo i ncop
x
5y ' With Ro i neap
                  A          B
              Soli-Bond Rote
                               942

-------
                         FIGURE 3
Effect of  solidification  and raincap treatments on  salt leached
from prepared drilling waste by 24 inches  of simulated rainfall.
            SALT  LEACHED  FROM  PREPARED

          DRILLING WASTE,  WITHOUT RAINCAP       ^
                                                 '°   a
                                                 to   o
                                                     a
                                                    
-------
                          FIGURE 4
Effect of solidification and raincap treatments on chloride leached
from prepared drilling waste by 24 inches of simulated  rainfall.
             CHLORIDE  LEACHED FROM PREPARED

             DRILLING  WASTE. WITHOUT  RAINCAP
                                                        o
                                                       — /
                                                        o
        2   3  4  5  6  7  8   9  10 II  12
                 Irrigotion Set
             CHLORIDE LEACHED FROM PREPARED

               DRILLING WASTE, WITH RAINCAP
                                                       u
5  6  7   8  9  10
 I r r i go t i on Se t
                                    12
                                                    LSD
                                                        D
                                                       —^
                                                        O
                                                       u
                             944

-------
SULPHUR BLOCK BASEPAD RECLAMATION PROGRAMS UNDERTAKEN  AT  THREE FACILITIES  IN
CENTRAL ALBERTA
S.A.  Leggett
Senior Consultant
Jim Lore and  Associates Ltd.
Calgary,  Alberta, Canada
S.L.  England
Senior Environmentalist
Mobil Oil Canada
Calgary,  Alberta,  Canada
Introduction

Reclaiming soils that are heavily contaminated with elemental sulphur is specific
to a small part of the oil and gas industry.  Alberta produces 95% of Canada's
elemental sulphur by converting  the  hydrogen sulphide present in sour oil and
gas to elemental sulphur (1).

The majority of sour gas plants built prior to the mid 1970's stored elemental
sulphur by pouring molten sulphur  into  large blocks.   The block was poured on
top of a basepad, which was  usually formed  from molten  sulphur.   Many of the
basepads were poured directly onto soil, with minimal ground preparation.

There are approximately 105 elemental sulphur block basepads at 34 locations in
Western Canada (2). These basepads range  from a few  hundred to fifty thousand
square meters in area (3) and the total combined area of basepads is estimated
to be 100 hectares.   Since 1980 few,  if  any,  new basepads have been established
in Western Canada.  Therefore,  most basepads and associated blocks have been in
place for  at least ten years.  As  a  result  of  increased sulphur  sales and
declining hydrocarbon reserves in older  sour oil and gas  fields, sulphur blocks
are being depleted.

Once a sulphur block has been recovered,  the basepad remains. Approximately 10%
of the total sulphur inventory  in Alberta is comprised of basepad material.  The
clean-up and  reclamation of  former  sulphur basepad  sites  can be a difficult
process, as up to 30% sulphur may remain in the soil once  the initial clean-up
phase is complete.

Once basepad clean-up is complete and  the sulphur-contaminated soils are exposed,
sulphur oxidation and,  in turn,  acidification will occur  if  the  soil is  left
untreated.   Former  basepad  areas  must  be  neutralized and plant  owners  must
satisfy regulatory authorities that the sites are environmentally secure.


                                      945

-------
Initial  approaches  to  basepad reclamation,  and  a  technical  and  economic
evaluation of their recovery and reclamation have been previously published (4)
(5).  This  paper is intended to provide  an overview of the  reclamation steps
taken, and  results  of  these steps,  in the reclamation of three former basepad
areas in central Alberta.

Background  Information

Mobil Oil Canada began reclaiming  former sulphur block basepad sites  in 1987.
These former basepad areas are located on agricultural land and are adjacent to
sour gas processing plants.  The principal objective of the reclamation program
has been to  establish a vegetation cover over the former basepads and surrounding
areas.

When basepad sites were levelled prior to construction,  the topsoil was usually
stripped and molten  sulphur poured directly  onto  the  subsoil.   Over the years,
the  stripped  topsoil was  often  used for other  purposes,  leaving  a compacted
subsoil,  low  in  nutrients and organic carbon,  to be  reclaimed when  basepad
recovery was complete.

The  focus  of  a  reclamation program  is two-fold  when  there  is  no  topsoil
available:  firstly,  to neutralize the  active  and potential acidity generated
from  the oxidation  of  elemental sulphur;  and secondly, to  improve  the subsoil
so that it will be capable of sustaining plant growth.  The degree to which the
untreated soil  will acidify  depends on the amounts  of  elemental  sulphur  and
natural calcium carbonate present,  the extent and  rate of sulphur oxidation,  and
the  specific soil conditions.

It  is well  documented  that acidic  soils can be neutralized by  the  addition of
calcium carbonate (limestone).  There are several methods available to determine
the  amount  of limestone required. The principal method used in Alberta  is based
on  accounting for  the total acidity  generated   if all  the elemental  sulphur
present  in the  soil  was oxidized.   On  the basis  of molecular  weight  and
stoichiometry, calcium carbonate is required in a  ratio of three parts for every
part  of total sulphur detected in the soil.   Therefore a soil that contained 20%
sulphur, by weight,  would  require a limestone application of 60%, by weight, to
the  soil.

The  second  goal is  to  improve  the  structure,  and organic  carbon and  nutrient
levels of the subsoil so that it can support growth, assuming that the previously
stripped topsoil is not available for replacement.  In  addition to the low levels
of organic  carbon, compaction is a serious growth-limiting problem.  The weight
of  the  sulphur  block on the soil,  combined  with  the  heavy  equipment operating
in the vicinity  of  a storage area,  leaves  a severely  compacted soil.   Frequent
and  deep  soil cultivation is not usually  enough  to  ameliorate soil structure.
                                     946

-------
In order to improve the organic  carbon content and tilth of the soil,  organic
matter  in the form of animal manure  and/or straw is added.  Additionally,  the
sites are seeded with  a  forage  mixture and/or cereal grain that  can be ploughed
down as green manure.  The penetration of roots through the soil, resulting from
vegetation establishment,  also helps to improve soil structure.

From reclamation programs that  have been undertaken to date, it is apparent that
reclaiming a site that contains  an average sulphur concentration of less  than
5%  will take at least three  years,  and  more  likely  five to  seven years.
Therefore, plant owners are recognizing the merits of initiating liming programs
immediately following basepad recovery.  Prompt reclamation while the plant  is
still generating revenue allows  the  costs  to be spread over a number of  years
prior to decommissioning the entire plant site.

Case Histories

Mobil Oil Canada is in the process of reclaiming former sulphur basepad  sites
at  three  facilities;  Lone Pine  Creek,  Wimborne, and  Harmattan.   Reclamation
activities  were initiated  in  1987  at both Lone  Pine  Creek and  Wimborne
facilities, and in 1988 at the Harmattan facility.

The first step taken at all three sites, once basepad recovery operations were
completed, was to establish soil sampling sites that would be monitored annually.
Soil samples were analyzed for pH, electrical conductivity (E.G.), and  percent
total  sulphur.   Based on the analytical results, initial liming programs were
developed.

Table 1 presents a summary of the soil chemical parameters for each basepad  site.
It  has been generally noted that the  lower  the soil  pH  value,  the higher is the
B.C. value.  Soil pH  values  are generally  lowest (i.e., most acidic) in  soils
that contain finely divided particles of elemental sulphur and inadequate levels
of  limestone.  Total sulphur concentrations  vary widely across a basepad  site,
making  it difficult to  initially apply appropriate levels of limestone to  all
areas.

The decrease  in the number of  sites monitored annually  as  the programs  have
progressed is due to  the changing focus of the programs.  Initially, a number
of  sites are established to determine the degree of sulphur contamination across
the basepad area.  As vegetation becomes established, the number of sites  to be
monitored annually are reduced and the focus of the  sampling  program  is  shifted
towards  determining the cause  of bare  spots,  where vegetation has not become
established.

All three sites  were  limed using powdered agricultural grind limestone,  which
was applied  using  a truck mounted pneumatic spreader  bar.   Initial limestone
applications varied from 30-70 tonnes/acre,  depending  on  the  amount of  sulphur
present in the soil.   A source  of organic matter was also applied at each site.
                                      947

-------
                                                TABLE 1
Summary  of  selected  soil chemical  parameters  at  three  Mobil Oil  Canada former
sulphur  basepad sites.   Data are expressed  as mean values +  standard  deviations.
             	pB	     	Electrical Conductivity	     	total Sulphur	
                                                         (dS/D)                             (*)
  Site        1987        1988        1989        1987       1988        1989        1987        1988       1989
 Lore Pine     4.5+2.1     5.9+1.8      5.3+1.4      7.3+3.3    7.7+7.7      7.1+2.8      0.5+0.5     1.7+1.6      H/A
  Creek
  (n-9)

 Vttntame     3.9+1.9     5.6+1.6     4.1+2.31     13.5+7.2    7.8+2.5     13.6+9.71     6.5+9.2     5.1+6.9     6.5+4.91
 North Pad
  (n=23)

 Vttflfcome     5.7+1.8     6.6+1.2     5.3+1.92     10.2+3.7    7.6+1.6     10.8+6.42     7.8+4.7     4.8+4.1     e.2+4.62
 South Pad
  (n-15)

 Hannattan       N/A       7.4+0.7      7.7+0.2       N/A      5.5+0.7      6.0+0.8       N/A      1.2+1.4     4.7+5.1
  (n-5)
N/A      not available.
1
        n-8
                                                   948

-------
Once the initial  liming programs  were carried out,  the Lone  Pine Creek  and
Wimborne basepad areas were seeded in 1987.  There had been no growth on these
sites since the basepad recovery programs, and poor drainage and water ponding
were problems.  The objective  of the seeding program was to establish a plant
cover,  thereby  helping to  improve  soil  tilth and  the soil's  water storage
capacity.  Yellow sweet clover was  seeded because of its biennial nature,  its
ability to fix nitrogen, its deep tap root for penetrating compacted soil,  and
its ability to establish on clayey,  alkaline or sodic soils.  It  is  also a good
green manure crop  and  so was selected for its ability to  increase  organic matter
levels on these sites.  Barley and fall rye were seeded as cover crops at Lone
Pine Creek and Wimborne, respectively.

Initial germination at Lone Pine Creek was better  than expected.  Growth at  the
Wimborne site was poor, but  it is  thought that this was partly due to seeding
methods and the weather.

Following the initial yellow clover and cereal seeding program, there were bare
areas  at  both  Lone  Pine  Creek  and Wimborne,  where  no vegetation  became
established.  These  areas were mapped  and the soil  was  sampled.   Analytical
results indicated that the majority of the areas were both  acidic and contained
high levels of  soluble  salts.   Additional liming  programs were carried out in
both 1988 and 1989 to counteract the acidity.

The Hannattan site was seeded during the first summer following basepad recovery
(1989), but little growth was achieved.  Upon review of the soil analytical data,
it  was concluded that  a  low  level  of  organic carbon,  and not  the sulphur
contamination,  was the  principal chemical limiting  factor.   It was concluded
that soil compaction  was  also  limiting plant growth.  Yellow sweet clover  was
not used initially at Harmattan, although  it will be  included in the 1990 seed
mixture.

The second part of the seeding  program focused on  establishing plants on a more
long-term basis, rather than the green-manure emphasis  of the initial seeding
program.  The 1989 seed mixture  selected  for all  three basepad sites included
plants that have a tolerance  for high salt levels and/or low soil  pH  values,  and
an ability to grow on poorly drained, clayey soils.

Six row barley,  which is fairly salt tolerant, was seeded  in one direction.  A
forage mixture  composed of alsike  clover,  alfalfa,  tall wheatgrass, and brome
grass was then seeded in a perpendicular direction.  Alsike clover  and alfalfa
were selected for their ability to fix nitrogen.  Alsike clover was also selected
for  its  ability to  grow in poorly  drained,  clayey  soils,  and  its  ability  to
tolerate both moderately  acid and  alkaline  soils (6).   Alfalfa was selected
because of its sensitivity to acidic soils, and its usefulness to  indicate soils
which were not acidic.
                                     949

-------
Brome grass was selected because of its ability to establish quickly and to adapt
to a wide range of soil conditions.  Brome grass is reported to be fairly saline
tolerant, but to have a poor tolerance of acid soils  (6).   Tall wheatgrass was
selected because  of its ability  to  grow on  soils  that range  from  being  well
drained to where the water table  is within  a  few  centimeters  from the surface.
It is also reputed to be "the most salt tolerant of all cultivated grasses"  (6).

It was felt that  this  forage  mixture represented a combination of plants  that
should be able to establish over most of the  basepad  areas.   The use of plants
with  different tolerances to  such factors as moisture  conditions, and  soil
acidity and salinity should allow visual observations of  the  probable cause of
no  growth.    Further sampling  and  treatment of  these  areas  should  improve
reclamation success.

Barley established  well  in 1989, at both Lone Pine Creek and  Wimborne sites.
The  forage  mixture  was  slow to  germinate,  but growth  improved  by late  August,
1989.  The  summer of 1989 was hot and dry,  with small amounts of precipitation
scattered throughout the year.   However, the spring and summer of 1990 were  very
wet  and forage growth improved dramatically at both sites.

Yield samples  were  taken  in the late summer of 1989  from both  Lone  Pine Creek
and Wimborne.   Samples were taken using  a 0.5 m  sampling hoop,  and plants  were
cut  at the  soil surface.  The principal plant cover was barley, and  dry matter
yields ranged from no growth to 1.6 tonnes/acre.  Based on the Alberta Hail and
Crop Insurance  Corporation  long term averages, a dry matter  yield from barley
fields in  these two areas would be approximately 2.5  tonnes/acre.   Therefore,
the  yields  recorded for the best growth on the basepad sites  were  lower  than
those expected  from average fields in the regions.

Based  on the  data from  the  bare spot  sampling program  in  1989,  additional
limestone was  applied in  the fall of 1989.  All bare  spots were then re-seeded
in the summer of 1990.  Initial indications are that germination will be fairly
good.  More so  than any other year, the bare  spots  are clearly  delineated. It
is interesting to note that tall wheatgrass is the last plant  to survive around
the  perimeter of  the  bare areas.   Further  sampling  programs  this  year  will
indicate  whether the  bare spots  are  the  result of  acidity,  salinity,  or  a
combination of  the  two.

Table  2  summarizes the reclamation steps that have been  undertaken  to  date at
each basepad  area.

General Observations on Reclamation Program Success

A number of observations  have been noted during this  reclamation program.   The
first  of  these is that  sulphur  levels  across  a  site  are  highly variable.
Although the average levels for each site are quite low, the range of values is
wide.  Without sampling on a very small scale grid, it  is difficult to accurately
determine  sulphur levels.  Because of the variability of  sulphur levels in the
soil,  repeated liming and seeding  operations are required to treat the  bare
spots.

                                      950

-------
                                   TABLE 2
Summary of reclamation steps undertaken at former sulphur basepad sites of three
Mobil Oil Canada facilities.
Year
lOBEnB
1987
1988
1989
1990
HDKHB
1987
1988
1989
1990
IBimiUi
1988
1989
1990
Area (ha)
3.4
3.4
3.4
3.4
3.2
3.2
3.2
3.2
1
3.4
3.4
3.4
Amount of
Limestone
Applied
(tomes)
363
103
71
437
68
56
145
23
ongoing
Aurunt and Type
of Organic
Matter Applied
	
8 round bales
of yellow sweet
clover
	
	
330 tonnes of
manure and
	

	
750 tonnes of
manure
Type of Seed
Used
Barley & vellow
Barley & yellow
sweat clover
Barely & forage
mixture
Barley & forage
mixture on bare
spots
Fall rye &
yellow sweat
clover
	
Barely & forage
mixture
Barley & forage
mixture on bare
spots
Barley Ł forage
nuxture
ongoing
Estimated
Annual
Cost
(S)
23,690
18,000
13,000
ongoing
15,000
11,000
9,000
ongoing
10,625
7,000
ongoing
Estimated
Annual
Cost/ha
(S)
6,967
5,294
3,825
ongoing
4,687
3,448
2,815
ongoing
3,125
2,060
cogoing
                                      951

-------
Secondly,  some site  preparation work  is generally  required  as  part of  the
reclamation  program.    This  includes  landscaping in  order  to improve  site
drainage, and rock-picking.  It is important that acidic materials not be buried
during landscaping.  It is most efficient to leave the sulphur-contaminated soil
on the surface where limestone can be easily mixed  with it.  This allows for the
opportunity to neutralize areas that re-acidify over  the years.

Thirdly,  the  areas  that  are  re-acidifying  and  not  supporting plant  growth
generally  exist  around the perimeter of  where the sulphur block was  located.
Elemental  sulphur would have been continually  deposited on the soil surface as
a  result of block operations  and  spills.  Another  area where bare spots  are
commonly located are  where piles of  sulphur-contaminated material,  remelt pits
or equipment were  located during basepad  recovery  operations.

Another  observation is that the methods used for seeding and the types  of  seeds
used are crucial to the success of the program.  The cover established when seed
was broadcasted was not  optimal, and a  seed drill  is  now used.  Because of the
relatively small size of  the sites and the even smaller size of the bare spots,
eight  foot wide  farm equipment is used.  This  allows treatment and seeding of
the bare areas without disturbing the rest of the site that is supporting growth.

Finally, as the  reclamation program progresses, a shift  in  focus  is evolving.
Once  the  initial  site  assessments  are made  and  limestone has been applied  a
sufficient number  of  times, there is a shift from simply managing soil pH levels
to the long term development and maintenance  of adequate soil  structure needed
for agricultural production.

Summary

Reclamation of these sites requires the application of  a  number of scientific
principles to a very specific set  of  circumstances.   As stated earlier,  the
aerial extent  of former basepad sites is not large, but the ramifications of not
treating them  could be great.   Unchecked sulphur oxidation from  these sites could
lead  to groundwater and neighboring soil  contamination.

The approach taken by Mobil Oil Canada has been to initially apply limestone in
a 3:1 ratio based  on the average  sulphur concentration of the former basepad
site.   Areas known to be more contaminated receive additional limestone.   Th6
former basepad sites are then seeded and growth  is monitored.  Once  the bare
spots become evident, additional soil sampling is  carried out.  Amendments are
applied to the bare spots as necessary and the areas  are re-seeded.

Monitoring  of  reclamation  treatments  at   all   facilities  provides  useful
information.   Annual monitoring is  a good method of obtaining an  overview of
general soil chemical conditions of  a former basepad site.  Sampling individual
bare  spots allows determination of  the cause of  the bare spot,  thus  allowing
remedial action  to be taken.

The major management  issues in reclaiming these types of sites are working out
the  logistics of accomplishing the required work,  and ensuring that the site is
monitored and actively treated until successful reclamation is achieved.
                                      952

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References
1.    J.B.  Hyne,  Recovered  sulphur  -  a  disposal problem.   Alberta  Sulphur
      Research Ltd.  Quarterly Bulletin, Vol XIV: 5-24.

2.    J.B.  Hyne, W.J.  Schwa1m,  Drawing down  inventory:  rerneIt and  block pad
      problems.  In;  Proc.  1983  Alberta Sulphur  Symposium.  Sponsored by SUDIC.
      September 27,  1983. Calgary, Alberta.

3.    J.B.  Hyne, Managing solid sulphur wastes.  Presented at the Petroleum Waste
      Management Conference, Calgary, Alberta, January 22-23, 1986.

4.    S.A.  Leggett,  S.L. Graves, and A.J.  Boger, Approaches to the reclamation
      of sulphur block  basepads.   In; Energy Extraction:  Concerns and Issues
      Related to Soil Reclamation.   Proc. of 34th Annual  Meeting of Canadian
      Society of Soil Science.  August 21-24, 1988.  Calgary, Alberta.

5.    S.L.  England,  S.A.  Leggett, A technical and economic evaluation of sulphur
      basepad recovery and reclamation options.   In;  D.G. Walkers et al. Proc.
      of  Conference:  Reclamation,   A Global   Perspective.    Alberta  Land
      Conservation and Reclamation Council Report No.  RRTAC  89-2, 383-392, 1989.

6.    L.E.  Watson,  R.W.  Parker,  and D.F. Polster, Manual of species suitability
      for reclamation in Alberta.   Alberta Land  Conservation  and Reclamation
      Council Report No. RRTAC 80-5,  1980.
                                     953

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A TC MODEL ALTERNATIVE FOR PRODUCTION WASTE SCENARIOS
H. S. Rifai, P. B. Bedient
Department of Environmental Science & Engineering
Rice University
Houston, Texas
Introduction

The Environmental Protection Agency has recently promulgated the Toxicity Characteristics (TC).
The rule [1] establishes regulatory levels for approximately 40 organic chemicals based on health-
based concentration thresholds and a dilution-attenuation factor that was developed using a
subsurface fate and transport model.  In summary, any waste containing any of the 40 organic
chemicals discussed in the rule at a concentration which exceeds the maximum allowable leachate
concentration is considered to be hazardous and cannot be disposed of in a municipal landfill. The
EPA has specifically exempted Exploration and Production (E & P) wastes from the TC rule,
mainly due to economic considerations.  Some states, however, may adopt the TC rule to regulate
E & P wastes, and it is conceivable that the EPA will repeal its exemption for those wastes.

The objective of this study was to develop a toxicity modeling scenario to represent reasonable
waste management practices for E&P wastes.  The modeled scenario, on-site management with
benzene as the primary constituent, would be used as an alternative to EPA's current municipal co-
disposal scenario for E&P wastes. The scenario used by EPA in the TC rule assumes steady-state
conditions and infinite source strength, non-biodegradable constituents, and national distributions
for some of the model parameters. The final toxicity rule dictates a maximum allowable leachate
concentration which is 100 times the health-based maximum allowable concentration for the TC
organics. The E&P wastes scenario varies from that used by EPA in two main areas: (1) transient
conditions are assumed for contaminant transport in the unsaturated and saturated zones; and (2)
data about geometric configurations of disposal facilities, waste volumes, concentrations of
benzenes in oily wastes, and distributions of E & P activity over the U. S. were obtained from the
E&P wastes database compiled by the American Petroleum Institute.
The TC Model - EPACML

The Environmental Protection Agency's Composite Landfill Model (EPACML)  simulates the
movement of contaminants (through the unsaturated and  saturated  zones) leaching from a
hazardous waste landfill.  The composite model consists of a steady-state, one dimensional
numerical module that simulated flow in the unsaturated zone. The output from this module,
seepage velocity as a function of depth, is used as input by the unsaturated zone transport module.
                                    955

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The latter simulates transient, one-dimensional (vertical) transport in the unsaturated zone and
includes the effects of longitudinal dispersion, linear adsorption, and first-order decay.  Output
from the unsaturated zone modules, i.e., contaminant flux at the water table, is used to define the
gaussian-source boundary conditions for the transient, semi-analytical saturated zone transport
module.  The saturated zone module includes one-dimensional uniform flow, three-dimensional
dispersion, linear adsorption, lumped first-order decay, and dilution due to direct infiltration into
the ground water plume [2]. A shematic of the waste facility and leachate migration as simulated
using the EPACML model is shown in Fig. 1.

The  uncertainty in the medium and environment-specific parameters in the unsaturated and
saturated zones is quantified in EPACML using  a Monte Carlo Simulation technique. Several of
the model  parameters can be input as statistical distributions, and the model is run for many
iterations (around 2000) to obtain a cumulative frequency distribution of the concentration at a
receptor  point, usually  a monitoring well.   The model output is used to back-calculate the
maximum allowable concentration of a chemical constituent at the point of release (i.e., below a
landfill) such that the receptor well concentration does not exceed a health-based (maximum)
threshold level. The Dilution  Attentuation Factor (DAF) is defined as the reciprocal of the
computed normalized  concentration at the receptor well.  The product of the DAF and the health-
based maximum allowable concentration equals the maximum allowable leachate concentration at
the facility.

Previous studies  [3,  4] indicated  that there are  several weaknesses in EPA's approach  and
modeling scenario.  Mainly, use of the steady-state conditions in the modeling scenario masks the
attenuation that would be expected through the unsaturated zone (except when biodegradation in
the unsaturated zone is simulated). In addition, the steady-state assumption produces results which
are inconsistent with common-sense waste management practices.  For example, when the effect of
seepage velocity in the  model is considered under steady-state conditions, a hydrogeologic
environment with  high seepage velocity  such as glacial outwash would have higher allowable
source concentrations than an environment with  low seepage velocity, such  as an unconsolidated
shallow aquifer.

For the purposes of this study, the parameters of interest which were used to develop an alternate
modeling scenario f or E  & P wastes were mainly the source parameters and  the hydrogeologic
properties of the aquifer.  The source parameters in EPACML include the infiltration rate from the
landfill,  the area  of  the waste disposal unit,  the duration of the source,  the spread of the
contaminant source, the recharge rate, a  source decay constant, the initial concentration at the
landfill, and the length and width scales of the facility. The  source parameters which are used in
EPA's modeling scenario are listed in Table 1 with a brief description of the type of distribution
used for each parameter. The hydrogeologic parameters which were used to develop the E & P
wastes modeling scenario are discussed later in this paper.
The API 1985 Production Waste Survey

Exploration and production wastes can be divided into three basic categories: drilling wastes,
produced waters and other associated wastes. Drilling fluids consist primarily of drilling muds,
cuttings from the well bore and chemicals added to  drilling fluid  systems to improve mud
                                      956

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properties.  Produced water consists of formation water plus chemicals added for treatment.
Associated wastes consist of small volumes of waste such as tank bottoms and produced sands
generated in conjunction with drilling and producing operations.

The American Petroleum Institute  (API) conducted  a  study on wastes associated  with the
exploration for and production of oil and natural gas.  The goals of the study were to develop
independent estimates of waste volumes and sources and to analyze waste management practices,
waste disposal methods, waste characteristics and pit closure practices [5]. A survey questionnaire
was prepared by API and mailed to representatives of the API member companies. The production
waste survey was divided into several parts: (1) Part I- Drilling Waste; (2) Part n- Associated and
Other Wastes; and (3) Part ffl- Produced Water (includes a supplement).

Part I of the survey was designed to estimate the source, volumes and disposal practices of drilling
fluids for all wells drilled in 1985. The sample contained 659 wells (about 1% of all  the wells
drilled in 1985).  Typical information provided on each well included the location of the well by
State and County, the total depth of the well, total fluid volume, total volume of drill cuttings
discharged  into the reserve pit,  the reserve pit dimensions, and  the methods  that were used to
dispose of the reserve pit contents.

Part II was designed to estimate the volume of other wastes associated with the exploration,
development and production of oil and gas resources such as sludges, tank bottoms, oily debris,
waste waters, and untreatable emulsions.  About 141 responses on volume estimates were listed
from 25 different companies.  The data in Part n of the E  & P database provided estimates of the
volumes of associated wastes listed by State and operator (or member company). Part II also
included the percentages of those volumes which were disposed of by several methods: recycling,
spread on roads, land spread, incineration, onsite pit, onsite burial, offsite commercial facility, and
other methods. The methods of disposal of interest in this project include: land spread, onsite pit,
and onsite burial.  The data in Part II indicated that  17% of associated wastes were disposed of by
those three methods [6]. Unfortunately, Part II of the database did not include any information
about the specifics of the three disposal practices for associated  wastes. As a result, it was not
possible to develop a TC modeling scenario for associated wastes.

The data in Part  III  consisted of state and industry  records of produced water volumes.  A
supplement included in the surveying process was also used to estimate volumes of produced
water.  The estimates of produced water from the supplement were based on 170 responses which
accounted for 51% of the total onshore U. S. production of crude oil. The data in Part III and the
supplement of the API E & P wastes study indicated that produced waters are for the most pan
disposed of by salt water disposal, enhanced oil recovery, and NPDES discharge.  In this  case, it
was not necessary to develop a TC modeling scenario for produced waters.
 Statistical Analysis of the API 1985 Production Waste Survey Data

 The data in Part I of the E & P database were used to develop the E & P wastes modeling scenario.
 The majority of drilling wastes are disposed of in reserve pits. The contents of the reserve pit are
 subsequently disposed of by several methods  which include hauling offsite, onsite burial, land
 spread, discharge to the surface, evaporation, and injection down the annulus. The database did
                                      957

-------
not include detailed information on the contents of the reserve pits, and their operational lifetime.
A  significant percent of the reserve pits are lined, however, the EPACML modeling approach
assumes unlined municipal landfills.  For the purposes of this study, no distinction was made
between lined and unlined pits. In essence, the most significant parameters in the database which
were relevant to this project were the geometric configurations of the reserve pits, waste volumes,
and the distribution of E & P wastes activity over the U. S.

The reserve pit geometric configuration data were analyzed using  a commercially available
statistical program [7] to develop  statistical distributions for area, length, width, and depth of the
reserve pits.  The most appropriate  distribution for the four parameters was the  lognormal
distribution (Fig. 2). The data for the area of the reserve pit were also fit with an exponential
distribution.
Linking the E & P Wastes Database to a Hvdrogeologic Database

In a related, but separate effort (funded by the API), a survey of 400 sites across the nation [8] was
used to develop a national database for the main hydrogeologic parameters used in the TC model
(hydraulic conductivity, seepage velocity, depth-to-water, penetration depth).  The survey data,
referred to as the HydroGeologic DataBase (HGDB), were used to develop national averages for
each of the parameters, and to develop parameter distributions for subsurface environments with
similar hydrogeologic characteristics. The grouping procedure of the data was based on the
DRASTIC  system [9] which divides the U. S. into Ground Water Regions. Each of the Ground
Water Regions in DRASTIC is further divided into Hydrogeologic Settings (144 in all). Due to
the lack of sufficient data for some of the 144 settings, the data in the HGDB were grouped into 12
Hydrogeologic Environments which are composed of the 144 originally discussed in DRASTIC.
The DRASTIC Ground Water Regions, and the HGDB Hydrogeologic Environments are listed in
Table 2. The HGDB parameters which relate to the EPACML model are the saturated thickness of
the aquifer, the hydraulic conductivity, the seepage velocity, the gradient, and the penetration depth
of the source into the saturated  zone.  These five parameter distributions  were utilized in
developing an E & P wastes modeling scenario.

For the purposes of this study, the E & P wastes  database was linked to the HGDB in order to
utilize some of the HGDB parameter distributions.  The reason for this is that the national average
parameter distributions used by the EPA (which were found to be very similar to the HGDB
national distributions)  are too generic  and do not  reflect the characteristics of specific
hydrogeologic environments. Newell et al. [8] and Hopkins [10] conclude that different results arc
obtained with the TC model when the HGDB parameter distributions are utilized in the analysis.

The first approach attempted to correlate the EPA defined production regions to the HGDB. This
approach was not realistic, however, because it did not reflect the location of the actual producing
fields. The adopted approach for this study involved correlating the Oil & Gas producing regions
to the DRASTIC Ground Water Regions.  The location of each of the wells in the database was
correlated to a  DRASTIC Ground Water Region.  In  some cases, the  well was considered to
belong to two regions because of inaccuracies in the mapping procedures. The results from the
correlation  study indicated that for the most parts, the reserve pits were mostly located in the High
                                       958

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Plains, Nonglaciated Central, Alluvial Basins, Atlantic and Gulf Coastal Plains, Colorado Plateau
& Wyoming Basin, and Glaciated Central DRASTIC regions.
Modeling Results

A sensitivity analysis was conducted using EPA's scenario to determine the effects of changing the
source configuration data on the modeling results. The data in Table 3 show the DAF results for a
number of the sensitivity runs. It can be seen from Table 3 that using the geometric configuration
data from the E & P wastes database changes the DAF significantly from EPA's scenario (there are
several ways  that one can enter the geometric configuration data into the EPACML  model).
Basically, the DAF's ranged from about 176 to 255 compared to EPA's scenario DAF of 8.

An attempt was made to develop the E & P waste scenario using a Monte Carlo transient modeling
approach, however, the runtime for those conditions was quite long (exceeds 48 hrs in some
cases). In the interest of time, and for the purposes of examining the sensitivity of the model to
some of the  parameters  using transient conditions, it was decided to utilize the transient
deterministic option in the model.  The deterministic option in the model replaces the statistical
distribution  for any parameter with a single value, usually the mean of the distribution.

Some of the results from the transient deterministic model runs  for two of the  HGDB
Hydrogeologic Environments (alluvial basins, valleys, and fans, and river alluvium with overbank
deposits) are  shown  in Table 4 (due to  the large number of DRASTIC Regions and HGDB
Environments, only a few are discussed in this paper).  The E & P data for the Alluvial Basins
DRASTIC region was used in this case because it had the largest number of reserve pits in the
database. The transient model results are shown in Table 4 for two points in time: 100 years and
10,000 years.  The first two runs listed  in Table 4 consist of EPA's scenario run,  and EPA's
scenario with the geometric configurations of E & P  drilling reserve pits for benzene.  It is noted
from the first two runs in Table 4 that the time-to-steady state is in excess of 100 years.

The other runs listed in Table 4 mainly show the sensitivity of the transient assumption model
results to changes in the aquifer parameter distributions obtained from the HGDB. The parameters
that had the most effect on model results were the saturated thickness, the gradient, the hydraulic
conductivity and the seepage velocity. This  effect varied in magnitude between the two HGDB
environments presented, with it being more pronounced in the river alluvium environment.  The
runs listed in Table 4 also indicate that for some cases, the transient concentrations at 10,000 years
are not equivalent to the steady-state concentrations. The cause for this was not investigated.

In summary,  the model results indicated that utilizing  the E & P wastes database  geometric
configurations for reserve pits and the parameter distributions from the HGDB could potentially
yield much  larger DAF's than EPA's modeling scenarios.
                                      959

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References

1.     U. S. EPA, Final Toxicity Characteristics Rule, 40 CFR Parts 261, 264, 265, 268,271
      and 302, Federal Register, March 29, 1990.

2.     Woodward-Clyde Consultants, Background Document for EPA's Composite Model for
      Landfills (EPACML), Report Prepared for the U. S. EPA, February 1990.

3.     Bedient, P. B., C. J. Newell, and C. Chang, Review of the EPACML Model for
      Hazardous Waste Regulation, unpublished report,  1988.

4.     Bedient, P. B., C. Chang , and C. J. Newell, Evaluation of the EPACML Model and the
      Horizontal Plane Source Model for Hazardous Waste Regulation, unpublished report,
       1989.

5.     P G. Wakim,  API 1985 Production Waste  Survey, Statistical Analysis and Survey
      Results, API Internal Report, October 1987.

6.    P. G. Wakim, API  1985 Production Waste Survey, Part II Associated and Other Wastes,
       Statistical Analysis and Survey Results, API Internal Report, June 1988.

7.     SYSTAT, The System for Statistics, User's Manual, 1985.

8.     Newell, C. J., L. P. Hopkins, and P B. Bedient, Hydrogeologic Database for Ground
      Water Modeling, API Publication # 4476, 1989.

9.     National Water Well Association, DRASTIC: A Standardized System for Evaluating
       Ground Water Pollution Potential Using Hydrogeologic Settings, 1987.

 10.    Hopkins, L. P., Hydrogeologic Database for Stochastic Ground Water Modeling With
      Hydrogeologic Environment Specific Applications, Masters thesis, Rice University, 1989.
                                     960

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              TABLE 1
Source Specific Parameters for EPACML
Default Values
Variable Name
Infiltration rate
Area of waste disposal unit
Duration of pulse
Spread of contaminant source
Recharge rate
Source decay constant
Initial concentration at landfill
Length scale of facility
Width scale of facility
Distribution Types
Constant
Normal
Lognormal
Exponential
Uniform
Log 10 uniform
Empirical
SB Distribution
GELHAR Distribution
AREA Transformation
Units
m/yr
mA2
yr
m
m/yr
1/yr
mg/1
m
m
Code
0
1
2
3
4
5
6
7
8
9
Derived Variable
No
No
No
Can be derived
No
No
No
Can be derived
Can be derived











Distribution
6
9
0
-1
6
0
0
-1
-1











Parameters
Mean
0.007002
4.21
1E+30
50
0.0076
0
1
100
100











Std Dev
0.007002
2.16
3
0
0.0076
0
0.01
1
1











Limits
Min
0.0000254
-0.884
0.1
0.001
0.0000254
0
0
1
1








v


Max
0.668
12.3
1E+30
60000
0.668
10
10
100000
100000











                                                                                  1—I
                                                                                  s

-------
                              TABLE 2
  List of DRASTIC Ground Water Regions and HGDB Hydrogeologic Environments
   Drastic Ground Water Region1
   HGDB Hydrogeologic Environment
             Alaska
         Alluvial Basins
  Atlantic & Gulf Coastal Plains
Colorado Plateau & Wyoming Basin
      Columbia Lava Plateau
     Glaciated Central Region
             Hawaii
           High Plains
   Nonglaciated Central Region
  Northeast & Superior Uplands
     Riedmont & Blue Ridge
     Southeast Coastal Plains
    Western Mountain Ranges
     Alluvial Basins, Valleys, & Fans
       Bedded Sedimentary Rock
            Coastal Beaches
        Metamorphic & Igneous
               Outwash
 River Alluvium with Overbank Deposits
River Alluvium without Overbank Deposits
            Sand & Gravel
          Solution Limestone
        Till  & Till Over Outwash
       Till Over Sedmentary Rock
 Unconsolidated and Semi-Consolidated
       Shallow Surficial Aquifers
                                         962

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                      Table 3
Results from EPACML Steady-State Monte Carlo Runs
Run Description
EPA Scenario for Benzene
API area distrib.-lognormal; L,W derived
API A, L, W -lognormal distributions
API area distrib-expon. L,W derived
Area-transform lognormal, L,W derived
Area, L,W- transform lognormal
Table 4
Results from EPACML Transient

Run Description
EPA Scenario for Benzene
E&P L, W, A transform lognormal
Alluvial, Saturated Thickness
Alluvial, Gradient
Alluvial, Hydraulic Conductivity
Alluvial, Seepage Velocity
Alluvial, Penetration Depth
River, Saturated Thickness
River, Gradient
River, Hydraulic Conductivity
River, Seepage Velocity
River, Penetration Depth
85th C/Co
1.25E-01
5.67E-03
3.83E-03
5.98E-03
5.47E-03
3.92E-03

Deterministic
85th C/Co
100 years
9.18E-23
4.02E-21
4.02E-21
1.60E-20
1.73E-22
5.17E-10
5.45E-21
1.35E-20
3.57E-20
1.06E-10
1.12E-10
6.22E-21
85th DAF
8
176
261
167
183
255

Runs
85th C/Co
10000 years
2.26E-06
3.45E-04
6.87E-04
1.35E-03
1.50E-05
1.59E-06
3.45E-04
8.82E-04
1.16E-03
1.09E-07
1.15E-07
3.45E-04









85th C/Co
Steady State
2.26E-06
3.45E-04
6.87E-04
1.35E-03
1.50E-05
1.59E-06
3.45E-04
2.40E-03
2.92E-03
3.00E-07
3.16E-07
3.45E-04
                              963

-------
                          Contaminant  Plume
                                  Monitoring


— -3Z.__.



^ Waste Facility $^\
+ + 1
Unsaturated Zone
v.
V.




'f»
Aquifer

—


-

W<;


J
1
>ll
Ground Surface
Water Table
B
V

Fig. 1.  A Schematic of the Waste Facility Source
Boundary Condition  and  Leachate  Migration Through
the Unsaturated and Saturated  Zones for EPACML
                       964

-------
       Pit Length
       Pit Width
E
X
P
C
T
D
U
ft
L.
U
E
•*

2


0

-2

-4
lit,

, 1
f
r
•
! 1 '
r '

i i i i i
 34367






         LNL
E
X
P
E
T
D
0
Ft
L
U
E
*t


2
0

-2

-4
i i i i

'
J" '
.
, 1
1 '
, 1"


23456





       LNW
      Pit Depth
                                              Pit Area
E
X
p
E
C
T
E
D

U
n
L
U
E
T


2



0


-2

-4
i i i


.1
,.l

| '

1 '

| '


   1      2      3





       LAD
                                 -2
     e     to    12




       LNA
Fig 2. Lognormal Distributions for Reserve Pit Dimensions
                           965

-------
 THE APPLICATION OF  CONCENTRIC PACKERS TO ACHIEVE MECHANICAL

    INTEGRITY FOR  CLASS  II  WELLS IN OSAGE COUNTY, OKLAHOMA


                       EVERETT M. WILSON

        U.S ENVIRONMENTAL PROTECTION AGENCY - REGION  6

                      PAWHUSKA,  OKLAHOMA
ABSTRACT

The  Environmental  Protection Agency's Region 6 policy of  working
with  private  industry to develop new methods for remedial action
resulted  in  the  adaptation of the concentric packer to  the  role
of  providing  mechanical  integrity  of  the  casing in Class II
wells  in  early 1987.   Prior to this time,  oil companies in  Osage
County,   Oklahoma   whose  wells  failed  the mechanical integrity
test as a result of holes in the  casing had  the  basic  remedial
action options  of  squeezing,  cementing new casing inside the old
casing, backing  off and replacing the bad  casing joints  if  well
conditions   permitted   or   plugging   and  abandonment  if  no
production zones were  available for recompletion.

The  use of a concentric packer to seal off casing  holes,  collar
leaks  and   old  perforations  therefore  allowing  the  well  to
demonstrate  that there is no significant leak in the  casing  per
40  CFR   Part  147.2912  (1)  has  proven  to  be  a  successful
alternative  to  the   basic  remedial  action  options  if   well
conditions   are  favorable.  As of March 1989, there have been 26
concentric packers  run  in  Class  II  wells  in  Osage  County,
Oklahoma   with  20  of  the  wells  passing  the  EPA  mechanical
integrity test as  a result.   The  use  of  this  tool  has  also
allowed   operators  to  realize  a  significant cost reduction in
their  workover  operations  with  little   of  the  risk  to  the
wellbore   that  is  inherent in other operations such as squeezing
cement or running  a liner.


INTRODUCTION

The  Environmental  Protection  Agency's  Region  6  has   direct
implementation  of  the Osage UIC  Program as set forth in the Safe
Drinking  Water Act  of  1974.  The  Osage UIC  Regulations  (40  CFR
Part  147,    Subpart   GGG)  require  that  all  injection  wells
demonstrate  mechanical integrity  by  December  30,  1989  and  at
least  once  every   five years thereafter-  The Osage UIC Program
                             967

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regulates approximately 3500  injection  wells.   These wells  range
in  age  from  new  wells to  those  drilled  around  the turn of the
century.   Many of Lhe.se  wells  require  some   type  of  remedial
action  in order to pass the  mechanical integrity  requirements as
set forth in 40 CFR Part 147.2912  (1).

The basic casing repair options have  historically  been  squeeze
cementing,  running and cementing  a smaller size casing or tubing
as a liner inside the old string,  backing off  the  bad joints  and
replacing  with  new ones or  plugging and abandonment if the well
was not salvageable.

Squeezing old casing or running a  liner are relatively  expensive
operations  in  an  mature  producing   area where  economics are
already  tight.  Replacement  of   bad   casing   with   a   backoff
operation  is often unfeasable due  to the age  of the well and the
initial completion practices  used.  In  addition, there is  always
a  certain  amount  of  risk  involved   as   the type of stresses
inherent in these operations  can   worsen the   condition  of  the
casing  or  even  cause  the  well  to   be   junked.   Plugging and
abandonment of a Class II well can  impose an economic  burden  on
a  lease  due  to  a  loss of injection capability as well as the
cost of the abandonment operation.

In an effort to find an alternative method  of  casing repair  that
would  be  effective,  economical,  easily   applied  as  well  as
relatively low risk, the concept of using   a   concentric  packer
was developed and applied to  these  Class II wells.
CONCENTRIC PACKER

The  concentric packer, sometimes  refered  to  as  a  scab packer,  is
not a new  tool.  It  has  been   in   use   for many  years   as  a
production  tool  in wells to  shut-off  an  influx of water above a
production zone that would either  kill  the   well   or  render   it
uneconomical  to produce.  This packer  has also  been used to shut
off a gas influx  to  the  wellbore   that  was   interfering  with
production operations.

The  concentric  packer  is  ideally  suited to the task of casing
repair on Class II wells as  it meets  the  regulatory  requirements
for  establishing mechanical integrity  under  40  CFR Part 147.2912
(1). These  requirements  are  met since  there  is  an annulus
between  the tubing and the  packer assembly that allows hydraulic
communication from the wellhead to the  injection  packer at  the
bottom  of  the  tubing.  This  type  of   construction allows  the
mechanical integrity tests   to  demonstrate   that   there are   no
significant  leaks  in  the  casing,  tubing and  packer as long as
the bad section of the long  string casing  is   isolated  with  the
packer  assembly.   The  packer assembly  consists  of an upper  and
lower packer with two rubber casing cup elements on each packer,
pointed  opposite  each  other to  contain  pressure from above  and
below,  and a casing sleeve that   connects  the   upper  and   lower
                                968

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packers.    The  casing sleeve is generally the  largest  size casing
that will  fit  inside the old long string casing  so  as  to allow  a
maximum  by-pass  area  between  the  sleeve   and   the  injection
string.  The   length  between  the  upper  and  lower   concentric
packer  is  determined by how many joints of casing is used for the
sleeve.  The  length of casing  sleeve  required  to isolate  the
leaks   is   dependent  on  the location of the  bad sections in the
long  string.   The overall length of a concentric packer  assembly
can  range  in   length  from  30  feet  to  several hundred feet
depending  upon  the condition of the casing.  The  longest  casing
sleeve   run  to date on a concentric packer is 365  feet in a well
that  had several areas of bad casing within that interval.

There  are  two  basic  concentric  packer  configurations.    The
configuration  seen  in Figure 1 is not attached to the tubing in
any way.  This   configuration  is  assembled   around   the  tubing
while  being  run  in  the hole.  As can be seen in Figure  1,  the
tubing  collar above the upper packer will push the  assembly  down
the  hole and the tubing collar below the lower element will pull
it  out  when  the  tubing  is  removed.   The second  type   of
configuration  is  actually  attached to the tubing string  by use
of a stinger assembly located on the lower packer.

In both configurations, the rubber casing cups on the  packer  fit
against  the  old  casing  and are energized with pressure  in the
annulus to form a seal above and below the bad section of  casing
after   the  injection  packer  is  mechanically  set   above  the
injection zone.

To maximize the concentric packers effectiveness in isolating  a
leak,  the  casing  wall  should  be  cleaned  to   facilitate  the
ability of the rubber casing  cups  to  form   a  seal.    Sharp  or
extremely  rough  areas  of  the  casing should be  dressed  out  to
prevent tearing of the rubber elements while the packer is   being
run.   In  addition,  the  appropriate  durometer   rating for  the
rubber  elements  should  be  selected  to  compensate  for    any
corrosion  of  the  casing wall.  Particular care should  be  given
during the  workover  operation  to  accurately  determining  the
location  of  all  leaks  and to placing the packer assembly over
this interval.

Field results have demonstrated that if all of the  above  points
are   adequately   addressed,   the  concentric  packer  will   be
effective in isolating the bad section of casing  and   allow  the
well  to pass the mechanical integrity test unless  other  problems
manifest themselves during the test.
 ECONOMIC COMPARISON OF REMEDIAL ACTION OPTIONS

 The  six  case  histories  detailed  in  Table   1   represent   a
 comparison  of  the  typical  costs  associated  with  squeezing,
 installing a liner, and  running  a  concentric  packer.  A  case
 history   covering  the  cost  of  backing  off  old  casing  and
                              969

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\f\
                     -Casing
                                                    FIGURE  1




                                        CONCENTRIC PACKER  ASSEMBLY
                     -Cemnt
                     • Upper Picker
                     •Casing Collar Leak
                     •Sleeve
                     -Hole
                     -Lower Packer
                     -Formation
                     -Tubing
                                       970

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                             TABLE  1
CASE 1:   CONCENTRIC PACKER
               7" X 5 1/2" X 2  7/8" CONCENTRIC  PACKER
               WORKOVER RIG
               5 1/2" LINER (42')
               TRUCKING, SUPERVISION &  LABOR
 $  1100
    720
    230
    500
 $  2550
CASE 2:  CONCENTRIC PACKER AFTER TWO SQUEEZE  JOBS
               WORKOVER RIG
               CEMENT & CEMENT SERVICES
               TOOLS, TRUCKING, SUPERVISION  &  LABOR
               7" X 4 1/2" X 2  3/8" CONCENTRIC  PACKER
               4 1/2" LINER (108' )
               WORKOVER RIG
               TOOLS, TRUCKING, SUPERVISION & LABOR
$11000
  3500
  7010
$21510

$ 1100
   600
  1000
  1400
$ 4100
CASE  3:  TWO SQUEEZE JOBS
               WORKOVER RIG
               CEMENT & CEMENT SERVICES
               TOOLS, TRUCKING, SUPERVISION & LABOR
$15000
  3200
  7100
$25300
CASE  4:  5 1/2" LINER IN 7" CASING
               WORKOVER RIG
               5 1/2" LINER  (2500' )
               CEMENT & CEMENT SERVICES
               5 1/2" X 2 3/8" INJECTION PACKER
               TOOLS, TRUCKING, SUPERVISION t LABOR
$10000
 12500
  2500
  1000
  8900
$34900
CASE  5:  3 1/2" LINER IN 5 1/2" CASING
               WORKOVER RIG
               3 1/2" LINER  (2600')
               2 1/16" TUBING
               3 1/2" X 2 1/16" INJECTION PACKER
               CEMENT & CEMENT SERVICES
               TOOLS, TRUCKING, SUPERVISION & LABOR
$10000
  8500
  6400
  1800
  2000
  9400
$38100
CASE  6:  CONCENTRIC PACKER
               4 1/2" X 3" X 2 3/8" CONCENTRIC PACKER
               WORKOVER RIG
               3" LINER (365' )
               2 3/8" TUBING W/ CROSSOVERS TO 2 7/8" TUBING
               TOOLS, TRUCKING, SUPERVISION &. LABOR
$  650
  4100
  1130
   540
  2680
$ 9100
                                971

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replacing it with new  is not  included  due  to the  fact  that  the
operation  is  generally   feasable   only   when the leak is at the
very top of the casing string  and the  pipe is free of cement  and
debris.
The  situation  detailed   in  Case   2   is  represented by the  well
schematic in Figure 2.  This schematic  illustrates  the  situation
where  a  well  has  been  squeezed  several  times  in an attempt  to
repair  the  casing  and   pass   the  mechanical   integrity  test.
Although  the  squeeze jobs successively reduced  the magnitude  of
the  leaks,  they  were  unsuccessful   from  the  standpoint    of
adequately   repairing   the  leaks  so  that the   casing  could
demonstrate integrity  After  the   third   squeeze,   a  concentric
packer  was utilized to isolate  the  entire  interval of bad  casing
and allowed the well to pass the mechanical integrity test.
The actual workover operation and associated  costs  of   a   squeeze
job  performed  on  an   injection  well   is summarized  in  Table 2
while Table 3 summarizes a hypothetical   workover   operation  and
the  associated  costs of running a concentric  packer on the same
type of well.  Comparison of the two  procedures  indicates  that
had  the  option of using a concentric packer existed at the time
the squeeze jobs were performed, a cost  savings of   approximately
63% could have been realized.

The  workover operation  and costs summarized  in Table 4 are those
associated with utilizing a concentric packer on a   well   with  a
casing  leak  that  was  determined inappropriate to squeeze based
on its  size  and  proximity  to  a   highly   permeable  sandstone
formation.  Review of other wells previously  squeezed in the same
area indicated that the  minimum expected cost of  a squeeze  job
would  be  $5250  with   at  least  two   squeeze jobs   needed  to
adequately  correct  the  problem   in    order   to  demonstrate
mechanical  integrity-   ,Using  a concentric  packer, the operator
was  able  to  locate  the  leak,  repair the  well,   pass   the
mechanical  integrity  test  and  resume injection  within  one day
which resulted in considerably less downtime  and expenses  than  a
squeeze job.
SUMMARY

Comparison   of   the   procedures   and  associated   well   costs
demonstrates  that  the  use  of  a  concentric   packer    is  an
attractive  alternative  to  squeeze cementing or running  a  liner
in a well for the purpose of acquiring  mechanical  intergity  of
the  casing.  Although  savings  are dependent upon  the  operating
protocol of the oil company involved  in  the  workover  and  the
individual  well conditions, the use of a concentric  packer  in an
appropriate situation can result  in  a  significant   savings  in
repair costs and in time needed to get the well  back  in  service.
                               972

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c
           :.••»
                                          FIGURE  2


                            COMPLETION  SCHEMATIC  FOR  CASE 2
                           3/4'
                                60 *x

              348*
             TOP OF 7- x 4 1/2" x 2 3/B" COJCHWRIC PACKER
           G{" 373 '-404*  Sail. PH«DLE OR COLLAR LEAK
                                                 TVOCE
           Ł> 404'-436'  LAKE HOLE.  CEMENT TO SURETiCE AM) SQCEE2E TO
           -*           500 PSL
              465'
             BOTTCM OF OCNCENTRIC PACKER
c>
           VI
C^ 2785*
'•i
                         7" x 2 3/8"  AD-1 DNSICN PACKER
          . '•$ 2905'-2966*  PERPQRATICIB


            ^•; 2974'       7" CEMEJ/m) W/ 270  ax
                                 973

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                              TABLE 2
 OPERATION SUMMARY OF CEMENT SQUEEZE AS PERFORMED  ON  INJECTION  WELL


 1.  Move in rig up well service unit & blow well  down
 2.  Trip out hole w/tubing & packer
 3.  Trip in hole w/retrievable bridge plug &  packer  on  tubing
 4.  Set retrievable bridge plug at 2780'
 5.  Pressure test retrievable bridge plug
 6.  Isolate casing leaks at 2407'-2500'
 7.  Pump 1 1/2 BPM at 300 psi
 8.  Trip in hole & latch onto retrievable bridge  plug
 9.  Attempt to set retrievable bridge plug at 2809',2780', and 2620'
10.  Unable to shut off flow: Trip out hole w/tubing  and tools
11.  Trip in hole and set cast iron bridge plug by wireline at  2805'
12.  Trip in hole w/open ended tubing to 2572'
13.  Move in rig up cementers
14.  Spot 100 sx cement from 2572' to 2034'
15.  Trip out hole w/tubing and fill casing w/water
16.  Pressure casing to 750 psi: squeeze 1 1/2 bbl cement behind pipe
17.  Shut-in and wait on cement
18.  Trip in hole w/bit and 2 drill collars on tubing:
     Top of cement at 1800'
19.  Drill cement to 2580'
20.  Pressure test casing to 200 psi. Held OK
21.  Drill cast iron bridge plug at 2805'
22.  Clean out well to TD of 2985'
23.  Trip out hole and lay down tubing and tools
24.  Trip in hole w/Baker AD-1 packer on tubing
25.  Load annulus w/packer fluid
26.  Set packer at 2791'
27.  EPA mechanical integrity test to 200 psi. Held OK
28.  Release pressure
29.  Resume injection
COST SUMMARY
     Well service unit
     Tank truck service
     Tools
     Wireline service
     Baker AD-1 packer
     Cement and services
$ 4764
   687
  1440
   695
  1175
  1497
$10238
                                   974

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                             TABLE 3
 HYPOTHETICAL   OPERATION  SUMMARY  UTILIZING   A   CONCENTRIC  PACKER
             TO  REPAIR CASING ON INJECTION WELL
1.  Move in rig up^ well  service unit & blow well  down
2.  Trip out hole  w/tubing & packer
3.  Trip in hole w/retrievable bridge plug & packer  on  tubing
4.  Set retrievable bridge plug at 2780'
5.  Pressure test  retrievable bridge plug
6.  Isolate casing leaks at 2407'-2500'
7.  Trip out hole  w/retrievable bridge plug and packer  on  tubing
8.  Trip in hole w/ Baker AD-1 and concentric packer with  103*
    of casing  sleeve on  tubing.
9.  Load annulus w/packer fluid
10.  Set Baker  AD-1 packer at 2791'
11.  EPA mechanical integrity test to 200 psi.
12.  Release pressure
13.  Resume injection
COST SUMMARY
    Well service unit           $  450
    Tank truck service             200
    Tools                          300
    Casing sleeve                  530
    Baker AD-1 packer             1175
    Concentric packer             1100

                                $ 3755
                                 975

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                              TABLE 4
            OPERATION SUMMARY AS PERFORMED ON »1 SWD
 1.   Move in rig up well service unit and wireline unit
 2.   Run radioactive tracer survey: pinpoint leak at 165'-195"
 3.   Trip out hole with tubing and packer
 4.   Trip in hole with injection packer and concentric packer on
     tubing
 5.   Run tracer survey for EPA:  no leaks
 6.   Rig down well service unit  and wireline unit
 7.   Resume injection
COST SUMMARY
     Well service unit           $  375
     Tracer survey                  600
     Casing sleeve (40')            160
     Concentric packer             1100

                                 $ 2235
                              976

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THEORY,  DESIGN AND OPERATION OF AN ENVIRONMENTALLY MANAGED PIT SYSTEM


Darrell  Pontiff, John Sammons
SOLOCO,  INC.
Lafayette,  Louisiana

Charles  R.  Hall, Richard A. Spell
Oryx Energy Company
Houston, Texas


Introduction

Onshore Drilling has traditionally utilized a  single  large reserve pit  to
contain drilling waste cuttings,  water, and other liquids.    Today,   how-
ever,  with  increased environmental awareness  and  responsibility,   land
owner concerns and the complications of greater  drilling  depths,   the  tra-
ditional reserve pit can be extremely expensive  if not  prohibitive to   op-
erate.

This  paper addresses an environmentally managed reserve  pit   system   that
can minimize the cost of the disposal of drilling wastes.   This  is accom-
plished  by constructing a reserve pit system  consisting  of four   or   more
pits  and  managing  the  wastes in these  pits   to  segregate relatively
uncontaminated  wastes  from the more contaminated wastes.    The  program
maximizes the use of the traditional onsite disposal  methods,   land farm-
ing,  burial,  and injection, while minimizing or eliminating  offsite  dis-
posal.

The  most effective application of this system is when  drilling waste   can
be  land farmed and/or injected onsite,  though  experience has shown   that
the  use  of the system can result in savings  when much of the  waste  is
handled offsite.

The  use of this system depends on the proper  planning  and  communication
coupled with proper location design and effective pit management.


System Design

A successful environmentally managed reserve pit program  must  begin with a
design  meeting.   This should include representatives  of the  operator,
(such as drilling engineers, operations,  land,   and  environmental person-
nel), site preparation contractors and reserve pit management  personnel.
Items of discussion should include the well drilling  program,  orientation
                                  977

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of the location and positioning of the well  stake,  available  acreage  adja-
cent to site for land farming,  landowner concerns  and  regulatory   limita-
tions,  choice of drilling contractor and rig,  and accessibility   to the
drill site.

The next step in the design program is site  assessment.    This  should in-
clude  photographs of the site, preliminary  background  soil   sampling and
testing,  establishing good communications with the landowner,  and deter-
mine the possibility of flooding conditions,  runoff areas and  other  land
conditions.

1. Background testing of the soil is highly  recommended to determine  the
   possibility of pre-existing contaminants  in the  soil and to  establish
   soil characteristics that may affect land farming operations.

2. Good communications with the landowner can answer many  questions about
   how the area handles rain water runoff and land  use  prior  to and after
   drilling.

A management checklist,  as shown in Fig. 1,  is used to assemble the data
to be used in the reserve pit design, as shown in Figure #1.  Based on the
information  gathered,  the reserve pit system is then  designed to  handle
the volumes of waste to be generated, the expected  weather conditions, the
planned  disposal  of the drilling generated waste,  and oriented   to the
planned drill site.

The  environmentally managed reserve pit system is  predicated on two  pri-
mary operation considerations:

1. Ability to land farm non-contaminated material on site.

2. Annular disposal of contaminated material down hole.

The use of annular disposal requires approval from  the  appropriate  regula-
tory agency and is affected by casing depths,  cement requirements  and un-
derground sources of drinking water (USDW).

Land  farming operations for a reserve pit management project requires  an
additional four to five acres of land in addition to the actual drill and
pit site.    This is necessary as the solids  should  be spread  to a   maximum
of three inches in thickness.   Amounts in excess of three inches will not
de-water and dry properly, making land farming and  dilution difficult.
                                   978

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From the above parameters, a pit system  is  designed.   A typical pit system
design is shown in Fig. 2.  The design shown  in Fig.   2 should not be con-
sidered as a fixed design as it represents  only what  was required for  one
particular well.  Flexibility in this pit system allows for different con-
figurations, orientation, number, and size  of pits  to accommodate most lo-
cations, well depths, and drilling mud programs.
Construction

The construction of the environmentally managed  reserve  pit system  should
be  performed by a reputable site preparation  contractor who  is   familiar
with the application of the system, utilizing  proper  equipment,   and under
competent  supervision.   This should assure the operator of  receiving   a
finished product that meets specifications and site plans.

The  levee  walls are constructed in a manner  to allow movement   of   heavy
equipment  such as draglines on the levees to  work each  of  the pits.   The
entire  reserve pit system is constructed in an  area  that  normally   would
hold  a  traditional 200'  x 300'  reserve pit for a  well  to  be drilled
14,000' to 18,000'.

Typical equipment used on managed reserve pit  locations  include draglines,
bulldozers, and pile driving equipment (if a bulkhead is constructed).

'One option the operator has during the construction phase is to include   a
timber bulkhead in lieu of an earthen levee on the rig side of the  shaker
pit  (Detail A,  Fig.  2).   The purpose of the  bulkhead is to reduce the
length  of slides and pipes leading from solids  control  equipment to the
pit and to increase the drop angle of the slides and  pipes.    This reduces
the tendency of the slides and pipes to clog during the  drilling  operation
which requires flushing with water.   This in  turn reduces  water  volume  in
the pit which ultimately requires some method  of disposal.   Although the
bulkhead  system increases the up-front construction  costs,  it will  save
costs on the volume of water to be handled during drilling.
Reserve Pit Operation

In daily operation of the environmentally managed reserve  pit  system,   Pit
//I is "The Shaker Pit".   The waste generated by the solids  control  equip-
ment  is discharged into this pit.   Material in this pit  may  be moved   by
dragline to Pit //2 for storage or moved directly to the  land farming area.
Fluid  may be transferred from Pit //I to Pit //3 through  a  PVC  pipe set   in
the levee wall or with centrifugal pumps.  This fluid in Pit //3 is stored
                                   979

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to allow the solids to settle.   The  water  is  then moved by centrifugal
pumps  to Pit /M.   The water  in Pit //4  is either recycled for rig use  or
tested  and treated for discharge as allowed  by regulations.    Rain  water
and  waste water from the  location may be  pumped directly to  Pit //3.    Pit
//5 is provided to contain  salt water flows,   cement  over runs,  and  other
emergency pit functions.

Maintenance  of freeboard  or maximum allowed  volume  in the pit  system  by
treating and discharging water can be a  costly  item  depending on the  dura-
tion of the drilling operations.   Water conservation  items to be  consid-
ered for use on a proposed drilling  program include:

1. Construction of drillsite location no larger than necessary.

2. Use of automatic shutoff nozzles  on all hoses on  rig floor and washdown
   racks.

3. Recycling of reserve pit water to wash  out slides draining to shaker
   pits.

4. Use of ring levee water (if acceptable) for  makeup  water.

5. Use of drip pan beneath rig floor with  flexible hoses draining to
   cellar to avoid dirty water and mud dripping on rig substructure
   and location area.

6. Installation of water meters  on fresh water  sources to monitor and
   control water usage.
Reserve Pit Monitoring

An  environmentally managed reserve pit program  requires  daily  monitoring
of the project by the reserve pit management  personnel.   The status  of  the
pit  system  is surveyed daily to determine volumes  in each  pit,  changes
from the previous day,  work performed in handling wastes from any of   the
pits,  rainfall  amounts,  and weather conditions.    This  information   is
charted daily on the work progress report (Fig.  3) and provides documenta-
tion on waste volumes handled throughout the  job and disposal methods uti-
lized.

Samples can be extracted from the pit system  and analyzed or bench  tested
by  an  approved  laboratory in accordance with  current  State  rules   and
regulations.  The analyses of these samples dictate  the disposal method
used.


                                   980

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Open communication between the reserve pit management  personnel,   mud com-
pany  personnel,   drilling contractor and the company   representatives  is
very  important.    All parties involved must know complete  daily   activity
and also what is  planned for the following day.   A successful  reserve pit
management program requires the cooperation of all parties  mentioned above
which is usually  stressed at the "spud meeting"  before drilling   actually
begins.
Waste Management

A  reserve  pit management is based on handling drilling waste   by   onsite
disposal methods.  The program uses traditional onsite disposal  techniques
including  land farming mud and cuttings which meet regulatory   guidelines
for  onsite disposal,  burial,  treating and discharging of pit  water   and
rain  water,  and injection.   In the event that one or all of the   onsite
disposal methods cannot be used,  offsite disposal of the contaminated  ma-
terial at an approved commercial disposal facility may be necessary.  This
is  the  last option considered due to increased costs  when  compared  to
onsite methods.

Land farming operations consist of isolating mud and cuttings and  spread-
ing this material no greater than three inches thick,  allowing  the  mate-
rial to de-water,  then plowing the solids into the existing ground  to  the
appropriate  depth to achieve proper dilution.   The application of  soil
amenities and replowing is acceptable.

Treating  and discharging of pit water occurs when enough water  has  been
generated  to fill the treating pit.  Pit water samples are extracted   and
analyzed in accordance with current rules and regulations to determine  the
level  of  contamination,  chemically treated to  reduce  contaminants  to
within regulatory limits,  then re-analyzed, and finally discharged  onsite
after obtaining regulatory approval.

Pit waste that cannot be land farmed or chemically treated and   discharged
is stored in the reserve pit system for annular disposal.   The  pit  waste
is physically mixed into a slurry by using a dragline,  then fed to  a dis-
posal pump unit which screens out the larger solids, and injects the mate-
rial.   Chart  recording equipment is used to monitor  pumping   pressures,
record pumping time and disposal volumes.

Any residue remaining in the pit system after annular injection  that  can-
not be dealt with onsite requires offsite disposal.  This process consists
of  loading  the material into vacuum trucks if it is wet,  or   into  dump
trucks if it is drier, and then hauled by an approved commercial disposal


                                  981

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 facility.
Final Reserve Pit Clean Up

Once  drilling  operations  are  complete  and all  of the  options  described
above  have  been implemented,   the  reserve pit  management system  can  be
backfilled using earthen levee  material.    Any trash and debris is  removed
from the site and properly  disposed.   The  pit system area is  leveled  and
restored  to predrilling conditions.   Post closure sampling and analyses
are  performed  on the backfilled  area to insure compliance with  current
rules and regulations.   All documentation  is  compiled into a  post  closure
package for the operator's  files and is  helpful  in filling out forms   con-
cerning the disposition of  the  waste.
Advantages of a Managed Reserve  Pit System

The two main advantages of the managed  reserve  pit  system are the   ability
to  process  drilling wastes as  generated and the  isolation  of  wastes  to
minimize contamination.   These  advantages  are  reflected  in  lower  disposal
costs.

The ability to process drilling  waste as generated  is  significant  in  that
it reduces the volume available  for contamination,   it reduces the impact
of unexpected problems,  and it  keys rig personnel  to  the effects  of  their
actions on waste management.  By processing the waste  as  generated, only a
small volume of waste is present in the pit system  which  could potentially
be contaminated.   In a conventional reserve pit,   the entire pit  contents
could be contaminated.

The  ability  to  isolate waste  is beneficial because   it prevents  small
amounts of highly contaminated waste from impacting large amounts  of  man-
ageable waste.  It also allows flexibility  in the scheduling of waste pro-
cessing.   In addition,  isolation provides the opportunity   for  selected
waste  to  be  treated  by alternative  methods such   as solidification,
dewatering, etc.
Conclusion

An effectively designed and environmentally managed  reserve pit system can
not only facilitate compliance with the regulations  on reserve pit closure
and disposal of drilling waste; it can reduce  the  cost of compliance.   The
proper design, construction, and daily management  of a managed reserve pit
                                  982

-------
system  can minimize or eliminate the volumes of drilling waste  that  re-
quire offsite disposal.   The result can be substantial savings over  con-
ventional methods currently available.
                                 983

-------
                                   FIGURE  1
                  RESERVE PIT  CONSTRUCTION, MONITORING,  it



                             MANAGEMENT  CHECKLIST
 Operator/Drilling Co. 	     DATE:_



 Well  Ntme           	



 Location of  Well	



 Company  MID        __^	Ph.  »
 Well Depth           	 Ft.  No. of Dayi



 Mud Program        	Cuing Program 	
 Land Available       	  Acres



 Site Map  Available               Yes 	       No 	



 Rig Plat Available                Yes 	       No 	



 Pumping of Water During Drilling  Yes 	       No 	



 Pumping of Mud &  Water After  Drilling   Yei 	  No 	




 Pumping Rate  Allowed 	 bbl/min



 Mai. Pumping  Pressure 	 PS I




 Will Background Testing Be Done  Yes 	        No 	



 Bid Due  Date	
Additional  Comment!:
                                984

-------







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                                   FIGURE  3
                                  DAILY PROGRESS REPORT

                       WASTE MANAGEMENT/TURNKEY REPORT

        FOREMAN	                   REPORT NO.

                                                     DATE: 	
 OPERATOR:

 WELL NAME

 LOCATION:
                   Depib   Vol. Per      Total     Chtnge  From Previoui  Day
 Pit  *    Type      Fool     Fool        Vol.              O or O
Rain Gauge:   AVG. 	IN.         Weather:.
COMMENTS:
DEPTH


MUD WT
AFTER TREATING WATER


CERTIFIED LAB ANALYSIS PERFORMED BY (LAB) 	_DATE 	


PHONE 	


LAB RESULTS:         	 pH


                    	 (TSS) TOTAL SUSPENDED SOLIDS


                    	 CHLORIDES (PPM)


                    	 OIL & GREASE


                    	 (COD) CHEMICAL OXYGEN DEMAND


                    	 CHROMIUM


                    	 ZINC


DEQ APPROVAL BY 	 DAtE_	TIME_


VERBAL OR ONSITE
                                   986

-------
TOXICITY  AND  RADIUM 226 IN PRODUCED WATER 	 WYOMING'S  REGULATORY APPROACH
John  F.  Wagner
Technical  Support Supervisor
Water Quality Division
Wyoming  Department of Environmental Quality
Cheyenne,  WY  82002
 Introduction

 In  1989  the State  of Wyoming  produced about  108  million  barrels  of oil  and
 about 861  million Mcf of  natural gas.  These  levels of production  placed  the
 state sixth in the nation  for both oil  and natural gas production  (1).

 Associated  with  the production  of  this oil and  natural  gas was  approximately
 1.65 billion barrels  of produced water.   About 10% of this produced  water  was
 reinjected  or  pumped  into  disposal  wells  and  about  30%  (^95 million  barrels)
 was discharged  into surface streams and drainages  (1).   The discharges  to  the
 surface are  regulated by the Wyoming Department of Environmental  Quality (DEQ)
 through the  National  Pollutant  Discharge  Elimination System (NPDES)  discharge
 permit program.   It is these discharges which are the subject of this  paper.

 There  are  currently  610  active produced  water NPDES  permits  in  the  state.
 About 95?  of these  permits are  associated  with wells producing oil only  or  oil
 and natural gas.  Only about 5%  are  associated with  wells  producing only natural
 gas or coal bed methane.

 Regulatory History

 The NPDES  program can be delegated by  the U.S. Environmental Protection  Agency
 (EPA) to the states.  Wyoming has had  primacy for the NPDES  program since
 In  1976 when  the  EPA  proposed  effluent  standards  for  produced  water,  it identi-
 fied  best  practicable treatment  (BPT)  for on-shore  oil  and gas  production  as
 "no discharge of  produced water".   EPA's  position was that reinjection  was  an
 efficient and  cost effective alternative to surface discharge.

 Adoption of the proposed  EPA  regulation would  have meant  the elimination  of all
 produced water discharges in  Wyoming.   Because Wyoming is a  semi-arid state and
 because much  of  the  produced water  in the state  is relatively  "fresh"  (less
 than  5,000  mg/1  of total dissolved solids),  loss  of the produced water would
 have  meant the  loss  of  important  sources  of water for stock and  wildlife.
 Because of this,  the  state expressed strong objection to  the EPA  proposal.
                                     987

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As a result of  the  state's  efforts and with the assistance  of  EPA Region  VIII,
the final version of the EPA  regulation contained  an  "Agriculture  and  Wildlife"
subpart.  This  section of the  regulation  allows the surface discharge  of  pro-
duced water provided the following conditions are  met:

1.   That the discharge is located west of the 98th meridian;

2.   That the produced water  is of good  enough quality to be used  for wildlife
     and  livestock  watering  or  other  agricultural uses  and that  the produced
     water is actually put to such use during periods of discharge; and

3.   That the oil and grease  concentration not exceed 35 mg/1.

While  the state  was  generally  satisfied  with  the  final form  of the  federal
regulation,  it  still   had  two  concerns.    First,  the allowable  oil and grease
concentration of  35 mg/1 was much higher than  was  acceptable.   The  state had
data  from its  own  sampling as  well as  the sampling of  the dischargers which
showed  that, a properly operated and  maintained system  consisting of a heater
treater  followed  by a  series of  skim  ponds  could  consistently meet an  oil and
grease  limitation of  10 mg/1.  Second, the state  felt that  proving that a  dis-
charge  was  actually being put to use for agricultural and wildlife  purposes was
going  to  be a cumbersome  and  time consuming process.  In addition, the  regula-
tion seemed to  prohibit  new produced  water discharges since it would  be impos-
sible  to show  that  the  discharge  was  being  put  to  use  if  it  had not yet
occurred.

The solution  to  this  problem  was for  the state to adopt  its own produced water
effluent  regulations  within  the general  framework  of  the federal regulation.
Therefore,  in  1978 Wyoming  adopted  the  produced  water  effluent standards (2)
summarized  in Table 1.
                                    TABLE  1
         Summary of State of Wyoming produced water effluent standards

Parameter                              Standard
Chlorides                              2,000 mg/1
Sulfates                               3,000 mg/1
Total Dissolved Solids                 5,000 mg/1
Oil and Grease                         10 mg/1
pH                                     6.5 - 8.5 std. units
Toxic Substances                       None in concentrations or combinations
                                       that are toxic to human, animal, or
                                       aquatic life


Because the state's oil  and grease standard was more restrictive  than  the  fed-
eral standard,  EPA  had no  objection to  that  part of the state regulation.   In
addition,  the  state took the  position that any  discharge meeting  the limita-
tions shown  in Table  1  was suitable  for  stock and  wildlife  use,  and  assumed
that the water  was actually being  put  to such use.  EPA's  Region VIII,  which has
oversight authority for Wyoming's  NPDES program, has accepted this approach.
                                     988

-------
While  the  state has had language  in  its regulations since  1977  prohibiting the
discharge  of  toxic substances  (see Table  1), no  serious effort  was made  to
identify or  quantify the presence of toxics in  produced  waters  in  Wyoming until
1987.   There were  two reasons  for  this:  first, most  (about  85$)  of these dis-
charges flow  into  intermittent or ephemeral  drainages which are not  protected
for aquatic  life  uses.    In addition,  the  waters were  clearly  being  used  for
.stock  and  wildlife watering with  no  apparent  ill  effects.  Second,  for those
discharges which  do flow  into  live  waters,  there did  not  appear  to  be  any
obvious problems  (no reports  of  fish  kills  or  complaints  from  the  wildlife
management agencies).  However, it must also  be stated that there was  a limited
amount of  information in the state's  files  as well as in  the literature  (8)  to
indicate that  the  presence of  aquatic  life  toxicants  in produced water  was  a
distinct possibility.

In  1987,  EPA's Region  VIII began  to  aggressively  promote the use of  "whole
effluent toxicity"  (WET) testing as an  economical and  efficient  means  of  deter-
mining the  toxicity of  wastewater discharges.  The WET test involves  exposing
aquatic organisms   (usually an  invertebrate  such  as  Ceriodaphnia  dubia  and  a
fish  species  such  as fathead minnows)  to  varying concentrations of wastewater
effluent.   The  reaction of the  organisms  (mortality, loss  of weight,  or«reduc-
tion  in reproduction) is used to estimate the  relative toxicity  of  the effluent
to aquatic life in  general.

In  August  of 1987  the  state  sent effluents  from eight different  Wyoming  pro-
duced  waters  to EPA for preliminary  screening.  EPA's testing revealed varying
levels  of acute  toxicity   (mortality)  to  Ceriodaphnia  in seven  of the  eight
effluents.   In  October  of  1987, EPA  sent  their mobile  laboratory from Duluth,
Minnesota  to Casper, Wyoming  to run  acute  and chronic  WET  tests on  produced
water  effluents.   The results of EPA's  testing  (3) are summarized in Table 2.

 In  addition  to  conducting  the  WET tests,  EPA also conducted Toxicity  Identifi-
cation  Evaluations  (TIEs)  on   eight  different Wyoming  produced waters.   Those
 investigations  indicated   that  in most cases  hydrogen  sulfide (HpS)  was  the
suspected primary  toxicant but  that,  in at  least  one  case, a non-polar organic
was probably  the primary toxicant.  In  the particular effluents  tested,  salinity
did  not  appear to  cause   toxicity  even  though  total  dissolved  solids  (TDS)
concentrations  were in the  2,000 - 4,000  mg/1 range.   It was concluded  that
salinity  toxicity  would be more likely if more of the salinity  would  have been
 in  the form  of  sodium chloride.

This  EPA  study provided conclusive  evidence  to  the  state that produced  water
discharges  had  significant potential  for  toxicity and that, at  least  for those
discharges  flowing into class   1, 2, or 3  waters  (waters  which  receive aquatic
 life  protection under  Wyoming's standards),  corrective  actions  would  be  neces-
sary.   Also  at  this time,  EPA directed  the states  to begin preparation of their
 304(1)  lists.   Section 304(1)  of the federal  Clean Water  Act requires  each
state  to  identify   its  toxic discharges and  to develop a  strategy  for  elimina-
 ting  the  toxicity  by  July, 1992.   In response  the  state began an exhaustive
 field  review of all of  its produced water discharges.   The purpose  of  the field
 review was  to place each discharge into one of  the  following three categories:
                                    989

-------
     Category 1  - Discharge flows immediately into a class 1, 2, or 3 water.

     Category 2  - Discharge flows into a class 1, 2, or 3 water after traveling
                  a significant distance in a class 4 water.

     Category 3  -Discharge will not  reach  a class  1, 2,  or 3 water under dry
                  weather conditions.
                                    TABLE 2
         Acute and chronic toxicity in four produced waters in Wyoming

Organism/Test
Ceriodaphia/LC50(1)
Fathead M./LC50
Ceriodaphia/LOEC(2)
Fathead M./LOEC
*
Timberline
55%
55%
10%
30%

Conoco 03
2%
2.6%
n
3%

Conoco 90
55%
31*
30%
-

Amoco LACT 11
5%
2.5%
3%
3%

(1)   The 50%  lethal  concentration or the effluent  concentration  at which 50%
      mortality  to  the  test  population occurs.   Ceriodaphnia  exposed  for 48
      hours, fathead minnows for 96 hours.
               «
(2)   The lowest  observed  effect concentration or  the  lowest effluent concen-
      tration  at  which a  statistically  significant  reduction  in  reproduction
      (Ceriodaphnia) or growth (fathead minnows) occurs.

(Summarized with  permission  from Taraldsen,  Amato,  and  Mount, Toxicity Testing
and  Characterization  of Toxicants  From Effluents  of the  Powder  River Basin,
Wyoming.)
The state's field review  resulted  in  the placement of 50 discharges into cate-
gory  1,  57 discharges  into  category  2, and  503 discharges  into  category 3.
Those facilities in category  1  were  then placed on the state's 304(1) list and
the NPDES permit for each was modified to include the following:

1.    A  requirement  to conduct  two  species  (Ceriodaphnia  and fathead minnow)
      acute toxicity tests on at least an annual basis;

2.    A requirement to eliminate toxicity by July  1,  1992; and

3.    A list of three options for achieving compliance,  including:

      a.  Treatment to remove acute toxicity;

      b.  Elimination of the discharge; or

      c.  Passing  the  two  species  chronic  toxicity  tests  by  utilizing the
          dilution factor in the receiving stream.
                                     990

-------
The status of  the category 1 discharges as of July  1,  1990  is  given in Table 3.


                                    Table 3
       Compliance Status  (as of July  1,  1990)  for category 1 discharges

Out of  compliance due to failing acute toxicity test for  both  species        15
Out of  compliance due to failing acute toxicity test for  Ceriodaphnia only    3
Out of  compliance due to failing acute toxicity test for  fathead  minnows  only 2
Out of  compliance due to failure to test                                       3
In compliance  due to passing acute test for both species                       3
In compliance  through elimination of the discharge                             6
In compliance  due to passing of the chronic toxicity test for  both  species    2
In compliance  due to an expected reduction in stream classification           3
Not tested,  but facility typically non-discharging                            12


Information from  the  dischargers  indicates  that,  in many cases,  acute  toxicity
can be  removed  through aeration and that the  most common  toxicant encountered
is hydrogen sulfide.    However,  many  operators are  indicating that  their pre-
ferred method  of achieving compliance  is through reinjection.  Reinjection  has
the following advantages over treat and discharge:

 1.    The solution  is  final  in  the  sense that  there is no  concern  about  future
      changes in toxicity  requirements;

2.    Since there  is  no  discharge  there  is  no  possibility  of being out  of
      compliance;

3.    The testing and reporting costs  associated with monitoring an  NPDES dis-
      charge are eliminated;

4.    The costs  of  operating and maintaining a  treatment  system are eliminated,
      although they may be replaced or outweighed by the  costs of reinjection;

5.    In some cases  the produced water can  be used  to  enhance  oil production by
      increasing pressures in the producing formation.

 Action on the category  2  discharges is not  expected  to be initiated until  after
 1992 when compliance  by .the  category 1 dischargers  should be  complete.  Consid-
erable  work  still  has  to  be  done to  determine  to  what extent  toxicity  is
 reduced or  eliminated  when produced waters  travel long distances in  open  chan-
nels prior  to confluence  with flowing  streams.  Preliminary evidence indicates
 that toxicants  which tend to be volatile  in  nature are  effectively  removed by
natural  aeration processes.    More persistent  toxicants,  such  as  chlorides,
appear  to  be  uneffected.   This  conclusion  is  supported  by the work  of Lamming
 (*!) who observed chronic  toxicity effects on Ceriodaphnia 68  kilometers below a
 number of large  volume produced water  discharges.   However, it is  the  position
of the  state  that WET  test  results  should  be  supplemented with  in-stream bio-
assays.   King (5)  studied zooplankton  populations  in Wyoming stock  ponds  and
observed little  difference between  those  consisting  primarily  of  produced  water
 versus those  consisting only  of natural runoff.
                                    991

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At this time the  state  has no intent of addressing  toxicants  in  the category  3
discharges.  Such discharges  do  not effect  waters  protected for  aquatic  life
uses;  however,  such discharges  are used extensively  by stock and  terrestrial
wildlife.  There  is no evidence  to date that stock and  wildlife  are adversely
effected  by  drinking produced water, although  research in  this  area  is  very
limited.

Radium 226

In early  1989,  the State  of Wyoming received  a report  (6)  from  the State of
Louisiana's Department  of  Environmental  Quality which addressed the  problem of
radiation  associated  with  oil and  gas production.   Information in  that  report
indicated  that  produced waters had  the potential to  be high  in  dissolved radium
226. In response,  the  Wyoming DEQ selected four of  its  produced waters  at  ran-
dom  and  had  them  analyzed for radium 226.   Three  of the  four samples  showed
total  radium 226  levels of 0-10  picoCuries/1  (pCi/1).   Levels such as these are
not  considered  to be unusual;  however,  the  fourth  sample  showed  a  radium 226
concentration of  approximately 1,200 pCi/1.   Subsequent sampling  of  this  dis-
charge and analysis by  a second  laboratory  resulted  in a reading of about 1,700
pCi/1.

This single very  high  value indicated to the state  that  there was  at least the
potential  for a problem with high radium 226  levels  in Wyoming  produced  waters.
Therefore, in August  of 1989 the agency  requested that all produced  water  dis-
chargers  test   for  radium   226  and   submit  the  results  to  the  DEQ within six
months. Results of  this voluntary self-monitoring program are given  in Table 4.

Currently  Wyoming has an  in-stream  standard  for radium 226 plus  radium  228 of
5.0  pCi/1.  This  standard  is based  on the national  drinking water  standard but
applies  to all  waters  in  the state regardless  of whether  or not  the water is
classified  for drinking   water  use.   Since  produced  water  discharges often
comprise  the only flow  in  intermittent streams,  discharges  to such streams  were
faced  with the  prospect of having to meet a 5.0  pCi/1  radium  limit at the point
of discharge.

This  situation  caused  DEQ  to   reevaluate  the  appropriateness  of  using the
federal  drinking   water  standard for  waters  not used  for  human  consumption.
Investigation  of   the  matter  revealed  that  the Nuclear Regulatory  Commission
(NRC)  had  established a  limitation  on radium  226 for unrestricted  access waters
(waters not being used  for human consumption) of 30 pCi/1.   Further  investiga-
tion showed that  the  NRC  is currently in the process  of reviewing that  regula-
tion and  that  the new proposal  is  for  a 60  pCi/1  limit (7).  Since  the NRC's
unrestricted access waters appeared to be analogous  to waters classified by the
State  of  Wyoming  as  class 3 and 4 waters,  DEQ  has proposed changing  its in-
stream standards  for  class  3  and 4 waters  from 5 pCi/1  of radium 226 plus 228
to 60  pCi/1  of radium 226.   The state  plans to leave  its standard  for  class  1
and  2  waters, which are classified  for drinking  water  use,  at 5 pCi/1 of radium
226  plus 228.
                                     992

-------
                                    TABLE 4
         Total  radium 226 concentrations  in Wyoming produced waters

     Total  number of discharges  tested                373

     Highest recorded value                         2,152 pCi/1

     Lowest recorded value                              0 pCi/1

     Average value                                   21.5 pCi/1

     Median value                                     3.7 pCi/1

     Number of values greater  than  1,000 pCi/1          2

     Number of values greater  than  100  pCi/1            6

     Number of values greater  than  60*  pCi/1           15

     Number of values greater  than  5**  pCi/1          167

     Number of values less  than  5 pCi/1               206

*    Proposed  Nuclear Regulatory Commission  Standard  for  unrestricted access
     waters

**   U.S. EPA drinking water  standard  (radium 226  plus radium 228).


If the DEQ's  proposed modification  is accepted  by the  state's  Environmental
Quality Council,  it  is expected that approximately 50 produced  water discharges
will  be  effected.   Since it  is  doubtful  that radium  226 removal  technologies
will  be  practicable for  produced waters,  it  is  assumed  that these discharges
will  be reinjected.

Summary

Wyoming  has  regulated produced  water  discharges   to  surface  drainages  since
197^.  Until  the late  1980's,  the major pollutants of concern were salinity and
oil  and grease.  In  1987,  evidence  was collected  which showed  that  produced
water effluents  were  likely  to  be  toxic to aquatic   life.   It  appears  that
produced waters  often  contain  relatively short-lived volatile toxics that cause
immediate  acute  toxicity  and more  persistent  long-lived  toxics that  cause
chronic  toxicity  effects.  These  toxicants are now being regulated in instances
where discharges effect  receiving waters  protected for aquatic life uses.   At
this  time  there  is no  evidence that  the consumption of produced  water adversely
effects  stock or  terrestrial  wildlife,  though  research  in this  area  is  very
limited.

Radium  226  concentrations  in  Wyoming  produced   waters  are  highly  variable
ranging  from over 2,000  pCi/1 to 0  pCi/1.   Where human  drinking  waters  are a
protected  use,  the federal drinking  water standard is the appropriate in-stream
•standard.   For waters  which do not require human  drinking water  use protection,
the  proposed  Nuclear  Regulatory  Commission Standard  for  unrestricted  access
waters of  60  pCi/1 of  radium 226  appears to be adequate.
                                    993

-------
References

1.    W.  Frueauf,  Personal  Communication,  Petroleum Association  of  Wyoming,
      Casper, Wyoming, 1990.

2.    Wyoming  Water  Quality   Rules  and   Regulations,   Chapter   VII,   Surface
      Discharge  of  Water  Associated  with  the  Production  of  Oil  and Gas.
      Cheyenne, WY.,  1978.

3.    J.E.  Taraldsen^1^,  J.R.  Amato^,  D.I.  Mount^,  Toxicity  Testing and
      Characterization of Toxicants from  Effluents  of the Powder River  Basin,
      Wyoming7AmericanScientificInternationalInc.v ',andU.S.
      Environmental Protection  Agency'   , Duluth, MN., 1987.

4.    F.N.  Lamming,  A.M.   Boelter,  H.L.   Bergman,   Assessment  of  Potential
      Environmental Impacts  of Saline Oil  Field Discharges into Salt  Creek and
      the  Powder  River,   Wyoming, Wyoming  Water Research Center, Laramie, WY.,
      1990.

5.    K.W.  King,  Effects  of  Oil  Field   Produced  Water  Discharges  on Pond
      Zooplankton  Populations,  Wyoming Department  of  Environmental  Quality,
      Cheyenne, WY.,  1990.

6.    State  of  Louisiana,   Department of  Environmental Quality,   Radiation
      Associated with Oil and  Natural Gas  Production  and Processing  Facilities,
      Baton Rouge, LA., 1988.

7.    H. T.  Peterson, Jr.,  Personal Communication, Office of Nuclear Regulatory
      Research, Nuclear Regulatory Commission,  Washington D.C.,  1990.

8.    D.F.  Woodward,   R.G.   Riley,  Petroleum  Hydrocarbon Concentrations  in  a
      Salmonid Stream Contaminated  by Oil  Field Discharge Water and  Effects on
      Macrobenthos, Archives of Environmental  Contamination and  Toxicology, 12,
      1983, 327-334.
                                     994

-------
UNSUCCESSFUL OILFIELD WASTE DISPOSAL TECHNIQUES IN
VERMILION PARISH, LOUISIANA
filma A. Subra
Subra Company, Inc.
New Iberia, Louisiana, USA
Introduction

Vermilion Parish  (county), Louisiana  borders the Gulf  of  Mexico,  in
southwest Louisiana.  Within the geographic  boundaries of the
parish, approximately 3,500  oil and gas  veils have been drilled.
These 3,500 veils are distributed  throughout the parish in 66 oil
and gas fields.   The earliest recorded veil  vas  dug in 1922.

The vaste from the  oil and gas drilling  and  production activities
within Vermilion  Parish vas  disposed  of  on site  as veil as in a
number of commercial facilities spread throughout the  parish.
Waste from adjacent parishes as veil  as  other states vas  also
disposed of in the  commercial facilities located in Vermilion
Parish.  Today, only one  commercial facility continues to receive
oilfield vaste.   The other facilities stopped receiving vaste in
the mid 1980's.   The closed  sites  have still not been  cleaned up,
and they all  contain large quantities of vaste.   The environmental
damage at three of  the vaste sites is so severe  that the
Environmental Protection  Agency has designated the sites  as
Superfund sites.

Waste Disposal Methods/Problems

The off-site  vaste  disposal  of oil and gas drilling and production
vaste in Vermilion  Parish has been accomplished  by a vide spectrum
of methods.   Tne  facilities  utilized  methods such as injection
veils, unlined surface impoundments,  land application, landfill,
burial in excavated holes, and marsh  reclamation utilizing
untreated vaste.
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The environmental damage resulting  from  the disposal  of  the  waste
consist of extensive groundwater contamination,  surface  water
contamination, marsh destruction, agricultural  field  damage,
terrestrial environmental contamination, and aquatic  and
terrestrial biota contamination.  The environmental damage is
continuing today because the sources of  contamination, the oil and
gas drilling and production wastes  are still present  at  each of
the off-site commercial locations.  The  total impact  of  the
environmental damage at each site is unknown due to lack of  data.
The three sites with the greatest amount of data are  the three
which are now Superfund sites.  These sites are known as PAB Oil
and Chemical Service, Inc.  Gulf Coast Vacuum Services,  and
D. L. Hud, Inc.
PAB Oil and Chemical Services, Inc.

The PAB Oil and Chemical Services, Inc. site is a 9 4 acre
oilfield waste disposal facility located north of the town of
Abbeville.  The site was approved by the Office of Conservation
(Louisiana Regulatory Authority for oilfield waste) for the
acceptance of oilfield waste.  The site accepted waste from early
1976 until 1982.

The site contains five acres of waste lagoons consisting of four
pits.  Three of the pits are interconnected and contain oily sludge
containing barium, chromium, lead, toluene, and other organics.

As early as April 1979 the pits were documented as having poor
levee construction which was allowing waste to leach through.  The
site was judged a health hazard in 1979 due to its location
one-quarter mile from a sand and gravel pit.  In 1980, EPA
documented 22 drinking water wells within one-quarter mile of the
PAB site.

The EPA site assessment investigation identified the presence of
contaminant plumes resulting from the migration of materials from
the pits on both the surface and subsurface.  Groundwater
monitoring wells indicate elevated levels of barium, chromium,
and nickel.   There exist only five feet of clay, of unknown
quality, between the bottom of the disposal pits and the top of the
major local groundwater aquifer.   Therefore, at the present time
there exists the potential for major contamination of the
groundwater aquifer.
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There also exists the potential in the  future for contamination of
the municipal water wells serving  the City of Abbeville.   The EPA
has determined that the PAB site directly affects 18,000 people and
2,100 people use the groundwater for irrigation.

Gulf Coast Vacuum Service

The Gulf Coast Vacuum Service site is a 12.78 acre site located
southwest of Abbeville.  The facility operated as a waste oil
handling facility and truck washout facility.  The site was
operated in conjunction with a waste injection well located
approximately two miles away.

Three open pits on the site were used to dispose  of oil-based mud,
drilling fluids, saltwater, and truck wash-out water.   The pit
contents and surface soils are contaminated with  significant
concentrations of arsenic, barium,  cadmium, chromium,  copper,  lead,
mercury, zinc, pentachlorophenol,  naphthalene, benzene,  and
toluene.  The pits contain liquids and  sludges.   The ground on the
site has been built up with the contaminated  pit  sludges.   The
large pit is overtopping the levee each time  it rains.   The
contaminants are flowing into an adjacent drainage and have
contaminated the pasture area adjacent  to the site.  Cattle still
graze in the contaminated pasture  even  though in  1988  the EPA
recommended the contaminated pasture be restricted and secured.

In addition to the surface contamination,  contaminants have
migrated out of the pit and into the groundwater  under the site.
The shallow aquifer under the site is used for drinking water and
irrigation of cattle, rice, and crawfish ponds.   The EPA has
determined that the Gulfco site directly affects  2,600 people.

D. L. Hud. Inc.

The D. L. Hud., Inc. site^ is a 12-acre  site that  was part of  the
original 25 acre Gulfco site.  In  1981,  12.78 acres of the original
site was sold to Dow Chemical.  The site operated under the names
of the Dow Chemical, Dowell Schlumberger,  Inc., and D.  L.  Hud,  Inc.
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The facility was a drilling mud mixing facility when owned by Do*
and D. L. Bud, Inc.  Tanks on the facility were filled with
drilling muds, saltwater, and drilling fluids,  faste sludges from
the Gulfco pits were deposited on the ground as fill material.  The
soil and subsurface soils and sediments on the site are
contaminated with significant concentrations of arsenic, barium,
chromium, lead, mercury, zinc, and organic solvents.  Organic and
inorganic contamination has been detected down to a depth of 35
feet.

The waste remaining in the 15 tanks which range in size from 210
barrels up to 3,000 barrels was removed and disposed of in the Dow
Hazardous faste Incinerator in Plaquemine, Louisiana.  The cleanup
of the contaminated sludges and soils and groundwater have not yet
been addressed.

The EPA has determined that the D. L. Hud site directly affects
2,600 people.

Status of Superfund Process

In August 1989, the EPA sent out notices to companies listed as
potentially responsible parties (PRPs) for each of the three sites.
The PAB site PRPs consisted of companies that disposed of oilfield
waste in the PAB pits.  The Gulfco and D.  L.  Hud sites'  PRPs
consist of companies that sent waste to the site as well as
companies who had material transported by the truck service which
disposed of the residual chemicals and truck wash water at
the facilities.

The PAB site PRPs consisted of 166 companies.  Minety-one percent
(91X) of the PRPs were Louisiana companies and 11 companies were
located in Vermilion Parish.   The D.  L. Hud PRPs were composed of
306 companies.  Fifty-six (56X) of the PRPs were Louisiana
companies and four companies were Vermilion Parish companies.  The
Gulfco site had 442 PRPs of which 69X were Louisiana companies and
nine were Vermilion Parish companies.

At the present time the EPA is planning to conduct remedial
investigations at each of the three sites.  These investigations
are designed to assess the extent of the contamination at each
site.   The next step will be the feasibility study which will
evaluate various remedial actions and clean-up methods.
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Future of laste Sites In Vermilion

The potential for additional Superfund  sites  in Vermilion Parish
are being investigated as a part  of  the three present Superfund
sites.  A number of sites with Known environmental problems
received the same waste as that received by the three Superfund
sites.  These six sites, which are known as Superfund daughter
sites, consist of the Pershing Broussard/Leleux Disposal  site,  the
Leo Fontenot pit, the Seventh fard dump, the  Tan Romero/Sixth lard
dump, the Har-Low/Oil Field Brine disposal  site,  and  the
John Nunez injection well.

In addition to the six daughter sites,  EPA  is currently
investigating three other sites for  inclusion on the  Superfund
list.  These sites are known as the  Forked  Island Ship Yard
location 1 and 11 and the Larry Landry  Intracoastal city  dump.

Oil and  gas drilling and production  waste was disposed of in seven
other commercial facilities in Vermilion Parish.   These seven sites
in addition to the ones previously listed,  all have environmental
impacts  as the result of the disposal of oilfield waste.   The case
study of unsuccessful oilfield waste disposal techniques  in
Vermilion Parish will continue to unfold for  many years in the
future.  A complete understanding of the extent of the problem is
presently hampered by a lack of financial resources.   This lack of
financial resources, likewise extends into  the area of site
remediation.  Thus, site remediation at all sites within  the parish
is a  dream which extends far into the future.
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THE USE OF HYDROCYCLONES  IN  THE  TREATMENT OF OIL CONTAMINATED WATER SYSTEMS
I.C. Smyth, M.T. Thew
University of Southampton  (UK)
Introduction

Water  contaminated with oil  is a  large  scale by-product  of the  production,
transportation  and  refining  of  crude  oil  as  well  as  a wide  range  of industrial
processes.   Increasing  public awareness of the  impact of oil  pollution,
together  with tightening  legal restrictions on  environmental  discharges  (1)
and a  growing interest  in  recovering  the  oil product from the waste water  and
process  equipment  miniaturisation,  have  stimulated  the  development  of
innovative  water/oil separator technologies where  conventional  systems have
proved inadequate.    One such development has been  the emergence of effective
liquid-liquid hydrocyclone separators,  in particular for  the  treatment of oily
water, after  extensive  research at  the  University of Southampton  in the  1970's
and early 1980's (2,3,4,5).

The hydrocyclone is an  enhanced gravity separator which generates acceleration
fields between  several  hundred and  several thousand "g" by  directing a
pressurised  feed flow tangentially  into a generally  conical vessel  to create a
confined  vortex.     Any dispersed  component within the flow  will segregate
radially within the vortex by  virtue  of  its  density  difference from the
continuous component.   Heavier material  moves to the wall where  it  is carried
away  from the  inlet to emerge at the apex of  the unit  whilst the  lighter
material  migrates to the centre and is  usually carried away from  the apex by a
reverse flow and out of a  central aperture adjacent  to the  inlet.

Conventionally  hydrocyclones have been  used largely in mineral processing  for
the separation  of solid fractions from  a  water phase.   The classical geometry
is a simple  tangential  feed  pipe leading  into  a short cylindrical section on
top of a steeply  tapered  cone, with  inlet  and outlet  aperture  sizes
controlling  the operation.

Figure 1  shows  a schematic of a commercial  (water)  deoiling  geometry based on
the University  research, illustrating how dealing with light oil drops rather
than  dense solids  affects the  design  concept.    Firstly, oil drops  will  be
moving to the  centre  of  the hydrocyclone  to be separated,  rather than  the
wall,  and this  means flow  near  the  core must be  kept free of instabilities or
excessive turbulence which  might allow  re-mixing.     In addition, the much
lower  density  differences for  oil/water  systems implies the need  for longer
settling  times  or stronger swirl  to obtain adequate  radial migration of drops,
although  use of high inlet velocities must be balanced against the dangers of
droplet  disruption  in  the associated  high  shear fields.    Accordingly,  key
features  of  the design  are:
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-  an enlarged feed injection section, which allows  a  high degree of spin to
be achieved  by  gradual  acceleration through the  reducing section rather than
directly driven by a high velocity inlet  stream

-  a large  overall length:diameter ratio,  to provide adequate  residence times

-  an involute type feed  duct and  taper  section  of only 1-2°  included angle,
to promote  flow  symmetry and  in particular a fine stable core  of reversed
flow.

It should also be noted  that discharged  flow control is achieved by external
valves,  the bulk  of flow emerging as "clean" water from  the clear outlet,  the
rejected  flow being  set sufficient  to  ensure  removal of the oil  core  and
emerging as a mixture  of oil  and  water.

The principal advantages of hydrocyclones for deoiling  are  the  compactness and
simplicity of the hardware.    These and  other  features,  including operational
characteristics,  will  be illustrated  with  reference to the  most  widely
exploited application of the  technology  to  date  - crude oil production.   New
areas of  potential linked with  the  oil industry  will be investigated,  in
particular as  part  of an oil  spill treatment  system.  Applications  in other
industries will also be  considered.

Oilfield Produced Water  Applications

There is  almost  always  a water  phase associated with  crude  oil production,
which may vary from a  few percent at an early  stage in an oil  field's life to
80 or 90% as it  nears  exhaustion,  and economics currently dictate  that  the
water is removed from the oil and treated at or close to the production site.
In  the  offshore environment  in  particular  this means that  there is  a
significant premium on flexible  and compact  water treatment  facilities.

The  principal  commercial  design  of hydrocyclone  deoiler  is the  Vortoil'   ',
manufactured  by  Conoco  Specialty Products.    This  comprises a  liner which
effects  the  functional  geometry  of  the separator, as shown in Fig.  1,  and  a
containment vessel which supports the liner and  facilitates connection to the
process  and operation  under pressure.   As  scaling criteria  dictate that large
flows are  best  treated  by using  hydrocyclone  units in  parallel,  designs  in
which a number of liners  are incorporated  into a common pressure vessel have
been  developed,  producing  considerable  savings  in  pipework  and  valving
requirements.   The "Multi" system,  which can take up to  37  hydrocyclone tubes
in one vessel, is illustrated in  Fig.  2.  Options to  use  35mm  or 60mm diameter
tubes (measured  at the widest point of the taper  section)  depend  on  the
particular application.   At a given pressure drop, whilst a 60mm unit has 2-3
times the capacity of  a 35mm  hydrocyclone (6),  its efficiency  may be slightly
lower as  the  internal centrifugal force field is  weaker.   This  may be
recoverable if higher  driving pressures are  available.

The  operational  weight  savings which  can be  achieved  over conventional
separation systems, like  TPI (tilted  plate  interceptor) and IGF (induced gas
floatation) units, are  typically  up to 90%.   A  25,000  bpd (barrels per day)
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Vortoil system,  for example, has  a flooded weight  of  only about  6.5  tonnes.
Space requirements are  also  low  and the combination of  the modular
construction  of  hydrocyclone systems  and their  insensitivity to  orientation
means  additional units  can  be  easily  added  as  water production  increases.
This insensitivity  also  extends to motion, making them well suited to  use  on
floating  structures.   Maintenance needs are  minimal as  there  are no  moving
parts, no build  up  of residues  and the  internals  are constructed  from  erosion
and corrosion resistant  materials.

Operation and Performance

Further features of deoiler hydrocyclones are  exemplified  by considering their
operational  and  performance characteristics.   Figure  3   shows  a  simplified
diagram  of  an oilfield production  separator system incorporating
hydrocyclones, where  the required  pressures are  supplied by the process.   The
produced  water stream coming from  the  first stage  separator (3-phase knock out
vessel) is  regulated  by  level control within  the  first separator using  valves
beyond the  hydrocyclone  unit.   This  eliminates  any possible problems due  to
droplet  breakup  through upstream  control valves, a  difficulty  competing low
pressure  separators cannot  avoid.    The balance between the discharged  flows
from the  hydrocyclone is maintained by keeping the pressure  drops  between the
inlet to  reject  and inlet to clean outlet in  a constant ratio (7).   Figure 4
shows a typical  relationship between  flowrate  through a 14 liner 35mm Vortoil
and the  larger  of these pressure drops (by a factor of 7:4), that  to the
reject.    The  1.5%  reject  ratio refers  to  the fraction of the  feed flow
emerging  from the  reject.    So  long as  this flow  remains  above  a critical
minimum   below  which  the   stable  reversing  core  breaks   down,  separation   is
independent of  reject ratio providing  it also exceeds the  amount of oil  to  be
separated (5,8).   With  oil levels in  produced water  typically in the range  of
a  few hundred  to  a  thousand  ppra,  the  usual  1-2% reject  ratio used can
accommodate fluctuations above these  concentrations  without  adjustment.     If
higher reject flows  are required,  these can be  obtained  by  increasing the
driving  pressure  drop,  or   for  more  permanent  adjustment by using a  larger
diameter  reject  orifice.

A  flowrate against oil removal efficiency curve  for  the  same system is  given
in Fig.  5 under  field conditions.    As throughflow increases, separation  rises
to reach a plateau  condition  which  is  sustained  over  a considerable flow
range.    The fall in performance at  high flowrates was  ascribed  to process
pressure limitations being inadequate to   drive  the reject  flow in this
instance, but ultimately  separation may  also be restricted  by  an increased
tendency  for droplet break up to  occur.    Operating ranges  for single  liners
will  be  of  the order  of  50-165  1/min  (455-1500 bpd)  for 35mm units  and 130-435
1/min (1200-4000 bpd) for  60mm  units,  at inlet to reject  pressure  drops  of  1-
 15 bar.   Minimum values  of  4 and  6 bar respectively  are usually recommended  to
allow some operational  flexibility, maximum  values  around 30 bar  represent a
drop  stability limit.

Clean stream discharges with <40  ppm oil (i.e. within the current IJTC  and  NW
European  offshore  limit)   are  consistently  achieved  by  hydrocyclones,  best
performance  being  obtained when  the  process  liquids  are hot,  the crude   is
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light and the produced water very saline (i.e. density difference is high) and
the dispersion coarse.   As a general guide, particle removal efficiencies for
5-10 urn drops  are around  50%,  so  dispersions around  this  size will  be
difficult to treat.    Enhancement  options might  include the  use of chemicals
to aid pre-feed coalescence, and typically, hydrocyclones are found to require
much lower  dosage  rates   to obtain  adequate separation than  do conventional
separators.  If plenty of pressure is available, an alternative may be passing
the flow through  other hydrocyclones connected in  series.   Automated control
of such systems has been demonstrated (9), which  included  diversion of slugs
into a holding tank.

Although deoiling  hydrocylones  cannot unaided deal with slugs  of  oil because
of their  low residence  time (2 seconds or  less),  this  is balanced  by  their
ability to  achieve full efficiency  immediately,  either on  start  up or  when
recovering from upstream upsets.

Contaminant  phases,  gas and solids,  do  not  appear  to  adversely  affect  the
oil/water  separation  process so  long as  their  concentrations are  not  high.
Laboratory tests with free gas  contents of up to at least 20% by volume  in the
feed have  shown a restricting  effect on the  liquid flow at the reject  where
the gas emerges (10).    The general lack of such problems in the field implies
that the main  production knock out  vessel efficiently  removes free  gas  from
the produced  water stream and  that  gas evolution  due  to  the  pressure  drops
across  the hydrocyclone  is not substantial within the separator itself.
Indeed, the phenomenon  of  dissolved  gas  coming  out   of  solution after  the
pressure let down through the hydrocyclone has been significant enough in some
cases  to  make it  worthwhile putting a small  tank beyond the clean stream
outlet to obtain a secondary oil separation effect of the gas floatation type.
Heavy solids, even when  oil wetted, tend to  be  scrubbed  clean  by the cyclonic
action and  emerge  with the  bulk of  the water phase.  Deoiler  geometries  with
an additional solids take-off facility to provide 3-phase separation have been
suggested  (11), but  experience shows  the  oil/water separation effect may  be
compromised by such modifications (12).

Recent and Future Developments

Taken  together  then,  the combination  of  features  which the  deoiling
hydrocyclone offers - compactness,  flexibility  (with regard  to flowrate  and
orientation), efficiency and minimal operator  attention  - makes it  an  ideal
separator for offshore produced water treatment.   This is  particularly  so  in
the expanding  subject  of  marginal  field  exploitation  where large  fixed
platforms  are  inappropriate because  of  small  reservoir  size or  great  water
depth.   Floating, sub-sea and  small unmanned satellite production  systems are
the kind of  options  being developed  and  these  provide further  potential  for
hydrocyclones. Their insensitivity to motion  has  already  proved a  significant
advantage  for  water treatment  on  Tension  Leg  Platforms  like Mutton in  the
North Sea  (8)  and  their ability to  withstand  high  pressures (a  "900  ANSI"
rated unit  is currently  available)  meets  the anticipated  need for separators
which can  cope with  wellhead   shut-in  pressures  in  the  sub-sea  environment
(15).    Interest for onshore production applications  is  also  building,  with a
number of units already in operation.
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In installations where  there is insufficient feed  pressure a pumped system is
required.    The potential  for the break up  of oil droplets to unrecoverable
sizes  in conventional  centrifugal pumps  means low  shear  progressive cavity
type pumps are  favoured (13,  14).    However,  if process drop sizes are already
small  or separation requirements undemanding,  the  reliability  and low cost of
centrifugal pumps may be more important.

The  potential  to  provide  effective treatment of heavy  oils has also  been
demonstrated  for  steam  flood production conditions,  although the  problems  of
superheated produced water  flashing to steam within the hydrocyclone had to be
overcome  by  raising back pressures (15).

New  developments  of the  oily water hydrocyclone itself are being essentially
directed at providing lower pressure  drop  and higher  efficiency operation (7).
The  main objective  of the low pressure concept  is  to  allow adequate separation
to be achieved in  conjunction  with  a single  stage  centrifugal  pump.    The
intention  of the  high  efficiency design  is  to  increase  the  hydrocyclone's
capability  to  deal with difficult separations, especially to  reduce  further
the  need for  chemicals.

Application  to  much higher  oil  c'ontents  has also  been  pursued.     A  modified
Vortoil unit is being field  tested in  California  as a  primary separator
dealing with water cuts of 60% or  more.   The function  of  the unit is to
extend the  productive  life  of the field by  both  concentrating the oil  phase
and  cleaning the  water  phase  such  that  existing .over-stretched  production
equipment  can meet the  appropriate discharge  specifications.    This  type of
"pre-separator" concept  could  have  considerable  use  in aging oil  producing
areas, as production separator design capabilities for water are exceeded.

This  expansion of  the  deoiling   hydrocyclone's   range  imparts  considerable
stimulus to  applications outside the  sphere of  oil production.

Oil-Spill Applications

The amount  of oil  released  into the  marine environment  in  connection  with  its
transportation  is  at  least  an  order of magnitude  greater than due to  its
production  (1).  A  significant fraction of this release is as crude oil spills
at sea.   These can  quickly develop into  stable  and  very  thick  sea  water in
crude emulsions due to  wave action and are commonly referred to as "chocolate
mousse".   Chemical dispersants become progressively less  effective  as  slick
viscosities  increase and collection methods are then adopted (17).    However,
chocolate  mousse  can  be 70%  water (18)  or more and additional large and
variable amounts of free water tend to be  removed  with  it in  the  recovery
process.   This means  a considerable volume of  the recovery vessel is devoted
to carrying  sea water and the difficult problem of shore based  disposal of  the
mousse would  still  need to  be addressed.    A treatment  concept  is put forward
in which the material  collected is first  mixed with  demulsifier  to break  the
mousse and  the  resulting oil/water mixture  fed to a bank  of hydrocyclones to
achieve a  separation,  concentrating  the  oil  phase  for  possible re-use  and
allowing the  water  to  be immediately  discharged back  to the sea (Fig.  6).
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This 2-stage process has been  investigated  by  laboratory  separation  tests of
hydrocyclones with a simulated  weathered  crude/water/demulsifier  mixture, at
the  University  of Southampton,  complemented  by  pilot  scale  tests  working
directly with batches of  artificial mousse,  at .the BP Research Centre, Sunbury
(UK).   Tests  were based around  a 38mm hydrocylone  separating  a  10% oil in
fresh water system with  mean  drop sizes around 100 u m and demulsifier levels
averaging 670 ppm (19).    Results from the laboratory programme, Fig. 7,  show
the  importance of the  reject  or split ratio in determining  the  required
operating condition which  maximises  the  product quality  of both  discharge
streams.  It can be seen  that   70% of  the  oil can be  concentrated  in  a stream
which  is  only 15% of the  feed flowrate,  leaving a water  stream with 0.4%
residual oil.

The acceptability of discharging  even this  small  amount  of oil at the  spill
site will clearly be  an  issue.    However,  an  additional  hydrocyclone  stage
bringing oil contamination  down to a few hundred ppm might be a viable option,
particularly as low presure drops were  a  consideration in the design of the
hydrocyclone tested,  inlet  to  oil stream  being ~3.5  bar  and  inlet  to water
stream being ~2  bar  for a working  flowrate  of 100  1/min in the  optimum
geometry.   This  throughput also  appeared  to be an  upper  limit  in  terms of
efficiency as well, the high  demulsifier  levels  resulting  in  a  very low
oil/water interfacial  tension (0.0015 N/m)  and consequent  poor  droplet
stability characteristics.

Commercial interest has been  shown  in an  oil-spill clean up vessel with
processing rates as  high as 33,000 1/min.   This could  be treated  in  a single
pass hydrocyclone array  with an estimated operating weight  of 120-150 tonnes.
Air portability may  also be a  consideration  for  such  systems and  dry weights
are only  fractionally lower that  operating  weights,  as separator  inventories
are small.

Other Applications

The  following listing  represents  an overview of  the range  of  oily water
separation  problems  which  have  been identified  as  offering  potential for
hydrocyclones based  on investigations carried  out by  Conoco, often  including
trials with a mobile  test unit.    Like the oil-spill application, however, the
hydrocyclone may require  additional  equipment to  achieve an  acceptable
solution.

Marine applications  include bilge water and  ballast water  clean up on ships,
although  secondary polishing may   also be  required  before discharge at sea
(11) -  the  IMO  limit  on bilge  water  discharge in coastal waters is  only 15
ppm.   Use in association with the treatment plants which take  oil slops from
tankers is also envisaged and  interest from similar oily waste   disposal
centres has been expressed.

Another applicable oil industry related  separation need is the decontamination
of wash water -  from the washing of  mud cuttings  during  drilling operations
and from its process  use  in refineries and  tank farms.    The surface drainage
treatment  systems  to  these  areas is  another likely  place to employ
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hydrocyclones.    Indeed,  a unit  has already been  sold for  deoiling ground
water1 below an old tank farm site which is being redeveloped.

The  mining industry  has  requirements  for  large scale  processing  of  water
wastes, often contaminated  with  organic  solvents.   In  the  future,  there may
also be applications   based on the exploitation  of  oil  shale beds,  currently
an uneconomic source of oil.

In petrochemicals,  the  typical  requirement  appears to  be  a  recycling
operational mode.   This is illustrated in Fig. 8 for a project in an ethylene
plant where the Vortoil installation  is designed  to  reduce levels of  wax   and
oil  in a caustic  solution,  allowing  it  to  be  effectively  re-used  for
decontamination  of process gas  streams.    A  similar type  of separation
function  is needed for quench water treatment in the same plant.

In steel   manufacture  and working,  process  water  becomes  contaminated  with
quench  oils.    Both oil  recovery and  clean water  discharge are objectives for
separation equipment.

Dense  liquid separation  in hydrocyclones is also  gaining  momentum,  with  an
onshore 115,000 bpd gas  condensate dewatering  facility  fed by pipeline having
been recently commissioned  (Bass Strait, Australia).

Conclusions

Since the first commercial unit was  delivered  in 1984, the  light  dispersion
hydrocyclone  has  rapidly established itself  in  the  area of  compact  oilfield
produced  water treatment equipment,  with  nearly 4,000,000 bpd  capacity
installed or on order world-wide.    It  has  already become  the  first choice
technique for  new  offshore installations  and is gaining a foothold for land-
based production as well.   Recent product developments are not only expanding
the possible range  of applications within the oil industry,   but  also  helping
to open  up  new areas of  use  - wherever  a need  exists  to  process large
quantities of oily water.  Work  is going on to improve gas handling  and ultra-
fine drop separation  and  to combine  deoiling  hydrocyclones with  dewatering
units to  give integrated, compact plant.


References

1.     H.D.  Parker,  G.D.  Pitt, Pollution Control Instrumentation for Oil  and
       and Effluents,  Pub.  Graham and Trotman, London,  1987.

2.     G.R.  Kimber,   M.T.  Thew,  Experiments on Oil/Water  Separation with
       Hydrocylones,  Proc. 1st European Conf. on Mixing  and  Centrifugal
       Separation, Cambridge (UK),  9-11 Sept.  1974,  El-1  to El-27, BHRA,
       Cranfield (UK), 1974.

3.     D.A.  Colman,  M.T. Thew,   D.R.  Corney, Hydrocyclones  for  Oil/Water
       Separation,  Proc.  1st International  Conf. on Hydrocyclones,  Cambridge
       (UK),  Oct.  1980,  143-166, BHRA, Cranfield (UK),  1980.
                                    1007

-------
4.      I.C.  Smyth, M.T.  Thew,  P.S.  Debenhara,  D.A.  Colraan,  Small  Scale
       Experiments on Hydrocyclones for Dewatering Light Oils, Proc.  1st
       International Conf.  on Hydrocyclones, Cambridge  (UK),  Oct.  1980,189^
       208,   BHRA,  Cranfield  (UK),  1980.

5.       M.T.  Thew,  Hydrocyclone  Redesign  for  Liquid-Liquid  Separation,  The
       Chemical Engineer, July/August  1986,  17-23.

6.     Conoco  Specialty Products,  Vortoil Technical Literature, 1990

7.      F.  Skilbeck, Applications of Hydrocyclones in the  Oil Industry,  Two-
       Phase Separation with Cyclones  Course,  University  of  Bradford  (UK),
       April 1990,  Inst. of Chemical Engineers.

8.      N.  Meldrun,  Hydrocyclones:   A Solution  to Produced  Water  Treatment,
       19th Annual  Offshore  Technology  Conf.,   Houston, Texas,  1987.  Paper
       OTC 5594.

9.     P.G.  Marsden, D.A. Colman,  M.T. Thew, Microcomputer Control of  a System
       of Hydrocyclones,  1st  Conf.  on  the Use of Micros  in  Fluid Engineering.
       London,  June 1983, Paper  Cl, BHRA, Cranfield (UK), 1983.

10.    K. Nezhati,  M.T. Thew, Further Development  of  Deoiling Hydrocyclones,
       Dept.  Mechanical  Eng.,  University of Southampton (UK),  1985,
       Unpublished  report.

11.    S. Bednarski, J. Listewnik, Hydrocyclones for  Simultaneous  Removal of
       Oil  and  Solid  Particles  from  Ships' Oily  Waters,  Proc.  3rd
       International Conf. on Hydrocyclones, Oxford (UK), Oct. 1987, Paper  G2.
       Elsevier,  Barking (UK), 1987.

12.    K. Nezhati,  M.T. Thew, Further  Developments of Deoiling Hydrocyclones
       for  Simultaneous Solids  Removal,  Dept. of Mechanical  Eng.,  University
       of Southampton,  1986,  Unpublished report.

13.    D.A.  Flanigan et al.,  Droplet Size  Analysis:   A New  Tool for Improving
       Oilfield Separations,  63rd  Annual Conf. Society of Petroleum Engineers,
       Houston,  Texas,  Oct. 1988,  Paper SPE 18204.

14.    D.A. Flanigan  et  al.,  Use of Low-Shear Pumps in  Conjunction with
       Hydrocyclones for Improved  Performance  in the  Clean  Up of Low-Pressure
       Produced Water,  64th Annual Conf. Society  of Petroleum Engineers,  San
       Antonio,  Texas,  Oct. 1989,  Paper SPE 19743.

15.     B.   Bowers,  Hydrocyclone Separator  used   in Steam Flood Applications,
       Canadian Heavy Oil Association Quarterly Meeting,  Oct.  25, 1988.

16.    Goodfellow  Associates,  Offshore Engineering Development of Small
       Oilfields, Pub-.  Graham and  Trotman, London, 1986.
                                    1008

-------
17.      International Tanker  Owners  Pollution  Federation  Ltd.,  Response  to
      Marine  Oil Spills. ITOPF,  London, 1987.


18.    A.L.  Bridie et al.,  Formation, Prevention and Breaking of Sea Water  in
      Crude Oil Emulsions  "Chocolate Mousses",  Marine  Pollution Bulletin,  11,
      1980, 343-348.                             —'	


19.    D.S. Robertson  et al,  Hydrocyclone  for the Treatment of  Oil-Spill
      Emulsions, 2nd International Conf.  on Hydrocyclones,  Bath  (UK),  Sept.
      1984, Paper F3,  BHRA,  Cranfield (UK), 1984.

                                                                       Clear Outlet
      Fig.  1      Schematic of  a  deoiling hydrocyclone




        Oily Water Inlet
Oil Droplets Migrate
lo Oil Core
                               Central Oil Core

                     Accelerating
                     Helical Flow Pattern
   Concentrated
   Oil Reject
                   INLCI
                             RC.ir.ri
                                          OUTLt '
                   DRAIN                              DRAIN


          Fig. 2      Internal arrangement of a  14  liner  "Multi" unit
                                       1009

-------
                                 Cos
                   ->^H    Seporalor
                      )>-




L
F

	


Voducod
Water
1

<^


Lv
r
I HH
© ©L
T a
^^^-^^
Vorloil
Hydrocyclone
               POYK- POC,
                          I
                     Oily Reject
                Fig.  3      Produced  water treatment schematic


CO
a.
0)
V)
(O
tx
^ro
cu
Q



Ł«*UU
2200 -
2000 -
1800
1600

1400 -
1200
1000
800 -

600
400 -
200
0 -4
Pn,«
	 '- — ^^^^ Inlet to Reject
P ' " °uti«t Reject Hate 1.5% /
Q = 14x(39.37iiP)"!'5
Standard Geometry




/'
,/
/
^/
_^"^
Fig. A
                                          ~\—r
0   200  400  600   800  1000  1200  1400 1600  1800  2000  2200 2400  2600  2800

                       Flowrate (l/min)


Relationship between  flowrate and differential pressure  for a 14
liner 35mm Vortoil  deoiler (lOOkPa = 1 bar,  100 l/min  =  909 bpd)
                                   1010

-------
                     100
                      80  -
                      60
                    LJ
                      40
                      20
                              5000    10000   15000   20000
                                        Flowrate (BWPD)
                                                          25000    30000
Fig. 5      Relationship  between  flowrate  and efficiency of  oil removal from
            the  clean stream for  a  14 liner  35mm Vortoil deoiler
            (1000 bwpd =  110 1/min)
                                MOUSSE' DEMULSIFICATION
                                 AND SEPARATION SYSTEM
                               	A,	
MATERIAL
COLLECTION
MOUSSE •
SEAWATER

EMULSION
TREATMENT
OIL-
SEAWATER

SEPARATION
                                                             OIL

                                                           TRANSPORT
                                                                            PRODUCT
                                                                             SALES
                                 DEMULSIFIEH
SEAWATER
DISCHARGE
                -*-FUEL OIL
             Fig.' 6      Oil-spill  treatment  concept
                                    1011

-------
                         I   \

            Fig. 7      Effect of  split ratio on effluent quality
                        (tests on  simulated  demulsified mousse)
                Couslic
                Tower
                         Uulli-Stoge
                         Centrifugal
                         Pump
                               Pressure
                               Rotio
                               Control
Pressure
 0«Po)
                                              Vortoil
                                                     Gear
                                                     Pump
                                                                 Reject
Fig.  8      Typical light  contaminant regulating installation  for a deoiling
            hydrocyclone - caustic  tower loop in an  ethylene plant
                                          1012

-------
USE OF MINTEQ FOR PREDICTING AQUEOUS  PHASE TRACE METAL CONCENTRATIONS IN
WASTE DRILLING FLUIDS
George M. Deeley
Research Chemist
Shell Development Company
Houston, TX, USA  77251-1380
 Introduction

 Drilling fluids are used by  oil  companies  when they drill wells to explore
 for oil and natural gas or to  develop  existing oil-fields.   The drilling
 fluids are circulated  in and out of  the  well-bore  during drilling to control
 pressure, remove cuttings, lubricate and cool  drill bits,  and seal the
 geological formation being drilled.  These activities  result in the
 generation of more than 200  million  barrels of waste drilling fluid/cuttings
 per year in the United States  (1).

 Freshwater drilling fluids consist of  naturally occurring clays (bentonite),
 weighting materials (barite),  water, and small amounts  of other additives
 (lignosulfonates, lignite, caustic soda, lime).  Measurable  levels of heavy
 metals may be present  in the formulated  fluid  or contributed by the drilled
 cuttings.  These elements may  be of  environmental concern and it is important
 to understand their movement and fate.

 The heavy metals are distributed between the solid  and  liquid phases of  the
 waste.  This distribution may  be evaluated through  total metals analysis,
 equilibrium modeling,  speciation analysis,  or  leaching  studies.   Sorption  to
 solids and the formation of  insoluble  precipitates  control aqueous phase
 metal concentrations in most waste freshwater  drilling  fluids.

 The purpose of this paper is to  examine  the availability of  heavy metals in
 waste freshwater drilling fluids based on  the  application of MINTEQ,  a
 chemical equilibrium model (2).   Knowing the identity of the solid phases,
 aqueous phase concentrations of  the  elements can be predicted from
 thermodynamic data.  Aqueous phase concentrations reflect the potential
 mobility of the element and  are  useful in  transport modeling.   The model
 predictions are compared with  analytical results obtained in past
 characterization studies.
                                   1013

-------
Background

Investigations into the fate and transport of constituents contained  in waste
freshwater drilling fluids have, to date, been limited to analyzing or
manipulating waste samples to simulate behavior in the field.  Little work
has been performed to evaluate the mechanisms responsible for  the observed
behavior.  However, while a strictly analytical approach does  not provide the
tools necessary for predicting or modifying behavior based on  chemical
properties, it does provide valuable information in regards  to the waste
samples tested and some general insight as to the expected behavior in
similar wastes.  A summary of previous freshwater drilling fluid work
involving total metals analysis, speciation studies, batch leaching studies,
and column leaching studies is provided as examples of this  approach.

A laboratory study was performed to examine the chemical forms of solid phase
arsenic, barium, chromium, and lead in drilling fluid wastes by sequential
extraction following equilibration at an adjusted pH or ionic  strength value
(3).  This provided insight as to the stability of the existing metal
species.

Three active drilling fluid disposal sites located in Oklahoma were sampled.
The pH or ionic strength of sub-samples were adjusted and the  mixtures allowed
to equilibrate.  A sequential extraction procedure was then used to separate
arsenic, barium, chromium, and lead into fractions defined as  aqueous (water
phase removal), exchangeable (KNO,-extractable),  adsorbed (H^O-extractable),
organically bound (NaOH-extractable),  carbonate (EDTA-extractable),  and
residual (HNO_-extractable) .

The majority of each of the elements studies was found in the  organically
bound, carbonate, or residual fractions except for one waste which contained
a major portion of the total barium in the exchangeable fraction.  Generally,
decreasing pH caused a shift from the more stable residual fraction toward
less stable carbonate, organically bound, or exchangeable fractions.  In no
case was there a substantial release to the aqueous phase with changing pH or
ionic strength.  The significance of these results is that, with pH or ionic
strength changes to be expected in the natural environment,  there is not
likely to be a major release of these elements from freshwater drilling fluid
waste facilities.  The lower pH values (<4) which might produce some impact
are unlikely to occur because the wastes themselves have a large neutralizing
capacity.

Barium was examined in 11 waste drilling fluid samples using a slightly
different extraction method (4).  This method partitioned the  barium into
water soluble, exchangeable,  carbonate, iron/manganese oxides, organic, and
residual fractions.  The residual fraction accounted for 87.4  to 97.6 percent
of the barium with only 0.1 to 1.7 percent in the soluble phase.

The Extraction Procedure Toxicity Test (EP Tox) (5) and Toxicity
Characteristic Leaching Procedure (TCLP) (6) are batch extraction tests
designed to determine the maximum leachate concentrations produced by a waste
under a given set of test conditions.   Both of these procedures evaluate
                                   1014

-------
amounts  of constituents available for leaching  in an acid medium (co-disposal
with municipal waste).

It may be  argued as to whether a co-disposal  scenario using acidic leaching
solution validly represents the disposal environment of all wastes,
especially alkaline waste drilling fluids.  Nevertheless,  the tests  are
required to meet regulatory guidelines, and are at least useful as worst case
indicators of waste behavior.

The EP  Tox Test has been performed on freshwater drilling fluid wastes (7,8).
Both studies  examined arsenic, barium, chromium,  and lead with resulting
concentrations less than the EP Toxicity limits for each constituent (Table
1).

TCLP analyses were performed and compared with  proposed limits  for both the
liquid and solid phases of freshwater drilling  fluid wastes (9,10).   In no
sample were the limits exceeded for any organic or inorganic constituent in
the waste, including arsenic, barium, cadmium,  chromium lead mercury,
selenium and silver.  Representative TCLP results  are shown in  Table 2.

It is apparent that when the EP Tox or TCLP extraction tests have  been
applied to waste drilling fluids, the resulting concentrations  of
constituents of interest were less than the suggested limits.   Relative  to
drilling fluid disposal, metals appear to be  stable under  what  might be
considered worst case analyses.  Although not representative, these
extraction tests may provide a basis for comparison with other  wastes.

Column  leach tests  involve placing the waste  sample in a column, where it
continuously contacts with a leaching solution  at  a flow rate either
controlled by pumping or the permeability of  the waste.   Column tests  may  be
considered to be more representative of field leaching conditions  than batch
extraction tests because of the continuous flux of the leaching solution
 through the waste.  These tests are not often used,  however,  because of  high
cost and operational problems.

Drilling fluid wastes were subjected to column  leachability tests  to
 investigate the hydraulic conductivity (permeability)  of waste  drilling
fluids, determine concentrations of chemical  constituents  in the column
filtrate, and compare effluent constituent concentrations  with  initial total
waste drilling fluid constituent concentrations as a measure of attenuation
with waste drilling fluid (11). Concentrations  of  metals found  in  the  column
effluents were low  relative to the total amount in the waste or associated
soils  (Table 3).

Actual  monitoring at waste drilling fluid disposal storage or handling
facilities would, or course, be the best method of determining  the amount  of
metals  migrating from these wastes.  A few studies on disposal  in  pits have
been performed and  are summarized.
                                  1015

-------
A study by Murphy and Kehew (12) examined salt-based drilling  fluid  disposal
pits ranging in age from 2 to 23 years.  Pore water in both  the  saturated and
unsaturated zones were analyzed.  While chlorides were found to  leach  from
the pit,  concentrations of metals were found to reach background  levels
within less than 100 feet of the pits.  The restriction of constituents
within the local area of these disposal pits was attributed  to attenuation,
mixing, and dispersion processes within the soils.

Henderson (13) studied eight sites throughout the United States  and  found
that heavy metals, sodium and chloride tend to be elevated,  relative to
background, in subsurface soil locations in or near pits or  impoundments.
However, constituents did not appear to migrate any appreciable  distance away
from these facilities, as evidenced by ground water data.  Most  high
concentrations in subsurface soils collected in pit areas occurred in
distinct layers with visible evidence of contamination.  The only parameters
showing definite evidence of vertical migration through subsurface soils were
sodium and chloride.

From this combination of chemical analysis,  speciation studies, leaching
experiments, and field monitoring, the behavior of various inorganic
constituents with waste freshwater drilling fluids may be elucidated.
Arsenic, barium, cadmium, chromium, copper, mercury, nickel,  and lead appear
to strongly attenuated and/or present at insignificant total concentrations
under the pH conditions (>7) which predominate this type of waste.   Strontium
was found predominantly in the aqueous phase although total concentrations
were also near background.

From these studies, it is clear that metals within a drilling fluid waste may
be acted upon by attenuating mechanisms which greatly decrease their
environmental impact.  In evaluating proper handling and disposal routes for
freshwater drilling fluid wastes, we should not focus only on a  total
chemical characterization of the waste without addressing the actual fate of
these constituents within the surrounding pit environment.

Measuring and regulating the chemical constituents in drilling fluid wastes
in terms of total concentrations implies that each identified constituent
will have an acute impact on the environment based on this total
concentration but not on its availability.   As a conservative approach to
initially assessing environmental impact or as a means of designing
conservative treatment schemes based on dilution of the total constituents to
acceptable levels, total concentrations are useful.  However, one should be
aware that many waste fluid constituents may be present in forms that make
them unavailable chemically and biologically.   The net effect of these
attenuating mechanisms can be assessed by incorporating them within
mathematical models which describe the bulk flow, dispersion, and chemical
attenuation of these compounds within the soil/ground water matrix at a given
site.
                                 1016

-------
Equilibrium Modeling -  MINTED

Several trace  elements, such as As, Ba, Cd, Cr, Cu, Hg,  Ni,  Pb,  and Sr,  may
be  contributed to  waste freshwater drilling fluids  from  drilling fluid
components, make-up water,  or drill cuttings.

Using estimates of waste composition, trace element estimates  for each
component  (Table 4),  and known or assumed solid phases (Table  5),  the trace
element distribution between the aqueous and solid  phases were calculated
(Table 6) .  A  chemical equilibrium model (MINTEQ) was used  to  predict the
distribution.   MINTEQ is a thermodynamic equilibrium model  that  computes
aqueous speciation, adsorption, and precipitation/dissolution  of solid phases
(2).  The  model has a large, well-documented data base that  contains
equilibrium constants and accessory data for more than 35 metals  and  60
ligands.   MINTEQ was developed to provide a predictive tool  capable of
performing screening-level analyses, but may be used to  investigate potential
impacts  of different metal sources.  MINTEQ is supplied  by and obtains strong
support  from the U.S.E.P.A. (2).

A waste  drilling fluid contains an element of interest in proportion  to  its
contribution to the total waste volume.  Freeman and Wakim  (1) reported  that
the average drilling pit in the United States in 1985 stored approximately
827,000  liters of waste fluids.  Liquids and solids made up  about  90  percent
(744,300  liters) and 10 percent (82,700 liters) of  this  volume, respectively.
Based on a 1,700 meter deep well with a diameter of 20.3 centimeters,  about
5.9 percent (48,800 liters) of the solids would be comprised of cuttings  with
the remaining 4.2  percent (35,700 liters) being the drilling fluid solids.
The drilling fluid solids can be further divided according to  average
component usage for a clay-lignosulfonate fluid of barite-69%, clay-26%,
chrome lignosulfonate-2%, lignite-1.5%, and caustic soda-1.5%.  The result is
a  component summary for an average drilling fluid waste  with components
reported in mg/kg dry weight after adjustment for solid  densities  (Table  5).

Solid phases for equilibrium modeling were based on known or assumed  species.
Barium is added to drilling fluids as the barium sulfate.  Chromium is added
as chrome lignosulfonate in its trivalent form and would be  expected  to
precipitate as chromium hydroxide at the average pH of waste drilling fluids.
Montmorillonite (bentonite) elements (Si.Fe.Al)  are assumed to be present as
relatively inert oxides since bentonite is not in the MINTEQ data base and
would not be expected to dissolve.  All of the starting  solid  phases  and  dry
weight concentrations are listed in Table 5.

This information was provided as input to MINTEQ at a pH of  8.3 and redox
potential (Eh) of 0 volts.   The resulting aqueous solid  phase  distribution is
shown in Table 6 along with results of analyses from field collected  waste
drilling fluids (9).  Of the metals examined, only Ni was indicated as
existing predominately   in the aqueous phase while As,  Ba,  Cd, Cr, Cu, Hg,
Pb, and Sr were predicted as mineral phases.  Results were consistent  with
chemically analyzed aqueous and solid phases from waste  drilling  fluids,  with
the exception of Ni being insoluble while a significant  portion of the
available Sr was soluble.
                                  1017

-------
Conclusions

Using reasonable geochemical assumptions, MINTEQ is an effective screening
tool for predicting the behavior of inorganic constituents within waste
freshwater drilling fluids.  Agreement between modeling results and average
measured constituent concentrations is reasonable.  This suggests that the
mechanisms represented within MINTEQ are geochemically sound when applied to
these wastes.  Therefore, examination of these potential soluble and solid
components provides insight into the chemical behavior of these complex
wastes.  This information will be valuable in evaluating past and current
waste disposal practices.  Modeling these systems may also be useful in
designing drilling fluids to minimize constituent mobility.
                                  1018

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References

1.   B.D. Freeman and P.G.  Wakim,  API results on 1985 onshore waste volumes
    and disposal practices within the petroleum extraction industry, in
    Drilling Wastes.  Elsevier Applied Science, New York, 1989, 343-357.

2.   U.S. Environmental Protection Agency, MINTEQAl,  An Equilibrium Metal
    Speciation Model:  User's Manual, EPA-600/3-87/012,  October, 1987-

3.   G.M. Deeley and L.W.  Canter,  Distribution of heavy metals in waste
    drilling  fluids under conditions of changing pH, Journal of
    Environmental Quality. Vol.  15,  No.2, 1986, 108-112.

4.   W.  Crawley, J.F.  Artiola, and J.A. Rehage, Barium containing oilfield
     drilling  wastes:  effects on land disposal, in Proceedings of a National
     Conference on Drilling Muds,  Environmental and Ground Water Institute,
    University of Oklahoma, Norman,  1987, 235-259.

5.   U.S.  Environmental Protection Agency, A procedure for estimating
     monofilled solid waste leachate composition, Technical Resource Document
     SW-924, 2nd edition,  Office of Solid Waste and Emergency Response,
     Washington, D.C., 1986.

6.   Federal Register, Vol. 51, No. 216, November 7,  1986, 40643.

7.   G.M.  Deeley, Chemical Speciation and Flyash Stabilization of Arsenic,
     Barium, Chromium, and Lead in Drilling Fluid Wastes, Ph.D. Dissertation,
     University of Oklahoma, Norman,  1984.

8.   L.W.  Canter, R.C. Knox, D.M.  Fairchild, G.M. Deeley, S.G. McLin,  G.D.
     Miller, J.G. Laguros, and M.  Zaman, Environmental Study of Merkle Pits
     near McCloud, Oklahoma, Environmental and Ground Water Institute,
     University of Oklahoma, Norman,  Oklahoma, April, 1984.

9.   American Petroleum Institute, Oil and Gas Industry Exploration and
     Production Wastes, Document No.  471-01-09, prepared by ERT, Houston,
     July,  1987.

10.  U.S.  Environmental Protection Agency, Exploration,  Development, and
     Production of Crude Oil and Natural Gas, Field Sampling and Analysis
     Results,  Publication 530-SW-87-005, Office of Solid Waste and Emergency
     Response,  Washington, D.C.,  1987.

11.  G.M.  Deeley, Physical/chemical fate of organic and inorganic
     constituents within waste freshwater drilling fluids, in Drilling
     Wastes, Elsevier Applied Science, New York, 1989, 297-315.
                                1019

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12.   E.G.  Murphy and A.E.  Kehew, The Effect of .Oil and Gas Well Drilling
     Fluids on Shallow Groundwater in Western North Dakota, Report of
     Investigation No. 82, North Dakota Geological Survey, Fargo, North
     Dakota,  1984.

13.   G.  Henderson, Analysis of Hydraulic and Environmental Effects of
     Drilling Mud Pits and Produced Water Impoundments, Vol. 1., Executive
     summary and report,  Dames and Moore, Houston, Texas, October, 1982.

14.   I.  Bodek, W.J. Lyman, W.F. Reehl,  and D.H. Rosenblatt, Environmental
     Inorganic Chemistry   Properties,  Processes, and Estimation Methods,
     Pergamon Press, New York, 1988.

15.   J.D.  Hem, Study and Interpretation of the Chemical Characteristics of
     Natural Water, 3rd Edition, U.S. Geological Survey Water-Supply Paper
     2254, USGS, Alexandria,  VA, 1985.

16.   J.R.  Kramer, H.D. Grundy, and L.G. Hammer, Occurrence and solubility of
     trace metals in barite for ocean drilling operations, Proceedings of a
     Symposium - Research on Environmental Fate and Effects of Drilling
     Fluids and Cuttings,  American Petroleum Institute, U.S.  Environmental
     Protection Agency, and Canadian Petroleum Association, Lake Buena Vista,
     Florida, 21-24 January 1980.

17.   T.W.  Duke, Drilling Mud Assessment - Chemical Analysis Reference Volume,
     EPA-600/3-84-048, U.S. EnvironmentaJ. Protection Agency,  Gulf Breeze,
     Florida, March, 1984.

18.   C.  Perricone, Major drilling fluid additives - 1979, Proceedings of a
     Symposium - Research on Environmental Fate and Effects of Drilling
     Fluids and Cuttings,  American Petroleum Institute, U.S.  Environmental
     Protection Agency, and Canadian Petroleum Association, Lake Buena Vista,
     Florida, 21-24 January 1980.

19.   V.  Valkovic, Trace Elements in Coal, CRC Press,  Inc., Boca Raton,
     Florida, 1983.

20.   S.  Mitra, Mercury in the Ecosystem - Its Dispersion and Pollution Today,
     Trans Tech Publications  Ltd.,  Switzerland, 1986.
                                1020

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                                TABLE 1
Study
                    Average EP Toxicity results for
                   freshwater drilling fluid wastes
  Number of
  of Samples
Deeley  (7)         3
Canter  et  al  (8)   5
EP Toxicity  Limit -
   Arsenic
   (mg/L)

   0.0118
   0.043
   5.0
      Barium
      (mg/L)

       1.22
      15.3
       100
        Chromium
         (mg/L)

          0.62
          0.21
          5.0
           Lead
           (mg/L)

            0.31
            1.77
            5.0
                                TABLE 2

                  Average TCLP results for freshwater
                     drilling fluid waste solids
Study

 API (9)
 EPA (10)
TCLP Limit
Number of
of Samples

   19
   21
Arsenic
(mg/L)

0.0002
0.008
5.0
Barium
(mg/L)

 1.45
 1.37
 100
Chromium  Lead
(mg/L)    (mg/L)
 0.21
 0.11
 5.0
0.12
0.20
5.0
Mercury
(mg/L)

0.0002
0.0007
0.2
                                TABLE 3

         Average percentage attenuation of inorganic compounds
                  within waste drilling fluid column,s
          Component

          Arsenic
          Barium
          Beryl 1i urn
          Chromium
          Cobalt
          Copper
          Lead
          Molybdenum
          Nickel
          Potassium
          Sodium
          Strontium
          Vanadium
                                                            Average
                                                          Attenuation
                                                97.1
                                                99.8
                                                99.0
                                                95.0
                                                99.8
                                                95.5
                                                99.8
                                                85.
                                                96.
                                                95.
                                                49.
                                                95.8
                                                74.3
                                     .3
                                     .5
                                     .3
                                     .7
                                  1021

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                                TABLE 4

         Average concentrations of elements in drilling fluid
                1          ?       3       4  Chrome  r        g
Element    Water  Cuttings  Barite    Clay  Lignosul.  Lignite  Caustic

Si(mg/kg)      7    206000   70200  271000      2390
Fe(mg/kg)    0.5     21900   12950   37500      7220
Al(mg/kg)    0.3     40400   40400   88600      6700
Mg(mg/kg)      4     23300    3900   69800      5040
Ca(mg/kg)     15    240000    7900    4700     16100
 K(mg/kg)    2.2     13500     660    2400      3000
Na(mg/kg)      6      3040    3040   11000     71000
Ba(mg/kg)   0.01       158  590000     640       230
Sr(mg/kg)   0.07       312     540    60.5      1030
Pb(mg/kg)  0.003        37     685    27.1       5.4
Cr(mg/kg)  0.001       183     183    8.02     40030
Cu(mg/kg)  0.003        22      49    8.18      22.9
Ni(mg/kg) 0.0005        15       3      15      11.6
As(mg/kg) 0.0005       3.9      34     3.9      10.1
Co(mg/kg) 0.0002       2.9     3.8     2.9         5
Cd(mg/kg) 0.0001      0.08       6    0.50       0.2
Hg(mg/kg) 0.0001      0.12     4.1    0.12       0.2

^Average elemental composition of freshwater - reference 14.
^Average elemental composition of sedimentary rocks - reference 15.
 Average elemental composition of barite - reference 16.  Al and Na
.assumed identical to cuttings average.
 Average elemental composition of bentonite clay - reference 17.  Ni, As,
rCo, Cd, and Hg assumed identical to cuttings average.
 Average K, Na, and Cr composition of chrome lignosulfonate - reference
gl8.  Other elements assumed identical to lignite.
^Average elemental composition of lignite - reference 19.
 Average elemental composition of caustic based on production from
 sea-salt by mercury cell electrolysis resulting in 5 ppm Hg
 concentration   reference 15 and 20.
2390
7220
6700
5040
16100
460
2400
230
1030
5.4
65.3
22.9
11.6
10.1
5
0.2
0.2
339
0.04
0.013
17800
5400
51400
500000
0.26
105
0.004
0.00066
0.039
0.09.
0.039
0.00053
0.0013
5
                                    1022

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                               TABLE  5
       Initial solid phases  considered  during  MINTEQ  modeling
                 of waste  freshwater  drilling  fluid
  Element

    Ba
    Si
    Ca
    Al
    Mg
    Fe
    K
    Na
    Sr
    Cr
    Pb
    As
    Cu
    Ni
    Cd
    Hg
Solid Species

   BaSO.
   SID/
   CaCO,
   A12°3
   Mg6 6
   NaOH
   SrCO,
   Cr(OH)
   PbCO
   CuO
   Ni(OH)
   CdCO,
   HgCOj
  Concentration (dry weight)
 mg/kg                percent
332000
272000
248000
 68800
 26700
 22900
  8610
  8530
   528
   462
   314
    60.
    32.
    13.0
     3.16
     1.86
 33.6
 27.4
 25.1
  7.0
  2.7
  2.3
  0.9
  0.9
 <0.05
 <0.05
 <0.05
 <0.05
 <0.05
 <0.05
 <0.05
 <0.05
100
                                TABLE  6

        Comparison  of MINTEQ  results and  chemical analyses for
            an  equilibrated freshwater drilling fluid waste
                                                Average Analysis
Element

As
Ba
Cd
Cr
Cu
Hg
Ni
Pb
Sr
MINTEQ
Aqueous
(mg/1)
<0. 000001
4.4
0.00068
0.00070
0.00014
0.0039
2.6
0.55
0.87
Solid
(mg/kg)
83
63000
0.56
75
16
0.40
0
78.1
99

% Solid
100
100
99.9
100
99.2
99.0
0
99.3
99.1
                                                                1
Aqueous
(mg/i)
0.06
4.0
0.0018
0.44
0.069
0.000035
0.065
0.83
63.7
Solid
(mg/kg)
3.3
1800
0.069
12.1
6.01
0.015
6.7
25.8
103.7

% Solid
98.2
99.8
97.4
96.4
98.9
99.8
99.0
96.8
38.6
1
 Reference 9
                                 1023

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USING  OILY WASTE  SLUDGE  DISPOSAL TO  CONSERVE AND  IMPROVE  SANDY CULTIVATED
SOILS
Volkmar  0.  Biederbeck
Research Station,  Research Branch
Agriculture Canada
Swift Current,  Saskatchewan  S9H 3X2
Canada
Introduction

The  development  of  heavy   oil  deposits  in  western  Canada  must  increase
substantially in the  near future to replace diminishing  supplies  of light to
medium crude oil  if Canada  is to  attain  energy self sufficiency.   Heavy oil
development is  being furthered  by two upgraders,  one  completed in  1988 at
Regina,  Saskatchewan and one still  under  construction at Lloydminster, on the
Alberta/Saskatchewan  border,  to  eventually provide  a  combined  capacity to
process 16,000  m   of heavy  crude per  day.   To improve  heavy  oil  recoveries,
beyond  the 5  to  10% yield  feasible  with conventional pumping,  so-called
"enhanced oil recovery"  (EOR) methods  (such  as  steam  injection,  fireflood and
alkaline-polymer  flooding)  will have  to  be used more  in the future.   These
EOR  methods are  more  effective  in   pushing  heavy  oil  out  of  underground
formations, but unfortunately they  also produce much  higher volumes of sludge
and other non-refinable wastes.

The  disposal  of oily wastes  generated during  field  production has  become  a
major  environmental  issue  in  heavy   oil  development.    Historically,  these
wastes  have  been  spread on  lease  and rural roads  but the practice of "road
oiling" can no  longer accommodate the growing quantities of  waste materials.
Furthermore, provincial  and federal environment  agencies are  concerned that
runoff  from  oiled  roads  could  eventually  pollute  rural  drinking  water
supplies with undesirable chemicals such  as  polynuclear aromatic hydrocarbons
 (PAHs) .    Without  the  means  for  waste  handling  and  disposal   in a  more
acceptable   and   sustainable   manner,   waste   management   could   create
environmental problems  that would  ultimately  slow or  impede  the development
of the  heavy oil  resources  in Canada.

 To  assess  if   heavy  oil  production   wastes  can   be  used  to  conserve
 agriculturally  marginal  sandy soils a field and laboratory  study,  funded by
 the  Government  of  Canada  under  the  Interdepartmental  P.E.R.D.  (Panel on
 Energy  R&D)  Programme,  was  jointly initiated  in 1986  by Environment Canada
 and  Agriculture Canada.  The  project takes a  novel  approach  to  research on
 landfarming  with  oily wastes by focusing on the  potential for improvement of
                                     1025

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highly erodible  and  infertile cultivated  soils  through application  of  waste
sludge and  fertilizer rather  than to emphasize  industrial disposal  aspects
which have  invariably led  to  attempts  'to  get  rid  of the largest  possible
volume of wastes on the smallest and nearest  available  land area'  with little
regard   for   soil   conditions   and   potential    agricultural    benefits.
Consequently,  the  primary  objectives of  the present   study  were  to:    (i)
evaluate if productivity and structure of  marginal  sandy land  can  be enhanced
by  incorporation  of  organics  contained  in  heavy  oil waste  sludge;   (ii)
determine if  these oily wastes  can  induce more  stable aggregation  of  loose
surface  particles  and  thereby  reduce   the  high  susceptibility  of  sandy
cultivated soils to degradation  by wind  erosion; and (iii)  determine optimum
loading and  agronomic conditions for sludge  use  to improve soil  quality  and
stabilize crop yields without excessive  contamination of crops and soils with
undesirable   chemicals;   so   as  to  facilitate  the   development  of  an
environmentally sound and agriculturally beneficial disposal option.
Materials and Methods

In late  June  and early September  1986  two plot experiments were  established
on a  level  2.0  ha (5 acres) area  of  Meota loamy sand, a Black Chernozem  (or
Udic  Boroll according  to  the  US system  of  soil  taxonomy) ,   located  10 km
southeast  of Maidstone,  Saskatchewan.    This  member of  the  'Meota'  soil
association had  developed on sandy glacial alluvial-lacustrine deposits that
have  been  re-worked  by wind.   Major  properties of the  0-10 cm and 10-30 cm
depth of the  eroded  drift deposit, viz. the  2 soil segments to be  primarily
affected  by  oily waste  applications,   are  listed in  Table   1.    The 'FC'
experiment  is a  fallow-wheat-wheat rotation where the  sludge was only applied
in the fallow phase  i.e.,  on June 25, 1986.   The 'CC' experiment  was planned
to be a  continuously cropped cereal  rotation where the sludge was  initially
applied  on  September 3,  1986  and was  to  be  re-applied  in future years,  in
fall,  after the grain harvest,  whenever  deemed  suitable.    Unfortunately,
initial  oil  contents  in   soils  from sludge-treated   plots  of  the  'CC'
experiment  were,  inadvertently,  several  fold  higher  than targeted  due to
extreme variability  in  oil  content of sludge  from one  truckload to another at
time  of  application.   Due  to  the resultant  abnormally  high  and persistent
phytotoxicity  in  all  sludge-treated  CC   plots only  results  from  the  FC
experiment  will  be presented in this paper.   However, some data  from the CC
experiment  were  included  in an earlier project report by  Biederbeck and  St.
Jacques  (3)  and copies of  this report  are available,  upon  request, from  the
authors.

Three sludge application  (designated  by 1st and 2nd digit of the  4 digit plot
treatment  code   as  00=none, 01=300  and 02=600  tonnes/ha)   and  fertilization
rates  (designated by 3rd  and 4th digit of  the code as F0=none, Fl=150  kg  N  +
15 kg P  +  24  kg S, and F2=300  kg  N  + 30 kg P + 48 kg S/ha) were  used in the
fallow plots  in trying to reach the  targeted waste loadings of 1.0% and 2.0%
oil in soil (wt/wt),  respectively.   The planned waste loading was based on an
average  composition  of  5% oil  + 65%  brine  + 30% solids (VFS) in the EOR waste
sludge being  hauled  to the  site  from the  Husky Oil Ltd.,  Golden  Lake Waseca
Fireflood   Pilot  Plant  #4  near  Maidstone.    The  ratio  between  the  three
                                      1026

-------
nutrient  elements added  as fertilizer,  i.e.,  N/P/S=100:10:16,  and the total
amount  of  fertilizer  applied were  selected  such that  they would optimize
microbial conversion of hydrocarbons to  soil  humus-type materials rather than
maximizing oil degradation and C02 evolution  to  effect a possible net loss of
soil organic matter.   All  9  sludge x fertilizer  combinations were replicated
3 times on a total of 27 plots, each being  4  m wide and 14 m long.  First the
fertilizer was broadcast,  then  the EOR sludge was  applied and simultaneously
incorporated to a depth  of 10 cm  with  a specially modified  rotovator pulled
by a tractor and connected through its Bowie  pump and 3" hose to a tank truck
running alongside.  Due  to the  large volumes of  waste sludge required (e.g.,
30  litres/m2  for the  '01'  rate), the  '02'  application rate necessitated  2
consecutive  passes  with  the applicator-rotovator about  16  hours apart  to
prevent any possibility of lateral movement of oily wastes away  from the  area
of  soil  incorporation.   In mid-October 1986 and  1987  all  plots  received  fall
tillage  by  working  the surface soil with  a heavy duty cultivator  to  a depth
of  10  cm to improve aeration and  soil  mixing.   On May 15,  1987  and  also  on
May 10,  1988  all plots  and the  surrounding area  were  seeded  to hard  red
spring wheat,  cv. Katepwa,  at  a rate of  86  kg/ha  (77  Ib/ac) .    In  1989  all
plots  were  summerfallowed  by cultivating and rototilling  twice  to 10  cm  soil
depth.   Tillage  and  seeding  operations  were  performed  with standard  farm
machinery.  No fertilizer  was applied to any  plots during the first crop  year
 (1987)  and  during  the  second  fallow   phase  (1989)  but  prior  to  stubble-
 cropping fertilizer  was  re-applied in April  1988 at the  'Fl' and 'F2' rates
 as  per  the original  treatment  plan  and  thereafter  all plots  were roto-
 tilled.    No  herbicides  were   used on  any  plots   until  October  1987  to
 facilitate  proper evaluation of the herbicidal  effects exerted by  the soil-
 incorporated  hydrocarbon  residues.   Thereafter  herbicides were  applied  but
 still  rather  sparingly.

 Soils  in  all  27  plots  were   sampled  hydraulically  to  120  cm  depth  (2
 cores/plot  and 5  depth  segments/core)  just  before  the  fertilizer and  oily
 sludge applications  in late  June  1986  and again prior to wheat  seeding  and
 after  grain harvesting in 1987 and  1988 and  also in  spring  and  fall  of  1989
 for routine physical  and  chemical  analyses.   The  surface layers  (0-10  cm)
 were   sampled  more   often,   at  least   initially,   for  soil   structural,
 biochemical,  microbiological and hydrocarbon analyses.   Plant production was
 determined  by sampling  twice  during  each crop year.   When  the  wheat  was
 flowering,  around the end of July,  two  1.0 m  samples were  cut  in each  plot
 to  count the weed population and  the  wheat stand density  and to measure the
 vegetative  dry matter (DM) production by  the wheat crop.  At  full maturity,
 between  early and mid-September, duplicate 1.0  m  samples of wheat were cut
 in  all 27 plots  for  subsequent  drying  and hand-threshing  to determine grain
 and straw yield  and  also major  parameters  of  grain quality.

 All hydraulically cored soil samples  and  also the  surface samples collected
 manually for  dry aggregate  analysis  were air   dried  and stored  at  ambient
 temperature  until   analyzed,  while  those   surface  samples  destined   for
 waterstable   aggregate,    hydraulic    conductivity,    microbiological   and
 hydrocarbon analyses were always stored field moist at 0°C.  To determine the
 amount  of  oily   residues  remaining  in  the  sludge-treated soil  a composite
 sample  was  taken  from  six  locations  in   each  plot  and  representative
                                    1027

-------
subsamples  were  periodically  shipped  to  a  commercial  laboratory,  i.e.,
Norwest Labs  in Edmonton, Alberta,  where the  oil  and water  were  separately
recovered by hot toluene extraction  according to  the method of Dean and Stark
(16) .    To  assess  sludge  treatment  effects  on  one major  phase  of  soil
structure  the   state   of  the   secondary,   field  or  dry   aggregates   was
periodically  measured.    Triplicate  composite samples  were  taken from  six
locations in  each  plot  and after  drying the soil was mechanically separated
into  various   aggregate   sizes   by  rotary  dry  sieving   (5)   because   the
susceptibility  of  soil to  erosion  by  wind  is  closely related  to the  size
distribution  of  its  dry  aggregates   (7).    The   primary  or   waterstable
aggregates  represent  another  important   aspect   of  soil  structure.     To
determine  the  size  distribution of  these  aggregates  duplicate  composite
samples were  taken from four  locations  in each plot  and after  screening  (<  8
mm) the  field moist soil (25 g  subsamples)  were  wetted  and the  disruptive
force of water was used for aggregate separation  by  the wet sieving technique
as  described  by  Kemper and Chepil (7).   For ease of  evaluation of  oily waste
addition effects the aggregation  data were expressed in the form of a single
parameter per sample  by calculating the geometric mean diameter  (GMD) which
is  considered to be  the  most  reliable  index  of  waterstable aggregation  in
soils.   To  assess the effects  of sludge  incorporation on  the rate of water
movement through soil  three  undisturbed cores of topsoil were  taken manually
in  each plot  with  15 cm  long  x 5 cm diameter aluminum tubes.  All  tubes  were
tightly closed with  plastic  caps for transport  to  the  laboratory where  the
saturated hydraulic conductivity  was measured by the  constant-head method as
described by  Klute (8).

Heterotrophic  microbial  activity  was  assessed by  determining rates  of  soil
respiration.   Two subsamples  from the composite surface sample taken from six
locations in  each plot were  placed in  Biometer  flasks  (1) and  incubated at
field capacity moisture and  21°C  for 14 days.  The  amount  of  C02 evolved was
collected in  NaOH and measured  at appropriate intervals  by titration.   The
population  levels  of  major types  of  heterotrophic   microorganisms   were
determined  on the same composite surface  samples,  as taken  for  respiration
and hydrocarbon  analyses,  by  using the dilution plate count method.   Aerobic
bacteria  and  actinomycetes were  enumerated  with  spread-plate techniques  on
soil  extract  agar   and   filamentous  fungi  and   yeasts   on  rose   bengal-
streptomycin  agar as described by Biederbeck  et al  (2).

All data  from soil  and plant analyses were processed statistically and least
significant  difference  (LSD)  values were calculated  and  used  to test  for
significant differences between treatment  means.
                                 1028

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Table  1.  Major physical  and chemical properties of Meota  soil at
         PERD project site  near Maidstone, Saskatchewan,  prior to
         oily waste sludge incorporation  in  1986.
Soil Property
Texture :
Sand, %
Silt, %
Clay, %
Texture class
*
PH ^
Electrical conductivity , mS/cm
Bulk density,^ g/cm3
*-
Saturated hydraulic conductivity5, cm/hr

0-10
79.9
8.7
11.4
loamy sand
5.8
0.54
1.31
7.3
Depth, cm
10-30
81.9
8.6
9.5
loamy sand
6.1
0.26
nd
nd
 Water content:
  At field capacity  (0.033 MPa),  %
  At perm, wilting pt.  (1.5 MPa), %
 Cation exchange capacity, meq/100 g

 Water-extractable cations, (ig/g  soil
11.8
 8.4
49.7
7.5
5.7
 nd
NaT
K+
Ca2+
Mg2+
Total N, %
Organic C, %
C/N ratio
1.45
5.47
0.81
1.80
0.184
2.20
12.0
1.23
3.38
1.61
1.48
0.114
1.31
11.5
   In saturation extract.    For  0-15  cm depth.   nd=not  determined.

 Results and Discussion

 Reasonably  uniform incorporation  of  the  EOR waste  sludge  was  accomplished
 without difficulty,  at' both application rates,  by running the blades  of the
 applicator-rotovator  at  top speed  (i.e.,  550 rpm) while  the tractor pulling
 the rotovator is travelling very slow (i.e,  0.59 km/h or 0.36 mph).   Although
 there was more variability  in  toluene-extractable oil content of surface soil
 between  treatment replicates  than was  apparent  from  visual examination  of
 treated  plots  and although there were  some unexplainable increases  in soil
 oil  content during the  first  winter  (Table 2)  the  measurements  of residual
 oil  contents  in  our  four year study  were considerably  less  erratic than the
 corresponding results reported from some other oily waste landfarming studies
 (12,  15) .    Sludge incorporation  changed  the appearance  of the Meota  loamy
 sand  as  rotovating   drastically lowered  the density  by  'fluffing up'  the
 topsoil,  particularly in the  double  roto-tilled 02  plots, and  as  oily waste
 admixture perceptibly darkened its color.   Not all sludge-treated plots could
                                      1029

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be manually  soil  sampled  within  24  hours  of  oily  waste  incorporation  for
subsequent hydrocarbon analyses  because the pungent odors and noxious  vapors
emanating from the soil  surface  made  this task very difficult and  unhealthy.
Thus initial sampling  was  limited to the  unfertilized  01 and 02 plots.   The
characteristic odor  of this  EOR sludge  could  still be  detected on treated
plots  for  the   next   16  months.    Thereafter,  the  odor  only re-appeared'
immediately after any tillage operation.

Table 2.  Effect of  oily waste  sludge  incorporation and  fertilization
          on  content   of  toluene-extractable  organics  in  Meota loamy
          sand.
Sampling date
Treatment
code
01FO
01F1
01F2
01 Mean
02FO
02F1
02F2
02 Mean
June
1986

1.03
ns
ns
—
1.45
ns
ns
	
Sept.
1986
May
1987
Sept .
1987
Extractable oil as %
0.70 0.85 0.66
0
0
0
1
1
1
1
.56
.76
.67
.10
.20
.09
.13
0
0
0
1
0
0
1
.99
.70
.85
.30
.99
.93
.07
0
0
0
1
0
0
0
.84
.76
.75
.03
.96
.99
.99
Apr.
1988
Sept.
1988
of dry wt .
0.85 0
0
0
0
0
0
1
0
.75
.65
.75
.93
.98
.01
.97
0
0
0
0
0
0
0
May
1989
of soil
.77 0
.75
.73
.75
.89
.86
.88
.88
0
0
0
0
0
0
0
S
.71
.66
.68
.68
.86
.86
.85
.86
Sept.
1989

0.
0.
0.
0.
0.
0.
0.
0.

71
74
65
70
85
79
83
82
ns
Soil  in  untreated  OOFO  control  plots  contained  0.093  and 0.087%
extractable  oily  substances  when sampled  in  June  1986  and April
1988, respectively.
Samples  collected June  26,   1986  i.e.,  one day  after  oily waste
sludge incorporation.
All values are mean of 3 replicate plots/treatment at 0-10 cm depth.
= not sampled.
During  the first  10  weeks  after  sludge incorporation  the rate  of loss of
toluene-extractable oily  materials  from Meota loamy sand was  high,  averaging
32  and  24% for  unfertilized 01  and 02 treatments,  respectively  (Table  2) .
Much  of this  initial  rapid loss  can be  attributed to  physical  processes
whereby some very light oil fractions  move  upward within the sandy  soil  and
upon  reaching  the   surface   are   readily  lost  to   the  atmosphere  by
volatilization  and evaporation.   Biological  processes  are  the other  major
loss mechanism as the soil microbial population  readily metabolizes the more
easily  degradable  oily waste  components  and respires  some  oil-C as  C02.
Initially  elevated rates of oily  sludge  biodegradation have  also  been  found
in  several other studies  (4, 13) .   Over  the next three years there appeared
to  be no further decrease  in residual oil  content in any of the soils treated
at  the  01  rate and only  an  average  decrease of  another 19%  in soils treated
                                     1030

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with  sludge at  the 02  level  (Table 2) .   These very  low rates  of waste oil
degradation were  certainly unexpected as  they are  consistently  lower than
biodegradation  rates  observed  in other  landtreatment  studies  (12,  17,  15,
13) .    The  lack  of biodegradation could  be  attributed,  in  part,   to  the
occurrence of very severe drought  conditions  at the experimental site in 1987
and 1988 or,  in part,  to the coarse texture  of the Meota  soil since Skujins
and McDonald  (15)  found  that waste oil  biodegradation  in a  semi-arid soil
occurred  only  during  short  seasonal  periods  of  favorable  moisture  and
temperature conditions  and as Riiraner and  Al-Khafaji (13)  emphasized that fuel
oil degradation in soils  decreased markedly  with decreasing  clay contents.
At 3  1/4  years after  incorporation  of  the  EOR  sludge  69 and 59%  of  the
initially soil-contained oily materials were  apparently still present in 01FO
and  02FO  plots,  respectively  (Table  2) .   However,  based  on  the extensive
decline in  phytotoxicity  of  the sludge-treated soils,  observed over the same
3-year period,  it  can be assumed  that most oily residues in this  sandy soil
were   attached   by  microorganisms   and   were  biochemically   modified   or
transformed but not to such  an  extent that they were  rendered unextractable
to  toluene.    The microbial transformation   of   hydrocarbons  and  eventual
incorporation   into   soil   organic   matter   was  reported    from   several
 ' landfarming'   studies  (4,  15).    Thus,   in  the  current   study oily  waste
incorporation had  by  September 1989 effected  a 20 and 16%  increase  in total
soil  organic  matter   (based  on  soil-C  data)  over   the   initial  level  of
indigenous  organic matter before  sludge  application at  the 01  and  02  rate,
 respectively.   Addition  of  N+P+S  fertilizer had no  effect   on  waste  oil
degradation  at  the  01 sludge  treatment  rate, while  at the  02 sludge  rate
there  was, at  least  initially,   a  trend suggesting  that   fertilization  had
stimulated  oil  degradation  (Table 2)  but  these  fertilizer effects  were  not
 statistically significant.   Some  other  investigators have also  found  that
 fertilization  failed  to  increase  oil degradation significantly  (Odu  1978;
 Skujins  & McDonald  1985)  while  many  others  have  reported the  opposite  and
 strongly  recommend fertilization  (12,  18, 10,  13).

 Neither  initial fertilization in  June 1986 nor fertilizer  re-application  in
 April  1988  had  any   significant effect  on  the  size distribution  of  dry
 aggregates  in sludge-treated  or  in control  soils.   Consequently, only results
 for  those treatments  that were sampled twice each  year for dry sieving,  viz.
 OOFO,  01F1 and 02F2,  are shown  in  Table 3.    These  dry sieving analyses  of
 secondary aggregation  show  that  incorporation of EOR sludge,  even  at  the
 lower  01  rate,  was very effective in  reducing  the  erodible fraction near the
 surface  of the loamy  sand  for  about 3  1/2  years,  but  8  months  later  all
 differences had disappeared  at  both sludge  rates.

 At 11,  15  and  22  months after soil oiling the erodible  fraction  in sludge-
 treated plots  was, on average,   16, 16 and 11%  (of  dry wt. of soil)  lower,
 respectively,   than  in  control   plots (Table  3) .    The  magnitude  of  these
 topsoil  erodibility  reductions  effected through   oily  sludge   incorporation,
 was  considerably  greater than those found by Biederbeck and co-workers  (2)  to
 have been effected after 12  years by different crop rotations on a Brown loam
 in southwestern Saskatchewan.   This  increase  in  stable dry  aggregation was
 sufficient to  render  the sludge-treated soils completely  resistant  to wind
 erosion because  thin  layers  of   white,  unoiled  sandgrains,  obviously blown
                                     1031

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onto the dark-colored, oiled  plots  from the surrounding untreated  land,  were
frequently observed,  but  no similar deposition  of  dark,  oiled sand was  ever
detected on untreated soil downwind from any 01.  or  02 plots.   It  must  also be
emphasized that for  three years the erodible  fraction  in 02 plots was never
lower than in 01 plots despite  the  initially about 50% higher oil  content in
the former plots  (cf. tables 2  and  3).   This implies  that addition  of  more
oil,  than is  necessary  to  attain  an  initial 1%  concentration  in soil,
provides no additional benefits  for erosion proofing of this loamy  sand.

Table 3.  Effect of oily waste sludge incorporation on erodibility  of
          Meota loamy sand
Sampling date
Treatment
code
May
1987
Sept .
1987
Apr.
1988
Sept.
1988
May
1989
Sept.
1989
May
1990
OOFO
01F1
02F2
94.2
78.5
78.0
CitUUl
90.4
75.8
72.4
IJJ-t; J-J.OL.LJ
94.5
83.7
82.9
-uu as T>
93.3
88.7
85.9

-------
residues would considerably lessen  the disintegrating force  exerted by rapid
and'repeated  water entry during the wet sieving  action.

Table  4.   Effect of oily  waste  sludge incorporation  on  waterstable
          aggregates in Meota loamy sand
Treatment
code
May
1987
                                     Sampling  date
Sept.
1987
Apr.
1988
Sept.
1988
May
1989
Sept.
1989
OOFO
01F1
02F2
0.37
3.27
4.17
0.62
3.36
4.51
OM cuamei
0.77
3.15
4.12
;er in mm
0.72
3.97
4.64
0.37
2.68
3.19
0.48
2.90
1.93
LSD (P=0.05)  for treatment x date =0.90 mm, n =  6.
   Geometric mean  diameter  as determined  by  wet  sieving of  soil
   from  0-10  cm  depth.    GMD  is   an   index   of  the  state  of
   aggregation.

Results  from  the dry  and wet  sievings  clearly  show  that oily waste  sludge
incorporation  markedly  improved the  structure  of  the  loamy  sand  through
greatly  increased  and  more  stable  aggregation.     Erosion,   salinization,
acidification  and  declining levels  and  quality  of  organic matter have  been
identified as  the major sources of  soil  degradation  in  western  Canada  (6)
with  high  wind and  water erodibility and lack  of  organic matter being  the
predominant  problems  on  sandy,  cultivated soils.    Considering  the  soil
organic  enrichments  and structural  (aggregation)  improvements  that can  be
effected with  well-managed oily waste  incorporation into cultivated fields it
should  be  possible  for  EOR waste  sludge  management  and  disposal to make  a
very  significant  and  beneficial  contribution  to  future conservation of  and
sustained crop production on these  sandy problem  soils.

As  expected,  water movement within  the  surface soil  was  drastically reduced
as  the  result of oily  sludge  incorporation   (data  not  shown).    Saturated
hydraulic conductivity decreased from 7.3  cm/hr  in control plots  to 1.9  and
2.5  cm/hr  in  01  and  02  plots,  respectively,   within  one  day  of  sludge
application.   Eleven months later conductivities were  still  similarly  low in
treated  soils,  but  by  3  1/4  years   after   soil   oiling   the  hydraulic
conductivities in   01  and  02  plots  had  recovered  to   a  level  that  was
equivalent to  about  80 and 40% of  the rate of water  movement  in  the control
 soil.    Although   the  sludge  applications  caused  extensive  and  rather
 persistent reductions  in hydraulic  conductivity  of  surface soil there  was no
 serious  interference  with normal  rates  of water movement  in  this  coarse
 textured soil  (3).

 Soil  incorporation  of massive amounts  of organic  carbon  (i.e.,  from  about
 10,000   to   25,000  kg  oil-C/ha),   in  the  form   of  EOR  sludge-contained
 hydrocarbons  was expected to  boost soil microbial  populations  and stimulate
                                     1033

-------
heterotrophic microbial activity which can be  readily  determined by measuring
the production of CC^.  Within 10 weeks of the sludge  application respiration
rates in unfertilized 01 and 02 plots were already  2.2-  and  2.7-fold those of
the corresponding controls,  while C02 evolution  by all fertilized  and  oiled
soils,  except for 02F2, was significantly greater than in  fertilized controls
(Table  5) .    However,  eight months  later respiration  rates  in all  sludge-
treated soils were greatly enhanced, now being 4.2- and  5.4-fold those of the
respective  controls  in unfertilized  01  and 02  treatments.    Thereafter,
respiration rates in all sludge-amended soils  decreased  extensively (i.e., by
a factor of  3  to  4)  and then remained very  close to control  levels  over the
next two years.

Table 5.  Effect  of  oily  waste  sludge  incorporation  and
          fertilization on  rate of  microbial  respiration in
          Meota loamy sand

                	Sampling date	
Treatment       Sept.     May      Sept.     Apr.      Sept.
code            1986      1987     1987      1988      1989
                           |J.g CO2-C/g O.D. Soil
OOFO
OOF1
OOF2
01FO
01F1
01F2
02FO
02F1
02F2
98
98
99
220
143
103
261
140
181
53
59
52
225
235
127
285
269
249
55
65
59
58
62
59
96
75
65
59
70
55
81
77
59
100
62
58
80
88
82
74
87
72
77
58
54
LSD  (P=0.05) for treatment x date = 60 \ig C02-C, n =  6.
   Cumulative  CC>2  evolved during 14  days at  FC  and 21 °C by
   soil from 0-10 cm depth.

It must be  noted that  the period of maximum soil microbial C02  production  in
most sludge-treated  soils,  i.e.,  May 1987, did not  coincide with  the  period
of maximum oil biodegradation,  i.e.,  June  to  September 1986.   An  initial
decline or lag in  respiration,  after oil  addition  to  soils,  followed by  a
rapid rise  and later slow decline in  activity  was  reported in  a review of  oil
spill effects  (14)  while very high  initial respiration rates were observed in
some oily waste disposal  studies  (4,  13).    Contrary to results  from  plot
experiments  in  Alberta  (9)   fertilizer  addition  failed  to  significantly
increase  C02  production  by oily  sludge-amended  Meota  loamy  sand; in  fact
within  10  weeks of  sludge  addition  respiration  rates in all  fertilized  and
oiled  soils were  significantly  lower than  in  the  respective  unfertilized
                                    1034

-------
soils  (Table  5).

Population  changes of aerobic, heterotrophic bacteria  followed a pattern that
was  similar to the one just described for  respiration  rates.   Again there was
a short  lag  (10 week),  especially at the  02  sludge addition  level,  followed
by a rise to maximum numbers  at  11 months, when bacterial  populations in all
waste  oil-amended  soils were 5-  to  8-fold greater than  in the  respective
controls  (Table  6) .    Thereafter,  bacterial  populations in  the oiled  soils
declined  rather  gradually until  September 1988  (data  not  shown)  when  they
were no  longer significantly  different from the controls.

Table 6.   Effect  of  oily  waste  sludge incorporation  and  fertilization  on
          microbial populations at 0-10 cm depth in  Meota loamy  sand
Samplinq date

Treatment
code
OOFO
OOF1
OOF2
01FO
01F1
01F2
02FO
02F1
02F2
Bacteria
Sept.
1986
59
49
47
175
193
121
74
37
89
(x!0b
May
1987
66
103
84
496
508
602
390
561
565
/q O.D.
May
1989
67
98
103
117
179
158
136
103
135
soil)
Sept.
1989
96
105
75
80
130
99
97
87
98
Funqi
Sept.
1986
142
147
149
635
190
101
232
82
89
(x
May
1987
239
238
185
818
355
254
521
295
380
10-Vq 0.
May
1989
149
243
300
388
363
337
313
281
272
D. soil)
Sept.
1989
256
304
398
326
416
344
335
287
326
 LSD  for bacteria at P=0.1  for treatment x  date  =  92 x  10  /g.
 LSD  for fungi at P=0.1 for treatment x date = 218  x 103/g.

 In  contrast  to the  bacterial  response,   there   were very  few  significant
 increases  in fungal  populations  due to  EOR  sludge   incorporation.    These
 occurred only in unfertilized  plots at 10 weeks and at 11  months  after waste
 oil  addition.   For all  other  treatments  and dates  there were  no  population
 differences  from the respective  controls  (Table 6).  Generally similar trends
 in  soil bacterial  and  fungal population responses to  waste oil  incorporation
 were  reported from other landtreatment studies  (9, 15).

 Oily  materials  are  known to  exert strong  herbicidal effects  (14)  and the EOR
 waste sludge being incorporated  into Meota loamy  sand  was no exception.  Thus
 at  seven weeks  after the sludge  application in  1986  there were practically no
 weeds on any 01 or 02  plots, while a very dense  stand of annual weeds (> 100
 plants/m )   had  developed on  all  unoiled  control  plots.   The  herbicidal
 effects of  the  oily  residues were rather  persistent  because weed infestations
 in  the unsprayed wheat crop  grown in 1987 were,  on average,  90  and 96% lower
 on  01 and  02 plots  than  on the  respective  control plots  (3).
                                     1035

-------
Unfortunately,  the phytotoxic  effects exerted by  the  waste oil residues and
the remaining  brine  salts on  vegetative  growth and grain  production by the
spring wheat crop were drastically aggravated by the occurrence of severe and
prolonged drought stress during  the  1987,  and even more so, the 1988 growing
seasons.   The  pitifully small  grain yield  produced  in 1988  on  the unoiled
control plots  (Table 7) is proof of the severity of the drought stress.  Such
extensive  and  consecutive droughts  are  considered to  be  very  unusual for
northwestern Saskatchewan.

Table 7.  Effect of  oily waste  sludge  incorporation and
          fertilization  on yield  of  spring  wheat,  cv.
          Katepwa,   during 2  successive  years  on Meota
          loamy sand
Grain Yield*
1987
Treatment
code
OOFO
OOF1
OOF2
01FO
01F1
01F2
02FO
02F1
02F2


bu/ac
15.
26.
22.
6.
10.
11.
2.
4.
5.
8
1
2
9
0
9
5
9
8
% of
control
100
100
100
43
39
54
16
19
26

1988

bu/ac
4.
5.
5.
5.
7.
10.
2.
4.
6.
3
0
9
3
1
1
5
3
5
% of
control
100
100
100
123
143
172
58
86
111
LSD  (P=0.05) for 1987 yield = 9.5 bu/ac
LSD  (P=0.05) for 1988 yield = 4.1 bu/ac
*                                    ?
   All  values  are  mean of two  1.0  m  samples/plot and  3
   replicate  plots/treatment  cut  on September  14,   1987
   and  on September 6, 1988.

In  1987  grain  yields   on  control   and  on  sludge-treated  plots  generally
increased with  N+P+S  fertilization  and,  on average,   01  plots produced almost
half,  but  02  plots  only a  fifth  as much grain  as  was  harvested from the
control  plots.     The  extent  of   yield  reductions   due  to  EOR  sludge
incorporation  15 months  earlier,   was  very  similar to reported  reductions
 (3) in  vegetative growth of the  spring wheat.  Although  the quantity  of  wheat
produced on  oily waste-treated  soil was severely  reduced  the quality  of this
grain,  in  terms of protein content and test weight, was  very adequate.   In
1988  fertilization  again effected  significant increases  in grain yield but
this  time  only on sludge-treated  plots.    It  seems  that  fertilizer  helps  to
overcome the phytotoxic  effects of  oily  residues  in soil  even  under drought
conditions.  This is  suggested  by the fact that  grain yields on fertilized  01
plots were about 60%  greater  and on fertilized 02  plots  about the same as the
                                     1036

-------
respective  control yields.   Similar  beneficial effects  of fertilization on
plant  growth and  grain production  in oiled  soils have  been  found  in other
plot experiments  (17,  10).
Conclusions           ,

The feasibility of using  disposal of EOR-type  oily waste sludge  for erosion
proofing  and  organic enrichment  of  cultivated  sandy  soils  in a  semi-arid
northern  environment  has  been  demonstrated.    Sludge  incorporation  greatly
improved  the  soil's  structure  through  large   and persistent  increases  in
primary and secondary aggregation.   It  also effected beneficial  increases in
soil microbial  activities  and populations.    Under drought  stress,  cereal
grain  production  was   initially  reduced  by  phytotoxicity  from  the  oily
residues  but  later these  deleterious effects  were largely compensated  with
fertilization.
 References

 1.   R.  Bartha, D.  Pramer,  Features of a  flask  and method for measuring  the
     persistence and biological effects of pesticides  in  soil.   Soil  Science,
     100,1965,  68-70.

 2.   V.O.  Biederbeck,  C.A.  Campbell,  R.P.  Zentner, Effect  of crop  rotation
     and  fertilization   on  some   biological  properties   of   a  loam   in
     southwestern Saskatchewan.  Canadian J. of  Soil Sci.  64,  1984, 355-367.

 3.   V.O.  Biederbeck, R.M. St. Jacques, Using  oily  waste  disposal  for  erosion
     proofing of sandy cultivated  soils.   Prelim. Rept.  on joint  Agriculture
     Canada/Environment Canada Study of PERD Project No.  24106,  July  1988,  18
     PP-

 4.   I.  Bossert,  W.M.  Kachel,  R.  Bartha,  Fate  of  hydrocarbons during oily
     sludge  disposal in  soil.   Applied  and  Environ.  Microbiol.,  47,  1984,
     763-767.

 5.   W.S.  Chepil, A  compact rotary sieve and the importance of dry sieving in
     physical soil analysis, Soil Sci. Soc. Amer. Proc.,  26,  1962,  4-6.

 6.   D.R.  Coote,  J.  Dumanski,  J.F.  Ramsey,  An assessment of  the  degradation
     of  agricultural  land  in  Canada.    Land  Resource  Research  Institute,
     Contrib. No. 188, Ottawa, Ontario, 1981.

 7.   W.D.  Kemper,  W.S. Chepil,  Size distribution  of  aggregates,  p.  499-510
     In:  Methods of Soil Analysis  (C.A. Black,  Ed.),  Part I,  Agronomy No. 9,
     Amer. Society  of Agronomy, Madison, Wisconsin,  1965.

 8.   A. Klute,  Laboratory measurement of hydraulic  conductivity of saturated
     soil.   p.  210-221 In: Methods  of Soil Analysis  (C.A. Black,  Ed.),  Part
     1, Agronomy No. 9, Amer.  Society  of Agronomy,  Madison, Wisconsin,  1965.
                                    1037

-------
9.    W.B.  McGill,  M.J.  Rowell,  Soil respiration  rates,  p.  98-108  In:   The
     Reclamation of Agricultural Soils after  Oil  Spills  (J.A. Toogood,  Ed.)
     Part  1:    Research,  Alberta  Institute of  Pedology  Publ.  No.  M-77-11.
     University of Alberta, Edmonton, 1977.

10.   W.W.  Mitchell, T.E.  Loynachan,  J.D. McKendrick,  Effects of tillage  and
     fertilization on  persistence of  crude oil contamination in an  Alaskan
     soil.   Journal of Environ. Qual., 8, 1979, 525-532.

11.   C.T.I.   Odu,  The  effect  of nutrient  application  and  aeration  on  oil
     degradation in soil,  Environ. Pollut., 15, 1978,  235-240.

12.   R.L.   Raymond,  J.O.   Hudson,  V.W.  Jamison,  Oil  degradation  in  soil.
     Applied and Environ.  Microbiol., 31, 1976, 522-535.

13.   D.L.  Rimmer, A.A. Al-Khafaji, The fate of added  fuel  oil in  soil  and  its
     effect  on  soil  aggregate  stability,  p.  449-450.   Transactions of  the
     XIII.   Congress   of  Internatl.   Society  of  Soil  Science.     Vol.   II.
     Hamburg, Germany, Aug. 13-20, 1986.

14.   MAJ.  Rowell,  The  effect  of  crude  oil spills  on  soils -  A  review of
     literature, p. 1-33.  In: The Reclamation of Agricultural Soils  after  Oil
     Spills  (J.A.  Toogood,  Ed.)  Part  1:   Research,  Alberta  Institute of
     Pedology Publ. No. M-77-11.  University of Alberta, Edmonton.   1977.

15.   J. Skujins,   S.O.  McDonald,  Waste  oil  biodegradation  and  changes in
     microbial  populations in  a  semi-arid  soil.   p.   549-561  In:   Planetary
     Ecology  (D.E.  Caldwell,   J.A.  Brierley,  C.L.   Brierley,  Eds.),   Van
     Nostrand Reinhold Co., New York, 1985.

16.   Syncrude  Canada  Ltd.,  Determination  of  bitumen,   water  and   solids
     contents  of Middlings  and  tailings  samples,  p.  69-74 In:    Syncrude
     Analytical  Methods for  Oil  Sands  and Bitumen  Processing.    Edmonton,
     Alberta, 1987.

17.   J.A.  Toogood,  M.J. Rowell,  M.  Nyborg,  Reclamation  experiments in  the
     field,   p.  34-64  In;    The  Reclamation  of Agricultural  Soils  after  Oil
     Spills  (J.A.  Toogood,  Ed.)  Part  1:   Research,  Alberta  Institute of
     Pedology Publ. No. M-77-11.  University of Alberta, Edmonton,  1977.

18.   J.A.  Toogood, W.B. McGill, The Reclamation  of Agricultural Soils  after
     Oil Spills.  Part 2:   Extension, Alberta  Institute of Pedology Publ.  No.
     M-77-11.  University of Alberta, Edmonton, 1977.
                                    1038

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WASTE MINIMIZATION IN E&P OPERATIONS
N.E. Thurber
Environmental Coordinator
Amoco  Corporation
Houston,  Texas
Introduction

The purpose  of  this  paper  is to  examine a  practical  application of  waste
minimization to  the oil  and  gas  exploration and  production  (E&P)  industry.
Waste minimization was  formally introduced  as  a  regulatory  concept  in  the
1984 Hazardous  and Solid  Waste Amendments  to the  Resource Conservation  and
Recovery Act (RCRA) of  1976.   The  concept is broadly defined as volume and or
toxicity reduction of a hazardous waste,  prior  to disposal,  and is  a method of
pollution  prevention.    Waste  minimization  is   a  RCRA  requirement  for  all
hazardous waste  generators  and has  typically received little attention in  the
RCRA-excluded  E&P  industry.   The   concepts   however   have   far  reaching
implications for all waste  streams.  As  stated by Vajda  and Stouch,  "...the
development and  implementation of an effective waste minimization program will
likely become  the  single most essential component of the  successful corporate
environmental program,  success being  measured in terms of both  compliance  and
costs" (1).

Costs may be broken  down into immediate costs resulting from waste management
and  disposal,  and into  long-term costs  which can result  from the  liability
associated  with  waste.   Such  liability  results in  the  ever  more  expensive
remediation  of  past  site  contamination and  invokes  involvement  with  the
Superfund program.  The  precedent for E&P Superfund participation has been  set
 in the  court  decision Eagle-Picher v.   EPA.   By 1990,   four  exploration  and
production  sites  in  Louisiana were  brought  into  the  Superfund  universe.
Cleanup costs are  high.

The  concept  of  waste  minimization   can be   successfully  incorporated   in
exploration  and  production  operations;  however,  concepts   must be  both
flexible and site-specific  to cover the diverse  environment  and the extractive
nature of  oil  and gas  operations.  Extractive operations have  little  control
over  product  source,   or  feedstock,   and  have  limited  choice  for  facility
location  and  production processes.  Additionally,  market  conditions govern
production  activities.   Higher  petroleum prices  increase ultimate  petroleum
 recovery,  and  in  turn,  the amount of  waste generated  at a given production
 facility.   Low petroleum prices have also driven many waste volume reduction
measures that  are  now  standard industry practice.  The practices,  while  truly
waste  minimization, are not normally recognized  as  such  and will  not  be
 covered here.

Basic E&P Waste  Categories
                                         1039

-------
The 1980 RCRA amendments divided  exploration and production wastes into  three
categories; produced water, drilling fluids, and associated wastes.   Figure #1
shows the  relative  volumes of the  three  categories,  based on  a 1985 API E&P
waste survey.  (2)  Produced water  is  the  largest waste category at roughly 21
billion barrels  per year,   or  over 98Z  of the  E&P  waste stream  volume. The
water  occurs  naturally  in subsurface  formations  and  is   produced  from  a
wellbore,   along  with  petroleum.   Surface  facilities  separate the undesirable
water  from the  petroleum.   The  water   is  then  either injected   into  the
producing  formation to sweep  additional oil towards a  producing well,  or the
water is disposed by  injection into a non-producing  formation.   Less than 92
of  the  produced water  is  surface   discharged,  via  a  National   Pollution
Discharge  Elimination System  (NPDES)  permit.  Figure #2  gives  a breakdown of
produced water use and disposal.

Drilling fluids  makeup the second largest E&P waste  category and are perhaps
the  most   amenable  to  waste minimization  concepts.  The  fluids can  be quite
complex and are  an  essential part  of  creating  a  wellbore  from which  petroleum
may  be transferred to  the  earth's   surface.   Drilling  fluids  are usually
disposed   after  a  wellbore  has   been   completed.    If   the  fluid  has  an
oil-continuous phase or other expensive characteristics, it is normally reused
in other drilling operations.

Associated wastes   comprise  less  than one-tenth  of  a percent,  of all  E&P
wastes.  The waste  streams are highly diverse in nature  and  are dependent on
both  the  unique  petroleum  and reservoir  conditions at a  specific production
facility.   In general, the wastes are predominantly a  subset of wellbore and
petroleum  reservoir fluid and solid components. Figure #3 shows a breakdown of
the largest associated waste streams.

Time plays a  significant  role in all  three  waste  categories.  Typically, the
longer  the facility operates, whether a  drilling  operation or  a production
facility,  the greater the waste stream variance,  quantity, and complexity.

Produced Water Waste Minimization

The mechanics of produced water movement  in the petroleum reservoir is well
introduced by Amyx,  Bass,  and  Whiting,   (3)  and  by Dake   (4).    Reservoir
mechanics,  including relative  permeability  effects,   govern  produced  water
production and are  responsible for the increase  in  produced water production
over the  life of a  petroleum reservoir. The  irreversibility  of the  mechanics
can most  be appreciated by understanding that,  when  present,  produced water
primarily  dictates  the  economic life  of  a petroleum  reservoir.   Here, waste
minimization has  its  strongest ally  -  a   direct increase  in  profitability by
waste stream reduction.  Figure #4  gives  a rough approximation for the  strong
economic  incentive  to minimize  produced  water  production.  The  Figure  also
shows how  increased petroleum prices  allow a  greater  level  of produced  water
production, and subsequently an increase in total waste generation.


Produced water  minimization  is  an industry  goal  -  more strongly   driven by
economics  than a regulatory process.   The  statement  strikes  hard when  proper
produced water reuse or disposal becomes  too costly as produced water  volumes
increase.   An operator has two choices,  one,  sell the property to  a  company
                                        1040

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with  lower overhead or  two,  close  down the field.   When a  property has  no
buyer,  the  only legal option is to cease operations.

A great  deal   of  research  and technology  has  been  implemented to  minimize
produced  water production,   beginning  with well  placement   and  completion
techniques,   production   and   well  workover   techniques,   and   ending   with
application of enhanced  recovery techniques.   Horizontal  drilling  is  perhaps
the most  successful technology to date that reduces  produced water production.
Such  technology  often maximizes  the  distance  between  the wellbore  and  the
reservoir zone of high water  saturation  (5).  Application of the  technology  is
rapidly  advancing,  strongly  driven by  profitability  -  high  oil  production
rates and often proportionately  lower  produced  water volumes offset the  often
30X-100X   increase  in   drilling   costs.   Currently,   the  technology   seems
applicable only to reservoirs with specific characteristics.


The  waste  minimization   goal  of  toxicity   reduction  can  however  be widely
applied  to  produced water.   Specific  chemical  additives  are  used to reduce
oil-water  emulsions and  corrosion  caused  by  produced  water.   Incentive  to
reduce toxicity  comes  from  recognition of  concerns  over  both  onshore and
offshore discharges and  from  the leaks  and  spills  associated  with surface  or
injection facilities, e.g. chrome contamination. Additives should  be carefully
evaluated  to  reduce toxicity  and  or any RCRA  hazardous  chemical  components.
Less toxic or hazardous additives should be used.

While  the  benefit  of such product  substitution may seem  moot where produced
water  is safely injected,  the substitution  decreases the manufacturing of the
toxic  or  hazardous product.   Such a  decrease  has  significant  benefit  in
preventing pollution  -  pollution from product  manufacture  and pollution  from
product  spillage or mismanagement.  Reduction or elimination of EPA's Toxicity
Characteristic (TC) compounds  in produced water additives is the  first goal  in
waste  minimization.   Additives of  concern  are  primarily  those containing  TC
metals or aromatic hydrocarbons.

Drilling Fluid Waste Minimization

 Drilling  fluids  offer  the  greatest  E&P  waste  minimization  opportunities.
Reduction  in  waste volume is  achievable with both environmental  and economic
 benefits;  and, waste toxicity/RCRA-hazards  can  be  reduced   or  eliminated.
However, it  is crucial to recognize that waste  minimization  concepts  need  to
 tailored to the level of  drilling development activity.  An industry "success"
 ratio  of 1 completed well per every 9 exploratory wells  drilled  typifies the
 difficulty  in  understanding  subsurface geology,   knowledge   which plays  a
 significant  role   in  minimizing drilling  waste.  Consequently,  once  a  field
begins   commercial  development  and   greater   data  control   is  obtained,
 opportunities  arise  for  improving  waste  minimization.    Conversely,  strict
 implementation of  waste  minimization on an exploratory well  can result  in a
 lack of  flexibility to control unanticipated events.

 Drilling waste, including drilling fluids and drilled  cuttings, comprise  about
 two  percent of the E&P waste  stream, estimated by  API in  1985 at 361 million
 barrels. Basic waste  minimization  methods have  potential to reduce the stream
 volume by  over 60X. Workover  and  completion fluids will be discussed in the
                                        1041

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drilling  fluid  waste   minimization  section  because   of   the   technical  and
operational similarities to drilling fluids.

Well workover and  completion  fluids were estimated at  5.6  million barrels in
the  API  study   and  make-up  about  48Z  of  the  associated waste   category.
Drilling, workover and  completion fluid waste minimization will be  discussed
in  two  sections,  the  first one  covering volume  reduction; and  the second,
toxicity reduction.

Drilling Fluid Waste Minimization - Volume Reduction

The role and nature of drilling fluids is well covered by Bourgoyne,  Millheim,
Chenevert, and Young  (6),  and in their listed references.   The importance of
reducing  fluid  volumes  is  well  recognized  for  minimizing  the environmental
impact  of  a drilling operation.   Industry  response  to meeting the  no fluid
discharge regulations focused  on minimizing drilling  fluid discharge through
upgrading drilled  solids separation  equipment.   The  approach usually involved
increased use of equipment and emphasis on its proper installation.   Since the
equipment  was  to  eliminate  fluid  discharge  to  the  environment,   the  term
"closed-loop mud system" was established.

As practiced in the past,  closed-loop mud systems were not always effective in
minimizing  fluid  discharge  to  the  environment.   Fluid   ended  up in  the
environment because drilled solids  removal  equipment was not properly chosen,
operated,  or  capable  of   removing  enough  drilled  solids  created through
drilling.   Moreover,   water  used  by  other  wellsite   activities  and  water
influxes from nature also contributed to the fluid volumes with which industry
had  to  contend.  Lastly,  the role of fluid chemistry was seldom recognized in
achieving  a  successful closed-loop  mud  system.    For  these   reasons,  past
attempts at minimizing drilling waste were often of dubious success.  Opinions
on closed-loop mud systems varied widely.

Proper  design of  closed-loop  systems  for drilling waste  minimization should
address three factors:

i)   drilling  fluid  systems   should  be  designed  to   minimize drill  solids
     degradation,

ii)  drilled  solids removal  equipment should be properly  chosen and properly
     installed; and,

iii) water  contacting the  drilling operation from nature  and other  well site
     activities  (e.g. stormwater  runoff,  rig wash, drill-pipe handling, water
     lubrication  of pumps,  etc.)  should be  diverted  and or  minimized and
     reused.

Proper  drilling  fluid design can  minimize  the tendency of drilled  solids to
degrade to smaller particle sizes.  Large particle sizes, greater  than roughly
10-15 microns,  are relatively easy  to  remove from the  drilling fluid, using
only  mechanical   separation   equipment.    Smaller  solids  are   increasingly
difficult  to  remove.  (A  buildup  of  small  particle  sizes,  in the  colloidal
range,  usually  results  in  undesirable  drilling  fluid   properties.   This
condition normally results in an  increase of fluid waste.)
                                       1042

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In practice,  more  inhibitive  drilling fluids  can be  designed  over a  broad
range of  complexity -  dependent on the drilled  formations. Geologic  areas of
low formation  reactivity  may  only  require  drilling  fluid  enhancement  by
polyacrylamides.    Geologic  areas  with  a  greater  tendency  to  react  with
drilling  fluid  might require  inhibition enhancements  ranging from  addition of
more  polymers  and salts,   up   through  use  of  oil  base  drilling  fluids.
Alternatively.   mechanical   solids   separation   can  be   enhanced   through
centrifuge/flocculation technology  first  introduced to E&P operations  in 1982
(7).  The process  separates waterbase drilling fluid  into  its liquid and solid
components.

Performance and cost  analysis using the  proper  combination of drilling  fluid
inhibition  and  or  flocculation  technology,   or  other  solids   separation
technology, is  not amenable  to  intuition.   In  1988,  Lai  (8)  introduced  an
economics and solids separation performance  model which properly analyzed  the
economics and solids removal performance  required  to  achieve  a closed-loop  mud
system.  Several  important insights  on waste  minimization may be  drawn  from
Lai's work:

i)   the  closed-loop  condition  of  discarding "dry"  solids can  be meet with
     less  than  100X  drilled solids removal efficiency;   fluid  absorption  by
     cuttings,   drilling fluid  left behind  casing,  and  site  specific  fluid
     density increases  allow reduced removal efficiencies,  and,

 ii)  currently, the economics  of utilizing a closed-loop  system are justified
     when  the  combination  of  drilling  fluid,  drilling  fluid  dilution,  and
     fluid disposal costs  exceed roughly  $6-10  per barrel. (Pit construction
     and  reclamation costs included in  disposal  costs.)

 Figure  #5  shows  the  typical  decrease  in  overall  costs  associated with
 minimizing drilling fluid waste,  as predicted by the  model.   Figure #6  shows a
 case  where  very  low  drilling  fluid  dilution and  disposal   costs  do  not
 economically justify additional  solids  removal equipment.

 One  key  to  achieving  the closed-loop  condition  and a  "dry"  drilled  solids
 discharge  is proper selection of drilled solids removal equipment.   (The term
 "dry"  refers  to no free  liquid  on the drilled solids.   Figure  #7 shows  the
 limiting  condition,   ranging  from  about  48X-86X  weight  percent   solids,
 dependent on the solid's characteristics.)   Success at  achieving  a  closed-loop
 condition can not  be met without  proper equipment and system  design (9,  10).

 Optimum  drilled solids separation equipment  involves  use  of  linear  motion
 shale  shakers  which  maximize  fluid-screen  throughput   capacity  and  allow
 running  finer mesh screens for  a  given  flowrate.  (Shakers  used  for  precleaning
 or  scalping   to   remove   gumbo  do  not  require  linear  motion.)     Shaker
 performance  is discussed in  detail  by Hoberock and Lai  (11).

 Hydrocyclone use is discussed in detail by Young (12).  Proper  combinations of
 hydrocyclones  should  be  used,  with   emphasis   on   the  smaller  size  cones.
 Decanting centrifuges  should be used for  both  unweighted  and weighted drilling
 fluid  solids separation.   Installation methods  and  high  g-force  centrifuges
 should be used, as discussed by Thurber (13).  Lastly,  centrifuge/flocculation
 systems  have been commercialized by several  companies.    Comparative  process
                                      1043

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studies have not been conducted - perhaps suggesting  service and cost play a
major  role,  as opposed  to system  design.   A performance  comparison between
various  shale  shaker   capacity,   hydrocyclones  and  centrifuge   separation
performance is shown by Figures #8, #9 and #10.

The  last  important, aspect of  drilling fluid waste  minimization covers water
use management  on  a drill site.   Lack of proper water  management can negate
any waste  volume  reduction obtained  from closed-loop mud  systems.   Table #1
gives  the  magnitude  of some-water influxes.  Figure  #11 shows an inexpensive
practical  method  for  capturing  and  reusing the  water.   Ideally,   attention
should be made  to reducing or  eliminating the water sources by recycling pump
lubrication water or using mechanical pump  seals,  by using high pressure-low
volume water hoses, by designing drill sites  to  divert runoff, and by reducing
the areal extent of pits.

Drilling Fluid Waste Minimization  - Toxicity  Reduction

Data   from  EPA's  report  and  from  API's   E&P  waste  study  support  EPA's
determination  (14)  that  drilling  wastes  are typically RCRA nonhazardous.  Both
EPA  and  API did show  data where  several reserve pits  contained TC  hazardous
components.   Chromium,  lead,   and  pentachlorophenol were  the  more  common
components. The components can generally be  further  reduced or eliminated by
product  substitution.  Table #2, prepared by Kemp (15), lists several examples
of  generic drilling  fluid chemical  additives typically available  to the E&P
industry  that  contain compounds  of  potential toxicity  concern  as  defined by
RCRA.  Toxicity reduction steps may  be  taken by not  using additives with an
"E"  designation.  (Additives with  other potential RCRA characteristics such as
ignitability,  corrosivity, and reactivity are covered under other regulations
and  normally  lose  the characteristic when  introduced  to the drilling fluid.)
Polymer  additives  such  as polyacrylamides  are  suggested  as  replacement for
fluid  thinning  additives which contain chromium.

The  importance  of  reducing  or   eliminating RCRA hazardous  components  is
underscored by the  concentration  of  components  that  occurs  as  fluid volumes
are  reduced by  closed-loop mud systems and proper water management.

Substantial progress in drilling  fluid  toxicity reduction  has  been shown by
Bray   (16)  in  Gulf  of Mexico  operations.    EPA  Region  VI  requires bioassay
testing  of drilling fluids,  prior  to discharge, and a  LC50  of  30,000 ppm or
greater.   Careful  screening  and product  substitution  by Bray has resulted in
fluid  LC50's that commonly approach 1,000,000 ppm.  Figure #12 shows  a typical
additive  screening,  while Fig.  #13  and  Fig.   #14  show overall  progress  in
reducing  fluid  toxicity.

As  a  final comment  on  toxicity, care  should  be  taken when  evaluating the
site-specific use of oil base  drilling fluids.   Oil base fluids have a greater
per  unit  toxicity  than waterbase  drilling  fluids.   However, from a pollution
prevention viewpoint,   oil  base  drilling  fluids  have   several   important
advantages.   Formation/fluid  interactions  are  minimized  which in turn can
reduce wellbore washout on  the order of 201 or more.   Less washout reduces
both  the  volume  of  drill cuttings  brought  to  the  surface  and reduces the
volume of  drilling  fluid required to drill the  hole.  Reduced  formation/fluid
interaction maximizes drilled solids  separation efficiency because  solids do
                                        1044

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not readily degrade to particle sizes which are difficult  to  remove.   Drilling
fluid  dilution requirements  are  minimized.  The high  cost of oil  base fluids
encourages  good housekeeping which  in turn minimizes spills. Lastly,  oil base
fluids have good stability,  which when coupled with their high  cost,  greatly
encourages  recycle and reuse.  Peripheral benefits are obtained  when  oil base
fluids contribute  to increased  drilling  performance.   In  general,  the  more
quickly a well is drilled, the less the environmental  impact.

Associated  Waste Minimization

Associated   wastes  are   created   from  oil  and  gas  production  processes.
Operation  economics   strive  for   maximum  petroleum  production  and   the
minimization of  petroleum in any waste  stream.   Wastes in  this category  are
described  in  the  API Environmental  Guidance Document  (17),  in addition  to
those E&P wastes that are not included under the RCRA exclusion.  API  reported
that  approximately 6 million barrels  of associated  wastes were  created  in
1985,   not  including  workover  and  completion  fluids.  The wastes  tend to  be
generated  infrequently   through   a  wide  variety  of  processes.    Chemical
constituents  in  the  waste  streams  tend  to mimic  those in  the petroleum  and
produced water, though often at higher concentrations.

Cooling  tower water  is  the largest  associated  waste stream.  Waste   toxicity
reduction can be achieved by substituting  chromate corrosion  inhibitors and or
pentachlorophenol  biocides  with  less  hazardous  and toxic products.    Usually
organic  phosphonates   and   or  bisulfites  can   be  successfully  used   for
controlling   corrosion;    and,    isothiazolin,    carbamates,   amines,    and
gluteraldehydes used as substitute biocides.

Tank  and vessel sludges  and emulsions can be  reduced by increasing  the  oil
recovery from these  wastes.  Decanting   centrifuges  -  either  two  or  three
phase,  belt  or  filter  presses,   and  thermal  processes have  given documented
success  in minimizing the amount  of waste disposed.   Here, oil is  recycled to
the crude oil pipe line.

The last major associated waste category  is spill cleanup, typically involving
produced water and petroleum spills.   The key is in prevention and awareness.
Fewer spills  means  less contaminated soil  and  groundwater,  which  in turn
reduces  waste  disposal,  remediation,  and  future  offsite  liability costs.
Attention  to  seemingly  insignificant   drips  results  in   the  recovery   of
substantial  fluid volumes,   over time.   Extra operational  awareness  reduces
spills.

Summary

Waste minimization concepts can be successfully adapted  to the  E&P industry,
 though  concepts   need   to   recognize  the  extractive  nature   of  petroleum
production  operations.    In  general   though,  waste  minimization  makes  good
business sense  because both  short and long  term waste management costs  are
reduced.  Long  term  casts arise  from cleanup of past onsite and  offsite  waste
disposal, and pose the  greatest economic  liability to a company.

The E&P  industry has  high volume,  low toxicity waste streams  as pointed out by
EPA,  however,  improvements in  reducing  waste  volumes and toxicity  may  be
                                        1045

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reasonably accomplished.  Such improvements are  necessary  to prevent not only
E&P  pollution,   but  to minimize   the   introduction  of  hazardous  or  toxic
compounds to the environment, either as  a  result of the manufacturing process
or as a result of subsequent product mismanagement.

Product substitution can play  a  significant role  in  reducing produced water,
drilling fluid,  and associated waste stream hazardous components.  Closed-loop
mud systems and  waste  water management have potential  to  economically reduce
drilling waste streams  by  over half, when properly implemented.  Limitations
to achieving  further  waste minimization practices are hampered by reservoir
mechanics,  lack  of control over petroleum  quality  and  location,  and  bound
fluid constraints on various solid waste streams.

Support  from  top  management  is  the  first  step  in  initiating  a  waste
minimization program.   The second important step involves a complete inventory
and characterization of waste  streams  and chemical additives used in  the  E&P
operation.  Subsequent  waste minimization  steps  and processes  are given  by
ENSR (18) .
                                   TABLE 1

              Common Sources of Water Discharge to Reserve Pits

Source	Average Discharge (bbl/day)

10" Rainfall in 200' x 200' area                            6000
Location run-off/near surface aquifers                      0-4000
Water Hoses                                                 0-250
Jetting Mud Pits                                            0-300
Pump Rod Lubrication                                        0-200
Desanders or Desilters                                      150-700
Shaker Overs                                                0-50
Centrifuge Solids Slide                                     20-100
Water Lubrication of Centrifugal Pump                       10-50


                                  TABLE 2

Generic Additive	Potential Toxicity Characteristic

Sulfomethylated Tannin/Dichromate                      metals
Melanin polymer derivative                             metals
Lignosulfonate/lignite blend                           metals
Chrome lignosulfonate                                  metals
Lignite                                                metals
Chrome tannin compound                                 metals
Lignite-sodium dichromate mixture                      metals
Sulfomethylated tannin-sodium dichromate               metals
Ferrochrome lignosulfonate                             metals
Sodium Dichromate/Chromate                             metals
Leonardite                                             metals
                                       1046

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References

1.   G.F.   Vajda   and  J.C.   Stouch,    "An   Integrated   Approach  to   Waste
     Minimization",  , presented  at  83rd  annual  meeting   of  Air  and  Waste
     Management Association, Pittsburgh, Pa., June 24-29,  1990.

2.   API  (1987),  "Oil  and  Gas Industry  Exploration  and  Production  Wastes",
     Document No. 471-01-09, July 1987.

3.   J.W.   Amyx,   D.M.  Bass,  R.L.  Whiting,  Petroleum  Reservoir  Engineering,
     McGraw-Hill  Book Co. 1960, pg. 36-174.

4.   L.P.   Dake,   Fundamentals  of Reservoir  Engineering,  Elsevier  Scientific
     Publishing Co. 1978, pg. 29-32, 94-139, and 303-333.

5.   S.D.  Joshi,  "Augmentation of Well Productivity Using  Slant  and  Horizontal
     Wells",   paper  SPE   15375,   presented   at  the  1986  Annual  Technical
     Conference,  New  Orleans, October 5-8.

 6.   A.T.  Bourgoyne Jr.,  K.K. Millheim,  M.E.  Chenevert,  and  F.S. Young Jr.,
     Applied  Drilling  Engineering,  SPE  Textbook Series,  Vol.  2,  Society of
     Petroleum Engineers, 1986, pg. 42-75.

 7.   Amoco Production Company patent  disclosure  July,  1981,  field  trials in
     1982,  Evanston,  Wyoming.

 8.   M.  Lai,   "Economics  and  Performance Analysis Model for Solids  Control",
     presented at the 1988  SPE conference,  Houston,  Tx. Oct. 2-5, 1988, paper
     18037.

 9.   G.S.  Ormsby, G.A.  Young, IADC Mud  Circulation  Subcommittee - Mud System
     Arrangements Handbook  2, Gulf Publishing Company,  1983.

 10.  M.  Lai  and N.E.  Thurber,  "Drilling Wastes  Management  and Closed-Loop
     Systems",   Drilling   Wastes,   Elsevier   Applied  Science,  pg.    213-228,
     proceedings  of  the  1988  international conference on  drilling   wastes,
     Calagary. Canada,  April  5-8.

 11.  M.    Lai,   L.L.   Hoberock,    "Solids   Conveyance   Dynamics   and  Shaker
     Performance",  SPE 14389 paper presented at  the 1985  SPE conference, Las
     Vegas,  Nevada, Sept.  22-25, 1985.

 12.  G.A.  Young,  "An Experimental  Investigation of the  Performance  of  a  3-in.
     Hydrocyclone",  SPE/IADC  paper  16175  presented  at   the  1987  SPE/IADC
     Drilling Conference, New Orleans, Louisiana, March 15-18, 1987.

 13.  N.E.  Thurber,   "Decanting  Centrifuge  Performance  Study",  M.S.  Petroleum
      Engineering Thesis,  University  of Tulsa, April  1988.
                                        1047

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14.   US  EPA  (1987),   "Interim   Report  on  Wastes   From  the  Exploration,
     Development,   Production  of  Crude  Oil,  Natural  Gas,  and  Geothermal
     Energy".

15.   N.P.  Kemp,  Amoco Production Company memorandum attachment, May, 1990.

16.   R.P.  Bray,  "Protecting the Environment Through Aggressive Drilling Fluids
     Management  in the Gulf of Mexico",  presented at the IADC/AADE Symposium,
     Hyatt Regency,  Houston,  Texas,  September 1989.

17.   API (1989),  API Environmental Guidance Document, Document No. 811-10850,
     pg. 15-18,  January 1989.

18.   ENSR (1989),  "Waste Minimization:  Manufacturers' Strategies for Success",
     prepared for  National Association of Manufacturers
                                       1048

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                Waste Groups
        1987 API  E&P Waste Study
   Percent
100
 76
 60
 26
                                      API Data
     Produced Water
    Drilling

   Figure #1
                                   Allocated
             Associated Wastes
         Six Largest Waste Streams
80
60
40
20
  Percent
                                       Cooling
                                       Water
   Workover
            Waste
            Fluids
 Oily
Debris   Sand

          I API 1987 Survey   && Amoco Inhouie Survey

                    Figure #3
                                         Produced Water Disposal Methods
                                      Percent
                                                      100
                                                       50
                                                                                            API Data
                                                           EOR Operations     SWD Wells     NPDES Permit
                                                                            Figure #2
                                     Oil Price vs. Produced Water Production
                                                      40
                                                      30
                                                      20
                                                       10
                                      Oil Price ($/bbl)
                                                                       (Example Graph)
                                              10       16        20        25
                                                Water Production (bbls/bbl oil)
                                                         Figure #4
                                                                                                    30

-------
     Solids Removal Economic Analysis
       Normal Dilution/Disposal Costs
100
   Total Percent Coal
                                      (Lai. 1988)
               20       40       60       80
             Solids Removal Efficiency (%)
  *
  •al Dilution Coats  ^^ Disposal Costs  I  I Equipment Costs

                      Figure #5


  Various Solids  Dryness  versus G-Force
100


 80


 80


 40


 20


  0
   Weight Percent Solids
                                    (Thurber. 1988)
          600      1000      1SOO
                      G-force

                 ~~ Bsrite  ~t~ Silics

                     Figure #7
                                    2000
                                             2600
     Solids Removal Economic Analysis
         Low Dilution/Disposal Costs
                                                        120

                                                        100

                                                        80

                                                        80

                                                        40

                                                        20

                                                         0
                                                          Total Percent Coat
                                      (Lai. 1988)
       0        20       40        80
             Solids Removal Efficiency (%)

   Hal Dilution Coats  ^^ Disposal Costs   I  I Equipment Costs

                      Figure #6


    Processing Rate versus  Screen Mesh
             Water/Polymer  Fluid
1200

1000

 800

 800

 400

 200
   Flowrste (gpm)
                                      
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   Hydrocyclone Separation  Performance
   Separation Efficiency (%)
1001	
 80
 eo
 40
 20
                                      (Young. 1987)
                            (SO gpm per con* llowrate)
             20         40         60
           Underflow Weight Percent Solids
          ~~ Typical 4' Cone  ~*~ Optimum 3" Cone

                     Figure #9
                                              80
 Centrifuge Solids Separation Performance
100

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   Separation Efficiency (%)
                                                                                             (Thurber. 1988)
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                     Figure
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               Toxicity  Database
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                                       (Bray. 1989;
                   Mud Lubricants
                      Figure #12

-------
                        Drilling Fluid  Bioassay Test Results
                               Gulf of  Mexico, 1988
                                                      (Bray, 1989/
  Drilling Fluid Bioassay Test Results
         Gulf  of Mexico, 1989
                       LC60 (ppm)
                 1000000
                 600000
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-------
WASTE MANAGEMENT GUIDELINES FOR THE CANADIAN PETROLEUM INDUSTRY
Paul D. Wotherspoon
President
Paul Wotherspoon & Associates inc.
Calgary, Alberta,  Canada

Gary A. Webster, James J.  Swiss
Senior Coordinators; Health,  Safety and  Environment
Canadian Petroleum Association
Calgary, Alberta,  Canada
 Abstract
 In 1988, the Canadian  Petroleum Association (CPA)  initiated studies to provide  its member
 companies with management information on 88 types of wastes associated with the  production
 and processing of oil and gas in Canada.   The  long term intent  of  these  studies was to
 formulate  "Waste Management Guidelines" for use by member companies within their field
 operations.  The studies compiled information from CPA member companies on waste sources,
 volumes, chemical characterizations, data reliability, present  disposal practices  and hazard
 classifications as well as associated studies in Canada and the  United States.
 For waste types where  management and disposal requirements were not clearly identified by
 Alberta government  regulations  and/or  acceptable  treatment/disposal  options were  not
 available,  a cooperative industry/government workshop was held to establish these parameters.

 The final step in the CPA's waste management objectives will be the  production in 1990 of the
 "Waste  Management  Guidelines  and  Resource  Information  Handbook"  to promote  the
 environmentally acceptable practices.  The handbook's main component is a  "Waste Information
 Guideline"  for each of  the 88 identified wastes.
 I nt r ndu r t i nn

 The  Canadian  Petroleum  Association  (CPA)  represents medium to  large oil and
 gas  exploration,  production  and pipeline  companies  operating in Canada.  Its
 members are the industry's major employers,  and their combined staff represent
 a  majority of the people  who work in  the  upstream  sectors of the industry  in
 the  Canadian  provinces  of Alberta,  British Columbia and  Saskatchewan.  CPA
 members produce 80 percent of Canada's oil and  70 percent of  its natural gas.
 virtually  all  of that  production  is  shipped  to  market  through  pipelines
 operated  by CPA member  companies.   In  cooperation  with government  and other
 regulatory  agencies,  the  CPA commissions  research and helps   set  operating
 guidelines for the Canadian petroleum  industry.

 Some  of  the  early oil  field waste  management practices  which were  fairly
 common to the industry  in the 1960's and 70's were the use  of  both private and
 public landfills, the  flaring  of  waste hydrocarbons,  and  the  active use  of
 deep  well injection for  the  disposal  of a variety  of industry  produced waste
 liquids.   Ten years ago,  the industry found  itself moving into  a new era  of
                                     1053

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waste management; and in  1981,  the  CPA produced "Waste Management Guidelines
for Oil  Industry Operations".   These original  guidelines covered  16  waste
types.

During the intervening years, government  regulations,  corporate policies and
increased  public  concern and  'awareness  of waste management  forced  many
companies  to  examine their  policies.   In  1988,  recognizing the  expanding
operational and waste management problems  facing the  petroleum industry,  the
CPA's Environmental  Planning and  Management Committee established a  Waste
Management Sub-Committee.  The  Sub-Committee's  mandate was to develop  a CPA
position on the  practicality and suitability of traditional  waste  disposal
methods  with  an  ultimate  objective  to  produce revised  waste management
guidelines for field operations.  The CPA encourages its members to  take full
responsibility for the waste that they produce  and  to  ensure  that all  wastes
are properly disposed.

A five phase  approach was developed to address  the sub-committee's  mandate.
The first  three  phases  were  progressive  investigations  into  the present
disposal methods used in  the industry.   The fourth was a  consultative  phase
involving all major government  agencies.   The final fifth phase will be  the
production of  the actual  guidelines.
Phaae I  (September 1988)

The objectives of Phase I were  to determine:
      • what wastes were produced,
      • where they were produced,
      • how they are disposed,  and
      • to document  any related problems  with  the current waste  management
        methods.

An industry survey (l)  solicited information on the identification of  88  types
of waste  generated  by the industry,  and their  sources.   The  most common
disposal  methods  and  associated  problems  were  also  identified  by the
respondents.   Table  l  illustrates  the  wastes  in List A for which  CPA member
companies were asked to identify the Current Disposal Method,  List B.

The survey was sent to 63  CPA member companies who have active operations  (47
producers and 16  pipeline/marketers).   The survey response  represented 48% of
the  CPA membership  or approximately  65% of  Canadian petroleum resource
production.
An example of the study results is  shown in Table 2 for the waste  "Acid".  The
table indicates:
      • the waste source   given as the %  occurence that the waste originates
        from each type of facility;
      • the existing  disposal  methods    the  %  by volume  that the waste is
        disposed for each  method    these  results do not necessarily  reflect
        practices recommended by the CPA.
                                1054

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                                Phase  I
                                 List A
        Waste Inventory
                                            Liet B
Acid
Acitivated Carbon
Batteries
Boiler Slowdown Water
Catalyst   Non-Sulphur
Catalyst   Sulphur
Caustic
Construction & Demolition Material
Containers   Drums Barrels  (Used)
Containers   Pesticide
Contaminated. Debris & Soil    Oil
Contain. D & Soil   Mercury
Contam. D & Soil   Cond./Solvent
Contam. D St Soil   Produced  Water
Contain. D & Soil   Res.  Herbicide
Contam. D & Soil   Sulphur
Cooling Tower Wood
 Crude Oil Sample  Bottle  Liquids
Deseicant
Drip Scrubber Liquids
 Filter Backwash Liq   DEA
 Filter Backwash Liq   MEA
 Filter Backwash Liq   Water  Soft.
 Filter Backwash Liq   Water  Treat.
 Filters   DEA Amine
 Filters   DIPA Amine
 Filters   Glycol
 Filters   Lube Oil  (Hydrocarbon)
 Filters   Lube Oil  (Synthetic)
 Filters   Other  (raw gas/fuel/air)
 Filters   Process Water
 Filters   Produced Water
 Filters   Raw Water
 Filters   Sulfinol
 Filters   Water Injection
 Filters _ MEA Amine
 Garbage   Domestic Waste
 H2S Sensing Tape
 Hydro Teat Fluids  Methanol
 Incinerator / Burn Barrel Ash
 Insulation / Asbestos
 Ion Exchange Resin   Demin. Systems
 Ion Exchange Resin   H  & OH
 Ion Exchange Resin   Na  Cycle
Iron Sponge
Lab Chemicals   Inorganic
Lab Chemicals   Organic
Lubricating Oil   Hydrocarbon
Lubricating Oil   Synthetic
Mole Sieve
PCB   Contaminated Liquids
PCS   Contaminated Solids
Pigging Waste Liquids/Wax
Process Waste waters
Produced Sand
Produced Water
Rags -Oily
Scrap Metal
Sludge   Amine System
Sludge   Classifier / Separator
Sludge   Closed Water Drain tank
Sludge   Cooling Tower
Sludge   Crude Oil Slop Tank
Sludge   Crude Oil Stock Tank
Sludge   DEA Amine System
Sludge   Digester
Sludge   Filter Backwash Pond
Sludge   Flare Knockout
Sludge   Flare Pit
Sludge   Fractionator Bottom
Sludge   Gas Sweetening, Sulfinol
Sludge   Glycol System, Gas Drying
Sludge   Inlet Separator
Sludge   Lime
Sludge   MEA Amine System
Sludge   Neutralization
Sludge   Open Water Drain Tank
Sludge   Process Pond
Sludge   Sulphur Block Runoff Pond
Sludge   Treater Bottom
Sludge   Utility Boiler
Sludge   Water Treatment
Treater Hay
Wash Fluids   Solvent
Wash Fluids   Water
Well Workover Fluid   Acid Water
Well Workover Fluids   HC
Well Workover Fluids   Prod. Water
 Burn  Barrel
 Incinerator
 Open  Pit  Burning
 Company Downhole
 Contract  Downhole
 Company Landfill
 Other Landfill
 Ecology Pit
 Other Pits
 Pond
 Sewage  Lagoon/Field
 On Site Storage
 On Site Recycle
 Licensed Reclaimer
 Licensed Recycler
 Returned to Supplier
 Other Disp. Company
 Land Farm
 On Site Land Treat.
 Road Application
 Irrigation
Watershed Drainage
 Hazard.  Waste Plant
                                         1055

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Phase  I    Waste Inventory.
        Table 2
Example of results received for waste  "Acid".
                                      WASTE SOURCB
                                      (% Occurance)
                             30.0%    Gas Processing Plants
                              7 .0%    Gas Compressor Stations
                              7.0%    NGL Straddle Plants
                             16.0%    Oil Sande /  Heavy Oil Production
                             29.0%    Conventional Crude Oil Production
                             11.0%    Pipeline Transmission Facilities

                              BXZSTXNO DISPOSAL HSTRODS
       A. Total Survey

       19 survey respondere have this waste.
       Reported Disposal Methods
           27.8%  Company Deep Well Disposal
           19.8%  Contract Deep Well Dispoal
           13.1%  Other Disposal Company
           11.0%  Pond
            9.5%  Other Landfill
            6.4%  On Site Recycle
            6 .3%  Returned to Supplier
            4.7%  Licensed Reclaimer/Recycler
            1.0%  Company Landfill
              .2%  Open Pit Burning
              .2%  Other Pita
               B. Major Companies

               7 of the 10 Major Companies have this
               waste.   They represent approximately 39% of
               resource production.

               Reported Disposal Methods
                    42.9%   Company Deep Well Disposal
                    26.0%   Contract Deep Well Disposal
                    12.5%   On Site Recycle
                     8.1%   Licensed Reclaimer/Recycler
                     6.3%   Pond
                     4 .1%   Returned to Supplier
Phase  IT  (March 1989)

This phase represented the  first industry wide effort  to estimate and document
the  volume  of  various wastes  produced  by  the  upstream Canadian  petroleum
industry (2).  The CPA membership was again canvassed  to determine the present
inventory and the  rate of  production for the  88 waste types.    In  addition,
existing  analytical   data   was   compiled  that   included   an   initial
characterization of 'the  wastes.   An example of  the study results is shown  in
Table  3  for the  waste "Boiler  Slowdown water".  Hazardous ratings are based  on
Alberta  government  standards.
                                     1056

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                                          Table 3
Phase  II    Waste Inventory.   Example  of results received  for waste  "Boiler
Slowdown Water".
  WASTE NAME:       Boiler Slowdown Water

  WASTE SOURCE:     This waste includes blowdown from utility boilers,  heat recovery boilere
                     and sulphur boilers.  It is found predominantly in  gae plants and heavy
                     oil stream injection operations.  It is estimated that 83 gas plants
                     have this waste..


  WASTE VOLUME DATA:

                            PRODUCTION ESTIMATE  (M3/YEAR)
                     Qas Processing:              631,500.0
                     Crude Oil Production:              0.0
                     Pipeline Transmission:             0.0
                     Heavy Oil Production:          5,000.0
                     Gas Compression:            	0.0
                                       Total:     636,500.0

  Notes:       Volume estimates are based on responses from 4 gas plants and 5
              companies representing approximately 18.8% of total resource production.


  CHEMICAL  CHARACTERISTICS:
  Significant Components and Ranges:
       Waste composition will  be specific to the type of  boiler water treatment
       process.
              TDS: 1500 to 3000 mg/1 ;
              PO^: 5 to 50 mg/1;
              pH: 10 to 11;
              SO3: 20 to 60 mg/1.
  Classification:
       Hazardous:
       Non-Hazardous:  X
  Notes:       Chemicals added to the treatment process (corrosion inhibitors)  could make this
              waste hazardous.


  ENVIRONMENTAL CONCERNS:
       High pH waste, may result in organics leaching from waste water pond sludges.


  DISPOSAL  GUIDELINES:
  Present Disposal Methods:
       Evaporation ponds,  Deep well disposal
  Preferred Future Disposal Methods:
       Evaporation ponds,  Deep well disposal
  Industry Comments:
       Large volumes may make disposal  a problem for  the future.
  Ranking:
       Low:
       Medium:  X
       High:
                                         1057

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      III   (June  1989)
This phase provided a further investigation of- available characterization data
and a  refinement of volume estimates of  the 26 priority wastes identified in
Phase II  (Table  4) .
                                     Table 4
                            Phase III Priority Wastes
   DBA Amine
   MEA Amine
   DIPA Amine
   Glycol
   Lube Oil (Hydrocarbon)
   Lube Oil (Synthetic)
   Sulphinol
   Process Water
   Produced Water
   Raw Water
   Water Injection
Gas Sweetening
Sulphur Block Runoff Pond
Process Pond
Flare Knockout
Flare Pit
Treater Bottoms
Tank Bottoms
Neutralization
    Other
Produced Sand
Hydrocarbon Removal Wastes
Process Waste Water
Wash Fluids, Solvent
Wash Fluids, Water
Well Workover Acid Waters
Well Workover Hydrocarbons
The criteria  for  priority waste designation  included:
      •  a  significant volume of the waste is generated,
      •  there is  a potential for the waste to be hazardous,
      •  only  limited characterization  data was available,
      •  there was a  low confidence  level in  the classification procedure or
         in the analytical data used for  the classification procedure.

Phase III  also provided preliminary information regarding potential health and
safety  hazards associated with the  waste materials.   Analytical methodology
was reviewed  and  the data's reliability  was  indicated  (3).  Sample results are
extensive  and are therefore not represented  in this paper.

During  the completion  of the first  three phases,  current  disposal practices
employed by CPA members  were compared to practices used  in the United States
and Europe.   Procedures were  generally found to  be   equivalent.   Variations
were noted in some  areas where legislative/regulatory differences limited or
prohibited the use of certain disposal options.
                                   1058

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phase IV  (November 1989)

Following the completion of the  first  three phases,  it was necessary for the
CPA to more firmly establish,  in conjunction with regulatory bodies, specific
waste management   options.   For many  waste types,  management  and disposal
requirements are  clearly  identified by government regulation and facilities
are available in  the province of Alberta for the treatment  and disposal of
such wastes.   There  are,  however,  other waste  types for which government
regulations do not provide specified requirements and/or for which acceptable
treatment and disposal options are not  clearly  established.

TO address these  concerns, a  "round table" two day workshop was held between
CPA  members  and  senior  "decision making"  representatives from  the  Alberta
government departments and three waste  management associations.   The purpose
of  the  workshop was  simply  to provide agreement on disposal practices  for
certain wastes and to identify where further information was  required before
'suitable disposal  practices  could  be recommended.   A  strong commitment  was
made  to develop  effective  reuse  and  recycle strategies,  with  particular
emphasis on methods to reduce  and reclaim  waste materials.

At  the conclusion of the  workshop,  the government  departments agreed  to
provide more detailed guidelines  and procedures based on their regulations  for
the  CPA's  guidance (4).   In  addition,  there remained a  number of waste  types
for  which more comprehensive waste management procedures were  required  to
ensure  the  integration  of  the waste  types  into  a  comprehensive  waste
management plan.  Joint government/industry task forces were formed to address
the:
      • road application of oily wastes,
      •  incinerator technology for  the disposal of oil field wastes,
      • disposal  of used filters,
      • management requirements for  process sludges,
      • the  development  of  operational   criteria  for  off-site  commercial
        reclaiming and recycling facilities,  and
  and •  criteria  for  deep well waste disposal.

The task  forces  would  operate during  the  development  of  the  Guidelines
 (Phase  V)  and provide  periodic updates  and review during the  Guideline's
preparation.
                                  1059

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Phase V  (Completion September 1990)

The final step in the CPA's  waste  management objectives will be the production
of the  "Waste  Management  Guidelines and Resource  Information Handbook"which
promotes  environmentally  acceptable  waste  management  practices  for  the
upstream sector of the oil  industry.

      The  Guidelines purpose is  to assist  member  companies  in  the
      implementation  of effective waste management plans  within their
      operations.    Essentially,   the  guidelines  are  an  information
      resource from  which  individual companies can develop  their  own
      waste management guidelines  and corporate  strategies.

The Guidelines address three important concerns  of waste management:
      • Environmental  (practicing effective  waste  reduction, treatment  and
        disposal methods);                                                   »
      • Handling  (ensuring  that  adequate   employee  health  and   safety
        precautions are present);
      • Transportation (ensuring  that  public safety  and  transportation
        regulations are addressed).

Guideline topics include:
      • developing a corporate waste management  policy;
      • implementing  effective waste management principles  using  the  4Rs:
        Reduction, Reuse,  Recycle  and Recover;
      • methods   to  classify  a  waste   based  on  its  potential  hazardous
        component s;
      • a  discussion of the merits of  the various  treatment  and disposal
        methods;
      • requirements for effective waste  storage and transportation.

The main component of  the publication is a  "Waste  Information Guideline"  for
each of the 88 identified wastes.   These individual guidelines summarize  each
waste's:
      • source and description;
      • waste  management  options  based  on  reduction,   reuse,  recycling,
        recovery, pre-treatment requirements and, if  required, final disposal
        methods.
      • components and physical/chemical  data;
      * health, first aid,  fire,  explosion and reactivity data;
      • handling, storage,  transportation and  environmental considerations;

CPA  member companies  are  urged  to follow the format  and  content  of  the
Guidelines when they are designing their  own "Waste Management Guidebook".   In
many situations,  with minor  modifications,  the  CPA Guidelines may suffice as
the  company guidebook.   Some companies may  wish to  develop more  than  one
guidebook,  based on the geographical distribution and technical variations of
their operations.

The CPA Guidelines have been designed  as an  information  resource.  They are
not intended to replace the responsibilities that a waste generator  must  take
to ensure adequate and effective  treatment  and  disposal  methods within their
regulatory  obligations.   In  particular,  the Guidelines  do  not replace  the
requirement to perform laboratory  analytical procedures.  The  ultimate goal of
the CPA's  waste  Management Sub-Committee was to provide  the field  employee
                                 1060

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with correct  waste  management  information.    with the  production  of  the
Guidebook,  the CPA believes that  this goal has  been accomplished.
       Efforts
The development of  effective  waste  management  principles  is  continually
evolving as certain  treatment and disposal  methods become uneconomic  and/or
new^and revised policies and regulations are formulated.   However,  the  CPA
believes  that  the  cooperative  approach which  was taken  between  the  oil
industry and  government to develop  the Guidelines, will  be of considerable
significance   when  waste  management   procedures  require   revision   and
modification.

Further efforts are required to implement the conclusions of the task forces,
to standardize  sampling protocols, and to improve the consistency with which
waste management procedures  are  practiced across  the industry.

Information on the availability of the Guidelines and any other environmental
programs of the CPA  can  be  obtained  from the Canadian Petroleum Association,
Suite 3800, 150 6th Avenue S.w. ,  Calgary,  Alberta, Canada, T2P  3Y7 .   Phone
 (403)  269-6721.  Fax (403)  261-4622.
 References

 1.    P. Wotherspoon,  Industry Waste Survey,  Canadian Petroleum Association,
      Calgary,  1988.
 2.    P. Wotherspoon,  J.  Selann,  K.  Morrison,  Petroleum industry
      Manaijpment Study,  Phase II:  Inventory;  Classification, Canadian
      Petroleum Association,  Calgary,  1989.

 3.    P. Wotherspoon,  J.  Selann,  K.  Morrison,  Petroleum Industry Waste
      Manajempnt Study,  Phasp III:  Priority Wastp  Classification,
      Canadian Petroleum Association,  Calgary,  1989.

 4.    P. Wotherspoon,  J.  Selann,  Report  on the CPA / Alberta Environment/
      ERPR wagt-p Management workshop r  Canadian Petroleum Association, Calgary,
      1989.
                                  1061

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WASTE MANAGEMENT PRACTICES: THE ROLE OF UNIDO
W. Kamel
Chief
Section for Integrated Industrial Projects
Department of Industrial Operations
UNIDO
Vienna, Austria
 Before  beginning  I  would like  to  thank the  organizers of
 this  symposium for their hard work,  and to emphasize what a
 pleasure  it  is  for me  to  be here  today on behalf  of the
 United  Nations  Industrial Development  Organization.   The
 subject  of the  symposium  is  a very timely  one.   The rapid
 acceleration  of  depletion and  degradation of  the  earth's
 resources  makes  sustainable development without doubt one of
 the  greatest,  if not the greatest challenge of today.   The
 impact  of  the petroleum industry  and its  many derivative
 industries on the environment is enormous.    Both remedial
 and  preventive action  is required on many fronts:  tackling
 problems   of  oil  and  gas  waste management,  dealing  with
 hazardous  as  well as  non-hazardous  wastes,   conducting
 research  into  waste   characterization,   waste  disposal
 techniques,  assessment of risks  and  economic considerations.
 These and  many more.  And where  the  industrialized countries
 have  long  experience and practice, most developing countries
 do  not.    Indeed,  environmental  problems  often take  low
 priority   in  the  struggle  for  development.   However,  the
 economic  aspects  of  cleaner  industrialization  are  rapidly
 gaining  an audience.  More  efficient  energy utilization in
 industry,  and  attention to  conservation and proper waste
 generation,  handling and disposal, will lead to  considerable
 savings and an improved  economic  climate, not to  mention the
 positive  potential  impacts  on  long-term health costs and
 worker  safety.

 A number  of global initiatives have  recently been undertaken
 to   identify  and   enhance  awareness   of   the   urgent
 environmental  problems facing  humankind.  These  efforts have
 been  directed towards the alleviation  of  globally recognized
 major  environmental   hazards   which  know  no national
 boundaries,  such as depletion of the ozone layer and global
-warming,  acid  rain,  hazardous  waste  and the pollution of
                             1063

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coastal  and   inland  waters.    Even  problems   such  as
deforestation, which  may be  geographically confined  to  a
particular  region, can have far-reaching global  effects.

In developing  national and  international  strategies  and in
securing  government  commitment   on  major environmental
issues,  there  are a  few  important factors  I would  like to
bring to your attention.   First of all,  the greater part of
current  pollution   originates  in  developed  countries.
Secondly,  those  countries  bear a major  responsibility for
combating such pollution.   And thirdly,  international co-
operation  between developed  and  developing  countries  is
essential  to securing   and  transferring the   required
scientific   information  and  environmentally  sound
technologies.

As you may know,  UNIDO is one  of the specialized agencies of
the United Nations system.   Its objective is to promote the
accelerated industrial development of  developing  countries
and  it  runs   technical co-operation  programmes in about  a
hundred developing countries.   In  1989, UNIDO delivered  some
US$134  million  in   technical  co-operation and   promoted
industrial investments of about US$556 million.

Though  UNIDO  has been actively involved in technical co-
operation since  1966  in  various projects  related  to  energy
and  the  environment,  efforts  to  develop  an organizational
philosophy and a programme related to  environment  started
only  recently.    In  May  of this  year,  UNIDO's  Industrial
Development Board approved  a  document which contained the
elements of a comprehensive programme on  environment.   The
programme is  comprised of  four  subprogrammes,  of  which the
last  two  are  particularly .relevant  to  the  issues under
discussion during this  week's  symposium.   They are:  the
promotion of  clean,   low- or non-waste,  recycling  or  re-use
technologies;  and  provision   of  technical assistance  in
pollution abatement  through rehabilitation and/or  upgrading
of existing polluting industries.   These activities comprise
the heart  of  UNIDO's  work.

A programme  for  sustainable  industrial  development  should
place  as  much  emphasis  on  the  prevention of  industrial
pollution  as  on the  alleviation  of  its effects.    The
adoption of  environmentally  sound technological  processes
may  ultimately prove their economic  value as  a  result of
more efficient use of raw materials and resources.  Results
are  to  be  achieved  through creation  of  expanded  data and
information   banks   within  UNIDO   and   in  appropriate
institutions   in  developing  countries;    description  of
                            1064

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technologies;  .sources  of  supply;  and costs  and economic
performance, as  well  as assessment of environmental impact
when  compared  with other  technological  options.   Other
outputs will be  an  expanded roster of  experts and  data base
on  institutional  facilities,   advisory  services,  pre-
investment  studies  and assessment  of clean  technologies
within   the  industrial   structure   and   environment  of
developing countries.

As in the  case of energy,  greater benefit can sometimes be
derived from improvements in efficiency than  from  investment
in pollution  control.    UNIDO  supports  adoption  of clean,
low-waste  and  energy efficient  recycling  or  re-use
technologies  and methods  in  the  industrialization  of the
developing  countries.   It also  assists in the environmental
upgrading  and  rehabilitation  of  existing   industries,
especially  those  contributing most to  industrial pollution.
We not only promote applied research  on, and  development of,
clean  technologies,   but  we  also   undertake   on-site
demonstrations  and assessments of  the same.  All this  is
backed   up  by  our ever-extending  data  bases  and  the
preparation  of  guidelines   that  will   facilitate   the
incorporation  of  environmental considerations  in  the
development,  appraisal, implementation  and evaluation  of
industrial development  projects.

Addressing  issues  of  environment  calls for the formulation
of  policy  and  regulations that  combine  industry-specific
considerations  with broader national, social  and economic
concerns.   It  is in this context  that  UNIDO sees a role for
itself.   It can contribute to  promoting the sustainability
of  industrial  growth,  by striking a proper balance between
short-term  profitability and  the  need  for durable resource
and  environmental  conservation.   Within  the context  of
UNIDO1s  primary  mandate to  support the industrialization of
developing  countries,  we  also endeavour  to   mobilize
additional  financial  and  human  resources  so  as  to  help
developing  countries  identify,  analyze,  monitor,  manage or
prevent  industrial  environmental problems  in  accordance with
national development   plans,   priorities  and  objectives.
Since the environment  is  a  global resource, environmental
protection  lends itself to  international  co-operation in the
transfer  of knowledge,  science  and technology.   As the co-
ordinating  agency for  industrial  development in the United
Nations  system,  UNIDO  is  the  natural focal point for co-
operation  in  industry-related environmental matters. At the
same  time,  close ties  are  maintained with UNEP,  the United
Nations Environment Programme.
                             1065

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Among the  resources required  for industrial  development,
energy plays a  central  role.   This is demonstrated  by  the
close   structural   inter-relationship  between   energy
technological  processes  and  production  systems  in  all
industrialized  countries.   There  is an  ever  increasing
recognition that energy  economy and efficiency are essential
for further industrial  development.   However,  a  comparison
of the  present  status  of  energy management in  industrial
processes  discloses  substantial differences  between  the
developed and developing countries of the  world.

During the last ten years the energy  content of  the  GNP  in
most  industrialized  countries   decreased  by  around   20
percent.   Industrial  energy efficiency in most  developing
countries,  however,  continued  to be  much  lower  than  in
industrialized  countries and energy management efforts  are
still at an early stage.  Savings  ranging from zero  to  ten
percent  and  upwards may  be achieved  by the  turn  of  the
century.  This  would be  achieved  by the important,  on-going
restructuring of  the  overall industrial framework  towards
fewer energy-intensive and more  energy-efficient  industries
to reduce energy needs in their industrial sectors .

Many developing  countries  have  industrial  plants that  are
often  based  on  out-of-date —technologies  and  economic
parameters,  so  that energy intensity is  higher in  these
industries - 20   to  50 percent higher in terms of  energy  per
unit  of  output  -   than  in developed  countries.   Many
developing countries depend on  imported fuel,  mostly oil,
which in spite  of recent decrease  in prices,  still continues
to be a burden on the state budget and balance  of payments.
Where  energy  prices  are  subsidized,  it is  difficult  to
generate  internally  the  financial  resources  needed  for
energy  conservation investments.   Focussed  research  and
development programmes,  development  of technical  skills  and
improved  technology  transfer are  needed  to implement  and
disseminate  new ways   and  means  of  achieving   energy
conservation.  A  firm  institutional  base  is  required  to
conduct  promotional   campaigns  to  provide  technical
assistance and different advisory services.

One of the most interesting recycling  activities  in  the  oil
industry  is  the rerefining  of used lubricating oils  from
engines,  gears  and hydraulic   systems  of  all  kinds  of
vehicles and industrial  machinery.  Rerefining  of waste  oil
may include distillation, hydrotreating, and/or  treatments
employing  acid,  caustic,   solvents,   clay  and/or  other
chemicals.  The  value of a waste  oil after  treatment can be
as. either a high  Btu content clean  burning  fuel,  or a lube
                            1066

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base    stock   equal  to  a  highly  refined  virgin  oil.
Rerefining of these waste oils means considerable savings of
resources  and  energy,  as  well as  an alternative to  the
present polluting methods  of  waste  oil disposal.   Current
practices  include  indiscriminate   disposal   into   the
environment by  dumping into landfills, pouring  into  sewers
or  domestic drainage  systems  or  applying it to  roads  to
reduce dust problems.   The oil leaches into soil  and water
supplies,  releasing hazardous metals into the environment.
In  other  cases,  waste  oil is burned as fuel with  little  or
no  prior  treatment, which  results  in  the deterioration  of
boilers and release of  pollution  into  the  atmosphere,  since
such  oils contain  heavy metals,  chlorines,  flourines  and
other contaminants.

The following figures  on  commercial consumption of  liquid
fuels  should  give  you  an  indication of what's at  stake  in
developing  countries.  In  1986,  according to the  1988  Energy
Statistics  Yearbook, Brazil's  commercial consumption  was  45
million metric tons of  liquid fuel,  while  Indonesia's  was  24
million and Zimbabwe's  655,000  metric  tons. Many  developing
countries  rely  heavily  on  importation  of   these  fuels.
Obviously,  in  addition to the  environmental benefits  cited
above  of  recycling  the  waste  oil  generated   are  the
significant  foreign  exchange  savings possible  and the
reduction of dependency on foreign  imports.

UNIDO  has been  very active in promoting  the  recycling  of
waste  lubricating  oil.   Back in 1985  a  working paper was
prepared  which  outlined  the  rationale  and  detailed the
processes by which  waste lubricating oil could  be  collected,
rerefined,  blended  and  reused.  Since  that time,  of course,
processes  have  continually been upgraded.   Instead of the
acid and  clay treatment, for instance,  which  itself produced
considerable  quantities  of contaminants,  various methods
such  as  hydrofinishing  ensure  a  high  quality  product.
Although  there  are some  60  waste  oil  rerefining plants  in
operation  in   the  industrialized  countries,  rerefining
operations  have  not really  had  a  breakthrough  in  developing
countries  in  spite  of  the  urgent  economic  and  environmental
reasons.   Lubricating  oils show the highest value-added  of
all petroleum  products due to  the  sophisticated  technology
used for  their  production.   Only a  few developing countries
are currently in  possession  of lubricating oil  production
facilities  and  must rely therefore on  imports.   This  makes
the economic benefits  of  reclaiming  waste oil  even  more
attractive.   But  aside  from  the  hard  currency savings and
conservation  of   non-renewable   natural  resources,  the
environmental damage of waste  oil to soil, ground  water and
                            1067

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air  in  many  cities  of  the third  world,  as  well  as  the
subsequent  effects  on health, have become unacceptable.

UNIDO started to respond  to requests  for the establishment
of rerefining facilities in developing countries in the mid
1970s.   It  has already  carried  out a  number  of technical
assistance  projects in waste oil recycling,  for instance in
Togo, The  Seychelles  and  Burkina  Faso.  Most  recently,  a
pre-feasibility  study  carried  out  at  the  request  of  the
Government  of Thailand  showed  very  positively  the benefits
of locating  a waste  oil rerefinery in  the  Greater Bangkok
area.   A next phase is under preparation.  It will include
development   of  the  process   scheme  and   design  basis,
evaluation of processes,,  study  tours to operating  plants
employing  the processes proposed,  and the  negotiation of
licensing agreements.   Upon completion of this  phase,  it is
expected that a waste  oil  rerefinery  costing  upwards of
US$12 million will be  constructed.   It  will  produce  base
oil,   which  the major oil  companies operating  in  Thailand
have  agreed,  subject to  the final price and  quality,  to
purchase for  blending and  sale in the domestic Thai  market.

Another major activity  in the area of  waste  oil recycling
has a more  global aim.   Under this project,  approved earlier
this  year,   regional  workshops  will   be  held  in  each of
Africa,  Asia  and Latin  America.   Prior  to each workshop,  a
detailed evaluation  in the  form of  a  case study will be
prepared by UNIDO experts  for four countries in each region.
This  will   entail  ascertaining   the  primary  users  of
lubricating   oil   and  estimating  the  total  quality  and
quantity of  oil  consumption by  industrial,  government  and
commercial   users,  from   which  can  be  extrapolated  the
different collectible rates of waste oil  and identification
of the types  of impurities expected to be found which would
necessitate  specialized rerefining methods.    The present
methods  of  handling,  storing,  disposing and  recycling of
waste  lubricating  oil  will also  be  examined.     Present
methods used  for waste oil collection, if any,  will also be
determined and an  appropriate system to improve the present
one will be  designed.   Potential locations  for  rerefineries
will also be  suggested,  as well  as the  current  and  potential
markets  for  rerefined products.    Full  advantage will be
taken of the  experience gained in industrialized  countries
in these areas.

These data will  be analyzed for each  country  to  determine
overall  the  waste  oil  rerefining potential  and  envisaged
problems,  the technical  requirements and financial  viability
of   a   rerefining plant,  and  the  national  economic
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implications,  costs  and benefits  of creating  a national
capacity  to  rerefine   waste   oil.   The  results will   be
presented  and discussed at the  regional workshops.     In
addition,   recommendations  concerning the required economic
and legislative policy measures will be elaborated.   At each
workshop,  decision  makers  and  technical personnel from  the
regions will meet together with the UNIDO  experts  as  well as
representatives of interested companies, to  explore the best
ways  of transferring  this technology  to  the   developing
countries.

In  sum,  UNIDO continues to assist developing countries  in
selecting  the  best  technologies,  not only from an economic
but also from an environmental point of view.  In this  era
of  diminishing natural  resources  and mounting environmental
crisis,  we would do well  to  engage in  activities which
conserve and  maximize the impact  of  the inputs while at  the
same  time  ensuring  that any waste generated  is disposed of
in  an environmentally  sound  and  sustainable  way.   We  are
continuing  to promote  improvement  in  the  efficiency with
which fossil  fuels  are used,  both  directly and  in   the
generation of  secondary  energy.   Fossil  fuel  usage   is
accepted as being  irrevocably associated with atmospheric
pollution.   However,  energy demand  in developing  countries
doubled between  1971  and 1987  and will  continue to increase
rapidly.      UNIDO  will  continue  in  its  efforts  through
training, research and technical assistance.   Technology  and
production  are essential to development,  but  their negative
effects must  be  addressed as well if sustainable  industrial
development,  not to  mention  a  healthy planet,  are  to  be
achieved.
                              1069

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WASTE MANAGEMENT DECISION  MAKING PROCEDURE  AT PRUDHOE  BAY,
ALASKA
Michael J. Frampton
Environmental Coordinator
ARCO Alaska, Inc.
PRB 7
P.O.  Box 100360
Anchorage, Alaska 99510-0360, USA
 Introduction

 This  paper  is concerned with the application of existing and
 complex waste management  regulations and achieving compliance
 with  those  regulations  in an oil field.  It describes a case
 study in  environmental  compliance examining  one  regulatory
 compliance  technique currently  employed in the  largest oil
 field in  the  United  States .   This case  study describes the
 use  of  a  flowchart to provide a single and consistent point
 of  focus  for  providing  waste  management  guidelines  and
 disseminating waste management information throughout the oil
 field.

 Background

 Prudhoe  Bay  is  the  largest oil field in the  United States
 currently producing  approximately 1.5  million  barrels of oil
 per   day.   The field  is  divided  into two working areas and is
 operated by  two  companies, BP Exploration Alaska operates the
 Western  Operating  Area  (WOA)   and  ARCO  Alaska  Inc.   (AAI)
 operates  the Eas-tern  Operating Area  (EGA)  .   This  paper
 describes  a  waste management  tool currently  used by AAI in
 the EGA.

 The  EOA  encompasses  an  area in   excess of  175 square miles.
 Located within the  boundaries  of the  EOA are a large variety
 of  industrial facilities which  include;  four  oil production
 facilities,   central  gas  facility,  central  gas  compressor
 plant, sea  water treatment  plant, sea  water injection plant,
 waste water  treatment plant, crude oil  topping unit,   24 drill
 sites,  maintenance  facilities,   and work force  support and
 living  quarters .v   The  size of  the  work force  in the field
 regularly ranges between  1,500 and 2,000  individuals  composed
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of AAI personnel,  service company personnel,  and construction
contractors.   With  shift schedules  and  24  hour staffing in
all  facilities the effective  work  force  size  can approach
5,000.    This  combination  of  facilities  and  personnel
represents  a  complex industrial city  with a significant
potential  for waste  generation.   This  industrial  city is
situated in an arctic wetlands  which provides summer habitat
to  numerous  wildlife  species.  Additionally,   the  field is
isolated  from conventional  waste management  facilities by
hundreds to thousands  of  miles.

Compliance Challenge

The  industrial   output   of  Prudhoe  Bay  along  with  its
associated  and varied wastes  places these  activities  under
the  jurisdiction of  many  federal  and 'state  regulatory
programs.   The  most significant from  a  waste  management
perspective are  the  Resource  Conservation and  Recovery Act
 (RCRA),  Safe Drinking Water  Act-Underground injection Control
 (UIC),  and  the Clean  Water  Act-National  Pollutant Discharge
Elimination System  (NPDES).   There  are  over  8,500  pages of
coded federal environmental  regulations in CFR 40.  These are
supported by  the  daily  publication  of the  Federal  Register
and  other  numerous guidance  documents.   Within  RCRA  alone
there  are  17 steps  required in  the   determination  .of  a
hazardous waste.   Additionally,  state  and  local regulations
and  permits  set  many   site   specific   requirements.    The
challenge lies in how do  you simplify complex and overlapping
regulatory requirements encompassed by these acts and permits
and disseminate them  to a large,  diverse  and often transitory
work  force.   Large  segments of  the  work  force  may  be
unfamiliar  with facilities  in  Prudhoe  Bay  and general  waste
management options in  the  State of Alaska.

Compliance Tool

To  address the  compliance  challenge a simplification  of
complex  regulations,  and a  central  focal point  was  deemed
necessary.   A  "Prudhoe Bay Specific" flowchart  was developed
to  synthesize  and coalesce  the  waste  management regulatory
requirements and viable  recycle, reuse and disposal options.
The  Prudhoe  Bay  specific  aspect  of  this  flowchart  is
significant.   Presently  there already exists  many decision
matrices  and  flowcharts  for  regulatory  interpretations.
Several  of  these are   contained  within  the  regulations
themselves while  others  are  produced commercially.   Generic
aids are to complex  and  not  activity/site  specific.   These
generic  aids   assume  a   certain level  of  familiarity  with
regulatory  rationale  and  jargon  that  frequently  does not
exist on  a  widespread   basis  within  the  oil  field.    The
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Prudhoe  Bay  specific flowchart  simplifies  and  translates
regulatory  framework  into field  specific activities/sites
that the work force is more familiar  with.

The Waste  Management Options  Flowchart  currently in  use  is
shown in Fig. 1.  The flowchart is composed of four sections;
definitions,  decision  process,  management  options  and
examples.   The chart provides  a  framework that  assists the
user  to  properly  identify  their  material  and  to  select
appropriate  reuse,  recycle or waste  disposal options.   Each
section  was  designed to  be  read  from left  to  right.    A
discussion of the four sections  follows.

Definitions  - Federal and State solid waste  regulations are
definition  dependent.   Regulatory definitions are presented
along the top of  the  flowchart.    The  correct management  of
certain  wastes  is based  upon  the source of the material and
its  waste  classification.    The  management  option  for   a
material  may not  always  be the same  in every case  (see  case
illustrations  below).    Each  material must be evaluated
individually to ensure proper  handling.

Decision  Process  - The correct management  option  is  arrived
at by answering the  questions  posed  in the  decision  process.
This  process  is  composed of  six  basic   question  blocks,
labeled  Steps 1  through  6.   The question  for  each step  is
enclosed in  a horizontal rectangle.   All  questions  are
resolved with  a  'YES1  or  'NO'  response.   In all cases,   a
 'YES1  response  leads directly  to  the  management  solution
while  a 'NO'  response requires  additional decision process
steps.   Located directly above each step  you find  definitions
pertinent to the decision at hand.

Management  Options -  For  each  'YES1  response  in the  decision
process  you have at  least  one  management  option.   Approved
options  are  enclosed  in  vertical,  rounded-corner  rectangles.
Each  option has facility operational stipulations that  must
be met before the material can be received  and disposed of  at
that  location.    These   stipulations  are  listed  for  each
option.

Examples -  Included  along the bottom of  the flowchart are
four  lists of materials  frequently  encountered  in the  EOA.
The  first  two lists  contain materials that are suitable and
unsuitable  for  recycling.    The remaining  lists  provide
examples of exempt vs. non-exempt  wastes.

This  flowchart  is a  suggested  format.  The  actual  wastes and
management  options  available   in   individual  oil  field
applications  will vary,  but from our  experience the flowchart
                             1073

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                                                            Figure 1
                                            Waste Management Options Flowchart
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-------
is easily modified to accommodate  such  variations.   This  tool
has been in  use  for  over a year and has been modified on  two
occasions as.regulatory interpretations and waste management
facility  options  have  changed.    To  date  we  have   not
encountered  a waste  that did  not fit within  the flowchart
boundaries,  although I  am not  suggesting that  one  does  not
exist!

Examples

Included below are several  illustrations for use of the Waste
Management Options Flowchart.   For most users  in the EGA, if
they  advance  beyond  Step 3,  the are advised to contact Field
Environmental Compliance for assistance.

Case  #1  Methanol Spill  on snow during  well work operation at
         drillsite .   Cleaned up  material is  a mixture  of
         methanol and contaminated snow.

         Step 1  NO,  material is  not  a  petroleum hydrocarbon
                 and is  unsuitable  for  recycle  (see  examples
                 list) .
         Step 2  YES,  material can be  reused in freeze protect
                 operation.  Process stops here as material is
                 not  a waste reguiring disposal.

Case  #2  Methanol  Spill  on snow/gravel  during  well  work
         operation at- drillsite  (methanol  has  been down  hole
         in  well work application).  Cleaned up material  is a
         mixture of snow/gravel  contaminated with methanol.

         Step 1  NO,  material not a petroleum hydrocarbon and
                 is unsuitable for recycle.
         Step 2  NO,   material   is  contaminated  and   is
                 unsuitable  for  further reuse.   Material  is
                 now  defined as  a  waste.
         Step 3  YES,   material   is  an exempt  waste  (see
                 examples list),  if the material is melted it
                 goes to UIC  Injection  Facility,  if  material
                 is a solid it is  disposed of at the permitted
                 solid oily waste  pit.

Case  #3  Methanol Spill  on snow/gravel  at a storage  pad,  or
         while in  route  to a drillsite.  Cleaned up material
         is  a  mixture  of  snow/gravel  contaminated  with
         methanol.

         Step 1  NO,   spilled material  is  not  a  petroleum
                 hydrocarbon and is unsuitable for recycle.
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         Step 2  NO,  Material is  contaminated with  sand and
                gravel  and is unsuitable  for  further reuse.
                Material is now defined as a waste.
         Step 3  NO,  material  is not an exempt  waste because
                it  was  not used in exploration,  development,
                or  production activities.
         Step 4  YES, methanol is a listed hazardous waste and
                the spill  residue  is  a hazardous waste.   The
                waste must be transported to the RCRA storage
                facility.

Case #4 Crude Oil  spill on snow during well work operation at
         drillsite.   Cleaned  up material  is  a mixture  of
         crude oil and  snow.

         Step 1  YES,   material  is  a  hydrocarbon   and  is
                suitable for  recycle.   Process  stops here as
                material is not a waste requiring 'disposal.

Case #5 Crude Oil spill  on gravel  during  well  work operation
         at drillsite.    Cleaned up material is  a  mixture of
         gravel  contaminated with  crude oil.

         Step 1  NO,  material  is partly a hydrocarbon  but is
                unsuitable  for recycle due to contamination.
         Step 2  NO,  material is  contaminated  with  sand and
                gravel  and is^unsuitable for  further  reuse.
                Material is now defined as a waste.
         Step 3  YES,   material  is  an  exempt  waste  (see
                examples list),  if the  material  is melted it
                goes to  UIC Injection Facility,  if waste  is  a
                solid  it  is  disposed  of  at  the permitted
                solid oily waste pit.

Case #6 Jet  fuel  Spill  on  snow  while  refueling  AAI aircraft.
         Cleaned   up  material  is   a  mixture   of   snow
         contaminated with  fuel.

         Step 1  YES,   material  is  a  hydrocarbon   and  is
                suitable for  recycle.   Process  stops here as
                material is not a waste requiring disposal.

Case  #7  Jet  fuel   Spill   on  gravel  while  refueling  AAI
         aircraft.   Cleaned  up  material  is   a mixture  of
         gravel  contaminated with  fuel.

         Step 1  NO, material  contains hydrocarbons but due to
                solid nature  it is unsuitable for recycle.
         Step 2  NO,  Material is  contaminated with  sand and
                gravel  and is  unsuitable for  further reuse
                and is a waste.
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         Step  3  NO, waste is not exempt.
         Step  4  NO, waste is not a listed hazardous waste.
         Step  5  NO, waste  is  not  a mixture of a waste  and -a
                listed hazardous waste.
         Step  6  YES or  NO,  will depend  upon  the waste.   If
                material   is   liquid   then  there  is   a
                possibility that  the  material  could  fail
                hazardous   waste   characteristics,   if  the
                material is a solid  it  is unlikely that  it
                would  fail characteristics.   Contact Field
                Environmental Compliance.

Transferability  and Adaptability

When the  Waste  Management   Options  Flowchart  was  originally
designed it was intended for use in Prudhoe Bay.   Due to its
relatively  simple  layout  it  has  been  shown to  be highly
transferable  to  other oil  fields.    Another  major field in
Alaska has  recently begun  use  of  the flowchart.   The only
required  changes  involved  modifying  the management options
for those available at the  new  field.

Benefits

There are four significant  benefits that we have noted since
we  started using  the Waste  Management Options Flowchart.
These  include;  smoother  environmental  compliance,  waste
minimization,  reduction of  fugitive wastes, and  improved job
satisfaction.    Brief  discussions  of  these benefits  are
included below.

The  flowchart  allows  for consistency  in  dealing  with  a
variety of  wastes  and  is flexible  in determining  management
options.  One payoff from disseminating simplified  guidelines
on  waste  management procedures,  such as  that  described in
this paper,  is  smoother and less  time  consuming field wide
environmental compliance.   We have  found  that  awareness on
the  part  of the 'work force is a  key to assure compliance.
The  flowchart is a tool  to  promote  awareness.  Throughout the
EOA  flowcharts  have been laminated  and  stored  in vehicles,
and  posted  in  facility  control rooms and maintenance shops.
Even if an individual  does  not  understand all  of  steps in the
process,  the  flowchart  helps  to  make the  individual aware
that  waste management  requires  systematic  methodology and
analysis and different materials must  be managed  differently.

The  decision  making procedure  promotes reuse and  recycling.
Users of the flowchart are  first prompted to  consider whether
there is  a  recycle or reuse application for  their material.
A  'YES'  response  in  Step  1  or 2  results in  recycling or
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reuse.   In most  cases these  are the  preferred management
options because they  emphasize  waste minimization,  are cost
effective and  involve  the  least amount of support time.

Consistent application  of the decision  making  process also
helps eliminate 'fugitive  wastes'.  We  define  fugitive  wastes
as those that  have the affinity  to collect  in  back corners of
a warehouse  in use by  several  different  groups,  on  seldom
visited storage pads  or between  buildings.  When  these  wastes
are  'discovered'   very little  is known about  them  and  a
financially responsible  party is  hard to identify.   These
wastes  typically  require  extensive   fingerprinting  and
sampling   for  identification.     Wastes  typically  become
fugitive because generators are not  familiar  with management
options and the materials  are  left behind for someone 'more
knowledgeable'  to  deal  with.    We  have found that with
widespread distribution  of the  flowchart  these  types  of
wastes are less of a problem as the  work force is aware that
management options exist.   In addition, the chart also tells
the  user  who  to  contact  if they need more  information  or
help.   By putting the  phone  numbers or  locations  of local
environmental  support personnel  on the chart  the user  has an
even  greater  range  of  options.    If  they  are unable  to
determine  the  correct  management option  they   can  get  you
involved  early.    We  have found  that  early  involvement  of
compliance personnel  can dramatically cut time and costs when
determining   material  management   options.     With  early
involvement  pertinent  information  gets  recorded,  sample
analysis performed, and standardized  waste analysis plans are
instituted.

Over  the  past  year,   through  an internal audit  program,  we
have had the  opportunity to spend  candid  one on one time with
over  one  hundred members of  the  work  force  discussing
environmental  issues  such  as waste management.  One rewarding
message we received from these discussions was that a  better
level of  job  satisfaction was apparent  from  those  that  had
taken  the time  to  familiarize  themselves  with the  Waste
Management Options Flowchart.   These  individuals  felt that
they  worked  in less  of an information  void than  they  had
before and by  understanding the waste management strategies
used in the EOA they  felt  better  about our activities as an
industry.   They now have first hand knowledge  that wastes are
properly managed and there is  method to what  a times appears
to them to be  regulatory  double talk and counter intuitive.
The  over  all  effect  was  an  improved  self  worth,  job
satisfaction and pride  in the industry.
                            1078

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Methods of Digfribution

Currently  in  the  EGA  we  have  adopted  four  methods  of
distributing the  Waste Management Options Flowchart.   These
field  rollouts   include;   dedicated  sections  in  facility
environmental manuals, supervisor training sessions,  facility
safety  meetings  to the general work  force,  and  specially
arranged  training with  groups  having greater potential  for
waste  generation.   No one method of  distribution  has  proven
to be  adequate - rather a combination of these methods  has
achieved  the   best  effect .    Several  work  groups  have
distributed plastic laminated versions of the flowchart  and
the flowcharts are kept in  service and utility trucks.

Originally  we had hoped that  wide  distribution  of  the
flowchart with  directions  and  examples would  achieve  the
desired  results.   This proved not to be the case.   Although
we tried  to simplify  the chart,  it  still  was new  information
and  for  some  too  complex  to  be  used effectively.   This
prompted  our  current  multifaceted  approach of distributing
the  flowchart  in  combination with training  sessions  targeted
for  supervisors  and  groups  with a  large  waste  generation
potential.

Summary

To streamline  waste management decision making  procedures  and
enhance   environmental compliance  in  Prudhoe  Bay  a  field
specific  waste management options  flowchart  was designed.
After  over one year of use the  flowchart has proven to be a
useful  waste management  and compliance tool.   The  flowchart
includes  regulatory  definitions,   a   decision  process,
management  options, examples  and additional help  sources  for
more  in  depth  information.  Waste minimization is  emphasized
as  the user is  lead  through a  decision  process that  first
encourages  recycle  or  reuse  possibilities.  Several  benefits
have  been realized by distributing the flowchart  throughout
the  oil  field.  These benefits  include enhanced  compliance,
waste minimization,   reduction of  fugitive  wastes,   and
improved  self  and industry image.  The most  effective methods
of  distributing  the  flowchart  and  guidelines have been a
combination  of including it under its own section  in  facility
environmental  manuals  and  by providing training sessions to
supervisors  and  work  groups with a high potential for  waste
generation.   The  waste management options flowchart used in
the  EOA  of Prudhoe  Bay  has  been  successfully  adopted by
another  large Alaskan  oil field with  few  difficulties  and
modifications.  The tool described in this paper  has  enhanced
our  compliance efforts and  we would  encourage  you to try a
                            1079

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similar approach in  your  own waste management and  compliance
efforts.
                            1080

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WHO IS QUI TAM? / PRIVATIZING  ENVIRONMENTAL  ENFORCEMENT
Philip M. Hocker
President, Mineral Policy Center
Washington, D. C.r U.S.A.
INTRODUCTION;

The public's  strong  desire for stricter environmental protection
is  encountering  obstacles to  fulfillment  which  are  inherent  in
the nature of the  issues  and the  institutions now being  employed.
Traditional  donation-funded nonprofit  public-interest  organiza-
tions  have  been successful  in transforming public  opinion  into
legislation,  but enforcement has  lagged.

Funding  of  government agencies has not  been  adequate to provide
satisfactory  enforcement  of environmental  statutes.   In  addition,
there  is always  a  significant  risk  that  government regulatory
personnel will  be "captured" by their regulated professional
peers.   The  accepted pattern of dependence  on  state  agencies,
rather  than  Federal,  for  primary enforcement  operations  under
many laws increases  the vulnerability of the process,  if there  is
no  independent enforcement capability in society.

An  appropriate  method of improving public-interest participation
would  be the broadening  of  existing statutory  authorization  of
citizen  lawsuits to include monetary rewards  beyond  the current
provisions  for  recovery  of  attorneys'  fees where  violations  of
legislated  environmental  standards can be  proven.   The creation
of  a  cadre of  "enforcement  entrepreneurs" would  offset,   though
not  eliminate,   the  problem of  serious, underfunding  and   under-
staffing of State  and Federal  regulatory agencies.


PRIVATIZATION;

"Privatizing" functions which  had been  the purview of government
—selling or  giving  them  to non-governmental enterprises, usually
profitmaking— was touted by  the  Reagan and Thatcher  administra-
tions,  and  received  a particular  boost  in  the President's  budget
message  in February,  1986.

The common  belief  underlying  most "privatization" suggestions  is
                              1081

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that government  agencies  are inherently  less  efficient users of
resources than private enterprise,  and  that therefore the public
as a whole is  better  served if any service  for  which there is a
market be provided by profitmaking entrepreneurs.

The concept  of "privatizing" should be  applied  to environmental
enforcement.   Action  should  be  taken  to  provide  not only the op-
portunity, but also  the  incentive for private citizens to bring
enforcement actions against violators of environmental laws.
THE ENFORCEMENT PROBLEM:

Despite the  rise  in  popularity of  "privatization"  in other for-
merly government-only endeavors, the enforcement of laws is still
generally regarded as a public  function and private  law-enforce-
ment entrepreneurship is viewed with  skepticism.   However, there
are exceptions in existing  law, and the climate is favorable for
greater private-sector involvement  in law enforcement.

Current enforcement of environmental regulations suffers from two
weaknesses: funding and will.

Recent environmental  legislation  has  generally established mini-
mum Federal  standards for  pollution  prevention.    This  has been
found necessary to prevent  "blackmail"  of industry-hungry states
by companies who  threaten  to move  across state lines to a less-
stringent environmental climate.  However, these uniform national
environmental objectives are  typically  accompanied by a reliance
on state enforcement.  State enforcement levels vary  widely.

For example, a 1989 survey of state regulation of oil/gas explor-
ation and production wastes found that  the budgets of state regu-
latory agencies responding  ranged from  a low of $19/well-year up
to $4,054/well-year.  Agency  personnel  resources  varied from one
FTE per  9.3  wells to one per 5,991 wells.   While some state-to-
state variation is reasonable, a 600-to-l ratio "could indicate a
staff need...  in the  upper end  of this  range,"  as  the  report
dryly concluded.  (1)

These data  strongly suggest  that  a  more  subtle  version  of the
industry shopping  feared  at  the  legislative stage  can  occur at
the enforcement level.

National enforcement  is inadequate,  as well.   At  the national
level, EPA staff  levels were  cut  throughout the Eighties.   Water
program  staff  shrank by  forty  percent  and the  total  EPA Clean
Water Act enforcement staff  now numbers only 350. (2) (3)   These
gaps have not been filled by increased  budgets or staff at other
levels of government.
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The EXXON Valdez  spill  dramatically illustrated the  consequences
of "capture"  and complacency  on the part  of regulators.   As  a
result, in January,  1990,  the  Alaska Oil Spill Commission  recom-
mended stronger  roles  for citizen  participation  in oil  shipment
regulation. (4)

As enforcement replaces legislation  as the most important element
in improving environmental quality,  a new source of funds,  vigil-
ance, and  initiative is badly needed.   Bringing  individual pri-
vate citizens  into the enforcement universe is overdue.
INCENTIVE SYSTEMS FOR CITIZEN ACTION;

American government  today  employs  three  distinct systems to pro-
vide incentives  for  citizen  action to enforce statutes: informer
rewards, citizen suit provisions,  and qui tarn laws.

Informer rewards: Rewards  to informers are now most actively used
by  the  Internal  Revenue Service.  The Secretary of  the Treasury
is  authorized  to pay  "such  sums  as  he  may deem  necessary"  for
information  leading  to  the recovery of  unpaid  taxes  from viola-
tors of  the  Internal Revenue laws.  (5)   The  Service  has a price
list for rewards;  the  schedule  is  not generous:  10%  of the first
$75,000  recovered,  5%  of  the next $25,000,  and 1% of  any addi-
tional.

Though  parsimonious, the  program  is  very  effective:  in  Fiscal
Year 1989  $1.5 million  was paid in rewards  for  information which
led  to  the  recovery of $72  million.    This  on only  519  claims
allowed.   The  highest  recent year for  returns  from  the program
was FY1986,  when  820 claims  allowed  cost $1.3  million in rewards
and recovered  $258 million.  (6)   IRS cannot be  accused of being
profligate  (93%  of  claims  filed are  rejected),  and  one suspects
that a higher payout rate  ultimately would be more profitable for
the Treasury.

While informer  rewards could be used in  environmental enforce-
ment, they depend on the prosecutorial resources of government to
be  effective.  EPA  and  the states  are already aware  of many vio-
lations  which  they  choose not   to pursue,  for  budget  or  policy
reasons.   Those  issues  are part of  the  problem,  and  reliance on
informer rewards does nothing to address them.

Recently,  the  Superfund  Amendments   and Reauthorization  Act  of
1986  provided for  awards of up to  $10,000  to informers  whose
information leads  to  arrest and  conviction  for violations of
CERCLA  subject  to  criminal penalties.  There has been  little
experience by which  to  judge this  provision's effectiveness. (7)
                              1083

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Citizen Suits: Since the  first  legislative provision for  citizen
suits was included at  Section 304  of the Clean Air Act  in  1970  ,
many environmental  laws  have included  "citizen suit" provisions
which admit  individuals  or environmental  groups to  litigate.(8)
However, the  possibility  of filing citizen suits  is  not an ade-
quate inducement for significant private-party  effort in environ-
mental enforcement.

Recent data on the level of citizen suit activity are incomplete;
the  most  comprehensive study was  done by  the  Environmental Law
Institute in the mid-Eighties.  (9)  Over a  six-year period  ending
in April, 1984, ELI  found  349 notices of intent to sue  which had
been issued,  and 189 filed cases,  under the citizen suit provis-
ions of five  major  laws.   The Clean Water Act,  because  of  infor-
mation reported under  the  NPDES system, was host to the majority
of suits.  After the study period, it is believed that  there was
a short time  of fairly high citizen suit activity,  followed by a
decline. (10)

The  nationwide level of citizen suit  activity cannot be  described
as high,  given the  scale  of the  national  industrial base.   In
recent years,  the  annual  total  of  all environmental actions com-
menced in Federal  district courts,  only a fraction  of which have
been citizen  suits,  has  averaged about  900  (278,420  district
court actions were commenced in 1989; 233,529 of these were civil
actions) .  (11)   Why has   the citizen suit opportunity  not been
more widely  used?    The  ability to  merely  recover  costs  from a
successful action  against an environmental violator  is  not suf-
ficient to spur significant "privatization," yet this is the only
financial incentive offered under citizen suit provisions.

Any  enforcement  program  requires  research and  investigation  of
many incidents, each of which may or  may not lead to prosecution.
Citizen enforcement  is no  different.  In  the  most concentrated
use  of  citizen suit  provisions to  date,   the  Natural   Resources
Defense Council reviewed files on over  1,000 permitted discharges
in order to eventually file 18  complaints in  the early  Eighties.
(12)   In most cases where  a complaint  is  actually  filed,  plain-
tiff may  or  may not  prevail.    The long delay  between  making a
large outlay  for  factual  research and eventual  collection,  and
the  risk  that there will  be no collection at  all,  make  filing
suits where the best possible outcome is break-even an uneconomi-
cal proposition. (13)

As a result,  it is no  surprise that the great majority of  citizen
suits have  been brought   by non-profit organizations  which are
funded by donations  and  do not  depend  on  the  suits  for  income.
(14)   The  flurry  of Clean Water  Act suits brought  by  NRDC and
associated non-profit  law organizations in the mid-Eighties led
                             1084

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to speculation that the existing  citizen suit opportunities were
adequate.  However, that spate of action has since dwindled.

Citizens' access  to  the courts was  recently reduced  by  the Su-
preme Court  in Gwaltnev  of Smithfield  v.  Chesapeake  Bay Foun-
dation.   (15)   The "boilerplate"  citizen  suit  legislative lan-
guage, which has been employed with little change since its Clean
Air Act  origination,  requires  giving notice of  violation to the
EPA,  the alleged  violator, and  the State  sixty days prior  to
commencing  civil  action.  The Court held  that cessation of a
violation during  the sixty-day  notice period  was adequate  to
prevent  suit, and  that  "the interest  of  the citizen-plaintiff  is
primarily forward-looking." (16)  (17)

Thus  a  citizen-enforcer  faces  the risk  that he may  invest time
and  funds to study 50 sites,  add the investment to  prepare  one
case  against  an  identified violator,  and yet be foreclosed from
recovering even these costs —let alone  any  reward  for risk—  by
the timely shutdown of the offending facility.  This is hardly  an
incentive system for private environmental enforcement.

It  has  been  argued that  a violating  company which  remedies  the
violation within  the 60-day warning  period should  be protected
from  penalty  as  a matter  of equity.   While there may have been
justice  in this at an early time, environmental  violations today
are  often the result  of   conscious  evasion  of   regulation  until
caught.   Someone  who  is  pulled  over  for  speeding  would hardly
argue that  he was exempt  from  ticketing because,  at  the moment
the officer was checking his registration,  his car had stopped.

Beyond  the  fairness  question, the  value of the  60-day  notice
provision needs  to be judged as  it affects  an  entire  regulatory
system.   If  judicially  maintained, the Gwaltnev view  will  chill
citizen  enforcement,  and  further  narrow the inadequate  citizen
suit  path.

Citizen  suit provisions  were  intended  more  to provide  citizen
oversight to prevent "capture" of  regulators,  than to  signifi-
cantly  supplant  government  regulation.  (18)    These  provisions
have  succeeded  in bringing a major change  in  the flavor  of en-
forcement in  some  areas,  most notably Clean  Water Act.   However,
they  do  not  constitute "privatizing"  enforcement and  to  describe
them  as  such  is incorrect.

Qui Tarn  Actions: The abbreviated Latin phrase "qui  tarn" refers  to
legal actions brought by  private  parties,  under statutes  which
establish penalties for the commission of acts,  and  which  provide
for  sharing  of recovered  penalties between  the  private initiator
and  the  government.  (19)   "tl]n qui  tarn  actions...  society makes
individuals  the representatives of the public for the  purpose  of
                             1085

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enforcing a policy explicitly formulated by legislation."  (20)

Specific statutory  authorization  is necessary  for  qui tam  act-
ions, and it is rare.   The First Congress enacted a  number  of qui
tam  statutes,  presumably  in an effort  to enlist citizen  action
while the  Executive powers were undeveloped.   Over time,  those
provisions were  largely  repealed  or supplanted.  (21)   The  most
prominent example of a qui tam provision in effect in Federal law
today is the False  Claims Act.  (22)   This Civil-War era statute
was  enacted to reduce  fraud by Army  procurement  contractors.
After decades of decline,  the False Claims Act was revitalized  in
1986 through the enactment of a package  of amendments promoted  by
Senator Charles E. Grassley (R-Iowa).

Senator Grassley,  incensed  by estimates  that  fraud against  the
government was costing the  Treasury up  to $50 billion per  year,
argued that "[tlhe solution calls  for  a  solid  partnership between
public law enforcers  and  private  taxpayers."  (23)   Grassley  de-
scribed the  goal  of his  amendments as  being  "to complement  the
Government's resources  by encouraging private  individuals  to
become actively involved  in  the war  against fraud." (24)    These
same goals are appropriate, and necessary,  for  adequate environ-
mental enforcement.

The  1986 False Claims Act amendments provided for treble damages
and  specific  forfeitures  per  false  claim.   Rewards to persons
bringing qui tam  actions  under the Act  normally will  range  be-
tween 15 and 25 percent of the total recovered.   This is expected
to produce a major rise in fraud litigation by both  public-inter-
est  and for-profit attorneys. (25)


RECOMMENDED ACTIONS;

Congress should  adopt a  Comprehensive  Environmental Enforcement
Entrepreneurship Act, which  would  (i)  establish  a  general  right
to file  qui tam actions  to enforce  any environmental  statute
where  citizen suit provisions  now exist,  (ii) eliminate  the
Gwaltney problem  of polluters who  evade prosecution by ceasing
their discharges during the 60-day window  of  opportunity after  a
notice of  intent  to sue  is  filed,  (iii) ensure  that  "standing"
challenges, in which environmentalists  must demonstrate that they
have been directly  injured before suit can be brought, no  longer
work to prevent judicial  scrutiny of environmental  offenses,  and
(iv)  require that  all  state programs  certified under  Federal
environmental statutes include similar  provisions.

In addition, more  identifiable and measurable  standards need  to
be incorporated in environmental  legislation  and regulation.
Where it is unfeasible to write quantitative  standards into law,
                             1086

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the law should  direct that  regulations  include  such provisions.
Only with these  standards  can the specifics  of  litigable viola-
tions be clearly established.

Some issues deserve further consideration.  Should steps be taken
to ensure  that  public qui  tam  enforcers  can  obtain access to
private sites for  inspection and to obtain  samples  for  testing?
(Recommendation: Yes, with controls  to  prevent  oppressive zeal.)
(26)   Should some portion  of qui tam  awards be required  to be
reinvested in further enforcement or other non-profit environmen-
tal work? (Recommendation: No.)
CONCLUSION;

The  recent EXXON Valdez  oil spill  demonstrates  the problem  of
reliance  on regulatory  agencies alone  for continued  long-term
vigilance.   Environmental  enforcement  by  private  entrepreneurs
may  be  more effective  than reliance on  government staff  whose
closest professional peers  are often  the  regulated  industry per-
sonnel themselves.   At  the least, it is  an important  complement
to agency  action which deserves to be encouraged through positive
economic  incentives.   By  making every citizen  a potential  en-
forcement agent, privatization  will put  new  reality into Dr.
Johnson's  observation that  "conscience is  that  little  voice that
tells us someone may be watching."

Private environmental  enforcement action cannot  totally  replace
public-agency work,  nor should it.  But as the  spotlight in  envi-
ronmental  protection  shifts from passage  of legislation to  the
enforcement of laws on the books, it is clear that more  resources
are  needed than agency  budgets  can  provide.   Privatization  of
environmental enforcement,  through  providing qui tam  opportuni-
ties which apply to  environmental statutes,  is  essential  to com-
plement   tax-funded  agencies  and  donation-funded  nonprofit
activities.

Beyond the quantifiable issues of enforcement budgets and person-
nel  which  have  been  discussed herein lie  two  more  philosophical
arguments  in favor of privatization of environmental enforcement:
representation and  innovation.  Environmental  protection is,
literally, the safeguarding of the citizenry's  lives.  While much
of that task must perforce be undertaken by delegates,  in a  demo-
cracy realistic paths (not merely the idealistic opening of  citi-
zen  suits) should be  open for  citizens directly  to represent
themselves  and  their fellows,  and to be  rewarded for  success  in
so doing.   Secondly,  the pride of privatization  is  its  stimulus
to innovation and the  discovery of more  efficient methods  of
realizing  objectives; environmental  enforcement needs innovation,
and  some early efforts have demonstrated what improvements even a
                             1087

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little bit of private-sector invention can produce.  (27)

In the long run, a flexible array of enforcement methods is need-
ed.  There may  be  a  larger role for  informer  rewards in the fu-
ture, and there may  be  a need for a  sharing  of roles and powers
between private and  public enforcers which is  more complex than
citizen suits  or  qui  tarn actions  permit.    But the  first step
should be to greatly  increase  the  incentives  for public enforce-
ment action.  Qui  tarn powers should be  applied to environmental
statutes generally.  Soon.
ACKNOWLEDGMENTS:

R. Clark Boyd,  of the Mineral  Policy Center,  has been an invalu-
able partner  in the development of  the  facts and  logic  of this
paper.  David Lennett, Esq., made very helpful suggestions in its
evolution, as did several other colleagues to whom I give thanks.
The conclusions, and any errors, are my own.
REFERENCES

1.   G. Christiansen, Draft Report of Personnel and Resources
     Subcommittee, IOCC Council on Regulatory Needs, 30 November
     1989, 10.

2.   Environmental Safety, Inc., Report, June 1988.

3.   EPA Office of General Counsel, 5 June 1990.

4.   Spill, Report of the Alaska Oil Spill Commission, Executive
     Summary, January 1990, 13, 21.

5.   26 U.S.C. 7623.

6.   IRS Office of Media Relations, 2 July 1990.

7.   Pub.L.99-499, 42 U.S.C. 9601 et seq., at 9609(d).

8.   42 U.S.C. 7604.

9.   Environmental Law Institute, Citizen Suits: An Analysis of
     Citizen Enforcement Actions under EPA-Administered Statutes,
     1984.

10.  Personal communications with environmental litigators.  A
     back-pressure developed to some of the Clean Water Act cam-
     paign.  See also the discussion of Gwaltnev below.
                             1088

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11.  Annual Report of the Director of the Administrative  Office
     of the United States Courts, 1989,  Table  C  2.

12.  EPA Office of Water Analysis and Evaluation, Section 505
     Citizen Suit Analysis  (undated).

13.  B.J. Terris, Environmentalists' Citizen Suits,  Environmental
     Law Reporter July 1987, 10254.

14.  Id.

15.  108 S. Ct. 376  (1987).

16.  Id. at 382.

17.  Gwaltney was later found to be  in "intermittent" violation,
     however, and fined.

18.  B. Boyer, E. Meidinger, Privatizing Regulatory  Enforcement:
     A Preliminary Assessment of Citizen Suits Under Federal
     Environmental Laws, Buffalo Law Review, Vol.34, No.3, Fall
     1985,  833.

19.  Black's Law Dictionary 1414  (4th ed. 1968).

20.  Priebe & Sons v. United States. 332 U.S.  407, 418  (1947)
      (Frankfurter, J., dissenting).]

21.  E. Caminker, The Constitutionality  of Qui Tarn Actions, The
     Yale Law Journal. Vol. 99:341,  1989.

22.  31 U.S.C. §§231-235.

23.  Statement of Senator Charles E. Grassley before the  House
     Judiciary Committee, Subcommittee on Administrative  Law  and
     Governmental Relations, February 6, 1986.

24.  Id.

25.  S. France, The  Private War on Pentagon Fraud, Journal of the
     American Bar Association. March 1990, 46, 47.

26.  For a  discussion of limits on qui tarn prosecution, see
     Caminker, supra, at 368.

27.  E.g.,  the improvements to the SMCRA Applicant Violator Sys-
     tem database developed by non-governmental  entrepreneurs.
                              1089

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                                AUTHOR INDEX
AUTHOR                                                                 PAGE
Adamache, I.; Contaminated Sulphur Recovery by Froth Flotation	       185

Andrews, D. E., Abou-Sayed, A. S., and Buhidman, I. M.;  Evaluation
      of Oily Waste Injection Below the Permafrost in Prudhoe Bay Field,
      North Slope, Alaska  	       443

Bakke, T., Gray, J. S.,  and Reiersen, L. O.; Monitoring in  the
      Vicinity of Oil and Gas Platforms: Environmental Status in the
      Norwegian Sector in  1987-1989  	       623

Balkau, Fritz; International  Aspects of Waste Management, and the Role
      of the United National  Evironment Programme (UNEP)	       543

Baruah, K. C.; Environmental  Evaluation of Oil Drilling and Collection
      System   A Case Study  From India  	       357

Biederbeck, Voklmar C.; Using Oily Waste Sludge Disposal to Conserve
      and Improve Sandy Cultivated Soils	      1025

Bohlinger, L. Hall; Regulation of Naturally-Occurring Radioactive
      Material in Louisiana  	       833

Boyer, David G.; State Oil and Gas Agency Environmental Regulatory
      Programs  How Successful Can They Be?  	       897

Boyle, Carol A.; Management  of Amine Process Suldges	       577

Bozzo, W., Chatelain,  M., Salinas, J., and Wiatt, W.; Brine Impacts
      to a Texas Salt  Marsh and Subsequent Recovery 	       129

Branch, Robert., Artiola, Dr. Janic, and Crawley, Walter W.;
      Determination of Soil Conditions that Adversely Affect the
      Solubility of Barium  in  Nonhazardous Oilfield Waste  	       217

Braun, Jack E. and Peavy, Mark A.; Control of Waste Well Casing
      Event Gas From A Thermally Enhanced  Oil Recovery	       199

Brommelsiek, W. A., and Wiggin, J. P.; E & P Waste Management
      in the Complex California Regulatory Environment ~ An Oil
      and Gas Industry Perspective	       293
                                1090

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Buchler, P. M.; The Attenuation of the Aquifer Contamination
      in an Oil Refinery Stabilization Pond	        109

Crawley, Wayne W. and Branch, Robert T.; Characterization of
      Treatment Zone Soil Condition at a Commercial Nonhazardous
      Oilfield Waste Land Treatment Unit  	        147
      (presented as a poster session)

Crist, Dennis  R.; Brine Management Practices in Ohio	        141

Deeley, George M.; Use of Minteq for Predicting Aqueous Phase
      Trace Metal Concentrations in Waste Drilling Fluids  	       1013

DeGagne, David and Remmer, W.; A Practical Approach to Enforcement
      of Heavy Oily Waste Disposal	        783

Desormeaux,  Tom  F. and Home, Brian; Hazardous Waste Treatment/Resource
      Recovery Via High  Temperature Thermal Distillation	        529

Deuel, L. E.,  Jr.; Evaluation of Limiting Constituents Suggested
      for Land Disposal of Exploration and Production Wastes 	        411

Fitzpatrick, Mike; Common Misconceptions About the RCRA
      Subtitle C Exemption for Wastes from Crude Oil and
      Natural Gas Exploration, Development and Production	        169

Frampton, Michael J.; Waste Management Decision Making
       Procedure at Prudhoe Bay, Alaska	       1071

Frazier, Forrest W.; Comprehensive Environmental Training
       Program for the Production of Oil and Natural Gas Industry	        179

Fristoe, Bradley; Drilling Wastes Management for Alaska's
       North  Slope 	        281

Codec, M. L. and Biglarbigi, K.; The Economic Impacts of
       Environmental Regulations on the Costs of Finding
       and Developing Crude  Oil  Resources in the United States  	        319

Green,  Kenneth M.; The Potential for Solar Detoxification
      of Hazardous Wastes in the Petroleum Industry
       (presented as a poster session)	        771

Grimme, S. J. and  Erb, J. E.;  Solidfication  of Residual
       Waste Pits as an Alternate  Disposal Practice in Pennsylvania  ....        873

Hall, Robert; Environmental Consequences of Mismanagement
       of Wastes from Oil  and Gas Exploration, Development,
       and Production	        387
                                  1091

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Hardisty, P. E., Dabrowski, T. L., Lyness, L. S., Scroggins, R.
      and Weeks, P.; Nature, Occurrence and Remediation of
      Groundwater Contamination at Alberta Sour Gas Plants	        635

Hartmann, S., Ueckert, D. N., and McFarland, M. L.; Evaluation
      of Leaching and Gypsum for Enhancing Reclamation and
      Revegetation of  Oil Well Reserve Pits in a Semiarid Area  	        431

Henriquez, L. R.; The Development of an OEM Cutting Cleaner
      in the Netherlands  	        243

Hocker, Philip M.; Who is Oui Tam? / Privatizing Environmental
      Enforcement	       1081

Huddleston, Ross D., Ross, W. A., and Benoit, Jacques R.;  The
      Development of a Waste Management System for the Up-Stream,
      On-Shore Oil and Gas Industry in Western Canada   	        227

Ignasiak, T., Carson, D., Szymocha, K., Pawlak, W., and
      Ignasiak, B.; Clean-Up of Oil Contaminated Solids	        159

Janson,  Len G., and Wilson Everett  M.; Application of the
      Continuous Annular Monitoring Concept to Prevent
      Groundwater Contamination by Class II Injection Wells 	         73

Jones, Fredrick V. and Leuterman, Arthur J. J.; State
      Regulatory Programs for Drilling Fluids Reserve Pit  Closure:
      A Overview  	        911

Kalra, G. D.; Regulations and Policy Concerning Oil and
      Gas Waste Management Practices in India	        841

Kamel,  W.; Waste Management Practices:  The Role of UNIDO	       1063

Kennedy, Alan J., Holland, Lancecelot L., and Price, David H.;
      Oil Waste  Road Application Practices at the ESSO
      Resources  Canada Ltd., Cold Lake Production Project  	        689

Kiser, S. C, Wilson, M. J., and Bazeley, L. M.; Oil Field
      Disposal Practices in Western Kern County, California	        677
      (presented as a poster session)

Korsun, George and Pierce, Matthew; An Evaluation of the Area
      of Review  Regulation for Class II Injection Wells	        467

Ledec, George; Minimizing Environmental Problems From
      Petroleum  Exploration and Development in Tropical
      Forest Areas	        591
                                  1092

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Leggett, S. A. and England, S. L.; Sulphur Block Basepad
      Reclamation Programs Undertaken at Three Facilities
      in Central Alberta	        945

Lynn, Jeffrey S., and Stamets, Richard L.; A Review of State
      Class II Underground Injection Control Programs	        853

Macyk, T. M., Nikiforuk, F. L, and Weiss, D.K.; Drilling
      Waste Landspreading Field Trial in the Cold Lake
      Heavy Oil Region, Alberta, Canada	        281

Mann, W., and McLean, R.; An Overview of Produced Brine
      Injection Practices in Kentucky 	        717

McFarland, Mark L., Ueckert, Darrell N., and Hartmann, Steve;
      Evaluation of Selective-Placement Burial for Disposal of
      Drilling Fluids in West Texas  	        455

Mead, Douglas and Lillo, Harry; The Alberta Drilling Waste
      Review Committee - A Cooperative Approach to Development
      of Environmental Regulations	          1
Meyer, L.; Simple Injectivity Test and Monitoring Plan for
      Brine Disposal Wells Operating By Gravity Flow 	       865

Miller, H. T., Bruce, E. D. and Scott, L. M.; A Rapid Method
      for the Determination of the Radium Content of Petroleum
      Production Wastes  	       809
      (This paper was not presented orally at the Symposium.)

Miller, H. T. and Bruce, E. D.; Pathway Exposure Analysis and
      the Identification of Waste Disposal Options for Petroleum
      Production Wastes Containing Naturally Occurring Radioactive
      Materials 	       731

Mutch, Graham R. P.; Environmental Protection Planning for Produced
      Brine Disposal in Southwestern Saskatchewan Natural
      Gas Fields  	       375

Myers, Julian M. and Barnhart, Michael J.; Pilot Bioremediation
      of Petroleum Contaminated Soil  	       745
       (presented as  a poster session)

Nunes, Pepsi and Frampton, Michael J.; Environmental Auditing
      at Prudhoe Bay:  A Waste Management Tool	       339
                                   1093

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Perry, Charles W. and Gigliello, Kenneth; An EPA Perspective on
      Current RCRA Enforcement Trends and Their Application to
      Oil and Gas Production Wastes	       307

Poimboeuf, W. W.; Combination Injection/Monitoring Well in a
      Single Borehole  	,        43

Pontiff, Darrell; Sammons, John; Hall, Charles  R. and Spell,
      Richard A.; Theory, Design and Operation of An
      Environmentally Managed Pit System	       977

Powter, C.B.; Alberta's Oil and Gas Reclamation Research
      Program	         7
Pusch, G. and Weber, R.; Modelling of Toluene Migration in
       Ground Water with the Use of a Mulitphase Simulation
       Programme	       611

Quaife, L. R. and Moynihan, K. J.; A New Pipeline Leak-Locating
       Technique Utilizing a Novel Odourized Test-Fluid (Patent
       Pending) and Trained Domestic Dogs  	       647

Rabalais, Nanacy N., Means, Jay C., and Boesch, Donald F.; Fate
       and Effects of Produced Water Discharges in Coastal
       Environments	       503

Reiersen, L. O.; A Harmonized Procedure for Approval, Evaluation
       and Testing of Offshore Chemicals and Drilling Muds Within
       the Paris Commission Area	       515

Reller, Carl; An Environmental Compliance Audit of Four Oil and
       Gas Facilities in Kenai, Alaska 	       345

Rifai,  H. S. and Bedient, P. B.; A TC Model Alternative for
       Production Waste Scenarios	       955

Roberts, L. and Johnson, G.; A Study of the Leachate Characteristics
       of Salt  Contaminated Drilling Wastes Treated with a
       Chemical Fixation/Solidification Process  	       933

Ruddy, Dennis and Ruggiero, Dominick D.; An Overview of Treatment
       Technologies for Reduction of Hydrocarbon Levels in Drill
       Cuttings Wastes  	       717

Schmidt, Ernst and Jaeger, Shirlee; PRS Treatment and Reuse of
       Oilfield Wastewaters	       795

Shaw, Geraldine and Slater, Barry; BP Superwetter - An Off-Shore
       Solution to the Cutting Cleaning Problem  	       117
                                   1094

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         <1
Shirazi, Dr. G. A.; Land Fanning of Drilling Muds in Conjunction
      with Pit-Site Reclamation:  A Case History	        553

Shuey, Chris; Policy and Regulatory Implications of Coal-Bed
      Methane Development in the San Juan Basin, New Mexico
      and Colorado	        757

Simmons, Jerry R.; The States' Regulation of Exploration and
      Production Wastes  	        925

Simms, K., Kok, S.,  & Zaidi, A; Alternative Processes for
      the Removal of Oil from Oilfield Brines  	         17

Smyth, I. C. and Thew, M. T.; The Use of Hydrocyclones in the
      Treatment of Oil Contaminated Water Systems  	       1001

Spell, Richard A., Hall, Charles R., Pontiff, Charles and
      Sammons, John; Evaluation of the  Use of a Pit
      Managment System	        491

St. Pe, Kerry; Means, Jay; Milan, Charles, Schlenker, Matt;
      An Assessment of Produced Water Impacts to Low-Energy,
      Brackish Water Systems in Southeast Louisiana: A
      Project Summary	         31

Steingraber, Walter A, Schultz, Fred E. and Steimle,
      Stephen E.; Mobil Waste Management Certification
      System	        599

Stilwell, C. T.; Area Waste Management Plan for Drilling
      and Production  Operations  	         93

Subra, Wilma A; Unsuccessful Oilfield Waste Disposal Techniques
      in Vermilion Parish, Louisiana	        995

Taylor, Renee C.; The Cost of Education	        211

Thurber, N. E.; Waste Minimization in E & P Operations	       1039

Ueckert, Darrell N., Hartmann, Steve and McFarland, Mark L.;
      Evaluation of Containerized Shrub Seedlings for
      Bioremediation  of Oilwell Reserve Pits  .	        403

Van Sickle, Virginia and  Groat, C. G.; Oil Field Brines:
      Another Problem for Louisiana's Coastal Wetlands	        659
                                   1095

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Vickers, D. Troy; Disposal Practices for Waste Waters from
      Coalbed Methane Extraction in the Black Warrior
      Basin, Alabama  	       255

Wagner, John F.; Toxicity and Radium 226 in Produced Water -
      Wyoming's Regulatory Approach	       987

Warner, D. and McConnell, C.; Evaluation of the Groundwater
      Contamination Potential of Abandoned Wells by Numerical
      Modeling	       477

Wascom, Carroll D.; A Regulatory History of Commercial Oilfield
      Waste Disposal in the State of Louisiana	       821

Wilson, Everett; The Application of Concentric Packers to
      Achieve Mechanical Ingerity for Class II Wells in
      Osage County, Oklahoma  	       967

Winklehaus, Charles; Clark, George L., and Pomerantz, Robin;
      Statistical Assessment of Field  Sampling Project Data
      on Petroleum Exploration  and  Production Wastes	       883

Wotherspoon, Paul D.,  Webster, Gary A.,  and Swiss, James J.;
      Waste Management Guidelines for  the Canadian
      Petroleum Industry	      1053

Yates, Harold; Onshore Solid Waste Management in Exploration
      and Production Operations 	       703

Zimmerman Peter; Landfarming Oil Based Drill Cuttings	       565
                                     1096

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