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;
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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;
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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).
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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
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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).
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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.
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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.
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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
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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
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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
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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
Figure 4 Long Term IGF Performance at Site B
-------
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Flfure 6 Description of viatic hydrocyclone
Fi«ure 7 Schematic of Crosaflow filtration Processes
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ma.
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Figure 6 Description of Rotary Hydrocyclone
Figure 6 Typical Process Schematic of Crossflow Filtration
-------
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
-------
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
-------
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
-------
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
-------
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
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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
-------
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
-------
STEP NO. 2
MONITORING CASING THRU
MONITORING FORMATION
FIGURE NO. 4
DRILL OUT AND
SET MONITORING
CASING ^---_
^==S#jJ
X j
X .t
/ f
>
/ ;
7^ '
s~\
/ ~
.•.-.•.•.•.•.•.•.•.•.•.- Y "V
•»
•.Y.Y.Y.Y.Y.Y.Y./
y '
s - "4
X
/
/
X
/
X
X
X
/
X
X
§
d
H
g
X y
X X
X
X X
' X
X X
X X
X
X X
X
X X
CEMENT TO SURFACE
'.• vit
j? •• = GROUND UATI
L*1 1**
•-
• ^^^^^_
•* x
r ^^
f /"
L. _ _ __^ _
> /
• r
'•' S
X
'• m^^^
|T
;;.•.•.•.•.•.•.•.•.•.•.-.•.• MONITORING
•••.•.•.•.•.•.•.-.•.•.•.•.-. FORMATION
P
i>
>' 7
'/
/
X
X
X
X
/
X
,
.Y.vr/fjY.vr.Yo-.. .•.•o'-'-'-'/.'Q'.'.'.. .YO'-".YB$Y.Y.Y.QY. . .•.'O'-'-'-'
51
-------
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
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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^
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/
/
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SECTION
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BRIDGE PLUG j
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fe
X
X
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X
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. .'.'G-'-'- • •'•(-^'•'.
53
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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
-------
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
-------
STEP NO. 9
INSTALL ANNULUS MONITORING FLUID
AND ANNULUS MONITORING POT
FIGURE NO. 11
HDNITORING
nONITORING
FLUID
58
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
INJECTION WELL WITH MONITORING SYSTEM
FOR MONITORING TWO ANNUL I
FIGURE NO. 24
71
-------
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
-------
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
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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).
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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
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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
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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.
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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.
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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.
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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
-------
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
0
phenol on TMA
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
as
r-t
o
CM
O
co
bo
0
.0
L,
O
CO
•a
0)
-P
3
i— i
O
CO
CO
03
10
TMA-tetramethy1ammonium
FDA-fatty acids derivative
0
phenol on TMA
phenol on FDA
C0 on TMA
8
C on FAD
8
C on TMA
C on FDA
200 400 600 800 1000
Equilibrium concentration (ppm)
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
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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
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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
-------
;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
-------
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
-------
'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
-------
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
-------
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
-------
• 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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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.
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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
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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
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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
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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
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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
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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
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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
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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.
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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
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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.
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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
-------
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
-------
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
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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
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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
-------
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
-------
/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
-------
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
-------
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
211
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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,
212
-------
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,
213
-------
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
-------
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.
215
-------
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.
216
-------
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
-------
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
-------
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
-------
oooooooo
oooooooo
000000
ooooooo
ooooo
o o o p/o o o o
FIGURE 1: CROSS SECTION OF BUCKET USED IN GREENHOUSE STUDY
220
-------
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
-------
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
-------
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
-------
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.
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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.
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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).
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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.
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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
-------
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
-------
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)
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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.
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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
287
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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.
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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.
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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
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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.
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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
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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.
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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
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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
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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
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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
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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.
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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).
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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.
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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-
-------
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:
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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.
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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.
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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
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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
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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
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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
-------
COMPLIANCE MONITORING & CIVIL ENFORCEMENT
Issue Warning Letter/ NOV
I Noncomoiiance I
Develop Administrative
Comptaint-
Dratt relief
Calculate penalty
Conduct Inspection
Writ* Inspection Report
Laboratory Analysis of
Decision to take enf. action
Offer State enforcement
lead
t
tiate
1 k<
Adjudicatory Proceeding
before AU
State Enforcement
Administrative
Compliance Agreement
Final Order _
• Calculate steps
1
*
r
Oversee Compliance
+
TinaJ Order
Appeal- to Administrator
*
Respondent Res Civil
Suit
Refer to
AG
Deveidp Civil Judicial
Referal
^
i
r
Refer to DOJ
• Direct
• Through OECM
t
Provide legal and
technical assistance
t
Judicial Decree
t
Appeal
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
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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
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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.
325
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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
-------
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
-------
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
-------
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)
-------
OJ
Q
v
a
fc
eo
CO
g
o
•a
o
4-
3-
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)
-------
100.0%
•o
0*
I
eg
-------
6-f
vn
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-------
tn
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o
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4>
U.
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5.0-
0.0
Reference Case
Low Scenario
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)
-------
15-1
CO
I
«
CO
O
(2
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)
-------
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.
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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
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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.
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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).
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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
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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.
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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).
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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
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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.
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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.
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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.
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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
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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
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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.
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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.
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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
-------
Pnottuc-
TtOH WfiL >jd
Barn
To
-P4-
FIRS
GAS
O/LV WASTE
GROUP
SECOND
I
To
STATION
SouGcz:
OIL
TIOH
PIT
-------
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
-------
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
-------
BY PASS
EFrLULUT
SLOP on-
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
-------
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
-------
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.)
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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.
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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.
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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.
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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.
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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.
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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.
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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
-------
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
-------
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
-------
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
-------
(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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
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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
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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
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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
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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
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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
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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
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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
-------
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
-------
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
-------
(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.
477
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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.
481
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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
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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
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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
?
'l:
\
'
t
'<
j
f
\e
(
<
'
^Hrt.g^o.ing
d
i
^
/
i
|?j
'•?
lii
X
x;
\
^
<
$
^
)<
X
\
j
v
[
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
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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
-------
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
-------
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
-------
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
-------
•o
c
16
14
12
to
8
g
4
2
350
300
250
200
150
100
50
-e
1
•
B
1
t.
00 -600
16
A
* .U t i
c
-400 -200
14
12
10
8
6
4
2
0
400
350
300
250
, 200
I 15°
H
•1 too
II 5°
•• In
) 200 400 600 800
B
^ *
« *
*« » * *
•
e
.
-18 T T ' ,
0 200 400 800 800 1000 1200 1400 1800
sw Distance from Discharge (m) NE PAH (ppb)
I
I
22
20
16
14
12
10
8
6
4
2
0
S
a
Z
180
160
140
100
80
60
40
-"20
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
-------
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).
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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.
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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.
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
-- 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
-------
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
-------
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
-------
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
-------
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
1.0
CA
ppm
4745
4658
966
201
_IM
__L5JL
127
939
1194
155
110
,32
25
409
495
172
272
19
13
1160
533
168
186
60
55
727
314
164
146
48
5fl
MG
ppm
35
17
87
?8
22
^L-
18
136
136
28
22
10
36
74
110
40
74
18
24
131
75
31
—
10
10
71
42
24
26
_2
11
NA
ppm
1747
1656
367
56
49
__A5.
47
222
282
47
26
7
18
77
98
28
65
10
18
449
200
84
81
21
34
137
204
70
82
14
2Z
SO -S
j)j>m
184
153
129
114
119
107
31
35
96
37
5
7
11
9
74
95
6
5
7 j
3 1
83
38
I2_i
5
35
23
107
102
10
17
CL
. SPQL
8256
8550
2140
117
76
86
48
2234
2653
131
58
40
41
977
1230
220
260
97
215
3337
1403
170
300
30
98
1702
741
"T10
250
2.}
-6.L
TGR
_t/ac
90.8
81.6
<0.1
*0.1
-•0.1
<- .1
*0.1
/.O.I
<- .1
* .1
1.2
1.6
L 0.1
<. .1
0
0
1- .1
< ,1
•
<- .1
L .1
0
0
0
1.1
<• .1
-c .1
~o~--
. o
L
a
N
J»JlnL
-. _
1
1
1
1
5
15
1
1
—
31
20
2
2
~
1
1
1
3
1
1
— .
1
^"4
"T
15
1
...2.
P
ppm
—
. - . -..
7
3
6
3
2
1
14
3
104
59
6
1
4
4
6
3
"6"
1
6
2
22
-— 9"
1
0
19
..A
K
-Pm
— —
—
— . —
141
141
224
206
244
242
252
260
161
184'
277
250"
333
326
147
88
135
233
130"
1TO
151
156
"170"
194
160
155
S
J>JJ]"
—
—
—
"27
14
--— -
—
'W
16
—
_ _ —
—
"15
.13
20
160
—
OS
FOOTNOTE: Soil analysis completed from all 32 sites, but results included for only 5 sites.
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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
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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
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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
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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
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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
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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
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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
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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
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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.
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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.
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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.
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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,
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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
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(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.
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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.
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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.
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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
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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.
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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.
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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
-------
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,
604
-------
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
-------
EXHIBIT 1
MOBIL WASTE CERTIFICATION SYSTEM EVALUATION SCHEMATIC
TRANSPORTER
FACILITY
PROCESS
TRANSPORTER
FACILITY
PROCESS
TAKEN
orr
9TE
INJECTED
-------
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
-------
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
-------
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
-------
EXHIBIT 4
RATINGS OF WASTE FACILITIES
PERCENT PER CATEGORY
g
NON-HAZARDOUS
HAZARDOUS
% (PERCENT)
70-
60
ACCEPTABLE
ACCEPTABLE W/
PROBLEMS
UNACCEPTABLE
WASTE FACILITY CATEGORIES
-------
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.
-------
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
-------
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
613
-------
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
-------
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
-------
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*
^
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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.
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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
-------
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.
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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
655
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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.
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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.
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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.
-------
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
-------
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
-------
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
-------
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
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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.
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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
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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
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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.
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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.
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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.
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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.
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Figure 1 : Oil Field Location Map
Figure 2 : Regional Cross Section A - A
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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
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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.
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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
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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
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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.
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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
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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
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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.
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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
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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.
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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
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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
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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.
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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:
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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.
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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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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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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.
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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;
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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.
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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.
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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
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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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Deuel, American Petroleum Institute, 1220 L Street, N.W., Washington,
D.C.
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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.
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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.
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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»
-------
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.
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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(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
-------
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
-------
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
-------
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
-------
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.
762
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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
-------
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.
765
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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.
766
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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.
767
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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.
769
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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
776
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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
779
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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.
781
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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.
784
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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.
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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.
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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.
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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.
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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
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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.
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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,
796
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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
797
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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
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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
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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
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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
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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
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§
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
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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
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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
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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
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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
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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
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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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.
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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.
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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
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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
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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
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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
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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.
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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
861
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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
866
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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.
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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.
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Figure 1
00
8
Mell Ridge Field
Green County, Kentucky
-------
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
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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
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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.
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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
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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.
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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.
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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
-------
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
-------
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
-------
(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
-------
(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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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.
925
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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.
930
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
-------
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
-------
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 $5250 with at least two squeeze jobs needed to
adequately correct the problem in order to demonstrate
mechanical integrity- ,Using a concentric packer, the operator
was able to locate the leak, repair the well, pass the
mechanical integrity test and resume injection within one day
which resulted in considerably less downtime and expenses than a
squeeze job.
SUMMARY
Comparison of the procedures and associated well costs
demonstrates that the use of a concentric packer is an
attractive alternative to squeeze cementing or running a liner
in a well for the purpose of acquiring mechanical intergity of
the casing. Although savings are dependent upon the operating
protocol of the oil company involved in the workover and the
individual well conditions, the use of a concentric packer in an
appropriate situation can result in a significant savings in
repair costs and in time needed to get the well back in service.
972
-------
c
:.••»
FIGURE 2
COMPLETION SCHEMATIC FOR CASE 2
3/4'
60 *x
348*
TOP OF 7- x 4 1/2" x 2 3/B" COJCHWRIC PACKER
G{" 373 '-404* Sail. PH«DLE OR COLLAR LEAK
TVOCE
Ł> 404'-436' LAKE HOLE. CEMENT TO SURETiCE AM) SQCEE2E TO
-* 500 PSL
465'
BOTTCM OF OCNCENTRIC PACKER
c>
VI
C^ 2785*
'•i
7" x 2 3/8" AD-1 DNSICN PACKER
. '•$ 2905'-2966* PERPQRATICIB
^•; 2974' 7" CEMEJ/m) W/ 270 ax
973
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
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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
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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
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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
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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
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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
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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.
995
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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.
996
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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.
997
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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.
998
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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.
999
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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:
1001
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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)
1002
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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
1003
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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.
1004
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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).
1005
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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
1006
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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
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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
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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
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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
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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
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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
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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
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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
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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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
-------
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
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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
-------
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
-------
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)
-------
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
80
60
40
20
0
Separation Efficiency (%)
(Thurber. 1988)
50 100 160 200
Fluid Throughput (gpm)
--- High Q-Forc* ~t~~ Low O-Force
Figure
250
Rig Water Reuse System i
(Thurber, 1984)
To Rig Reuse x N. Frac Tank Cellar Pump
Rig Water
Does Not
Drain To
Reserve
Pit
To
Steel
Mud
Tanks
_j^\_
1 BOP Cellar |
\^_*/
Ditches~Xround
Rig Substructure
Drain to Cellar
Figure
LC60 (ppm)
1000000
600000
Toxicity Database
Corrosion Inhibitors
(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
LC60 (ppm)
Figure #14
(Bray. 1989;
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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.
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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.
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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
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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.
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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.
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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
1071
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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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•fad » M udi*4 »r "I^«»« • E
11» *wi>* rf te •
T* hi M *UBB Wl
— —f— *—• -
M te turn «^M (Cu? c in,
MI4». Cknu« M35, WT *».
H 1MB. CP*. P-ST7),
-------
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
1077
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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.
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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.
1082
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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
-------
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
-------
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
-------
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
-------
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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