United States
Environmental Protection
Agency
Office of Solid Waste
and Emergency Response
Washington D.C. 20460
October 1986
EPA/530-SW-86-051
Solid Waste
Technical Report

Wastes from the
Exploration, Development
and  Production of Crude
Oil, Natural Gas and
Geothermal Energy

An Interim Report
on Methodology
for Data Collection
and Analysis
             U.S. Environmental Protection Agency
             Region 5, Library (PL-12J)
             77 West Jackson Boulevard, 12th Floor
             Chicago, tL 60604-3590

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                                TABLE OF CONTENTS


                                                                     Page No.

                         Part I:   Oil and Gas Extraction

General Introduction.	    1

Chapter 1  Overview of the Oil and Gas Industry and Waste
           Generation	  1-1-1
           Industry Profile  	  1-1-1
             Exploration and Development Operations 	  1-1-2
             Production Operations 	  1-1-12
           Waste Generation  	  1-1-27
             Literature Review 	  1-1-28
             Exploration and Development Wastes 	  1-1-34
             Production Wastes 	  1-1-41
           References 	  1-1-49

Chapter 2  Industry Waste Management Practices	  1-2-1
           Introduction 	........	  1-2-1
           Current Industry Waste Management	  1-2-3
             Onsite Methods of Waste Disposal ,	  1-2-3
             Centralized Methods 	  1-2-18
             Land Application 	  1-2-27
             Subsurface Disposal 	. .	  1-2-29
             Ocean Discharge 	  1-2-35
           Construction and Monitoring Requirements 	  1-2-41
             Introduction 	  1-2-41
             Pit Design and Construction 	  1-2-43
             Examples of Drilling Pit/Impoundment  Permit
               Requirements  	  1-2-48
           Evaluation of Waste Management Methods  	  1-2-54
           References 	  1-2-58

Chapter 3  Estimating the Costs of Alternative Waste Management
             Practices 	  1-3-1
           Introduction and Overview 	     1-3-1
           Estimation of Costs for Individual Current and
             Alternative Waste Management Practices 	     1-3-4
             Earthen Pit Storage and Disposal 	       1-3-5
             Disposal in Lined Pits (with Installation of
                an Impermeable Cap at Site Closure) 	       1-3-7
             Monitoring and Site Management Practices 	       1-3-8
             Offsite Disposal in a Secure Facility (i.e., Those
                Employing Multiple Liner Systems and Other
                Controls) 	       1-3-10


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                         TABLE OF CONTENTS  (continued)
                                                                       Page No.
         Estimation of Waste Transportation Costs for
                     Centralized Disposal 	    1-3-12
                Class II Injection Wells 	    1-3-14
              Plans for Adapting EPA Cost Models and for Original
                 Cost Estimation 	    1-3-15
                 Identify Incremental Actions and Costs 	    1-3-16
                 Develop Regional and Aggregate National-Level
                   Cost Estimates 	    1-3-17
              References 	    1-3-19

Chapter 4     Impact of Waste Management Scenarios on Petroleum
              Exploration,  Development,  and Production 	    1-4-1
              Introduction and Overview  	    1-4-1
              Model Project Analysis 	    1-4-2
                Identification of Model  Projects 	    1-4-2
                Establishing Representative Cases 	    1-4-3
                Environmental Control Costs 	    1-4-6
                Marginal Economic Cases  	    1-4-6
                Economic Parameters of Model Projects 	    1-4-7
                Marginal Economic Cases  	    1-4-10
                Model Project Simulations 	    1-4-11
              Corporate and Industry-Level Impacts 	    1-4-12
                Industry-Wide Assessment 	    1-4-13
                Financial Assessment for Representative Companies...    1-4-14
              Impact on Industry Exploration, Development,  and
                Production 	    1-4-15
              References 	    1-4-17

                           Part  II:   Geothermal  Energy

Chapter 1     Industry Description	    II-l-l
              Background	    II-l-l
              The Nature and Occurrence  of Geothermal Energy Systems    II-1-2
                Hot Igneous Systems	    II-1-4
                Conduction-Dominated Systems	    II-1-4
                Hydrothermal Systems	    II-1-6
                Vapor-Dominated Reservoirs	    II-1-7
                Liquid-Dominated Reservoirs	    II-1-9
                The Geographic Distribution of Geothermal Energy
                  Systems	    II-l-ll
              Exploration of Geothermal  Resources	    II-l-ll
                Preliminary Exploration	    II-l-ll
                Geothermal Well Drilling	    II-1-13
                Drilling Fluids (Muds)	    II-1-16
                Distribution of Geothermal Drilling Activity	    II-1-19
                                      -11-

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                        TABLE OF CONTENTS (continued)
                                                                   Page No.

           Electrical Power Generation	   II-1-19
             Current and Planned Development	   II-1-24
           Direct Use Applications	   II-1-24

Chapter 2  Waste Generation	   II-2-1
           Waste Sources	   II-2-1
             Drilling Wastes	   II-2-1
             Drilling Fluid Waste	   II-2-2
             Deck Drainings Wastes	   II-2-2
             Drilling Fluid Cooling Tower Wastes	   II-2-3
             Miscellaneous Small Waste Streams	   II-2-3
           Waste Streams from Power Plants and Direct Users	   II-2-3
             Electric Power Generation	   II-2-3
             Reinjection Well Fluid Wastes	   II-2-4
             Piping, Production Well Filter Waste, Scale Waste,
               and Flash Tank Solids	   II-2-7
             Brine Effluent Precipitated Solids	   II-2-7
             Settling Pond Solids	   II-2-8
             Cooling Tower Drift and Slowdown.	   II-2-9
             Direct Steam Usage	   II-2-9
           Waste Characterization, Composition, and Volumes......   II-2-9
           Waste Streams from Electric Power Generation and
             Direct Users	   II-2-10
           Drilling Wastes	   11-2-17
             Production Waste	   II-2-17
           Data Needs	   II-2-19

Chapter 3  Waste Management	   II-3-1

Chapter 4  Cost of Current and Alternative Disposal Practices....   II-4-1
           Development of Estimates	   II𦴖
             Bottom-up Technique	   11-4-2
             Parametric Technique	   II-4-2
             Specific Analogy Technique	   II-4-3
             Cost Review and Update Technique	   II-4-3
             Factored Cost Technique	   II-4-3

Chapter 5  Economic Impacts of Alternative Methods of Treatment
             and Disposal	   II-5-1
                                    -111-

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                        TABLE  OF CONTENTS  (continued)
                           Part  III:   Case  Damages
                                                                   Page No.
Chapter 1  Introduction	   III-l-l

Chapter 2  Approach for Collecting Damage Cases	   III-2-1
           Specification of Information Types Required	   III-2-1
           Identification of Case Study Information Sources	   III-2-2
           Specification of Procedures for Collecting Data	   III-2-4
           Specification of Criteria for Classifying Cases	   III-2-6

Chapter 3  Application of Damage Case Results..-	   III-3-1

                          Part  IV:   Risk Assessment

Chapter 1  Introduction	   IV-1-1

Chapter 2  Overview of the Risk Assessment Approach	   IV-2-1
           Overview of the Risk Assessment Methodology	   IV-2-1
           Alternative Methodologies Considered	   IV-2-5

Chapter 3  Input Data for the Analysis	   IV-3-1

Chapter 4  Industry Characterization and Classification	   IV-4-1
           Waste Generators	   IV-4-1
           Waste Stream Types	   IV-4-2
           Waste Treatment, Storage, and Disposal Practices/
             Release Sources	   IV-4-4
           Environmental Settings for Release Sources	   IV-4-5
             Climate	   IV-4-6
             Hydrogeology	   IV-4-7
             Surface Water	   IV-4-9
             Human Exposure Points	   IV-4-11
             Environmental Exposure Points	   IV-4-12

Chapter 5  Exposure Pathway Analysis and Model Scenario
             Development	   IV-5-1

Chapter 6  Development and Refinement of Modeling Techniques	   IV-6-1
           Contaminant Release to Ground and Surface Waters	   IV-6-1
             Underground Injection Wells	   IV-6-2
             Surface Pits	   IV-6-3
             Effluent Point Sources	   IV-6-4
                                    -iv-

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                        TABLE  OF CONTENTS  (continued)


                                                                   Page No.

           Contaminant Transport and Fate	    IV-6-4
             Ground Water	    IV-6-4
             Surface Water	    IV-6-6
           Exposure and Health Risks	    IV-6-8
             Cancer Risks	    IV-6-8
             Chronic Noncancer Health Risks	    IV-6-8
           Environmental Damage	    IV-6-8

Chapter 7  Analysis of Scenarios	    IV-7-1

APPENDIX A

APPENDIX B
                                    -v-

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Introduction

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                            GENERAL INTRODUCTION
Regulatory Background

    Under Section  3001 (b)(2)(A)  of  the 1980  amendments to  the  Resource
Conservation  and  Recovery  Act   (RCRA),   Congress   temporarily  exempted
several types of  solid wastes from regulation as hazardous wastes, pending
further study  by the  Environmental  Protection Agency  (EPA).    Among  the
categories of wastes exempted were "drilling fluids, produced waters,  and
other wastes associated with the  exploration,  development, or production
of crude oil or natural gas or geothermal energy."

    Section 8002(m)  of the amendments required the Administrator of EPA to
conduct a  study and  submit a final  report to Congress  by October  1982.
EPA did not conduct the study.

    In  its  study  of  these wastes.   Congress  directed  EPA (through  RCRA
section 8002(m)) to consider:
      is also  required  to  make  regulatory determinations  affecting  the
oil  and gas  and geothermal  energy industries  under several  other  major
statutes.   These   include   designing   appropriate   effluent   limitations
guidelines  under the Clean  Water  Act,  determining emissions  standards
under  the  Clean  Air  Act,  and  implementing  the  requirements  of  the
underground injection control program under the Safe Drinking Water Act.

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    1. The  sources  and  volumes  of discarded  material generated  per  year
       from such wastes;
    2. Present disposal practices;
    3. Potential  danger to  human  health  and  the  environment  from  the
       surface runoff or leachate;
    4. Documented cases  that prove or  have caused danger  to  human health
       and the environment from surface runoff or leachate;
    5. Alternatives to current disposal methods;
    6. The cost of such alternatives;  and
    7. The  impact of   those  alternatives  on  the  exploration  for,   and
       development  and  production  of,  crude  oil   and  natural  gas  or
       geothermal energy.

    In  August 1985,  the Alaska  Center for the  Environment sued  EPA (Alaska
Center  for  the  Environment  v.  Lee Thomas)  for  its  failure  to  conduct  the
study.   EPA  then  signed a  consent order  obligating it to submit the  final
Report  to Congress on  or before  August 31,  1987.  In the interim,  the  Agency
must  meet  several requirements  by  specific dates.   One  such  milestone  is to
complete the present Technical Report  by October 31,  1986.

    All of the information and methods  presented in this Technical Report are
preliminary  and  subject to  revision.   Comment.?  are  solicited and encouraged
on any portion of the document.

    Pursuant  to  the  consent  degree,  EPA  is  preparing  a  separate  technical
report  that  will characterize wastes  associated with oil and  gas extraction.
Information  and  analytical  data necessary for  waste  characterization  were
collected  in a  nationwide   screening  sampling program that lasted from  June
through  September of  1986.    This  information  is  now being   interpreted  and
compiled and  will be  formally released, as  required by the  consent decree, in
January of 1987.

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    Wastes Included Under the Exemptions
    The  legislative  history of  Section 3001(b)(2)(A) sheds  some  light on the

identity of oil and gas and geothermal energy wastes subject to exemption:


    The term  "other  wastes associated"  is  specifically included  to designate
    waste  materials  intrinsically  derived  from  the primary  field operations
    associated with  the  exploration,  development, or production of  crude oil,
    natural  gas,  or  geothermal energy.   It  would  cover  such substances  as
    hydrocarbon-bearing  soil   in   and  around  facilities;   drill   cuttings;
    materials  (such  as hydrocarbon,  water,  sand,  and emulsion) produced from a
    well in conjunction with crude oil, natural gas, or  geothermal energy; and
    the  accumulated  material  (such as hydrocarbon, water,  sand,  and emulsion)
    from production  separators,  fluid treating vessels, storage  vessels, and
    production impoundments.

    The phrase  "intrinsically  derived from the primary field operation ..." is
    intended   to   differentiate  exploration,  development,   and  production
    operations  from  transportation (from  the  point of  custody transfer  or of
    production separation and dehydration) and manufacturing operations.


    Floor  commentary on  the  exemptions  consists  of   only  a  few  brief

statements of general support.   The speakers note  that muds and brines are
exempted,  and also  specify that geothermal energy must be  treated  in  a

manner consistent with oil and gas  extraction (125 Congressional Record,

June 4, 1979).
    Since  the  exact identity of  the  wastes exempted affects the  scope  of
the present  study,  EPA has relied on RCRA's  language  and the  legislative
history  to  develop  tentative  criteria  for determining  which wastes  are
included:
Conference Report, 96th Congress,  2nd Session 32  (1980)

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    1.  Only waste streams intrinsic to  the  exploration  for,  or  development
       and production of,  crude oil, natural gas,  or geothermal energy  are
       subject to  exemption.    Waste  streams  generated at  oil,  gas,  and
       geothermal energy facilities that are  not  uniquely associated with
       exploration,   development,  or  production activities  are  not  exempt
       (one example  would be spent solvents  from equipment  cleanup).

    2.  Exempt  wastes must  be  associated  with  "extraction"^  processes,
       which   include  measures   (1)  to  remove   oil,   natural  gas,   or
       geothermal energy from  the  ground or (2) to remove impurities from
       such  substances,   provided that the  purification  process  is   an
       integral part of  normal  field operations.*

    3.  The proximity  of  waste  streams  to primary  field operations  is  a
       factor  in   determining  the   scope   of  the  exemption.    Process
       operations that are  distant from the  exploration,  development,  or
       production operations may not be  subject to exemption.

    4.  Wastes associated with  transportation  are  not  exempt.  The point of
       custody transfer, or of production separation  and dehydration,  may
       be used as evidence in making this determination.
    As  shown  on  Table 1,  EPA  has  used  these  criteria  to  tentatively

designate  various wastes  as  exempt  or  not  exempt.  The  Agency is  aware

that this  table  does  not  include all waste streams  found  at oil, gas,  or

geothermal  extraction facilities.   Therefore,  EPA  invites commenters  to

specifically describe  other affected waste streams  and  to articulate,  in
terms of  the  above criteria,  whether or not these  additional  streams  are
or  are  not  subject  to  the  Section 3001(b)(2)(A)  exemption.   EPA  also
invites comment  on the criteria  themselves  and on  the  appropriateness  of
the tentative classifications  shown on Table  1.
      term extraction  is  defined  to  include,  exploration,  development,
and production activities for oil, gas, and geothermal energy.

4Thus,   wastes   associated  with   such   processes   as   oil   refining,
petrochemical-related  manufacturing,   or   electricity  generation   from
geothermal energy are not exempt.

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                                          Table  l
                     Wastes Considered Exempt Under Section 3001(b)(2)
Oil and Gas
Geothermal Energy
   Drill ing media
   Drill cuttings
   Well completion, treatment,
   and stimulation fluids
   Packing fluids
   Produced waters
   Produced sand
   Workover fluids
   Field tank bottoms
   Waste crude oil and waste
   gases from field operations
   Waste triethylene glycol used
   in field operations
   Drill ing media and cuttings
   Reinjection well  fluid wastes
   Piping scale and flash tank solids
   (except for those associated with
   electrical power generation)
   Precipitated solids from brine effluent
   Settling pond wastes
                   Wastes Considered Not Exempt Under Section 3001 (b)(2)
Oil and Gas
Geothermal  Energy
   Waste lubricants
   Waste hydraulic fluids
   Waste solvents
   Waste paints
   Sanitary wastes
   Refining wastes
   Waste motor oil
   Wastes resulting from the generation
   of electricity,  such as:
   - hydrogen sulfide wastes
   - cooling tower  drift
   - cooling tower  blowdown
   Waste lubricants
   Waste hydraulic  fluids
   Waste solvents
   Waste paints
   Sanitary wastes

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Structure of This Report

    Part I of  this  Technical Report presents  an overview  of the  oil  and
gas  extraction  industry  and  describes EPA's  proposed  methodology  for
addressing the study areas mandated by RCRA Section 8002(m).

    Part II of  this report provides an  overview of the geothermal  energy
industry and  describes  potential  sources of  wastes.   It  also  identifies
additional information needed to address RCRA's mandates.

    Part  III   presents   a  methodology  for  collecting   and  presenting
documented cases  of damage  caused by  wastes associated with  oil,  gas,  or
geothermal energy extraction.

    Part IV presents a methodology for preparing a risk assessment  of  the
potential  danger  to  human  health  and  the   environment  from  improper
management of wastes from the oil, gas,  and geothermal energy  extraction
industries.

    Appendix A of  this   report  summarizes   State  and  Federal regulations
currently affecting the   oil  and  gas  extraction  industry.    Summaries  of
State and  Federal regulations affecting geothermal energy  extraction have
not yet been developed, but will be included in the Report  to  Congress  due
on August 31,  1987.

    Appendix B  of this  report contains a brief glossary of terms and list
of abbreviations relevant to the present report.

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    Parti
Oil and Gas

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                                  CHAPTER 1
          OVERVIEW OF THE OIL AND GAS INDUSTRY AND WASTE GENERATION


                              INDUSTRY PROFILE

    The onshore oil  and gas industry  is  responsible for  the  exploration,
development,  and  production of  petroleum resources  in the  United States.
Petroleum is  a  complex mixture of hydrocarbons occurring  in the  earth as
gases,  liquids,  and solids.   For the purposes of this discussion,  oil is
defined  as  crude  petroleum  oil  and  other   hydrocarbons,  regardless  of
gravity, which  are  produced at the wellhead in liquid form.  Natural gas is
any hydrocarbon fluid  that  is produced in a  natural  state from  the  earth
and  which  maintains   a  gaseous  state  at  16癈   (60癋)  and  standard
atmospheric pressure.   Gas  liquids  are the  liquid  hydrocarbons  known  as
"natural gasoline"  recovered  from natural gas.  In general,  petroleum is a
liquid (crude oil) that is recovered from within  the  earth through drilled
bore  holes.   Liquid  and gaseous  petroleum occurs naturally  underground,
primarily in the pore spaces of sedimentary rocks.

    Chemically,    crude   oil   is   composed   of    carbon   and   hydrogen
(approximately  82-87  percent  carbon,  12-17  percent   hydrogen).  Lesser
quantities of sulfur,  oxygen,  and nitrogen organic  compounds  account  for
the balance  of  material.   Crude  oils are  also  classified as  paraffins
organic  compounds  containing  methyl-CH.  structure,   napthenes梠rganic
compounds   with    C H,    structure,    and    aromatics   with    C H_
                     n 2n                       	            n 2n-6
                                   1-1-1

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structure.   (The  n denotes  the  number of carbon atoms  in  the hydrocarbon
molecule.)   A  number of  inorganic  substances are  also  commonly  found  in
crude oil.   Sodium chloride,  usually  found dissolved in crude  oil,  comes
from  the aqueous  medium which  nearly  always  coexists  underground  with
petroleum.   Lesser  quantities  of  free  sulfur,  hydrogen  sulfide,  and
carbonyl  sulfide  also  are   found.   Two  metals梟ickel  and  vanadium梐re
common to crude oils; these metals are present as metal porphyrins.

    As   of   1983,   the  earth's   verified  petroleum  reserves   totaled
                       9
approximately  600  x 10   barrels (Kirk-Othmer,  1985).   However,  the  rate
of  discovery of  large  petroleum  reserves has  steadily declined  for the
past  four decades.   Future  demands  will  be  met  through  exploration and
discovery of new  fields梠perations  that will become more costly  as  fewer
and  fewer  reserves  are  located梐nd  through  the  development  of  new
extraction  techniques  to recover  portions of crude  petroleum left behind
by conventional extraction  methods.   All of these  elements will result  in
higher crude oil prices in the future.
Exploration and Development Operations

    Exploration operations  are those  activities  occurring  in the  search
for  petroleum in  areas previously  undeveloped  with  regard  to  petroleum
reserves.  These  operations  include  activities  associated with  locating
potential petroleum  reserves  (such as seismic exploration), well drilling,
well  stimulation,  well completion, and/or well  abandonment.   Development
operations are similar to  exploratory operations except that developmental
operations occur  in the attempt  to  establish productive  wells  in  areas
known   to  contain  petroleum  reserves.    Developmental   operations  are
conducted in known reservoirs or oil fields, with the  objective of further
enhancing the  productivity  of an area. The  vast  majority  of well drilling
operations in the United States is developmental activity.
                                    1-1-2

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    Petroleum  is  found  and recovered  on  all  of  the earth's  continents
except Antarctica.  In the  United States, the first  onshore oil  well  was
drilled by Col. E.  T.  Drake near Titusville, Pennsylvania, in 1859.  Drake
struck oil at 69-1/2 feet from the surface.  Since  then,  approximately 2.7
million oil and gas wells have been drilled in the United States.

    Drilling activity  in the  United States is almost  entirely  limited to
32  States.   As  shown  in  Figure  1-1,  these  States   are  grouped  by
petroleum-bearing  basins,  which  are   contiguous   between  many  States.
Alaska and California are notable exceptions.

    From  1980  to  1986,  onshore  drilling  activity  proceeded   at  a  rate
averaging  80,000  wells per year  {Oil and Gas Journal, 1985). However, in
1986 the worldwide drop in oil prices caused drilling  activity to decrease
by  almost 50  percent  (Oil  and Gas  Journal, 1986b).   New wells  range in
depth from several hundred feet to over 20,000 feet.
    Well Drilling

    Rotary  Mud Drilling.   During the last  five decades,  rotary drilling
has  become the  predominant drilling  technique.  A  sketch  of  a  typical
rotary drilling  rig  is  given in Figure 1-2.  Essentially,  the bit and the
drill  pipe  suspended above  the  bit  are  slowly  rotated,  gouging  and
chipping away  the rock  at  the bottom of the well.   As the  well becomes
deeper,  additional  sections  of  pipe  are added.  An  advantage  of  rotary
drilling is  that it minimizes  loss  of crude oil and gas.   The drill core
is circulated  with  a  weighted drilling fluid  (called drilling  mud)   that
serves as  a  pressure  seal for the well.   As a  rotary well  is drilled, mud
is circulated  down  the  drill pipe where  it  picks  up  cuttings  and carries
them  up the  hole  to the  surface.   At  the surface,  mechanical  devices
separate the  mud from  cuttings.   The mud  is  recirculated;  cuttings  are
                                    1-1-3

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                                                                fluid* tot
                                                      _      downhole injection
                                                       " .,   centralized pit for long term itorage
                                                     '" '*'^   centralized treatment and discharge
                                                      >  暎晻   话t>ile treatment and discharge
                                                             landspreading or landfarming

Figure  1-2.   Drillino Onpration

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displaced  (with  associated  mud)  into an earthen  reserve  pit.   The reserve
pit  receives this  mixture   (and  all the  chemicals associated  with these
wastes) and  rig deck drainage.  Depending on the site,  it  may  also receive
sewage  and other wastes.   The  following pits usually  are associated with
rotary  mud drill  sites:  reserve  pit(s), emergency  pit, and/or fresh water
pit  (or tank).   Most  States have construction  requirements  or guidelines
for  these  pits;  many  States have  specific  pit reclamation  requirements
(see Appendix A).

    Rotary drilling techniques make  it  possible to drill  wells over 20,000
feet deep.   A  recent  development  in rotary drilling  has   involved  a fluid
powered  turbine  at  the  bottom  of  the bore  hole  to  provide  the rotary
motion of the bit.  In this  method,  the  drill pipe does not rotate, but is
used to weight the bit and carry the drilling mud to turn  the  turbine.

    Pneumatic Drilling.   Pneumatic  drilling is another boring method used
in the Appalachian Basin, in  southeastern Kansas/northeastern  Oklahoma, in
the  four  corners area of the southwest,  and in the Rocky Mountain States
(see Figure  1-1).   Pneumatic drilling may be favored over rotary drilling
when the underlying formations are  hard rock or in shallow locations where
the  use of  fluids  to  maintain  subsurface  pressure is not required.   In
these  circumstances,  pneumatic  drilling  is  considerably faster  and less
     Special  chemical  fluids  are   introduced  into  the  bore  hole  to
     lubricate the action of a rotary bit,  to remove the  cuttings,  and to
     prevent  blow-outs.   Drilling  muds  circulate  continuously down  the
     drill pipe,  into  the  bore hole,  and upwards  between the  drill  pipe
     and  the  walls of the hole to a  surface pit, where they  are purified
     and  recycled.  The composition of drilling muds may  vary.  They  can
     be oil or  water  base;  all contain high  concentrations  of solids such
     as barite, calcium carbonate, or clays.  The mud  is  maintained as  a
     suspension  with  emulsifiers,  wetting   agents,  and  other  specialty
     chemicals.
                                   1-1-6

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expensive than rotary mud drilling.   In pneumatic drilling, air  usually is
the drill medium.  Compressed  air drives the drill bit  and lifts cuttings
back  to  the  surface.   Once  the  cuttings  reach the   surface,  water  is
injected into  the cuttings  return  line for dust control.  This slurry of
cuttings and  water is  deposited  into  an  earthen waste  pit  at the  drill
site.    When  fluids  are  encountered  during  pneumatic   drilling,  foaming
agents are used to bring the fluids to the surface.  The  fluid  and foaming
agents are  also  displaced into the waste pit.   The pit may subsequently be
treated with defoamants.

    Cable-Tool Drilling.  Early oil and gas wells were drilled  with impact
tools by a  method called cable-tool drilling.   In this  drilling method, a
chisel-like bit  is suspended from a cable to  a  lever on the surface,  and
an  up-and-down motion of the  lever  causes  the bit to pound  the bottom of
the hole  and  chip away the rock.   These wells  must  be  free   of  liquids
during the  drilling  process so that the bit can remove  waste  rock.   When
the bit penetrates the gas or oil formation,  large  quantities   of  gas  and
oil can flow  rapidly ("blowout")  to the surface.   This "gusher" appearance
gives the  impression  of a successful well when,  in  fact,  these materials
are  wasted  and  can  contaminate  much  of  the  surrounding  countryside.
(Drilling without  protection against blowouts  is  now prohibited  by  State
regulations.)
    Well Logging

    After  the  bore hole  has penetrated  the petroleum-bearing  formation,
the   formation   must   be  tested  to  determine  if  expensive  completion
procedures  (described  below)  should be used.   These evaluations  are made
with  well  logging measurement instruments that can  detect the differences
in  rock, water,  and petroleum.  Only a production  test can  establish the
                                    1-1-7

-------
potential productivity  of a well.   In  this  test梒alled  a  "drill  stem"
test -  the  bore  hole  is sealed  above and below the  petroleum formation,
with only the  drill  pipe open to the  formation.  The  drill pipe  is  then
emptied of the  drilling mud so that the crude oil can enter. After a time,
the openings to the  drill pipe are  closed  and  fluids  are brought  to  the
surface.  The   fluids   are  then  analyzed  to  determine their  hydrocarbon
content and quality.   If there is gas  in the formation, the  gas  will  flow
from the top of the drill pipe during the test.
    Well Completion

    If preliminary tests  show  that one  or  more of  the  formations  in  the
bore hole  will be commercially  productive,  the well must be  prepared  for
the continuous production of the oil or gas.   First, a large  outside pipe,
or  casing,  slightly  smaller in  diameter than the drill hole,  is  inserted
to  the  full depth of  the  well.  A  cement  slurry  is forced between  the
outside of  the  casing  and the  inside surface of the drill  hole.   When set,
this cement forms a  seal  so  that  fluids   cannot  communicate  from  one
portion  of  the  well  to  the  other  through  the  bore   hole.    In  the
continental U.S., the casing is usually about 23 centimeters  (9  inches)  in
diameter.   It  creates  a  permanent  well   through  which  the  productive
formations  may  be reached.  After  the  casing  is  in place,  a  production
string  of  smaller   (8  centimeters,  or  3 inches  in diameter)  tubing  is
extended from  the surface to the productive  formation.   A packing  device
is  used  to seal  the productive interval  from the  rest of the well.   If
multiple  productive  formations  are  found,   as  many  as  four  production
strings of tubing may be hung in the same cased well.
                                    1-1-8

-------
    Since the  casing  is  sealed against the productive  formation,  openings
must  be made  to  allow  the  oil  or  gas  to  enter  the well.  A down-hole
perforator uses an explosive  to shoot holes through the  casing and cement
and  into  the  formation.  The  perforating  tool  is lowered on  a wire line.
When it is in the correct position,  the charges are  triggered electrically
from the surface.   Such  perforating will  be sufficient if the formation is
quite productive.   If not,  well  stimulation  techniques  (described below)
may be used to encourage production.

    When the subsurface  equipment  is  in place,  a  network of valves (called
a "wellhead" or "Christmas tree")  is installed on the surface  and  arranged
so that  flow  from  the  well can  be regulated and  measured, and  tools to
perform  subsurface  work  can  be  introduced  through  the  tubing.   The
wellhead may be  very  simple,  such as  might be found on a low-pressure well
that must  be pumped, or it may  be  very  complex,  as   in  the  case of  a
high-pressure  well with  multiple  producing strings.   Figure  1-3  shows  a
wellhead.

    Well completion fluids  and well treatment fluids are generated during
the processes  described  above.  These wastes  may include muds,  additives,
and hydrocarbons.
    Well Stimulation

    After  drilling  is  completed,   well  stimulation  techniques   may  be
performed to  enhance production.  Acidizing  is  one  of  the original  well
stimulation techniques still in  modern  use.   The first  and by  far  the  most
successful well  stimulation acidizing   technique  uses  hydrochloric  acid
introduced  into   the   petroleum-bearing  formation.   Hydrochloric   acid
                                   1-1-9

-------
                           WELL HEAD
                           CONNECTIONS
                           SURFACE PIPE
                           CEMENTED
                              TUBING
          OIL SAND
                     V 晻!--  INTERMEDIATE STRING
                     'M^ CEMENTED
                           昉ACKER

                     12.- OIL STRING CEMENTED
Source:
Figure 1-3.

API.  1983.
Production well

Introduction to Oil  and
    B鞍k X of Vocational
    pp. 8, 19.
                    1-1-10

-------
stimulation  is  used  in dolomite  and limestone  formations.   Hydrochloric

acid treatment produces carbon dioxide, calcium chloride,  and/or magnesium

chloride.


    Another   acid  treatment   uses   a   solution   of  hydrochloric   and

hydrofluoric acids  to stimulate  wells in  sandstone  formations.  In  this

instance,  sodium  fluoride  is  an  additional  reaction  product.    Other

acidizing systems include:


       Organic acids - formic and acetic acid  (usually  used  in
        combination with hydrochloric or hydrofluoric);

       Powdered acids - sulfamic acid, chloroacetic acid;  and

       Retarded acid systems  -  gelled acids,  chemical retarded
        acids, emulsified acids.


    Other chemical agents  that are added to petroleum wells to maintain or

increase well productivity are the following:


       Corrosion inhibitors - to  reduce  the attack of  acid  on
        metal.    Some  of these contain arsenic compounds;  many
        contain organic compounds.

       Surfactants  -  to  demulsify  acid  and  oil,   reduce
        interfacial tension, alter formation wettability,  speed
        cleanup, prevent sludge formation.

       Friction  reducers  -   to   minimize   pumping   energy.
        Usually  these  are  organic  polymers  added   to  the
        stimulation fluids  (guar,  cellulose, fatty acids).

       Acid flow-loss additives - Composed of solid  particles
        that enter  formation  pores, and  a  gelatinous material
        to  plug   pores,   silica  fluor,   calcium   carbonate,
        polyvinyl alcohol,  polyacrylamide.

       Diverting agents -  to  direct  stimulation fluids.
                                   1-1-11

-------
       Complexing agents  - to solubilize  iron and  other pipe
        or  metal  corrosion  products  that  might  precipitate.
        Most   satisfactory   product    is    ethylene   diamine
        tetracetic acid (EDTA).
       Cleanup additives  - to  cleanse the well of  the reactor
        products  and  unusual reagents  after  acid  treatment.
        These  products are  flushed with water and  removed  by
        use of  nitrogen gas.  Alcohols  and wetting  agents  are
        added to ease these tasks (Williams, et al.,  1979).
    All   water-soluble  reagents,  sludges,   and   organic   residue   will
eventually be  pumped  from  the  well  to the  surface.   In general,  these
wastes are displaced into a holding pond for treatment and disposal.
Production Operations

    Production  operations  include  all  activities  associated  with  the
recovery of petroleum  from  geologic formations.   Production operations are
delineated into those activities associated with  downhole  operations (such
as   petroleum  recovery  techniques,   workovers,  and  well   stimulation
techniques), and those activities associated with surface  operations (such
as  oil/gas/water  separation  and treatment  of oil,  gas,  gas  liquids,  or
produced water).

    In the  United States,  approximately  28 billion  barrels  of crude  oil
had  been discovered  as of  December  1985.   Less  than  one-half of these
reserves  will  ultimately  be  recovered  with   existing   technology  and
economic  conditions.    Unfavorable   reservoir   geology,   adverse   fluid
properties,  or low  oil  content  in  the   reservoir  rock  limit  recovery
prospects for  petroleum resources.
                                   1-1-12

-------
    By 1984, there were 864,405 producing onshore oil and gas  wells  in the
                                                g
United States.   These wells  yielded 3.09 x  10  barrels of crude  oil and
19  x  106MM  cubic  feet  of  gas   annually    (Kirk-Othmer,   1985;   IOCC,
1985).
    Approximately  70  percent  of  the total  number of  oil  wells in  the
United States are  "stripper  wells."  Stripper wells are defined  as  those
oil  wells  that produced  less  than  10 barrels  of oil  per  day (44  FR
22069).

    In addition to this production,  the United  States  must  import  crude
oil to augment its productive capacity.

    Table 1-1  presents 1984 onshore  oil and gas production  data  for each
State  as  reported  by the  Interstate Oil  Compact  Commission.  The  table
contains each State's  1984 annual  oil and gas production,  total  number of
oil and gas  wells, and number  of   stripper  wells  (IOCC, 1985;  IOCC/NSWA,
1985).

    Water is produced  along  with crude petroleum and/or natural gas.  This
water,  called  "produced  water"  or  "brine,"  is  an  aqueous   solution
containing many dissolved  chemicals,  minerals such as sodium  chloride  and
dissolved hydrocarbons.  It  can present  major disposal  difficulties.   In
several western States, produced water may be a vital source  of water for
livestock, which can tolerate  higher  sodium chloride  concentrations  than
humans.
     The  crude oil  production  unit has  traditionally been  the  barrel,
     which is equivalent to 0.159M3,  42  U.S.  gallons,  or 5.61 ft3.
                                   1-1-13

-------
             TABLE 1-1
ONSHORE OIL AND GAS PRODUCTION - 1984

Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Total #
Oil Wells
797
864
26
9r490
48,908
5,287
0
0
165
0
0
0
28,920
6,792
0
57,633
19,980
28,068
0
0
0
4,881
0
3,569
557
4,665
2,072
34
0
0
24,954
4,678
0
4,026
26,878
99,030
0
20,739
Annual
Production
MM BBL/YR
24.0
631.0
0.2
18.5
411.7
38.6
0
0
17.2
0
0
0
28.9
5.4
0
96.7
11.8
604.7
0
0
0
40.5
0
33.5
0.1
30.7
6.6
2.0
0
0
129.9
1.0
0
58.7
15.3
207.5
0
4.8
*
Gas Wells
659
81
5
2,492
1,220
4,665
0
0
0
0
0
0
157
1,194
0
12,680
9,013
16,815
0
9
0
510
0
715
0
2,152
18
0
0
0
17,523
3,800
0
58
27,846
23,647
6
24,050
Annual
Production
MMSCF Gas
130,080
300,046
225
162,678
470,124
271,544
0
0
15,404
0
0
0
1,530
394
0
466,590
61,518
5,867,511
0
20
0
144,695
0
210,393
0
56,895
2,347
0
0
0
965,717
27,000
0
80,596
186,480
1,996,713
2,790
166,342
*
Strippers
98

14
4,738
26,650
1,690
0
0
165
0
0
0
29,942
6,134
0
45,749
16,433
16,500
0

0
3,500
0
1,923
548
3,085
1,700

0
0
14,749
4,532
0
1,061
25,129
82,431

19,540
                    1-1-14

-------
                                TABLE 1-1 (Continued)

                   ONSHORE OIL AND GAS PRODUCTION - 1984

                               Annual                     Annual
                  Total I     Production     #          Production    #
                 Oil Wells    MM BBL/YR   Gas Wells    MMSCF Gas   Striroers
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming

Totals
      0
      0
    141
    775
203,178
  1,862
      0
     35
      0
 15,475
      0
 12,463

636,942
     0
     0
   0.7
   0.9
1186.1
  39.0
     0
   0.3
     0
  10.0
     0
 143.4

3799.4
      0
      0
     41
    726
 43,174
    728
      0
    499
      0
 30,700
      0
  2,280
        0
        0
    2,468
    5,023
6,753,889
   99,800
        0
    8,928
        0
  143,731
        0
  600,137
      0
      0
     30
    744
162,855
    400
      0
     32
      0
 15,200
      0
  5,020
227,463    19,201,608   493,844
 () No Data
Sources:  Interstate Oil Compact Commission, The Oil and Gas Compact Bulletin.
          Vol. XLIV, No. 2. December 1985; Interstate Oil Compact Commission
          and the National Stripper Well Association, National Stripper Well
          Survey. January 1, 1985; Oklahoma City: Interstate Oil Compact
          Commission, October 1985.
                                   1-1-15

-------
    Downhole Production Operations


    Oil and Gas  Recovery Techniques.   Conventional  primary and  secondary

recovery   processes  produce   about   one-third   of   the   original   oil

discovered.  These techniques are described below.  Recovery efficiency is

a  result  of  a  variation  in the  properties of  the  specific  rock,  the

properties of  the petroleum  fluid  involved from  reservoir to  reservoir,

and the recovery technique(s) employed.


    In all petroleum recovery methods,  aqueous solutions are  produced and

must be treated,  stored, recycled, or disposed of.
       Primary oil and gas recovery.  "Natural drive" production  relies on
       natural  reservoir  pressure  to drive  the oil  through the  complex
       rock pore  network  to  the producing wells.  The driving pressure is
       derived  from  the expansion  of liquid and the release of  dissolved
       gas  from  the  oil  as  the pressure  of  the  well  decreases  during
       production.  Also  affecting  the  flow  is the expansion of  free gas
       or   "gas  cap,"  the   influx   of  natural   water,   and   gravity.
       Eventually, the  natural pressure  lowers  to  a point at which added
       pressure must be applied to the well to produce significant amounts
       of oil and gas.

       Many oil wells  do  not have a formation pressure  high enough to push
       the  head of oil standing in  the  well to  the surface.   In  these
       cases,   some   artificial  method  for  lifting  the  oil   must  be
       installed.   The most  common  installation  involves  a   motor  and
       "walking  beam"   (like  a  seesaw)  on the  surface  that operates the
       pump  on  the bottom  of  the  production string.   A  chain  of  solid
       metal  rods  connects the beam and the pump.   Another method,  called
       gas  lift,  uses  the buoyancy of a bubble of gas  in the  tubing to
       push  the  oil  to  the  surface.   A third type of artificial  lift
       forces some of  the produced  oil down the well at  high pressure to
       operate  a  pump  at  the bottom of the well.  Even though initially an
       oil field may have enough pressure to produce naturally,  artificial
       lift  will  usually be  required in later  stages of production.   Gas
       wells that produce  little or no liquid do not need  artificial  lift
       devices  (see Figures 1-4 and 1-5).
                                   1-1-16

-------
                              ARTIFICIAL LIFT
                                                      WALKING
                          EQUALIZER
                           旹ARING
                         EQUALIZER
                                                                ION SOCKET
                                                              TOWARD LONG ',
                                                              f MO OF CRANK
                                                                        WASINO HEAD
                                                                 SAMSON I
                                                                  POST
       MIME
      MOVER
                                                        COUNTER
                                                        WEIGHT
                                                         BOLT
   Figure 1-4. The major parts  of a
   conventional crank counterbalanced
   beam pumping unit are shown  in this
   drawing.   All units are not  exactly
   like this one, but they operate
   generally in the same way.
    POLISHED ROD CLAMP-

         POLISHED MOO 
         STUFFING SOX '
               TEE-
                                                         TUBING RING ^J
                                                      SUCKER MOO
                                                     FLUID LEVEL
                                                     (IN ANNULUS)
                                                       ROD PUMP r桾-*
                                                              . "  
                                                     MUD ANCHOR *<珪:
                                                      CASING
                                                   PERFORATIONS
 CARRIER BAR
                          FLOWUNE
                          CASINO HEAD
                          CASINO STRINGS
                          TUS4NO STRING
                          P
                         SUMFACE CASINO
                         \\
                         PRODUCTION CASING

                            TIMING
                            MOO
                                                                          PMOOUCINO ZONE
Source:  API.   1983.   Intro-
duction to Oil  and Gas Production.
Book 1 of Vocational  Training
Series, Pp. 8,  19.
Figure 1-5.   This sketch shows the
principal  items of wellhead and  down-
hole equipment installed for a typical
sucker rod pumping system.
                                     1-1-17

-------
  Secondary oil  and gas recovery.   Secondary  oil  recovery  involves
   the injection  of  gas  or  water into the  petroleum-bearing formation
   around producing  wells.    The  injected  fluids  maintain  reservoir
   pressure  and  displace a portion  of  the  remaining crude  oil  to  the
   production wells (see  Figure 1-6).

   Water  flooding  is  the   leading  secondary   recovery   method  and
   accounts  for  a very  large  part  of all U.S.  oil  production.   Fresh
   water or  treated  produced  water  is  usually  used as  the  flooding
   liquid.   The  use  of  natural  gas for secondary recovery is limited
   because of its cost.   Natural gas has a high market value and would
   only be used when water is  not available.

  Tertiary oil and  gas  recovery.   Tertiary (or enhanced)  oil recovery
   is  the  recovery  of   the  very  last  segment  of  oil  that  can  be
   economically produced  from the petroleum  reservoir  over  and above
   what  has  already  been  economically   recovered by   conventional
   primary  and   secondary   methods.   Tertiary  recovery  operations
   generate  wastes  similar to other  oil  and  gas  field  operations.
   Tertiary recovery  can be divided into the following techniques or
   methods:   chemical, miscible,  and thermal.   All of  these  methods
   involve injection  of  a solution  or  gas  into the rock  formation to
   direct the crude  oil  to  the well from which  it  is recovered (DOE,
   1984).

   The chemical methods  of enhanced recovery include polymer flooding,
   surfactant flooding,  and alkaline flooding.  Each method is usually
   tied  to  a  specific  set  of formation  and  crude  oil  conditions.
   Polymer  flooding  is   simple  and  inexpensive;   it   is  in  fairly
   extensive  commercial   use.   Surfactant  flooding is  expensive  and
   still in the  laboratory testing  stages.   Alkaline flooding fills  a
   need in formations containing higher acid crude oils.

   Miscible    oil    recovery    involves    formation  flooding    with
   gases梒arbon  dioxide, nitrogen,  or  a  hydrocarbon  gas  such  as
   propane.   The  specific  application  of   these  techniques  is  the
   recovery of  low viscosity  crudes.   Hydrocarbon  flooding has  been
   commercially   available  since   the  1950s.   Carbon   dioxide  and
   nitrogen flooding are  more  recent developments.

   Thermal  recovery  methods   include  steam  injection  and  in  situ
   combustion  ("fire  flooding").    Steam  processes are   most  often
   applied to formations  containing  viscous crudes and tars.  In situ
   combustion remains a  terminal recovery  technique because  it burns
   out  the  hydrocarbons  as   the   firefront  advances    through  the
   formation.   However,  in  situ combustion can yield up  to 4 barrels
   of crude for each barrel  burned.
                               1-1-18

-------
M
I
M
VO
                                                    PRODUCED FLUIDS fOIL. OAS. WATER!
                                                           SEPARATION AND
                                                          STORAGE FACILITIES
                                                                                                    PRODUCTION WELL
                              INJECTION WELL
                                                    WATER
                                                  INJECTION
                                                    PUMP


                                         I   I    I   I   I   I    I   I   I    I
                                                                 ^^^^*W*^B梌^^^^^^^^^^^^^^^^^^^^^^^*"^^" ^^^^^  ^^^^^^^|^^^玘^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^-^^B
                                                 OIL ZONE
   DRIVE WATER
       SOURCE: Admttd fcoM origM drawing* by Jo* B. Undtoy. U.S. O**rtm** el Eiwrgy.
Enwoy TKhnotogy C玶tw
                                                      Figure  1-6

-------
    Workover Operations.  As  a  well continues to produce  crude oil and/or
natural  gas,  its production  may begin  to  decrease  and  may  even cease.
There  are  many geological  and  man-made  reasons  for  this  nonproductivity.
Workover  operations are  operations on  a  producing  well to  restore  or
increase production.  Producing  wells  need a workover operation when there
has  been a mechanical  failure  or  a  blockage from corrosion  products  or
sand.

    A  typical  workover  cleans out  a  well that has sanded up.   The tubing
is pulled, the casing and bottom of the hole are washed, out with  mud,  and,
in some  cases,  explosives are set off in the hole to  dislodge the silt and
sand (Williams and Meyers, 1984).

    Workover operations generate  cleaning fluids,  packing fluids,  bailing
fluids, and deck drainage that must be disposed of.

    Well   Stimulation  Techniques.    The   well   stimulation   techniques
discussed in the Industry Profile,  Exploration and Development  Operations,
and  Well  Stimulation sections,   are equally applicable to production  well
enhancement.  Well  stimulation  wastes may include acids, additives,  and
other wastes as discussed above.
    Surface Production Operations

    Surface production operations generally  include  transport of the  well
fluids (oil, gas,  gas  liquids,  water)  from the wellhead or from a group of
wells to  a facility that  separates the  fluids  and treats  them prior  to
sale.  The  separation  facility  is  called a lease operating unit, or  tank
battery  (see  Figure 1-7).   Products  may  be  transported  from  the  tank
battery by truck or pipeline.
                                   1-1-20

-------
      Stock tank*
                                                                  |nt玞tton iMCfc
                                                                  OnMto 暬粫珪 l w
Figure  1-7    Oil/Gas  Production  Operation

-------
    Impoundments  (or  pits)  are used  in nearly  all  petroleum  producing
operations to contain produced  water and other waste material generated at
the production site.

    For  clarity,  the following discussion  of production  processes  will
focus separately  on oil and gas  and will briefly consider the  case where
gas production is concomitant with oil production.  The first  example to be
discussed is production  of oil.

    Oil  Production  Operations.   Water,  oil,   oil/water  emulsion,  and
limited  amounts  of gas  flow  into  the  well  and  are  brought  to  the
wellhead.   This mixture  is usually  piped from  the wellhead,  through an
oilfield gathering  system  serving  many wells,  to the  lease operating unit
or  tank battery,  although some  wells  have  dedicated  surface  facilities
(see Figure 1-7).

    A "separator" may be used to divorce produced gas  from produced fluids
(including  oil  and water  at this point).   A  separator  is  a vertical or
horizontal baffled vessel;  it is designed for sufficient  retention  time to
allow gas  to  break out  of the  wellhead  fluids.   If  the guantity of gas is
low, a  "free water knock  out"  vessel may  be used to  make the  initial
separation  of free water   (taken  off the bottom of  the vessel)  and  gas
(taken off  the  top of the vessel) from  free oil and oil emulsion (taken
from  the  midsection  of   the  vessel)  (see  Figure   1-7).   Gas  from  the
separator  and/or the free  water  knock  out  may be  routed into  a  low
pressure  gas  gathering  system  or  flared (burned  in a  controlled manner
onsite).   Produced water  is sent  to  an impoundment,   pit,  or  tank  to
accumulate prior to disposal.
                                   1-1-22

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/
                     +p

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    The free oil and oil  emulsion  may be treated differently from  site  to
site,  depending  upon how difficult  it  is  to break the emulsion  and  other
factors.  If  the emulsion  is  difficult to  break,  the  free oil and  oil
emulsion  may  be heated  and  chemically treated  prior  to  mechanical  or
gravity separation.  A  "heater-treater"  is  used to heat  the free oil  and
oil emulsion prior to a settling process (see Figure 1-7).

    If  the  emulsion can  be broken  through  longer  settling time (with  or
without  emulsion-breaking  chemical  addition),  the  free  oil   and  oil
emulsion are  sent  to a larger settling vessel, usually a  "gun barrel" (see
Figure 1-7).   The gun barrel may be used as the settling vessel  after the
heater-treater, or it may be used alone.

    Crude   oil  flows  from   the   gun  barrel   to  stock  tank(s)   (see
Figure 1-7).   Ownership of  the oil may change past  the  stock  tank.  Stock
tank  oil  is measured (corrected to  60癋)  and moved off  the lease  or unit
for sale.

    The  most  modern  production  sites  have  computerized  oil  transfer
gauging  systems  called  Lease Automatic  Custody  Transfer  (LACT)  units.
These  units take samples,  record  temperature, and  determine   the  quality
and   net   volume  of   the   oil.    They  also  recirculate  bad   oil  for
reprocessing,  keep  records  for production  and  accounting  purposes,  and
shut  down and sound an alarm  when  something goes wrong.   LACT  units are
used mainly with pipeline systems.

    In all  crude oil recovery methods, aqueous solutions are  produced and
must  be treated, stored,  recycled,  or  disposed  of.   As a  well  ages, the
aqueous   fraction   of   the   crude   oil-water  production  increases.    In
California,  there  are  areas  where crude oil  wells produce  98-99  percent
brine  with  1  to  2  percent crude oil.  For stripper well  production,  25 to
80 percent  is  brine  (EPA, 1986).
                                   1-1-24

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    Depending  upon State  regulations,  produced  water  may be  reinjected
into  the   petroleum   formation,   used  for  ice  control  or  as  a  dust
suppressant  on   roads,   land  spread,  stored   in  pits   to  evaporate,
percolated, or be discharged into surface waters.

    Gas  Production  Operations.   As  in  oil  production,  water,  liquid
hydrocarbons,  and impurities must  be  removed from  natural gas  before  it
can  be  marketed.  Gas  production  contains  limited  amounts of  heavier
petroleum   compounds.   Gas   is  separated  from  wellhead  fluids   in   a
separator.

    In one  technique,  natural  gas from the well enters a chamber where the
pressure on the  gas  is increased.  This causes  a concomitant  decrease  in
temperature, and petroleum liquids  and  water precipitate  out of  the  gas
stream and flow through a drain at the chamber bottom.   Natural gas exists
near  the top  of  the  chamber.   Heat  exchangers are  also used  with this
system  to  further  cool  the  gas.   This  process  is  also  called  Low
Temperature Separation.  In  this  system,  the petroleum liquid that settles
out of the separator bottoms enters a low pressure  separator chamber where
additional  gas  is  removed.   Natural  gas  and  petroleum  liquids are  the
products  that   leave   this  separator  (API,  1976).    This   gas  may  still
contain  substantial amounts  of  water.   It must be  dehydrated  and sold,  or
sent to a gas plant for further processing.

    One  problem  associated  with  the  production  of  natural   gas  is  the
presence of free water.   Free  water promotes  corrosion and  formation  of
hydrates.   Both  corrosion  and hydrates  cause increased piping  pressure
drops and piping restrictions.  Hydrates  are precipitates that form in the
presence of free water under certain conditions.  The  greater  the pressure
in the equipment,  the  higher the  temperature at  which hydrates will form.
Hydrates will  form of  methane,  ethane,  propane,  isobutane,  normal  butane,
hydrogen sulfide, and carbon dioxide from a natural gas stream (API, 1976).
                                   1-1-25

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    Problems associated with the presence  of free water may be  avoided by
dehydrating the gas  stream  or  by preventing formation of hydrates in other
ways.  Water may  be removed by  glycol dehydration,  by desiccants, or by
expansion-refrigeration.  Glycol  is a liquid desiccant  that absorbs water
from  the  gas.  When using  liquid  absorbent,  the  gas  passes  through  a
chamber into  which a fine  spray  of the liquid is  introduced.   The liquid
flows out the  bottom of the chamber and is  heated to remove the water so
that the  liquid can be reused.  The dry gas exits the chamber at the top.
Solid absorbents (desiccants)  are used in conjunction with a gas permeable
filter through which  the  gas  flows.  The solid absorbent may be renewed by
heating (API, 1976).

    Hydrates usually are  prevented  or removed from  the  gas  stream  by  one
of  three  methods.   The first  method  is to remove  the  water,  and  various
ways of doing this have been described.  Another method is to heat  the  gas
stream to keep  the hydrate  from becoming saturated in the gas.   When using
the latter method, heating has to be repeated at  every  point where  hydrate
formation  is likely.   The  third  method  of hydrate control  is to add a
chemical to  the gas stream  to lower the temperature at which  the  hydrate
will  precipitate  (i.e., "antifreeze agent").  Alcohol  is usually used  for
this.  With  the hydrogen  sulfide  hydrate,   a solid  filter can be  used to
remove the hydrate.   As the gas stream containing  hydrogen  sulfide passes
through this  filter, the gaseous  hydrogen  sulfide  is converted to solid
iron  sulfide  (API,  1976).   These  filters  cannot  be  reused  and  must be
properly disposed of.

    Once  removed,   free  water may  be  accumulated  in  tanks,  pits,   or
impondments pending disposal.
                                   1-1-26

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    Other  impurities,  such as  hydrogen sulfide and  carbon dioxide,  must
also  be  removed  from the  gas  stream.   The  removal processes  vary  from
absorption to  chemical reaction.   All of these removal  processes generate
waste material.

    Produced  water  disposal   is  described  in the  previous section.  Oil
Production Operations.
                              WASTE GENERATION

    This  section identifies  the  sources of  wastes considered  within the
scope of this study and presents  a  methodology,  or the means  by which EPA
will develop  the methodology,  for generating national estimates of volumes
for  major  wastes  (i.e.,  drilling  fluids,  well  stimulation  and  well
completion  fluids,  workover  fluids,  produced  fluids).    In addition,  a
brief  literature review  is presented.   Quantitative  estimates of  waste
volumes will be  completed for inclusion in the final Report to Congress.

    The methodologies  presented herein have  inherent  limitations.  Some of
these limitations include:

      Oversimplification;
      Incomplete  accounting  of  wastes  generated  (i.e.,  accounts  for
       drilling  media  but  not  other  associated  wastes  such  as  well
       treatment/well completion fluids, deck drainage, sewage, etc.);
      Lack of accounting for drill cuttings and formation fluid; and
      Lack of accounting for drilling media makeup water.
                                   1-1-27

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    Nevertheless,  these  limitations  do  not  preclude  the  Agency  from
calculating  estimates  of  waste  volumes.   The  Agency plans  to  use  the
method(s)  presented herein (or  combinations  thereof)  to  estimate  waste
volumes.   Waste  volume estimates  will be used in  the  risk assessment and
economic analysis (see Part IV, Risk Assessment).

    For this  preliminary  technical  report, the potential  wastes generated
from  oil  and gas  exploration,  development, and  production activities are
listed  in  Table  1-2.   Not all of these  wastes are necessarily  within the
scope of the project as discussed in the Introduction.

Literature Review

    EPA has conducted  an  extensive literature review of both published and
unpublished reports addressing the sources and volumes  of  wastes generated
from  the   exploration,  development,  and production activities of  oil  and
natural gas.  One aspect  of this  process was a review  of  EPA's  literature
in this area.  This  includes the EPA  1976  Oil  and Gas Extraction Industry
Development  Document  for  the  Office  of  Water's  effluent  limitations
guidelines  (See   Appendix  A  -  EPA)  and  the  1985  Proposed  Development
Document for  the  offshore segment of the oil  and gas  extraction  industry
effluent limitations guideline.

    The  disposal of  wastes  associated  with  oil  and gas  drilling  and
production has been an  increasing concern  over the last five  years.   As  a
result, the main  objective  of most of the  literature  has  been to evaluate
disposal practices of the  given waste  in a given  area of  reporting,  or  to
present case  studies.   Therefore, any reporting  of  volumes of waste  has
been a minor objective, if performed at
all  (Waite et  al,  1983;  Eck  and  Sack,  1984;   Elmer E.  Templeton  and
Associates, 1980).
                                   1-1-28

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               l o tat ion/Development

                 Drilling media
                                                              6.
 I
t^i
>0
                 a.
                 b.
                 c.
          Water-base drilling fluid system
          Oil-base drilling fluid system
          Pneumatic drilling fluids system
                    Air
                    Foam
                    Hist
                    Aerated mud
     d.   (Some) produced fluids

2.   Drill cuttings

3.   Deck drainage

4.   Well completion fluids/well treatment fluids

5.   Well Stimulation fluids

6.   Packing fluids

7.   Waste lubricants, waste hydraulic  fluids, waste
     solvents, and waste paints

8.   Sanitary Waste

Production

1.   Produced waters (oil and gas)
               Skimmed solids from air  flotation units
2.   Produced sand
3.   Workovet fluids
               Cleaning fluids
          -    Packing fluids
               Bailing fluids
               Deck drainage

4.   Field tank bottoms
               Gun barrel
               Free water knockout (FWKO)
               Stock tank(s)
               Other production tanks
               Skiniuing surface inpoundntents, pits, and
               tanks

5.   Waste crude oil
     Waste specialty chemicals, waste lubricants, waste
     hydraulic fluid, waste motor oil, waste paints; waste
     solvents
7.   Sanitary Waste

8.   Waste associated gases (CHj &

9.   Waste triethylene glycol (TEG)

10.  Gathering pipelines to central oil and gas
     separation facilities
               Hydrostatic test fluids
               Pig wax
               Filters/slug catchers

11.  Secondary and tertiary production operations
               Produced water
               Tank bottoms [all sorts - be more specific]
               Filter media (solid waste)
               Water treating residues
          -    Pipeline pigging waters (prior to separation
               facilities)
               Workover fluids
               Waste fluids from compressors, turbines, and
               boilers
               Waste paints, waste solvents, waste specialty
               chemicals
          -    Waste associated gases
               Waste crude oil
               Dehydration units (waste TEG)
               Waste scrubber sludges
               Sanitary Waste
                                               Table  i-?:   List of Potential  liases

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    Many of the reports  collected  address  a single waste such  as  drilling
fluids  (Canter,  at  al.,   1984;   Freeman  and  Deuel,  1986;  West   and
Snyder-Conn, 1985), pit  fluids  (EPA, 1984),  drill  cuttings  (Michigan  Oil
and  Gas  Association,  1984),  or  produced waters  (Elmer E.  Templeton  and
Associates,  1980;  Morton,  1983;  Herrold,  1984;   Coleman   and Crandall,
1981).   Some  documents  attempt  to  discuss  both  drilling  fluids   and
produced waters (Waite  et  al.,  1983; EPA, 1985a;  EPA,  1985b;  API,  1983).
Few  studies  attempt  to address  other oil  and  gas "associated  wastes"
(Waite et al., 1983).

    Almost all of the  literature  is  either site-specific  (Heitman,  1985;
Manuel,  1982;  CH2M  Hill,  1983),  State-specific  (Morton,  1984; Birge  et
al.,  1985),  or regionally-specific  (Murphy and Kehew,  1984;  Alaska  DEC,
1983;  Freeman  and Deuel, 1986;  Powder River  Conservation District,  1986).
None of the literature addresses the wastes generated from  the  oil  and gas
extraction  industry from a  national perspective.   Data  reporting  volumes
for  the  two  main  wastes,   drilling  fluids  and   produced  water,   are
periodically presented  (Waite et  al., 1983; Eck and Sack,  1984; Wilkerson,
1984;  Rafferty,   1985).   Of  all  the  wastes  generated,   produced  water
figures  are  reported  with  the  most  frequency,  followed  by  drilling
fluids.  There  are many reports  that  address  the  waste   and/or  disposal
practice  without  waste  volumes reported  (API, 1983;  Freeman  and Deuel,
1986; Canter et al., 1984).

    Two major problems  exist  with  most of data presented.   One problem is
verification  of  the source.  For  example, Rafferty  (1985)  stated  that an
estimated  315  million barrels  of  waste  drilling  fluid  are generated  by
onshore   oil  and  gas  drilling  activities.   There   is   no  supporting
documentation  to   verify that  number,  however.    The   second   problem  is
determining  how  to evaluate data when they are  derived  using different
approaches.
                                   1-1-30

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    For  example,  EPA  has  received two  recent submittals  addressing West
Virginia brine production.   In 1984,  Eck and  Sack  estimated  West Virginia
brine  production  at  11.6  million  barrels  annually.   In  1986,  the  West
Virginia Oil and  Natural Gas Association and  the  Independent Oil  and Gas
Association  of West   Virginia  (hereafter  "West  Virginia Joint  Survey")
submitted profiles  of average  brine  production for  over  5,000  wells  in
West  Virginia.   The  methodology  and documentation  of both  estimates are
illustrative  of   the   difficulties  encountered  when  evaluating  previous
waste volume estimates.

    Eck  and Sack  based their  estimate  on  information  from  a variety  of
sources and on assumptions.  The number of producing oil and  gas  wells for
1981  was  obtained  from  the  Interstate  Oil Compact  Commission  (IOCC,
1982).  Estimates of brine  production per well were obtained  from a report
on produced water  volumes  in two districts of Pennsylvania (Waite,  et al.,
1983).   As  shown in  Table 1-3, Waite,  et al., presented only  ranges  of
produced fluids observed from a few specific  Pennsylvania  areas.   Eck and
Sack  apparently  assumed that  the  average  of the  product water  volumes
paralleled  West  Virginia  brine production.   This  is  a  major  assumption
that  overlooks the  effects of the different geologies of  Pennsylvania and
West  Virginia, the  relative  ages  of wells  (i.e., older  wells produce more
water),  and local production  practices.   In  addition,  the format of the
Waite,  et  al., production  estimates  was presented  in terms  of  "deep gas
wells,"  "shallow gas  wells," and so  on.   This  situation  appears  to  have
compelled Eck  and  Sack to  assume ratios of  "deep  gas  wells," "shallow gas
wells," and so forth  in West Virginia for  purposes of estimating volumes.
Table  1-4  presents some of  the assumptions  and calculations of produced
water in West Virginia.

    The  1986  West  Virginia Joint  Survey  used a  different  approach  to
illustrate brine production  ranges  in that State.   A survey  was  conducted
                                   1-1-31

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                              TABLE 1-3
Development Areas

I.  Shallow Oil

    1A. Venango
        District

    IB. Bradford
        District
                    ESTIMATED WASTE FLUID VOLUMES
                           IN PENNSYLVANIA .
     Waste Fluid Type

Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
(After 6 months of pumping)

Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
(After 6 months of pumping)
     Ranges In
  Waste Fluid
Volumes Per Well

  *  0-2,000 Gal.
      26,000 Gal.
     1-2 BBL/Day
  (42-84 Gal/Day)

  *  0-2,000 Gal.
      30,000 Gal.
     1-2 BBL/Day
  (42-84 Gal/Day)
 II. Shallow Gas

     Upper Dev.


III. Deep Gas

     Medina Fin.
Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
  *  0-5,000 Gal.
      40,000 Gal.
     0-1 BBL/Day
   (0-42 Gal/Day)

  * 0-25,200 Gal.
      58,800 Gal.
     2-4 BBL/Day
  (84-168 Gal/Day)
* Estimated volumes of fluids produced during drilling, does not
  include top hole water or ground water encountered before surface
  pipe is set.

  These estimates apply only to air rotary drilled holes.

  All ranges are considered typical for the type of well indicated.
  Individual wells or groups of wells in selected locations may
  differ significantly from the ranges indicated here.
Source:  Waite, B.A., Eeauvelt, S.C., and Mood, J.L., 1982, Cil and
         Gas Well Pollution Abatement Project ME No. 81495, Part C.
         Moody and Associates, Inc. Meadeville, Pa. Pg. 52

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                              TABLE 1-4

          ESTIMATE OF BRINE PRODUCTION IN WEST VIRGINIA

Assumptions:

  o  Daily volumes of brine produced per:

                    Deep gas well    - 2 BBL/day
                    Shallow gas well - 0.35 BBL/day
                    Shallow gas well - 1.2 BBL/day

                 (Above values chosen from Table 1-3)

  o  90% of Gas wells are "shallow"
     10% of Gas wells are "deep"
     100% of Oil wells are "shallow"

Given:

  o  No. of producing wells in West Virginia in 1981:

          Gas wells - 26,925            Oil wells - 14,700

Calculate daily brine production per gas well based on above
information:

      (0.90 x 0.35 BBL/day) + (0.10 x 2 BBL/day) =0.52 BBL/day

Calculate annual brine production:

  o  Gas wells:

       0.52 BBL brine/day/well x 26,925 wells x 365 days/yr

     = 5,110,365 BBL brine/year

  o  Oil wells:

       1.2 BBL brine/day/well x 14,700 wells x 365 days/yr

     = 6,438,600 BBL brine/year

  o  Total produced brine:

       5,110,365 BBL brine from gas wells/yr

     + 6,438,600 BBL brine from oil wells/yr

     = 11,548,965 BBL brine/yr

     = 11.6 x 106 BBL brine/yr
Source:  Eck, Ronald W. and William A. Sack.  1984.  "Determining
         Feasibility of West Virginia Oil and Gas Field Brines as
         Highway Ceicing Agents, Phase I, Volume II -
         Appendices."  WVDOH Research Project 68.  West Virginia
         Department of Highways in cooperation with U.S.
         Department of Transportation and Federal Highway
         Administration.
                              1-1-33

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of 5,232  wells in  West  Virginia, and  the results are presented  in Table
1-5.    The  results  are  informative  but  not  concrete.   In  fact,  major
assumptions  would  still be  required to  project West Virginia  production
from Table 1-5.

    An interesting  comparison of  the  Eck and Sack and West  Virginia Joint
Survey  results  is  possible  by  back-calculating  total  estimated  brine
production (on a per-well basis) from Eck and Sack as follows:

    Given:  Total estimated brine production = 11.6 x 10  BBL/yr

    Calculate:  Unit brine production for:
                              5.1 x 106 BEL brine/yr
               Gas wells:                         1
                              161,251 MMCF gas/yr
                         =31.6 BBL brine/MMCF gas
               ...   ...       6.4 x 106 BBL brine/yr
               Oil wells:  	2
                              2.433 x 106 BBL oil/yr
                         =2.63 BBL brine/BBL oil
    These  results  are  not  inconsistent  with  the  results   of  the  West
Virginia  Joint Survey presented  in Table  1-5.   These examples were not
selected  to  say whether one number  calculated  is potentially  better than
the  other,  but  to  illustrate  how  carefully  numbers presented  in the
literature for  any waste will have to be evaluated.

Exploration  and Development Wastes

    As  shown   in  Table  1-2,  wastes   associated  with  exploration  and
development  are  largely drilling media (the media used to  drill,   i.e..
                                   1-1-34

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                                               TABLE 1-5

                                  WEST VIRGINIA  PRODUCED WATER SURVEY

                                               2,799 Gas Wells
Gas Vol .
0-10
10-30
30-60
>60
TOTAL
% of TC/TAL
i
i
in
Oil Vol.
BOPD
0-1
1-5
5-10
>10
TOTAL
% Of TOTAL
No Prod.
Water
676
423
275
91
1,465
52%
No Prod.
Water
447
283
19
5
754
3.1%
0-10 BPM1
Prod. Water
143
663
182
137
1,125
40%
0-10 BPM
Prod. Water
491
62
3
2
558
23%
10-20 BPM
Prod. Water
5
31
21
24
81
3%
2
10-20 BPM
Prod. Water
121
28
0
0
149
6%
20-30 BPM
Prod. Water
0
32
47
4
83
3%
,453 Oil Wells2
20-30 BPM
Prod. Water
64
20
2
0
86
3%
30-100 BPM
Prod. Water
0
3
22
5
30
1%
30-100 BPM
Prod. Water
130
63
2
0
195
8%
>100 BPM
Prod. Water
1
0
11
3
15
1%
>100 BPM
Prod. Water
404
305
1
1
711
29%
Total
825
1,152
558
264
2,799

Total
1,657
761
27
8
2,453

% of
Total
30%
41%
20%
9%


% of
Total
63%
31%
1%
1%


*BPM is defined as Barrels Per Month
Doeu not include any waterflood producing wells.
Source:   Independent Oil  and Gas Association of West Viiginia and West Virginia Oil and Natural Gas
         Association.  1906.  "Oil and Gas Produced Water Survey."  Submitted to EPA April 30  .

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fluids, air, gas),  cuttings,  and deck drainage.  In general,  these wastes
are temporarily  (up  to  1 year) or permanently  disposed  of into an earthen
pit, the  reserve pit.   Some  long-term disposal  options are:   dewatering
and  burial,  land  farming,  road  spreading,   and  centralized  pits  (see
Industry Waste  Management  Practices).   Well  completion and/or  treatment
fluids, along  with well  stimulation  fluids,  also may be  disposed  of into
the reserve pit. Smaller volume wastes such as  waste  lubricants,  hydraulic
fluids,  solvents,   paints,  and  sewage  may either  be  commingled in  the
reserve pit or disposed  of  separately,  which can be subject to  control  by
regulatory programs.  At this  time,  volume estimates will not be developed
for small miscellaneous  waste  sources; any  incremental  estimate of  these
waste volumes  is not expected to significantly increase  the overall volume
estimate per well site for exploration and development, sources.   Also,  EPA
is  still   defining  the  scope  of  this project,  which  could affect  the
Agency's need to quantify volumes of wastes generated (see Introduction).

    Virtually every  aspect  of  drilling operations affects the quantity  of
wastes  generated.    Table   1-6  presents  a  listing  of  factors  that  can
influence   waste   volumes.    These   factors   may   influence   volumes
individually,  but   they usually  are  so  strongly   interrelated  that  the
effect of a single factor can be obscured.

    For example, anticipated  downhole  geology  dictates the  drilling  media
selected.    When water-bearing formations  are  encountered,  however,  waste
volumes  increase  (via   water  displaced  to the  surface).   Further,  the
addition of  this connate water  causes changes  in  the  drilling  media  for
which  compensation  is   required.   The  addition  of  connate  water  also
contributes to  the  possibility of such problems as  stuck drill pipe.   Once
the drilling media and drill cuttings are brought to the  surface,  the type
and  extent  of  solids  control  equipment  used influence  how  well  the
cuttings  can  be  separated  from  the  drilling  fluid,  and  hence  also
                                   1-1-36

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                            TABLE 1-6

             FACTORS INFLUENCING THE VOLUME OF WASTE

DRILLING FLUIDS, DRILL CUTTINGS, WELL TREATMENT/WELL COMPLETION,

     o    Geology, e.g.  -    Hard rock formations
                              Shale
                              Sandstone

     o   . Well Depth / Hole Size / Casing Program

     o    Drilling media; e.g.
                         -    Mud type
                              Air
                              Gas
                              Foam

     o    Extent of solids control equipment used; e.g.
                              Influences the amount of water
                              added to the circulating mud system
                              Cuttings washing efficiency

     o    Problems encountered during the operation; e.g.
                              Stuck pipe
                              Lost circulation
                              High pressures and temperatures
                              (expected/unexpected)

     o    Service products used; e.g.
                              Types of products used
                              Numbers of products used
                              Solids vs. liquids
                               1-1-27

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influence  the  volume of  waste displaced  to  the reserve  pit.   When  poor
drill   media/cuttings  separation   occurs,   the   drill  media   must  be
continuously diluted  with makeup water to  counter  the  high solids content
of  the media.   Thus, poor  surface  separation  causes drill  media volume
swell.   This   example is  illustrative  of the  interacting   factors  that
affect  final waste  volume.   All of the factors  in  Table 1-6 are similarly
complex.

    Table 1-7 describes factors affecting total  solids  content in weighted
drilling  muds.   The  table  further  illustrates the  number  and  type  of
factors  introducing variability into  volume  estimates.   Even with  these
factors  in mind,   EPA  will  fulfill  the   larger objective of  collecting
pertinent  information by  examining  the  data collected  through  standard
industry recordkeeping practices.

    For  example,  drilling contractors keep records  that  routinely itemize
the type and quantities of products used on a given  well;  this information
is extremely site-specific.  The  drill report does  not describe the solids
control  equipment  in use  at  the  site,   however,  nor  does  it  include
freshwater consumption data.   The  information noted on the drilling report
is generally unavailable to the Agency because it is not  required in  State
or  Federal  regulatory  programs.   Some  drill report  data were  collected
during  the screening  sampling  program conducted  in conjunction  with  this
study  during  June  -  September  1986,   and   will   be  presented  in  the
January 31, 1987, Technical Report.
    Drilling Waste Methodology

    EPA plans to  work  cooperatively with the Petroleum Equipment Suppliers
Association  (PESA)  to  develop  a methodology  to  estimate  drilling  waste
                                   1-1-38

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2823
       Table 1-7   Factors That Control  Total  Solids Content in Weighted Muds
                  (Numbered in Order of  Decreasing Influence)
Item
 Contributes to
low total  sol ids
Contributes to
high total solids
                         First Order of Importance
la Type of formation



Ib Bit cutter type


2  Mud density

3  Bit jet horsepower

4  Annular lift


5  Rig shale shaker
Medium hard
UnconsoTidated sand
and gravel

Long teeth
Minimum

Adequate

Adequate
Constant efficient
operation

Second Order of Importance
 6   Full-flow
 7   Rig  screen mesh

 8   Fine screen used
    to return to system
    part of the liquid,
    clays, and silts
    from hydrocyclone

 9   Removing directly
    from system a
    fraction of clay
    and  1iquid with
    centrifuge, while
    maintaining weight
    and  volume

 10 Centrifuge used to
    return to system
    the  1iquid and
    clay from
    hydrccyclone
    unaerflow (see No.6)
Unconsolidated silt
Very hard
All Small diamond /
Slow drill ing

Above minimum

Inadequate

Inadequate (rare  if hole
is near  gauge size)

Bypassed
Effectiveness varies with
formation and bit type

Fine*

Secondary separation does
not further reduce solids
Varaible effect on  total
solids  content, but  good
viscosity  reduction
Not  applicable
 Coarse'

 Variable  increase in
 total  solids  content,
 but  more  than centrifuge
 salvage  (see  Mo.  10);
 no viscosity  reduction

 Primary  separation cannot
 increase  total  solids
 content
 Secondary  seoaration
 cannot  raouce  solias
 content; not normally
 recommended on water-
 base  weignted  muas
 Variable increase in
 total  solids content, but
 less than screen salvage
 (see No. 8); no viscosity
 reduction

-------
2823
                              Table 1-7.  (Continued)
Item
 Contributes to
low total solids
Contributes to
high total solids
11 Chemical  treatment
   to prevent shale
   cuttings  dispersion
Variable (but may help
screen removal?)
Normally does not cause,
but decreases viscosity
to total-solids-content
ratio
12 Chemical treatment
   to disperse shale
   to clay-size
   particles
Variable, but can help
centrifuge removal of
shale as clays
Normally does not cause.
but increases viscosity
to total-solids-content
ratio
      Whether  or  not  a  finer  screen  will  help noticeably  in this  primary  separation
      depends  upon  the  comparative  size  relation between  the  cuttings  reaching  the
      surface  and the screen  mesh,  and whether  or not  the finer mesh can  be
      maintained  in proper operation.  If a  "fine"  screen cannot  operate  properly at
      full  flow,  a  coarser screen will maintain lower  total solids  content  than a
      finer screen  that is bypassed.
 Source:   Chilingarian, G.V.  and P.  Vozabute.  1983.   Prilling and Drilling Finds.
           Elsevier Science Publishing Co., Amsterdam,  Holland,  pp. 450-451.
                                       1-1-40

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volumes generated  annually.   PESA is an  industry trade  organization that

has a  subset  membership of drilling service and  product  supply companies.

Members  of  PESA  have  substantial  technical   expertise  in  estimating

drilling   supply  needs   on  a   site-by-site   basis.     They   also  have

considerable information on types and quantities of materials consumed.


    Individual sources  of  wastes that  will be considered  in designing the

methodology  include  drilling  media, well  completion treatment,  and well

stimulation fluids.


    Some of  the methodologies  considered for  estimating exploration and

development wastes are:
       Determine the average  well  depth nationwide. Develop an estimate of
       the  volume  of drilling  fluids used  (either  per  foot  or per  the
       determined  average  well depth) based on site-specific  or standard
       industrial  calculations  (Chilingarian,  1983).    National   volume
       would be  estimated  by  multiplying the volume of drilling fluid used
       by the average number  of wells drilled over the past  three  to five
       years.

       Interview  and  gather  data  from  operators  by  State  and/or  by
       region.  Extrapolate these data to the national level.

       Develop a model to  consider  all the possible  variables  or only the
       most  important  shown  in Table 1-6.  This method has  been rejected
       as a viable alternative because of  complexity,  number  of variables,
       and the time and cost involved.

       The  methodology  (or  combination  of  methodologies)  used will  be
       determined by the quantity and reliability of the data  gathered.
Production Wastes


    As  shown on  Table 1-2,  the main  wastes  associated  with  production

activities  are  produced  water,  produced  sand,   workover  fluids,   tank
                                   1-1-41

-------
bottom, waste  crude oil, and  waste triethylene  glycol.  Depending on  the
waste,  the  primary methods  of  disposal  are  injection  into  subsurface
formations,    deposition   into    earthen    pits    (production   pits   or
impoundments),  discharge  to  surface  waters,   and  road  spreading  (see
Industry Waste Management Practices).   All  of these methods are subject to
control by  existing State and Federal regulatory  programs  (see  Appendix
A).  This technical report  discusses the methodology used  to estimate  the
volumes of  produced water.   Although  EPA does not present  a  methodology
for associated  wastes  generated  from  production activities,  as discussed
herein, the Agency  is  contemplating various courses of action  to evaluate
these wastes.

    For  example,  while  EPA   recognizes  that  wastes  are  generated  from
secondary and tertiary enhanced  recovery operations,  the Agency  will  not
include a  methodology  for estimating  the  volumes in this  report.   EPA is
coordinating with the  Department  of Energy  in  this area  in order  to  use
the Department's  expertise  and existing  data prior to generating any  new
estimates.

    EPA has  considered generating  estimates of  volumes  of  tank  bottoms,
waste  crude  oil,  and  waste  triethylene glycol,  but this  technical report
does not present such a  method for several  reasons. First,  EPA found that
the existing  literature  lacks any useful data.   Second,  the  industry is
not  routinely  submitting  pertinent  waste  volume   data   to  regulatory
agencies  because  of the absence  of such  regulatory requirements.  Third,
there  are many  significant  factors that can  influence the  volume produced
(see  Table  1-8).    At  this  time,  EPA  is  considering the alternative  of
developing  an industry profile and visiting  commercial  operations  (that
dispose of  or reclaim  these wastes) in various parts of  the country to get
an  indication of  the  amount  of  waste tank  bottoms  or  crude oil  they
routinely dispose of or reclaim.
                                   1-1-42

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                       TABLE 1-8

         FACTORS INFLUENCING VOLUMES OF WASTE

           TANK BOTTOMS AND WASTE CRUDE OIL


o    Type of crude oil, type of gas

o    Single well vs. central battery vs.  field separation
     facility

o    Numbers, sizes, and types of vessels

o    Method utilized for separation/dehydration -
     gravitational heater treater

o    Age and efficiency of equipment used

o    Settling time/velocity

o    Any capacity for recirculating settled material,  at
     what points,  and how many times
                       1-1-43

-------
    As  stated,  EPA  will estimate  annual  quantities  of  produced  water.

Table  1-9  lists  the major  factors  influencing  the  volumes of  produced

water.  Even with  all  these variables,  estimating produced  water  volumes

is possible, since many  States require that volumes be  reported (Herrold,

1984b).  The following methodology  outlines how  EPA expects  to calculate

volumes of produced water.  EPA welcomes comments on this procedure.


    Produced Water Methodology


    The following  method  is  proposed  for use  in determining  a. national

estimate of volumes  of  produced water  generated  from primary,  secondary,
and tertiary oil and gas production operations:
    1. Establish the number of  producing oil and gas wells by State and by
       zone (EPA, 1986), as well as a total for the United States.

    2. Establish a range  of  barrels of  oil produced  and the millions  of
       cubic feet of natural  gas and gas  liquids  produced  by State, and a
       national total.

    3. Complete  and  update   a  table   similar  to  Table  1-10   (Herrold,
       1984b).    The  table will list  which oil  and  gas States have  any
       produced water reporting  or  manifest systems.  Table  1-11  presents
       an example from  the State of Alaska (Alaska Oil and Gas Commission,
       1986).

    4. Review volumes reported  in  the  literature  (Elmer  E.  Templeton  and
       Associates,   1986;  Herrold,  1984a).   Use  estimates and/or  water:
       oil/gas  ratios presented  in  the EPA  Eastern and  Western Workshops
       Proceedings  presented by  State  personnel  where they can be  verified
       (EPA, 1985a;  EPA,  1985b).   Review  the data  gathered  during  the
       screening/sampling  program.   This  source  of  information  will  be
       valuable  in  those  States where  no  formal  reporting  requirements
       exist and/or the  data  are not computerized.

    5. Make use  of  regional  oil  and/or  gas  to  water  ratio patterns  to
       estimate  volumes  for  States  where  only  hydrocarbon  production
       information  is available.

    6. Make  use  of  data from  trade  organizations (WVIOGA/O&NGA,  1986),
       research  institutes,  and/or  other  Federal  agencies  (such  as  the
       Department of Energy)  when possible.
                                   1-1-44

-------
                       TABLE 1-9

         FACTORS  INFLUENCING VOLUMES OF WASTE

                    PRODUCED WATER

o    Type of producing well; e.g.,
                         Oil
                         Gas
                         Oil and gas

o   . Depth

o    Type of reservoir; e.g.,
                    -    Light crude
                         Heavy crude
                    -    Wet gas

o    Size of reservoir

o    Age of the well;  e.g.,
                         The older the well, the more
                         associated water

o    Water to product  (oil, gas, oil and gas) ratio

o    Type of production operation; e.g.,
                         Primary
                         Secondary
                         Tertiary
                        1-1-45

-------
                           TABLE I-10

                   PRODUCED WATER RECORD-KEEPING IN
                    SELECTED STATES AND PROVINCES
                  Production Records
Disposal Well Records

1.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
19.
22.
23.
24.
27.

Annual Monthly
Texas x
California x
Louisiana
Oklahoma
Wyoming X
New Mexico x
Kansas
North Dakota x
Mississippi x
Michigan X
Montana X
Colorado X
Illinois X
Florida X
Ohio
Indiana
Pennsylvania
West Virginia
New York X
Ontario X
Annual Monthly No Recorc


X
X
X
X
X
X
X

X



X
X
X
X

X
Source:   Eerrold, Jeffrey E. 1984.  Saltwater Disposal and Reccrdkeepin:
         in Selected States and Provinces.  Geological Survey Division,
         State Michigan. April 5. p. 6.
                                 1-1-46

-------
                                                 TABLE  J-ll
                          201,639
                        6,615.161
OIL FIELDS I ALL  POOLS I  CHUDE OIL
BEAVER CREEK
GRANITE POINT
KUPAHUK RIVER
HCARTMUR RIVER
MIDDLE GROUND SHOAL
PRUOMOE HAY
SWANSON RIVER
TRADING UAY
 TOTAL ACTIVE FIELDS
    DAILY AVERAGE
  NCL PRODUCTION
                          279.221
                       M7.51 7.0*4 ii
                          172.8*49
                      	62^281
                       57.673.365
                         1.860,MlI
KUPARUK RIVER
MCARIIIUR RIVER
PHUDIIOE BAY
SWANSON RIVER
TRADING UAY
 TOTAL ACTIVE FIELDS
    DAILY AVERAGE
     CAS FIELDS

BEAVER CREEK
BELUGA RIVfR
EAST UARHOW
KENAI
LEWIS RIVER
MCAIMHUn HIVCn
MIDDLE GROUND SHOAL
NOIUII COOK INLC1
SOU1H BAHHOW
TRADING UAY
  T01AL ACIIVE FIELDS
    DAILY AVERAGE
 .INJECTION PROJECTS

 GRANITE  POINT
 KUPARUK  RIVER
 MCARIHUn RIVER
 MIDDLE GROUND SHOAL
 PHUDMOE  BAY
 SWANSON  RIVER
 THAD INC  BAY
  TOTAL ACTIVE FIELDS
     DAILY AVERAGE
                           135.093
                            (4.357
                         CONDEN.
                          Ullll. I
                           OIL
                          IUUL1
                                      WA1EH
                                      IHIII I
        15
    8*4, 121
 1.976.567
 1.651.671
   *413,197
 9.912.9'l5
   158,006
_ 122^8.52
 1*1,596.376
   (470,650
   WATER
   I Dill. I
                                          4.971
                                          2.2*16
                                             10
                                          1.010
                                          B.239
                                            265
                                       WATER
 _ L!猾U _
    683,613
 1*4,201.612
  1. 191.9*18
    619,160
 36. 102,031
                                     _
                                     5*.012. 167
                                       1.76B. 13*4
CTION SUMMARY BY ACTIVE FIELDS
GAS PKOD. ADOL CUM
IMCFI WEILS COMPS
9,770 2
20*1,326 29
11,317.013 290
397.229 6*1 8
180,1472 Ml 2
89.11*4.326 5*15 M.
6,383.670 33
	 26^521 	 22 	 2 	
109.703.397 1,036 19 5,
3.536,819 T01AL INACTIVE
TOTAL ALL FIELDS 5.

TOTAL INACTIVE
FOII MAMCII.
CRUDE OIL
_LLU 	
3.210.1(15
101.67*1,562
222.93*4. 126
508. (418.938
1*4?, 8/9,226
1196.6*12,867*
203.712.656
_flLJ28271
77*1,001.263
	 155.526
77*4, 156.859
CUM NGL
.JI'Wl 1
915. /6*4
8,l|*l2.60l
1.966.069
1,130.065
356.765
12.611.3*4*1
0
TOTAL ALL FIELDS T2. 811, 3*4*4
CAS PROD. ADDL CUM CONDEN.
IMCFJ WE, IIS, COMPS IIIHLI
1,566.090 *4
2,2*46.507 13
60,106 M
6,971,96*4 35 21
210,562 2
619.800 5
f4i4,230 1
3,933.501 12
6*i.'l53 6
1*1.790 1
15.732.103 83 21
507,1467 TOTAL INACTIVE
11.877
11.677
0
T01AL ALL FIELDS 11,677
GAS INJ. ADDL CUM OIL
IMCFI WELLS COMPS IUUL
20
9,132,506 163
7 1
19 1
81,032.023 125
8.113.868 8
98.278.397 3M3 3
3,170,270 TOTAL INACTIVE
T01AL ALL FIELDS
13.012,875
13.012,875
0
13,012,875
1966
CUM WATER
11HILI
17,678
5.623,205
58. 6 39. Oi|(4
106. 211. (42*1
6*4. 8146.656
 211. 21*4. (406
6*4, 123.609
	 _56^J6K(502
2*49.638, lO'l
2*19
6*19,636.353
CUM WATER
(HIM 1
73.591
010
1O9
M33.2I5
31
77.85*4
12
585,622
0
585,622
CUM WATER
1217399.398
112.178,663
83*4.736.901
2*46.366.122
7/5,93*4,095
8.1471.561
_ 	 12Q.229.JlJl
2.220.077,1457
n
2.220, 077. '157
CUM CAS
IMCFI
1.320,091
68.008.063
263. 269. *40I
187,275.l)ii5
7M,6l'j.y<0
5,712.4403.995
1,597,391.069
. 58^.16.0^6.0
77963. 72'4.7獺l
*l'.>6
7.963,725.200
CUM CAS
( MCF J
3*4.320,925
210.BU6.2Vl
2.9*19.0147
1,661. 156.396
3,025. 1 J6
116.6I6.2U6
1.622, 1 18
7*4*4. "477, 620
16.798.6*16
2. (423.006
2,61*4. 199. *456
10. Ol>9. 167
2,032,268,623
CUM CAS
IMCFI
216.721,825
63.03*4
5,172,1?1.2449
1,613.955,90*4
7.202,6(i2.092
5獻7.*I57
7, 203, *409. 5*19
                                                           "INCIUDES  1,570.3*47  BIILS  OF CONDEHSATE
                                                          晻INCLUDES 7*4.209,'4/5  BOLS  OF CUNDENSAIE
                    Source:   Alaska Oil  and  Gas Conservation  Commission.    1986.
                                The Alaska  Report.   May 28:   Section  IX,  p.   1.

-------
7.  Assimilate produced water volume  estimates  by State,  by zone,  and
   nationwide.

8.  Finally,  cross-check  these  estimates  by taking  the oil  and  gas
   production figures  generated  by  State,  by  zone,  and  nationally,
   then  calculating  a series  of  oil  and/or  gas to  water ratios  by
   zone, which  are  then weighted  according to production  figures  to
   determine a national estimate.
                               1-1-48

-------
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Alaska   Department   of    Environmental   Conservation.     Division   of
Environmental Quality Operations.   1983.   Environmental Quality Monitoring
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Kenai Wetlands.   March 1983.

Alaska Oil and Gas Conservation Commission.  The Alaska Report.  May 1986.

American  Petroleum Institute.  1976.    Primer  of  Oil   and  Gas Production,
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American  Petroleum  Institute.    1983.   Introduction  to  Oil   and  Gas
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Birge,  W.  J.,   et  al.   1985.   Recommendations  on  Numerical Values  for
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CH2M  Hill.   1983.   San   Ardo  Field  -  Produced Water  Disposal/Reuse  -
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Coleman, Wendy  Blake and  Douglas A. Creendall.   1981.   Illinois  Oil Field
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Eck,  Ronald W.  and  William  A.  Sack.   1984.   Determining Feasibility of
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                                   1-1-49

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                                   1-1-50

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U.S.  EPA.    Industrial  Technology  Division.    1985.   Proceedings  of  the
Onshore Oil and Gas State/Federal Western Workshop.  December.

U.S.  EPA.   1986.   Oil and Gas Exploration, Development, and Production -
Sampling Strategy.  May 1986.

West, Robin  L. and Elaine Snyder-Conn.  1985.   The Effects  of  Prudhoe Bay
Reserve Pit  Fluids on the Water Quality and  Macroinvertebrates of Tundra
Ponds.   U.S.  Fish  and   Wildlife  Service,   Northern  Alaska   Ecological
Services, Fairbanks, Alaska.   August 5.

West  Virginia Independent Oil  and Gas Association and  West Virginia Oil
and Natural Gas Association.   Meeting with EPA, April  30, 1986.
                                   1-1-51

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Wilkerson,  Daniel  L.   1984.   Survey  of  Drilling  Mud  Use and  Disposal,
Staff   Report.    Alaska   Department   of   Environmental   Conservation.
September 1.

Williams,  B.  B.,  J. L.  Gidley,  and  R.  S.  Schechter.   1979.   Acidizing
Fundamentals.   Society of Petroleum Engineers of AIME, pp.  1-17,  92-102.

William, H. R. and C. J. Meyers.   1984.  Manual of Oil and  Gas Terms.   6th
Edition.  Matthew Bender Co.,  New York.
                                   1-1-52

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                                  CHAPTER 2
                     INDUSTRY WASTE MANAGEMENT  PRACTICES


                                INTRODUCTION

     This  section  is  a  preliminary   review  of   control   and  disposal
techniques currently used  by industry for wastes from onshore  oil and gas
exploration,  development,  and  production  operations.   Descriptions  are
based  on  specific  State  or  Federal  regulatory requirements,  published
information,  professional  observations  during  screening  sampling,  and
interviews.   In  addition,  the  practices   described herein  address  the
management of  major waste  streams (e.g., drill  cuttings,  drilling  muds,
produced  fluids,  etc.)  identified in  the  previous section titled  Waste
Generation. This section will be expanded for the full Report to Congress.

     Normally,  in  a   technical  review  such  as  this,   a  discussion  of
"current"  and  "alternative" practices  is presented.  In  the oil  and gas
industries, however, waste  management practices are  so varied  (because  of
the  influences of  State  and Federal  regulations,  operator  preferences,
etc.),   that   the   terms   "current"   and   "alternative"   are   often
interchangeable depending on the  context. Therefore, this section presents
waste   management  practices  without   distinguishing   their   relative
applicabilities.  Technologies  other  than those  presented in  this review
may be  identified based on the analytical  results  of  the  EPA  screening
                                    1-2-1

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sampling  efforts  conducted  from  June   through   September  1986.   These
sampling  efforts  and  associated  results  are  briefly  discussed in  the
section titled Evaluation of Waste Management Methods.

     Although the  disposal  practices  generally  used  by this  industry  are
not highly  complicated,  they are fraught with variabilities that influence
their ability to protect the environment.  State agencies  can accommodate
these  differences  to  a  large  extent  by  evaluating  waste  management
practices for each individual  case within a general  regulatory framework.
In  some  areas   of a  State, for  instance, unlined  reserve  pits may  be
permitted.   In  other,  more  hydrologically sensitive  areas  of  the  same
State, reserve pits  may be  required to have liners (meeting permeability,
puncture,  and  other  durability specifications),  monitoring  wells,  or  a
leak  detection   system.   Thus,  waste   management  practices  (and  the
corresponding construction and monitoring  requirements) are often tailored
to the specific situation even within a particular State.

     These  variabilities and  the lack of concrete data to characterize  the
extent of  the  practices prevent a definitive  assessment of  the  relative
effectiveness of disposal  options at  this time. The control  and disposal
techniques  presented herein  range  from pilot operations  to long-practiced
methods,  none  of which  have been  verified by EPA  for  treatability  or
economic feasibility.  Thus, it  is  the intent  of this  section to describe
the general management  practices employed for  pertinent wastes.  It  is  not
the purpose of   this  section to quantify  the  number of  sites using  each
waste  management  method  or  to  address  the   effectiveness  of  disposal
techniques.
  In this report, the term "permitted" means that formal permits are
  issued by a regulatory agency for the practice described.
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     One   difficulty   encountered  in.  developing   this   section  is  the
widespread use of  common  descriptive  terms for a variety  of similar waste
management  practices.    Where   descriptive  terms   for  waste  management
techniques  varied, the   most  rational  definition   for purposes  of  this
discussion  was  selected.  The  definition  of  these  terms  is  clarified
herein.

                      CURRENT  INDUSTRY WASTE MANAGEMENT

Onsite Methods of Waste Disposal

     The waste management methods  discussed in the  following  sections  are
divided into four topics:

       Onsite Disposal of Pit Fluids;
       Onsite Disposal of Pit Sludge;
       Closed Systems; and
       Treatment and Discharge Options.

     The first two topics are self-explanatory.  The  section titled Closed
Systems  discusses  drilling  mud   recirculation  systems   and  associated
technology.   The Treatment  and Discharge  Options   section  discusses  two
subcategories  of  the  onshore  segment  of  the oil   and  gas  extraction
industry  effluent  limitations  guideline:   (1)  Agricultural  and  Wildlife
Water  Use  and (2) Coastal Treatment  and  Disposal   (see also  Appendix  A -
EPA).
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     Onsite Disposal of Pit Fluids

     Evaporation/Percolation Pits.    Disposal   of   fluids   by   use   of
evaporation  and percolation  pits  is  the  simplest  and  least  expensive
disposal method.   It requires  no special handling of  the  fluids  and can
often be achieved at the drilling site itself.

     The purpose  of  an evaporation  or  percolation  pit  is  to  use  the
natural  processes   of  liquid  evaporation  or  diffusion  through  soil  to
remove  liquids  from,  waste   drilling  muds,  cuttings,  or  brines.   An
evaporation  pit may be  lined  or  unlined.    Percolation pits  must,  by
definition,  be  unlined.   Evaporation pits  are widely  used  in  areas  of
overall net  evaporation or net evaporation seasons.  Percolation pits are
typically  used  in  areas where  there  is no  potential  for  ground-water
contamination  or  when  percolating  fluids  are  known  not  to  adversely
degrade ground-water quality.

     In many cases,  the evaporation  or  percolation pit  is  the  actual
reserve pit  on a  drilling site.   As  drilling muds  and other fluids  are
added  to   the   pit,  the  evaporation  and/or  percolation  of  the  liquids
reduces  the  volume  of the  contents  of  the  pit.  Evaporation  pits  on
drilling sites that use polymer muds are  especially appropriate,  since the
dried  residue  of  these  muds  often  is  very  low  in  volume.    At  the
conclusion  of  drilling activities,  the  reserve  pit   is  allowed  to  be
completely dewatered by one  or  both of the  evaporation or  percolation
processes.   This method of  fluid disposal is  preferred  at sites  in  which
the reserve  pit is  to be backfilled with the dried solid  wastes  remaining
in the pit.
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     Evaporation pits and percolation pits can also be used for brine
disposal.  Percolation pits used for brine disposal are  less  common,  since
many States have  regulations  prohibiting such disposal.   Some States allow
such pits  if  the  chloride content  is  such  that  no contamination  would
result  if  the  fluids contacted  ground  water.   Several  States,  such  as
North Dakota, and  certain regions of New Mexico,  do  not allow the use  of
evaporation  pits  for  brine  disposal,   except  in  emergency  conditions.
Reasons for prohibiting  this  form of brine  disposal  include  the  presence
of  shallow ground  water,  highly permeable  soils, and/or  inherently high
chlorides  concentrations in  native brines.   In  general,  the  intent  of
regulations addressing brine  disposal  via evaporation or percolation is to
protect ground-water quality.

     Onsite Treatment and  Disposal.   Onsite treatment and  disposal  of
reserve pit wastes  is accomplished by a variety of techniques.  The choice
of  treatment  method  depends   on  characteristics  of  the  waste,  economic
considerations,  and applicable State or Federal regulations.

     Generally,  most  of  the  onsite treatment methods  are designed to treat
the  wastes generated  from drilling  activities.   The   following  sections
titled   Treatment   and   Discharge  Options   and  Centralized   Treatment
Facilities discuss  the  disposal  of  other wastes  such  as  produced  water,
completion fluids, and stimulation fluids.

     Onsite treatment  technologies are  commercially  available for reserve
pit fluids as well  as solids,  typically in  the  form of mobile  equipment
brought  to a drill  site.   Examples of liquid  treatment  methods are  pH
adjustment,  aeration,   coagulation   and  flocculation,   centrifugation,
dissolved  gas  flotation,  and  reverse  osmosis. Chemical   fixation  or
solidification is a method of pit solids treatment.  Usually,  a  treatment
                                    1-2-5

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company  employs  a  combination  of  these  methods  in  conjunction  with
physical separation techniques  in order to treat the  entire  contents of a
reserve pit.  One  possible  treatment sequence is described as  follows:   A
coagulant such  as aluminum  sulfate,  ferric chloride,  or  calcium chloride
is added  to  the  pit  followed by  a  flocculant  (a  natural  or  synthetic
polymer) to  remove suspended  solids  from the liquid  phase.  Depending  on
the  results  of  this   step,  the  liquid may  be  pumped  from the  pit  and
discharged to  the land  surface,  or may  receive  further  treatment  in the
form of  centrifugation or  filtration  prior to final discharge.  The  pit
solids are then stabilized  by mixing in cement kiln dust,  which produces a
cement-like material that is buried onsite (see also Solidification).

     Reverse  osmosis  has  been used  to  treat reserve  pit  fluids.   The
process can be described in four steps:
       Preclarification in the pit by flocculation of suspended solids;
       Filtration of  flocculated fluid  down  to  particles of  one micron
        in size (to extend the life of the membranes);
       Two-stage reverse osmosis  through cellulose acetate  membranes  to
        reduce total dissolved solids;  and
       Disposal  of  clarified  fluid  and  concentrated  fluid  products
        (Moeco, 1984).

     A  unique alternative  to flocculation and filtration of  reserve  pit
waste  is  boiler-evaporation.  A  company  that uses  this  technique  states
that it will  treat  "drilling fluids and  drilling muds"  from  a  reserve pit
by steam-heating  the wastes.   Part of the process  includes  taking  gas  or
oil from the  wellhead  onsite to burn  in  the  boiler that provides steam to
the evaporator (E-Vap Systems).
                                    1-2-6

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     Many States allow  onsite  treatment and disposal of pit contents as an
alternative  to other,  possibly less  cost-effective means  of  disposal.
Most States  do not  specifically require treatment of  pit  contents before
they are buried or land-applied onsite, but treatment is  often  a necessary
step in  order to  comply with limitations set on  pollutant  parameters for
ons i t e di sposa1.

     Among the States that address onsite treatment  of pit contents,  the
most   common  limitations  on  pollutant  parameters   include   pH,  total
dissolved solids,  oil and  grease,  and  metals  such  as arsenic,  cadmium,
chromium,  lead,  and  mercury.    For  example, guidelines  set by the  West
Virginia Department  of  Natural  Resources for the  acidic pit  fluids  from
air  drilling call  for a pH between  8  and 10 for waste that is landspread
"from  oil  and  gas  well  operations."   Other criteria  required  by  West
Virginia  include  a  24-hour  waiting  period between  pH  adjustment  and
discharge  (for  land application  only),  and  reporting  requirements  to
document  the  discharge.   West  Virginia also  requires  some  laboratory
analyses of  pit  waste  samples  in  order  to monitor  compliance with  the
discharge limitations.

     The  type  of  method  used  for  onsite treatment often  depends  on
particular characteristics  of a well  site  in  addition  to the  pollutant
parameters set  by a  State.   For example, the only forms of pit treatment
presently used in Alaska  are  "settling  and  freeze-thaw  concentration  of
contaminants."   That  is,  a   pit  must  go  through  a  one-year  cycle  of
freezing  and  thawing,   presumably   to  cause   heavy  metals   to   absorb
permanently  onto the  drilling  muds in the pit.  The  effectiveness  of this
technique is under debate within the State (EPA - AK, 1985b).

     Finally,  the  choice  of  treatment  method   is   influenced   by  the
proximity   of   reserve   pits   (or   production   tanks)   to   centralized
                                    1-2-7

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treatment/disposal  facilities.   Onsite  waste treatment  is  often used  in
locations where centralized  treatment/disposal facilities are  excessively
distant  or  not  available.   Centralized  treatment and disposal  practices
are discussed in the section titled Centralized Methods of Waste Disposal.
     Onsite Disposal of Pit Sludge

     Pit Burial.  Onsite  burial  of a pit is defined as the disposal of pit
sludge and  residuals  within the  approximate area of  the pit.   The  solids
are  covered by backfilling and  by pushing  in the walls of  the  pit.   This
method  of  disposal  is  very  often  used  for  the  closing  of  a  dried
evaporation/percolation pit.

     In  many States,  onsite burial  of  closed reserve  pits is  the  most
common practice.  Specific  regulations  for  proper closure and burial  vary
from  State  to State.   For example,  time  limits  for  closure  vary.   In
Texas, the facility has 1 year after drilling ceases to  close and  bury the
reserve  pits.   Oklahoma allows  18 months,  while  Louisiana  allows only 6
months.   Kansas has  no time  limit for  reserve pit  closure  (EPA -  KS,
1985b).

     Some  States  require testing  of  pit contents prior to  burial.   Under
Louisiana State Order 29-B, pit solids can be buried only  if the following
limitations are met:
     Arsenic           10 ppm
     Barium         2,000 ppm
     Cadmium           10 ppm
     Chromium         500 ppm
     Lead             500 ppm
                                    1-2-8

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     Mercury           10 ppm
     Selenium          10 ppm
     Silver           200 ppm
     Zinc             500 ppm
     pH               between 6 and 9
     Oil and grease    3% weight
     Moisture         50% weight
     Conductivity      12 mmhos/cm
     In addition, the  buried mixture must be 5 feet below ground level and
must be at least 5 feet above the water table.

     Texas backfill requirements vary according to the type of pit  and its
chloride content.  Permits  may have pit closure requirements; however, the
Texas Railroad Commission requires all pits to be  backfilled  and compacted
for closure after dewatering.

     Kansas encourages burial  onsite,  but has no law requiring backfilling
of pits.   In  geologically sensitive or hydrogeologically  sensitive areas,
onsite  disposal  of  drilling  pit  contents  can  be  prohibited  (EPA  - KS,
1985b).

     Wyoming  pit  closure rules  are included  in  the drilling permits and
may  include   special  provisions such  as  testing  and  treatment prior  to
burial (EPA - WY, 1985b).

     A  modified  version  to  standard  pit  burial  is   the   method  of
encapsulation.  This  is  a disposal method for burial of  solids  in a lined
pit.  After the  pit  is dried,  the top  of the pit  is  lined with  plastic
(presumably the  same type  of liner used  on the pit bottom).   The pit  is
then backfilled and  compacted.   In theory, the  pit solids are  completely
separated  from contact with other soil.  This method is  used to bury pits
in Alaska, Michigan,  and Utah.
                                    1-2-9

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     Another modified  method of pit burial is  the  technique of trenching.
A  synonym  for trenching  is  spidering  (Crabtree,   1985).   Trenching  is
accomplished by pushing the  pit solids  into  trenches extending  out  from
the  main body of  the pit.   This  increases   the  load-bearing  capacity,
making  it easier to cover  the pit.  It also tends  to become structurally
stronger  over  time.   This  practice was  common in Michigan,  but now  has
been phased out.  It still is used in the Williston basin in North Dakota.

     Solidification.   Solidification of  pit  wastes  is  a  method used  to
"stabilize" reserve pit wastes prior to pit closure.   Problems  reported  by
landowners, including  reduced load-bearing capacity of the ground over the
pit  and  the   formation  of  wet  spots  over  the   pit,   have  prompted
investigation  into  solidification.   In  addition,  plastic pit  liners  that
are  now required in many  States do  not allow  for  timely  drying of  pit
solids.   Solidification  provides   a   faster   means  of  closing  a  pit,
particularly in areas  of net precipitation where  seasonal  changes  often
interfere with site restoration (Crabtree, 1985).

     There  are  two categories  in  which  solidification methods  can  be
placed:   chemical   and  physical.   In  general,   chemical  methods   of
solidification  involve  mixing  cement-like products  with  the  dewatered
contents  of  a  pit,  and  physical  methods   of   solidification  involve
permanent   freezing of   pit  solids.    Only   locations  in  Alaska   have
environmental conditions appropriate for physical solidification.

     Solidification of pit  wastes  is   offered  as  an acceptable  disposal
alternative in  the  regulations of several States.  Title 18  of the  Alaska
Administrative  Code,  Chapter  60,  specifically   addresses  construction
requirements for  "a containment structure which  is  designed  to  contain
                                   1-2-10

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drilling wastes  in  a  permanently frozen state," including a  waste  surface

level 2 feet below the active thaw zone  (ISAAC  60.520,  1986).   Louisiana's

Statewide Order  29-B  states  that,  "Pits containing  nonhazardous  oilfield

wastes (as  defined  within Order 29-B) may be  closed by solidifying  waste

and  burying  it  onsite"  if  the  material   to  be  buried  meets  specified

criteria, summarized in the table below:


   - pH                                      6-12

   - Leachate testing for:
          Oil and grease  .                   < 10.0  mg/1
          Arsenic                            <  0.5  mg/1
          Barium                             < 10.0  mg/1
          Cadmium                            <  0.1  mg/1
          Chromium                           <  0.5  mg/1
          Lead                               <  0.5  mg/1
          Mercury                            <  0.02 mg/1
          Selenium                           <  0.1  mg/1
          Silver                             <  0.5  mg/1
          Zinc                               <  5.0  mg/1

     -  Top of buried  mixture must be at least  5  feet  below ground  level
        and covered with 5 feet of native soil.

     -  Bottom of burial  "cell" must be at least 5 feet above the  seasonal
        high water table.

     -  Unconfined compressive strength         > 200 psi

     -  Permeability                            < 1 x 10~6  cm/sec

     -  Wet/dry durability                      > 10 cycles to
                                                  failure

     Michigan's  Supervisor  of Mineral  Wells  Instruction 1-84  specifies

lined  pit  closure  requirements,  and  includes  the  following  statement
regarding solidification:
     Earthen materials  shall  be mixed with the  pit  contents  to
     stiffen it  sufficiently  to provide physical  stability  and
     support  for the  pit  cover.  A  pit stiffening process  as
     approved  by the Supervisor  may  be used  at the option  of
     the operator.
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     Materials  commonly  used to "stiffen pits"  in  Michigan include native
soils,  gravel,  and  sawdust.   Processes  have  been developed  within  the
State  that  "stabilize" dewatered  pit contents by  addition of  cement kiln
dust, cement, and other materials. Mixing is performed by a backhoe or jet
pump.   The  product  of  mixed  waste  and  cement  kiln  dust  resembles  a
low-grade mortar.  The Michigan Department  of Natural  Resources  has  run
tests  on  the  raw  material  and  the  mixed  product  of  one  of  three
"stabilizing" processes used in the State, and has  found that  "addition of
the  raw material  to a mud pit  would  not  introduce  toxic materials," among
other  findings.   The  Michigan  DNR  expressed concerns  over elevated  SO.
levels  found  in  leachate  from the  raw material,  in  addition to  other
findings,  and  is  pursuing  further  investigations  of   pit   stiffening
materials (Crabtree, 1985).

     A recent study  conducted by scientists from Shell Development Company
and the Environmental and Ground Water Institute  investigated the behavior
of drilling  fluid wastes  stabilized by the addition of fly ash.   The study
concluded that  "no significant  uptake or  release of [heavy] metals can be
expected during treatment,"   and that fly ash could be  considered a valid
method of treatment (Deeley and Canter, 1985).

     Closed Systems

     A closed system used for oil or gas  drilling is a system in  which the
drilling  fluids  and  liguids are  recirculated  and reused.  A  system  in
which  the   drilling   fluids  are  partially  recirculated  represents   a
semi-closed  system.   The  use  of  mud recirculation  systems is  a  common
practice  for   onshore  drilling.    Such   systems   can   be   closed   or
semi-closed.  Their use  represents  a great benefit, as they can reduce the
water and mud input  requirements.  This can translate into  cost  savings  on
raw  materials  and also a  reduction of waste  material generated requiring
disposal at the conclusion of drilling activities.
                                   1-2-12

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     Closed   systems   at   drilling   sites   can   be   operated   to  have
recirculation of the liquid  phase,  the solid phase, or  both.   In reality,
there is no  completely closed system for solids  since  cuttings are always
produced  and   removed.    The  closed  system  for  solids,   or   the  mud
recirculation system,  can  vary in design from site  to  site.   However, the
system  must  have  sufficient solids  handling  equipment  to  effectively
remove the cuttings from muds to be  reused.  A  very common apparatus used
for this purpose is the  shale shaker.  The shale shaker  is  essentially  a
screen  that  is used  to  separate  cuttings  from   muds.   Two  types  are
common.  In one type,  the screen is in the form of a tapered  cylinder that
is  rotated   by the   flow  of  the   drilling   fluid.    The   other  is  a
rubber-mounted  sloping flat  screen  that is vibrated by a motor;  drilling
fluids fall  by  gravity through the screen while the cuttings pass over the
screen  (McCray, 1959).   Other  equipment  utilized   for  mud  recirculation
includes desanders,  desilters, vacuum  chambers  (that  can remove  gas from
the muds), and centrifuges.

     Water that is removed  from the mud  along  with the  cuttings  can  be
reused.  A  separate  closed  system  for water reuse  can  be operated onsite
along  with  the mud   recirculation  system.    As with  mud  recirculation
systems, the  design of a water recirculation system can vary from site to
site, depending on the quality of the recycled water required for further
use.  This may  include chemical treatment of the water.  Also,  any solids
must be removed from the water.  This  can  be  accomplished by  the  use  of a
centrifuge or similar apparatus.

     A discovery well  in France had, at the  drilling site,  a closed system
for solids and  liquids.   The system  combined  physical  and chemical water
treatment  with  a  conventional  solids handling  system  to  continuously
create clean water.   As  a result,  the  total  pit  volume,  treatment,  and
reserve  was  reduced  to  about one-third  conventional  volume  (Neidhardt,
1985).
                                   1-2-13

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     In  the United  States, onshore  oil  or gas  drilling sites  that  have
closed  or  semi-closed  systems  use  variations of  the  systems  described
above.   In  California,  one  site was  known  to  use  a mud  recirculation
system using two  shale  shakers.   The reduction of  mud generated waste  at
this  site was  necessary  as the  wastes were stored in aboveground  storage
bins.  At the  conclusion  of  drilling,  the contents  of  these bins  were
emptied  and transported  to a centralized treatment  facility (EPA -  CA,
1986).

     In  Michigan,  a particular site  used  a  mud  recirculation   system
similar to  the one observed in California.  At this  site,  drilling wastes
at the end  of  drilling were placed in  a  lined pit and were  later  removed
by a vacuum truck  (EPA - MI, 1986).

     In  Wyoming,  mud  recirculation  systems   were  also  used.    At   one
particular  site,  two  reserve  pits  were  constructed.    The  first   pit
received  all mud  and cuttings  from the well hole.  The supernatant  and mud
flowed into  the  second  pit, while coarse cuttings  remained in the  first.
A  large  pipe  was  placed  at  the  base  of   the  second  pit  and  thus
recirculated only the mud  from the  second pit.  The mud then  went  through
an  additional  series  of  stages  to  further remove cuttings.   At   the
conclusion  of  drilling,  the  pits  were  dewatered.    The  supernatant   was
removed for disposal at a disposal  site; the  solids  remained  in the  pits
and were buried (EPA - WY, 1986).

     In Kansas,  a different type of mud recirculation  system was used.
Mud  and  cuttings  from  the well   hole  were  placed  in  a series of  working
pits.  Mud  flowed from  one end of the  working pit to  the  other.  At  the
end of the  pit,  the mud was piped back to the  well hole for reuse.   As  the
mud flowed along  the  length of the  working pit, the cuttings  were  removed
by gravity  settling.  Pipes were placed at the  base of the  working  pit.
                                   1-2-14

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 and at certain  intervals the settled  cuttings  were removed and placed  in
 the reserve pit.  At the  conclusion  of drilling, the  working and  reserve
 pits  were  dewatered  by evaporation  and buried. Neither  the  working  pits
 nor the reserve  pits  were  lined  (EPA  -  KS,  1986).
     Treatment  and Discharge Options

     Agricultural and Wildlife Water Use.  Agricultural and Wildlife Water
Use  is  a  subcategory  under  the  onshore  segment  of the  oil  and  gas
extraction   industry  effluent  limitations  guideline.   This  subcategory,
defined  in  40 CFR Part  435, Subpart  E, as  authorized  by the  Clean Water
Act, addresses  the  use of produced water that is of good enough quality to
be   used  for  livestock  watering  or  other   agricultural   uses.    This
subcategory  was  formerly  called  the  Beneficial  Use  subcategory.  The
terminology  was changed because  of the  confusion  resulting from  the word
"beneficial."    The   term  "beneficial use"  has  a  long history of  use  in
Western  U.S. water laws unrelated to its meaning in these regulations.

     This  subcategory was  established  because  many  western  States  had
asked  EPA   to   allow  produced  water  to  be  discharged  and  used  for
agricultural  and wildlife  purposes.    Investigation  showed that  in  arid
portions  of  the Western U.S.,  low-salinity produced waters  were often  a
significant  (if  not  the  only)  local  source   of  water  used  for   those
purposes.  The  regulation  is  intended  as a  restrictive  subcategorization
based on the unique factors of prior usage in the region, arid  conditions,
and the existence of low-salinity potable water.

     To  qualify  for  the  use  of produced  water  under  Agricultural and
Wildlife  use,  the facility must  be  located west  of the  98th  meridian.
                                   1-2-15

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Also, to qualify, the facility must show that the discharged  water will be
used  for  agriculture  or  wildlife.   The  discharger  must  also  meet  the
required oil and grease discharge limitation of 35 mg/1.

     There  are  inconsistencies from  State  to  State  for  the  issuance  of
discharge  permits under Agricultural and  Wildlife  Use.   For  example,  18
production  facilities  in Montana  have  been permitted,  yielding a  total
daily discharge  of 0.6  million gallons for agricultural  and wildlife  use
(EPA - MT,  1985b).   Wyoming currently allows  discharge of  produced  water
for  agricultural  and wildlife  use  under 550  NPDES permits  with effluent
limitations of:

     TDS              5,000 mg/1
     Sulfates         3,000 mg/1
     Chlorides        2,000 mg/1
     pH                6.5-8.5
     Oil and grease    10 mg/1
(EPA - WY,  1985b).
     These  oil  and grease  limitations  are met  generally by  the use  of
oil-water  separation  systems.  In  Wyoming, a system of  pits connected in
series has  been used.  Each  pit is  skimmed for removal of oil.   The  final
pit discharges directly into the Powder River.

     Coastal   Treatment   and   Disposal.    The  framework  for  regulating
treatment  and  disposal methods used in  coastal areas  is  derived  from  the
Coastal  subcategory  of the  onshore segment of the oil and  gas extraction
industry effluent limitations guideline, defined in 40 CFR 435,  Subpart D,
as  authorized by the Clean Water Act.   The  Coastal  subcategory defines
"coast"  as "any  body  of water  landward of the  territorial  seas, or  any
wetlands adjacent to such waters" (see also Appendix A - EPA).
                                   1-2-16

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     Methods used  for  treatment  and  disposal of  drilling or  production
wastes  in  coastal  areas  are  based  on  State  and  Federal  regulatory
requirements.  Where  applicable,  permits for  discharge to  coastal  waters
are   written  in   accordance  with   the  National   Pollutant   Discharge
Elimination  System  (NPDES),  and  may  be  issued  by  State  or  Federal
authorities.  At this  time,  37 States have approved  State  NPDES programs.
In States that do  not have approved NPDES programs,  permitting  of coastal
discharges  is  coordinated through Regional EPA offices  and State agencies
concerned with these  matters.  States  in EPA Region VI,  for example,  do
not have approved NPDES programs.

     Actual treatment  and disposal  methods  in coastal areas depend  on the
nature of the  effluent as well as applicable  effluent  limitations.   Types
of  waste  effluents   permitted by  Louisiana  include produced  water  and
water-based muds and  cuttings  (EPA  -  LA, 1985a). The Alaska Department  of
Environmental Conservation permits  surface  discharge  of reserve  pit  fluids
to  the  coastal  tundra region,  and  specifically  includes  the  following
limitations in the permits:

     pH                                6.5 to 8.5
     Chemical oxygen demand            200     mg/1
     Settleable solids                   0.2   mg/1
     Oil and grease                     15     mg/1
     Total aromatic hydrocarbons        10     ug/1
     Arsenic                             0.05  mg/1
     Barium                              1.0   mg/1
     Cadmium                             0.01  mg/1
     Chromium                            0.05  mg/1
     Lead                                0.05  mg/1
     Mercury                             0.002  mg/1

     Frequently,  the types of  oil  and gas field wastes  that are permitted
to be disposed of in coastal  areas  are expected  to  be compatible  with the
coastal   environment,   if  kept  segregated  from unacceptable  wastes.  For
example, at a production  site in  Louisiana,  the contents  of the  produced
                                   1-2-17

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brine are close  enough to the State's tidewater  effluent  limitations that
skim  tanks   to  separate  hydrocarbons  from produced  water  are the  only
treatment used prior  to discharge  (EPA  - LA,   1986).   In  most  cases,
monitoring,   laboratory analyses,  and reporting reguirements  are specified
in permits for coastal discharges of any oil or gas field waste.

     Simple  separation technigues  are  not  always  sufficient  to  achieve
reguired discharge  limitations.   In general,  brine treatment technology is
available in two categories:  physical-chemical  processes and  biological
processes.   Examples  of physical-chemical  treatment  include  flotation,
filtration,   activated  carbon  adsorption,  ion exchange,  air stripping,  and
break  point   chlorination.    Examples   of  biological   treatment  include
dispersed growth  systems  such as aerated  lagoons  and  activated  sludge  or
fixed film  systems such  as  trickling filters and bio-disks.  The  primary
pollutants  in  produced  water  that  these  technologies  affect  include
biological   oxygen  demand,   chemical   oxygen   demand,   phenols,  ammonia,
sulfide, and oil  and  grease.   The most common method of  treatment  is  oil
removal, which can be  accomplished in skim tanks,  tube  separators,  and,
more  recently,  sand  filters.   Biological  treatment   methods   are  only
recently being considered as alternatives to more conventional  techniques
(Michalczyk, et al., 1984).
Centralized Methods of Waste Disposal

     The waste  management  methods discussed in the following  sections  are
divided into four topics:

       Centralized Pits;
       Centralized Treatment Facilities;
       Reconditioning/Recycling/Reuse; and
       Incineration.
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     The  term  "centralized,"   rather  than  "off site,"  is  used  in  this
section  to  define a  pit  or facility  designed,  constructed,  and operated
expressly for the purpose of receiving wastes from numerous  oil  and/or gas
field  operations.   The  term "offsite pit"  is used  only in  reference  to
such pits located in  Oklahoma,  because  this  term is  in  common usage there
(Cantor, et al., 1984)
     Centralized Pits

     The use of centralized pits for disposal of oil and gas drilling
and/or production  wastes  is practiced in several  States.  Centralized pits
can be very large in size and can, as a result, accept the  wastes  for many
well  and production  sites over  large  geographical  areas.   They can  be
designed to accept  drilling muds, brines, or  a  combination of both.   The
design  capacity  of   a   centralized  pit  is  directly  related  to  land
availability and  topography,   in  addition to  the  anticipated volumes  of
drilling and production wastes generated in the "service area" of the pit.

     The purpose  of  a centralized  pit  is to accept  wastes  from outside
drilling and  production activities  and  to provide  long-term storage  for
these wastes.  No  treatment of the pit contents  is  performed.   A properly
sited, designed,  constructed,  and  operated  centralized  pit  allows  the
natural  evaporation process to concentrate drilling fluids and brines.   A
pit is "closed" when  it  no  longer  receives  any  new material.  The  final
disposition of  the pit and its  contents  is  determined by local  or  State
regulations.

     In  Oklahoma,  there  are  approximately  95  centralized  pits  (called
"offsite pits" in  the  State),  with surface areas  as large  as 15  acres and
with  depths  up  to 50  feet.   They  are  created  by  excavating,  damming
                                   1-2-19

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gullies, and  using abandoned  strip pits.  Rule  3-110.2  of the  Oklahoma
Corporation  Commission permits  centralized  pits  and  their use  provided
that they are  sealed  with an impervious  material,  do not  receive  outside
runoff water,  and  are filled and leveled within 1 year after closure.   The
chloride level of the pit contents cannot exceed 3,500 mg/1.  The  pits are
periodically sampled  and  checked for chloride.  If the  contents  are above
the chloride limit, they  must  be treated and  removed to  a hazardous waste
disposal site.  Operators of new centralized  pits are  required to install
and sample monitoring wells  for chloride and  pH.   It is proposed  to  make
this requirement applicable to existing centralized pits (Appendix A - OK).

     In  California,   drilling fluids  and  brines  may  be  transported  to
centralized pits.  Drilling  fluids  are  generally received  by  centralized
evaporation sumps, but many  of  these sumps are also used for  percolation
where no freshwater source is near.  No State manifest  is required unless
the material is  classified by the State as hazardous.  On the western side
of the San Joaquin Valley, where ground water is of poor  quality,  there  is
a commercial facility on  Federal land.  At this  facility,  there  are 20  to
40 acres of permitted sumps for evaporation and percolation.  BLM  has sumps
on Federal leases that range  up to 5 acres (Appendix A - CA).

     In  Ohio,  the contents  of  reserve pits may be required  to be removed
and transported to an Ohio  EPA  (State)  regulated  disposal site.  This  is
due  to  potential  ground-water  contamination  from  the  pit.  When  pit
contents are to  be moved, the  State  requires tests  to  determine  whether
the waste can be disposed of  in an approved landfill (Appendix A - OH).

     In  Texas,  about  200  centralized  saltwater disposal  pits  are  in
operation.  These  pits are  regulated  by the  Texas  Railroad  Commission.
State manifests are  required to transport brines to these pits  (Appendix A
- TX).
                                   1-2-20

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     In  Wyoming,   the  Department  of   Environmental   Quality  regulates
centralized pits.  Such pits require operating permits from  the State.   To
receive  these  permits,  the  pit  operators  must  demonstrate  that  pit
construction  will  not  allow a  discharge  to ground  water by direct  or
indirect  discharge,  percolation,  or filtration.  Also,  it must  be  shown
that the wastewater  quality will not cause  violation of  any  ground-water
standards  and that  existing  geology will not allow a discharge  to ground
water (Appendix A - WY).
     Centralized Treatment Facilities

     A  centralized  treatment  facility  for  oil  and  gas  drilling  and
production wastes  is a  process  facility that  accepts such wastes  solely
for  the  purpose  of  reconditioning  and  treating  wastes  to  allow  for
discharge or  final  disposal.   This removes the  burden of  required  onsite
treatment of  wastes  from the drilling or production facility.   Centralized
treatment can represent an economically viable alternative  to  onsite waste
disposal.   A  treatment  facility  can  be  run  in  batch  or  continuous
operation. The facility  can  have  a design capacity large  enough  to  accept
a  great   quantity  of   wastes   from  many  drilling  and/or  production
facilities.   In this way,  the centralized treatment  facility  can treat  a
large  quantity of  wastes  more  efficiently than a single  drilling  or
production facility can treat a small quantity of waste.

     Many  different  treatment  technologies  can  potentially  be  used  in
central  treatment  of  oil  and  gas  drilling  and  production  wastes.  The
actual technology used at  a  particular facility would depend  on a  number
of  factors.    One  of  these  factors  is  type  of  waste.  Presently,  some
facilities are designed  to treat  solids  (muds and cutting), while  others
                                   1-2-21

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are designed to  treat  produced waters, completion and  stimulation  fluids,
or other  liquids.   Some  facilities can treat a combination of both.  Other
factors  determining   treatment   technology  include   facility   capacity,
discharge  options  and  requirements,  solid  waste  disposal  options,  and
other relevant State or local requirements.

     Centralized treatment facilities  can be divided into  three  different
categories:   drilling  waste  treatment,  produced  water  treatment,  and
drilling  waste  and produced water treatment.  Examples of each  of  these
types are given below.

     An  example   of   a   drilling  waste  treatment  system  is   found  in
California.  Drilling  fluids at  some drilling sites  are accumulated  in
disposal  bins.  The  contents of  these bins  are  vacuumed into trucks  and
taken to  a facility that uses a  patented  process  to  convert the  sludge
into a  substance  having  a  gel-like consistency  that hardens in 2 hours.
Metals within the  drilling  fluids are converted into stable,  nonleachable
metal silicates.  The  final product  can  be  disposed of by  landfill  or can
be  used   for   backfilling   or   landfill   covers    (Ven   Virotek,   1986).
California  regulations do not  require a State manifest  for  transporting
material unless it is determined to be hazardous under State regulations.

     Another example of  a central drilling  waste treatment facility is  in
Alabama.  The facility accepts  water-based  drilling fluids and sewage from
offshore and coastal rigs in Alabama waters. Material is  received by truck
or by barge.  From the holding container,  the mud is pumped through shaker
screens  for  cuttings  removal.   Treatment  consists  of  pH  adjustment,
flocculation, clarification,  and dewatering.   The  water  is pumped to the
local publicly  owned  treatment works  (POTW) for  final  treatment.  Solids
are trucked off to the municipal landfill for disposal (SAFE,  Inc.,  1986).
                                   1-2-22

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     Examples  of  brine  treatment  are   exhibited   in  Pennsylvania  and
Colorado.   Pennsylvania  estimates  that 20 percent of all brines are hauled
to  a  treatment  plant   in  that  State   (EPA  -  PA,  1985).   It  is  the
responsibility  of the  brine  generator   to  transport  the material  to the
treatment   facility.   Treatment  at  these  facilities  may  include  flow
equalization,  pH adjustment, settling and  surface  skimming,  retention and
settling, and  aeration.  These facilities must have  NPDES  and Pennsylvania
Water Quality  Management Part II permits.  The permit  criteria  and limits
will be  governed  by the  receiving water  quality  standards.   Generally,
total  suspended  solids  will . be  limited  to an  instantaneous maximum  of
60 mg/1, with  an average monthly of 30 mg/1.  Oil  and grease will  have  a
maximum of  30  mg/1 and an average  of  15  mg/1.  pH must be between 6 and 9
and dissolved iron will have a maximum of 7 mg/1 (Appendix A - PA).

     In Colorado,  the  State Department of Health has  permitted  10  to  15
commercial  brine disposal facilities  to  discharge  under  the Wildlife and
Agricultural Use  subcategory.   Discharge  limitations include pH between  6
and  9,  a monthly  average of  30  mg/1  for  total  suspended solids,  with  a
daily maximum  of 45  mg/1, an oil and  grease  limit  of  10  mg/1, a monthly
average of  5,000 mg/1  for total dissolved  solids, with  a  daily maximum of
7,500  mg/1, and  metal   limits  under  the  State  water  quality  standards
(Appendix A - CO).   One brine treatment facility  was visited  during the
field sampling  portion  of the  Onshore  Oil and Gas  Study.   This  facility
treated  brines with  chemical  addition  (borax,  calcium hypochlorite,  and
potassium permanganate)  and aeration.   This  facility  did not  discharge;
rather, brines were placed in large evaporation ponds (EPA -  CO,  in press).

     Alaska  also  has  centralized  brine  treatment  facilities.   Produced
waters from 14 platforms  in Cook Inlet are sent  to  one of three  treatment
facilities.   Treatment  consists of heating to enhance oil/gas  separation,
solids settling,  and surface  skimming.   The water  is  discharged off  the
coast (EPA - AL, 1985b).
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     Louisiana  has  approximately  33  commercial  centralized  facilities
currently in operation.   Some  accept only brines, while  others  accept mud
and brine.  They must be permitted for operation by the State.

     Treatment of  reserve  pit  wastes can also  be accomplished  via  mobile
treatment  units.    Such units  employ  scaled-down  equipment designed  to
perform  the  same   treatment  processes  as  those  performed at  centralized
treatment  facilities,  except  that  the equipment  is truck-mounted  and  is
brought  to the  reserve pit  onsite.   Mobile  treatment   is  discussed  in
greater detail in the section .titled Onsite Treatment and Disposal.
     Reconditioning/Recycling/Reuse

     This section  discusses the  reconditioning  and reuse  of oil and  gas
drilling and  production wastes.   Not  included here are  the  recycling  and
reuse of drilling fluids (i.e., drilling mud  recirculation  systems),  since
these are cited in the section on Closed Systems.

     The  reconditioning,  recycling,  or  reuse   of  oil  and  gas  wastes
represents a  positive  environmental  policy,  when applicable.   By  means  of
chemical or physical  treatment,  a material that  otherwise would have to be
disposed of becomes a  material with a beneficial use.   In  some cases,  no
adjustment of the  waste material is needed  to  put it  to  an advantageous
use.  The  recycling and reuse of these  wastes  not  only  can reduce  the
volume of generated wastes  that requires disposal,  but also can reduce  the
need  for raw materials.   This  is  especially  important  in  geographical
areas  where  onsite  waste  disposal  is  extremely difficult  because  of
geological  or  other  physical  conditions,   or   not  allowed  because   of
regulation.
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     The  State of  Louisiana  has  regulations   that  specifically  mention

reusable  oilfield waste.   "Reusable  material"  is  defined as  a  "material

that  would  otherwise  be  classified  as  oilfield  waste,  but  has  been

processed  in  part  or  in  whole  for  reuse."   Commercial  facilities  may

produce  reusable  material  as  their  treatment   process  or in  conjunction

with  their  treatment  process.  In  either  case,   the  facility  must  be

permitted by the  State.  Onsite  generation  of  reusable material  requires

approval  from  the  State Office  of  Conservation.   The reusable  material

must be tested and meet the following limitations:
     Moisture content
     pH
     Conductivity
     Sodium adsorption rate
     Exchangeable sodium percentage
     Leachate test:
       Oil and grease
       Chlorides
     Leachate (EP Toxicity)
       Arsenic
       Barium
       Cadmium
       Chromium
       Lead
       Mercury
       Selenium
       Silver
       Zinc
 <50 % by weight
 6.5 - 9.0
 8 mmhos/cm
 12
 15%

 10.0 mg/1
500.0 mg/1

  0.5 mg/1
 10.0 mg/1
  0.1 mg/1
  0.5 mg/1
  0.5 mg/1
  0.02 mg/1
  0.1 mg/1
  0.5 mg/1
  5.0 mg/1
     Louisiana  has  permitted  reusable  material  that  meets  the  above
criteria  to  be  used  as  landfill  cover  or  various  construction  fill
material (LA State Order 29-B).


     A   relatively   new  well-site  treatment  system  offers  beneficial

material reuse.  The technology  mentioned earlier was  proven  on a  French

discovery well.   This  method  is now being tested on  several  wells  in the

western United States (Neidhardt, 1985).
                                   1-2-25

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     In  Canada,   a  feasibility  study  was  conducted  on reusing  produced
water as the feedwater supply for steam generation for onsite  oil  recovery
(Kus, 1984).  Such  steam-assisted  methods operate with steam-to-oil ratios
of  3  to 1  and  generate 2  to 5 barrels  of produced  water per barrel  of
oil.   To  raise   the  large  quantities  of  steam required  for  reservoir
stimulation, once-through  type steam  generators  are  most  commonly  used.
Preliminary investigations  into  the  feasibility of using produced water as
the only source of  water proved  to be uneconomical.  As  an alternative,  a
blend of produced water and municipal water was chosen (Kus, 1984).

     EPA authorized a  study on the feasibility of  removing and recovering
phenol and  acetic acid from  sodium  chloride  brine  (EPA, 1973).   A  pilot
plant was  constructed to  demonstrate  the feasibility of using the method
of  fixed  bed  adsorption  of  activated  carbon.   Separate   electrolytic
test-cell  evaluation  of the  purified  brine showed it to be  equivalent  to
pure  brine.   The  carbon  beds  were  regenerated  with  dilute  sodium
hydroxide.   Desorbed phenol  was  recycled  to  a phenol  manufacturer  (EPA,
1973).

   Incineration

     This  treatment  method  is  applicable  for  organic  and  oil-laden
wastes.  These  include oil-based  muds,  oil emulsions, and other  muds  and
cuttings contaminated with oil,  tank  bottoms,  and separator  sludges.   In
theory,  any drilling  or production  waste with a  low  enough  water content
can  be  economically  combusted.   The  combustion  residuals  must  also  be
disposed of.  The practice of incinerating drilling and production wastes
is not common.  It  is known to occur at a  central treatment  facility near
Kenai, Alaska.  This  facility receives oil and water from the coastal rigs
in Cook  Inlet.  All waste  oil is collected in  a storage tank  where  it  is
periodically  removed  and  incinerated.  The   residuals   are  placed  in  a
landfill on the facility property.   Incineration is also known to be used
                                   1-2-26

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on waste oil-laden cuttings and oil-based muds from  offshore  facilities in
Louisiana.   EPA  will  investigate  further  the  extent  of  the  use  of
incineration as a reliable waste treatment method.
Land Application

     Landfarming

     Landfarming, as defined  by the Railroad Commission of Texas  and used
in  this  report,  is "a  waste  management  practice  in which  oil  and  gas
wastes are  mixed with  or applied to the land surface in such a manner that
the waste will not migrate off the landfarmed area."   The  ultimate  goal of
landfarming is  to use  dilution, chemical alteration, and biodegradation to
decrease  the  level  of  pollutants  and  alter  the  waste  so  that  the
waste/soil  mixture  remains compatible  with the intended  or  original land
use (Freeman and Deuel, 1986).

     Landfarming  is generally viewed as a  long-term,  management-intensive
process.  Though widespread  in  Texas,  Colorado, and  Louisiana,  and to  a
lesser  degree  in  Mississippi  and  Alabama,  it  is not   common  in  other
States.   Improperly  managed  landfarming  sites have the  potential  for
environmental  damage.    The   State   of  Texas  has   identified   improper
landfarming  and  the   resulting runoff  to  surface water as  a  critical
environmental problem.

     Landfarming can provide  an efficient  disposal  method for various  oil
and gas wastes,  including  pit residue,  sludges, muds, and liquids.   Solid
wastes can  be  distributed  over the land surface and mixed with the  soils
by  mechanical   means.   Liquids  can  be applied to the  land surface  by
various types  of  irrigation,  including sprinkler,  flood, and  ridge  and
                                   1-2-27

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furrow.   Injection  plowing and  disking of  irrigated  land surfaces  allow
for subsurface application of wastes (Railroad Commission of Texas, 1985).

     Certain  criteria must  be  met,  however,  for  successful  landfarming.
Chloride content of the wastes must be  relatively low.   For  example,  Texas
allows  non-permitted landfarming  of wastes  only  if  chloride  content  is
less than or equal  to 3,000  mg/1.   Alabama requires a. chloride  content  of
less  than  500  mg/1.  Oklahoma  permits spray-application  of  reserve  pit
fluids if chloride content is less than 1,000 mg/1.

     Oily wastes and other organics is another concern.  To  alleviate this
problem,  some  States   allow  only  water-based  drilling  fluids  to  be
landfarmed, and also limit oil and grease content of the wastes.   Oklahoma
requires  less than  or equal  to  30 mg/1  of  oil and grease  in wastes before
allowing  spray  application.    Disking,   and  the  resulting  soil  aeration,
also assists in the biodegradation of oil,  grease, and other organics.

     The  presence  of heavy  metals  (primarily barium, chromium,  lead,  and
zinc,  and,  to a  lesser  extent, arsenic,  cadmium,  mercury, selenium,  and
silver) in  drilling muds is  also a concern  (Kissock,  1986).   The solution
to  this  problem is  to  limit the  landfarming of  wastes  with high  metal
content and to  carefully maintain a  soil  pH range of 6.5 to  9.0,  keeping
the heavy metals insoluble and immobile.

     In addition  to  these considerations,  the  site  and  design  of  the
landfarming facility  is  a critical  component in its success. Louisiana has
developed  location  and  facility  design  standards  that  address  these
concerns.    These   standards  prohibit  facilities  in  flood  zones  and
wetlands,   limit  their   proximity  to  existing  buildings,   require  spill
containment systems  in loading  and storage areas, and limit access to the
sites  (Field  and  Smith,   1986).   Additional  standards detail  requirements
                                   1-2-28

-------
of the treatment zone,  including  thickness,  permeability,  and relationship
to  the  water  table.   This  requires  a  detailed geological/geotechnical
investigation of prospective landfarming sites.

     Roadspraying

     In   addition   to  landfarming,   there   are  other   types  of   land
applications for oil  and  gas wastes.  In the past, pit and produced brines
have  been used for  ice  and  dust  control  on  roads   in  Michigan.   This
process,  called roadspraying  or roadspreading,  is  being  discontinued by
order of  the  State.   Alaska is  also reconsidering the  use of  brines  for
de-icing  roads.  Kansas  still allows  the  spreading  of  brines on  roads
under construction, and in New York, road spreading for ice  control  is  the
predominant disposal method.

Subsurface Disposal

     Subsurface disposal of  oil  or  gas field waste is  Federally regulated
through the  Underground Injection  Control  (UIC)  Program,  as  detailed  in
Appendix  A.   States  may  be  granted  primacy  over the UIC  program as  a
result of EPA's evaluation and approval of State  programs.   Otherwise,  EPA
is the  primary regulatory  authority in matters  of underground injection.
However, States that do not  have primacy may have regulations  in addition
to those  imposed by  the  Federal UIC  Program.  Pennsylvania, for example,
regulates underground  disposal  of  oil  and gas  field  wastes  through  the
Clean Streams Law (Waite,  et al., 1983).

     One of the most  common forms of liquid waste disposal used by the  oil
and gas industries  is  injection  into  non-producing  formations  (Waite,  et
al.,   1983).   Liquid  waste  is  typically produced  water  (also known  as
                                   1-2-29

-------
brine) brought to  the  surface with the produced oil or gas.   Historically,
surface  disposal  of  produced brine  has  been  believed  to  cause  severe
environmental damage  in States  (EPA  - OH,  1985a;  EPA - IL,  1985a;  EPA -
MM, 1985b), which  has led  to the widespread  use of  subsurface  injection
methods.

     Brine is injected  to  non-producing formations (or "safe horizons") by
two methods.  The  method often preferred  by  State regulatory agencies is
the use  of disposal  wells  specifically drilled,  cased,  and  completed to
accommodate brine.  Figure  1-8 .displays a typical  saltwater  disposal  well
pumping  into a  zone  located far  below  the  freshwater  table   (Elmer E.
Templeton  and Associates,   1980).  New wells  may be constructed  for  this
purpose,    or   old   wells  may   be   retrofitted  to  meet   construction
requirements.   The  second  method is  injection  into  the  uncased annular
space  of a producing well, or in the space within the production casing.
Figures  1-9   and  1-10   illustrate   these, techniques  (Templeton,  1980).
Annular  disposal  of  brine to non-producing  zones has been or  is  being
phased out of  many  States  (Elmer  E.  Templeton  and  Associates,  1980).
Louisiana  allows   annular   injection  of  reserve pit  fluids  whenever  the
surface  casing is  deep  enough to protect  underground sources of drinking
water  (Appendix A - LA).

     Wells used for  brine  disposal must be carefully  constructed in order
to protect freshwater  aquifers.   When old wells  are  retrofitted  for brine
disposal,  ground-water  contamination may occur  as  a result   of  casing
failure.    Consideration must also be given  to  abandoned   wells in  the
vicinity of  a proposed  disposal well site.   Figure  1-11   illustrates the
potential  for   freshwater   contamination  created  by  abandoned   wells
(Illinois EPA, 1978).

     In  addition  to construction requirements,  injection  pressure must be
determined  such that  it  successfully disposes  of waste  fluids without
                                   1-2-30

-------
                                                              V/WCR
                                                   MONITOR ANfciULUS PRESSURE
                                                    MS
DISPOSAL ZONE 'r-   -
  -- D\iPOL Z
       Figure I-S.   Brine  (saltwater) disposal  well design.

       Source:   Templeton, Elmer E., and  Associates, Environmentally
                Acceptable Disposal of  Salt Brines Produced with C;_l
                and Gas, January,  1980.
                               1-2-31

-------
                       tf
                    JJ
                     ^L
t^m^







1



1
 "1

I
1

f

f
T
I-
L
!
i
':(
I
V
^

  - _ 1^  _
vl- ^-
:Vv] '
"  4 | --  -- 
'. ' -J* 	 	 	 	 '
 ?!
^L^. CtMtNT

' ' ~~
>
1
i
C&.MLKIT
PRODUC
)
: ' 	 __  _ .
PRODUCT-ON
                                                     V1G
PRCCUCING
                      
Figure 1-9.  Annular disposal  outside  production casing.

Source:  Templetcn, .Elrr.er E. ,  anc  Associates,  Envircnr.ental
         Acceptable Disposal of  Salt Brines  Produced with O
         and Gas, January,  1980.

-------
                                           PRODUCTION.
Figure I-10.  Annular disposal within production casing.

Source:  Templeton, Elmer E., and Associates, Environmentally
         Acceptable Disposal of Salt Brines Produced with
         Oil and Gas, January, 1980.

                      1-2-23

-------
       BRINE-DISPOSAL
           WELL
             I
             A     Lond
                                                       AnANOONO) WCLLS
                                                      I             I
                                                WITH CASING    NO CASING
                                                      B            C
WATFR-SUPPLY
 WELL
   I
  0      Surface
WATFR-Slim.Y
     WtLL
       I
ro

GJ
                                      Cosing rusted;
                                      failure or
                                      absence of
                                      cement
                                  Well not
                                  plugged or
                                   improperly
                                     plugged
                                           V
                                                       INTERVENING  ROCKS
                                               --梌-CONFINING ROCKS(Low permeability) JII7
                                              i棔B-^, " ' "晻"  %  _       . __   """'粫.. ,.         <^i^^_
                                              r-i^r  r^^*7>^v**^M^^^^BB_ *^* --.	     ~  ..^*',.._ 	 "    i ii -
                                      ''Casing rusted; failure or
                                      absence of cement

Figure 1-11.  Pollution of  a fresh water  aquifer through abandoned  wells.

Source:   Illinois  EPA, Illinois  Oil Field Brine Disposal Assepsmoni-:    nt.
           Report, November  1978.

-------
propagating fractures (Waite et al., 1983).  Estimated maximum  and average
injection pressures  must be  included  in applications for UIC  permits (40
CFR 146.22).

     Pretreatment of wastes prior to injection is used in  locations  of low
permeability   in   order  to   extend  the  life  of  disposal   wells.  In
Pennsylvania, pretreatment  methods  that have  been  used include  settling,
filtration,  and  flocculation.   These  treatment  steps are enhanced  by the
addition of  corrosion inhibitors,  bactericides,  and other additives  used
to adjust pH or  prevent undesired precipitation  in  the  disposal  reservoir
(Waite et al., 1983).

     Another  subsurface  brine  disposal alternative  is  injection  of brine
into producing  zones for  the  purpose  of enhancing oil  or gas  production.
This secondary form  of  recovery  is referred  to  as  "water flooding," and
may utilize  surface  water  in addition to produced water.  This  is a widely
accepted method of reusing produced water.

     Drilling fluids  and reserve  pit wastes also can be disposed of  by  a
one-time annular  injection, depending on the  geological formations.  This
type  of  subsurface   disposal  is  preferred  by  some  States  because  it
eliminates  surface  disposal problems.   Oklahoma,  for example,  allows  this
type of disposal, provided the well to be used has surface casing at least
200 feet  below the  depth  of  the  base of  the treatable water  (McCaskill,
1985). Oklahoma sets  no limit on the  quantity of waste  to be  disposed  of
in  this  manner,   because   this  is  a  one-time   act  of  disposal,  unlike
continuous  disposal  of  produced  brine.    Examples  of  other  States  that
allow  the  annular injection  of  drilling fluid are Mississippi  (EPA - MS,
1985a) and Alaska (EPA - AK, in press).
                                   1-2-35

-------
     The  intention  of  subsurface  disposal  of  any  waste   is  to  avoid
treatment or  hauling  costs that would otherwise be  required.  Therefore,  a
well and  associated formation  must be permeable enough to accept  all the
waste generated onsite,  or another disposal alternative must  be  employed.
In many areas,  the alternatives are either  costly or not  allowed by State
regulations (Ohio EPA, 1983).
Ocean Discharge

     The  U.S.  Environmental Protection  Agency has  established  guidelines
for "Issuance  of National  Pollution  Discharge Elimination  System  (NPDES)
permits  for  the discharge  of pollutants  from  a  point  source into  the
territorial  seas,   the  contiguous  zone,  and  the   oceans"   (40  CFR  125,
Subpart  M),  as  required  by Section  403  of the  Federal  Clean  Water  Act.
The guidelines  are designed to  "Prevent unreasonable  degradation  of  the
marine  environment  and  to authorize  imposition of  effluent  limitations,
including a prohibition of discharge,  if necessary,  to ensure  this  goal"
(Federal Register,  October 3, 1980).

     In  general, ocean  discharge of  wastes from onshore  and coastal  oil
and gas  field operations  is  regulated on  a  case-by-case basis.   States
that  have  NPDES programs  oversee  the permitting  of any  discharges  or
dumping along the coast  or in marine waters. States  that do not  have  NPDES
programs,   such  as   Louisiana  and   Texas,   establish   guidelines   in
coordination with Regional EPA  offices.

     An  example  of  State-established  effluent  limitations  is  California's
"Water Quality  Control  Plan for  Ocean Waters of California," also  called
"The Ocean Plan."   The  Ocean Plan defines Water Quality Objectives,  based
on  bacteriological,  physical,   chemical,   biological,   and  radioactive
                                   1-2-36

-------
characteristics,   such  that   ocean   disposal   will   not  violate   the
objectives.   The  Ocean   Plan  next  defines  General   Requirements   for
Management of Wastes and Effluent Quality Requirements.

     The  General  Requirements  specify  constituents  that  must  not  be
present in waste discharges,  such as  floatable particulates,  settleable
material that may  be  harmful to aquatic life, and materials that result in
discoloration of the  ocean surface.  Another General Requirement  states
that  waste  discharges must  be  sufficiently diluted so  as to  minimize
concentrations   of  . substances  not   previously  removed  by   treatment.
Finally, the  General   Requirements  call for a "detailed  assessment  of the
oceanographic characteristics  and  current  patterns"  in order to determine
a  discharge  location  that  will  protect shellfish harvesting areas, areas
of special biological significance, and the overall marine environment.

     Effluent Quality Requirements  are specified  in  Tables A  and  B  of
Chapter IV of  the  Plan.   Table A,  presented here as Table  1-12,  applies
only to discharges  not covered by Sections  301,  302,  304,  or  306  of the
Federal Clean Water Act.   Table B, presented here as Table  1-13,  applies
to all discharges within the jurisdiction of the Plan.

     In California, wells  located  in the Santa Maria  Basin were granted a
suspension  to  the onshore  oil  and gas  effluent limitations  guidelines
requiring  "zero discharge" of any  wastewater  pollutants (Federal Register,
July 21,  1982). Exception was made for this area because  of the geologic
and hydrogeologic  problems  associated with reinjection of  produced  water,
the normal disposal method.

     Other companies,  located  outside the  Santa Maria Basin and interested
in obtaining  permits  that  would allow  ocean discharge,  have investigated
possible methods by which produced water can be disposed of.
                                   1-2-37

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                                 TABLE 1-12


               CALIFORNIA OCEAN  PLAN:   MAJOR WASTEWATER
                      CONSTITUENTS  AND  PROPERTIES
                                                 Limiting
                                             Concentrations
                                             Monthly   Weekly      Max imum
                                Unit of      (30 day   (7 day        at any
                              measurement      Average)  Average)      time
     Grease and Oil               mg/125        40          7B~
     Suspended Solids                             see below+
     Settleable Solids            mg/1             1.0       1.5         3.0
     Turbidity                   JTU            75       100         225
     pH                          units           within limits
                                                 of 6.0 to 9.0
                                                 at all times
     Toxicity  Concentration      tu              1.5       2.0         2.5
+Suspended  Solids:    Dischargers  shall,  as  a  30-day  average,  remove  75%  of
suspended  sol ids from  the  influent  stream before discharging wastewaters
to the  ocean*,  except  that  the  effluent  limitation to  be  met shall  not  be
lower than 60 mg/1.   Regional  Boards may, with  the concurrence  of  the  State
Board  and  the  Environmental  Protection  Agency, adjust  the lower effluent
concentration limit  (the 60  mg/1  above)  to  suit  the  environmental and effluent
characteristics  of the  discharge.   As a further consideration  in making sucn
adjustment, Regional  Boards  should evaluate effects  on existing and potential
water* reclamation projects.

If the  lower effluent  concentration  limit  is  adjusted by the Regional  Boars,
the  discharger  shall remove 75%  of suspended  solids from the influent  stream
at any time the  influent concentration exceeds four times such  adjusted effluent
1 imit.
  Source:   Water  Quality Control  Plan  for  Ooean Water:
             of California, November 17,  1985.
                                 1-2-28

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                             TABLE 1-13

            CALIFORNIA OCEAN PLAN:   TOXIC MATERIALS
                             LIMITATIONS
                                      Limiting Concentrations
Arsenic
Cadmium
      Chromium  (Cr+6)
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Total Chlorine  Residual
(continuous  sources)
Ammonia
  (expressed as
   nitrogen)
Toxicity Concentra-
  tion
Phenolic Compounds
  (non-chlorinated)
Chlorinated  Phenolics
Aldrin and Dieldrin
Chlordane and
  Related Compounds
DDT and
  Derivatives
Endrin
HCH
PCS's
Toxaphene
  Unit of
Measurement

    ug/1
    ug/1
    ug/1
    ug/1
    ug/1
    ug/1
    ug/1
    ug/1
    ug/1
    ug/1

    ug/1
                                      6-Month
                                      Median
 8
 3
 2
 5
 8
 0.
20
 0.
20
 5
14
45
               0.003
 Daily
Maximum

  32
  12
   8
  20
  32
   0.56
  80
   1.8
  80
  20

  11
                         2,400
         0.006
Instantaneous
   Maximum

     80
     30
     20
     50
     80
      1.4
    200
      4.5
    200
     50

    124
                     6,000
                  0.009
Radioactivity
    Not to exceed limits specified in Section 30269
    of the California Administrative Code.
      Source:   Water Quality Control Plan for  Ocean
                Waters of  California, November  17, 1983,
                              1-2-39

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     One  particular  study  investigated  several  methods   including  ocean
discharge  via  pipeline,  river  discharge,  percolation/evaporation  pond
disposal,  effluent  irrigation  disposal,  and  other  alternative  methods
(CH2M   Hill,   1983).    The   proposed  ocean   discharge   alternative  is
presented  in  two  parts:  a  treatment  system  and  outfall  design,  and
pipeline route  considerations.  The  treatment system includes three process
steps:

       Induced gas flotation for oil and suspended solids removal;
       Filtration for final oil removal and effluent polishing; and
       A minimum dilution of 100:1 to be achieved by the ocean outfall.
     Design  criteria for  two  alternative  pipeline  routes  are  based  on
pipeline orientation, pumping requirements,  and piping requirements.  Both
the  treatment  system and  the  p'ipeline  routes  are designed  to meet  the
anticipated ocean  discharge  effluent  limitations defined by the California
Ocean Plan {CH2M Hill, 1983).

     Alaska  permits  ocean  discharge  of  oil  and   gas   drilling  waste
according  to  applicable  Federal   NPDES  requirements.    The  permitting
authority  is  U.S.  EPA Region  X.  Alaska  does not   have  its  own  NPDES
program.   Statutory  bases on which permits  are written in this  State  are
derived from the Federal  Clean  Water Act, Sections 301(b), 304,  308,  401,
402,  and  403,  and  include  technology-based  effluent limitations,  ocean
discharge  criteria,  and State  of Alaska standards and limitations  (U.S.
EPA  Region X,  1985).   Specific permit  requirements  allow  discharge  of
"generic [drilling]  muds  and authorized additives," listed in Table  1-14.
Under   this   provision,   drill   cuttings   that  meet  specified  content
requirements may  be  discharged  "without special  permission"  (U.S.  EPA
Region X, 1985).
                                   1-2-40

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                                                                      TARI.K  I-.14


                                      U.S.  EPA REGION  X:   AUTHORIZED  DRILLING  MUD  TYPES
 i
ro
 i
      Components

I.  Seawater/Freshwater/Potasslum/Polymer Hud
      ice I
      Starch
      Cellulose Polymer
      Xanthan Gum Polymer
      Drilled Solids
      Caustic
      Barlte
      Seawater or Freshwater

2-  ifWlfl'USOJHuJloniii M*y!
      AttapuTgite or Behtonite
      Llgnosulfonite. Chrome or  Ferrochrome
      Lignite, Untreated or Chrome-treated
      Caustic
      Barlte
      Drilled Solids
      Soda  Ash/Sodium Bicarbonate
      Cellulose Polymer
      Seawattr

3.  lime Mud
      Lime
      Bentontte
      Llgnosulfonjte. Chrome or  Ferrochrome
      Lignite. Untreated or Chrome-treated
      Caustic
      Barlte
      Drilled Solids
      Soda  Ash/Sodium Bicarbonate
      Seawater or Freshwater

4.  Hondlspersed Hud
      Bentonlte
      Acrylic Polymer
      Barlte
      Drilled Solids
      Seawater or Freshwater
                                                              HaKI mum Allowable
                                                                Concentration
                                                                   (Ib/bbi)'
                                                                      50
                                                                      12
                                                                       S
                                                                       2
                                                                     100
                                                                       3
                                                                     4SO
                                                                   As needed
    50
    15
    10
     5
   450
   100
     2
     5
As needed
                                                                       20
                                                                       50
                                                                       15
                                                                       10
                                                                        5
                                                                      ISO
                                                                      100
                                                                        2
                                                                  As needed
                                                                       15
                                                                        2
                                                                      ISO
                                                                       70
                                                                    As needed
  Components

Spud Hud
  Lime
  Attapulglte  or  Bentonlte
  Caustic
  Barlte
  Soda Ash/Sodium Bicarbonate
  Seawater

Seawater/Freshwater Gel Hud
  Lime
  Attapulglte  or  Bentonlte
  Caustic
  Barlte
  Drilled Solids
  Soda Ash/Sodium Bicarbonate
  Cel lulose Polymer
  Seawater or  freshwater
                           _....
                    Li"- ! shwater/Seawater Hud
                     Lime
                     Bentonlte
                     Llgnosulfonate, Chrome or Ferrochrome
                     Lignite, Untreated or Chrome-treated
                     Caustic
                     Barlte
                     Drilled Solids
                     Soda  Ash/Sodium Bicarbonate
                     Cellulose Polymer
                     Seawater & Freshwater In 1:1 ratio

                    Llgnosulfonate Freshwater Mud
                     Lime
                     Bentonlte
                     Llgnosulfonate. Chrome or Fprrochroroe
                     Lignite. Untreated or Chrome-ti eated
                     Caustic
                     Barlte
                     Drilled Solids
                     Soda  Ash/Sodium Bicarbonate
                     Cellulose Polymer
                     freshwater
                                                                                                                Majilmuffl Allowable
                                                                                                                  Concentration
                                                                                                                     (ib/bbi)
                                                                         I
                                                                        50
                                                                         2
                                                                        50
                                                                         2
                                                                     As  needed
    2
   50
    3
   50
  100
    2
    2
As needed
                                                     2
                                                    50
                                                     6
                                                     4
                                                     3
                                                   180
                                                   100
                                                     2
                                                     2
                                               As  needed
                                                     2
                                                    50
                                                    15
                                                    10
                                                     5
                                                   450
                                                   100
                                                                                                                                     As
                               Source:    NPDFfl  Pornn't-  No.  AK-On4497-l   (draff-).  1985

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     In general, ocean discharge of  oil  and gas field wastes  is  viewed by
concerned  State  agencies as an acceptable  discharge  alternative, provided
that effluent limitations are observed by the industry (EPA - CA,  1985).
                  CONSTRUCTION AND MONITORING REQUIREMENTS

Introduction

     There   is   wide, variation  among   governmental   entities   regarding
construction and  monitoring requirements associated  with pits,   sumps,  or
impoundments used  to  contain wastes generated from drilling and  production
operations.  This  section  of the report discusses design and  construction
features,  and  provide examples  of  impoundments and  centralized/offsite
pits as prescribed for Federal lands and by States.

     The terms  "sump,"  "impoundment,"  "pond,"  and "lagoon"  often are  used
synonymously  to  describe   a  pit  (EPA,  1983).    The  pit  consists  of  an
excavation of predetermined size and  shape,  and may be  lined or  unlined
depending upon the intended purpose.

     In  the  1983 EPA  Surface  Impoundment Assessment National Report,  the
following statistics were  determined  from a sample population of oil  and
gas sites:
       Thirty-one  percent  (64,951) of  all sites  (176,242)  were oil  and
        gas  sites.    (Pits  associated   with   drilling  activities   were
        excluded.)
       Thirty-seven percent of  all impoundments were associated with the
        oil and gas category.
                                   1-2-42

-------
       Through  the  randomization  of  site selection,  only 13  percent  of
        the located  oil  and gas  sites and 5  percent of  the  oil  and  gas
        impoundments were assessed.
       Disposal  is  the  primary purpose  of  67 percent of  the oil  and  gas
        impoundments,  with  29  percent  being  used  for  storage  (i.e.,
        emergency pits),  and 4 percent  being used for  treatment  prior  to
        discharge (usually oil skimming).
       Only 20  percent  of  the oil and gas  impoundments were lined.   For
        this report,  however,  the  definition  of a liner  did  not  consider
        mixing bentonite with native soil  or compacted soils as liners.
     In  the  exploration and  development  phases, reserve pits are  used to
store  drilling  fluids,  cuttings,  and  associated  wastes   produced  by
drilling.  At  the drill site, there may  be one reserve pit  to  handle all
drilling  wastes  or several  individual  pits to  serve different  purposes,
such as  containing  fresh "make-up" water, holding circulating mud prior to
disposal  in  the  reserve  pit,  holding  well  treatment  fluids  (fracture
fluids),  acting as  an emergency  pit,  and acting as a test pit.  These pits
generally are constructed for  temporary use and are  backfilled  at  the end
of drilling operations.

     During  the production  phase,  pits are utilized  for  several different
purposes.  A pit  is  constructed  to  hold  produced waters.   This  pit  is
designed  for the  long-term storage and  evaporation of fluids  associated
with the production of oil and gas. At wells that  are  reinjecting  fluids,
long-term  storage  pits  are constructed  to  act  as  settling/holding  ponds
for the injection fluid.

     In general, pit  construction  practices are left to the  discretion of
the company  and subsequently  pit  designs vary  widely  throughout  the  oil
and gas industry.   Many parameters  must be taken into consideration in the
proper  design  and  construction  of   a  pit,  including  facility  layout.
                                   1-2-43

-------
function,  location of  drilling  rig,  location  of  adjacent  water bodies,
geology, climatology, topography,  volume  of waste, ground-water hydraulic
gradient, characteristics of waste, and soil characteristics.

     The  following  is  a  brief  synopsis  of  specific  pit  design  and
construction  criteria  for  the  containment  of  wastes  associated  with
exploration, development, and production of oil and gas.
Pit Design and Construction Features

     Pit Types

     Reserve pits.   Proper location  and  construction  of pits  facilitate
the reclamation process  and help prevent problems such as  leakage and pit
wall failure.  Ideally, a pit should be excavated  from  undisturbed,  stable
subsoil  to prevent  pit wall  failure. For  areas where  excavating  below
ground  level  cannot be  done,  the pit  berm  is usually  constructed as  an
earthen  dam.   Sidewalls should  be  constructed with  a  slope of  less  than
3:1 to  give support  and minimize seepage.   Whenever possible,  a reserve
pit should  not  be  constructed on sloping ground or near the edge of a hill
top. This is often impossible to avoid, which means that  the  hillside  must
be  contoured  in such  a way that  the runoff water is diverted  around the
drilling location and  reserve pit.   Pits  should be  located  a minimum  of
300 feet  laterally  from  the  high water  mark of the  nearest water  body
and/or  intermittent water  courses,  according to one  source (MoeCo,  1984).
The site chosen should  be  high  enough to escape flooding  in heavy  rains.
A reserve  pit  is  typically  excavated directly adjacent  to where the  rig
and associated  mud equipment  will  be sited;  however,  in  recent years,  a
growing  practice for  disposal  of drilling fluids has involved  the use  of
centralized pits.
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     Centralized pits  are larger than onsite pits,  and they may serve  the
disposal  needs for drilling or  production  wastes  from multiple wells over
large  geographical areas.   Centralized  pits should  be close  to drilling
and  production  sites  to be cost-effective, yet they should be located  in
environmentally  safe  areas.   A  site removed  from  well-defined  drainage
basins  will  minimize the potential for  surface  water pollution from heavy
runoff  (Univ.  of Oklahoma,  1984).

     The  reserve pit should be  of adequate  size  to  properly  contain the
drilling  fluid.   The  reserve  pit volume should allow for ample freeboard
when the  pit is full.   The  purpose of freeboard is to create  a  margin  of
safety  to protect against unexpected  drilling conditions and unpredictable
elements  in  planning the mud program.  Increasing  drilling depth increases
the  drilling fluid  volume  and therefore more reserve  pit  capacity  may  be
required.  Overfilling  the  pit has presented  significant problems  in the
past.   In the case  of  an  off site  pit,  the  design volume  is  generally a
function  of  land availability  and topography, along  with business-related
estimates  of  drilling  fluid  volumes likely  to be  generated within  the
potential geographical service area (Univ.  of Oklahoma, 1984).

     Percolation  pits.   There  is  a  certain  controversy  over  whether
percolation  or seepage  is an allowable alternative to evaporation in areas
with humid  climates  (Illinois  EPA,  1978).   Regulations  concerning  the
matter  vary  from State to State.  Many  State  regulations  prohibit  the use
of percolation pits;  some States require  a ground-water discharge  permit
for  their use.  A percolation pit  is an unlined pit  in  which substantial
waste   volume   percolates   to  the   ground,   with   some   loss   through
evaporation.   The percolation  pit  is  designed and located to  maximize  the
infiltration of  waste  through  the  soil profile.   The  critical  limitations
for  any  specific  site would  be  the   depth  to  ground  water,  ground-water
quality, actual or potential use  of ground  water,  and the existence  of  any
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impermeable layers within the soil profile.  Percolation pits must  be  sited
in areas  where the distance to  ground  water is great and where  there are
no  restrictions  to  infiltration.   In  addition,  the  location  of  the
percolation pit could  depend on the location and quality of the underlying
ground-water aquifer.   Percolation can  adversely  affect the  ground-water
quality.  Percolation  pits  often are designed with several cells,  so that
one cell can be cleaned  or  raked if necessary to  improve  filtration  while
others  are  in  use  (CH_M  Hill,  1983).   Percolation  pits  are not  always
                       *
suitable for all  waste materials,  and seepage can result in the  formation
of pockets  of  salt in .the underlying soil.   These salts can slowly migrate
to ground water via leaching (Univ. of Oklahoma, 1984).

     Evaporation pits.  When properly designed,  constructed, and  operated,
evaporation pits  rely  on the atmosphere to  concentrate brines  or drilling
fluids  by removal  of water  as vapor.  The  relationship between  the  local
precipitation  and evaporation rates  should therefore be  considered.   The
successful  operation of  such a pit depends  on  the annual net  evaporation
rate of the brine or drilling fluid. The presence of dissolved solids and
oil  films  lowers   the  evaporation rate.  Other  variables  influencing  the
rate  include  the   air  and  brine  temperature,  relative humidity,   and  wind
speed  (Reid,  et al.,  1974).   If  the  space  at  the  drilling   location  is
adequate, it is preferable  to have a larger, more shallow evaporation pit,
because   the   increased   surface-area-to-volume   ratio   enhances    the
evaporation  rate   and final  disposal  can  be  achieved more   quickly  and
efficiently.    When   suitable   foundation    soils   are   not   available,
alternatives must  be  sought such as lining with clay, concrete, or asphalt
or   employing   a   synthetic   material   to   line   the   pit    (MoeCo,
1984).
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     Pit Liners

     Natural  pit  sealing has been found  to  occur when  the  settled solids
form  a  bottom  layer  that  physically   clogs  the  soil  pores   (Univ.  of
Oklahoma,  1984).   This  can occur most  effectively with  certain types of
drilling fluids,  and many drill operators count on this phenomenon to seal
mud pits  (Freeman and Deuel, 1986).  In  permeable  soils,  however,  natural
sealing may not  afford enough protection and  earthen pits should be lined
with an impermeable  material.   Many types  of man-made pit  liners exist,
and  they  can  be  classified  into  two major categories:  (1)  synthetic  and
rubber  liners and  (2)  earthen  and cement  liners.  Also,  there  is a  wide
variety  of application characteristics  within each of  these  categories.
Choosing the appropriate lining for a specific site is  a critical issue in
the design  for seepage control.  The criteria  for  lining  a pit are highly
dependent   on  the   specific   geographical   location,   climate,   local
hydrogeology, and the characteristics of the waste material.

     Synthetic  and  rubber  liners.   Synthetic and  rubber liners  include
PVC, butyl  rubber, neoprene, and hypalon.  Synthetic  liners are  popular in
applications  requiring  essentially  zero  permeability.  These materials  are
economical  and resistant to  most  chemicals when  selected and  installed
properly.    However,  many  are  susceptible   to  degradation by  ultraviolet
rays  and,   therefore,  should  not  be  used  in  long-term  impoundments.
Further, there is  disagreement  regarding the level of tensile strength  and
puncture  resistance  needed  (Western  Workshop,   EPA,   1985).    Standard
procedures  for   installing   and   maintaining   synthetic  membrane  liners
suggest that  side slopes should  not exceed a ratio of  3:1  and  subgrade
surface should be  dragged for sharp rocks and  rolled smooth.    A layer of
clay is applied  as  a base  for  the  membrane  liner.   Generally,  membrane
liners  are  made from sheets of 0.008 inch or thinner  and must be protected
from mechanical damage.   As  a  protective measure,  the liners  are often
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buried (Univ. of Oklahoma, 1984).  The effectiveness of the  membrane  liner
depends on not  being  punctured or torn during installation or use.   It is,
therefore,  imperative that  liners  meet proper  strength  and  durability
specifications and are employed properly.

     Earthen and  cement  liners.   Bentonite, asphalt, and  soil  cement  have
been  used  as  linings  for  pits  and  reservoirs  for  several  decades.
Bentonite is a  sodium-type  montmorillonite  clay and exhibits a high degree
of swelling, imperviousness,  and low stability in  the  presence of  water.
Seepage  losses for  bentonite-lined  pits  represent about   a   60  percent
improvement over unlined pits (Univ. of  Oklahoma,  1984).   The construction
approach for using  bentonite  to line pits involves overexcavating  the  area
to allow for the added layer  of  clay.   Side slopes should not  exceed  2:1.
The  subgrade  is smoothed and dusted and the bentonite layer applied  over
the  top.   Permeability of  bentonite  linings  is  greatly  affected  by  the
quality of the  bentonite.   If the bentonite is finer than a No. 30 sieve,
it should be  used without specifying size  gradation, but  if the  material
is  coarser  than  the  No. 30  sieve, it  should be  well-graded.   Bentonite
tends to crack  and  deteriorate  if allowed  to dry;  therefore,  a protective
blanket of soil is usually placed over the bentonite layer.

     Asphalt  linings   composed  of  prefabricated  buried materials  can  be
used  for both  onsite and  offsite  disposal  pits, since the  amount  of
special  equipment  and  labor  connected  with  installation  is  minimal.
Asphalt  membrane  linings can  be  constructed  at  any  time  of   year.   Its
convenient  usage   in   canals  and  ponds  may dictate that buried  asphalt
membrane lining is  the appropriate one  to use in many  cases.   Asphalt has
been  used  extensively  as  a  lining  material for brine  storage  basins
(Ostroff, 1965).
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Examples of Drilling Pit/Impoundment Permit Requirements

     Drilling Reserve Pits

     Often States  do  not issue permits relating  to  drill pits  or reserve
pits.   Monitoring  generally  is  not  required;  construction  requirements
vary.   Some  States have  construction guidelines covering  above  or  below
ground  construction,  required  freeboard,  and  compaction.   Pits typically
are unlined.  Such pits contain drilling cuttings, contaminated fresh and
salt water  produced during construction and  well stimulation,  and various
additives used during  drilling and well stimulation.   Often pits  are not
reclaimed,  nor  is  there  a  permit  required  for  a  drill  pit,  nor  a
contingency fund  required for management  of  abandoned  pits (Appendix  A  -
PA).

     General  language  is used  in  other State  regulations  to  require  that
mud pits, sumps,  reserve  pits,  or  tanks be of  sufficient size  and managed
to  prevent  contamination  of  ground  water  and damage  to  the  surface
environment.  After a well is completed or abandoned,  the fluids  are to be
removed  and  disposed of  properly,  and all mud pits,  sumps,  reserve  pits,
and dikes usually must be backfilled with earth or graded and  compacted in
such a manner as to be returned to a nearly natural  state.

     There may  or may not be  a requirement for lining with plastic or an
impervious material and,  generally,  such pits must  be closed within 12 to
18  months.    Often,  the  pits  are  placed  in wetlands  (Summary of  State
Regulations  -  Alaska,  California,  Ohio,  Oregon,   North   Dakota,  South
Dakota;  Alabama  Oil and Gas Administrative  Code 400-1-5-.03;  Alaska Oil
and Gas  Commission 20  AAC 25.047;  Georgia Department of Natural Resources
391-3-13(11);  Oklahoma Oil and Gas  Conservation Division Rule  3-110.1; and
Tennessee  State   Oil  and  Gas  Board  1040-3-3-.02).   Generally,  State
agencies do not prescribe drilling pit construction  conditions.
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     More specific instructions are  supplied to a driller by  the  Arkansas
Department  of   Pollution  Control   and   Ecology  through  a   Letter  of
Authorization.  Reserve pits must  be constructed  with either a  synthetic
liner of  at  least 20  mils thickness  or  an 18- to 24-inch  compacted clay
liner.  Such reserve pits must maintain at least a 2-foot  freeboard.   Pits
must  be  closed within 60  days  after the  drilling rig is  removed  from the
site.   In  Utah,  saltwater  and  oil  field  wastes   associated  with  the
drilling  process  may  be  disposed  of  by  evaporation   if  impounded  in
excavated earthen reserve  pits  underlain  by tight soil or lined  (Rule 309
- Utah Oil and Gas Commission).

     A  Letter of  Instruction  was  issued  by the Michigan  Supervisor  of
Wells  on  April   6,  1981,  which  provided  for  a  two-pit   drilling  mud
system梠ne for  freshwater muds  and one  for  saltwater muds梐nd required
that all reserve pits receiving other than freshwater  fluids be  lined with
20  ml  PVC or  an  equivalent  liner  as   approved.   Instructions, in  1985
require that  all  mud pits be lined  with  an impervious material  that  will
meet  or  exceed  specifications  for 20 mil  virgin  PVC.   Liners  shall be one
piece, or with factory-installed seams, and shall be  installed  in  a manner
sufficient  to  prevent  both  vertical  and  lateral  leakage.  A  revised
Supervisor  Instruction,  effective  February 1, 1985,   requires  that cellars
shall be  sealed, and  rat holes  and mouse holes shall be equipped  with a
closed-end steel liner or  otherwise  sealed or cased  in such a manner that
all  fluids entering the  cellar,  rat hole, and/or mouse hole  shall  not be
released  to the  ground but shall be  discharged  to steel  tanks,  the  lined
reserve  pit,  or  the mud circulation system.  Aprons  of 20  mil  virgin PVC
or other  equivalent  material  shall be installed under steel mud tanks and
overlapping  the  mud  pit  apron,  and  in   ditches  or  under pipes  used for
brine conveyance from cellars to  pits or  to steel mud tanks  (Appendix A -
MI).
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     Production Impoundments

     Montana allows evaporation of production salt water  when impounded in
excavated earthen  pits  underlain by tight soil such as heavy clay (Oil and
Gas  Conservation  Division  36.22.1227).  California  uses  lined sumps  for
evaporation  of  produced fluids  (Appendix  A -  CA).   The  Colorado Oil and
Gas Conservation Commission  in 1984, Rule 325, specifies  that  if domestic
water  supplies  are found to  immediately underlie  significant geographical
areas and are  not  separated from the  surface  by  a confining layer,  it is
to  be  proposed to the  Commission  that  a  rule be adopted to  require all
produced  fluid  retaining  pits  in  the  area   to  be  lined  and  properly
constructed so as  to prevent pollution.

     Wyoming  exercises  its  regulatory authority over  the  construction
location, operation, and reclamation of produced water pits  that  are used
for  the  storage,  treatment,  and disposal of  production and treated unit
wastes.  After June  1,  1984,  no earthen retaining  pit can be  constructed
without a permit.   Produced  water pits that receive less than 5 barrels of
water per day  on  a  monthly basis  may be exempt  from the formal permit.
Owners  of produced  water  retaining pits  in  operation  prior  to June 1,
1984,  may  continue  with   such  operation  as  long  as  it   causes  no
endangerment to  the State's  waters and as long as the  operation conforms
to  the  requirements  of  new pits.  When any  retaining pit  is sited  in an
area where  the potential  for communication between  the  pit contents  and
surface water or shallow ground  water is high, the Commission  may require
lining or waterproofing of any  retaining pit, installation  of monitoring
systems and provisions for  reporting, and any other reasonable  requirement
that will assure the protection  of fresh water.   Unlined  pits  must  not be
constructed on fills.   Pits  must not be constructed  in  a  drainage,   or in
the  flood plain of a flowing  or intermittent  stream, or in  an area where
there is standing  water during any  portion  of the year  (Wyoming Oil  and
Gas Commission Rule 326).
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     Rule  632-10-192  of  the  Oregon  Department  of  Geology  and  Mineral
Industries   provides    for   saltwater   disposal   in  excavated   earthen
evaporation pits  that are  lined with impervious  material.   All pits  must
have a  continuous  embankment  surrounding them sufficiently above the level
of  the  surface   to  prevent  surface  water  from  running  into  the  pit.
Illinois also  provides  for saltwater  evaporation  in lined  pits (Illinois
Division of  Oil  and Gas  Rule  lX(2)(a.   Mississippi  requires  temporary
saltwater  storage pits  to  be  lined with  an  impervious material.   Salt
water  must  never rise  to  within  1  foot of  the  top of  the pit walls  or
dikes  (Rule 63.III.E.3). .

     In  proposed Rule  83-3-600,  the State  Corporation Commission  of  the
State  of  Kansas  would  require  all  surface  permitted  ponds  to  have
30 inches  of   freeboard;   observation  trenches,  holes,   or   wells,   if
required; and be sealed with artificial materials if it is determined  that
an  unsealed  condition  will present a  pollution threat  to  soil or water
resources.

     The  Utah Water  Pollution  Control  Committee,  in  Part  VI,  6.4  of
wastewater  disposal  regulations,  requires   surface disposal ponds to  be
fenced  and properly  netted to  prevent access  by  waterfowl,  to  have  a
minimum 2  feet of freeboard,  and to be lined.  Each pond used for disposal
of more  than  100 barrels per  day of  produced water is  required  to  have
monitoring  wells  and  leak  detection  technology  in  both  vertical  and
horizontal  directions.   Detailed  instructions  are  provided  for  onsite
containment soil and for liners.

     The  Railroad  Commission  of  Texas has  issued  a  Water  Protection
Manual, published by the Texas Oil and Gas Division, which provides design
and  construction techniques  for  pits  proposed for  long-term,  continuous
use that must be authorized  by permit.   All  earthen dikes  surrounding  pits
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should  be  constructed of  soil material  that  is  capable  of achieving  a
permeability  of   1   x  10    cm/sec  or   less  when  compacted.    During
construction, successive  lifts should  not  exceed 9  inches  in  thickness,
and the  surface  between  lifts should be scarified to achieve a good seal.
The  dike  height  and width  should  be  consistent   with  the  volume  of
wastewater  to be  retained.    When  wastewater  is  retained  in aboveground
pits, it is recommended that the top width  of the  dike be at  least  4 feet
and  the side  slopes  not  be  steeper  than  3 to 1  (3 feet  horizontal  to
1 foot vertical).  Dikes for all pits are "keyed" into  the  underlying soil
to  achieve  a good seal  between the ground and the  bottom of the  dike  to
prevent  lateral  seepage  of wastewater  through the base  of  the  dike.   Two
of  the  most common  construction  methods for pits  are  "above  ground" and
"below  ground."   The  aboveground pit  should be used in areas  where  the
water  table  is  high.   The  aboveground method consists of  constructing
dikes  around  the  area  without   excavating  below  the   surface.    The
below-ground method  of constructing a  pit consists   of  excavating  an area
and building dikes around  the excavation.   The below-ground  pit should  be
used in areas where the water table is  well below the surface.

     A  proposed  rule  of the  Alaska Oil and Gas Commission  would  require
monitoring  of  surface  ponds  to  include  at  least  three  ground-water
monitoring wells and  may include  a leachate collecting and  sampling system
designed to  collect any waste or  leachate  escaping  as  a  result  of  the
failure  of  the  primary  liner.   Finally, the Letter  of  Authorization from
the Arkansas Department of Pollution Control  and Ecology  requires produced
salt water  to be  stored in a plastic  or fiberglass   tank above  ground and
resting on a concrete pad.

     Centralized/Offsite Pits

     On the western side of the San Joaquin Valley,  California,  there  is  a
wastewater  disposal  facility permitted  on  Federal  land  where  the  oil
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industry has  cooperated with  a  private  consultant and formed a  series  of
sumps that cover  approximately 20 to 40  acres.  These  sumps  are used  for
percolation and evaporation (Summary of  State Regulations - California).

     Rule  325  of the  1984 Rules  of  the Colorado  Oil  and Gas  Commission
requires an impervious, weather-resistant lining, a  leak  detection  system,
monitoring wells,  and  an opportunity  for  State  inspection  of  the  leak
detection system, the liner,  and cover material for the  liner.

     Rule 3-110.2 of the  .Oklahoma Corporation Commission permits  the  use
of  centralized  earthen pits provided they  are  sealed  with an  impervious
material, do not  receive  outside runoff  water, and are filled and  leveled
within  1  year after abandonment.   The  chloride  content  of the  contained
fluids  must   not  exceed  3,500  mg/1.  Centralized  pits  are   created  by
excavating,  damming  gullies,   and  using  abandoned  strip pits.    Every
centralized earthen pit must be  completely  enclosed  by a  permanent  woven
wire  fence  of at least  4 feet  in height.   No centralized earthen pit  is
allowed  to contain  a  soil  seal  less   than  12  inches  thick   with  the
coefficient of  permeability no  greater  than 10    cm/sec.   Mew pits  are
required  to  have  monitoring  wells,  which are  sampled  principally  for
chlorides and pH.  There  is  currently a  proposal to  make such requirement
applicable  to   existing   centralized    pits.    Three    wells   would   be
required梠ne upgradient  and two downgradient.  Any  indicated change over
background  in  the  constituent  levels   tested  would  indicate   potential
pollution.

     Federal Lands

     The  Bureau of  Land  Management  (BLM)   approves  the  use,  on  Federal
lands, of  unlined surface pits as a  temporary means  of storage  of fluids
associated with drilling,  redrilling, reworking,  deepening, or plugging of
                                   1-2-54

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a well.  Such  pits  must be promptly and properly emptied and restored upon
completion  of   the  operations;  they  may  be  used  for  well  evaluation
purposes for  30 days  (see Appendix A.   Summary of  Federal  Regulations -
Bureau of Land Management).

     Generally, BLM authorizes  unlined pits when:  (1)  input  fluid volume
averages 5  barrels  or  less per day, (2) the total dissolved solids is less
than 5,000 mg/1, (3) water will be used for  livestock or wildlife watering
or  irrigation,  (4)  well  fluids are of better quality  than area's surface
or subsurface waters,  and .(5) a discharge is allowed by an NPDES permit.

     The Bureau of Land Management permits disposal of  produced water into
lined  and  unlined pits,  but  all  such  pits  must:   (1)  have  adequate
storage, (2) be maintained to prevent  surface discharge,  (3)  be  fenced  to
preclude large  animal  entrance, (4) be maintained free from floating oils,
and (5) be constructed away from established drainage areas and to prevent
surface water entrance.

     For longer-term,  lined, produced water disposal pits,  leak detection
underlying  a   gravel-filled   sump  and   lateral   system  is   required.
Monitoring  is  limited  to  total  dissolved  solids,  pH,  chlorides,  and
sulfates.

                   EVALUATION OF WASTE MANAGEMENT METHODS

     An  evaluation  of  disposal  methods  will   be  conducted  for  waste
disposal techniques.   Disposal  methods will be examined to determine their
effectiveness in removing  (or mitigating the environmental  effects  of)  the
pollutants  identified  during  the  screening sampling program conducted June
- September 1986  on wastes from onshore oil  and gas  sources.   Analytical
results  from  the  screening  sampling program will be presented in  the  EPA
Technical Report due January 31, 1987.
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     Identification  of waste  management practices  has  been accomplished
through  research  into  published  and   unpublished   literature,   through
extensive  contact  with  State  regulatory  agencies,  through  observation
during  the  screening  sampling  program,  and  through  interviews.    The
control/disposal practices identified  through this research were presented
earlier in this chapter.

     Waste management practices other than those identified  in  this report
may   be   appropriate   for  particular   pollutants,   groups   of   similar
pollutants, or estimated pollutant loadings.  Identification  of  alternative
waste management practices would be  questionable,  however,  if it was  based
only  on  the limited  data  available  from the literature.   The literature
contains  little  data  regarding  the  full range of constituents  in  oil  and
gas  wastes   (see   Literature   Review   under  Waste  Generation).    Thus,
identification of  alternative  treatment and  disposal technologies  will  be
directed  by  the analytical  results  from  the  screening  sampling  program
previously mentioned.   Detailed sample site  documentation,  in  addition  to
the analytical results, will  be part  of the  January 1987 technical  report.

     Alternative  technologies   will   be  identified  based  on   historical
evaluations  of  their  effectiveness  for handling particular  pollutants,
groups  of  similar  pollutants,  or   pollutant  loadings   as targeted  by
analytical data  from the screening sampling  program.   Technology  transfer
and  data  for  new  treatment   methods  under  development   will  also  be
considered.

     When  the  data  are available,  the  effectiveness  of waste  management
practices will be evaluated based on:

      Fundamental chemical and/or engineering concepts;
      Treatability or other  related  information from  the  literature;
                                   1-2-56

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      Best estimates based on professional engineering judgments; and
      Environmental conditions.

     It is  anticipated  that  the evaluation of  control/disposal  techniques
will be  presented in detail  in the  final technical  report.  For ease of
understanding, however,  the  effectiveness  of the technology may  be  ranked
in  ranges  appropriate  to  distinguish  between  levels  of  performance.
Mitigating  circumstances  affecting   the   performance  of  a   particular
technology   (e.g.,   the  use   of   evaporation  pits   in  areas  of   net
precipitation) will also be presented.

     If  the  analytical  data   present  a  relatively   limited   list   of
pollutants  of concern,  a matrix will be constructed  identifying  the major
pollutant   loadings  in  each  waste  stream,  current   waste   management
practices,  and  alternative control/disposal techniques,  as  illustrated by
the  example  in  Figure   1-12.   (If  the pollutant  list  is  extensive,  an
effort  will  be  made  to  construct  the matrix presenting  only  the  most
hazardous,  difficult  to  treat,  or   highly   concentrated   pollutants.)
Entries  in  the   matrix  will   be  codified  to  indicate  the   estimated
effectiveness of  waste   management practices  for each pollutant   found  in
concentrations  of  concern.   The  matrix  will  serve  as a  summary of  a
detailed discussion of the evaluation for each waste management practice.

     Some  alternative  waste  management  practices  will  be identified  for
control  or  treatment   of  particular  pollutants.     It  is  expected  that
literature  regarding treatability or  other  aspects  of  the  technique(s)
which  mitigate   environmental   effects will   provide  a  basis  for  the
evaluation.
                                   1-2-57

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                        CURRENT PRACTICES          ALTERNATIVE TECHNIQUES
Major pollutants
DRILLING

Muds
Pollutant 1
Pollutant 2
Pollutant 3
Reserve pits
Pollutant 1
Pollutant 2
Pollutant 3
PRODUCTION
Produced water
Pollutant 1
Pollutant 2
Pollutant 3
(and so forth for each major waste stream)
    Figure 1-12   Example matrix of pollutants and control/disposal
                  methods to be constructed
                                   1-2-58

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                                 REFERENCES

California Water  Resources Control  Board.   1983.   Water Quality  Control
Plan for Ocean Waters of California, November 1983.

Canter,  L.   W. ,   et  al.   1984.   Environmental  Implications  of  Off-site
Drilling Mud  Pits in Oklahoma.   University of  Oklahoma,  Environmental  and
Ground  Water Institute,  for Oklahoma  Corporation Commission.  May 1984.
Volumes I and II.

CH2M  Hill.    1983.   Feasibility  Study  Report: San  Ardo  Field  Produced
Water Disposal/Reuse, June 1983.

Corporate Literature supplied by  VenVirotek,  1536 Eastman Ave.,  Suite 6-A,
Ventura, CA 93003.

Crabtree,  Allen  F.    1985.   Drilling  Mud  and  Brine  Waste  Disposal  in
Michigan,  Geological  Survey  Division  of  Michigan  Department of  Natural
Resources, April  1985.

Deeley,  George  M. and  Larry W.  Canter.   1985.   "Chemical  Speciation  of
Metals in Nonstabilized and Stabilized Drilling Muds"  In:  Proceedings  of
a National Conference on Disposal of Drilling     Wastes, May 1985.

E-Vap  Systems.   "For  Immediate Release:   Water  Disposal for Gas   or  Oil
Wells  by  Evaporation,"  (advertisement),  E-Vap Systems,  400 North 8th, Fort
Smith AR  72901.

Federal Register Vol. 47 No. 139,  July 21, 1982.

Field,  Mary  M.  and  W.  G.  Smith.   1986.   Design  Considerations  for
Landfarming Non-Hazardous Oilfield Waste Drilling Fluids.

Freeman,  B.  D.  and  L.  E.  Deuel.   1986.    Closure of Freshwater  Base
Drilling Mud Pits in Wetland and Upland Areas.

Illinois  EPA.   1978.   Illinois  Oil Field Brine  Disposal  Assessment: Staff
Report, November  1978.

Kissock,  D.  C.    1986.   Landfarming:   The Cost Effective State-of-the-Art
Solution to Oilfield Waste Disposal.

Kus  and Card.  1984.   "Produced  Water Reuse  Considerations  for  In-situ
Recovery:  A  Case  Development,"   The  Journal  of  Canadian   Petroleum
Technology, January 1984, p. 66.

McCaskill,  Clark.    "Well   Annulus  Disposal  of  Drilling   Wastes"   In:
Proceedings  of  a National  Conference on Disposal of Drilling Wastes,  May
1985.
                                   1-2-59

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McCray  and  Cole.   1959.   Oil  Well  Drilling  Technology,  University of
Oklahoma Press.

Michalczyk, Betr  L., I.E. Pollock, and Heather  R.  White.   1984.  Treatment
of Oilfield Production Waters, October 1984.

Michigan   Department  of   Natural   Resources,   Letter   of  Instruction,
Supervisor of Wells, April 6, 1981.

Moeco  Sump  Treatment,   "Brief  Summary  of  the Reverse  Osmosis  Process"
(advertisement),  July 24, 1984.

NL    Baroid,    Advertisement   for    ENVIRO-FLOC   and    ENVIRO-FIX
reserve pit treatment processes, 1986.

Neidhardt,  Dietmar.  "Rig-site  System Allows  Water  Reuse, Cuts  Cleanup
Costs,"  Oil and  Gas Journal, March 4, 1985, p.88.

Ohio  EPA.    Brine  Disposal   from  Oil  and  Gas Production  in Ohio,  1983
(reprint).

Railroad Commission of Texas.  1985.  Water Protection Manual.

Templeton,  Elmer E.  and Associates.   1980.   Environmentally  Acceptable
Disposal  of Salt Brines Produced with  Oil and Gas,  for  the Ohio  Water
Development Authority, January 1980.

U.S. EPA Region X.  1985.  "Authorization to Discharge  Under the  National
Pollution Discharge Elimination System," No. AK-004497-1 (draft).

U.S. EPA.   Air  Drilling  Technology:  Five  States in West Virginia, November
1985.

U.S. EPA.   Office  of  Drinking Water.   Surface  Impoundment Assessment  -
National Report.  December 1983.

U.S. EPA.  Sampling Site Visit, Louisiana, June 16, 1986.

U.S. EPA.  Sampling Site Visit, West Virginia,  August 18,  1986.

U.S. EPA.   Site  Visit  Reports - Screening Sampling Program for Oil and Gas
Industry.  In Press.  June-September 1986.

U.S. EPA.  State/Federal Western Workshop, Alaska,  December 1985.

U.S. EPA.  State/Federal Western Workshop, California, December 1985.
                                   1-2-60

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U.S. EPA.  State/Federal Western Workshop, Louisiana, December 1985.

U.S.  EPA.   May  1973,  Fox  et  al.   Recondition  and Reuse  of  Organically
Contaminated Waste Sodium Chloride Brines.

Waite, Burt A.,  Jeffrey L.  Moody, and Scott  C.  Blauvelt.    1983.   Oil  and
Gas Well  Pollution Abatement  Project  ME No. 81495,  Part  C, submitted to
the Pennsylvania Department of Environmental Resources, June 1983.
                                   1-2-61

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                                 CHAPTER  3
       ESTIMATING THE COSTS OF ALTERNATIVE WASTE MANAGEMENT PRACTICES


                          INTRODUCTION AND OVERVIEW
    As  requested under  Section 8002(m)(F)  of RCRA,  this chapter  of  the
report describes EPA's procedures for estimating the  costs attributable to
oil  and gas  field alternative  waste  management practices.   Essentially,
this  involves  estimating the  incremental  costs  to oil and  gas  field
companies of  implementing increased  levels  of environmental control beyond
the  "baseline"  practices  currently  employed  in  the  various  Regions  and
States.  For  the  Report  to Congress, these costs will be  estimated at the
individual project level  for  representative typical projects.   Costs  will
also  be  scaled  up  to  Regional   and  National  totals   as  a  basis  for
evaluating potential industry-wide  impacts (see Chapter 4).

    Procedures  for estimating  these  costs  involve  a   series   of  steps
described briefly in the following  paragraphs.

Step 1.  Identifying Relevant Waste Management Practices

    For cost  estimating  purposes,  relevant  practices include both standard
waste  management practices  commonly  employed in  the  various   producing
regions,  as  well  as  more  advanced  or sophisticated  waste  treatment,
                                   1-3-1

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storage,  and  disposal methods  that  are potentially applicable  but  may be
used  less frequently  or  not  at all  in  certain  regions  at present.   A
relatively  complete  array  of  such  practices  was  described  earlier  in
Chapter 2 of this report,  and a selected representative group  will  be used
in the cost study.

Step  2.   Estimating Project-level Costs for the Selected  Waste  Management
Practices

    Engineering cost  functions  will  be developed for the  individual  waste
practices  based  on  previous  EPA  cost  modeling  work,  current  industry
literature, and selected  industry interviews,  as necessary.    These  cost
functions for unit  processes  at various sizes will constitute the building
blocks  of the  cost  estimating  methodology.    Preliminary  work and  data
sources for these basic costs are described in  some detail following this
introductory overview.

Step 3.  Structuring Waste Management Scenarios

    In  order  to  have a  consistent  basis for evaluating costs,  it  is
necessary  to   define  all   cost  elements  associated  with  each  waste
management alternative,  both  at  the  facility level  and  the  aggregate
industry   level.    Basically,   the   concept   of  the  "scenario"   is  to
hypothesize a  given  level  of  environmental   control,  typically  a  level
beyond  the  baseline  that is  currently being  achieved at some,  or  perhaps
many, projects in a given  region.  This might  be stated in terms of  a set
of waste-management technology  requirements (such  as present RCRA Subtitle
C  Standards)   or  in  terms  of  specified  conditions  on  environmental
contaminant  releases,  or  otherwise.    Two   or  three  such alternative
scenario will  be  structured for purposes  of the Report to  Congress.   Each
scenario  will  clearly  state  both  the   types  of  waste  characteristics
                                    1-3-2

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relevant to the particular  case and the control measures  involved so that
comparisons may be  drawn between  the  costs of  practices  observed  in the
baseline profile  and the costs estimated for  the  practices  assumed in a
given alternative scenario.

Step 4.  Determining Affected Projects

    Not all  projects in  a  given  Region  or State will  be  affected  by  a
given  scenario for  increased  environmental  control,  either because the
project does  not generate  "problem"  wastes or  because  current  practices
(either  naturally   or   because   of  current   State  or   other  Federal
regulations)  already  meet  the  full  requirements   for   the  management
scenario.   This  may be  the case  for entire States or multi-State Regions
for  a  given scenario.   The task  here  is to  identify the  proportions  of
total  projects in all  major Regions that would  be affected and the degree
to which they  would  be  affected for particular  waste-categories.   This  is
an   essential  step   in  generating  reasonable  cost   estimates  at  the
individual project level, and especially so in  scaling  costs to Regional
and National aggregates.

Step 5.  Calculating Project-level Cost Increases

    Given  the  waste  management  cost  functions  for both baseline  and
alternative practices, together with information on Regional practices and
affected   facilities,   "incremental   costs"   (increases   incurred  between
baseline   and  improved  alternative  practices)  will  be   calculated  for
representative Regional  projects.   (Regional differences  are discussed  in
some  detail  in  Chapter 4  in conjunction  with economic  impacts and the
selection  of typical representative projects.)
                                    1-3-3

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Step 6.  Scaling Up to Regional and National Aggregate Cost Totals

    The final  step  in the cost estimating analysis  is to  use  information
gathered  from the  industry-wide  profiles  of affected projects,  together
with  the  incremental  cost  estimates  for  representative  projects,  to
calculate  aggregate  costs.   Total  investment  costs,  total   annualized
costs, and cost per unit of product (per gallon of crude oil or  per  MCF of
natural gas)  will be presented on  both a Regional and National  basis for
comparisons.    These   aggregate    costs,    together   with    costs   for
representative projects,  provide  the  basis  for estimating the significance
of any  potential economic  impacts  due  to  changes  in current  practices.
These economic effects are the subject of Chapter 4.

    The  remaining  pages  of  this  chapter  provide  further  details  on
estimating  methods  and  expected  sources  of  data  on  cost functions  and
other work in progress.
ESTIMATION OF COSTS FOR INDIVIDUAL CURRENT AND ALTERNATIVE WASTE MANAGEMENT
                                  PRACTICES
    The  purpose  of  this  section  is  to  discuss  a  limited  number  of
representative disposal practices, such  as  the use of earthern pits {lined
and  unlined)   and Class  II  (hazardous   waste)  injection  wells,  and  to
briefly  describe how  EPA will  estimate baseline alternative  management
costs.  The section also presents known or expected sources of information
to support the cost analysis.

    Cost  estimates  for  other  important  current  control   and  disposal
methods not included here,  such  as waste solidification, landfarming,  and
incineration,   which  are  described at length  in Chapter 2,  will  also  be
analyzed as part of this effort.
                                   1-3-4

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Earthen Pit Storage and Disposal

    Drilling wastes are  commonly held in a reserve pit  prior to disposal.
Costs  for  disposal  in  lined  or  unlined  evaporation  or  evaporation/
percolation  pits  will   be  adapted  from the  general  surface  impoundment
estimates from the  EPA  literature (U.S.  EPA,  1985).   These  estimates  may
be  adjusted,  however,  in recognition of  possible difference between  the
assumptions of  the EPA  cost  functions  and  actual oilfield  practices.   A
more detailed  discussion of  current waste disposal practices  is provided
in Chapter 2.

    Literature Review

    The  drilling   cost   estimates   compiled  annually  by   the   American
Petroleum Institute and the  Independent Petroleum Association  of America
include a category  covering  road and site  preparation.   On  average,  road
and  site  preparation  represents  6.3  percent of  total  drilling  costs
(Independent Petroleum Association of America,  1986).  Unfortunately,  this
category is  too broad  to allow  identification  of costs  specifically  for
reserve pit  construction.  The  costs  for preparing the remainder of  the
site (other than the  reserve  pit) and for  any entry  roads commonly exceed
costs for the  reserve  pit.   Also, the  specific technology  represented  in
the  disposal  practices  is not identified by  the  industry-average figures.
Thus,  unless  more  specific   cost  breakdowns  can  be  developed  from  the
original industry  survey data,  the  published figures  can be used only  to
describe an upper limit to disposal costs.

    A  few  literature  sources  also  give some  indications  of reserve  pit
construction  costs  (e.g.,   Rafferty,  1985).   These   estimates  will   be
reviewed but will  not  be sufficient to provide the  basis  for  estimating
disposal costs.
                                    1-3-5

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    Various cost  estimates  for constructing lined and unlined  pits can be
derived  from  previous  EPA studies.  Estimates of these  costs are given in
several  sources  (Charles  River  Associates,  Inc.,   1985,  and U.S.  EPA,
1985).   Such  costs  will  be  reviewed  for  their   applicability  to  the
oilfield case.  The costs are  of  the form C = a  V   where C  =  cost,  a  = a
constant,  V = volume  of water or capacity of  the  facility,  and  b  =  the
elasticity of cost with respect to volume.

    Data Collection and Analysis

    Further  cost  analysis  for  construction  of  reserve  pits  will   be
developed using Means  Site  Work Cost Data 1986,  a standard cost estimation
source, and information to be provided by "dirt work" contractors.   In  the
Means  source,  costs are  presented for cut and fill  operations,  which  are
similar  to  the  process of  reserve pit construction.  The  unit  costs  for
site work  are  given per cubic yard.  These  unit  costs  may be converted to
total reserve pit construction costs using data on the capacity of  reserve
pits.  The  estimates derived using the Means source  will  then  be verified
and  adjusted  through discussions  with  firms engaged in site  preparation
work.

    For  closure  of the  reserve   pit,  the  pit  wastes   are   dewatered  (by
evaporation  or   vacuum  truck   removal)   and   backfilled.    Costs   for
evaporation are  incurred only when lease  agreements with landowners  are
based on the  amount of time the  reserve  pit  remains  in  place.   Costs  for
waste  removal  by  vacuum  truck  will   be  derived  through  contacts with
commercial oilfield waste removal  firms.   Costs for backfilling will  be
estimated using the  reference  source mentioned above. Means  Site Work Cost
Data 1986.
                                   1-3-6

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Disposal in  Lined Pits  (with Installation of  an Impermeable  Cap at Site
Closure)

    For  this technology,  clay or  artificial  liners  from one  to  three
layers thick would be  installed  in disposal  pits to limit  or  prevent the
release of leachate.   In addition,  an equivalent impermeable cap  would be
placed  over  the  facility   at   closure  to   reduce   infiltration  from
precipitation.   This  practice  is  primarily  applicable  to both  drilling
solids and associated wastes and to dewatered production sludges.

    Literature review

    Costs for liners  and  caps have been estimated in  the  models  prepared
by the Office of Solid  Wastes (specifically, see  U.S. EPA, 1985).   Cost
functions have  been defined  for  surface impoundments  using the  following
liner  designs:   single synthetic,  double  synthetic,   single clay,  single
synthetic/clay, double  synthetic/clay.   The  equations are of the  form C =
a  V  where  C =  cost,  a  =   constant,  V  =  volume  or  capacity  of  the
facility, and b  = the  elasticity  of  cost with  respect to volume.   The
values for b vary from 0.6  to  0.7 in the EPA studies.  Costs for  facility
caps are estimated in a similar fashion in these studies.

    Data Collection and Analysis

    The previous  EPA  studies  will be used in estimating costs for  facility
liners and  caps.   The  cost functions  for various  liner  designs can  be
developed on  a consistent  basis from this source.   Assumptions  in  the cost
models  about facility  design,  location,  and  soil  characteristics  that
influence the costs for facility  construction will be  reviewed before the
cost functions are used.
                                   1-3-7

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Monitoring and Site Management Practices

    This  includes  components  that  are  commonly  required  at  permanent
disposal  sites.   The   elements   include  leachate   collection   systems,
monitoring   wells,   runon/runoff   systems,   property  fencing   and   site
security, and provisions for post-closure maintenance  of the facility.

    Literature Review

    Costs  for  each  element  of  the  package will  be  adapted  from  the
previously  estimated EPA  cost models  maintained by  the  Office  of  Solid
Waste.  Depending on the element,  costs will be expressed as a  function of
the disposal volume or of the reserve pit dimensions.

    Table 1-15  presents cost functions estimated for  basic monitoring and
site management  items  in a previous EPA  study.   Economies  of  scale  exist
for  leachate  collection and  treatment  (the  exponent  in  the equation for
estimating capital costs is less than 1), but not for  the  other  items.

    Permitting  costs  may also  be  incorporated  into  this  alternative.
Costs for permitting activities will be derived from  previous  EPA studies
covering the  administrative  and paperwork  burdens  of permit application.
The  costs  will  be  based  on  estimates  of the  hours  and personnel  skill
levels needed to prepare permit materials.

    Data Collection and Analysis

    Assumptions about the design and extent of the monitoring package  will
be  adapted  (with  the  costs)  from  the  previous  EPA  estimates.   Some
adjustments must be  made to  account for the  unique  features  of  oilfield
waste  disposal  facilities.   For  example,  in comparison  to landfills  or
                                    1-3-8

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This page for 1-15
Sample    format    of    costs    for    monitoring    &     site    mgmt.
                                    1-3-9

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surface  impoundments  that have  been modeled  in most  EPA work,  oilfield
reserve  pits  are  small disposal facilities.  The capacity  of the smallest
surface  impoundment in a  recent  EPA study is given as  638,307 gallons, or
14,300 barrels  (U.S.  EPA, 1985).  This capacity would normally be adequate
to  handle  wastes  from  a  well  drilled  to  deeper-than-average  depth.
Extrapolation  of  the  cost  estimates  to allow  analysis of  smaller waste
volumes will be necessary.

Offsite  Disposal  in  a Secure  Facility  (i.e.,  Those  Employing  Multiple
Liner Systems and Other Controls)

    This  disposal  method is  primarily  applicable  to  most   drilling  and
production wastes.

    Literature Review

    Costs for offsite  solid  waste disposal  in secure facilities  have been
estimated by EPA  and are  included in  the Liner Location Risk  and Cost
Analysis Model,  Draft Report,  (U.S.  EPA,  1985).   The estimates  include
costs for  facility construction, operation  and maintenance,  and closure.
The disposal facilities were  designed with double or triple liner systems,
leachate collection and monitoring provisions,  and  other control systems.

    Alternatively, costs  for offsite disposal  might  simply include charges
made  by  commercial  facilities,  costs   for  waste  management  prior  to
shipping,  and   costs  for  transportation.   The  latter  are  described
separately below.   The disposal  charges at commercial facilities  have been
presented in recent  EPA  studies  (Industrial  Economics,  Inc.,  1985,  and
Sobotka and Company, 1985).   Table 1-16 summarizes the  estimates  presented
in  recent  publications.    Most  of  the estimates  were   defined for  broad
categories of hazardous waste and are  not specific to  disposal of reserve
pit   wastes.    Only   the   estimate    presented    in    the    Office   of
                                   1-3-10

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    TABLE 1-16.  Cost Estimates in Literature for Centralized Disposal
Type of
Disposal
Bulk from Waste
1983 Prices
  (per MT)
Source
Landfill       Based on charges for bulk-
               form waste; transportation
               costs not included.
                              $28-$100
              Booz,  Allen
              & Hamiliton,
              1984
Landfill3      Based on costs for low-risk   $125       Industrial
               hazardous waste (including               Economics Inc.
               drilling muds) disposal at               et al..  1985
               commercial facility; trans-
               portation costs not included.

Landfill13      Based on charges predicted    $13-$29    U.S. Office
               for a captive facility plus              of Technology
               profit estimates;  includes               Assessment,
               100-mile transportation                  1983
               charge.

Surface        Based on charges for a        $264.6     Industrial
Impoundment*5   captive facility plus pro-               Economics Inc.
               fit estimate; includes 100-              et al.,  1985
               mile transportation charge.
a   These estimates are based on estimated operating costs for a
captive facility (i.e.. a facility owned by the waste generator) combined
with an assumption regarding the profit level  and transportation expenses.

b   This estimate is based partly on figures compiled by Booz-Allen &
Hamilton which are also referenced in this table.  Thus, the estimates
may not be fully independent from the other observation.
                                  1-3-11

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Technology  Assessment  study   (Office   of  Technology  Assessment,  1983)
applies to low hazard wastes, such as most drilling muds.

    Data Collection and Analysis

    Price quotations  for  disposal at  selected  waste  disposal  facilities
will  be  assembled to  supplement  the  literature  estimates  for  offsite
disposal  of  reserve  pit  wastes.   Some  firms  are  currently  receiving
drilling  solids,  so their charges  can be used directly  in  this research.
For facilities that are not  receiving  such wastes at  this time, estimates
of  charges  for low hazard,  bulk  wastes  will be considered  most likely to
represent the applicable costs.

Estimation of Waste Transportation Costs for Centralized Disposal

    Oil  and gas  companies  will  incur   incremental  transportation  costs
whenever  disposal  alternatives   require  shipment of  wastes  off  site  or
shipment of wastes  to  more distant sites  than  those currently  used.   The
most  significant  transportation  costs will  be  incurred for shipping of
drilling  wastes  to centralized  treatment  facilities  or  pits  and  for
shipping  of production fluids  for treatment  and/or disposal in Class II
wells.

    Literature Review

    Literature on  hazardous  waste disposal includes estimates of  the  cost
per ton  for waste shipments  (e.g.,  Sobotka and Company,  Inc.,  1985).   Many
of  the  available  estimates from  EPA  reports are  derived from  an earlier
study  of waste transportation  costs  (Abkowitz et al.,  1984).   This  study
provides a set of assumptions that may be used to derive estimates of the
fixed and variable components of transportation costs.
                                   1-3-12

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    Previous  EPA  studies  have  estimated mileage  to  specific  hazardous
waste  disposal  facilities  by direct  measurement of  highway miles  or  by
averaging distances  from waste  generators  to  disposal  sites.   EPA data
bases  are  available  to identify  the  location  of  the specific  disposal
facilities.

    Data Collection and Analysis

    Shipping costs for oilfield wastes are regulated in some  States  (e.g.,
Oklahoma) and such  cost figures will be  assembled.  These  regulated price
limits  and  the  other  literature  values  may be  a  sufficient  basis  for
estimating shipment costs per ton-mile.

    To  estimate  the  distances for  transportation of   drilling  solids  and
associated  wastes,  an  average  distance  will  be   calculated  from  the
approximate  middle   of oil   and  gas  basins  to  the  nearest  disposal
facilities.    This  calculation  will  be  made  using  maps   of  National
oilfields  and  information  on  the  exact  highway  location  of  disposal
facilities.   Depending  on  the volumes  involved,  new  facilities dedicated
to  oil  and  gas  waste  disposal  may be  hypothesized   for  cost  estimating
purposes.

    To  estimate  incremental transportation  distances  for  drilling   fluids
and production fluids,  a similar procedure will be  used.   Drilling  fluids
and  production  fluids  may be shipped  longer  distances  if   necessary  to
reach  Class  I instead  of  Class  II  disposal wells.   At  present.  Class  II
disposal wells are  common  in  oilfield  areas and  transportation distances
are relatively short.  Class I disposal wells are much less common.

    Estimates of current transportation distances (to Class II wells) will
be  developed  based on  a sample  of  current  operations.    Next,  distances
                                   1-3-13

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from  the  approximate  middle  of  oilfield  basins  to  specific  Class  I
disposal wells will  be  estimated.   Information on the  location  of Class I
wells  will  be   requested   from  State  agencies  or   EPA   Regions  with
responsibility  for  the  UIC  program.   An  average   distance   will  be
calculated for a sample of oilfield basins.

    The transportation costs  incurred  by oil companies will  be  restrained
to  the  extent   that   nearby  disposal  options  eventually  become  cost
effective.    As   transportation  distances   increase,   for   example,   oil
companies become  more  likely  to drill  new Class I wells in their producing
fields.   Relative  costs  of  such  options  will  be  considered  in  the
transportation analysis.

Class II Injection Wells

    A  common  disposal  method for  most production liquids is injection in
Class  II wells.   Produced water,  however,   may  be  injected for  disposal
only  or  it  may  be  injected as  a part  of oilfield pressure  maintenance
efforts.   A detailed discussion is  provided in Chapter 2.

    Literature Review

    Costs for drilling  new  Class  II  injection wells were estimated  in a
1979 study of the Underground Injection Control Program (Arthur D. Little,
1979).  A  range of  estimates  was  given  for wells  drilled  to  depths  of
2,000  and  5,000 ft.  Since  1979,  however,  drilling costs have  fluctuated
widely.  Therefore,  current  costs for  drilling Class  II  injection  wells
will be obtained from drilling contractors.

    Costs  for  various  components  of  injection well  operations  are  also
addressed in the previous report (Arthur D.  Little,  1979).   The  estimates.
                                   1-3-14

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however, do not provide  a  complete profile of operating  costs  or disposal
costs per barrel of produced water.

    Data Collection and Analysis

    Costs for  injection  for  the purposes of disposal only are approximated
by  the  prices  charged  at commercial  disposal  wells.    Price  information
from  these  facilities will  be  obtained from a  limited survey.   Costs for
injection in  pressure maintenance  (waterflood)  operations  are offset  by
enhanced  hydrocarbon  production.   Effective   costs  for  disposal  may,
therefore,  be  zero  or  negative  depending  on  the   effectiveness  of  the
waterflood.

     PLANS FOR ADAPTING EPA COST MODELS  AND FOR ORIGINAL COST  ESTIMATION

    Many  if  not   all  of  the  baseline and  alternative  waste  management
practices described  have been  modeled,  to  some degree,  in previous  EPA
studies.  These models  and  other cost  estimates  found   in  the literature
will  be  adapted   where  appropriate.   Original   cost  estimates  will  be
developed where necessary to supplement the previous results.

    In  preparing   original  cost  estimates,  source materials will  include
literature  references,  price quotations  from vendors of waste  treatment
and  disposal   systems,  and  original  engineering estimates  as  appropriate
for each  cost element.   Cost estimation technologies to  be  used for  this
project  include exponential  cost  functions,  constant cost  functions, and
model case  estimates,  depending on the  specific item under  consideration.
In  most  cases,   exponential   functions  are  most  desirable  for  their
flexibility  in defining  disposal costs for wells   with differing  waste
volumes.   For  centralized  disposal  of  drilling  media  and  associated
wastes,  costs  to  the oil  and gas  industry  are   the  prices  charged  by
                                   1-3-15

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commercial  waste  disposal  firms,  plus  transportation.    Constant  cost

functions (e.g., a  constant  dollar-per-barrel  price estimate regardless of

waste quantity) have  been  used in much of  the literature  to  characterize

these  prices.   For  this  study,  information  on  prices   for  bulk  waste

volumes  (such as would  apply to drilling solids) will  also be  sought.   A

constant  or  variable  cost function  will  then  be fitted to the  cost data.

Cost information for small  volume wastes will also be obtained in  order to

establish a  cost function  for associated wastes  (such  as  tank bottoms and
separator sludges).


Identify Incremental Actions and Costs


    Those operations  required to  alter  their  waste management  practices

(i.e.,  affected  operations)  under  a  scenario  will   incur  incremental
costs.  The estimation of these incremental  costs requires:
    1.   Identification  of  baseline  waste  management  costs.    The
        estimates generated  in the analysis described above  will be
        applied  to   establish  baseline   costs   of  the   affected
        operations.

    2.   Estimation of incremental  compliance measures.   Based on the
        list of alternative waste management practices,  the  measures
        available  to conform  to  the  scenario will be  identified,
        including incremental waste transportation actions.

    3.   Establish least-cost compliance method.  In  some  cases,  more
        than one  alternative will  be  available for  affected firms.
        By  comparing  the cost of  available measures,  a  least-cost
        method can be identified.

    4.   Compare  costs  to  baseline costs.   Once   the  cost of  waste
        management practices of  affected  firms have been  estimated,
        these  costs  can be  compared  to baseline  costs  to  establish
        incremental compliance costs.


    The incremental  cost estimates  will   be  expressed  initially as  both

capital investment costs and operating costs.   The  capital  cost estimates
                                   1-3-16

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will be annualized  based  on the expected life  of  the capital item and the
industry discount rate.   The cost  estimates  will be  defined in  terms  of
constant  1986  dollars,  so  the  discount rate  employed  will reflect  the
industry's real cost  of  capital.   For  purposes of  calculating  annualized
costs, typical project lifetimes must be estimated from available industry
services.

    Because there  are so  many  oil  and  gas  projects,  the  cost  analysis
described above must  generally be performed on the basis of representative
or "model" operations.  In this case, model  oil and  gas  operations will  be
defined to represent  all of  the firms  affected  under a  given scenario.
The  identification  of model  facilities  is  described in  more  detail  in
Chapter 4.
Develop Regional and Aggregate National-Level Cost Estimates

    The  cost   estimates   for  affected  operations  will   be   aggregated
Regionally  and Nationally  to  derive  annual  total  costs  for   each  waste
management  scenario.  If  model  projects are used.  National costs  will  be
estimated  by  multiplying  the  model  facility  costs   by  the  number  of
facilities the model represents.

    Regional  or National  cost  estimates  will  be  two  types.   First,  a
National-level  investment  cost  total  will  be generated.   This  is  a sum of
the  investment costs  (before  annualization)  for  the  affected  projects.
Second,  a  National-level  annualized  cost  total  will   be  generated  by
summing the total annualized cost to affected projects.

    In addition to these National cost totals, other cost  measures  will  be
computed,  including the  environmental control  cost per  ton  of  disposed
                                   1-3-17

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waste and  the environmental control cost per  barrel  of oil or MCF  of  gas
produced.  The former can be used for comparison to the costs of  other  EPA
hazardous waste  management programs.  The  latter can  be  compared  to  the
current cost  of  producing  a barrel of oil  to  gauge  the  magnitude  of  the
impact of a waste management scenario.

    National-level  costs  will  be  developed  for  the  period  1987-2000.
Estimates of  the  level  of  growth of industry  activity for 1987-2000 will
be   obtained   from    the   Department   of   Energy/Energy    Information
Administration  (EIA).    The  EIA  mid-term   forecasting  system  generates
projections  of  oil  and  gas  activity  that  are  used in Federal  energy
planning.
                                   1-3-18

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                           REFERENCES  TO CHAPTER 3
    Abkowitz,  et  al.,   1984.   Assessing the Releases  and Costs Associated
with Truck  Transport of Hazardous Waste.   U.  S.  Environmental Protection
Agency, Office of Solid  Waste,  January 1984,  as referenced  in Sobotka &
Company, Inc.

    American Petroleum Institute, no date.   Land Treatment.

    Arthur   D.   Little,  Inc.,   1979.    Cost   of  Compliance,   Proposed
Underground  Injection  Control   Program,   Oil  and   Gas   Wells.    U.   S.
Environmental Protection Agency,  Office of Drinking Water, June 1979.

    Booz-Allen  &  Hamilton,  1984.  Review  of  Activities  of  Firms  in  the
Commercial  Hazardous Waste  Management  Industry:   1983 Update.   Office of
Policy Analysis, U. S.  Environmental  Protection Agency, November 30, 1984.

    Galloway, Mike, 1986.   Presentation at National Conference on Drilling
Muds, Environmental and Ground Water Institute, University of Oklahoma.

    Charles  River  Associates,   Inc.,  1985.   Estimated   Costs   to  the
U. S. Mining   Industry   for   Management  of   Hazardous   Solid   Wastes.
U. S. Environmental Protection Agency, August 1985.

    Davis,   Ken,   and   T.   Lawrence  Heniline,   1986.    Two  Decades  of
Successful Hazardous Waste Disposal Well Operation - A Computation of Case
Histories.   In  Proceedings  of   the  International  Symposium  Subsurface
Injection Practices Council, New  Orleans, Louisiana, March 3-5, 1986.

    Gulf Publishing Co., 1986. World Oil (Monthly magazine).

    Guthrie,  Mark  A.,   George  Patrick,  and  Thomas  N.  Sargent,  1986.
Economic Impacts  of Alternative  Technologies for Treatment and Disposal of
Liguid  Hazardous  Wastes.   In  Proceedings  of  the International  Symposium
Subsurface  Injection of Liguid Wastes,  The Underground Injection Practices
Council, New Orleans,  Louisiana,  March 3-5, 1986.

    Hanson, Paul M., Frederick V.  Jones,  C.  Michael Moffitt,  and  Miles R.
Rhea,  1986.   A  Review of  Mud  and  Cutting Disposal for  Offshore  and
Land-Based Operations.   In Proceedings of National Conference  on Drillling
Muds, University of Oklahoma,  May 29-30, 1986.

    Independent Petroleum Association of America,  1986, Report of the Cost
Study  Committee.   Midyear   Meeting,   Nashville,   Tennessee,   April   30-
May 2,  1986.
                                   1-3-19

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    Industrial Economics,  Inc.,  and  ICF  Incorporated, 1985.    Regulatory
Analysis  of  Proposed  Restrictions  on Land  Disposal of  Hazardous Wastes.
Studies and Methods  Branch and Economic Analysis  Branch, Office  of Solid
Waste, U.  S.  Environmental Protection Agency, December 27, 1985.

    Lloyd,  David,   1985.    Drilling  Waste  Disposal   in   Alberta.    In
Proceedings of a  National  Conference  on  Disposal of  Drilling  Wastes,
University of Oklahoma,   Environmental  and  Ground  Water Institute,  May
30-31, 1985.

    Moody  and  Associates,  Inc.,  1983.    Oil  and Gas  Well  Pollution
Abatement Project.   ME No.  81495. June, 1983.

    Rafferty,  Joe, 1985.   Recommended Practices for the Reduction of Drill
Site  Waste.   In  Proceedings of  the  National  Conferences  on  Disposal  of
Drilling  Wastes,  Environmental and Ground Water  Institute,  University of
Oklahoma,  May 30-31,  1985.

    R.S. Means Company, Inc.  1985.   Means Site Work Cost Data, 1986.

    Sobotka and Company,  Inc.,  1985.   Cost  Analysis  of Variances  to  Land
Disposal  Bans.    Economic  Analysis  Branch,   Office   of   Solid  Waste,
U. S. Environmental Protection Agency, December 16, 1985.

    Technical Resources, Inc.,  1985.  Assessment of  Environmental  Fate and
Effects   of   Discharges   from   Offshore   Oil   and   Gas   Operations.
U. S. Environmental Protection Agency, EPA 440/4-85/002.

    U. S.  Environmental  Protection  Agency.   1980.   Treatability  Manual,
Volume  IV:    Cost  Estimating.    Office  of   Research  and  Development.
EPA-600/8-80-042D.   July, 1980.

    U. S.  Environmental Protection Agency,  1984.   Handbook for Estimating
Sludge  Management  Costs  at  Municipal  Wastewater  Treatment  Facilities.
Contract No.  68-01-662/to SCS Engineering, Long  Beach,  California.   Draft,
September, 1984.

    U. S.  Environmental Protection Agency,  1985.   Liner Location  Risk and
Cost  Analysis  Model.  Draft Report.  Contract No.  68-01-6621.  Office  of
Solid Waste,  January 1985.

    U. S.  Office   of  Technology   Assessment,   1983.    Technologies   and
Management Strategies for Hazardous  Waste Control.  OTA-M-196.   March 1983.
                                   1-3-20

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                                 CHAPTER 4
       IMPACT OF WASTE MANAGEMENT SCENARIOS ON PETROLEUM EXPLORATION,
                         DEVELOPMENT,  AND PRODUCTION


                          INTRODUCTION AND OVERVIEW

    This chapter describes  the  scope and methods for EPA's analysis of the 
impact  of  alternative  waste management  practices  on  petroleum  and  gas
exploration,  development,   and  production,   as  called  for  in  Section
8002(m)(G)  of RCRA.   The methodology for estimating  the  economic  cost  of
alternatives is described in Chapter 3.  The impact of these costs will be
addressed  for  individual projects,  on corporations and  on the  aggregate
regional  and national  levels of  industry  exploration,  development,  and
production.

    The  impact  of  incremental  waste  management  costs  will  be  analyzed
first at the  level  of individual projects.   Because of the large number of
oil  and gas  projects   initiated  each  year,  "model"  or  representative
projects will  be  defined.   As  described in  detail below,  model  projects
will  be  specified  to  capture  regional  differences  in  oil   and  gas
development and to  depict  situations  in which the  impacts of  the waste
management scenarios are greatest.

    Each model oil and  gas development project will be characterized by a
stream of  expenditures  and revenues.   By estimating these expenditures and
revenues and factoring  these estimates into a discounted cash  flow model.
                                    1-4-1

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EPA will simulate  the  financial performance of  model projects.   A second
series of  model-project simulations  will  be run,  incorporating the added
costs  of  the  alternative  waste  management scenarios  for  representative
facilities.   Comparison  of  financial  performance  under  the  different
simulations will show the relative impact of the incremental environmental
control cost on project financial performance.

    The  cost  impact  of  the  waste  management  scenarios  will  also  be
assessed at  the industry  and  corporate  levels.   The  total  cost  of  the
waste  management  alternatives  will  be compared to total annual  industry
investment  and production  expenditures  to  provide a  broad  measure  of
aggregate  industrial-level  impacts.   To analyze impacts at  the corporate
level, the industrial-level cost of the waste management scenarios will be
allocated  to  individual representative corporations.   The  decline  in the
financial ratios of these corporations due  to incremental  waste management
expenditures will be calculated.

    This chapter  describes the methodology for  the project-level  economic
impact assessment,  corporate-level  analysis,  and the use of  those results
in  formulating conclusions regarding  the  impact of  environmental control
costs on industry exploration, development,  and production.
                           MODEL PROJECT ANALYSIS

Identification of Model Projects

    The   impact   of  the  control   requirements  and   costs  on  industry
exploration,  development,  and  production  is  essentially the  sum of  the
impact  on  individual  projects.   An  increase in  waste management  costs
could potentially  result  in the early closure of  existing  projects  or in
                                    1-4-2

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the cancellation of  new  projects.   If a large number  of  projects would be
cancelled  or curtailed  under  a given waste management  scenario, then the
level  of  industry  exploration,  development,  and  production  would  be
reduced.   Because   the  number  of  exploration   and  development  projects
initiated  each year is  so  large  (e.g.,  over 80,000  wells  were  drilled
onshore in  1985),  it is impossible to assess the impact of a scenario on a
case-by-case basis;  it  is  therefore  necessary to depict  "model" projects
to represent the entire population.

    Model  projects  will  be defined  for  this research  based on  several
criteria:
    1.   The  model  projects  must represent  the  entire  population;
         therefore,  each model  case must  represent  a  substantial,
         identifiable part of the population.
    2.   The  model  projects  must capture  the   impact  of the  waste
         management  scenarios;  therefore,  some of  the  model  cases
         must  be  selected to  represent  those  situations where  the
         largest  environmental   control  costs  (required  under  a
         scenario) will be incurred.
    3.   The   model   projects  must  depict   situations  in   which
         environmental    costs    could    affect   overall    project
         profitability;  therefore,   some  of  the  model  cases  will
         depict economically marginal activities.
    Establishing Representative Cases

    Concerning the first  criterion  (i.e.,  representativeness), it  will  be
necessary to depict  model cases that capture the geographical diversity of
the oil and gas industry.   The regions of the country  differ geologically,
resulting  in differences  in  mud  formulations,  drilling procedures,  and
production practices.   These regional differences,  in  turn,  bring  about
differences in the types  of wastes  generated,  the waste disposal  practices
                                   1-4-3

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employed,  and the overall  cost and profitability  of  the projects.  Model
projects must be defined to capture these regional differences.

    As  described  in  a  previous  report  (U.S.  Environmental  Protection
Agency,  1986),  the  nation can be  divided  into  11  oil and  gas Regions
(Figure 1-1).  Regions 1 and 3 do not have a significant  amount  of oil and
gas  production.    Thus,  the  model  cases  will  focus on  the  other  nine
regions,  with  cases  defined  to   capture   regional   c..aracteristics  of
exploration, development, production, and waste generation and disposal.

    Given  the  significant  regional differences in  the  basic  parameters of
oil and gas projects,  the nine  regions  will  be used as a primary variable
to distinguish model  cases.   Since the major  industry  data  series present
drilling and production information disaggregated to the  State level (API,
1986;  Independent  Petroleum  Association  of  America,  1986;  DOE,  1986),
these  data  can  be  used  to  specify  the  proportion  of  drilling  and
production that occurs in  each  region.   These proportions can, in turn, be
used to extrapolate the results  of modeling within  regions to  the national
level.

    There  will   be   significant  differences,   however,  within  regions
concerning many  of  the  parameters  described  above.   Further,  there  are
differences  in  the  current regulatory  treatment  of  these wastes,  which
lead  to  different baseline disposal  practices and costs for the  States
within a  region.   Model  projects  defined using average regional values for
the parameters will not capture  these differences.  It will,  therefore,  be
necessary  to  specify additional  model cases  that depict  situations  in
which the impact of the waste  management scenarios will be greatest.
                                   1-4-4

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    Environmental Control Costs

    Subregional   models   will  be   defined  to   represent   cases   where
environmental  control  costs will  be highest.  Projects  depicting average
regional  characteristics  may  not  experience  significant  environmental
control  costs  under  a  given  waste management  scenario.   However,  some
projects  within  the  regions  will  experience  significant  costs.   For
example,  if  a scenario's  environmental  protection  requirements lead  to
strict  controls  on oil-based  muds,  then model  projects  within  Regions  4
and 7  must  be defined to depict  the use  of such muds, even though the use
of oil-based  muds is  not  practiced by  the  majority of  projects  in  the
region.   Further,  projects  in States with  lenient  current  regulations may
experience  higher  incremental costs,  and  such  projects  must  also  be
modeled.   Essentially,  the  requirements  of  a  given  waste  management
scenario  are  compared to baseline  practices  in  each  region.   State  and
regional  project  profiles  will provide  the  data necessary to extrapolate
the results of the subregional models to the National level.
    Marginal Economics Cases
                                                             #
    Another critical  factor determining  the  impact of a  waste management
scenario  is  the baseline  economic  performance of  the model   case.  Those
cases  showing  marginal  economic  performance  in  the baseline  condition
could be most affected by environmental control costs.  Thus,  as  discussed
further below,  it  will  be  necessary to specify marginal  economic projects
within the regions.

    In  summary,  regional values  will  be  used as  a  primary   variable  to
identify  model  cases.   However,  "average"  regional  cases  may  have  only
limited interest to the analysis of a waste management scenario.   It  will.
                                    1-4-5

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therefore, be necessary  to specify subregional models  to depict  cases of

high  impact  of  environmental control  requirements and  marginal  baseline
economic performance.
Economic Parameters of Model Projects


    Regional  information,   such as  that  presented  above,   will  allow  a

project to be specified in technical terms.  For  example,  a  representative

case in Region  2  would incorporate such features  as  air drilling, shallow

depth,  discharge of  liquid waste,  and  a high  gas-to-oil  ratio.  It  will

also be  necessary to  define  the  model  cases  in  economic terms.   The

economic  specification of model  projects  will   allow  a  simulation  of ,

project   financial   performance  both  with   and  without   the   cost  of

environmental  controls inherent  in  a  waste   management   scenario.    The

following variables will be used to define  model cases in economic  terms:


      Drilling cost.  Drilling costs will  be  derived from the Joint
       Association  Survey  on  Drilling Costs  (American   Petroleum
       Institute  et  al.,  1985).   This   source  presents   average
       drilling costs  by  depth category and by  State.   It  can  be
       used to  derive  average drilling  costs for all  specific  model
       wells defined (by region or subregion)  in the analysis.

       A  new  Joint   Association   Survey   covering  1985   will   be
       published in December  1986.   Model  inputs will  be  defined  in
       1986 dollars.  To bring  the  survey  cost estimates  forward  to
       1986,  extrapolations  will  be  developed  using  more  recent
       published drilling cost  indices.  Such  indices  are published
       by  the  Independent  Petroleum Association  of  America and  by
       the  U.S.   Department   of   Energy   (Independent  Petroleum
       Association  of  America,  1986,   and U.S.  Energy Information
       Administration,   1985b).   At  present,  the  published   indices
       cover 1985,  but the DOE index for  1986 will be  published  in
       January 1987.   This index will  then  be  used  to adjust the
       region  and  depth-specific   costs   taken  from   the   Joint
       Association Survey.
                                   1-4-6

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Probability of  a  successful  wildcat well.  The probability of
a  successful  wildcat well  can  be  calculated  from  annual
statistics on  exploratory drilling as  published  in World Oil
magazine.  The  data present the  total number  of exploratory
wells  and the  number of  oil/ gas,  dry  and  suspended  (the
drilling  project  was  interrupted  before  its  outcome  was
determined) wells  by State  each  year.   Thus  the probability
of a  successful exploratory  well can  be calculated  for  each
State, and subsequently  for  each region or subregion depicted
in the model cases.

Data  are  currently   available   (as  of  October   1986)   on
exploratory wells  drilled through  1985.   The  1986  data  will
be published  in the  February  1987 World  Oil  magazine.   The
success  of  exploratory  well  drilling  over  the past  three
years will be averaged for input to the model.

Number of development wells per successful wildcat  well.   Oil
companies who drill wildcat  wells attempt to have surrounding
acreage   under   their   control.    Should   the  wildcat   be
successful,  the  company  can  then derive  the  benefits  of
additional (i.e.,  development) wells.   Thus  the  economics  of
a project  are   dependent  upon  the  success of a  wildcat  well
and the amount of development that results.

The number of development wells completed per year  is derived
by  subtracting  the  number  of  successful  exploratory  wells
from  the  number of wells completed annually.  The  latter  are
presented  in  industry sources (American  Petroleum  Institute,
1986).  The ratio  of  development  to successful wildcat  wells
by region  will  be  calculated  and used as a parameter  in  the
model projects.

Operating  costs.   Operating  cost  data  is  compiled  by  the
Energy Information Administration of the  Department of Energy
(Energy Information Administration, 1985a).   Cost  breakdowns
are  provided for  categories  of  lease  equipment and  direct
operating expenses  by region  and  by  depth  categories.   The
regions and  depth categories are,  however, different  in  this
source from the regions that  have been  defined  herein.  Thus,
interpolation of  the  statistics  will  be necessary  to match
the operating cost data to the  format needed for  the  economic
modeling.

Operating cost  data through  1985  will  be  available  for use in
the model.  Costs for 1986 will be  extrapolated based  on cost
                            1-4-7

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   trends from historical data and from trends  in other oilfield
   cost indices.

  Type of  production.   The type of production  (i.e.,  oil,  gas,
   or both)  in each  model  is  a  statistic calculated  directly
   from  State  oil  and  gas  production  figures.   The  type  of
   production combined with  current  wellhead prices for oil  and
   gas  determine  the  project  revenues.   These  statistics  are
   available in major industry sources such as World Oil  and the
   API  Basic  Petroleum  Data  Book  (Gulf  Publishing  Co.   and
   American Petroleum Institute,  1986).   The State data will  be
   combined  as  necessary  to calculate  the regional values  for
   the type of production.

  Peak production level.  Data on peak production are  necessary
   for the  effort to  describe the amount of production  and  thus
   the revenue stream from successful wells.  It  will be assumed
  晅hat peak production in  all successful  wells occurs  in  the
   first  year.   Thereafter,  production   is  assumed  to  decline
   over time until the well is shut in.

   Data on  initial  production (IP) are available  from  State  oil
   and  gas  commissions  and  from  the   Petroleum  Information
   Corporation  in  Denver,  Colorado.    The  initial  production
   statistics will be compiled  and averaged for each region  in
   the  study.    It  is  anticipated  that  initial   production
   averages will be calculated  covering  the past  three years  of
   production statistics.

  Production decline  rate.   The decline rate for production  is
   needed to complete the profile of production  and  therefore  to
   calculate  the  average revenue  stream  from successful  wells.
   Hydrocarbon production typically declines over the  life of  a
   well, although  decline rates are quite  variable.

   Two possible approaches  to development of this  statistic are
   under  consideration.   First,  a representative  decline  rate
   will be   developed  based  on  expert   judgment obtained  from
   industry  sources  and from Department  of  Interior,  Mineral
   Management Services,  publications.

   A  second  approach  remains  under consideration.    In  this
   approach,  actual  decline  rates   would  be   calculated  from
   individual  well  records.   A random  sample   of well  records
   would be required for this task.   The  size  of the necessary
   sample  and other details of  the  calculation  procedure  have
   not yet been estimated.
                               1-4-8

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      Wellhead  selling  price.   The  selling  price  for  recovered
       hydrocarbons  (in  combination with  the  production  profile)
       determines  the  revenue  stream  for  oil  and  gas  projects.
       Wellhead prices  as  of December 31, 1986, will  be utilized in
       the  modeling work.   Wellhead prices  are  reported  weekly in
       API publications.

      Tax treatment.   A  set of tax assumptions must  be included in
       the  model  to allow  calculation  of  the  after-tax  rate  of
       return.  The assumptions will approximate  the national (i.e.,
       all  regions)  tax treatment  of  oil and gas.   Changes  in the
       tax code  included  in  the tax  overhaul legislation  passed by
       Congress   in  September   of  1986   will  be   incorporated.
       Variations  in State  tax  laws  will be  incorporated into the
       subregional models.

      Cost   of   waste  disposal.   Each   model   case   would  be
       characterized by a distinct waste  disposal  cost.   Baseline
       waste  disposal   costs  for the industry will  be  developed as
       described in  Chapter  3.   This baseline cost  information  will
       be adapted to the model cases.
    Marginal Economic Cases


    The preceding  discussion has addressed  methods for  deriving economic

parameters that define average or representative oil and  gas  projects.   As

mentioned previously, it will  also  be necessary to develop model cases of

the marginally  profitable  projects  in the  industry.   Such  projects  are

most vulnerable  to increases  in waste management  costs,  and cancellation
of such projects will impact industry production levels.


    Projects  may  be  marginal   for  a  variety  of  reasons,   including

(1) location  in   areas  that  are   characterized  by   small   oil  or  gas
reservoirs  so   that   production  levels  are   below  industry   average,

(2) developments with high operating costs,  such as where large quantities

of  produced water are  generated and require  disposal  (e.g.,  stripper

wells,   waterflooding  projects),   and  (3) developments  by small  companies
                                   1-4-9

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that have  higher  hurdle rates (in other words,  a higher cost of capital).
Such firms may  pay higher rates for debt  financing than  larger companies
because of the greater risk to lenders.

    Based  on  these and  other factors, models  of marginal  economic cases
will be defined  for the analysis.   The  models will  reflect intraregional
variation  in  the  economic  variables  described  above.   For  example,  some
marginal cases will be  based  on patterns for  initial production;  that is,
some cases  will be defined  for those areas characterized  by  low initial
production (and,  therefore, modest  revenue streams during the  life  of the
project).
Model Project Simulations

    The  economic  parameters  of the  model  projects  will  be input  to  a
discounted  cash  flow model  designed  by  EPA  to  simulate  the  financial
performance  of  oil  and  gas  projects.   The economic  model  simulates  the
performance  and measures  the profitability of  model  projects.   For  each
model project,  exogenous  economic  data  (e.g.,  drilling  cost,  number  of
development  wells,  production rate,  wellhead  selling price) ^are  input  to
the economic simulation  model.   The model calculates the  annual  after-tax
cash  flow  for  each  year  of  project   operation,  as  well  as  cumulative
measures of  a  project's  performance  such as net  present  value  (NPV)  and
internal rate of return (IRR).

    The  EPA  economic  model  software   provides  integrative  calculation
procedures and algorithms that duplicate  (1) the oil  industry's  accounting
procedures,  (2)  standard  rate  of  return  calculation methods,  and  (3)
Federal  taxation  rules.   The tax  code   revisions  enacted  by Congress  in
September 1986 are now being incorporated into the  model.
                                   1-4-10

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    Each model  project will  be  simulated  in  a  base case  and under  the
requirements  of  each waste management scenario.  The base  case simulation
will, simply, operate  the model  incorporating baseline  economic values  to
calculate  a  model project's  economic performance.    The alternative cases
will incorporate  the  same economic information and  the  additional  cost  of
the  waste  management scenario to  estimate a  new (lower) NPV  and  IRR for
each model.  Costs for the waste  management scenarios  will  be  developed  as
described  in  Section 6.4.   The  national-level cost analysis  in Chapter 3
will employ the same model cases  as the  impact  assessment described here,
so the  cost  information developed  in that  chapter can be adapted directly
for use in the model project simulations.

    The baseline economic results will be compared to the economic  results
under  a  waste  management  scenario  as  a first   measure  of  regulatory
impacts.  The issues addressed in this comparison include the following:

     1.  Absolute  decline.  The absolute  decline in  internal rate  of
        return  under a  given scenario  for each model  project will
        give  an  immediate  indication of  economic  impact.   If  the
        decline  is  less  than one tenth of a percentage point for all
        models, for example, impacts will not be severe.
     2.  Hurdle rate.  A  second  indication  of  impact  is  whether  the
        incremental  waste management  costs push any  of the  model
        projects  from a  level   above  the  industry   hurdle  rate  of
        return  to a level  below that rate.   If the  decline  in IRR
        makes  some model  projects  unprofitable,  impacts  could  be
        substantial.
                    CORPORATE AND INDUSTRY-LEVEL IMPACTS

    Another way  to measure the impact of regulatory  costs  of exploration,
development,  and production is  to  compare annual  compliance expenditures
to   annual   corporate   and   industry   investment    expenditures.    These
                                   1-4-11

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comparisons can give a good initial indication  of  whether regulatory costs
are likely to have a substantial impact on industry capital formation.
Industry-wide Assessment

    Total  aggregate  annual  costs  will  be  estimated   for  each  waste
management  scenario  as   described  in  in  Chapter  3.    Total  industry
investment expenditures are  compiled and published annually  by  the  Energy
Economics Division of the  Chase Manhattan Bank.   This source tabulates all
industry  exploration  and  development  expenditures,  both   onshore -and
offshore.   By dividing  the total  annual costs  under a  given  regulatory
scenario  by  total  annual  industry   expenditures   for   exploration  and ,
development, one can obtain a  first measure of the magnitude of effects on
industry investment spending.

    EPA  will   compare  the  cost  of  each  waste  management  scenario  to
industry-wide  exploration  and  development  expenditures  in  four  separate
ratios:
    1.  Annual   Incremental   Expenditures   Under   a   Given   Waste
        Management  Scenario  (as  described  in Section  6.4)/Total
        Annual  Industry  Exploration  and  Development  Expenditures
        (Chase Manhattan Bank).
    2.  Annual Incremental  Expenditures  Under a Given  Waste  Manage-
        ment Scenario/Total Annual  Industry Onshore Exploration  and
        Development Expenditures.
    3.  Annual After-Tax Expenditures Under  a  Given Waste Management
        Scenario/Total Annual  Industry  Exploration and  Development
        Expenditures.
    4.  Annual After-Tax Expenditures Under  a  Given Waste Management
        Scenario/Total  Annual   Industry  Onshore   Exploration   and
        Development Expenditures.
                                   1-4-12

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    Each of  these ratios  provides  a slightly  different comparison.   The
use  of  onshore   expenditures  as opposed to  total  industry  expenditures
allows waste  management costs  to be compared  to the  subset  of  industry
expenditures  that the compliance expenditures  would be part  of.   The use
of  gross compliance  expenditures  in  the  numerator  (Ratios  #1  and  #2}
compares the  social  cost  of compliance to total  industry  exploration and
development expenditures.  However,  industry  will deduct compliance  costs
as  business  expenditures and  will,  therefore,  not  pay the entire  social
compliance cost.   The  use  of after-tax compliance  costs in the  numerator
(Ratios  #3  and  #4)   compares  the  cash  effect   of compliance  to  total
industry expenditures.  These latter ratios, then, provide  a measure,  from
the  industry's  point  of view,  of  the percentage  of funds diverted  from
other uses to pay for regulatory controls.
Financial Assessment for Representative Companies

    In addition  to  the above industry-wide ratios, a  second  set of ratios
can be calculated to show  the  impact of compliance costs  of  the financial
health  of  individual  corporations.   Using  financial  data available  from
corporate  annual reports,  EPA  will  construct  a  representative  balance
sheet  for  a  typical  major,  a  typical  large  independent,  and  a  typical
small  independent  oil company.   These  balance  sheets   can  be  used  to
calculate statistics and ratios which measure a company's  financial  health.

    EPA  will  use  four financial  parameters  in the  analysis:   level  of
working  capital,  current   ratio  (i.e.,  current  assets  divided  by  current
liabilities),  long-term debt-to-equity  ratio, and debt-to-capital  ratio.
These parameters  will  be  calculated both before and after the incremental
cost  of  a  waste management  scenario.  Parameter  calculations  under  the
waste  management   scenarios   will   be  calculated  under  two  sets   of
                                   1-4-13

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assumptions.  The  first assumption  is  that  incremental waste  management
costs  are  funded  out  of working  capital and,  therefore,  the level  of
working  capital and the  current  ratio  will  be  impacted.   The  second
assumption  is  that  incremental waste  management  costs  are funded  out  of
long-term debt, and  therefore,  the  long-term debt-to-equity ratio and  the
debt-to-capital  ratio  will  be  affected.    A  comparison  of  pre-  and
post-scenario ratios will provide an indication of the financial  effect  of
the scenarios on a corporation-specific basis.

    In the  above analysis,  the  fraction of total  industry compliance costs
attributed to the model  major and the model independent  oil  companies will
be estimated  by comparing the exploration and  development  expenditures  of
the model corporation to  those  of the industry as a  whole.   In  a  related
study,  EPA  estimated that  a  typical  major  accounts for  5.4  percent  of
industry  exploration   and   development   expenditures   while   a   typical
independent accounts for  0.3  percent of all  such expenditures.   Thus,  for
the ratio analysis described above,  it  will be assumed that  5.4  percent  of
total aggregate compliance costs  (as calculated in Section  6.4)  are borne
by a typical major and  that  0.3 percent of aggregate compliance  costs  are
borne  by a  typical  independent  oil company.   Small companies  in  areas
experiencing the greatest impact  of the  regulatory  scenarios, may  absorb
more  than  a proportional share  of   the  national  costs.   For  these  firms,
modified assumptions regarding the actual (larger) share of  national costs
to be borne will be developed for the ratio analysis.
         IMPACT ON  INDUSTRY EXPLORATION, DEVELOPMENT, AND PRODUCTION

    The analysis will provide  several indications  of  the economic  impact
of the costs of the alternative waste management  scenarios.   In particular:
                                   1-4-14

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     1.  The  financial  impact of  the  environmental control costs will
        be  simulated for  representative  projects, including average
        projects, projects expected to  show  the largest total costs,
        and   for   projects   showing   marginal   baseline  economic
        performance.
     2.  Incremental  costs  under  the  waste management  scenario  will
        be   compared  to  total  industry  onshore  exploration  and
        development  costs.
     3.  Incremental  costs  under the  waste management  scenarios  will
        be  compared to  total  industry exploration  and development
        costs.
     4.  The  financial  ratios  of  typical  small   independent,  large
        independent,  and  major  oil  companies  will  be  estimated
        separately,  both before  and  after  the  costs  of the  waste
       . management scenarios are estimated.

     EPA will  evaluate  these  results  to determine  whether  any  of the waste
management   scenarios   will   have   a   substantial   impact   on   industry
exploration,  development,  and  production.    Three  key  issues  will  be
addressed.   First,  a determination  will  be made as  to  whether any  (and
what  percentage  of) projects  would  likely be  cancelled under  each waste
management scenario.  Second,  a determination will be  made  as  to  whether
any  of  the waste  management  scenarios will affect the  industry's  ability
to  raise  capital.   Third, the  results  of  the   ratio  analysis  will  be
                                                             
reviewed  to  determine   whether  the  ratios  of  any  affected  firms  will
deteriorate  to  the point  where  the  probability  of  financial   failure
increase significantly.

    Because oil  is  sold  in a world market with abundant  foreign supply at
the  world  price, any  decrease in domestic  exploration,  development,  and
production will  lead to an  increase in  imports.   These balance of trade
effects will  be  estimated.   It is not expected that  the waste  management
scenarios will result  in production  declines substantial enough to  change
price  in  the  world  market,   so fuel  substitution  and  the  rate   of
development for alternative energy technologies  will not  be affected.
                                   1-4-15

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                            CHAPTER 4 REFERENCES
American  Petroleum  Institute, 1986.   Basic Petroleum  Data  Book,  October
1986.

American  Petroleum  Institute  et al.,  1985.   Joint Association  Survey on
Drilling Costs, 1984; December 1985.

Gulf  Publishing  Company,  no  date.   World  Oil.   Houston,   Texas.   Monthly
magazine.

Independent  Petroleum Association  of America,  1986.   Report of  the Cost
Study  Committee.    Mid-year   Meeting,  Nashville,  Tennessee,  April  30  -
May 2, 1986.

Interstate Oil Compact Commission, 1985.  History of Production Statistics,
Production and Reserves, 1969-1984, November 1985.

U.S.  Energy Information  Administration,  1985a.   Costs  and Indexes  for 
Domestic  Oil  and  Gas  Field  Equipment  and  Production  Operating,  1984.
DOE/EIA-0185 (84), May 1985.

U.S.  Energy  Information Administration,  1985b.   Indexes  and  Estimates  of
Domestic  Well  Drilling  Costs,   1984  and  1985.   DOE/EIA-0347  (84-95),
November 1985.

U.S.  Environmental  Protection  Agency,  1986.    Oil and  Gas  Exploration,
Development  and  Production;  Sampling  Plan  -  Draft.   Office  of  Water
Regulations and Standards, May 1986.
                                   1-4-16

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      PartH
Geothermal Energy

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                                 CHAPTER  1
                            INDUSTRY DESCRIPTION
    The purpose  of this  section is to  provide background  information on
geothermal energy  and  a  profile of the  geothermal energy  industry.   This
report  presents  a  brief description of  geothermal energy  systems;  where
geothermal  energy  systems  are  found,  some  common  techniques  used  by
industry  for  bringing the  resources  into production, and  a discussion of
how the resources are used.
                                 BACKGROUND

    The  crust  and the  atmosphere  of  the  earth account  for  less  than
one-half of a percent of  its  total mass.  The remaining  99.5  percent lies
concealed  beneath  the  crust,  and  our  knowledge of  the  nature of  the
material beneath the crust  is  largely a result of the  study of earthquake
waves,  and lavas, and measurements  of the flow of heat  from  the interior
towards the surface.  Nevertheless, this indirect  knowledge  has allowed us
to  construct  a fairly clear  and  consistent model of the  structure  of the
earth.   The  currently  accepted  structure  consists  of  four  concentric
spheres;  from  the outermost  to  the  innermost  they are  the  crust,  the
mantle, the liquid core,  and the innermost core,  which is believed  to be
                                   II-l-l

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solid.   This  structure  is  presented  in  Figure II-l.   Temperatures  and
densities rise rapidly  as  the center of the earth is approached.  The term
"geothermal  energy"  is defined  by  some   to  include  all  of  the  heat
contained  in these  four  concentric  spheres  (approximately 260  billion
cubic miles that constitute the entire volume of the  earth)  (Chilinger,  et
al.,  1982).   The potentially  useful  part  of this  enormous  energy supply,
however, is represented by that  small  fraction of  the earth's  volume  in
which crustal rocks,  sediments,  volcanic deposits,  water,  steam, and other
gases  at  usefully  high  temperatures  are  accessible  from  the  earth's
surface  and  from which it may somehow be  possible to  extract  useful heat
economically.    Even  this  small  portion  of  the  total  is  an  enormous
reservoir of  thermal  energy.   The  classification,  location,  and recovery
of  this  portion  of  the  available thermal energy are  the subjects of this
section.
           THE NATURE AND OCCURRENCE OF GEOTHERMAL ENERGY SYSTEMS

    Geologists and engineers classify geothermal energy  systems  into three
major categories:

      Hot igneous systems;
      Conduction-dominated systems; and
      Hydrothermal systems.

    The first two  categories  may contain the largest amount of useful heat
energy,  but  are  not  economically  and  technically  feasible  to  exploit.
Advancements in  current  technology  would be required in order to use these
potential  heat   sources  commercially.    The  third  category,  hydrothermal
energy systems,  is commercially viable and has received the most attention
because  extraction technology  exists  for the  economic  recovery of  heat
from these resources.
                                   II-1-2

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                                                     Continental crust
                                                     Average thickness about 35 km

                                                     Average density 2.7 g/cm3
             Densities
             (g/cm3)
                  Oceanic crust
                  Average thickness:
                   about 5 km water
                   about 5 km rock
                  Average density 3.0 g/cm3
                                          Total, with crust about 6370 km
                  Figure  II-l.   Concentric Layers  of the Earth.

Source:  Armstead,  Christopher H.,  "Geothermal Energy:   Its  past,  present and
         future  contributions to  the  energy needs of man," 2nd Ed., London,
         1983, E and FN Span.
                                    II-1-3

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Hot Igneous Systems

    These systems consist  of  magma chambers near the  earth's  surface that
are  created by  the buoyant  rise  of  molten  rock  generated  deep  in the
earth's crust.  This type  of  geothermal  energy  system is  made up  of two
major groups:   Hot, Dry Rock,  where the  magma  is no  longer  molten (less
than  650癈),  and Volcanic  Systems, where  the magma  is  still molten  or
partly  molten  (greater  than  650癈).    Figure  II-2  presents   a  schematic
diagram of a representative hot igneous system.

    Because of  the  great  depth (3  km)  and high temperatures   (650-1200癈)
associated with volcanic systems,  the  heat is not  recoverable with current
technology.  The hot, dry rock - hot igneous systems,  however,  are located
on  the  margins of molten  magma  chambers and  might  in  the future  be
favorable  candidates  for recovering heat  energy.   Some  speculate  that  a
system   of   hydraulic   fractures   can   be  created  between   special,
directionally-drilled wells to provide  circulation  loops  in  rocks  having
low to  very low permeability.   An  experimental program at  Los Alamos, Mew
Mexico, is  underway to  develop this technology.   Success  in these efforts
will  make  it  possible  to consider  exploitation of hot dry rock geothermal
energy.  In general, however,  the economic extraction of  energy  from this
resource has yet to be demonstrated (Chilinger et al., 1982).
Conduction-Dominated Systems

    The very high heat from  the molten center of the  earth is transferred
very  slowly  from  deep  within  the  earth  to  the  surface  by  thermal
conduction.  Because of  the  size and relatively low heat  flux at  or  near
the  surface,  however,   one  would  have  to  drill  5  to  10  km to  reach
subsurface temperatures of only 100癈.  Therefore, the development  of  this
                                   II-1-4

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             NATURAL FISSURE

                          WELL
                                                      HOT DRY ROCK
                                                 HEAT EXTRACTION SYSTEM
            PERMEABLE'./ SEDIMENTS
                                                         RED VOUCANIC ROCK  "
                                                           te* UNITS   -i-:
                  HYDROTHERMAL SYSTEM
      Figure II-2.   Schematic Diagram of a Hot,  Dry Rock Geothermal System.

Source:  Chilinger, G.V.,  L.M.  Edward,  W.H.  Fertl, H.H. Ricke  III   Editors,
         "The Handbook  of  Geothermal Energy."  Houston, Texas,  1982,  Gulf
         Publishing Company.
                                    II-1-5

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type of  system  is not, at this time,  economical.   Geopressured reservoirs
are  also  within  this  category,  however.   Geopressured  reservoirs  are
usually  found  in  deep  sedimentary basins where a  lower  level  of sediment
compaction  has  taken  place over  geologic  time  and where  an  effective
caprock   exists.    These  conditions,  supplemented   by   water  released,
possibly by  clay mineral alteration,  foster trapped-water pore  pressures
up  to  several   thousand  pounds  per  square  inch above  the  hydrostatic
pressures  that  would  normally exist.   For  example,  temperatures  up  to
237癈 with wellhead pressures  in  excess  of 11,000 psi have  been recorded
in  some   geopressured   zones   in   the  States  of   Texas  and  Louisiana
(Chilinger et  al.,  1986).   Since  there  is  no deep  circulation of  the
water, however,  it only reaches moderately  elevated temperatures.   Because
these  reservoirs  are   usually  associated  with  petroleum,   the  water  is
generally  saturated  with  methane  and  other  hydrocarbon  gases.    They
therefore  could  represent an important supplement to the  supply of natural
gas.  There  is  still no direct evidence  that heat,  natural  gas, or  both
can be  extracted economically from geopressured hot  water  reservoirs,  but
large-scale  field  experiments  are  now  underway   to   investigate   this
possibility.
Hydrothermal Systems

    Hydrothermal systems  are the  systems  of  economic  importance.   These
systems consist  of high  temperature  water and/or steam trapped  in porous
and permeable reservoir  rocks.   Because of  the  convective circulation  of
water and  steam through  faults  and fractures, the heat is transported  to
near the earth's surface.  Gravity is the driving force of this  movement,
owing to the  density  difference  between cooler,  downward moving  water and
the  hot,   upward  moving  water.   The  heat  that  is   available  in the
                                   II-1-6

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geothermal reservoir  rock  is  produced by bringing  hot water  and/or  steam
to the surface.   Figure  II-3  presents a schematic  diagram of a simplified
hydrothermal system.

    Two  classes  of   hydrothermal   reservoirs  exist.    Reservoirs   that
liberate    mostly    steam    are    referred    to    as    vapor-dominated.
Liquid-dominated  reservoirs  are  reservoirs  where  the   water  is  in  the
liquid  phase;  they  are much  more  abundant  and  are   usually found  in
permeable  sedimentary rock.   The  latter  reservoirs are also found  in
competent  rock  systems, such  as  volcanic formations,  if  open  channels
along faults  or  fractures  exist.   A brief discussion of both  systems  is
presented below.
Vapor-Dominated Reservoirs

    If the caprock  in  a  hydrothermal reservoir is not able  to sustain the
pressure  level  to prevent boiling, then pockets  of  steam will form.  When
the  pressure  is  relieved  (for  example,  by  drilling   a  well  into  the
pocket),  most  of the dissolved minerals are  left behind in the formation,
and relatively  pure  steam is recovered.  Except  for  a variable content of
noncondensible  gases (which could  be methane, carbon dioxide, radon, and
hydrogen  sulfide) the evolved  steam can be  an  economical  energy source.
Frequently,  it  is used to drive turbines and generate electricity.

    The   existence  of  a  large,  bounded  volume  of  rock  within  which
temperatures  are  high  enough  and  pressures  are  low   enough to  permit
boiling  within the cavity is rare.   Therefore, vapor-dominated systems or
natural  steam reservoirs  are  far less  common than  hot  water reservoirs.
Nevertheless,  the  technology  for  utilizing  energy from  vapor-dominated
systems  is  well developed, and one  of  the  largest geothermal  power plant
developments  in the world (at  The Geysers in California)  uses steam from
such a system  (Chilinger et al., 1982).
                                   II-1-7

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                                                           PRECIPITATION
                                                                   RECHARGE
                                                                           *
            CONVECTION

               .CELLS
                CRYSTALLINE \ ROCKJJH&':
                                                     LIQUIDS, GASES & VAPORS
                              CONDUCTIVE HEAT FLOW

                                    '/////////
                                    HOT INTRUSION
          Figure II-3.  Diagram  of a Hydrothermal Geothermal  Reservoir.




Source:  Chilinger,  G.V.,  L.M.  Edward, W.H. Fertl,  H.H.  Ricke III, Editors,


          The Handbook of  Geothermal Energy."  Houston,  Texas, 1982, Gulf

         Publishing  Company.
                                    II-1-8

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    Power  generation  from  these  resources   produces   relatively  small
quantities of  solid wastes.   This  is primarily  due to the  nature of the
vapor  transport  mechanism  that carries  the  volatile  components  to  the
surface.  Some secondary  waste components,  however, are generated from use
of the  vapor or  off-gas cleanup systems employed  in the  overall  process.
These  solid  wastes could  include  significant  levels of  hydrogen sulfide,
boric acid, arsenic, and mercury (USEPA,  1978).
Liquid-Dominated Reservoirs

    In  these  reservoirs water slowly circulates  through permeable crustal
rocks,  encounters  rock  at high temperatures, and,  becoming less  dense  as
it  is  heated,   rises  buoyantly  toward  the surface.    If  some  geologic
barrier prevents it from actually  reaching the  surface,  an  underground
reservoir  may form, within which the  water will  circulate  convectively.
This  slow circulation  of  the  water  allows it  to  continuously  extract
enough  heat  from  the  lower part  of the  reservoir  to compensate  for the
heat that  escapes  upward through the formation.  Thus,  an  equilibrium may
eventually  be   reached  in  which  the  water  temperature  throughout  the
reservoir  is  approximately uniform  (this temperature  may  range  anywhere
from slightly above ambient temperature to 350癈 or higher).

    Hydrostatic  pressure on the  water  is usually  high  enough  to keep  it
from boiling  even  when  the water is greatly superheated.  Because  of its
high  temperature  and   its  residence  time  in  the   reservoir,  the  water
becomes saline and can  be saturated  with the minerals with which  it comes
in contact.   Since the  solubilities  of a  number  of  minerals  increase with
temperature,  the  hotter  geothermal  waters   generally contain   greater
contents  of  dissolved   solids  than water  at  ambient  temperature.   This
condition  is, however,  strongly  site-dependent, because  the  mineralogical
composition of the rock of a geothermal  reservoir  varies widely from site
                                   II-1-9

-------
to  site.   As a  rule, the  concentration of metals  and other constituents
also  increases  as the  concentration of  total  dissolved  solids  increases
(USEPA, 1978).

    Geothermal  liquids  range rather widely  in  hydrogen ion concentration,
with  pH values  generally between  2.0  and 8.5  (USEPA,  1978).   It  appears
that  most liquids  are  above  a  pH of  7.0.   Liquids  of  higher salinity
generally  have  the  lowest  pH  and  can be  highly  corrosive  to  man-made
materials.

    Noncondensible gases,  those  that   do  not  condense at  normal  ambient
operating  temperatures,  are  environmentally  important  constituents  of
geothermal liquids.   They  may  be free gases, dissolved or entrained in the
liquid phase.   Hydrogen sulfide  traditionally  has  been  the component  of
greatest  concern.   Noncondensible  gases  usually  comprise between  about
0.3 percent and 5 percent of flashed steam from geothermal  liquids  (USEPA,
1978).

    Radioactive elements are also generally  found in geothermal liquids in
low concentrations.   These  include  uranium  and thorium  isotopes,  radium,
and  radon.   Radon,  a radioactive gas  and  one  of  the  products  of  radium
decay, is the most significant  generally recognized  radioactive  component
in  geothermal  liquids.   EPA data covering  136 geothermal  sites showed  a
range of 13 to 14,000 pCi/1 {picocuries per liter), with a  median of  about
510 pCi/1 (USEPA,  1978).

    Chemicals,  such  as  acids,   bases,   and   various   flocculants   and
coagulants, may be added  to geothermal  liquids  to  minimize  scaling  and
corrosion or to remove  certain  constituents. Although  these chemicals may
not in  themselves be  of great  consequence as pollutants,  consideration
must  be   given  to  interactions  that   might alter  the geothermal  liquid
                                   II-1-10

-------
composition.  This  is particularly  true  of any metal  compounds  which may
be added during  this process.   Most such chemicals  will be  acids  and/or
bases used for pH adjustment.

The Geographic Distribution of Geothermal Energy Systems

    The  locations  of hydrothermal  and  geopressured  resource areas  are
shown in Figure  II-4.   Identified  hydrothermal systems  with  temperatures
greater than  or  equal to 90癈 are  located primarily  in the western United
States, while low temperature geothermal  waters are  found in  the  central
and eastern United States.
                     EXPLORATION OF GEOTHERMAL RESOURCES

Preliminary Exploration

    The  overall  objective  of  any geothermal  exploration  program  is  to
locate  a geothermal resource  system from which  energy  can  be  profitably
extracted.  Rapid  low-cost  reconnaissance techniques  are  employed  in  the
early  stages  of exploration,  when gross  areas  are  to be  screened  for
commercial  potential.    For  example,   leakages  of  liquids   through  the
impermeable  capping often  occur   in  natural  geothermal  systems.   These
leaks  and/or  seeps may  produce such features  as fumaroles,  hot  springs,
warm springs,  geysers, mud  volcanoes,  or boiling  ground, and are  the most
direct and obvious indicators of the presence of  a geothermal reservoir or
system.   These  seeps  can  also provide  quantitative information on  the
nature of the reservoir and the liquids contained within  it.
                                   II-l-ll

-------
\
      >--._
    u.	/  \
                        Vl

              X'^     ''
 LEGEND          V	j^i梤-	^J

 Identified  Hydrothermal         \
 Systems with reservoir
 temperature greater  than  90C       \

 Known or Inferred  Low-Temperature
 Hydrothermal Systems
 Geopressured basins
                       Figure II-4   The Geographic Distribution of Geothermal Energy Systems

-------
Geothermal Well Drilling

    Exploratory  drilling  is  undertaken  once  an area  is defined.   This
allows the  exploration area to be narrowed  to  confirm the existence  of a
production field.

    The  drilling of geothermal  wells is  quite similar  to the  drilling of
oil and  gas  wells.   The major differences between  geothermal and  oil and
gas wells  have been  described in the  literature (Armstead, 1983).   They
are the following:

      Nearly  all   geothermal   well  drilling   is  performed   at
       relatively   low  pressure   (this  excludes  the  geopressured
       geothermal testing now underway in the Gulf Coast area).
      With  the  exception of  the Gulf Coast  area,  the  majority of
       the   geothermal  wells  are   of  relatively   shallow  depth
       (1,500 m), having high formation temperatures.
      The rocks being drilled are mostly igneous and metamorphic.
      Geothermal wells are usually 50-100癈 hotter  than oil  and gas
       wells of comparable depths (Armstead,  1983).
      Cooling  towers  are  sometimes  required  for the  geothermal
       drilling fluids.
      Gas/drilling  fluid  separation  is   sometimes   required  for
       geopressurized field drilling.

    In fields  that produce  water  exceeding  100癈,  the drilling  depth
usually  ranges  from about  500-2,000 meters, and although a  few  bores may
lie outside  of  these  limits,  the  majority lie  in depths  of  600-1,500
meters.  In  lower  temperature fields and in low grade  aquifers  depths of
approximately 1,800 meters  are common,  but  in  some  places  (e.g.,  Klamath
Falls, Oregon),  where the  aquifer  is located close to  the  surface,  wells
range  from  30  to  300 meters.   In  geopressured  fields,  depths  of  about
6,000 meters may be necessary (Armstead, 1983).
                                   II-1-13

-------
    Nearly  all  geothermal  wells  have  been  drilled  using  the  rotary
drilling   technique.    A   typical   rotary  drilling   rig  is   shown   in
Figure II-5.  Before the drilling operations can be initiated,  a concrete
cellar must  be constructed.   The cellar serves  to support  the weight of
the drilling rig and  accommodate the  wellhead valving  and is  generally
accessed  by  a  concrete  stairway.   Consolidation  grouting  is  usually
injected into  the  surrounding ground.   This grouting  provides  additional
support and serves to  deflect away from  the wellhead any  steam that  may
accidentally ascend to the surface along the outside  of  the bore  and  its
casings (Armstead, 1983).

    The  methods and  equipment used  for geothermal  drilling do  not  vary
greatly  from those  used  in petroleum  and  natural   gas  drilling.   Both
rotary  and  turbo drilling can  be  used.   In  geothermal  well  drilling,
however,   because   of  the   possibility  of   encountering  harder   rock
formations,  higher  temperatures,  and  highly corrosive  fluids,  certain
modifications   in  techniques,  materials,   and  equipment  are  required.
(Armstead,  1983)   Serrated tri-cone drill bits made of very hard steel are
used to effect  penetration.  The  drill bits are attached  to  a hollow drill
stem,  and both  are  rotated by a power source, which is  usually a diesel
engine {Armstead, 1983).

    The process of  drilling for geothermal steam is a complex  process.  A
tall  lattice  steel tower,  which  contains  a  pulley  system,  is  used to
position and withdraw  the  drill stem and the  casing.   Power  units are also
needed  for  rotating  the  drill,  operating  the derrick,  and  driving  the
auxiliary  pumps and compressor.  There are  racks for  carrying  a stock of
such  items  as  casing  pipes and  drill  stems, and a circulatory system for
pumping,   cooling,  screening,  settling,  and   storing  the  cooling  mud
 (Armstead,   1983).  This circulating system,  and its  cooling  fluid (mud)
are of primary concern since  it  is responsible for generating  one of the
major  waste streams.
                                   II-1-14

-------
           Derrick
   Blow-out preventer
              ri
                                                       Cooling
                                                       tower
        Pump

-Swivel head
              Pump
                          Mudtjank
                                                i.  Vibrating
                                                   .screen
                                                        Chips
                                                 Main mud tank
                                                                      Pump
                            -Drill stem
                          Mud
  Figure  II-5.   Typical  Rotary Drilling  Rig  and Mud Circulation Arrangements.

Sourca:  Armstaad, Christopher H., "Geothermal Energy:  Its past,  present and
         future contributions to the energy needs of man/' 2nd Ed., London,
         1983, S and FN Span.
                                  II-1-15

-------
    One  of  the  most important  factors  in  drilling  is the provision  of
adequate steel  casings.   Normally,  up  to four  concentric  casings may  be
installed in  a single well.   They  are  constructed of  high  quality  steel
and are rigidly fixed with cement to the surrounding rock.  The  purpose  of
the casing  is  to prevent the collapse of  a  newly drilled,  completed well.
Figure  II-6 presents  a  diagram  of  a   completed  hydrothermal  well  with
installed casings.
Drilling Fluids (Muds)

    The primary purpose  of the  drilling fluid  is  to cool and lubricate,
and to  flush out  rock chippings from  the bore  hole.   It also  serves to
prevent collapse  of the  bore  walls and to cool  the surrounding  ground.
The fluid is  pumped downward  through  the hollow  drill stem  and  returns
upward through the  annular space surrounding it.  The mud circulates from
the bore,  is  screened to remove rock cuttings,  and is  then passed through
a cooling  tower.   A cooling tower may  not always be needed and the need
for one depends upon the downhole temperatures (Armstead, 1983).

    The type  of drilling  fluid used and  its proper  control  are  essential
in geothermal drilling  operations.   The drilling fluid  used for both the
vapor-dominated  and  liquid-dominated   systems  may  be   similar.   However,
drilling  into vapor-dominated  systems  generally utilizes air so  as  not to
kill  the   production  zone  with a  hydrostatic  column  of  fluid.   Liquid-
dominated  systems  are normally  drilled with conventional  drilling  fluids
(muds).   Various  types  of drilling muds  may  be  used  and  the type and
composition of the mud depend upon the  drill-site conditions.   Some  of the
more common drilling fluid  systems are  listed in Table II-l.
                                   II-1-16

-------
               Main valve
                                                       Pump
                     normal
             water well depth
           Competent lithologic unit
                                                              Concrete pad
 Conductor pipe set at
  20'-80' (6-24m)

Surface casing
                                                          Cement

                                                          Fluid level
Pump turbines
and bowls
                                                          Cement
                                                          Production casing
                                                          Liner hanger
                                                          Slotted liner
                                                                                  ft.
                                                                                 (m)
 100*
 (30)

 500'
(152)

1000'
(305)
                                                                                 3000'
                                                                                 (915)
                                                                                 5000'
                                                                                (1524)
     Figure II6   Cross Section of a Typical  Hydrothermal Well  (not to scale).

Source:  Q'Banion,  K.  and D. Layton,  "Direct Use of Hydrothermal Gsotherroal
         Energy:  Review of Environmental  Aspects," U.S. Department of Enargv,
         April 1981.
                                      II-1-17

-------
   Table  II-1.  Common Orming Fluid Systems Prevalent in Geothermal Drilling
          Type
                                                Compos i t i on
Bentonite water
Bentonite lignite - caustic
soda system
Chrome - lignite - chrome
lignosulfate system
Polymer system
Seplollte system
Bentonite provides viscosity and fluid loss
control with MaOH addition for pH adjustments.

Lignite is incorporated in the fluid to
provide greater thermal stability and better
viscosity and fluid loss control than a
simple bentonlte water system.

Chrome lignite and chrome lignosulfate are
added to the drilling fluid to Impart greater
overall stability.

Predominantly composed of polymers.   This
results 1n bentonlte extension and
flocculatlon of drill solids, thus creating  a
low sol Ids, mud system.

Seplollte clay Is substituted for bentonlte
because it does not flocculate at high
temperatures and provides better viscosity
control.  Modified polymers are added for
fluid loss reduction and caustic soda for pH
adjustment.
                                      11-1-18

-------
Distribution of Geothermal Drilling Activity

    Table II-2  and Figure II-7  present data  on  the  locations  of current
major geothermal  drilling activity in the United  States  from 1976 to 1978
(Chilinger et al.,  1982).  This  activity is  mainly found in  the western
United States where hydrothermal resources tend to be  located.
                         ELECTRICAL POWER GENERATION

    There are basically  two processes that can be  used in  the generation
of  electrical  power:  the  conventional  steam cycle  and the  binary power
system.

    In  the  conventional  steam  cycle,  geothermal   brine   is  partially
converted to  steam by flashing or sudden pressure reduction  in a vessel.
Steam from the flash process system is then piped to  the manifold where it
is  used to  directly power a turbine generator.  The exhaust steam from the
turbine  is  condensed   on  a   surface   or  barometric  condenser.    The
noncondensible gases  are vented  to the atmosphere using a  steam injector
system.  The condensate is then  pumped to a cooling tower where  it  can be
cooled  and  reused  as  water  or,  more  typically,   reinjected  into  the
aquifer.   Figure  II-8 presents  a flow  diagram  for this type of  process
(USEPA, 1978).

    In order to  maximize thermal efficiency, some  cycles utilize multiple
flashes in the overall process scheme.  Because the brine usually includes
high levels of dissolved solids, the concentration of  solids  in the brine
increases  in each flash  cycle  and  the  brine  becomes  more  corrosive.
Therefore,   a flash  injection  system  may  not  be  economically  used  in
geothermal   energy fields  containing  a   high  concentration  of  dissolved
solids (USEPA,  1978).
                                   II-1-19

-------
Table II-2.
             Sunmary of Major Geothermal  Drilling Activity in
            Western U.S.A.   (1976-1978)
State Region Area
California Imperial Valley Westmorland
Brawl ey
East Mesa
Sal ton Sea
Heber
South Brawl ey

The Geysers Main Geysers
Southeast Geysers
Northwest Geysers
North Geysers
Howard Hot Springs
Borax Lake
Mlddletown
Thurston Lake
Castle Rock
Cloverdale
Mt. Konaockl
Callstoga

Mono Co. Long Valley
Inyo Co. Coso Hot Springs
N.W. California Lassen

Nevada Churchill Co. Desert Peak
Stlllwater
Lander Co. Beowawe
Carson sink soda Lake
Allen Springs
Pershlng Co. Rye Patch
Dixie Valley
Gerlach
San Emld1o Desert
Number of wells
1976
6
2
2
-
6
-

13
-
-
-
-
-
3
-
4
1
1
3

1
1
-

2
3
1
-
-
-
-
-
-
1977
1
2
S
-
-
-

14
13
2
1
1
-
-
1
.
-
-
-

.
1
-

.
_
_
1
1
1
-
-
_
1978

4
7
1
_
1

IS
6
1
2
1
1
1
_
.
_
_
-


.
1


_
_
_
_
1
1
1
1
Total
7
a
14
i
6
	 I
37
47
19
3
3
2
1
4
1
4
1
1
	 j
89
1
2
	 ]_
4
2
3
1
1
1
2
1
1
	 1
                                                              13
                        II-1-20

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Table  II-2.  (continued)
State
Oregon


Hawaii

Idaho





Utah





New Mexico



Region
Klamath Co.


Hawaii Island

Cassia Co.
Ada Co.
Washington Co.
Owyhec Co.


Beaver Co.

Mlllard Co.
Iron Co.


Sandoval Co.



Area
Klamath Hills
Mt. Hood

Puna

Raft River
Boise
Crane Creek
Castle Creek
Preston

Roosevelt H.S.
Thermo H.S.
Cove Ft.
Beryl Junction
Lund

Fenton H111
valles Caldera

TOTAL
Number of wells
1976 1977 1978 Total
1 - - 1
1 	 1
2
2 _j
2
2147
2 - - 2
1 - 1
- 1 - 1
1 	 ]_
12
3115
1 2
1124
2 - - 2
1 - 	 1
14
1 - 1
1 	 L
2
65 51 58 175
        II-1-21

-------
                 (*  \HAWAII
                 (^  2

                HAWAIIAN ISLANDS
   Figure II-7   Locations of Major Geothermai  Drilling,  Western USA,  1976-1973.

Source:  Chilinger, G.V.,  L.M. Edward, W.H. Fertl, H.H.  Ricke III, Editors,
         "The Handbook of  Geothermai Energy."  Houston,  Texas, 1582, Gulf
         Publishing Company.
                                 II-1-22

-------
                z
                o
                a
                O
                       STEAM FROM
                       OTHER  WEILS
    COOLING
     TOWER
                                    WASTE WATER
O
CJ
vu
z
   Figure IJ-8.  Simplified Schmatic diagram of Conventional Steam Cycle Electrical Power
               Plant
Source:  Hartley, R.,  "Pollution Control Guidance  for Geotheraal Energy
         Development," Industrial Environmental Research Laboratory, Cffics o:
         Research and  Development, "J.S. EPA, 1373.
                                      II-1-23

-------
    The  binary cycle  avoids  the  corrosion problem  by  employing  a  heat
exchanger to transfer  heat from the  brine to  a secondary working  fluid.
This  fluid,  usually isobutane  or isopentane,  is then  used  to  drive  a
turbine.  Binary  cycles are much  lower in  thermal efficiency than  flash
injection  systems.   Figure II-9 presents  a  flow diagram for  a  binary
system.
Current and Planned Development

    Table  II-3  presents  a  summary  of  the  status  (through  1985)  and
projected development of geothermal power plants in the U.S.   These  tables
also describe  power  generating capacity as either operational, planned, or
under construction; they also note process type.

    The two best known  power generating facilities, at The Geysers  and at
Imperial  Valley,  (both  in  California)  utilize  vapor-dominated  resources.
The Geysers  (through 1985)  had 1792 MW  operational  and  plans  to  expand
this capacity  to 2660.2 MW.  At Imperial Valley,  the  operational  capacity
is  32.5  MW and  plans  to  increase  capacity  to  4140   MW.    These  two
facilities  together  account for most of  the  installed capacity.   However,
other plants are being  constructed, mostly in  the western United  States,
to  take advantage  of the  high temperature hydrothermal  reservoirs which
can be utilized economically (DiPippo, 1985).
                           DIRECT USE APPLICATIONS

    In  addition to the  use of geothermal resources for  the  generation of
electric  power,  the   power plants  may  be  used  directly  for  heating.
                                   II-1-24

-------
                                   STEAM
                                                             QKGAHIC UflPOR
 I
M
 I

Ul
                        CEOTHERHAL
                        WELL
                                      Figure II-9  Simplified Schematic Diagram for  Binary Type Electric
                                                 Power Generation  System.

-------
            Table II-3.  Geothermal  Power  Plants  In the United States
Plant

California
Cosco:

Mammoth:

Honey Lake

Geysers:
Year


1986
n.a.
1984
198S
1987


PG&E Geysers 1960-1985





Imperial Valley
East Mesa


Sal ton sea



Heber
Binary Oemo Plant
Flash Plant (HOC)
North Brawl ey
Westmoreland
So. Brawl ey (CU I)
1985
1988
n.a.
n.a.
1988

1979
1986
n.a.
1982
1986
1985
n.a.

1985
1985
1980
1988
n.a.
Tyoe


1-Flash
1-Flash
Binary
Binary
Hybrid: wood-
geothermal

Dry steam
Dry steam
Binary
Dry steam
Dry steam
Dry steam

Binary
Binary
Binary
1-Flash
2-Flash
2-Flash
2-Flash

Binary
2-Flash
1-Flash
Binary
Flash
MW


25.0
2 x 25.0
2 x 3.5
5 x 0.6
20.0


1454
338
141.2
55
617
55

12.5
20.02
50.0
1010
73.1
31.4
49.0

45.0
49.0
10.0
15.0
49.0
Status


Under construction
Advanced planning
Operational
Under construction
Under construction


Operational
Under construction
Advanced planning
Advanced planning
Preliminary planning
Under CEC review

Operational
Under construction
Planned
Operational
Under construction
Planned addition
Planned

Under construction
Under construction
Operational
Planned
Planned
Hawaii




   Puna No.  1
1982   1-Flash
                                                  3.0    Operational
                                    II-1-26

-------
                              Table II-3.   (continued)
   Plant
                        Year   Type
                                                                   Status
Idaho

   Raft River
1982   Binary
   5.0    Being moved to  Brady U.S.
            NV
Nevada
   Wabuska Hot Springs
   Beoware
   Brady Hot Springs
   Steamboat Springs
   Fish Lake
   Big Smokey Valley
   Desert Peak

   Spring Creek
   Dixie central
Oregon

   Hanmersly Canyon 1983-1984  Binary
1984
1985
1986
1986
1986
1986
1985

1987
1987
Binary
2-Flasn
Binary
Binary
Binary
F1ash(?)
Total flow/
2-Flash
2-Flash
Flash
Utah
   Milford:
    Blundell Unit 1      1984
    Wellhead No. 1      1936

   Cove Ft Sulpnurdale:
    Phase  1             1985
    Phase  2             1985
    Phase  3             1986
       l-Flash
       Total now/
       2-Flasn

       Binary
       Binary
       Dry steam

       Totals:
0.6
17.0
8.3
5.5
15.0
10.0
9.0
20.0
20.0
Operational
Under construction
Under construction
Planned
Planned
Planned
Under construction
Planned
Planned
                           2.01    Operational
  20.0    Operational
  14.5    Under construction
4 x 0.675 Operational
2 x 1.0   Under construction
    2.3   Advanced Planning

1893.61   Operational'
 353.71   Operational  or U.C.
3331.11   Operational, u.c. or
            planned
   includes plants under ccnstruction and scheduled for comole'ion in 1985.

                                      II-1-27

-------
cooling, and  a  variety of other  applications.   Figure 11-10  presents  the
potential  extent  of direct  uses,  as well  as the  approximate temperature
range of  use.  In  general,  direct use  of geothermal  resources  comprises
applications   in   agriculture,   aquaculture,   space  conditioning,   and
industrial  processes.   The  end  use  distribution  along  with  the  use
temperature is  shown  in  Figure  11-11.   Space heating  is by  far  the most
widely practiced  direct  use  application of  geothermal  energy, other uses
include (Chilinger et al., 1982):

      Greenhousing;
      Mushroom culturing;
      Livestock raising;
      Soil warming;
      Aquaculturing (fish hatcheries, alligator breeding, etc.);  and
      Biogas production.

Industrial uses may include applications such as:

      Preheating;
      Washing;
      Cooking and peeling (pulp and paper industry);
      Evaporating;
      Sterilizing;
      Distilling and separating;
      Drying; and
      Refrigeration.

    There  are two basic  types  of direct use systems:  those  that utilize
the hydrothermal  water itself and  those  that transfer the  heat  from  the
hydrothermal  fluid  to another fluid  (a working fluid).   The main  reason
for using  a working fluid is to isolate the  system from  the  hydrothermal
                                   II-1-28

-------
                           昪
                          '200'


                          190-


                          180-


                          .170"
          SATURATED^
             STEAM
              THERMAL
               WATERS
                           90-
                           80
                           70-
                           20.
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H Drying ambar ~ -
                                                              ELECTRICAL:
                                                             PRODUCT/ON
                                   Drying fwm products 玹 high ratm
                                  ^Evaporation In sugar r
                          130 玈i EnrMtfon of tato by
                                                   u.   -'             -

                                                      w v  At  t f Jt 梩o	晽  -  *  
                                   Mast murapHXttaat svaparatians. aanaantratlan aiiaMna satait
                                   Oryin* witf curing NgM-*ggr玤n* contr玹 !晻
                                                    *
                                                               . v*g玭bln. we.
                                                   -_5

                                                   - ^
                                                                              --- . -- e  -
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                                   Spaca hMting of grnriout
                                   R玀g玭tio (know t籱p*rMiu* limit)
                                    Animal hutbantf>y
                                   CamWnW ipac* d hotbed htlng o( 9'*
                                   Mu
                                   Madlclnal b*m
                                   Swimming p玱n>. Mod玤n>玹lan. f玶m籲籲om
                                   Wwm w*r far y*r-round mining In ceM eUmaim
                                   O4clng
                                   n玭 hatching tnt 换H worming
        Figure n-10    Typical  Geothermal Fluid  Temperatures  for  Representative
                       Direct-Use  Applications.

Source:   Chilinger, G.V.,  L.M.  Edward, W.H.  Fertl, H.H.  Ricke  III.  Editors,
           "The  Handbook of  Geothermal Energy."  Houston,  Texas, 1982,  Gulf
           Publishing Company.
                                            II-1-29

-------
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-------
fluid and  its  impurities  and  thus to  confine  or  reduce  corrosion  and
scaling problems.   Such a system is shown in Figure 11-12.
                                  II-1-31

-------
                       HEAT EXCHANGERS - E.G. RESIDENCES
                                                                         WATER
                                                                       DISCHARGE
      Figure H-12
Simplified Schematic Diagram of Non-electric Use (space
heating) of Geothermal Energy.   Spent Liquids Can Be
Injected or Discharged to Surface Waters.
Source:  Hartley, R., "Pollution Control Guidance for Geothermal Energy
         Development," Industrial Environmental Research Laboratory, Office of
         Research and Development, U.S. EFA, 1973.
                                    II-1-32

-------
                                  CHAPTER 2
                              WASTE GENERATION
    A review of available information indicates that there are  two primary
processes   that   generate   wastes   associated   with  the   exploration,
development, and production  of geothermal energy.  These wastes  come  from
(1) the  process   of   drilling  and  (2) the  direct  utilization  of  the
resource.  This section presents a brief description of how the  wastes are
                                           
generated  and a  suggested  methodology  for  estimating  waste volumes and
characteristics.   A substantial  amount   of  information was  derived  from
three previous studies {USDOE,  1982; USEPA, 1978; USEPA,  1983).
                               WASTE  SOURCES
Drilling Wastes
    The process of drilling  for  steam from a geothermal  resource  has  been
described in detail  in  the Industry Description.  In a  1982  study (USDOE,
1982), it was estimated that (based on the experience of  drilling  50  wells
in  the Imperial  Valley in  California)  about 600 metric  tons  of mud  and
cuttings would be produced while drilling a typical 1,500-meter  well.
                                   II-2-1

-------
    Typically, there  are four  types  of wastes  generated by the  drilling
process.  They are:

      Drilling fluid and drill cuttings;
      Deck drainings;
      Drilling fluid, cooling tower wastes; and
      Miscellaneous small waste streams.
Drilling Fluid Waste

    A large quantity of drilling waste is derived from the  drilling mud or
the  processing  steps  taken to  reuse  and  recycle this  material.   The
drilling  fluids are  "cleaned" by  circulation  through  solids  separation
equipment,   (i.e.,   shale   shakers,   sand   traps,  hydrocyclones,   and
centrifuges).   After  "cleaning,"  the  drill  cuttings  and washwater  are
discharged and  the "cleaned" muds are reused.   There  is,  however, a point
of diminishing  return with the cleaning process.  When the  muds become too
viscous,  the muds  must be  discharged  into a  reserve pit.   Muds also are
discharged  into the  reserve pit when all  drilling is  completed  or  when
entire  mud  systems  are  changed  because  of  abrupt  changes  in drilling
conditions.

Deck Drainings  Wastes

    Typically,  drilling oprations generate deck drainings.   These wastes
are   composed  of  rig washdown,   rinses,  drilling   fluids,  and  other
miscellaneous   waste  materials  generated  on  or  around  the   derrick.
Depending on   the  type  of drilling  operations,  these  volumes  can be
substantial.
                                    II-2-2

-------
Drilling Fluid Cooling Tower Wastes

    Some  operations  may  necessitate  the  drilling  fluids  being  cooled
before  it  is recycled  into  the  well bore.  For those  cases,  the drilling
fluid  is circulated  through a  cooling  tower.   The   tower  will  require
occasional cleaning of scale and other deposits that build up in the tower.

Miscellaneous Small Waste Streams

    Other wastes will  also he produced in the drilling operations.   These
wastes  consist  of  empty  containers,  bags,  broken tools,  paint  wastes,
minor  spillages  and leaks  of diesel fuel, hydraulic fluid,  wood pallets,
and miscellaneous trash.
              WASTE STREAMS FROM POWER PLANTS AND DIRECT USERS

    It  is  convenient to  classify the wastes  generated from  the  usage of
geothermal energy into two categories:   (1) wastes  derived  from operations
that  use  geothermal  energy  for  electric  power generation and (2) wastes
derived from direct  usage.   These streams are  discussed on  the  following
pages.

Electric Power Generation

    Presented below  is  a  preliminary list of solid wastes  that may result
from the generation of power from geothermal energy.  These  wastes include:

      Reinjection well fluid wastes;
      Piping scale  wastes,  production  well  filter waste, and flash tank
       solids;
      Brine effluent precipitated solids; and
      Settling pond solids.
                                   II-2-3

-------
    The sources  of these  wastes  are shown schematically  in  Figures  11-13
and Figure 11-14 (USDOE, 1982).

    Several other wastes are generated by electric  power  generation plants
that  utilize  geothennal  energy,  but,  as  described in  the  Introduction,
these wastes are not  expected  to  be covered by the  statutory exclusion or
included in the final report.  The wastes include the following:

      Makeup water treatment solids;
      Hydrogen sulfide removal wastes; and
      Cooling tower drift and blowdown.

    These wastes are included in Figures 11-13 and 11-14 for completeness.

    As  indicated  in  Figure  11-14,  solid  precipitates  resulting  from
temperature and chemical  changes  in  the brine  during  energy extraction
constitute about  one-half of the solid waste  generated;  well cuttings and
drilling  mud constitute  about  one-guarter;   scale,  solids  from  cooling
water  treatment,  H_S  abatement,  and  other miscellaneous sources  make up
the balance.  It is not  known  if these charts are  typical of the industry
in  1986.   More   data  must  be  collected  to  verify  these  preliminary
estimates.

Reinjection Well Fluid Wastes

    The reject  fluid  from the geothennal  power plant potentially can  serve
as  a  vehicle for disposa.1 of  most  of  the  dissolved  solid  wastes when
reinjected  into an aquifer.  However,  brine   injection can  be complicated
by  precipitation  of  silica in high levels.   The  precipitation  of  silica
has  the  tendency  to occlude or  cause co-precipitation of other dissolved
ions  present  in the brine.  Thus,  the  silica  precipitate may contain heavy
metals at  elevated concentrations.
                                    II-2-4

-------
Nl

Ul
                            PIPE
                           昐CALE
                            WASTE
                                               HjbHtMOVAl /
                                                IHtAIMtNl
                                                  WASIE
                                FLASH
                                 VANK
                             SPENT
                             UHINE
      PHOOUCTION
      WELLflLTEfl
      WASTE
        WELL
        DRILLING
        WASTE
FLASH TANK
SOLIDS WASTE
(BHINE PHECIPITATEI
                                                                                                                  WATLH
                                                                                                                  Slim Y
                  COOI INli IOWER
                   UtfcAIMtNl/
                   blOWIIOWN
                     WASIE    i
MAKE UP
 WATER
 SOLID
 WASTES
         H Ull IHEATMF.NI
           (CI.AHIHEH/
          S miNGPONO)
                  rnr
                       T
LIOIJIU WASTE
                      SOI 1C)
                      WASIE
                                                                             7777
                IN IEC MOM
                WEI L FlUlO
                WASTE
                                              Figure 11-13.   Sources of Geothermal Solid Wastes.
                              Source:  Darnell,  A.J., et al.,  "Survey of Geothermal Solid Toxic Waste,"
                                       Rockwell  International  Energy Technology Engineering Center, for U.S.
                                       pppartment of Energy, San Francisco, California.

-------
              Flash  Tank  Solid
              Uastes(Br1ne
              Precipitate)  53 X
                                    Well Drilling Wastes
                                    (Well Cuttings &
                                    Drilling Muds) 26 X
                          Solids From
                          H,S Abatement
                           * 1 I
                                                           Production Well
                                                           Filter Wastes  4
                                                           Pipe  Scales Wastes
                                                           15  %
Slowdown Wastes
And Solids From
Cooling Water
Treatment 5 %
Figure 11-14.   Distribution of  Solid Wastes  from  Development of a Liquid-
               Dominated Geothermal  Resource.
 Source:   Darnell, A.J.,  et al.,  "Survey of Geothermal Solid Toxic Waste,"
           Rockwell International  Energy Technology Engineering Center, for
           U.S.  Department of Energy,  San Francisco, California,  1982.
                                   II-2-6

-------
Piping, Production Well Filter Waste, Scale Waste, and Flash Tank Solids

    Scale  can  constitute approximately  15  percent  of  the solid  wastes
requiring   disposal..    Temperature,   pH,   chloride   and   sulfate   ion
concentration,  and  dissolved gases  (C0_,  H.S,  NH )   all  influence  the
level  of  scale formation.   Scaling and plugging  may result  from one  or
more of the following:

      Precipitation and  polymerization of  silica and silicates (silica in
       solution will  neither precipitate  nor  adhere until  it starts  to
       polymerize);
      Precipitation of alkaline  earths as  insoluble carbonates, sulfates,
       and hydroxides;
      Precipitation of heavy metals as sulfides; and
      Precipitation of redox reaction products (e.g., iron compounds).

Silica precipitation  and scale formation  are among  the  major  problems in
geothermal energy conversion and injection systems.

    Many of  the factors  causing  the formation  of scale  from an  aqueous
solution could  be  reversible.   It is, therefore,  highly  likely that  scale
would  exhibit  some  solubility to surface waters under  ambient conditions
and that  any toxic  substances  present in  the scale would  potentially be
leachable.

Brine Effluent Precipitated Solids

    Brine  effluent  precipitated  solids  generated  from  geothermal  fluids
are saline and  may contain elements such as  arsenic,  lead,  boron,  and
fluoride.   If there  is  to  be optimum  utilization  of  heat,  most  brine
effluents  are  returned  to  the   reservoir.   In  some areas,  such as  the
                                   II-2-7

-------
Imperial  Valley,  these  can  be  supersaturated  with  silica.    Although
amorphous silica  may not  deposit  readily from  water flowing  in a  pipe,
separator, or  heat exchanger,  it  is known  to do so on concrete  or brick
surfaces.  Thus,  with  time,  it will reduce  injectability  by blocking  the
aquifer   formation   unless   the    chemical   composition   is   carefully
controlled.   Therefore,  treatment  of the brines will  have  a major  impact
on  the  type and  amount of  solids  that  must be disposed of.  In  order to
maintain  its injectability in the  accepting formation, it  is necessary to
adequately  treat   this  brine  effluent  to  rectify  its   supersaturated
dissolved solids  condition.   Three  processing methods used for  treatment
of geothermal brines are:

    (1)  Ponding  of  the  brine  effluent  with  reinjection of  the  clear
         liquor underground and landfilling any precipitated solids.
    (2)  Use of conventional water treatment technology to  precipitate  and
         remove  solids  and  toxic  materials.   The  wastewater  would  be
         injected and the  solids hauled to a landfill.
    (3)  Processing the geothermal  brine in such a  way that minerals  and
         useful  byproducts  are  recovered  from the  brine.  Solid  wastes
         would  then be  disposed of in  a  landfill,  and the clear  liquid
         injected into  the aquifer.

Settling Pond Solids

    Settling  pond  solids  are generated  by  spent   brine   holding  ponds.   A
holding  pond  has been used  at  the East  Mesa  site for  treatment of  spent
brine.   This  holding  pond  has  sufficient   residence  time  so  that  liquid
withdrawn from the end opposite the injection point  is sufficiently clear to
be  injected back  into the aquifer.  Solids  that accumulate in  the pond are
dredged  and then  dried by evaporation and transported to  a suitable landfill
site.   This  method has been  successful  in those cases  where the  salinity of
the brine is  low.   At  the  East Mesa site,  the salinity  of the  brine is low
compared  to the Salton Sea sites.  (USDOE, 1982)
                                    II-2-8

-------
Cooling Tower Drift and Slowdown

    Cooling  tower  drift will  be present whenever an  evaporative  type cooling
tower is  used.   The drift is a  fine  mist of water  droplets that  escape from
the  top  and  sides of  the  tower  during  normal  operation.   Any  compounds
normally present in the cooling water will be carried out with the drift.
Direct Steam Usage

    A brief  discussion of  direct resource utilization  has been  discussed in
the Industry  Description.   Drilling wastes  generated from  these  applications
are   expected  to  be   similar  to  those  produced for   power   generation.
Information  on  waste  sources  from  direct  steam  usage   is  currently  being
developed.
                WASTE CHARACTERIZATION, COMPOSITION, AND VOLUMES

    A  preliminary review  of  information  from  selected data-bases  indicates
that  the  literature  is  limited  in  the   areas of  quantifying the  sources,
volumes,  characteristics,  and  management  techniques   for   specific  wastes
derived   from  some,   but   not  the   majority,  of  geothermal   activities.
Nevertheless,  there  is still  enough  data  to  provide the  reader,  in  the
interim, with  a general sense of the  types  and characteristics of wastes that
may be  encountered  as a result of  the utilization  of geothermal  energy.   We
are currently reviewing the following:

      Chemical Abstracts;
      Enviroline;
      Pollution Abstracts;
                                   II-2-9

-------
      U.S. Geological Survey Library;
      U.S. Department of Energy, Geothermal Division Reports;
      Cambridge Scientific Abstracts;
      Sandia National Laboratories Technical Publications;
      Los Alamos Scientific Laboratory Publications; and
      Proceedings of the Geothermal Resources Council.

Because  of data  availability,   this  report  will  again  draw  heavily  on  the
results  of three EPA  studies:   published  in 1978, 1982, and  1983,  which were
undertaken  to characterize  certain types  of  geothermal  wastes  at  selected
sites.
          WASTE STREAMS FROM ELECTRIC POWER GENERATION AND DIRECT USERS

    In  1983,  major geothermal  resource exploration  and  development sites  in
the  western United States  and the  Gulf Coast were  screened by  Acurex  under
contract  to EPA  (USEPA, 1983)  to  locate candidate  sites  for  sampling  and
analysis.   A   telephone  survey  of   over   20   individuals  representing  15
organizations  was  conducted to identify the  types  of solid  wastes generated.
These data appear to be the most detailed and comprehensive found to date.

    As  a result of  the telephone  discussion,  follow-up  letters,  and  several
site  visits,   the  sampling  program was  defined and permission  obtained for
collecting  samples  in three geothermal  resource  areas:  the Imperial Valley 
7 sites. The Geysers  11  sites, and Northwestern Nevada    3 sites.

    The  samples, collected  on three  field trips,  encompassed  the following:
                                   II-2-10

-------
                         Total   Geysers, CA   Imperial Val., CA   Nevada
Drilling sumps
       Mud/fluid          82               3                3
       Mud only           3                               .            3
       Fluid only         5                          5

Reinjection treatment
       Sediment ponds     3                          3
         (brines)
       Flash tank         1                          1
       Filter press       1                          1

Cooling tower basins      3          3
H2S removal
       Centrifuge (iron   3          3
        sulfide sludge
        dewatering)
       Stretford process  1          1
        sulfur recovery
        stream

Miscellaneous
       Pipe scale         2                          2
       Geological surface 1          1
        expression
       Landfill           2                          2
    Of this sampling  and analysis program was to evaluate the solid wastes

for  some  RCRA  hazardous  waste  characteristics  and   listing   criteria
proposed in 1978.


    In addition  to the  eight  constituents analyzed  (Ag,  Ba, Cd,  Cr,  Pb,

Hg, Se,  As),  tests were also conducted  for  eight  other metals  in  that
study.  These metals  (Sb,  Be,  B, Cu,  Li,  Ni, Sr, Zn)  were included because

of their suspected presence  in geothermal solid  wastes  and  their  listing

in  the  water  quality  standards of  several  western States.  Analytical

results for these metals are  summarized in Table II-4.  In general,  these

levels were fairly low,  except the levels  for boron and zinc.
                                  II-2-11

-------
             Table  II-4.   Summary of Results for Additional Metals


Metal
Antimony
Beryl 1 ium
Boron
Cooper
Lithium
Nicfcel
Strontium
Zinc
Range of
Concentrations
 All Samples
(mg/1 )
0.05 - 0.18
0.020
0.2 - 660
O.OS - 60
o.os - s. a
0.2 - 0.90
0.5 - 1 ,400
0.020 - 6.000
Average Concentration
All values Above
Detection Limit
(mg/1 )
0.14
~
43
9
1.1
0.50
174
203

Number of
Values Above
Detection Limit13
3
0
26
12
19
n
16
30
alncludes results for both acid and ambient  pH extracts.
''Total  number of possible values (analyses)  equals 42.
                                 II-2-12

-------
    Additional   organic   analyses   were  conducted   on   three   samples,
presumably  drilling  wastes.   Sample  G12 was collected  at the Class  II-2
landfill  in Brawley.   This   landfill  contained a  mixture of  fresh solid
wastes,  predominantly drilling  muds, from  the Imperial  Valley.   Sample
G24-1  was  a geothermal drilling mud  sample  containing significant amounts
of oil.  Additives known to  be  present in this mud were bentonite,  sodium
hydroxide,  calcium  hydroxide,   sodium  tetraphosphate,  and  a  polymeric
material.   Sample  G22-1  was  selected  for   organics   analysis  because
cationic  polyamines   and anionic  polyacrylamides  are added  to   the  iron
sludge  removed  from  the  H.S  abatement   centrifuge.    These  additives
facilitate settling of the solids.

    Three  samples  (two drilling muds and an  iron sulfide) were screened
for the 11 acid compounds and 46 base/neutral compounds  listed as priority
pollutants by EPA.   Each sample gave two fractions for  analysis  by GC/MS.
Phenol  and  phenol   derivatives  were  found  in all   three  samples.   The
occurrence  of  phenols in  the  drilling mud  samples  (G12  and  G24-1)  is
probably  due to the  reaction  of  caustic  soda  (NaOH)  with  additives
containing  phenol  groups.   The  alkaline nature of the  muds and  the final
pH of  the  ambient  extracts  (both 9.4) suggest  that the phenol is present
as a sodium salt.  This is confirmed by the higher concentration of phenol
in  the   ambient  extract   (640 V*g/l)   compared ' to   the  acid  extract
(2 Mg/1)  in  G24-1.    Polynuclear  aromatic  compounds  (PNAs)  were  also
detected in G-12 and G22-1.   For sample G-12, these could  easily  have  come
from asphalt (known  to contain  PNAs),   which  may have  been used in an
oil-based drilling mud system.   The presence of a  PNA in the  iron  sludge
(G22-1)  cannot  be  readily explained,  since the only  known additives  were
polyamines and polyacrylamides.

    Tables II-5, II-6, and II-7 summarize the analytical  results  for these
three  samples.   In addition  to the trace levels of organics, the Brawley
                                   II-2-13

-------
                                           Table  II-5.  Geothermal Analytical  Data: Class  11-2  Landfill



          Number:  GI2  M437)                       Type:  Mixed  Solids
to
I
Location; Bradley

Bulk
Compofr j t j Qt)
Aluminum (Al)
Calcium (Ca)
Iron (Fe)
Magnesium (Hg)
Potassium (K)
Sodium (Na)
Chloride (Cl)
Fluoride (F)
Silica (Si02)
Sulfate (S04)
Sulfide (S)





ORGAN 1CS
( Imperial

Total

2.3
1.60
1.2
1.72
0.69
0.50
0.40
0.033
24.2
0.06
0.01






Valley!
Acid
Extract
(mq/1)
1
680
0.8
20
46
235
215
0.29
2
10
0.1






Priority Pollutants Detected
Acid. Extract
Neutral Extract

phenol
4.6-dini tro
Dhenol

-o-cresol

Anthracene/ohenathrene

Neutral
Extract
(mg/H
190
33
76
52
85
230
227
0.56
160
85
0.1






Mg/1
4
lfl
2
6
Site Owner/Operator:


Trace Elements
Arsenic (As)
Barium (Ba)
Cadmium (Cd)
Chromium (Cr)
Lead (Pb)
Mercury (Hg)
Selenium (Se)
Silver (Ag)
Antimony (Sb)
Beryllium (Be)
Boron (B)
Copper (Cu)
Lithium (Li)
Nickel (Ni)
Strontium (Sr)
Zinc (Zn)
OTHER
Corrosivi ty
Moisture
TSS
Radium 226

Imperial County Dept. of
Acid
Extract
tUflZlL-
100
1.000
5
23
20
1
20
20
50
20
200
70
130
200
2.400
250
PARAMETERS
10 pH
5r/.
NA
1.15 pCi/g

Public Works
Acid
Extract
(Ug/li
250
1,400
5
420
20
Int
50
20
100
20
340
230
340
200
100
1,400







-------
Number:  G22-1 (15791
                           Table 11-6.  Geothermal Analytical Data:  Iron Sludge from Centrifuge





                                           Type:   Sludge
Location; Unit 5 & 6 (The Gevserb)

Bulk
Composition
Aluminum (Al )
Calcium (Ca)
Iron (Fe)
Magnesium (Mg)
Potassium (K)
Sodium (Na)
Chloride (Cl)
Fluoride (F)
Silica (Si02)
Sulfate (S04)
Sulfide (S)





ORGANICS

Total
a>
0.01
0.005
7.7
0.005
0.004
0.065
0.005
0.001
0.04
0.29
0.2






Acid
Extract
(mg/ll
1
2.4
0.2
0.20
O.IB
24
1
0.12
4
9.5
0.1






Priority Pollutants Detected
Acid Extract

Neutral Extract
phenol
Benzo (k)


f luoranth^ne

Neutral
Extract
(mq/n
1
2
0.2
0.16
0.15
24
1
0.14
4
85
0.1






"g/1
Q 4
_^ 	
None detected
Site Owner/Operator: PG & E


Trace Elements
Arsenic (As)
Barium (Ba)
Cadmium (Cd)
Chromium (Cr)
Lead (Pb)
Mercury (Hg)
Selenium (Se)
Silver (Ag)
Antimony (Sb)
Beryllium (Be)
Boron (B)
Copper (Cu)
Lithium (Li)
Nickel (Ni)
Strontium (Sr)
Zinc (Zn)

Corrosivi ty
Moisture
TSS
Radium 226
Acid
Extract
jM.g/1)
20
300
5
20
20
1
20
20
50
20
28,000
70
50
200
500
60
OTHER PARAMETERS
6.6 pH
70%
NA
0 pCi/q
Acid
Extract
(Ug/1 1
20
300
5
20
50
1
20
20
100
20
27,000
70
100
200
500
30






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                                     Table II-7.  Geothermal Analytical Data:  Abated Well Sump, Beigel #1 Well


            Number:  G24-K158IR1                      Type:  Mud
to
 I
Location: Near Unit 18(The Gevsersl

Bulk
Composition
Aluminum (Al )
Calcium (Ca)
Iron (Fe)
Magnesium (Hg)
Potassium (K)
Sodium (Na)
Chloride (CD
Fluoride (F)
Silica (Si02)
Sulfate (S04)
Sulfide (S)





ORGANICS

Total
q>
1.58
0.59
3.03
1.6S
0.27
0.11
0.014
0.024
19.4
0.02
0.02






Acid
Extract
(mo/ll
,
280
32
9.6
6.3
24
2
0.34
4
32
0.1






Priority Pollutants Detected
Acid Extract

Neutral Extract
2-nitrophenol
phpnol
phenol



Neutral
Extract
(mg/1)
1
34
0.2
0.04
2.5
48
1
0.28
16
62
0.1






Mg/1
3
2
640
Site Owner/Operator:


Trace Elements
Arsenic (As)
Barium (Ba)
Cadmium (Cd)
Chromium (Cr)
Lead (Pb)
Mercury (Hg)
Selenium (Se)
Silver (Ag)
Antimony (Sb)
Beryllium (Be)
Boron (B)
Copper (Cu)
Lithium (Li)
Nickel (Ni)
Strontium (Sr)
Zinc (2n)
OTHER
Corrosivi ty
Moisture
TSS
Radium 226
Union Oil of California
Acid
Extract
(Ufl/l >
20
300
5
20
20
1
20
20
50
20
870
70
50
300
600
300
PARAMETERS
10 pH
53%
NA
0.5 pCi/g

Acid
Extract
(Ug/]\
32
300
5
20
20
1
20
20
50
20
15,000
70
50
500
500
20






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sites  showed  elevated  levels of  barium  1,400  l*g/l and  the  other two
sites  showed  elevated  levels  of boron  1,500-27,000  ^g/1   in  the  waste
streams.
                               DRILLING WASTES
    The 1982  EPA study (USDOE, 1982) provides a qualitative composition of
a typical  drilling fluid one might use  in geothermal drilling operations.
The report  presents the results of sampled  and  analyzed drilling muds and
cuttings at six power plant locations.

    The report postulates  that,  while the well cuttings  are  not likely to
be  hazardous  in  themselves,  they may  be  sufficiently  contaminated with
brine and  drilling fluid  to  require  special  disposal.   A summary  of the
results from the analysis of these samples is given in Table II-8.
Production Waste

    Analyses were made of several other waste streams including:

      Piping scale wastes and flash tank solids;
      Settling pond solids and effluent;
      Cooling tower drift and blowdown; and
      Brine effluent precipitated solids.

    Data from these  was  streams are included in the 1983 EPA study and are
provided in order  to establish the relative  ranges of  concentration pre-
sent at  one location.  In  general,  all four effluents  show  low levels of
arsenic.   Barium results showed levels of barium (300 - 10,500 Vg/l) in
                                   II-2-17

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0)982
                               Table 11-8.  Summary of Analysis from Drilling Muds




l-t
M
Nl
1
|-_ |
00



Location
East Mesa. CA
Nil and. CA
Westmoreland, CA
The Geysers, CA
(near Unit 13)
Steamboat. NV
Hunboldt. NV
Desert Peak. NV

pH
12.0
8.4
8.8
9.6
9.3
9.8
9.1
Radioactivity
(pCi/g)
1.0
2.1
5.9
0.4
1.0
1.6
Kb
As
Ba
Cd Cr
(Neutral
Pb
Extract)
Hg Se
Ag
(Mg/L)
20
20
41
20
260
140
20
300
300
6,800
300
300
500
300
5
5
5
5
5
5
5
20
20
20
20
20
27
39
20
20
20
20
20
400
20
1 20
1 20
1 120
1 20
1 20
1 20
1 20
20
20
20
20
20
20
20

-------
the acid  extract  and somewhat  lower  levels  (300  -  5,400  >*g/l)  in  the
neutral extract.   RCRA  limits for  barium are  100 Wg/1.  Arsenic  levels
range  from  36 to  230 Vg/1  in the  acid  extract  and  33  to  230 Hg/1  in
the neutral  extract.   The  analytical findings for  lead ranged  from  less
than  20  ug/l  to  200 Hg/1  in acid extract  and  less than 20  "g/1  to
130 ug/l in neutral extract.
                                 DATA NEEDS

    This waste information essentially represents "point" data,  but  is the
best available at  this time and shows characteristics that are believed to
be  highly  site  specific.   Further  data  are  required  before  definite
conclusions  can  be reached  about  the nature and characteristics  of waste
generated from power production from geothermal resources.

    Data are not available  to  allow the projection of total  volume  of mud
and cuttings for the  industry,  and this must be developed.   However, the
1982 EPA  study estimated  that 600 metric  tons  of  cuttings  and  that  mud
would  be  generated  by  the  drilling  of  one  1,500-meter  well.   These
estimates are based on data derived from drilling  50 wells in  the  Salton
Sea area of California.

    In addition,  information covering  the  volumes  and  composition  of the
waste  from  drilling  operations  must  be  developed.   This  information
includes the volume and characteristics of mud pit  solids, well cuttings,
and  cooling tower blowdown.   Because  of  the  dispersed  nature  of  the
industry,  it is  suspected that the  results of  these findings will  show
that the characteristics of these  streams will be  very  site  and  geologic
formation   specific.    If   this   is   the   case,   then  a   comprehensive
characterization of  the  industry   will  be  very  complex.  Data  are  also
                                   II-2-19

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required  in order  to prepare  reliable  estimates  of  volumes  of  wastes
generated by the industry.

    To fill  these data gaps  and to provide the data required to complete
the  study,  the literature  survey now  underway will be  completed.   This
manual  literature  search  of waste  characteristics and  volumes will  be
supplemented by accessing the following data bases:   Aqualine, Enviroline,
Pollution Abstracts,  and  Chemical Abstracts.   Appropriate articles will be
obtained and the information combined with existing  data.   The information
gathered  from  these  data  bases  will  be   analyzed,   tabulated,   and
summarized.     Data  gaps   will   be  identified  and  geothermal   facility
owners/operators  will be  contacted  to  fill   in  these  gaps.  RCRA  3007
questionnaires and  field sampling  may  also be  required,   if  appropriate.
The  Petroleum  Equipment  Supplier's Association has  also agreed  to provide
data to assist in the calculation of waste volumes.

    The  outputs  from the  review will be  (1)  an  up-to-date listing  of
active  and  planned  geothermal  power and direct  stream users;  (2) an
analysis of  the  amount and quality of  waste  characterization,  treatment,
and  disposal information  available for  each facility or geothermal region;
and  (3) a firm estimate of additional data required.

    Following EPA review and approval of area  selection,  drillers, owners,
and  operators  in  each area will be contacted either by  letter or telephone
to request their voluntary cooperation  with this program.  The goal  is to
find a few  operators  in each area  who  would be willing to provide process
details, waste characterization and allow site  sampling, if necessary.

    Once industry contact has been established, data from each  site  will
be collected and an  assessment will be  made  as to the necessity of  site
                                   II-2-20

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visits and waste  sampling.   If laboratory work is required, a sampling and
analysis  plan will  be prepared  and  arrangements  will  be made  for  the
actual sampling and  analytical work to be conducted.   Use  will be made of
similar  existing  sampling  and  analysis  plans,  where  appropriate,  to
expedite the work.

    Engineering studies will  then be conducted, where necessary, to define
and evaluate  alternative  disposal methods,  and to  review and  analyze  the
results   of   the   field   studies.    Concurrent  with   the   field  survey
activities, a preliminary list of alternative waste disposal options  will
be  prepared.   The  sources of these  options  will  be  the  literature  and
engineering judgment.
                                  II-2-21

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                                  CHAPTER 3

                              WASTE MANAGEMENT

    Although the  treatment  and disposal methods for wastes from geothermal
operations are not  well documented in  the published literature,  there  is
some  consistency in  the reported methods.   For example,  the  literature
reports  that  most  geothermal   wastewaters   are  reinjected   into  the
geothermal field (USDOE, 1982;  USEPA,  1978).  At the  Geysers reinjection
into  the same  formation was  started  in 1969.   Billions of  gallons  of
geothermal  brine  effluents  have  been  reinjected  since  then.   Cooled
geothermal  effluent  when   reinjected   back  into  the   same   formation,
scavenges heat from the reservoir rock matrix and may  be withdrawn again.
Steam condensate that is reinjected may be withdrawn again as  steam.   This
reinjection process provides  for a  higher  recovery  rate  of the  stored
heat,  helps   prevent   subsidence,  and   helps   maintain   the   reservoir
pressure.  Air  emissions  are not addressed in  this  report,  but will  be
discussed in the draft Report to Congress.

    Old production wells may be converted to use as injection wells  or new
wells  may be  drilled.   Injection can  be accomplished  by gravity  alone
because of the  higher gravity head  of the  cooler and denser  wastewater,
but pumps are  usually  provided.   The efficiency of the injection operation
is  highly  dependent   on   the   physical,  chemical,  and  thermodynamic
characteristics  and interrelationships  of  the wastewater, as well  as the
reservoir fluids and rocks.
                                   II-3-1

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    Pretreatment  may  be  required  before  injection  to  prevent  silica
plugging,  scaling,  and  pipe  corrosion.   Generally,   the  pretreatment
involves   settling,   coagulation,   clarification  and   filtration.    The
addition of corrosion or scale inhibitors may also be required.

    Most of the available treatment  and disposal data are old and will be
updated.    A  data   search  is   being   undertaken  to   identify  waste
characteristics that  will  provide  data  on treatment/disposal  processes.
This  information  will  be combined  with the existing  data and  data  gaps
will be identified.

    Where  data gaps  exist,  current information will be  solicited first by
telephone  and  then,  if necessary RCRA  3007 questionnaires  will  be sent to
selected operations.   If field  sampling of wastes  is required,  then  data
will  also  be  requested  on both current  treatment/  disposal practices and
alternative treatment/disposal processes.

    Some   information   is  available   on   alternative   treatment/disposal
processes.   Many  of  these alternative  processes have  been  field tested.
Existing data  on the  effectiveness  of  these  processes will  be evaluated
and compared to engineering studies to  establish viable alternatives.
                                    II-3-2

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                                  CHAPTER 4

             COST OF CURRENT AND ALTERNATIVE DISPOSAL PRACTICES


    The  literature contains  some outdated  cost  estimates  for  treatment
processes that were  in use during the  late  1970s.   Much of these data can
be  inflated with  appropriate  indices  in  order  to obtain  current  cost
estimates  for  those  particular treatment/disposal  processes  represented.
The Agency  is  in the process of  reviewing  additional literature  that  has
been  collected   to   locate  more  recent   estimates  for   these  current
processes.  In addition to these published sources of data,  a  small sample
survey will  be conducted  to obtain up-to-date  data on  current  treatment
and disposal practices.  This survey will seek cost  data (both investment
and  operations/maintenance)  on  these  processes.   These collection  cost
data will provide the basis for estimates of current waste practice cost.

    In order to  compare  various  alternatives,   a  cost  estimate will  be
derived for  each  individual process  or practice.  It is  important to know
the cost  of  both current and alternative treatment  processes  so  that  the
incremental  cost  of  any  new treatment  processes  can  be  evaluated  when
economic impacts are calculated.
                                     II-4-1

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                          DEVELOPMENT OF ESTIMATES

    There are  several  methods for preparing cost  estimates.   Selection of
a  method to  be  used  depends  on  the  amount  of  detailed  information
available and  the accuracy desired.  The following  list  briefly describes
the primary  cost estimating  techniques,  any of  which could  be the  most
appropriate,   depending  upon  design  constraints  and  guidelines  of  a
specific project.

Bottom-up Technique

    The  bottom-up  approach  to  estimating,   also   called  the  detailed
take-off  technique,  requires  a detailed definition of all  the equipment
and  material  needs  for a given  project.   This  explicit itemization is
accomplished  through  the   use of  completed  drawings,  flow  sheets,  and
specifications.   Equipment cost  data  are  generally  obtained from  firm
equipment  bids  based  on  detailed  purchase   specifications.   Costs  for
engineering,   supervision,   installation,   etc.,   are   determined  using
accurate   labor   rates,   employee-hours   standards,   and   productivity
assumptions.   These costs are accumulated from the "bottom  up"  to  obtain a
total cost estimate.  Accuracy  is usually 10 percent.

Parametric Technique

    Parametric  estimating  requires  historical  data  bases  on  similar
systems or subsystems.  For example,  costs may  be  estimated for a  proposed
facility  by  finding correlations among projects completed  in the past  that
use  similar design or performance  parameters  (known as  cost  drivers) in
addition  to  using  the same  or  similar  equipment items.   The   analysis
produces  cost  equations or cost estimating  relationships that can be  used
individually or  grouped  into  more  complex models.   Accuracy is usually
within an order  of magnitude  for estimates of this types.
                                      II-4-2

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Specific Analogy Technique

    Specific analogies  use the  known  cost of a prior  system  as the basis
for estimating the cost of  a  similar new  system.  Adjustments  are  made to
known  costs  to  account  for  differences  in  relative  complexities  of
performance, design, and operational characteristics.   Accuracy is  usually
+30 percent.

Cost Review and Update Technique

    The  cost  review  and  update  estimate  is  constructed  by  examining
previous estimates  of the  same or  similar projects  for internal  logic,
completeness  of  scope,   assumptions,  and  estimating  technology.   The
estimates are then updated to reflect the cost impact of  new  conditions or
estimating approaches.  Sometimes  a contractor efficiency index is derived
by comparing originally projected contract costs to  actual  costs  on  work
performed to date.   The  index is used  to  adjust the cost estimate of work
not yet completed.  Accuracy is usually +5 percent.

Factored Cost Technique

    Factored cost  estimating incorporates  elements  of several  estimating
techniques  including portions  of  those  previously discussed.  The first
step  in  factored cost  estimating  is  to  develop  an  equipment list  from
process  flow diagrams or engineering drawings.  Costs  for major equipment
items  are  collected  from  various  data  sources such  as  vendor  quotes,
equipment  catalogues, and  recent  prices  for the  same or similar items.
The total  equipment  cost  is then used  in  determining the add-on costs of
installation/erection,  piping,   instrumentation,   insulation,   electrical
system,  and  engineering.    These  add-on  costs  are   calculated  as  a
percentage  (based on extensive  historic experience) of the total equipment
                                     II-4-3

-------
costs  and   vary  depending   on   the  process   involved,   difficulty  of
installation, design complexity, past  experience, etc.  This results  in a
total direct  plant cost  to which  indirect costs such as  the contractor's
fee  and  contingency  costs  are  added.   Fee and  contingency  costs  are
usually estimated as the percentage of the total  direct plant cost.

    It is anticipated that  all but the bottom-up technique  may be used to
derive estimates  for  alternative  geothermal  treatment  processes.   It  is
not believed  that detailed  drawings  will be available  in order  to permit
use of  this more  costly and  time-consuming  estimating approach.   It  is
likely that many  of  the estimates  will be updates of previous estimates or
analogies.   Some   parametric  estimating   relationships   exist   in   the
published data, and these are also likely to be used for certain processes.

    Each  estimate  will  be normalized to  account  for  inflation,  geographic
location, geothermal production rate,  and similar factors that might  tend
to  skew  a comparison between  existing  and  alternative practices.   Similar
cost estimate categories will  be used  so that the same  adjustments can be
made  to  financial   statements   in  order  to  determine   total  economic
impacts.  At a  minimum, costs will be  broken into capitalized  investment
costs and annual operations maintenance costs.
                                     II-4-4

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                                  CHAPTER 5
      ECONOMIC IMPACTS OF ALTERNATIVE METHODS OF TREATMENT AND DISPOSAL
    An  economic  impact  assessment  analysis  will  be  conducted in  future
work  on  a  facility-by-facility  basis.   This  assessment will  encompass
evaluation of  impacts on production  costs, profitability, and liquidity.
In  addition, an  analysis of  the  impact  on  plant profitability and the
likelihood of  plant  closure  will  be made  using  computerized discounted
cash  flow techniques.   As  a  last  step,   small  business  and  community
impacts  will  be  calculated.    In  order   to   account   for   uncertainty,
sensitivity  studies   will   be  conducted   wherein  major variables  and
assumptions will be varied to assess the impact.

    The  economic  impact  analysis  will  begin  with   a  definition  and
description  of  the  industry.   This  industry description  will  include
geographic  locations,  production  levels,   income,  prices/rates,   product
volumes,  employment levels,  production  costs,  and  profitability  figures.
Product differentiation, substitution,  demand elasticity, and  barriers  to
entry also will be  evaluated.   Much of the data necessary for the  industry
description  is  currently available,  but  needs validation  and  updating.
Since several  of  the  facilities  will be  experimental,  the data  reported
may  vary  from  facility to  facility.    This  descriptive material  will
establish a baseline case for each facility.
                                   II-5-1

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    An  economic  impact  assessment consists  of a  comparison  of  current
financial measures, in which  the cost of current waste treatment processes
is  reflected,  with  pro  forma  financial  measures   in   which  selected
alternative  waste  treatment   options   are  substituted.    The  financial
measures  will  include  production  costs,  profitability,   and  liquidity.
Ideally,  these financial  comparisons will  be  conducted  at the  facility
level  so that  the economic  impact  on  the  geothermal  facility  can  be
isolated  and  quantified.   Financial  data  will be   obtained   from  State
Public  Utility Commissions (PUCs).   Regulated utilities are  required  to
file   periodic  statements  with  the   PUCs,   which   contain  information
regarding production  costs, taxes, profits,  assets,   and  other financial
data.   These  data  will  be gathered for each geothermal electric generation
production facility and for each regulated heating district.  The  PUC data
will form the baseline case that reflects current disposal  practices.

    The  cost  of disposal  practices  evolving  from  the cost  analysis will
provide  both  capital  investment and operations/maintenance costs  for both
existing and  alternative  waste  treatment/disposal systems.   The impacts of
the  existing  treatment/disposal  systems  will  be  subtracted  from  the
baseline  financial  data,   and  the cost of  removing  the  old  system  and
installing and operating the new system will be added.  The  impact of this
change  will be  reflected in a mills/kwh or  similar  measure  that can be
compared to  the  estimated cost of  alternative energy.   The impact  on
profitability  as  the  final  step of  determining  the economic impacts,  a
closure  analysis  will  be conducted wherein the current liquidation  value
of  the facility  is  compared to  the  present values of cash  flow over the
remaining life of  the facility.  From this  closure  analysis,  the impact on
employment, small  business, and the community can be estimated.
                                    II-5-2

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                                BIBLIOGRAPHY
Armstead, Christopher H.  1983.  Geothermal Energy:  Its past, present and
future contribution to the energy needs of man.  2nd ed. London:  E and FN
Span.

Chilinger, G.V., L.M. Edward, W.H. Perth, and Rieke. III. eds. 1982.  The
Handbook of Geothermal Energy.  Houston, Texas, Gulf Publishing Company.

DiPippo, R.  1985.  Worldwide Geothermal Power Development.  EPRI Annual
Geothermal Meeting.  San Diego, California.

Energy Development.  EPA-600/7-78-101.  Cincinnati, Ohio.  U.S.
Environmental Protection Agency.

Environmental Aspects, Livermore, California:  U.S. Department of Energy.

USDOE.  1982.  U.S. Department of Energy.  Survey of Geothermal Solid
Toxic Wastes.  San Francisco, California.

USEPA.  1983.  U.S. Environmental Protection Agency, Office of Research
and Development, Industrial Environmental Research Laboratory.  Analysis
of Geothermal Wastes for Hazardous Components.  NTIS  P893-18860.
Cincinnati, Ohio.  U.S. Environmental Protection Agency.

USGS.  1979.  U.S. Geological Survey.  Assessment of Geothermal Resources
of the United States.  Circular No. 790.  Washington, D.C.:  Federal
Printing Office.
                                  II-Bib-1

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        Partm
Damage Case Assessment

-------
                                 CHAPTER  1

                                INTRODUCTION
    Section 8002(m)  of the  Solid Waste Disposal Act, as  amended  in 1980,
requires EPA to conduct a  detailed and comprehensive study of  the adverse
effects,  if any,  of  drilling  fluids, produced  waters,  and other  wastes
associated  with  exploration,  development,  or  production of  crude  oil,
natural  gas,   or  geothermal  energy.   As  specified in  the  Act,  adverse
effects may include, but are  not  limited to, effects of  wastes  on humans,
water,  air,  health, welfare, and natural resources.  The study must also
review  the  adequacy of means and measures currently employed by  the oil,
gas,  and  geothermal  drilling  and  production  industries to  prevent  or
substantially mitigate such adverse effects.

    The most  direct method  for  meeting  this  requirement for  estimating
possible  damages  is through  the  use of documented  damage cases;  Congress
has therefore  directed EPA,  under Section 8002(m)(D)  of  RCRA,  to develop
such  damage case  data.   A  second method proposed  by EPA for  estimating
damage is through the use of risk assessment (described in Part IV of this
report).   The  two  approaches   are  independent,   but   are   intended  to
complement  and corroborate each  other.   Data developed  under  the  damage
case review for this project will not be  used as input  to risk assessment
models or methods.
                                   III-l-l

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    This  part  of  the report  deals with  EPA's  proposed methodology  for

gathering  damage  case  data  in  a  comprehensive,  structured,  and  fully

documented manner.   The  methods  described  below to gather,  document,  and

interpret damage case data  are simple and straightforward.   EPA's  overall

goal is  to develop  a compendium of  available  information on the incidence

of environmental contamination or damage,  both  actual  or suspected,  that

may be caused by the disposal of wastes from the subject industries.


    Although it is  impossible  to determine  precisely what types of adverse

impacts  are  caused  by  oil,   gas,  and  geothermal  operations   before

completing  the  damage   case  review,   the  general  categories  of  damage

expected are as follows:


        Human health effects  (acute  and chronic).   While  there  may  be
         instances where contamination  has  resulted  in documented cases of
         acute adverse human health effects,  such cases are  expected  to be
         rare.    Levels  of  pollution  exposure  caused by  oil,  gas,  and
         geothermal operations are  more  likely to be in  ranges  associated
         with  chronic  carcinogenic  and non-carcinogenic  effects.    The
         damage case study will therefore seek to document  instances  where
         operations result  in  levels of exposure associated with potential
         long-term chronic  effects, rather than attempt  to document  the
         adverse effects  themselves.

        Environmental  effects.    This  type  of  damage   would  include
         impairment   of   natural   ecosystems   and   habitats,   including
         contamination  of  soils,  impairment  of  terrestrial  or  aquatic
         vegetation, or  reduction of the quality of  surface waters.

        Effects  on  wildlife.    This  would   include   impairment   to
         terrestrial  or   aquatic  fauna; types  of  damage  could  include
         reduction in species' presence  or  density,  impairment of  species
         health  or   reproductive  ability,  or  significant   changes   in
         ecological relationships.
    If  necessary,  the  approaches  described  below  may  be  modified  or
    expanded over the course of the  project  in order to support  this  goal
    or in response to comments received on this initial  report.
                                   III-1-2

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    Effects on  livestock.   Damage  in this  category  would  include
     morbidity   or  mortality   of   livestock,   impairment   in   the
     marketability of livestock,  or any other adverse  economic  impacts
     on livestock.

    Impairment  of  other  natural  resources.    This   category  could
     include  contamination of  any  current  or  potential  source  of
     drinking water, disruption  or lasting impairment  to  agricultural
     lands  or  commercial  crops,   impairment  of  potential  or  actual
     industrial use of  land,  or  reduction  in current or potential use
     of land.
                              III-1-3

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                                 CHAPTER 2
                    APPROACH FOR COLLECTING DAMAGE CASES


    The  proposed  approach  for  collecting damage  case data  involves  four
separate  activities:    (1)  specification  of  information  types  required,
(2) identification of case  study information sources, (3) specification of
procedures  for  collecting  data,  and  (4) specification  of  criteria  for
classifying cases.  Each activity is discussed separately below.

                SPECIFICATION OF INFORMATION TYPES REQUIRED

    The  initial phase of  the damage case study will  identify the types of
information necessary for  fulfilling  the  directive of  Section  8002(m)(D).
The  types  of  information  EPA  plans  to gather will  also  support  the
Agency's  assessment  of   potential   danger  to   human  health  and   the
environment from surface runoff or leachate required in Section 8002(m)(C).

    The  information to be collected for each incident includes:
         Characterization  of  specific  damage  types.   This will  involve
         identification of the environmental medium or media involved,  the
         type of  incident,   and a characterization of actual  or suspected
         damage.
                                   III-2-1

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         The size  and location of the site.   Each  site's  location will be
         noted,  especially for  its  hydrogeological   and  other  pertinent
         environmental factors.

         The  operating status  of  the  facility  or site.   A notation  of
         whether the site is active or inactive will be made.

         Identification  of  the   type  and  volume  of  wastes.   For  each
         incident,  EPA will  characterize  the  types  and  volumes  of  oil,
         gas,   or  geothermal   wastes    involved.     This   will   include
         identification of  constituents  and  constituent  concentrations  in
         the wastes associated with the contamination or damage.

         Identification of waste management practices.  For  each incident,
         information   is   required  on  the   types  of   waste  management
         practices causing or contributing to the contamination or damage.

         Identification of  any pertinent  regulations  affecting the  site.
         These  could  include  local.  State,  or  Federal  rules  governing
         environmental   releases,   health   and   safety   requirements,
         production restrictions, or any other relevant factors.

         Type  of  documentation  available.   For  each  case,  the nature  of
         the  available documentation  must  be  noted.   This  may  include
         environmental  monitoring data,  site inspection  reports,  records
         of    citizen    complaints,    litigation,    enforcement-related
         information  for a  local. State, or Federal rule  violation,  court
         records, or records of administrative decisions.
              IDENTIFICATION OF CASE STUDY INFORMATION SOURCES


    The  next  phase  of this  effort will be  to identify  a  full range  of
potential sources of damage case information.


    Although  oil,  gas,  and  geothermal  operations   exist  in  33  States,

98 percent of the 1985 drilling  activity and 97 percent of  all  producing

wells in the United States lie within 21 of those States.  Because  of  time

and resource  limitations,  EPA will  restrict its damage case  study to these

21 States  (see Table  III-l).  Furthermore,  no attempt  will  be made  to

conduct  a  complete   census   of   all  known  damage  cases,   current   or
                                  III-2-2

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Table III-l.  List of States  from Which
             Case  Information Is Being
             Assembled
        1.  Alabama

        2.  Alaska

        3.  Arkansas

        4.  California

        5.  Colorado

        6.  Illinois

        7.  Kansas

        8.  Kentucky

        9.  Louisiana

       10.  Michigan

       11.  Mississippi

       12.  Montana

       13.   New Mexico

       14.   North Dakota

       15.   Ohio

       16.   Oklahoma

       17.   Pennsylvania

       18.   Texas

       19.   Utah

       20.   West Virginia

       21.   Wyoming
            III-2-3

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historical,  within these States.   Rather,  EPA  will seek  to  construct  a
representative  sample of  cases  based on  criteria  presented  in  the next
subsection (see below).
Sources  of  information  relating  to the selected  States  will include, but
are not necessarily limited to:

        Relevant  State  or  local  agencies.   These  will  include  State
         environmental  agencies,  oil  and  gas regulatory  agencies.  State,
         Regional,  or local  departments  of  health,  and  other  agencies
         potentially knowledgeable about damage cases.
        EPA Regional Offices.
        U.S. Bureau of Land Management.
    *    U.S. Forest Service.
    *    U.S. Geological Survey.
        Professional or trade organizations.
        Public interest or citizens'  groups.

An  attempt  will  be  made  to  contact  as  many   potential   sources  of
information  as  is possible in  each of the  21 States to  be  surveyed.   All
information  collected,  from whatever  source  (Federal,   State,  or  local),
will  be  furnished to  appropriate  State  agencies  for  review  prior  to
incorporation in this study.
               SPECIFICATION OF PROCEDURES FOR COLLECTING DATA

    The  third  phase of the study  will  be  to select an appropriate  sample
of  cases  from  the  range  of  those  uncovered  by  contacts   with  the
organizations  listed  above.   Documentation will  then be gathered on this
sample.
                                   III-2-4

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    Criteria  have  been  established for  guiding detailed  data  collection
efforts.   Cases selected for investigation will emphasize:
    1.   Recent cases.   Cases that  have  occurred  recently  are the  most
         likely to reflect current waste management practices.

    2.   Cases  that  illustrate   clear   relationships  among  environmental
         damage and  specific  waste management  practices.   Such  links  may
         best  be  documented  where   scientific investigations  have  been
         conducted at the involved sites.

    3.   Cases where the  most significant levels of damage have occurred.
         The Agency  will  seek to document as wide  a  range of damage types
         as possible (see above).

    Once sample  cases  have  been  selected for  investigation,   the  Agency
will  attempt  to develop  as  much documentation as  possible for  each case.

This will include:
      Site  investigation  reports performed by State agencies  in response
       to citizen complaints;

      Inspection reports of unsatisfactory waste management;

      Follow-up site investigations, memoranda, and reports  on individual
       sites;

      Special studies performed  on  local  or Regional  issues  that describe
       specific sites' problems;

      Testimony  of  expert   witnesses    in   administrative   or   court
       proceedings;  and

      Compliance   orders    or   other  administrative   directives,   with
       supporting documentation, issued by State enforcement offices.
    EPA  believes  that   these   materials   will  contain  the  information

required to satisfy Congress's  directives,  but will also  review any  other
available, appropriate information.
                                  III-2-5

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               SPECIFICATION OF CRITERIA FOR CLASSIFYING CASES

    The final  step of the damage  case review project will be  to classify
the collected  damage  cases and  subject them to  a  test  of proof.  For  the
purpose of  this  study,  EPA will consider that  a case has met  the test of
proof if the damage,  as  defined  above, is documented and is  determined to
have  been caused  by oil,  gas,  or  geothermal  operations  (1)  through  the
conclusion  of  a   scientific   investigation  of   the   case,   (2) by   an
administrative ruling, or (3)  by court decision.

    Cases that  fail to meet the test  of  proof  will not be discarded,  but
will be retained  to furnish  additional background  information  relevant  to
other needs of this study.
                                   III-2-6

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                                   CHAPTER  3


                       APPLICATION OF DAMAGE CASE RESULTS



    EPA  intends  to  use  the  information  contained  in the  damage  cases  to

support  the  assessment  of  the  potential  danger  to  human  health  and  the

environment.  EPA  plans  to present  descriptive information from these  cases

illustrating  empirical  relationships among damage  types and particular types

of wastes,  particular  environmental  contexts,  and particular waste  management

processes.


    In addition,  summary data will be cross-referenced by:


      Damage type.  (As discussed above).

      Waste  type.  This will  include consideration of the  physical, chemical,
       and toxicological characteristics of wastes.

      Environmental   setting.    Information    will   be    referenced,    as
       appropriate,   by  hydrogeological  characteristics,   aquatic  features,
       meteorology and  climatic  regime  (e.g.,  proximity  of site  to  surface
       water,  net  infiltration,  surface  and  ground-water quality and  flow
       velocity), and any other relevant environmental factors.

      Exposure.   Information will be referenced, as  appropriate, to important
       human  or  ecological  exposure pathways  (e.g.,  proximity  to public  or
       private drinking  water  wells or  surface water intakes,  exposure  to
       agricultural crops or through food animals,  etc.).
                                     III-3-1

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    The Agency  wishes to  emphasize  that these data on damage  estimation will
be compiled independently to the risk assessment.  None of the data  gathered by
this  effort  will  be directly  used  in  the  modeling analysis  (see Part  IV,
following).  The basic goal of this effort is to  compile  empirical  descriptive
data on the  existence of damages associated with exploration,  development,  and
production,  to  characterize as  representatively as  possible  the  nature  and
extent of these damages,  and to link causes and effects to the  extent feasible.
                                    III-3-2

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     Part IV
Risk Assessment

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                                 CHAPTER 1
                                INTRODUCTION


    Section 8002(m)  of  the Solid Waste  Disposal  Act, as amended  in  1980,
requires EPA  to conduct a  detailed and  comprehensive  study of  drilling
fluids,  produced  waters,  and other  wastes  associated  with  exploration,
development,   or production  of  crude  oil,  natural   gas,   or  geothermal
energy.  Section 8002(m)(1)(C) directs EPA  to analyze the potential danger
to  human  health  and  the  environment  from   surface  runoff  or  leachate
resulting  from  these  activities.    This  part   describes  the  proposed
approach  for  a risk  analysis  to  fulfill  the  requirements  of  Section
8002(m)(l)(C).  The approach  is  applicable  to both oil  and gas  operations
and geothermal energy operations, although the input data for  the  analysis
will differ for the two industry categories.

    The  objectives  of  the  risk analysis  are  to   (1)  characterize  and
classify the  major  risk  influencing factors  (e.g.,  waste  types,  disposal
technologies,    environmental   settings)   associated  with   current  waste
management practices  at  oil  and gas  and  geothermal energy  facilities;
1  In  this  part  all  references  to  oil  and  gas  and geothermal  energy
facilities  or  sites  refer  to  exploration,  development,  and  production
operations.
                                   IV-1-1

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(2)  estimate  distributions  of   risk  influencing  factors  across   the
population  of  facilities;  (3) rank  these  factors  in  terms   of  their
relative  risks;  and  (4)   develop  initial  quantitative  estimates  of  the
range of  baseline  health  and environmental risks for the  variety of waste
types, management practices, and environmental settings  that exist.

    To meet these  objectives, the  risk analysis  will  estimate health  and
environmental  risks  from  fully specified  model  scenarios  that  represent
the range of  wastes,  release sources,  and environmental  settings  typical
of onshore oi; and gas and geothermal  energy operations.   The Agency will
develop the model  scenarios  based  on its review and analysis  of  available
data on  actual oil, gas,  and geothermal energy  facilities,  including  the
information  obtained  from  its  sampling  efforts  (see  Part  I).   This
analysis  will not estimate  site-specific  risks  nor  will  it  produce  a
rigorous  quantitative  estimate  of national  population risks.   It  will,
however,  produce  methods,  modeling techniques,  and a  partial   data  base
that could be adapted  for that  purpose.  The proposed  risk analysis  also
will produce  initial estimates  of  health risks  and potential environmental
damages,  identification of low-risk and high-risk scenarios,  and rankings
of  major  risk influencing  factors  consistent  with  the  purpose  of  the
Section  8002(m)  requirements.   This  risk assessment  will  address  only
current  conditions  in  the  industry;  it  will  not   analyze  regulatory
alternatives to reduce the baseline risk.

    As  with  any  National  assessment  of   risk   from  waste  generating
activities,  whether  based on specific real  facilities  or  model  facility
scenarios,  many   assumptions  will   be   necessary  for   this   analysis.
Assumptions  are  necessary  for  at  least  three  reasons:  (1)   lack  of
important  data  about  waste  generating   and  management  practices   and
environmental  conditions,  coupled  with the expense of  obtaining  such data;
(2)  significant  limitations  of available  methods  for  modeling  chemical
                                   IV-1-2

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release,  transport,  fate, and  effects;  and  (3)  modeling feasibility  and
practicality,  which  are   essential  considerations  to  any National  risk
analysis  with  a broad  scope.   Any  assumptions  in  the  analysis will  be
explicit, and EPA will document them carefully in written reports.

    The  remaining  chapters  in  this  part  describe  the  proposed  risk
assessment  methodology.   The  next  chapter  gives   an  overview  of  the
approach  to provide  the   reader  with an  overall perspective.   Following
that, the  input  data  to be used in  the  analysis  are discussed  in  Chapter
3, and  Chapter 4  describes  EPA's planned  approach  to  characterizing  oil
and gas and geothermal energy facilities.  The  development of  combinations
of  release source  types,  waste types,  and environmental settings  (i.e.,
model scenarios) is discussed in Chapter  5.   The modeling techniques  to  be
used in  the  risk estimation  calculations are described in Chapter 6,  along
with the areas needing further model development and  refinement.   Finally,
Chapter  7  summarizes  the  actual  risk calculation,  which  will  follow
finalization of the model  scenarios and modeling tools.
                                  IV-1-3

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                                  CHAPTER 2
                  OVERVIEW OF THE RISK ASSESSMENT APPROACH
    Potential  health   and  environmental  risks   associated   with  waste
management activities depend on the types and  quantities of  wastes  being
managed; the  storage, treatment,  and disposal technologies being used; and
the environmental  settings in  which the waste  management activities  are
carried out.  These  factors  determine the degree to which receptors (human
or  environmental)  may  be exposed  to  harmful  constituents of the  waste
through  various   exposure  pathways.    Risk   is  estimated  by  combining
exposure information with data  on the  toxicity  of specific chemicals  and
information on the characteristics of receptor populations.

    The   following  section  summarizes   the  specific   risk  assessment
methodology to  be used  in the oil  and gas  and  geothermal energy  study.
Following this overview,  there  is a brief description of alternative  risk
assessment methodologies that were considered  for the study and rejected.
                OVERVIEW OF THE RISK ASSESSMENT METHODOLOGY

    EPA proposes  to conduct  a  generic, as opposed to  site-specific,  risk
assessment of  onshore  oil  and  gas  and geothermal energy operations.   A
schematic overview of the  approach is given in Figure IV-1.   A key part of
                                   IV-2-1

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Figure IV-1
                                   IV-2-2

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                                                       Chnractenzo
                                                       Waste Slie.im
                                                        Calo()Oiius
M
I
Review Available
Data on Wastes,
Management
Practices and
Environmental
Settings


Collect
Supplemental
Data, As
Necessary
                                                       Chaiiicteiuo
                                                       Management
                                                      Practico/Reloase
                                                     Sour co Cii
                                                        Chaiaclerize
                                                       Environmental
                                                          Soiling
                                                        Cali!(|oiics
                                                         Uuvolop
Injection Holcase
   Subroulino
                                                      Develop Surface
                                                      Walor Modeling
                                                         Subroulino
                                                          Develop
                                                       Environmental
                                                      Eflects Modeling
                                                         Subroulino
                                                       Modify Relevant
                                                      Submodels ot the
                                                            UM
                             Integrato  into
                             Fully Specified
                            Model Scenarios
Analyze Risk
Model Scciiii
for
IOS
                             Integrate into a
                             Computer  Risk
                                Model
                      FIGURE IV-I.   OVERVIEW OF THE RISK ASSESSMENT METHODOLOGY

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the generic approach  is  development and  specification of  model  scenarios
(i.e.,  hypothetical  facilities)  to  cover  the  range of  important  risk
influencing variables.  Essentially, scenarios  are unique  combinations  of
subcategories  of  important  variables  that  are  specified in  sufficient
detail  to  allow risk  estimation.   The model  scenarios for this  analysis
will  be derived  from actual  data on  wastes,  management  practices,  and
environmental settings.

    Although the model scenarios will  not  represent  individual  real sites,
they  will  represent  groups  of  similar  real  facilities  in the  analysis.
Generally,  the more one disaggregates  an analysis of  this  type  (i.e.,  the
more  variables  one considers  and  the  more subcategories they  are divided
into), the more precise the  results will be.   A  larger number  of  variable
subcategories means  that  each  subcategory can better represent a smaller
number of real facilities.  However, the  data  input  requirements,  modeling
complexity,  and analytical  requirements  also increase substantially  with
the  level  of  disaggregation.   Therefore,  the  design of  a  generic  risk
analysis such  as this must  account for  the  tradeoffs between  analytical
precision  requirements and  project  scope.   The  proposed  generic  risk
assessment  framework   provides  an  appropriate  level   of   detail   and
disaggregation to address the objectives listed in Chapter 1.

    As part of  the  model  scenario  development, the Agency will attempt  to
estimate  the  frequency   of  occurrence  of each  scenario.   For  example,
suppose that 10 percent of the facilities of interest  are  in  ground-water
category A, 20  percent in category B,  and 70  percent  in  category  C.  This
would allow the Agency to evaluate  the  representativeness of the  scenarios
and to weight the eventual risk estimation results by frequency.

    In  parallel with the  development  of model scenarios,  EPA  will  be
developing, refining,  and integrating the analytical  tools  necessary  to
                                   IV-2-3

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quantitatively  estimate  chemical  release,  transport,  exposure,  health
risk, and  environmental effects.   Existing OSW models will  be  adapted to
the extent possible,  especially the Liner Location Risk  and  Cost Analysis
Model (LLM)  (U.S.  EPA,  1985a).   The LLM is a fully computerized model that
calculates health  risks and  contaminated ground-water  volumes   caused  by
chemicals  released from land disposal  facilities.  The  LLM  was developed
primarily for  efficient  analysis of large  numbers  of  model  scenarios  (as
opposed  to   rigorous  analysis   of   site-specific  risk)   and  thus   is
well-suited to  the proposed approach.   It will, however,  need significant
supplementation in three areas:

        Estimating chemical releases from underground injection;
        Modeling chemical transport/fate in surface water; and
        Modeling   potential   environmental   effects    (other   than
         contaminated ground-water volumes).
As part  of  the oil and gas  and geothermal  energy risk analysis,  EPA will
develop  technical   approaches  to  these  three  modeling  areas,   and then
integrate them  into the LLM.  Substantial  alterations  to the LLM surface
impoundment  release  submodel  may  also  be  necessary  to   make it  more
applicable to  treatment  and disposal pits  at oil  and gas and  geothermal
sites.   The  Agency plans to use the current  ground-water transport,  human
exposure/risk,  and  plume  volume  submodels  of  the   LLM   with  limited
adaptation.

    In summary,  there  are  two major parts  of  EPA's  methodology   leading up
to  the  actual  risk calculation  step:  scenario  development  and  model
development.    Model  development  will   produce  the   analytical   tools
necessary to  estimate  quantitative risks, while scenario  development will
provide  the  model  inputs necessary to do the  risk estimation.  Of course,
these two  components are closely related.  Modeling tools are needed only
for  significant scenarios,  so  the  waste/source/setting characteristics of
                                   IV-2-4

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the  industry  largely determine  the  emphasis  in  the  model  development
effort.   Likewise,  the  specific equations  selected  as  analytical  tools
dictate  the  variables  that  must  be  specified within  scenarios.   For
instance,  a  complex  ground-water  model  with   substantial   input  data
requirements   would  necessitate   a  much   greater  level   of  scenario
specification  than  a  simpler model.   Thus,  the  two key  parts  of  the
approach should be viewed as complementary.

    The  final  step in  the methodology is actually  analyzing  risks  of the
scenarios using the modeling tools  developed.   In  particular,  the  Agency
will   estimate  incremental  chronic  human   health  risks   (cancer  and
noncancer),  that  is,  those  effects due  specifically  to  exposures  to the
waste  constituents  being assessed,  exclusive  of  background  exposures, and
also the environmental damages for each realistic  scenario.  There  will be
no attempt  to  factor  background exposures into the  risk  estimates  as part
of this analysis.
                    ALTERNATIVE METHODOLOGIES CONSIDERED

    EPA  believes  that  a generic  risk  assessment as  described  in  this
section  of the  report  will  satisfy  the  requirements  of  Section 8002(m)
(1)(C),  which directs  EPA to  analyze the "danger  to human health and the
environment from surface  runoff or leachate" from oil and gas and geother-
mal  exploration,  development,  and production  activities.  Section 8002(m)
(1)(C) does  not  stipulate that  quantitative  risk  estimates  be developed,
nor does it  require a  site-specific  assessment.  The Agency believes that
the proposed generic methodology, which will incorporate  available data on
the  industry  but  will  not  require   extensive  new  data  gathering,  can be
used to  assess risk on an overall National basis and to  identify patterns
of  risk  relative  to  a number of important risk  influencing factors.  In
                                   IV-2-5

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addition, this  study should provide preliminary quantitative  estimates  of

individual risks and  certain  types of environmental  damage,  which  can  be

refined with additional data collection.


    EPA  considered  and  rejected  several  other  methodologies  for  this

study.  The principal alternatives and the reasons these  methodologies are
not being proposed are:
    *    Detailed   exposure   and   risk  analysis   of  a   statistically
         representative sample  of actual sites.   This  type of  analysis
         would probably  provide the most  reliable results, but  it would
         be  impossible  to carry  out  at this  time  because of  extensive
         gaps in the  available  data.   A comprehensive, site-specific risk
         analysis of  a representative  sample  of  sites  would  be  a  very
         large project  even  if all  necessary input  data were  available.
         Therefore,   this  alternative  was   rejected  because   sufficient
         site-specific  input   data  are  not  available   and   would  be
         extremely time-consuming and expensive to collect.

    *    Worst-case  exposure  and  risk analysis  of  a sample  of  actual
         sites.   This  type of  analysis would be similar to  that described
         above,  but many  site-specific parameters would be set  based  on
         conservative  assumptions.   It would still  require an  extensive,
         site-specific  data   collection  effort,   and  the   worst-case
         assumptions  would blur distinctions that may exist among sites.
         Risk estimates   tend  to  converge   in  these types  of  studies,
         making  it   more  difficult  to  assess  the  effects of  important
         factors such as waste type or hydrogeology on risk.

        Detailed case study of a few sites.   This type of  analysis would
         provide reliable information on five  to ten sites,  but  is  too
         narrowly  focused to  meet  the  needs  of  Section  8002(m)  and
         therefore  was   rejected.   Case   studies  would  not   give  any
         information  on the  range or pattern of  risks across  the  Nation
         as a whole.

The  Agency believes  that the  proposed generic  approach  best meets  the

needs  of  the  Section   8002(m)  study.   It  will  incorporate  available

industry data on wastes,  management practices, and environmental settings,

but will not require massive field data collection for specific  sites.
                                   IV-2-6

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                                 CHAPTER  3
                         INPUT  DATA FOR  THE  ANALYSIS
    This  chapter identifies  the major  data  inputs  needed  for the  risk
analysis and the anticipated sources for these data.  A  comprehensive  risk
assessment  requires  the  availability of  substantial amounts  of  data  on
wastes, releases, and settings.  To illustrate this point, Table  IV-1  is a
partial  list  of data that would be useful for this assessment  of  oil and
gas  and  geothermal   energy  operations.    Table  IV-1   also   identifies
potential sources for  many of the key data  elements.  Acquisition  of some
of these  data  elements is beyond the scope  of this project, however,  and
EPA plans to  make  assumptions where necessary to  supplement  the available
data.

    Much  of  the  information  necessary  for  risk  assessment  is  being
collected, at  least  in the form of raw data, in other parts of the  Section
8002(m)  study.   In particular,  EPA  is  gathering  and  analyzing  relevant
data on  the  numbers  and locations of facilities in the  industry, types and
volumes  of  wastes  generated,  physical  and  chemical  characteristics  of
significant  waste  streams,  and  current waste management practices.   The
Agency will  rely largely on  these  data in  developing  model scenarios  to
represent the  industry.   Thus, the risk assessment itself involves little
primary data collection in areas of wastes  and release sources.   A  limited
research  effort  to  characterize the environmental settings of  oil  and gas
                                   IV-3-1

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02032 Risk Assessment
           Table IV-1.  Oil and Gas and Geothermal Energy Development
                        and Production Risk Assessment:  Potential
                        Data Needs and Sources
                                                                   Potential
                   Data element                                   data source
  I.     Production site/waste management system

    A.   General

       * 1.   Location of sites                                        a
         2.   Size, shape of sites                                     a
       * 3.   Description of waste management system components        b
       * 4.   Downgradient distance to site boundary                   a
         5.   Surrounding land uses                                    a,d,
         6.   Operating period                                         a

    B.   Surface impoundments (pits)

       * 1.   Number/types of pits                                     a,b
       * 2.   Size, shape, depth, residence time, annual flow          b
         3.   Subgrade permeability, clogged layer permeability,       b,f
              and thickness
       * 4.   Basic design features (e.g., liners/liner                b
              permeability, leachate collection, leak
              detection, cover)
       * S.   Effluent discharge rate/point                            b
         6.   Monitoring plan/data                                     b
         7.   Closure and post-closure care practices                  b

    C.   Underground injection

       * 1.   Number/types of injection wells                          a,b
         2.   Size of well/injection volume                            b
       * 3.   Basic design features                                    b
       * 4.   Discharge depth                                          b
         5.   Monitoring plan/data                                     b
         6.   Closure and post-closure care practices                  b

    D.   Other  potentially significant waste management                b
         system components (e.g., land application, storage tanks)
                                   IV-3-2

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0203Z Risk Assessment
                            Table IV-1.  (continued)
                                                                   Potential
                   Data element                                   data source
 II.     Wastes (drilling muds, brines)

       * A.   Total volume and volume per well                         a,b
         B.   Volume per unit of production                            a,b

       * C.   Chemical constituents and their concentrations           c
              inorganics, including metals
              organics

       * D.   Physical characteristics of the waste stream             c
              solids (total and suspended)
              density

       * E.   Treatment/disposal sequence and process description      b

         F.   Physical/chemical and toxicity characteristics of        e
              chemical constituents
              partition coefficients
              degradation rates
              solubility
              toxicity parameters (e.g., threshold, potency)
              bioaccumulation factors

III.     Environmental Setting

    A.   Hydrogeology                                                  e,f

         1.   Ground-water flow direction
       * 2.   Ground-water velocity
       * 3.   Depth to ground water (water table)
         4.   Hydraulic conductivity
         5.   Porosity
         6.   Gradient
         7.   Fraction organic carbon (foe)
         8.   Bulk mass density
         9.   Subsurface stratigraphy (number of layers, depths)
         10.  Soil type (of each layer)
         11.  Ground-water quality data
         12.  Seismicity
                                   IV-3-3

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0203Z Risk Assessment
                            Table IV-l.   (continued)
                                                                   Potential
                   Data element                                   data source
         13.  Fractures/faults
         14.  Hydraulic connections between injection zone
              and surface aquifers
         15.  Ground-water class
         16.  Other (e.g.. unusual ground-water conditions)

    B.    Surface water                                                 f,g

       * 1.    Distance/direction to surface water bodies
              (from site)
       * 2.    Type of surface water (perennial  stream,  river,
              lake)
         3.    Streams
            *    Flow rate
                   Size (width,  depth)
                   Downstream system description (what  it
                   flows into, where)
         4.    Lakes
            *    Size (width,  length,  depth,  volume)
                   Turnover rate
         5.    Surface water quality data
         6.    Use classification

    C.    Meteorology                                                   e,f

         1.    Precipitation, net infiltration
         2.    Severe storm frequency
         3.    Flooding frequency of site

    D.    Potentially exposed populations

         Ground water  human                                         f,h

       * 1.    Distance to nearest downgradient  well(s)
         2.    Number of downgradient wells within 5 miles
       * 3.    Site vicinity (USGS) map with well locations
         4.    Public/private designation
         5.    Water supply fraction
         6.    Well depth
                                   IV-3-4

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0203Z Risk Assessment
                            Table IV-l.  (continued)
                                                                   Potential
                   Data element                                   data source
         Surface water  human                                        f,g,h

       * l.   Distance to nearest intake/each surface water
         2.   Distance to all downstream public supply intakes
       * 3.   Use of each intake (e.g., public supply, irrigation)
         4.   Water supply fraction
         5.   Other significant point sources nearby

         Surface water -- ecological                                   f

         1.   Ecosystem description
         2.   Sensitive species/critical habitats
* Key data element for proposed methodology.

a.  Current EPA research on sources and volumes of wastes that is being
    conducted as part of the Section 8002 study.

b.  Current EPA research on waste management practices that is being conducted
    as part of the Section 8002(m) study.

c.  Current EPA waste stream chemical analysis that is being conducted as part
    of the Section 8002(m) study.

d.  EPA damage case studies that are being compiled as part of the Section
    8002(m) study.

e.  LLM data bases (supplemented with additional chemicals, if necessary).

f.  Mapping and literature surveys correlating site locations with
    environmental  variables.

g.  USGS (e.g.. REACH files)  and EPA (e.g.,  STORET) surface water data bases.

h.  Population and drinking water data bases (e.g., GEMS, FRDS).
                                   IV-3-5

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and geothermal  energy facilities  will  be conducted  at a  level  of detail
consistent  with  the  waste  and  release  source  data  and  the  modeling
techniques.   Some directly applicable  environmental  information,  such as
maps   of  net   infiltration   categories   and  locations   of   sensitve
environmental settings, has been  developed and used  in  recent  projects by
EPA and is readily available.

    One  other  significant  source  of  information  useful  to  the  risk
assessment is the  compilation  and analysis of  damages  attributable to oil
and  gas  and  geothermal  energy  facilities.   The  damage  case  summary
currently  being  conducted as  part  of  the  Section  8002(m)  study  will
provide  information  on the types and  severity of damages attributed  to
past  releases  of contaminants  from  these  facilities.    It  should  also
provide some information on the kinds of wastes, chemicals,  and management
practices  involved, as well as whether the  release was  intentional (e.g.,
permitted  effluent) or a  result of technology  failure.   EPA plans  to use
information  from the  damage  case reports  to  identify  important  exposure
pathways,  especially  in  the area of  environmental  (non-health)  effects,
and  to  confirm  that  its final  methodology  addresses these  significant
pathways.  The  analysis  will  not eliminate  consideration of  potentially
important  pathways simply  because they are not frequently  reported in the
damage cases; one would not expect pathways  with hard-to-measure  endpoints
(e.g.,  health   effects   of   chronic  exposures,   ecosystem-level  aquatic
effects) to be reported frequently.
                                   IV-3-6

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                                 CHAPTER  4
                INDUSTRY CHARACTERIZATION AND CLASSIFICATION
    To  initiate  this  risk  assessment,  EPA will  analyze  and  organize
relevant  data  on  the industry's  waste generators,  waste  stream  types,
release  sources,  and  environmental  settings.   Characterizations will  be
based  largely  on the  primary  research  and  analysis  being conducted  for
this  Section 8002(m)  study.   The  Agency will  first develop  appropriate
categories of waste  generators,  waste stream  types,  release sources,  and
environmental  settings  based  on these characterizations.   The  initial
industry  characterization   and  classification  is   discussed  in   this
chapter.  Then,  for  each waste  generator subcategory,  EPA will  develop
model  scenarios  of   the  waste  stream,   release  source,  and  environmental
setting to represent  current  practices in the industry and to serve  as the
basis for quantitative risk  modeling.   The development of model  scenarios
is described in Chapter 5 of this part.
                             WASTE GENERATORS

    After  organizing  and  reviewing  the  data  on  sources and  volumes  of
waste  (see  Part  I),   EPA  will  divide  the   industry  into  appropriate
categories  for  risk  modeling.   For  example,   waste   generators  may  be
divided  into  two main  categories, oil and gas  operations and  geothermal
                                   IV-4-1

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energy operations.   Each main  category  can be subdivided  into production
operations  and  developmental  operations  (drilling)  and   then  further
subdivided  into  active  operations  and inactive  operations.   It may  also
prove  useful  to  classify  generators  as  large-volume  and  small-volume
operations, and to  estimate  the number of generators and the locations of
facilities  in  each  subcategory,   based  on the  data  collected in  other
parts  of  the  overall study.   These  steps will  produce a  list of  waste
generator subcategories,  with estimates of the numbers and locations  of
each.
                             WASTE STREAM TYPES

    EPA will review  the  chemical  analysis data being generated  in another
part  of the  Section 8002(m) study  (see Part  I)  to identify  significant
waste stream types for each  waste generator subcategory.   It will  then  be
possible to determine waste  stream significance based on  volume, number  of
generators,  toxicity,  and   release  potential.   The  intent  will  be  to
identify   all   wastes   that  are   major  contributors   to  health  and
environmental risk  on a  national basis,  as   opposed  to   all  wastes  that
could  potentially  produce   high  risk  in a   few  situations.   The  risk
analysis will be  based  primarily  on the waste  streams  included  in  EPA's
current  sampling  and   analysis   program,   in  which  samples  are  being
collected from nine oil  and  gas  producing zones of the United States.

    The  Agency   will   also  estimate,   to  the   extent   possible,  the
distribution  of  waste   streams   across  waste  generator  subcategories,
release sources, and location.   EPA  will compile a  listing  of  potentially
toxic constituents  for  each  significant waste  stream type identified, and
may review published reports  to  identify "high-risk" constituents  that may
be present  in industry  waste streams but not  found in those  sampled during
this study.
                                   IV-4-2

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    For each significant  waste  stream type identified, it will be possible
to  develop  at   least   one  representative  waste  stream  for   modeling
purposes.    If  waste  characteristics differ  subtantially across  the  nine
sampling zones,  multiple representative  streams  will  be developed.   For
example,  three  different  representative  drilling  muds  corresponding  to
various geographic zones  might be  modeled.   The  representative  streams
will   be   defined   by   physical   form   and  constituent  identity   and
concentrations based  primarily on  the  EPA sampling  data.   The  analysis
will  also  review  the  sampling  data  to identify waste  streams  whose
constituents and/or constituent concentrations vary  substantially  from the
representative streams.

    After identification  of  significant  waste streams in the industry, the
next   step   will  be   to  identify  constituents   of  concern   for   the
representative streams.   Constituents of concern  will be  selected from the
list of all waste  stream constituents  based  on  concentration,  toxicity,
persistence, and  mobility in the  environment.  The LLM chemical  data  base
will  be  the   primary  source  used  to  rank   toxicity,  persistence,   and
mobility,  and  concentration data will  be obtained  from  the EPA  sampling
report.   Quantitative  scoring  algorithms  will  not  be   used  to  select
constituents;  instead, EPA  plans  to rank and evaluate  the constituents  in
a waste stream based on  the factors listed  above  and to  make the  final
selection based  on professional judgment.  In general, the  Agency expects
to  select  from  two to   six  constituents  per  stream  for  risk  modeling
purposes.    The  Agency  may  find  it  necessary  to expand  the  list  of
constituents to address potential environmental effects adequately.   Based
on the  Agency's  prior  experience  modeling hazardous  waste streams, most  of
the quantifiable risk associated with streams  is usually due  to one or two
constituents.  If  those can be identified, it is  unnecessary to include
all chemical constituents in the full risk modeling.
                                   IV-4-3

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    The  output  of  this step will  be a  limited number of  representative
waste  streams  (no more  than ten)  and constituents  of concern for  risk
analysis.  Each  representative  waste  stream  will be  defined in terms  of
its physical  and chemical  characteristics,  and its  disposal  amount  and
distribution across waste generator types  and locations will  be  estimated.
      WASTE TREATMENT, STORAGE, AND DISPOSAL PRACTICES/RELEASE SOURCES

    The next  step will  be  to  review  the  waste  treatment,  storage,  and
disposal technologies  employed in  the  oil  and  gas  and geothermal  energy
industry.    Significant  practices  are  being  identified  and  assessed  in
another part  of this study (see  Parts  I  and II).  EPA will  estimate each
technology's  distribution  across  waste  generator   subcategories,   waste
stream  types,  and  locations.   From  this   information,  the  Agency  will
identify the  potentially significant sources  and mechanisms  of  chemical
release to  the  environment  for each waste stream  type.  These  significant
release sources (e.g., surface pits) will  eventually be the starting point
for risk modeling.   The  Agency will also  identify low-frequency/low-volume
release sources that  appear to have an unduly high  potential for  release
into the environment.

    After reviewing  the  waste management information,  the next  step will
be to divide  the  identified release sources for modeling into  appropriate
categories  such as  underground   injection  wells  and  surface pits.   Some
release sources may be  subdivided  by size and/or design  characteristics
(e.g., presence of  a liner),  because these  variables  can affect the  timing
and magnitude of chemical releases  and, therefore, the risk.   It may also
be necessary  to subdivide to  represent  the  range  of existing  practices in
the industry  adequately.  For example, centralized  treatment and  storage
facilities,  such  as surface  pits,  are  common in  the industry and  may be
much larger than typical  units found at  individual  sites.
                                   IV-4-4

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    For each  release source  category,  the Agency will  identify potential
mechanisms  of  release  such  as  effluent  discharge   to  surface  water  or
seepage into ground  water.   The result will be  a  list of subcategories of
release sources along with  their potential mechanisms of  release.   It may
also be  possible  to  estimate the distribution  of release  sources across
generators, waste stream types, and locations.
                 ENVIRONMENTAL SETTINGS FOR RELEASE SOURCES

    The environmental  setting  of a release source location is an important
factor  that  influences  risks  associated  with  the   release  of  waste
materials.   In  general, the  analysis will develop  values for significant
environmental variables  based  on this project's  research  and on  a review
of  readily  available  information generated  as  part  of other  relevant
projects  (e.g., the Subtitle D risk analysis,  the cross-program regulatory
analysis,  other applications  of  the LLM, and applications  of  the  RCRA
Risk-Cost Analysis Model).

    The  first step  in characterizing  environmental settings  will be  to
estimate  the number  and  general  distribution  of  facilities  within  each
major  oil  and gas  and geothermal  energy  Region.   Much  of  the information
needed  to  complete  this  step will  come from  EPA's research  into waste
generators,  waste  stream  types,  waste  management  practices, and  damage
cases.   If necessary, however, these research  results  can be supplemented
with  additional  data  available  in  the  literature.   For  example,   the
Independent   Petroleum  Association  of   America   (1986),   the  American
Petroleum  Institute  (1986),  the  Department of Energy  (1985),  the  Colorado
School  of  Mines  (1983),  and  the Rand  Corporation  (1981)  provide useful
data  on the  number  and distribution of oil  and  gas  sites.  Next,  the
analysis  will  characterize  the  principal   environmental risk  variables
                                   IV-4-5

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for  each  of the major  Regions  as a whole.  Facilities within  each Region
will then be  assigned the distribution of environmental variables  for the
respective  Regions.   Although  this  approach  will  not   involve  a  site-
specific  analysis  of  all  sites,  the  Agency believes   it  is  justified
because  of  the sheer  number  of  sites  involved  (in  1985,  there  were
approximately 870,000 onshore oil  and gas wells)  and because  it  believes
that  a  Regional  as  opposed  to  a  site-specific  analysis  will  yield
reasonably  accurate   results  (available  information indicates  that  most
sites are clustered  in  certain  Regions).  EPA will  develop  a distribution
of   values   across   release   source   locations   such  that,   for   each
environmental variable,  it  will  have  at least two values:   a  typical  or
average value and  a  more conservative  value that  will  yield higher,  but
not necessarily worst-case,  risk estimates.

    Important risk influencing  environmental variables  are described below
under  the  categories  of  climate,  hydrogeology,  surface   water,   human
exposure  points,   and   environmental   exposure   points.     Each   section
identifies  the  necessary individual  data  items  required  to  characterize
environmental settings,  and outlines the  Agency's approach  for obtaining
values for these data.

Climate

    Net annual  infiltration rate  is  an  important  variable  that  will  be
used  to  characterize  climate.   Net  infiltration  affects   the  rate  and
extent of ground-water  contamination  from some types of  release  sources,
including landfills  and  land treatment  operations.  EPA will develop  a
distribution  of values  for this  variable based  on an  analysis  of  the
Regions in  which most of the oil and gas  and  geothermal energy facilities
are located.
                                   IV-4-6

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    As  part  of  OSW's  LLM project,  four  net  infiltration  regimes  (0.25
inch,   1   inch,   10  inches,  and   20   inches,   respectively)   that  are
representative  of  the  different  conditions  found  in the U.S.  have been
developed  from  a  previous  literature  review.   These  net  infiltration
regimes have  been assigned to different Regions  across  the U.S.  For this
project,  EPA  plans  to  develop a  distribution  of net  annual infiltration
rates  for oil and gas  and geothermal energy sites  based on the locations
of  the Regions  that contain most  of the  relevant  sites.   This  approach
will  be  consistent with  the method  the   Agency  has used to  assign net
annual  infiltration rates  to hazardous waste facilities  as part  of other
projects  (e.g.,  the  118  hazardous waste  land  disposal  facilities  in the
LLM's  real  facility data base and  the  55  facilities  examined as  part  of
the cross-program  regulatory analysis).

Hydrogeology

    The  primary  hydrogeologic  variables  of  interest  to  this  project
include   ground-water  velocity,   depth   to  ground   water,   hydraulic
conductivity,  and  various  soil  properties  used  to  assess  contaminant
retardation   (effective  porosity,  bulk  mass  density,   and  fraction  of
organic carbon).   In addition,  information on the occurrence and nature of
any layering  within the saturated zone (i.e.,  stratigraphic  data)  will  be
required  if  the  Agency  decides  to characterize more  complex ground-water
flow  systems.   All of  these  variables  influence  risks  by dictating  the
potential for contaminants to migrate  through ground water  to points  of
exposure.   In past analyses using the LLM,  EPA has  focused  on the  upper
layers  of ground-water  systems;  however,  oil  and  gas  wastes  are  often
released  into  deeper strata  using  injection  wells.  Information  in  the
damage  case  studies   will  be   used  to  determine  whether  significant
exposures to wastes released  in the  injection zone are common and,  if so,
additional  hydrogeologic  parameters needed to  characterize deeper  strata
                                   IV-4-7

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will be  identified.   At  this  time, however,  the  Agency does not  plan to
model transmission of  contaminants  from deeper strata  to upper  layers of
ground-water systems  because (1) there are no  simple  models to use,  and
(2) acquiring  the  stratigraphic  input  data  to assess  this  pathway  is
beyond the scope of this project.

    EPA  will  develop  a  range  of  values  for  several  of  the  required
hydrogeologic  variables  using  the  National  Water   Well   Association's
"DRASTIC"  system  (National  Water  Well Association, 1985).   This  system
divides  the  U.S.   into  hydrogeologic  Regions  and   provides   generally
recognized  values  within each  Region  for  several variables  related to
contamination  potential.   Superimposing  these DRASTIC Regions  onto  the
Regions  containing  the  majority  of  oil and gas  and geothermal  energy
activity will yield data on the depth to ground water,  aquifer media type,
and  unsaturated   zone  media.    Once   the  media  in  the   aquifers  and
unsaturated zones  are  defined,  the  Agency will  select a range  of  values
for  hydraulic   conductivity,  effective porosity,  and  bulk  mass  density
based on  typical values for  these  parameters  reported  for different soil
types.   For example,  Codell  and Duguid (1983)  provide tables  of  values for
hydraulic  conductivity  and effective porosity,  and Hough  (1957)  reports
typical bulk mass density values for a wide range of earth materials.

    Eleven  ground-water  flow  field  scenarios   have   been   developed  to
represent  the  majority  of ground-water  flow conditions  in the U.S.   These
scenarios,  which define  various combinations of  ground-water  velocities
(ranging  from   1 meter/year  to  10,000   meters/year)  and  aquifer-aquitard
layer sequences within the  saturated  zone,  are used  in the LLM to model
ground-water  flow.   Because  the  Agency  will  use  the   LLM  to  analyze
ground-water  fate  and transport   (see  the discussion  in  Chapter  6  on
modeling techniques), the values for ground-water velocity and the  aquifer
                                   IV-4-8

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 configurations  developed  for  this  project  will  be  confined  to  those
 specified  in the  11 flow field  scenarios of the LLM.

    To  determine  the appropriate distribution of  flow field scenarios for
 this  project,  ground-water  velocity  data  and   aquifer  configuration
 information  given  in the  DRASTIC  system  for the major oil  and  gas and
 geothermal  energy  producing  Regions will  be  examined.   Combining  the
 facility  location information  with hydrogeologic  data from DRASTIC (i.e.,
 estimating  densities  of facilities  per DRASTIC subregion),  will  yield  a
 frequency  distribution  for  the  variables  of  interest.    It  should  be
 emphasized  that the  Agency does not intend  to use  the  DRASTIC  scoring
 procedures, but only  the hydrogeologic data for various  subregions.   As a
 check  to  this  approach and to  fill in  any  data gaps,  two additional
 methods  for assigning  flow  field  scenarios will  be pursued.   The  first
 will  be to  examine  flow   field  scenarios  previously assigned  to  other
 facilities  located  in  the  various  oil  and  gas  and   geothermal  energy
 Regions  (e.g.,  the 55  facilities examined  in  the cross-program project,
 the 118  facilities  in the LLM's  real  facility  data base, and  the 67 sites
 examined to develop the LLM's  generic flow  field  scenarios).  The second
 will  be  to examine U.S.  Geological  Survey  (USGS)  topographic maps  for  a
 sample of  facilities  to  determine  a  range  of  hydraulic  gradients  which
 will be  ascertained by assuming the ground water underlying a  site has the
 same  gradient   as  the  land surface  slope.   These  values  for  hydraulic
 gradient will  be  used  to  calculate  ground-water velocities  using  Darcy's
 Law,  an  expression that  relates ground-water  velocity  to the  hydraulic
 gradient,  hydraulic  conductivity, and effective porosity (a  determination
 based on predominant soil types as described above).

 Surface Water

    Surface water data  are  needed to determine  direct impacts to  surface
water resources as  well  as  human and ecological exposures  through  surface
                                   IV-4-9

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water  intakes.   Although the  methodology for  modeling  chemical transport
in  and damage to surface waters  has not  yet  been finalized  (see  Chapter
6),  EPA expects  that  the data  needs will  include  the type  (e.g.,  lake,
river),  location,  size,  flow rate, and patterns  of  use of  nearby  surface
waters.

    Based  on the Agency's current knowledge,  the occurrence,  nature,  and
patterns of  use  of surface waters surrounding  oil and gas  and geothermal
energy  production  facilities  are highly varied across  the   universe  of
facilities.   Therefore,   rather   than attempt  to  rigorously  define  the
distribution  of  key  surface water  variables  across  all  sites, EPA will
simply  define for  each variable   a set  of values  that are  reasonable  for
the  major  oil  and gas  and geothermal  energy Regions.   It will  then  be
possible to  combine different  values for each  variable  to form  a  variety
of  surface water  scenarios.  As  a means of  illustration,  the  following is
a listing of surface water variables  and a possible set of  values for each:

        Distance  from  facility  to  nearest  surface  water   body:
         <^ 0.5 mile, between 0.5  and  2 miles, and > 2 miles;
        Stream flow rate: 10,  100, and 1,000 ft3/sec;  and
        Patterns of  use:  human  consumption only,  recreational uses
         (e.g.,  fishing and  swimming) only,  and  combined  consumption
         and recreational uses.

    To  derive a  reasonable  set  of   values  for  important  surface  water
variables,  the  first  step will  be to  examine  State  hydrologic  unit maps
for those  States where  the majority  of oil  and gas  and geothermal  energy
facilities   are  located.   These  maps   show  the position  and size   of
principal streams, rivers, and lakes.   Distances  of  facilities  from  these
surface  water  bodies  can  be  estimated by  superimposing  the  general
distribution  of  facilities  onto  these  hydrologic  unit  maps.    Other
information sources are available for determining values for other  surface
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water  variables.   For  example,  the USGS's  National Water  Data  Exchange,
Master Water Data Index, REACH Files, and Water Data  Storage and Retrieval
System all  contain values for water body-specific  data.   Similarly, EPA's
Stream Gage Inventory File  and STORE!  Flow File contain  stream flow rates
for thousands of  stream gauging stations throughout  the  country.   Data in
these information systems will be  examined  only at a level  of detail that
will enable EPA  to develop a representative distribution of values for the
major oil and gas and geothermal energy Regions.

Human Exposure Points

    Potentially exposed populations will be  characterized by examining the
distance  and  direction  to  human  exposure  points  in  the  vicinity of  a
sample of facilities.  The Agency does not plan to  estimate  rigorously the
number of people  potentially  exposed  at any specific  site  nor to develop
projections  of  the  total  exposed  population.    EPA  also  intends  to
emphasize  exposures  through  the  ingestion  of  contaminated ground  and
surface  waters;  the  Agency may expand  the  analysis  to  consider  other
exposures   including  ingesting  of  contaminated   fish   and  inhalation.
However, air exposures will be considered if waste  release and damage case
information indicates that  the airborne pathway should be addressed.  Once
sufficient  exposure  point  data have  been  developed  for  a  sample  of
facilities,   EPA   will  extrapolate   these  results   to   estimate  the
distribution of  distances to human exposure points  across all facilities.
The  assumptions  and uncertainties  associated with  this extrapolation will
be fully described in project reports.

    To determine  the distribution of human  exposure  points  through ground
water, the  first  step  will be  to  locate a  sample of facilities  on USGS
topographic maps  and to estimate the direction  of ground-water  flow from
the  site  by  assuming  the  ground  water  flows  in  the  direction  of  the
predominant land surface  slope.  Next, the area of  potential contamination
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will  be  defined  as  the  area  +  45  degrees  of  the  center  line  of
ground-water flow  and out to  some  specified distance,  such as  one  or two
miles.   Finally,  EPA  will  attempt  to  determine  whether  drinking  water
wells are  located  within this area of  potential  contamination.   Telephone
interviews  with local  officials are  the  most  reliable  source  of  well
location  information.   EPA  has  used  this  mapping/telephone  interview
approach  for  estimating  exposed  populations  in  several   other  recent
projects,   including  development   of   the   LLM  data  base   and  the  OSW
cross-program regulatory analysis.

    Potentially contaminated  surface  water  resources  will  be   defined  as
those  bodies  of  water  that  (1)   are  located  within  the  potentially
contaminated ground-water area;  and/or  (2) are  known  to  receive  liquid
effluents from  an  oil  and  gas or geothermal energy facility.   The  Agency
plans  to   identify   the  surface  waters   potentially   contaminated  by
ground-water seepage  through  the  USGS map  procedure  outlined  above,  and
may, for a  sample  of facilities, identify surface waters  receiving  direct
discharge  by  conducting telephone  interviews  with State  officials  who
oversee  National Pollutant  Discharge  Elimination  System  (NPDES)  permits.
In  addition,  the Agency  plans to  estimate  the distance  to surface water
intakes  (if any) for human consumption.

Environmental Exposure Points

    The   methodology    and    information   requirements    for    modeling
environmental   exposures  will  be  finalized  after   some   initial  data
gathering  is  complete.   This section,  therefore,  describes  the  general
information  requirements for an  assessment  of  environmental  damage  or
ecological risk.

    An ecological risk assessment requires the  development and  examination
of  two general  types  of data:  toxicological hazard data and environmental
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exposure data.   Environmental  toxicity  data reflect  the potential  for a
constituent  to  cause  an  adverse  effect  under  a   particular   set  of
conditions.  Adverse  effects  can  include mortality  to single  species  of
organisms;   reductions  in  populations  of  organisms   caused   by  acute,
chronic,  and  reproductive   effects;  and  disruption  in  community  and
ecosystem level functions (EPA, 1986c).  Common toxicological data used in
assessing  environmental  risks would  include  LC50  an^  LDCQ   values  and
no-effect  levels  for  certain  critical  species.   Environmental  exposure
data  include  the  estimated  environmental  concentration of  a contaminant,
as well as  the numbers,  types,  and distribution  of organisms  exposed  to
the environmental  concentrations.

    In general, the Agency  plans  to collect toxicity data from a review of
the  general  literature  (e.g.,  EPA's  Ambient   Water  Quality  Criteria
Documents;   Curtis  et  al.,  1979;  and  Stickel,  1974) and  from  discussions
with  relevant  scientific  and  government  organizations  (e.g.,  EPA,  the
Department  of the  Interior's Fish  and  Wildlife  Service,  and  academic
research institutions).  In particular within EPA,  the  Office of Pesticide
Programs'  Ecological  Effects  Branch,  the  Office  of  Water Regulations and
Standards,   and the  Corvallis  Environmental  Research Laboratory have been
active  in  examining ecological toxicity data and  should  prove  useful for
this  type  of  information.   In addition,  EPA  has  compiled  environmental
toxicity  data for  a  variety of  contaminants  in order  to develop  the
ecorisk submodel of the RCRA Risk-Cost Analysis Model (EPA, 1984b).

    Although  most  ecological  toxicity  data  have  been  developed  on  a
chemical-specific basis  in  the past,  considerable testing has been done in
recent years on intact effluents  and  wastes.   Some  of this type  of data
exists  for wastes associated  with oil  and  gas operations  (Gaetz et al.,
1986; EPA,  1984a).  The feasibility of  using  such a  waste-based  approach
for   assessing  ecological   effects  will  be  examined   as  a  means  of
supplementing the chemical-specific approach.
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    Data  on  contaminant  concentrations  in  environmental  media  will  be
calculated based on the modeling approach (for surface and ground  waters),
and/or  estimated based  on available  environmental monitoring  data  from
actual  facilities.    Rather  than  attempting  to  precisely  define   the
numbers,  types,  and  distribution of  potentially  exposed  organisms,  the
analysis will examine  the  risks to hypothetical  exposed  organisms of  one
or more  indicator species.  The  Agency will select appropriate  indicator
species based on such factors  as the  availability of toxicity data  for  the
species, the  sensitivity  of the  species to  constituents  of  concern,  the
likelihood of exposure of the  species to oil and gas and geothermal  energy
wastes, and the  aesthetic  and/or  economic importance of the species.   For
this type of  information,  EPA  will consult experts and standard  reference
materials (e.g..  Lee et al., 1980; EPA,  1972;  and Carlander, 1977).

    In addition  to modeling ecological  risks  on a chemical-specific basis,
EPA will develop other measures of potential  environmental damage  such as
proximity of  oil and  gas  and  geothermal activities to wetlands,  sensitive
areas, or endangered  species habitats.   The Agency also plans to  estimate
damage  measures   such  as  volumes  of   ground   water  and  surface  water
contaminated and acres of land damaged.

    To analyze potential  damage  to  environmentally sensitive  areas,  the
analysis  will   rely  on  existing maps  and  delineations  of   endangered
species'  habitats,  wetlands, and other areas of  interest.   For example,  in
analyzing  ecologically vital  ground water  as  part of  the ground-water
classification guidelines,  EPA  mapped the  environmentally sensitive  areas
in California and Louisiana, two  major  oil and gas producing States (EPA,
1986a).  Other useful sources  of information include 50  CFR Part 17,  which
identifies  the   historical  range  and critical  habitats  of threatened  and
endangered species, and experts within  the U.S. Fish and Wildlife  Service
and State Natural  Heritage Program Offices.  Information on the  locations
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of environmentally  sensitive areas will  be assembled  only at a  level  of
detail that  will allow  a  rough approximation  of  the  type  and extent  of
potentially affected areas.  The Agency will calculate approximate volumes
of  ground water and  surface  water  contaminated  through  the   modeling
approach,  but will  rely  primarily  on  the results  of  the  damage  case
studies to estimate acres of land damaged.
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                                  CHAPTER 5
          EXPOSURE PATHWAY ANALYSIS AND MODEL SCENARIO DEVELOPMENT
    Once   the   characterization   of   wastes,   release   sources,   and
environmental  settings is  complete,  the  Agency  will  identify  potential
human and  environmental  exposure pathways (an exposure pathway is a unique
combination  of  release  source,  environmental  transport  medium,  exposure
point, and exposure  route).   Actually, this step  is  a  reassessment of the
preliminary  identification of  significant  pathways that  is made  early in
the  analysis.   For  example,  the  Agency has  identified  as  a  potentially
important  human exposure  pathway releases of contaminants  to ground water
from surface pits,  followed  by ingestion via drinking water.  EPA has also
made the preliminary determination that pathways involving  release  to  air
will  probably  be  relatively  less  important.   The  data  collected  in  the
industry characterization step will,  however,  be  systematically  evaluated
to confirm the  significance  of exposure pathways identified earlier and to
identify ones that may have  been overlooked.  EPA will develop a complete
matrix of  reasonable  exposure pathways  and will  document  the  rationale
either for including or excluding each from the  risk analysis.

    Although dozens  of potential  exposure  pathways may be  identified,  the
Agency emphasizes  that  it   will  only  include  a  few in the  quantitative
modeling and  risk analysis.    Each additional  pathway  included  increases
the scope  and complexity  of  the  analysis.    It  is,  therefore,  important to
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identify  and focus on  the exposure pathways that  are  most significant in
terms  of  risk.   EPA  will  use  two  different  approaches  to  identify
important  pathways.    The  first  will  be  a   review  of  the  compiled
information  on  waste  types,  waste management practices,  and environmental
settings  for oil  and  gas and  geothermal  energy  facilities in  order to
develop hypotheses  about  possible  sources  and  mechanisms  of  contaminant
release  to  environmental  media.  For  each release  source/release  medium
combination,  the Agency  will  evaluate  the possibility  of transport  to
human  or  environmental  exposure  points,  as well as  the  likelihood of
intermedia transfers  (e.g.,  ground  water to surface  water).  The  second
approach will be to  review the damage case summaries (see Part III).  From
these  reported  cases of  damages attributable to oil  and  gas  production
operations,  it   will  be  possible  to identify the  chemicals and  exposure
pathways  that have  resulted in either  adverse  health  or  environmental
effects.

    After  the   exposure   pathways   for  quantitative  risk  analysis  are
determined,  the  next step is  to combine  the  major  waste  types,  release
sources,  and environmental  settings into  realistic  model  scenarios  for
risk modeling.   Essentially,  this is  a  reorganization  and  refinement  of
the data collected in the industry characterization (see the discussion in
the  preceding chapter).   Model scenarios,  intended to  represent  actual
current practices in  the  industry,  will be arranged as a matrix with three
primary dimensions  waste  type, source  type,  and  environmental  setting
type    with an  as  yet undetermined  number  of  categories  along  each
dimension.   It may be  possible, for example, to  reduce the  industry  data
to  10 composite  waste  types,   10  categories   of   release  sources,   and
20 environmental  setting  categories,  for  a  theoretical  total  of  2,000
model scenarios  for which risk  would be estimated.   It is also  likely that
the  theoretical  total  in  this  example  could  be  reduced  considerably,
because  some  combinations  may  be  unrealistic  (e.g.,  specific  release
sources may not  be applicable to all  waste types).
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    The final  matrix of  model  scenarios defines  what will  be  modeled in
the  subsequent risk  analysis.   The  Agency  will  estimate  a health  risk
and/or  an environmental  effects measure  for each  realistic cell  in the
matrix.
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                                  CHAPTER 6
              DEVELOPMENT AND REFINEMENT OF MODELING TECHNIQUES
    The  LLM will  be  used as  the predominant  tool for  estimating risks
associated  with oil  and  gas  and  geothermal  energy  facilities.    In  its
current  form,   the  LLM  can  assess  human  health  risks  associated  with
ground-water releases  from  surface impoundments  and  landfills.   Because
there are  several  other  areas of  interest  in  this project (e.g.,  releases
from injection  wells,  surface water fate and  transport, and  environmental
damage),  it may be  necessary to  adapt  the LLM and/or use  other  modeling
techniques  to  supplement  the  LLM  analyses.   This  chapter  discusses  the
proposed  general  approach for  modeling  contaminant  release  mechanisms,
environmental fate and transport,  human exposures  and health  risks,  and
environmental damages.   For more  information  about  specific  submodels of
the LLM, refer to the most recent draft report (EPA, 1985a).

              CONTAMINANT RELEASE TO GROUND AND SURFACE WATERS

    At this time, EPA  plans to  examine at least three  sources  for release
of oil  and gas  and geothermal energy wastes:  underground injection wells,
surface  pits,  and  effluent point  sources.   Based  on a review  of  the
background   information   presently  available   to  EPA,  these  disposal
practices appear to  constitute  the principal  release sources  of  concern.
For this project, the Agency plans to model all releases deterministically;
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stochastic failure  and  release  models will not be  developed  or used.  EPA
anticipates  developing  several  release profiles  to  represent the  major
mechanisms of  failure,  including  low-probability,  high-quantity failures,
as determined by a literature review and engineering analysis.

Underground Injection Wells

    In examining  releases  from  injection wells, the scope of the  analysis
will  be   limited  to  releases  to  upper aquifers  through failure of  the
injection well.   At  present,  EPA does not  intend to model  risks  from  the
emplacement of  wastes in  an  injection zone, primarily because the Agency
suspects that the health and environmental hazards are small  if the wastes
are  confined  to  deeper  formations.   For  example,  the  RCRA  Risk-Cost
Analysis Model only considers releases from  injection wells  that  lead  to
the contamination of  upper aquifers.   However,  EPA will  examine its damage
case studies to determine  whether releases into the injection  zone result
in  significant  exposures and whether such releases should  also  be  taken
into account in this analysis.

    In general, two main types  of injection well failures that can result
in  releases  to upper ground-water systems  will  be examined:   well-head/
piping failures and casing/grout seal  failures.   Well-head/piping  failures
involve the failure  of  a pump seal or a rupture of a pipe such that wastes
are  discharged directly  to  the  ground  surface.   Although  most  of  the
wastes  released  in  this  way will be cleaned  up,  some  fraction may  be
directed  to  surface  water or  seep  into  the  ground.   Casing/grout  seal
failures  involve  a deterioration  of  the well casing or  seals,  creating a
hydraulic connection  between  the  injectant and an aquifer.   For this type
of  failure,  a significant  portion of the injected wastes may  escape into
an aquifer.
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    The Agency  will model  release  volumes and  estimate the  frequency of
occurrence associated with  each of these  release  types.  A  probabilistic
approach involving  simulation  modeling  will not be attempted; instead, the
Agency will  develop "typical"  injection well release  scenarios based on
case histories  involving  injection  well failures.   For example, it will be
possible  to  estimate  how  many  well-head/piping  failures   a   typical
injection well  experiences  over its operating life, what volume is usually
released  per failure,  and what  portion  of  the  released volume  is  not
cleaned  up.   It  will  then  be  possible  to   estimate the  fraction  of
injection  wells  that   result   in  releases  as   defined  by  this  typical
scenario.   Such an approach  is used to estimate  releases from hazardous
waste  injection wells   in  OSW's RCRA Risk-Cost  Analysis  Model, based on
data   gathered   through   consultation   with  experienced  engineers   and
injection well  operators.   EPA will explore  the possibility  of using the
injection well release scenarios developed for that model in this project.

Surface Pits

    For modeling  chemical  release  from  a surface pit,  the Agency plans to
adapt  the  unlined  surface  impoundment  failure   release  submodel from the
LLM.   The LLM models  release (1) during the  active  operating period,  when
the  impoundment  contains   liquid  and contaminant  releases are driven by
that   liquid;  and  (2)  during  the  period  following   closure,  when  the
impoundment  has been  drained  and  covered and  contaminant  releases  are
driven  by  net   infiltration.   The  model  may   need  to  be  modified for
drilling  mud reserve   pits  because  of  the  potential  for  clogging  and
sealing.  Available information collected for this  project indicates  that
the clay content  of oil and gas wastes  may in  some cases reduce  leachate
release  rates by lowering  the  permeability  of  drilling fluid  pits.   EPA
plans to examine its waste stream and release source data (see  Parts I and
II) and other literature  sources as needed to quantify this phenomenon; if
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necessary, the permeability or  other assumptions will be adjusted  so that
the LLM submodel will be more similar to drilling mud surface  pits  at oil
and gas and  geothermal  energy sites.  EPA also  plans  to investigate other
potentially  applicable  models,  such  as  the Post  Closure  Liability  Trust
Fund  Model   (EPA,  1985b);  Hydrologic  Simulation  on  Solid Waste  Disposal
Sites  (Perrier  and Anthony,  1980);  and  a new  release  rate  model  being
developed by OSW's Land Disposal Branch.

Effluent Point Sources

    As discussed  in  Chapter  4,  the risk analysis will identify significant
waste  streams  for several  waste  generator  subcategories.    Based  on  the
available waste stream  data,  it will be possible to develop typical source
terms  characterizing  constituent concentrations  and  release  rates  for
effluent  point  sources.  EPA will thus assign  source terms  for  effluent
inputs to surface water based  on the  data review rather  than through  a
predictive modeling approach.

                       CONTAMINANT TRANSPORT AND FATE

    For  this  risk  analysis,  the  Agency anticipates  modeling  chemical
transport in two environmental media, ground water and surface water.

Ground Water

    EPA will use  the LLM's subsurface transport submodel to  determine the
transport  and  fate   of contaminants  of  concern  in  ground  water.   That
submodel  predicts  mass transport  of contaminants  through  the unsaturated
zone梩he  soil  layer above  the water table  in which the  pore spaces are
only partially filled with water梐nd the saturated zone.
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    The LLM calculates  the  travel time for a  released contaminant to pass
through the  unsaturated zone  and reach  an  underlying  aquifer using  the
modified McWhorter-Nelson wetting front  model.  The travel time is related
to the difference in water content between the layer  immediately above  and
below  the  front,  the  distance  traveled  in the  unsaturated zone,  the
leakage  rate,  and  the  retardation  of  contaminant   movement  by  soil
adsorption.   Unsaturated  zone  thickness, leachate  discharge  rate,  and a
chemical's  retardation  factor have  the  most  effect  on travel  time.   Key
assumptions  in the  unsaturated zone  transport  component of  the  submodel
are  that  no  contaminant  interactions  occur  and  that  one-dimensional
(vertical, downward) modeling  of the transport in the  unsaturated zone is
valid.   EPA will  address  how these  assumptions affect the   final  risk
estimates.

    The Agency will  assess  the transport of contaminants  in the saturated
zone  and  predict  contaminant   concentrations   over   time   at  distances
downgradient of  the  release sources using the saturated zone component of
the    subsurface    transport    submodel.     As    discussed   previously,
concentrations  of  contaminants  in  ground  water  can  be   estimated  for
11 generic flow fields.

    The LLM estimates  concentrations  in  the  11 generic  flow fields with a
modified  version  of  the   Random-Walk  Solute Transport  Model (Prickett,
Naymik,  and   Lonnquist,   1981).   Dissolved  chemicals   are   treated   as
particles  that move  in  two  stages.  First,  each  particle moves  in  the
direction  of  ground-water  flow,  and then each particle  disperses  randomly
based  on  values  of exogenous dispersion coefficients.   In the  LLM,  the
basic  random-walk  model  output  is  adjusted  for  several  factors  not
rigorously  modeled,   including   source   strength,   duration,  and  width;
degradation;  retardation;  transverse  dispersion; and  dilution caused  by
pumping.
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    The   LLM  calculates   a   separate   time   profile   of   contaminant
concentrations at the  exposure  point for each year of contaminant input to
the saturated  zone,  and then sums  these  profiles  to produce  the  overall
time  profile  of  concentration  (i.e.,  breakthrough  curve).   As for  the
unsaturated  zone  model, key  assumptions in the  saturated  zone  component
will  be  outlined and  their effects  on the final  risk estimates will  be
evaluated.

Surface Water

    The LLM currently models releases of contaminants to surface  water via
ground water,  but  it does not model the fate and transport of contaminants
once they enter the  surface water body.  The Agency  will  therefore  modify
the LLM  to  incorporate a simple surface water model for this project.   The
Agency also intends  to modify  the  LLM to  consider direct  releases  to
surface water.

    The  environmental  fate of  contaminants entering surface  water  bodies
is  dependent  on  the  type of  water  body involved.   In general,  there  are
three  predominant classifications  of  surface  water  bodies:   rivers  and
streams,  lakes and other impoundments, and estuaries.  Based  on  the known
distribution  of  oil  and  gas  and  geothermal  energy  sites,  all  three
classifications  may  be  important  in assessing  waste  releases  for  this
project.

    For  rivers and  streams, the initial concentration of  a  constituent in
the water is  simply  the mass loading  (from either  ground-water seepage or
direct  discharge) divided by  the   streamflow.   To  determine  constituent
concentrations  downstream,  the  analysis  will   use  a   one-dimensional,
steady-state  model  similar  to  the  one  proposed  for use  in  the  land
disposal  restrictions program:
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                              Cx = C0
    where
              Cx  =  Concentration at downstream distance x (mg/1)
              CQ  =  Concentration in stream after initial dilution
                     (mg/1)
              K   =  Decay rate constant for surface water (sec"1)
              U   =  Mean stream velocity (m/sec)
              x   =  Distance downstream (m).
The input data  for such a model will  be  developed through an  examination
of existing data  compilations  and summaries available within EPA  and from
the USGS.  There  are several  other  simple river  and stream models  being
evaluated for  use in this project (e.g., equations available  in  Delos et
al., 1984; Fisher et al., 1979; Liu,  1977; and Neely,  1982).  While such
models may  have  to  be  adapted for- this  analysis  to consider  oily wastes
that do not mix completely with water, the Agency  favors  a  simple surface
water  model   for  this  analysis  because  such   models   provide  useful
predictions of contaminant  concentrations without the  substantial  data
inputs  and resources   needed  to  run  more complex  models  (e.g.,  EPA's
Exposure Analysis Modeling System).

    There is great diversity in impoundment and estuary types, as well as
a wide  range  of complexity in methods  for  predicting  contaminant  fates in
these  types  of surface water bodies.  Mills  et al.  (1982)  identify  and
describe  several  estimation methods   useful  in  impoundment  and estuary
assessment.  EPA  is currently in the process of  evaluating  these and other
models for impoundments and estuaries.
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                          EXPOSURE  AND HEALTH  RISKS

    The LLM  will be  used to predict the human health  risks  from chronic
exposure  to  contaminated  ground  water  via  drinking  water.   The LLM  is
capable of assessing both cancer and noncancer health risks.

Cancer Risks

    Cancer  risks will  be  estimated  by  using a  linear  (at   low  doses),
non-threshold dose-response  equation.  The  LLM uses the  one-hit  equation,
which  calculates the  lifetime  individual  risk  as  an exponential  (but
linear at low doses)  function of potency and  lifetime average  dose.   Dose
will  have  been  determined  from  the  release  and  transport  submodels
described in previous chapters.   Potency is chemical  specific  and  will  be
set  equal  to the the upper-bound unit  risk  parameter  estimated  by EPA's
Carcinogen Assessment Group.

Chronic Noncancer Health Risks

    Chronic noncancer health risks will  be estimated  with  a  dose-response
model that calculates risk from noncarcinogens as a continuous function of
dose at dose levels above a threshold.  For this purpose, the LLM  uses the
Weibull  equation with  a  threshold.   The  lifetime  individual  risk  is  an
exponential  function  of   several   parameters,   including  the   Weibull
dose-response  parameter,  the  lifetime  average  dose, and  the  threshold.
Individual risk is considered to be zero below the threshold.

                            ENVIRONMENTAL DAMAGE

    To  assess  the  environmental  damages  caused  by  oil  and  gas  and
geothermal  energy  wastes,  the  Agency  will  examine  potential   adverse
                                   IV-6-8

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effects on ground  water,  surface water, land, and ecosystems.  Because EPA
believes that potential environmental damages are  an extremely significant
aspect  of  this study, and  because  some of these  damages  are not amenable
to the chemical-based predictive modeling procedures to be  used for health
risk  assessment,  several  assessment  approaches  will  be  employed  for
estimating  environmental  effects.   EPA  definitely  plans  to  conduct  a
chemical-based analysis  of  model scenarios  for some  environmental damage
endpoints.   Specific  endpoints  to  be  assessed   in  this   way  include
contaminated  volumes  of  ground water  and  surface water,  and  exceeded
aquatic  ecosystem   thresholds   for  individual  chemicals.    This  model
scenario approach  will parallel  the health risk analysis,  and  many of the
necessary modeling components  (e.g.,  chemical release and  transport)  will
be identical.  Thus,  estimates  will be available  for both health risk and
environmental damage for some of the model scenarios developed.

    A second approach will be to use current  information from damage cases
to extrapolate  observed  environmental  effects  to the universe  of  oil and
gas  and  geothermal   energy sites.    EPA  will  attempt  to  derive  point
estimates  or distributions of  relevant  endpoints,  such   as  contaminated
acreage or crop  damage,  per well or  per some  other index of  production.
As a  third approach,  EPA intends to correlate locations of oil and gas and
geothermal energy  operations with  locations  of significant  environmental
variables,  such as   wetlands  or  critical habitats.   EPA has used  this
approach in  the  Section  8002 mining waste  study.   These  three  approaches
to analyze environmental  damage are  briefly described below.

    Damage to ground  and  surface waters can be assessed by determining the
volumes of water contaminated above  certain thresholds such that  the water
is rendered  unfit  for human consumption,  unfit to support  aquatic life, or
otherwise significantly less useful  than before becoming contaminated.   To
assess  the  volumes  of   contaminated  ground  water from  specific  model
                                   IV-6-9

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scenarios,  EPA  will   use   the  LLM,  which  is   capable   of  estimating
contaminant plume widths  and volumes.  Using the modified LLM,  along with
surface  water damage  thresholds  for specific chemicals,  the Agency will
also estimate the volumes of surface water contaminated.

    Estimating adverse effects to land must be carried  out through methods
other  than chemical-specific  modeling  using  the  LLM.  Documented  cases
involving damages to  significant  areas  of land primarily involve  releases
of brines  (i.e., chlorides).   In several States,  damage cases suggest that
thousands  of  acres  have  been  damaged  or rendered   useless  from  brine
releases  originating   from  oil and  gas  well  sites.   In  one Region,  for
example, the  average  acreage lost as a result of  oil  and  gas  production
activities has been reported as approximately 0.8 acre per brine pit.  EPA
intends  to  develop  a distribution  of  factors,   such as  the  one  just
presented,  that  relates  the  number  of  acres  damaged  per  unit  of  waste
release  or waste  management  activity.   Because most   land damage  cases
involve  and  most   information appears  to  be  available  for releases  of
brines, hazards to  land will be assessed mainly by  focusing  on brines.   In
addition,  EPA will have  to  define  exactly what  it means by "damaged";  it
plans  to  develop a range of adverse  effects to  land to reflect  different
levels of damage.

    Two  complementary approaches to  assessing ecosystem damages  (a subset
of  overall environmental  damages)  are  under  consideration.   The  first
would  be  a guantitative assessment of  ecological risks for  a set of model
scenarios.  As in health risk assessment, an ecological risk assessment  is
generally  made  up of  four  general  components:  hazard  identification,
dose-response  assessment, exposure  assessment,  and  risk characterization.
The  primary   difference  is  that  ecological  risk assessments  focus  on
aguatic   and   terrestrial   indicator   species   rather  than  on   humans.
Barnthouse  et al.   (1982a and b) describe  five  methods for environmental
                                   IV-6-10

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risk analysis; the Ecological  Effects Branch of EPA's  Office  of Pesticide
Programs also  has documented  its  approach to  ecological risk  assessment
(EPA,  1986c).    In  addition,  EPA's  Office of  Solid  Waste has  recently
applied an ecorisk scoring  system  for hazardous  wastes  (EPA, 1986b),  and
EPA's  Integrated  Environmental Management  Division  (IEMD)  has  applied an
ecological effects  assessment  procedure  for  specific  chemicals.   These
methods are under consideration for use in this project.

    As  an alternative  approach to examining  ecosystem damages,  EPA  will
investigate the  proximity of  endangered species  habitats,  wetlands,  and
possibly other sensitive  environmental  areas  to oil  and gas and geothermal
energy facilities.  The Agency will  determine  the proximity  of sensitive
areas  by  mapping the  general  distribution  of  wetlands  and  endangered
species habitats  relative to the major oil and  gas  and  geothermal  energy
regions.   This  analysis,  combined  with  results concerning  the  volumes of
water  contaminated  and acres  of land  damaged, will  form  the  basis  for
qualitative conclusions about the hazards to these sensitive environments.
                                   IV-6-11

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                                 CHAPTER  7
                           ANALYSIS OF  SCENARIOS
    In  this  final  major step  of  the  risk analysis,  EPA will apply the
modeling  tools   developed   to   estimate   health   risks  and   potential
environmental damages  for the  complete set of  reasonable model  scenarios.
This  step will  produce  the  quantitative  risk modeling results  of  the
Agency's  analysis,  and  will  form  the basis  for  its  conclusions  about
potential health  risks  and  environmental effects.   EPA will  probably use
an  integrated  computer model,  adapted  from the  LLM,  to  do  the necessary
calculations for the large number of model scenarios.

    The outputs of this step will be a quantitative measure of health risk
and/or   environmental   effects   for  each   realistic  scenario   in  the
waste/source/environmental setting matrix and,  if possible on  the  basis of
available  data,   an estimate  of  the  distribution of  actual  facilities
across  scenarios.   This  type  of result would  provide  information  on both
the frequency and intensity of potential adverse effects  from oil and gas
and geothermal energy  facilities.  The Agency  will then  be  able  to rank
scenarios on the  basis  of  the  risk  and identify  extremely  high-risk and
low-risk  combinations.    It  may  be  possible to  construct  relative  risk
rankings of  individual factors, such as waste type or source type.
                                   IV-7-1

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    EPA does  not plan  on  presenting precise  point  estimates of  absolute
risk using the  generic  methodology described in this chapter.  Instead, it
plans  to  present  the  results  as  both  weighted   (by   frequency)   and
unweighted   frequency   distributions   of  individual   health  risk   (or
environmental damage) across various combinations of model  scenarios.   For
example,  a  risk distribution  across  all  scenarios  might  be  developed
first;  the  data might  then be disaggregated  into  numerous  distributions
across  subsets  of  scenarios  (i.e.,  if  there  were  ten  waste  stream
categories, the  analysis would  develop  and compare the  risk  distributions
for .each).   Figure  IV-2   illustrates  the  type  of  frequency distribution
that will result from the risk analysis.

    Clearly,  many   assumptions   will   be  necessary  to  carry   out   the
quantitative  analysis  of  risks.   EPA  plans  on  testing  the  potential
effects of major assumptions  through a  sensitivity  analysis, varying  the
values  assigned  to  key  parameters  over  their  reasonable  range,   and
determining the effects on the risk measures used.
                                   IV-7-2

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H

I
-J
I
          E
          Q
          U
          E
          N
          C
          Y
             12 -r
             10 -
6
             4 -
             2 -
             0
                                                              0.25 inch

                                                              1 inch

                                                              10 inches

                                                              20 inches
                   -10
               -9
          IIGUUE IV-2.  CONTRIBUTION OF INFILTRATION TO WEIGHTED AVERAGE BASELINE RISK

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                                   REFERENCES
American Petroleum Institute, 1986, Basic Petroleum Data Book, Petroleum
    Industry Statistics, Volume VI, Number 3, Washington, DC.

Barnthouse, L.W., et al., 1982a, Methodology for Environmental Risk
    Analysis, ORNL/TM 8167.  Oak Ridge National Laboratory, Oak Ridge, TN.

Barnthouse, L.W., et al., 1982b, Preliminary Environmental Risk Analysis
    for  Indirect  Coal  Liquefaction.   Draft  Report.    Oak  Ridge  National
    Laboratory, Oak Ridge, TN.

Carlander, K.D., 1977, Handbook of Freshwater Fishery Biology, Volume 2, Iowa
    State University, Ames, IA.

Codell, R.D. and J.D. Duguid, 1983, Transport of Radionuclides in Groundwater,
    Chapter  4  in  Radionuclide Assessment:   A  Textbook on  Environmental  Dose
    Analysis, U.S.  Nuclear Regulatory Commission,  Washington, DC.

Colorado School of Mines, 1983, Potential Supply of Natural Gas in the United
    States  as  of  December  31,  1982, Potential  Gas  Committee,  Potential  Gas
    Agency, Golden, CO.

Curtis, M.W. et al., 1979, Acute Toxicity of 12 Industrial Chemicals to Fresh-
    water and Saltwater Organisms, Water Research  13:  137-141.

Delos, C.G., et al., 1984, Technical Guidance Manual for Performing Wasteload
    Allocations,  Book  II:    Streams   and   Rivers,   EPA,   Office   of   Water
    Regulations and Standards, Washington, DC.

DOE, 1983, Oil  and Gas Field Code Master List,  1985, DOE/EIA-0370(85),
    Washington, DC.

EPA, 1986a, Analysis of the Definition of Ecologically-Vital Ground Water
    Under  the   Proposed  Ground-Water  Classification  Guidelines,  Office   of
    Ground-Water Protection and Office of Policy Analysis.
                                    IV-Ref-1

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EPA, 1986b, Assessment of Impacts of Land Disposal Restrictions on Ocean
    Disposal of Solvents, Dioxins, and California-List Wastes,  Office of Solid
    Waste, Washington, DC.

EPA, 1986c, Hazard Evaluation Division Standard Evaluation Procedure:
    Ecological   Risk  Assessment,   EPA-540/9-85-001,   Office   of   Pesticide
    Programs, Washington, DC.

EPA, 1985a, Liner Location Risk and Cost Analysis Model,  Draft Report, Office
    of Solid Waste, Washington, DC.

EPA, 1985b, Post Closure Liability Trust Fund Model, Office of Solid Waste,
    Washington, DC.

EPA, 1984a, A Survey of the Toxicity and Chemical Composition of Used Drilling
    Muds, EPA-600/3-84-071, EPA Research Laboratory, Gulf Breeze, FL.

EPA, 1984b, The RCRA Risk-Cost Analysis Model, Phase III  Report, Office of
    Solid Waste, Washington, DC.

EPA, 1972, Biota of Freshwater Ecosystems, Water Pollution Control Research
    Series, 18050 ELD 05/72, Manual No. 1-10.

Fisher, H.B., et al., 1979, Mixing in Inland and Coastal  Waters, Academic
    Press, Mew York, NY.

Gaetz, C.T., R. Montgomery, and T.W. Duke, 1986, Toxicity of Used Drilling
    Fluids  to   Mysids   (Mysidopsis   bahia),   Environmental   Toxicology   and
    Chemistry, 5: 813-821.

Hough, B.K., 1957, Basic Soils Engineering, The Ronald Press Company.

Independent Petroleum Association of America, 1986, The Oil and Gas Producing
    Industry in Your State, 1986-1987, Petroleum Independent, Washington, DC.

McWhorter, D.B. and J.D. Nelson, 1979.  Unsaturated Flow  Beneath Tailings
    Impoundments.  Jour. Geotech. Eng. Div. ASCE GT 11: 1317-1334.

Lee et al., 1980, Atlas of North American Freshwater Fishes.

Liu, H., 1977, Predicting Dispersion Coefficients of Streams, J. Environmental
    Engineering  Division,  Proceedings  of  the  American   Society   of  Civil
    Engineers, Vol. 103.

Mills et al., 1982, Water Quality Assessment:  A Screening Procedure for Toxic
    and  Conventional   Pollutants,   Part   1,   EPA   Office  of   Research   and
    Development, Athens, GA.
                                    IV-Ref-2

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National Water Well Association, 1985, DRASTIC:  A Standardized System for
    Evaluating Ground-Water  Pollution Potential  Using  Hydrogeologic Settings,
    PB85-228146,  Worthington, OH.

Neely, W.B., 1982, The Definition and Use of Mixing Zones, Environ. Sci.
    Technol. 16(9): 520A-521A.

Perrier, E.R. and G. Anthony, 1980, Hydrologic Simulation on Solid Waste
    Disposal Sites  (HSSWDS), U.S. Army  Engineer  Watimag Experiment  Station,
    Contract No.  EPA-IAG-D7-0101197.

Prickett, T.A., T.C. Naymik,  and C.G. Lonnquist, 1981.   A "Random-Walk" Solute
    Transport Model  for Selected Groundwater  Quality  Evaluations.   Bulletin
    #65, Illinois State Water Survey.

Rand, 1981, The Discovery of  Significant  Oil and Gas Fields in the United
    States, R-2654/l-USGS/DOE, Santa  Monica, CA.

Stickel, W.H.,  1984, Some Effects Of  Pollutants in Terrestrial Ecosystems,
    Proceedings  of the  NATO Science  Committee  Conference  of  Ecotoxicology,
    MontGabriel,  Quebec, Canada, May  6-10.
                                   IV-Ref-3

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                       Appendix  A











       SUMMARY OF STATE AND  FEDERAL REGULATIONS




                       RELATED TO




ONSHORE OIL  AND GAS EXPLORATION,  DEVELOPMENT, AND  PRODUCTION

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          SUMMARY OF STATE AND FEDERAL REGULATIONS




                         RELATED TO




ONSHORE OIL AND GAS EXPLORATION, DEVELOPMENT, AND PRODUCTION

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                             NOTICE
THE INFORMATION CONTAINED IN THIS APPENDIX HAS NOT YET BEEN
VERIFIED BY STATE AGENCIES.   WE INVITE THE COMMENTS OF STATE
AGENCIES ON THESE SUMMARIES.  SUGGESTIONS AND COMMENTS WILL BE
INCLUDED IN THE REPORT TO CONGRESS.  PLEASE SUBMIT COMMENTS TO:
               Susan L. de Nagy
               Industrial Technology Division
               U.S. Environmental Protection Agency
               401 M Street, S.W.
               Washington, DC  20460
                                  A-ii

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                        TABLE OF CONTENTS
SUMMARY OF STATE REGULATIONS 	  A-l
     ALABAMA	A-2
     ALASKA	  A-5
     ARIZONA	A-9
     ARKANSAS	A-12
     CALIFORNIA	A-16
     COLORADO	A-21
     FLORIDA	A-26
     ILLINOIS	A-29
     INDIANA	A-32
     KANSAS	A-35
     KENTUCKY	A-39
     LOUISIANA	'	A-42
     MARYLAND	A-46
     MICHIGAN	A-49
     MISSISSIPPI	A-54
     MISSOURI	A-58
     MONTANA	A-61
     NEBRASKA	A-64
     NEVADA	A-67
     NEW MEXICO	A-70
     NEW YORK	A-75
     NORTH DAKOTA	A-80
     OHIO	A-83
     OKLAHOMA	A-87
     OREGON	A-91
     PENNSYLVANIA  	  A-95
     SOUTH DAKOTA	A-99
     TENNESSEE	A-102
     TEXAS	A-105
     UTAH	A-110
     VIRGINIA	A-114
     WEST VIRGINIA	A-117
     WYOMING	A-120

SUMMARY OF FEDERAL REGULATIONS 	  A-125
     U.S. FOREST SERVICE   	A-126
     BUREAU OF LAND MANAGEMENT	A-l27
     U.S. ENVIRONMENTAL PROTECTION AGENCY, EFFLUENT
       LIMITATIONS GUIDELINES  	  A-131
     UNDERGROUND INJECTION CONTROL 	  A-134
                              A-iii

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SUMMARY OF STATE REGULATIONS
              A-l

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                             ALABAMA
INTRODUCTION

Alabama produced 8,438,000
barrels of oil and gas from 760
oil wells and 130 x 109 cubic
feet of gas from 509 conven-
tional gas wells and 184
coalbed methane wells in 1984.
Thirteen percent of conven-
tional oil and gas wells are
strippers; 52 percent of
coalbed methane wells are
strippers.

Alabama began limited
regulation of oil and gas
activities in 1946.
Regulations for disposal of drilling wastes were adopted in 1973.
Regulations and/or administrative codes have continued to be
revised during the forty years of regulation.
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activity in Alabama:

     -  Alabama State Oil and Gas Board
     -  Alabama Department of Environmental Management
     -  U.S. Bureau of Land Management
     -  U.S. Corps of Engineers

The Alabama State Oil and Gas Board is "charged with preventing
the waste of Alabama's oil and gas resources and protecting the
correlative rights of owners."  In carrying out its mandate, the
Board issues drilling permits for oil and gas operations through
the production phase.  The Oil and Gas Board has authority to
issue permits for UIC Class II wells.  The Oil and Gas Board
Administrative Code details statewide rules applicable to all
categories.  The Administrative Code is supported by Oil and Gas
Laws of Alabama (1975).

The Alabama Department of Environmental Management has the
authority to issue permits for all UIC wells other than Class II.
The Department of Environmental Management also has NPDES
authority.  The Oil and Gas Board and Department of Environmental
Management operate under a 1979 Memorandum of Agreement which
requires the Board to forward information regarding actual or
proposed discharges to  the Department of Environmental
Management.
                                 A-2

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The U.S. Bureau of Land Management, authority and regulations for
Federally-held mineral rights are discussed separately under
Federal Agencies.  The U.S. Forest Service retains surface rights
(and usually coordinates stipulations with the Bureau of Land
Management) in Federal forests and grasslands.


STATE RULES AND REGULATIONS

DRILLING

Drilling pits are permitted by the Oil and Gas Board.  The Board
has certain construction requirements to ensure the integrity of
the pit.  Pits are closed by dewatering (see below), then
backfilling, leveling, and compacting.

Drilling muds and pit fluids may be disposed in one of three
ways.  They may be injected into a formation below underground
sources of drinking water.  They may be transported to a drilling
mud treatment (recycling) facility.  In non-wetland areas, the
fluids may be applied to the land surface or into an approved
landfill if:

     - The chloride concentration is less than 500 mg/L
     - The Oil and Gas Board is properly notified
     - The landowner provides written approval
     - It is a one-time-only application
     - There will be no discharge to surface body of water

These activities are permitted by the Oil and Gas Board prior to
allowing disposal of fluids.


PRODUCTION

No discharge of produced water (brine) is allowed.  Class II UIC
wells are used for disposal of Alabama brines.

After conferring with EPA, EPA-Region IV has advised Alabama
authorities that coalbed methane production is not covered under
the Federal onshore oil and gas regulations.  Produced waters
from coalbed methane wells may be allowed to accumulate in lined
pits, settle, and then may be discharged directly into live
streams.
                                 A-3

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REFERENCES

State Oil and Gas Board of Alabama, Submittal to EPA
     Regarding Onshore Oil and Gas Subcategory,  March 1985.

State Oil and Gas Board of Alabama Administrative Code,
     general order prescribing rules and regulations
     governing the conservation of oil and gas in Alabama
     and oil and gas laws of Alabama with Oil and Gas' Board
     forms, Oil and Gas Report 1, 1983.

Alabama Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas Workshop, U.S. EPA,Washington,D.C.(March
     26-27 in Atlanta, GA) .
                                 A-4

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                             ALASKA
INTRODUCTION

Alaska produced 617,606,000
barrels of oil and 300 x 109
cubic feet of gas in 1984.
Production is from 864 oil
wells and 81 gas wells.  Alaska
is second in U.S. oil
production but twenty-third in
the number of producing oil
wells. It ranks eighth in U.S.
gas production and twenty-
fourth in the number of
producing gas wells.

Alaska has two main oil and gas development areas:   the South
Central area and the North Slope area.  The South Central area
includes Cook Inlet and the Kenai Peninsula.  There are 13 oil
platforms and one gas platform in Cook Inlet.   These wells are
considered to be in the Coastal Subcategory.

The Kenai Peninsula produces mostly gas with little associated
brine.  Brines are primarily reinjected.  Drilling muds present a
larger problem in the Kenai Peninsula.  Three to four hundred
wells, mostly onshore, have been drilled.   Most of the reserve
pits have been unregulated.

The North Slope sends about 1.5 million barrels of oil down the
pipeline per day from three producing units (Kuparuk, Prudhoe,
and Milne Point).  There is a lot of exploration occurring on the
North Slope and the exploration is moving east toward the
Canadian border.
STATE REGULATORY AGENCIES

Five agencies regulate oil and gas activities in Alaska:

          Alaska Oil and Gas Conservation Commission
          Alaska Department of Environmental Conservation
          U.S. Bureau of Land Management
     -    U.S. Fish and Wildlife Service
          Alaska Department of Natural Resources

The Oil and Conservation Commission permits wells regarding
conservation of resources.  It checks well casings to prevent
contamination of water and the Commission has primacy for the UIC
Class II program.  Section 31.05.009 of Title 31 of Alaska
Statutes established membership of the Oil and Gas Conservation
                                 A-5

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Commission to three members appointed by the Governor.   There is
a compliance bond of $100,000 for an individual well or $200,000
for a blanket bond.

The Alaska Department of Environmental Conservation regulates
waste disposal and issues permits regarding waste disposal.

The U.S. Bureau of Land Management is responsible for all oil and
gas activity on Federal lands.  There are 370 million acres  of
land in Alaska, of which 250 to 200 million are Federal acres.
There are 150 producing oil and gas wells on Federal leases.  The
BLM works closely with the Alaska Department of Environmental
Conservation to regulate these wells.  Regulatory processes  for
oil and gas operations are covered in Onshore Oil and Gas Order
No. 1 and Regulation 43 CFR 3160.

The U.S. Fish and Wildlife Service has been conducting research
related to the permitted discharge of drilling and production
fluids to the tundra wetlands.  The research project currently in
progress is designed to determine the deleterious nature of  the
discharge to wildlife in wetlands, especially the waterfowl.

The Department of Natural Resources distributes leases for wells
on State land.  Stipulations are made to environmental concerns,
such as requiring that reserve pits be rendered impermeable  or
denying the discharge of produced waters to the tundra, at lease
award.
STATE RULES AND REGULATIONS

DRILLING

Existing drilling pits and reserve pits are not lined.  Many are
located in wetlands.  The Department of Environmental Conser-
vation is moving toward reducing pit sizes, subgrading pits to
enhance freezeback, injecting liquids, and capping pits to
prevent ponding.  Currently, everything is put in reserve pits
including materials from mouse holes, rat holes,  sewage, and
other wastes.  Waste segregation and separate waste treatment
with fluid injection is a Department goal.

With pit closure, pits must be dewatered, stabilized to hold the
cover, and covered.  Fluids often are reinjected down an annulus
in a nearby exploratory well.
PRODUCTION

Production fluids have been injected, used on roads, or
discharged to the tundra.  The department is moving toward
reinjecting the fluids, and the use on roads is being considered
carefully because of potential pollution problems.
                                 A-6

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There are two general wastewater disposal permits issued under
Alaska Statute 46.03 of the Alaska Administrative Code.  These
discharges are considered minor discharges by the U.S. Environ-
mental Protection Agency and thus do not require an NPDES permit.
The permits are for discharges from onshore reserve pits used for
storage of produced water, drilling fluids and cuttings, boiler
blowdown, rig washing fluids, and completion fluids.

In 1985, 36 million gallons were discharged from 43 r'eserve pits.
Of the 43 pits, 35 violated permit limits; of the 35,  16 were in
violation of the manganese limit only.  Manganese was  deleted
from the 1986 permit because of high levels found naturally in
the North Slope.  Discharge is to the tundra.

The permit discharge limits are:

     pH                            6.5 to 8.5
     Chemical oxygen demand        200     mg/1
     Settleable solids               0.2   mg/1
     Oil and grease                 15     mg/1
     Total aromatic hydrocarbons    10     /ug/1
     Arsenic                         0.05  mg/1
     Barium                          1.0   mg/1
     Cadmium                         0.01  mg/1
     Chromium                        0.05  mg/1
     Lead                            0.05  mg/1
     Mercury                         0.002 mg/1

The environmental effects of large-scale reserve pit fluids
disposal to the tundra are unknown.  Annually, 31 million gallons
of the fluids, which originate from drill muds, workover fluids,
snow melt, and other sources, must be disposed of from the pits.
Alternatives to tundra disposal include dedicated disposal wells
on the North Slope.  Trucking is usually needed to get the muds
to one of the dedicated disposal wells.  To avoid trucking
associated with injecting down one of the dedicated wells, it is
often possible to inject down the annulus of the well  being
drilled or another well on the pad.  The annulus of these wells
usually terminates at the bottom of the permafrost layer, about
2,000 feet below the ground surface.  These are short-term
options, as the annulus must soon be cemented closed to preserve
the integrity of the permafrost and prevent collapse of the
well.  Once cemented closed, it cannot be reopened.


OFFSITE AND COMMERCIAL PITS

Hauling from two or three well sites to another pad has been
allowed to concentrate wastes at one site.

Presently, there are no offsite and commercial pits.  There was
one commercial pit, but it was closed because of pollution
problems; the case is in litigation.
                                 A-7

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REFERENCES

Alaska Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas State/Federal Western Workshop.   U.S.
     Environmental Protection Agency,  Washington, D.C.
     (December 1985).

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Regulations, Alaska Administrative Code, Title 20, Alaska
     Oil and Gas Conservation Commission, April 2, 1986.

Alaska Statutes, Title 31, Chapter 05, Alaska Oil and Gas
     Conservation Act.

Fristoe, Bradley R.  1985.  Letter Communication to EPA.
     State of Alaska Department of Environmental
     Conservation.

Personal Communications:

     Dan Wilkerson, Alaska Department of Environmental
     Conservation  (907) 274-2533.

     Doug Redburn, Chief of Water Quality Management Section,
     Juneau (907) 465-2666.
                                 A-8

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                             ARIZONA
INTRODUCTION

Arizona produced 214,000
barrels of oil and 225 MMCF of
gas in 1984.  Production was
from 26 oil wells and 5 gas
wells.  All brines are
reinjected and all drilling
fluids ^go to reserve pits.
Approximately 655 bbls/day of
brines are produced in the
State per day.  Arizona does
not have NPDES or UIC program
primacy.
REGULATORY AGENCIES

There are five agencies that regulate the oil and gas industry in
Arizona:

          U.S. Bureau of Land Management
     -    U.S. Bureau of Indian Affairs
          Arizona Oil and Gas Commission
          Arizona Department of Health and Safety
          EPA, Region IX


The Bureau of Land Management has the authority to issue oil and
gas drilling permits for Federal minerals.  Where Indian mineral
rights prevail, oil and gas activity may be governed by both the
BLM and the Bureau of Indian Affairs.

The Arizona Oil and Gas Commission reviews all oil and gas
drilling applications and is primarily responsible for approving
and enforcing oil and gas activities.  The Oil and Gas
Commission's regulations pertain to the construction, location,
and operation of onsite drilling and production activities.

The Department of Health and Safety Coordinates with EPA's Region
IX for any surface water discharge or underground injection
permit.  Region IX administers the UIC program; there are no
discharges from oil and gas facilities.
                                 A-9

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STATE RULES AND REGULATIONS

Arizona's Official Compilation of Administrative Rules and
Regulations, Chapter 7, Oil and Gas Conservation Commission,
states in Section R12-7-140 that, "The owner or operator shall
take all reasonable precautions to avoid polluting streams,
polluting underground water,  and damaging soil."  These
regulations govern all construction, binding, well spacing,
reporting, and abandonment procedures for oil and gas activities.
Permit requirements for injection wells are specified, but the
substance to be injected is not mentioned.  Section R12-7-108
states that, "In order to assure a supply of drilling mud to
confine oil, gas or water to its native stratum during the
drilling of any well, operators shall provide, before drilling is
commenced, an adequate pit, either earthen or portable, for the
drilling mud or the accumulation of drill cuttings."
                                 A-10

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REFERENCES

Ray Brady, Deputy State Director,  Division of Mineral
     Resources.  Letter to EPA.  September 4, 1985.

Official Compilation of Administrative Rules and Regulations
     for Arizona, Chapter 7,  Oil and Gas Conservation
     Commission,  Article 1.  Oil,  Gas and Helium.  1975.

Personal Communications:

     Lyndon Hammon,  NPDES Permits Section Manager,  Arizona
     Department of Health and Safety.  September 29,  1986
     (602) 257-2262.

     Nate Lau, Director of the UIC Division, EPA Region IX.
     September 28, 1986 (415) 974-0893.
                                 A-11

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                            ARKANSAS
INTRODUCTION

Arkansas produces 17,618,000
barrels of oil and 162,678 MM
cubic feet of gas each year.
Production is from 9,490 oil
wells and 2,492 gas wells.  The
State is divided into two
geographical districts.  The
Arcoma Basin, located in the
northwest corner of the State,
produces 99 percent natural gas
on a volume basis.  The
Mississippi Embayment in
southeastern Arkansas produces
approximately 90 percent oil
and 10 percent gas.
STATE REGULATORY AGENCIES

Two agencies regulate oil and gas activity in Arkansas:

     -  Arkansas Oil and Gas Commission
     -  Arkansas Department of Pollution Control and Ecology

The Arkansas Oil and Gas Commission, a division of the Arkansas
Department of Commerce, regulates industry practices regarding
drilling and production of oil and gas wells by means of
Statewide General Rules and Regulations Order No. 2-39.  The
General Rules and Regulations do not address all aspects of
industry practices, and refer the reader to "special rules
pertaining to individual oil, gas, or salt water fields and
pools."  Special rules of any non-emergency nature require a
public hearing, and are provided for in Rules A-2 and B-38 of the
General Rules and Regulations.  The reader of this document is
also advised that, "There is a considerable body of statutory law
in Arkansas that must be consulted in evaluating an oil and gas
matter," and is referred to the Arkansas Statutes, Annotated,
Title 53.

The Arkansas Department of Pollution Control and Ecology, a
division of the Water Pollution Control Commission, derives its
regulatory authority from Regulation No. 1, "Regulation for the
prevention of pollution by salt water and other oil field wastes
produced by wells in new fields or pools."   The regulation was
promulgated on October 13, 1958, pursuant to the authority
provided by Act 472 of the Acts of Arkansas for 1949, and is
currently being revised.  The updated regulation is being modeled
                                  A-12

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after Louisiana State Order No. 29-B,  and is expected to be
promulgated in 1987.

It is apparent from the regulations that there are areas in which
the responsibilities of these two agencies overlap.  "Memorandums
of Understanding" are on file that define the role of each agency
as it applies to oil and gas regulations.  For example,  the
Arkansas Oil and Gas Commission regulates underground* disposal of
salt water, and the Arkansas Department of Pollution Control
regulates surface discharges of salt water.  The state does not
have NPDES delegated authority.


STATE RULES AND REGULATIONS

DRILLING

Section 4 of Regulation No. 1 forbids discharging salt water from
an oil or gas well such that the salt water may come in contact
with "any of the waters of the State,  whether by natural
drainage, seepage, overflow, or otherwise."  Other sections of
Regulation No. 1 require the well operator to obtain a permit for
a waste disposal system that prevents the wastes from contacting
State waters.  The regulation provides two alternatives for salt
water disposal:  subsurface discharge in disposal wells con-
structed in accordance with the Rules and Regulations of the
Arkansas Oil and Gas Commission, and surface discharge into lined
earthen pits.

The Arkansas Department of Pollution Control and Ecology issues a
letter of authorization that serves as an informal permit for the
construction of reserve pits on drill sites.  The Department uses
the letter to clarify and add strength to the outdated Regulation
No. 1 which is currently being revised.  The letter lists
conditions which the Department of Pollution Control and Ecology
expects to be followed during drilling operations pertaining to
reserve pit construction, pit fluid and drilling mud disposal,
and drill site reclamation.

All earthen pits must be lined with a synthetic liner (20 mils
thick) or a clay liner (18 to 24 inches thick), and must maintain
at least 2 feet of freeboard.  Pits must be reclaimed to grade
and seeded within 60 days after the drilling rig has been removed
from the site.

Reserve pit wastes may be treated and land applied at the drill
site if they contain less than 2,000 mg/1 total dissolved solids,
and if they are treated.  Wastes having greater than 2,000 mg/1
TDS must be disposed of in State-permitted disposal wells.

The letter of authorization also states that completion fluids
high in total dissolved solids, such as KC1, should be kept
separate from the contents of the reserve pit, and recommends
that a lined pit be used for this purpose.
                                 A-13

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Disposal of reserve pit fluids and drilling mud requires a. permit
from the Arkansas Department of Pollution Control and Ecology.
The permit requires that the disposal company provide an analysis
of the pit fluids and drilling mud, the amount hauled, and its
final destination.  A disposal company that is permitted to land
apply pit fluid and drilling mud near the well must provide the
Department with a copy of the land owner's agreement "as well as
an analysis of the wastes.  An analysis of pit fluid will include
tests for chlorides and pH,  and a drilling mud analysis will
include tests for chromium,  zinc, chlorides, and pH.
PRODUCTION

Rule C-7 of the General Rules and Regulations defines the means
by which salt water produced from oil and gas wells may be
discharged into subsurface formations.  The Oil and Gas
Commission states that it will consult the State Geological
Survey and the State Board of Health, when reviewing an
application to inject salt water, in order to protect fresh water
supplies.  Disposal wells are to be cased and cemented "in such
manner that damage will not be caused to oil, gas or fresh water
resources."  The mechanical integrity of a disposal well is to be
tested prior to its first use, and at least once every 5 years
thereafter.  A monthly salt water disposal report is required
that includes the amount of water injected, the injection
pressure, and the zone into which the salt water is injected.

The letter of authorization issued by the Arkansas Department of
Pollution Control and Ecology states that salt water produced any
time during the lifetime of a well will remain the responsibility
of the production company, and "shall be stored in a plastic or
fiberglass tank above ground and resting on a concrete pad."


OFFSITE AND COMMERCIAL PITS

State regulations do not address offsite and commercial pits.
                                 A-14

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REFERENCES

Personal Communication with Mr. David A. Thomas,  Arkansas
     Department of Pollution Control and Ecology, August ??,
     1986.  Telephone (501) 562-7444.

Arkansas Department of Pollution Control and Ecology,
     "Regulation No. 1,"  October, 1958.

Arkansas Oil and Gas Commission, "State of Arkansas Rules and
     Regulations Order No. 2-39," revised 1983.

Interstate Oil Compact Commission, The Oil and Gas Compact
     Bulletin, Volume XLIV, No. 2, December 1985.

Interstate Oil Compact Commission, Summary of State Statutes
     and Regulations for Oil and Gas Production,  June 1986.

U.S. Environmental Protection Agency, Proceedings; Onshore
     Oil and Gas State/Federal Western Workshop,  December 1985.

Letter of Authorization from Mr. David A. Thomas, Arkansas
     Department of Pollution Control and Ecology, to
     Mr. William S. Walker, Stevens Production Company,
     August 20, 1986.

Letter to Mr. Naresh R. Shah, West Virginia Department of Natural
     Resources Permits Branch, from Mr. Terry Muse, Arkansas
     Department of Pollution Control and Ecology, regarding
     Arkansas Water Permit No. 2839-W, March 2, 1984.
                                 A-15

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                           CALIFORNIA
INTRODUCTION

California produced 411,665,000
barrels of oil and 470 x 10'
cubic feet of gas in 1984.
California ranked fourth in
U.S. oil production and sixth
in U.S. gas production.
Production is from 48,908
producing oil wells and 1,220
producing gas wells.  Approxi-
mately 55 percent of the oil
production is attributed to
enhanced oil recovery.

At present, California has 10,652 Class II wells:   9,657 are
injecting fluids back into hydrocarbon producing zones;  971 are
water disposal wells.  Some of the water produced in association
with oil and gas in the San Joaquin Valley is of a good  quality.
In those cases, the water is cleaned up through filtration and
used for irrigation purposes.  Some waters produced in urban oil
fields are disposed into municipal sewer systems.

California has been injecting fluids into non-hydrocarbon-
producing zones of the Santa Maria Valley and the Salinas Valley
for many years.  Fluids from shallow, heavy oil steam flood
production is injected into other formations such as the Santa
Margarita.


STATE REGULATORY AGENCIES

Eight agencies regulate oil and gas activity in California:

     -    California Department of Conservation,
            Division of Oil and Gas
          California Water Resources Control Board with  the
            program administered through nine Regional Water
            Quality Control Boards
     -    State Lands Commission
          State Air Pollution Control Districts
          California Department of Fish and Game
     -    Local governmental agencies
          U.S. Bureau of Land Management
          U.S. Department of Energy

The California Division of Oil and Gas was created in 1915 by the
State legislature.  The Division was given the authority to
                                  A-16

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supervise the drilling, operation, maintenance,  and abandonment
of oil and gas wells to prevent,  as far as possible,  damage to
oil and gas deposits from infiltering water and other causes and
to prevent loss of oil and gas reservoir energy.

Since 1915, operators have been required to obtain a permit prior
to drilling, reworking, or abandoning a well.   At the time of
permit application,  engineers have prescribed well casing,
cementing, testing,  and/or plugging requirements.  In the early
1930s, additional legislation was passed that provided well
spacing and well bonding statutes.  At that time, the State Oil
and Gas Supervisor was mandated to prevent damage to underground
and surface waters suitable for irrigation or domestic purposes
from degradation from oil and gas operations.   The Division has
been delegated authority to issue UIC permits for Class II wells.

The Water Quality Control Boards  have statutory responsibility to
protect waters of the State and to preserve all present and
anticipated beneficial uses of those waters.  The Water Resources
Control Board has been delegated  authority to issue NPDES
permits.  The Division of Oil and Gas and the Water Quality
Control Boards have entered into  a Memorandum of Understanding to
provide a coordinated approach resulting in a single permit that
satisfies the responsibilities of each agency.  Basically, the
coordinated approach uses a method that provides the other agency
with the opportunity to comment on the proposed waste discharge
requirements.  A permit to discharge will not be issued unless
the concerns of each agency are satisfied.

For wells on State-owned, onshore lands, the State Lands
Commission has joint responsibilities with the Division of Oil
and Gas.  Their responsibilities  are expressed in the provisions
of the lease terms.

State Air Pollution Control Districts issue permits to operate
equipment that emits pollutants into the atmosphere.   The
equipment includes steam generators used for enhanced oil
recovery projects.

The California Department of Fish and Game provides comments and
recommendations on methods to mitigate any problems that oil and
gas operations may have on fish and wildlife.   They coordinate
State operations involving any spills that affect fish and
wildlife.

Cities and counties  also issue land use permits for oil and gas
operations.  Generally, a condition of their permit requires that
an operator comply with the Division of Oil and Gas regulations.

The Bureau of Land Management approves approximately 400 oil and
gas drilling permits per year on  Federal lands.   BLM has
approximately 350 water disposal  wells and approximately 500
earthen sumps for water disposal.  Presently,  there are 6,200
oil, gas, and injection wells on  Federal lands.   The oil and gas
                                 A-17

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wells produce approximately 22-1/4 million barrels of water per
month.  Most of this water is reused in steam flooding projects,
some goes into evaporation ponds, and some is reinjected for
water flooding projects.  Presently, the BLM and Division of Oil
and Gas are negotiating a Memorandum of Understanding under the
UIC program on Federal wells.

The Department of Energy manages the Elk Hills Naval "Petroleum
Reserves.  These fields produce approximately 80,000 barrels of
water per day, 133,000 barrels of oil per day, and 390 billion
cubic feet of gas per day, from 1,900 wells.  There are 13
injection wells and, during fiscal year 1985, 23 new wells were
drilled.  For fiscal year 1986, 36 new wells are planned.  The
Department of Energy's goal will be to stop the disposal of
produced water in sumps by the end of fiscal year 1986.  Pres-
ently, 1,400 barrels per day ar disposed into 34 earthen sumps.


STATE RULES AND REGULATIONS

Drilling muds are disposed at State-approved hazardous waste
disposal sites if the muds contain constituents considered to be
hazardous.  Nonhazardous muds can be left in a drilling waste pit
if the free liquid is removed and the solids and semisolids are
nonhazardous.  The drilling pit is reclaimed at the end of the
drilling operation.

Drilling pits may or may not need to be lined or sealed depending
upon their location.  The State agency doesn't prescribe pit
construction conditions.  The conditional use permit that a
driller obtains from each county generally details the pit
requirements.  If the fluids contain hazardous materials, the
pits would have to have liners.  At the completion of a well,
drilling fluids may be transported offsite generally to
evaporation sumps.

On Federal lands, drilling fluids are left in the sump until
completion of the well.  After completion of the well, drilling
fluids are hauled to a Class II disposal site for oil field
wastes.  Most of these sites are surface sumps.

Usually there is one pit for each drilled well but often portable
tanks are used in lieu of sumps.  Mud pits usually are in
existence until the time of well completion or abandonment in the
case of dry holes.  Brine pits are located only in areas where
percolation is allowed and they remain in existence as long as
needed.  Emergency pits are allowed as long as they are evacuated
and cleaned after any spill.
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PRODUCTION

Production waters are disposed approximately as follows:

     Evaporation in percolation sumps   -    18 percent
     Evaporation in lined sumps         -     6 percent
     To sewer systems                   -     2 percent
     To surface water                   -    18 perce.nt
     Underground injection              -    56 percent

The small percentage that goes to sewer systems.predominantly is
within the Los Angeles County Sanitation District.  Production
waters entering such sewers must meet applicable pretreatment
standards including a maximum oil and grease content of 75 mg/1,
heavy metals limits, cyanide, chlorinated hydrocarbons, and
sulfides.  There is no pretreatment limit for chloride.

Some production waters are permitted for discharge to waters of
the United States including principally irrigation canals,
ephemeral streams, and dry ditches.  There are at least 12 such
permits in the Fresno office of the Regional Water Quality Board.
There are a number of additional such discharges that currently
are pending a determination by the U.S. Environmental Protection
Agency.  Discharge permit limits include the following maximum
values:

          Electrical conductivity   1,000 p mhos
          Boron                         1 mg/1
          Chlorides                   200 mg/1
          Oil and grease               35 mg/1
OFFSITE AND COMMERCIAL PITS

On the western side of the San Joaquin Valley, there is a
wastewater disposal facility permitted on Federal land where the
oil industry has gotten together with a private consultant and
permitted a series of sumps that cover approximately 20 to 40
acres.  These sumps are used for percolation and evaporation.
BLM has some sumps on Federal leases that range up to roughly 5
acres.  The quality of groundwater on the west side is very poor.

Drilling fluids and production brines may be transported to
offsite and commercial pits.  Drilling fluids generally are
received by evaporation sumps, but many such sumps are used for
percolation and evaporation where fresh water sources are not
nearby.  A manifest is not required unless the material
transported is a hazardous waste.
                                 A-19

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REFERENCES

California Meeting Report.   1985.   Proceedings of the
     Onshore Oil and Gas State/Federal Western Workshop.
     U.S. Environmental Protection Agency,  Washington,  D.C.
     (December 1985).

Summary of State Statutes and Regulations for Oil and Gas
     Production.1986.Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.   1985.  Interstate Oil
     Compact Commission(December).

Mefferd, Marty.  1985.  Letter Communication to EPA.
     Supervisor, Division of Oil and Gas.

Personal Communications:

     Bob Reid, Division of Oil and Gas (916) 445-9686.

     Scott Smith, Central Valley Water Quality Board
     (209) 445-5116.

     Chong Rhee, L.A. County Sanitation District (213)  699-7411
                                 A-20

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                             COLORADO
INTRODUCTION

Colorado has a long history of
regulating oil and gas activ-
ities.  As far back as 1889,
Colorado passed a bill pro-
hibiting the discharge of oil,
petroleum, or other substances
into any waters of the State.
In 1950, a second bill was
passed 'that included provis-
ions for well plugging.  In
1951, the Oil and Gas Con-
servation Act was passed.  The
Solid Wastes Disposal Sites
and Facilities Act (Title 30-
20-Part 1, C.R.S. 1973, as
amended) also has juris-
diction.

In 1985, Colorado produced 38,584,000 barrels of oil from 5,287
wells; 271,544 million cubic feet of gas were produced from 4,665
gas wells.  Mud and air drilling are both encountered.
STATE REGULATORY AGENCIES

Three agencies share regulatory authority for oil and gas wastes
in Colorado:

     - Department of Natural Resources-Oil and Gas
         Conservation Commission
     - Department of Health
     - U.S. Bureau of Land Management

The Colorado Department of Natural Resources and Department of
Health share statutory and regulatory authority over oil and gas
activities in the State.  Two divisions of the Department of
Health梩he Water Quality Control Division/Commission and the
Waste Management Division梙ave statutory and regulatory
authority over solid waste disposal sites and facilities
(discharges and evaporation ponds, respectively).  The Oil and
Gas Conservation Commission is dedicated to prevention of wastes
and conservation of oil and gas; the Department of Health is
concerned with endangerment of public health or the environment.

The shared regulatory responsibilities between the Oil and Gas
Conservation Commission and the Department of Health were worked
out in a 1971 Memorandum of Agreement between the groups.  In
this agreement, primary responsibility for oil and gas activities
were delegated to the Oil and Gas Conservation Commission.  The
                                 A-21

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Department of Health retained the responsibility for offsite
disposal of oil and gas wastes.   The Department of Health has
since sought to update the Memorandum,  but the Oil and Gas
Conservation Commission has declined to change the agreement.  In
fact, the Oil and Gas Conservation Commission has recommended
that their authority be expanded to cover offsite pits,  ponds,
and lagoons (currently regulated by the Department of Health).

The Colorado Department of Natural Resources, Oil and Gas
Conservation Commission amended its rules and regulations
effective July 16, 1984.

The U.S. Bureau of Land Management has  jurisdiction over
Federally-owned mineral rights.   The U.S. Forest Service retains
surface rights on Federally-owned forests and grasslands.  Both
agencies are discussed separately under Federal Agencies.


STATE RULES AND REGULATIONS

DRILLING

Oil and Gas Conservation Commission rules provide that,  "Before
commencing to drill, proper and adequate slush pits shall be
constructed for the reception of mud and cutting and to
facilitate the drilling operation.  Special precautions shall be
taken to prevent contamination or pollution of state waters."
Rule 324 charges owners with the responsibility to take "such
precautions as necessary to prevent polluting the waters of the
state ... by oilfield wastes."  The rule does not contain
specific guidance regarding achievement of this goal.

Section 325 of the 1984 Rules and Regulations sets forth the
requirements for disposal of water produced with oil and gas
operations or other oil field waste into retaining pits.  The Oil
and Gas Conservation Commission requires demonstration (via
geological information, percolation tests, or other means) that
the proposed retention pond will not pollute surface or
groundwater.  The rule also requires chemical analysis of the
wastes to be stored and of the domestic water supply nearby.  No
provisions for pit closure are noted in the Commission's Rules
and Regulations.

The Oil and Gas Conservation Commission rules and regulations for
drilling coincide with Department of Health Rules and
Regulations, which are applicable for all waste impoundments.
The Department of Health regulations set forth site standards
(including engineering design, geologic, operational, hydrologic,
and other data) for all facilities.  For impoundments of oil and
gas wastes, the Department of Health considers facilities in
compliance if they are regulated by the Oil and Gas Conservation
Commission or if there is no endangerment of public health or the
environment.
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The Department of Health regulations also set standards for
closure of facilities.  These standards include provisions for
testing of remaining sludge for hazardous characteristics and
final disposal of the sludge.  The provisions are not reflected
in Oil and Gas Conservation Commission rules.

The Oil and Gas Conservation Commission rules have extensive
notification and construction requirements (including- spacing
requirements) for wells.

The Oil and Gas Conservation Commission requires lined pits for
5,000 mg/1 total dissolved solids waters.  Reserve pit sludge is
dried out and disposed of on the surface by tilling it into the
ground."  The sludge may be moved to a different location before
landfarming.  The Oil and Gas Conservation Commission does not
consider this practice land application discharge of drilling
fluids.  The Commission has permitted one facility for land
application discharge of wastes with limitations on total
suspended solids, total dissolved solids, oil and grease, and
chemical oxygen demand.
PRODUCTION

Oil and Gas Conservation Commission rules and regulations do not
distinguish between handling of produced waters and handling
other drilling or oil field wastes.

Produced water often is discharged under the provisions of the
BPT Wildlife and Agricultural Use Subcategory.  In some cases,
the well operator has been asked by the landowner to put an
accumulation sump and head gate in to allow build up of produced
waters before being used for watering cattle.


COMMERCIAL BRINE DISPOSAL FACILITIES

The Department of Health permits 10 to 15 commercial brine
disposal facilities to discharge under the BPT Wildlife and
Agricultural Use Subcategory.  These discharges must generally
meet the following limitations:

     -  6.0 >_ pH <_ 9.0
     -  Total suspended solids of 30 mg/1 30-day
          average (45 maximum one-day)
        Oil and grease less than 10 mg/1
     -  Total dissolved solids of 5000 mg/1 30-day
          average (7500 mg/1 maximum one-day)
     -  Some metals are limited by Water Quality
          Standards
                                 A-2 3

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Flows from these facilities are on the order of 10,000 gallons
per day.

Centralized pits are used for long term disposal in Colorado.
                                 A-2 4

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REFERENCES

Interstate Oil Compact Commission,  The Oil and Gas Compact
     Bulletin, Volume XLIV, No. 2,  December 1985.

U.S. EPA, Proceedings of the Onshore Oil and Gas
     State/Federal Western Workshop, December 1985. -

Colorado Department of Health.  Statement of the Colorado
     Department of Health for the Informational Hearing
     Regarding Oil and Gas Brine Waste Disposal to the
     Colorado Water Quality Control Commission.  May 10,
     1983.
       t,
State of Colorado.  Department of Natural Resources.  Oil
     and Gas Conservation Commission.  Rules and
     Regulations, Rules of Practice and Procedure, and Oil
     and Gas Conservation Act (As Amended).Effective July
 ^
 id	
16, 1984.
State of Colorado.  Regulations Pertaining to Solid Waste
     Disposal Sites and Facilities, Effective Date:  October
     1, 1984.
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                             FLORIDA
INTRODUCTION

Florida produced 14,090,000
barrels of oil and 15 x 109
cubic feet of gas in 1984.
Production was from 165 oil
wells; there are no producing
gas wells.  Virtually all
drilling fluids as well as
produced fluids are reinjected.
STATE REGULATORY PROGRAMS

Three agencies are primarily responsible for regulating the oil
and gas industry in Florida:

          Florida Department of Natural Resources, Division of
            Resources Management, Bureau of Biology
     -    Florida Department of Environmental Regulation
          Florida Regional Water Management Districts
          U.S. Environmental Protection Agency, Region IV

The Department of Natural Resources (DNR) is the permitting
agency for oil and gas wells, including approval to dispose of
waste fluids by subsurface injection.  The DNR regulates the
exploration, drilling, and production of the oil and gas industry
with respect to reporting, spacing, safety, and construction.

The Department of Environmental Regulation oversees the industry
with respect to water quality standards and dredge and fill
requirements (for pits) if oil and gas activities occur in waters
of the State.

Florida's Regional Water Management Districts, which are separate
regulatory groups on a local level, regulate oil and gas
activities with regard to water use.  Consumptive use permits are
issued if applicable.

Other State agencies may be involved on a case-by-case basis.
These agencies are the Florida Game and Freshwater Fish
Commission, the Department of Community Affairs, and the
Department of Transportation.

The State of Florida does not have primacy for Class II UIC
program wells.  The State operates a separate program for
injection wells with a State permit and State inspections.  A
driller wishing to inject fluids underground must apply for
permit to do so from two separate governmental entities, the U.S.
Environmental Protection Agency Region IV and the State, and
undergo two sets of inspections.
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STATE RULES AND REGULATIONS

Drilling fluids are put into pits during operation but then
disposed of by reinjection.  Pits are nearly dry when they are
backfilled.  All produced waters are reinjected.

The DNR is governed by Chapter 377, Florida Statutes, and its
implementing rules, Chapters 16C-25 through 16C-30, Florida
Administrative Code.  Part of Chapter 377's specific purpose is
to "require the drilling, casing, and plugging of wells to be
done in such a manner as to prevent the pollution of fresh, salt,
or brackish waters on the lands of the State."  And Section
377.371, further states that, "No person drilling for or producing
oili gas, or other petroleum products shall pollute land or
water; damage aquatic or marine life, wildlife, birds, or public
or private property."

UIC permits are issued pursuant to Chapter 403, Florida Statutes
and Chapter 17-28, Florida Administrative Code.  If applicable,
dredge and fill activities are regulated under Chapter 403,
Florida Statutes, Chapter 17-12 Florida Administrative Code, and
water standards are issued under Chapters 17-3 and 17-4, Florida
Administrative Code.  "Water management licenses (consumptive use)
are issued under Chapter 373, Florida Statutes, by the regional
Water Management Districts.
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REFERENCES

Lloyd Wise, Region IV NPDES permit writer, Summary of EPA
     Workshop presentation, Onshore Oil and Gas Workshop
     Meeting Report.  July 1985.

Lynn Griffin, Environmental Specialist, Department of
     Environmental Regulation.  Letter to W. A. Telliard,
     EPA, March 22, 1985.

State of Florida Regulatory and Review Procedures for Land
     Development.   Chapter 14.  November 1, 1984.

Personal Communication:

     Lynn Griffin, Environmental Specialist, Department of
     Environmental Regulation, October 2, 1986
     (904) 488-8615.

     David Curry,  Florida Department of Natural Resources
     (904) 487-2219.
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                            ILLINOIS
INTRODUCTION

Illinois produced 28,873,000
barrels of oil and 15 x 109
cubic feet of gas in 1984.
Production is from 28,920 oil
wells and 157 gas wells.  Nine-
teen barrels of brine are pro-
duced for every barrel of oil.
Twelve thousand injection wells
are operating in the State.
STATE REGULATORY AGENCY

Principally one agency regulates the oil and gas industry in
Illinois:

      -   Department of Mines and Minerals,  Division of Oil and
          Gas

The Department of Mines and Minerals operates under an Act in
Relation to Oil, Gas, Coal and Other Surface and Underground
Resources.  Section 8A of the Act provides the Department with
the power and authority to regulate the disposal of salt- or
sulphur-bearing water and any oil field waste produced in the
operation of any oil or gas well, and to adopt proper rules and
regulations relative thereto.  Section 8B provides that no person
shall drill, convert or deepen a well for the purpose of
injecting gas, air, water, or other liquid into any underground
formation or strata without first securing a permit therefor.
Section 8C(A) states that no person shall operate an oil field
brine transportation system without an oil field brine
transportation permit.  Section 8G(3) specifies that the
permittee shall not dispose of oil field brine onto or into the
ground except at locations specifically approved and permitted by
the Mining Board.  No oil field brine shall be placed in a
location where it could enter any public or private drain, pond,
stream or other body of surface or ground water.

The Division of Oil and Gas has UIC program primary for Class II
wells.  There are Federal lands in Illinois but there is no
drilling or production on Federal lands currently.  The Illinois
Environmental Protection Agency has been delegated NPDES
authority but no surface water discharges from the oil and gas
industry are allowed.
                                 A-29

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STATE RULES AND REGULATIONS

DRILLING

There are no State requirements that drilling pits be permitted
or lined.  Fluids from the pits may be disposed in a dry drill
hole.  When the pit mud dries,  the pit is back-filled and
reclaimed.  Pits must be reclaimed within 6 months after drilling
ceases.
PRODUCTION

Production fluids go to lined holding-evaporation ponds or they
are reinjected into certified injection wells.   The lining may be
clay or plastic,  but recently no requests for plastic-lined pits
have been received.  Requests now are for fiber glass or concrete
lined pits.  Earthen lined pits have been substantially
eliminated during the past 5 years.  The Department of Mines and
Minerals has been reducing the number of old pits by removing and
injecting the brines, stabilizing the contents, applying topsoil,
and vegetating the pit area.

Neither road spreading nor land farming is allowed.
OFFSITE AND COMMERCIAL PITS

Use is not made of offsite or commercial pits in the State of
Illinois.
                                 A-30

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.   1985.  Interstate Oil Compact
     Commission (December).

Illinois Meeting Report.  1985.   Proceedings of the Onshore Oil
     and Gas  Workshop.  U.S. Environmental Protection Agency,
     Washington, D.C.  (March 26-27 in Atlanta, GA).
       v
State of Illinois.  1984.  An Act in Relation to Oil, Gas, Coal
     and Other Surface and Underground Resources.Revised
     Edition.

State of Illinois.  1984.  Rules and Regulations.  Department  of
     Mines and Minerals, Division of Oil and Gas.  Revised
     Edition.

Personal Communication:

     George R. Lane,  Division of Oil and Gas (217)  782-7756.
                                 A-31

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                             INDIANA
INTRODUCTION

Indiana produced 5,394,000
barrels of oil and 394,000,000
cubic feet of gas in 1984.
Production was from 6,792 oil
wells and 2,294 gas wells.
STATE REGULATORY AGENCIES

Two agencies principally regulate oil and gas activity in
Indiana:

     -    Indiana Division of Oil and Gas
     -    U.S. Environmental Protection Agency,  Region V

The Indiana Division of Oil and Gas regulates the industry
through Rule 310 IAC 7-1.  No discharge to surface waters is
allowed so that any involvement of the Indiana Department of
Environmental Management would occur as a result of improper
disposal of oil and gas wastes.  Concerns that owners of Federal
lands may have regarding oil and gas surface treatment are
satisfied thorough conditions of the respective lease agreements

The Oil and Gas Division does not have primacy for UIC program
Class II wells.  The State is in the process of attaining such
status.  Currently, however, anyone interested in underground
injection must obtain two permits梠ne from the State, and one
from the U.S. Environmental Protection Agency.
STATE RULES AND REGULATIONS

DRILLING

Pits associated with drilling operations are allowed;  they are
small with a 250 cubic foot capacity,  approximately.  Drill pits
must be reclaimed within 60 days after drilling has stopped.
Fluids associated with such drill pits generally can be
                                 A-32

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classified as fresh-water and are mixed with bentonite clays.
When a pit is closed, the practice is to pump the small amount of
fluid in the pit to the surrounding land, bury the drill cuttings
and other pit muds, and reclaim the land.


PRODUCTION                                           . -

Pits used for gathering production fluids and storing them until
reinjection must be lined with impervious clay or an artificial
liner.  All production fluids must be reinjected underground.
Evaporation pits were disallowed by the State two years ago.


OFFSITE" AND COMMERCIAL PITS

There is one operating commercial injection well with associated
holding pits.  Some use is made by a producer at one well of
another's holding pits and injection well for produced fluids
disposal.
                                 A-33

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Personal Communication:

     Mike Nickolaus,  Indiana Division of Oil and Gas
     (ai7) 232-4055.
                                 A-34

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                             KANSAS
INTRODUCTION

Kansas produced 75,723,000
barrels of oil and 466.6 x 109
cubic feet of gas in 1984.
Production is from 57,633
producing oil wells and 12,680
gas wells.  Kansas ranks
seventh in both U.S. oil
production and U.S. gas
production.  There are 11,000
injection wells in the State.

Oil was found in Kansas in the
1860s, but it was not commer-
cially developed until 1895.
Oil and gas regulation began in
1935.
STATE REGULATORY AGENCIES

One agency regulates oil and gas activities in Kansas:

     -    Kansas Corporation Commission

One July 1, 1986, by passage of House Bill 3078,  the Kansas
Legislature transferred the Department of Health and Environment
responsibilities in oil and gas activities regulation to the
Kansas Corporation Commission.  Prior to July 1,  1986, the
Department of Health and Environment maintained certain
responsibilities related to lease maintenance, emergency pits,
drill pits, burn pits, and storage ponds.  Kansas Statute Chapter
55, Article 10, 55-1003 provided that for the disposal of oil and
gas brines and mineralized waters, the plans and specifications
for such were to be submitted to and approved by the State
Corporation Commission and the Secretary of Health and
Environment.  By legislative action, the Secretary of Health and
Environment no longer is a party to such action.

There are few Federal lands and little involvement of Indian
Tribes in the Kansas oil and gas industry.  The State informs
neither party directly when an application for a permit to drill
has been received.  Such information is published as a routine
matter in local news outlets, and if there are specified
requirements by the Bureau of Land Management or Indian Tribes,
they are communicated directly to the driller through lease
agreement condition or by other legal means.
                                  A-35

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STATE RULES AND REGULATIONS

DRILLING

Kansas Statute 55-156 states that prior to abandonment of any
well which has been drilled, is being drilled,  or may hereafter
by drilled, the operator shall protect usable groundwater or
surface water from pollution and from loss through downward
drainage by plugging the well, in accordance with the rules and
regulations adopted by the Commission.  Failure to comply with
these rules and regulations shall be a class E felony.

A compliance or surety bond is not required.  Regulation of the
industry is through the issuance of drilling and well operation
permits.  With the recent departmental transfer of responsi-
bilities, the Corporation Commission is in the process of
resolving issues, revising, and proposing regulations pertaining
to those activities formerly administered by the Secretary of
Health and Environment.

Drilling pits and burn pits have been regulated under a general
permit for a maximum period of 365 days unless the operator
requests and receives approval for an extension.  No application
for permit is required.  In the sandy soils of the State, such
pits would need to be lined.  In the heavy clay region of the
North-Central portion, for example, such pits most likely would
not be lined.

Permits are required for emergency pits but not reserve pits.  If
an emergency or reserve pit gets brine in it, it must be pumped
out upon termination of the emergency or completion of the well.
Kansas does not support transporting contents of reserve pits
upon closure to landfills in central locations.  Burial on site
is the primary method used.  There is no law requiring
backfilling of pits, but most of the lease agreements contain
that provision.  In geologically sensitive or hydrogeologically
sensitive areas, seals in drilling pits can be required and in
situ disposal of drilling pit contents can be prohibited.


PRODUCTION

Kansas Statute 55-901 provides that the owner or operator of any
oil or gas well which may be producing and which produces salt
water or waters containing minerals in an appreciable degree
shall have the right to return said waters to any horizon from
which such salt waters may have been produced, or to any other
horizon which contains or had previously produced salt water or
waters containing minerals in an appreciable degree, if the owner
or operator of such well makes a written application to the State
Corporation Commission for authority to do so and written
approval has been granted him or her after investigation by the
State Corporation Commission.  Salt water is defined as water
with greater than 5,000 mg/1 chlorides.  Spreading of salt water
                                 A-3 6

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on roads under construction is not prohibited if approval is
received from the Commission.  The Commission has primacy for UIC
Class II wells.

Requests for a surface pond permit are granted unless denied by
the Commission within 10 days.  According to proposed Rule 32-3-
600, the Commission, in approving applications for surface pond
permits, shall consider the protection of soil and water
resources from pollution.  Each operator of a surface pond shall
install observation trenches, holes, or wells if required by the
Commission, and seal the pond with artificial material if the
Commission determines that an unsealed condition will present a
pollution threat to soil or water resources.  Surface drainage is
to be prevented from entering the pond.  During the past two
years, it has become a practice, on a case-by-case basis, to
require monitoring wells in association with surface ponds.

There are approximately 25 permanent pits, receiving a total of
30 barrels of brine a day, mostly in the Southeast corner of the
State where there are no groundwater or seepage problems and
where chloride is quite low.  Surface discharges of produced
brine are not allowed nor is pit disposal allowed.

Upon the permanent cessation of the flow of fluids into any
surface pond, all fluids resulting from oil and gas activities
shall be removed to a disposal well approved by the Commission,
or used for road maintenance or construction if approved by the
Commission.  Pond solids may be transported to a permitted solid
waste landfill or to an approved offsite disposal area; however,
this latter condition of former Rule 28-41-5 and currently
proposed Rule 82-3-603 has not been used.
OFFSITE AND COMMERCIAL PITS

Use is not made of offsite or commercial pits.
                                 A-37

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REFERENCES

Kansas Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas State/Federal Western Workshop.   U.S.
     Environmental Protection Agency,  Washington, D.C.
     (December 1985).

Summary of State Statutes and Regulations for Oil and Gas
     Production.1986.Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission (December).

General Rules and Regulations, the State Corporation
     Commission of the State of Kansas (Effective May 1,
     1986).

Personal Communication:

     Jim Schoff, Kansas Corporation Commission (316) 263-3238,
                                 A-3 8

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                            KENTUCKY
INTRODUCTION

Kentucky produced 7,788,000
barrels of oil from 19,980 oil
wells and 61.5 x 109 cubic feet
of gas from 9,013 gas wells in
1984.
STATE REGULATORY AGENCIES

Five agencies regulate oil and gas activity in Kentucky:

          Kentucky Division of Oil and Gas
          Kentucky Department of Natural Resources and
            Environmental Protection
          U.S. Bureau of Land Management
          U.S. Army Corps of Engineers
          U.S. Environmental Protection Agency, Region IV

The Kentucky Division of Oil and Gas issues drill permits and
provides well casing and well plugging requirements.  The State
is seeking primacy but does not yet have primacy for the UIC
Class II well program.

The Kentucky Department of Natural Resources and Environmental
Protection has NPDES-delegated authority.  The Department issues
permits for holding pits containing production fluids and
instructions, pursuant to regulations, for pit construction.

The U.S. Army Corps of Engineers becomes involved in oil and gas
activities on lands maintained for water management projects.

The U.S. Environmental Protection Agency, Region IV, issues UIC
program Class II injection well permits.
                                 A-39

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STATE RULES AND REGULATIONS

DRILLING

Pursuant to Kentucky regulation 401 KAR 5:090,  there can be no
discharge from a pit without an NPDES permit.  Pits used to
contain drilling muds or fluids associated with drill-ing
activities do not have to have a permit for construction or
operation provided that the pit life is not longer than 30 days.
Where the pit life is longer than 30 days, a pit is defined as a
holding pit and a permit is required.  When a pit no longer is in
service, it must be backfilled and the land restored.  There are
no liner requirements for a pit with less than a 30-day life.
PRODUCTION

A holding pit with a life longer than 30 days must have a permit
and must be lined with a synthetic material of 20 mil minimum
thickness.  The State may grant an exemption to the lining clause
for pits that pre-existed the date of regulatory enactment.
Construction requirements include at least l foot of freeboard
and a 2-foot berm above ground around the pit.  Surface waters
must be diverted from the pit.

No NPDES permits have been issued for discharges from holding
pits.  However, the Department of Natural Resources and
Environmental Protection recently was sued and entered into a
consent decree which specified a water quality criterion of 600
mg/1 chlorides as appropriate for receiving water quality,  it is
anticipated that there will be a number of requests for NPDES
permits to discharge produced fluids.  Discharge constituent
limits will be a part of any permit issued.

Some holding pits are used as produced water storage pits until a
contract hauler transports the fluids for well injection or other
purposes.  There is no manifest system per se, but there is
registration of drilling fluid haulers with the Department and
there is reporting of the producer of the fluid and its
destination following transportation.  Most of the fluid goes
into injection wells.

There is no roadspreading or landspreading of produced fluids in
Kentucky.  Some use is being made currently of mechanical
evaporation.
                                 A-40

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REFERENCES

Summary of St.atie Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Personal Communications:

     Brian C. Gelpin, Kentucky Division of Oil and Gas
     (606) 257-3812.

     Brad Lambert, Kentucky Department of Natural Resources
     and Environmental Protection (502) 264-3410.
                                 A-41

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                            LOUISIANA
INTRODUCTION

Louisiana produced 449,545,000
barrels of oil and 5,867 x 109
cubic feet of gas in 1984.
Louisiana ranks third in U.S.
oil production and second in
U.S. gas production.  Over
half of Louisiana's 25,823 oil
wells are strippers.  More
than two-thirds of Louisiana's
14,436 gas wells are marginal
(produce less than 60 thousand
cubic feet of gas per day.)
Eighty five percent of all
produced fluids is salt water.

State statutes have regulated
drilling operations since
1950.  On January 20, 1986,
the Department of Conservation
promulgated amended rules and
regulations regarding "the
storage, treatment, and
disposal of non-hazardous
oilfield waste."
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activities in Louisiana:

     - Louisiana Department of Natural Resources
     - Louisiana Department of Environmental Quality
     - U.S. Bureau of Land Management
     - U. S. Corps of Engineers

The Louisiana Department of Natural Resources Office of
Conservation regulates all subsurface and surface disposal of
oil- and gas-associated wastes.  These powers were delegated to
the Office of Conservation under Title 30 of the Revised
Louisiana Statutes of 1950.  The Office of Conservation has been
granted primacy for all classes of UIC wells.

The Office of Conservation does not coordinate with EPA on NPDES
permits, but does coordinate with the Louisiana Department of
Environmental Quality, Water Quality Division, on any problem
discharges originating from oil and gas activities.
                                 A-42

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The Bureau of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands where the
mineral rights are federally held.  Surface rights in Federal
forests and grasslands are retained by the U.S. Forest Service.
These rules, regulations, and orders are discussed in a separate
section, Federal Agencies.  The Bureau of Indian Affairs has some
jurisdiction in limited areas of Louisiana.          ;
STATE RULES AND REGULATIONS

DRILLING
       <*
All pits must be lined such that the hydraulic conductivity of
the liner does not exceed 1 X 10"^ cm/s.  Liners may consist of
clays, soils, synthetics, or any combination meeting the 1 X 10~7
cm/s limitation.  Pits located within inland tidal waters, lakes
bounded by the Gulf of Mexico, and saltwater marshes are
excempted from the liner requirement provided they are part of an
approved treatment train for removal of oil and grease.  Natural
gas processing pits and compressor station pits are also
exempted.

Louisiana State Order No. 29-B contains pit construction and
closure requirements which are consistent with most States (i.e.,
2-foot freeboard,  pit closure within 6 months of completion,
prohibition of trash and produced water into reserve pits).  The
Order is unusual in the perspective it uses for these
requirements.  The Order is written specifically so that "pits
will be protected from surface waters."  Another aspect of the
Order is that it defines sixteen classes of oilfield waste
(including drilling fluids, produced fluids, workover fluids,
completion fluids, and others) as "non-hazardous oilfield
wastes."

Pit closure and land treatment facilities must meet certain
requirements for pH, electrical conductivity, and concentrations
of certain elements.  These requirements are set in Statewide
Order 29-B.  Reserve pits must be closed within 6 months of
reaching total depth during drilling.  Closure may be through
annular injection, injection down another newly-drilled well
which will be plugged, land treatment, solidified and buried
onsite, or offsite disposal at permitted commercial facilities.

Annular injection of reserve pit fluids is allowed whenever
surface casing is deep enough to protect underground sources of
drinking water.  Reserve pit solids may be transported offsite to
a permitted commercial treatment facility for treatment and
disposal.  A manifest system is enforced.
                                 A-43

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PRODUCTION

Produced waters must be disposed into subsurface formations
unless discharge is permitted under "applicable state or federal
discharge regulatory program."  Produced water may also be
treated and disposed by an approved commercial facility.
                                 A-44

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REFERENCES

Louisiana State Statutes 1950 30:204.

Interstate Oil Compact Commission,  Oil and Gas Compact
     Bulletin, Volume XLIV, No. 2, December 1985.

State of Louisiana Department of Natural Resources, Office
     of Conservation, "Amendment to Statewide Order
     No. 29-B,"  January 20, 1986.

Wascom, Carroll, D., "Oilfield Pit Regulations - A First for
     the  Louisiana Oil and Gas Industry," May 30, 1986.
                                 A-4 5

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                             MARYLAND
INTRODUCTION

Maryland produced 20 million
cubic feet of gas from 9 gas
wells, and no oil, in 1984.
STATE REGULATORY AGENCIES

Two agencies regulate oil and gas activities in Maryland:

          Department of Natural Resources, Bureau of Mines
          Department of Health, Office of Environmental
            Protection

The Department of Natural Resources regulates oil handling,
storage, and transportation.  Drilling permits are issued, and
site erosion is regulated.

All wastewater regulation is managed by the Department of Health.
Section 6-104 of the public general laws of Maryland provides
that a person may not dispose of any product of a gas or oil well
without a permit issued by the Department.  The Department has
both NPDES delegation and UIC program authority.


STATE RULES AND REGULATIONS

DRILLING AND PRODUCTION

Drilling and production wastes are managed by the Department of
Health, Office of Environmental Protection.  There is no
differentiation between pits that are associated with drilling or
production activities.

A pit may be lined with an impervious material such as clay or a
plastic to prevent groundwater pollution.  Fluids introduced to
                                 A-46

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lined pits generally are transported to a brine disposal facility
or to a sewage treatment plant, or they may be transported out of
State for disposal purposes.  There are no requirements on
thickness or type of pit liners.  There is no manifest system
associated with transporting gas wastes unless such wastes are
defined as hazardous.

Pits that are not lined must have a groundwater discharge permit
issued under Code of Maryland regulations.   The requirements
associated with pit contents that would meet permit conditions
for a groundwater discharge are determined on a site-by-site
basis.  If there is a discharge from a pit, an NPDES permit would
be required.

The State currently has neither issued an NPDES permit for
surface discharges nor a UIC permit for underground injection.
There is a groundwater discharge gas storage extraction facility
in the western part of the State that is permitted to discharge
about 1 million gallons per year.   The permit requires that the
first of a series of ten ponds be lined.  There are periodic
monitoring requirements for the ponds and in a nearby stream, but
there are no monitoring limits and no monitoring wells.


OFFSITE AND COMMERCIAL PITS

The only offsite pit used in the State is the one in Western
Maryland described above.  Some transported production fluids are
received by this facility.
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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission (December).

Personal Communications:

     Al Hooker, Department of Natural Resources, Bureau of Mines
     (3P1) 689-4136.

     Bob Creter and David Fluke, Department of Health, Office of
     Environmental Protection (301) 791-4787.
                                 A-4 8

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                            MICHIGAN
INTRODUCTION

Michigan produced 30,980,000
barrels of oil and 144.7 x 109
cubic feet of gas in 1984 from
3,848 stripper oil wells, 1,759
full-production oil wells, and
721 gas'wells.  In 1984, the
state ranked twelfth in U.S.
oil production and thirteenth
in U.S. gas production.  Oil
and gas production in Michigan
had been relatively constant
for the past 5 years, but more
recently oil production is down
because of declining crude oil
prices.

The first successful Michigan
oil well was drilled in 1886.
The first oil and gas drilling
permit was issued in 1927.
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activities in Michigan:

     -    Michigan Department of Natural Resources
          U.S. Forest Service
     -    U.S. Bureau of Land Management
     -    U.S. Environmental Protection Agency

The Michigan Oil and Gas Act of 1939 (PA 61) established the
Supervisor of Wells within the Geological Survey Division of the
Michigan Department of Natural Resources.  The prime regulator of
the oil and gas industry is the Supervisor of Wells.  The
Supervisor has authority to subpoena, to establish well spacing
requirements, to develop orders without legislative interference,
and to control disposal of solid and liquid wastes from drilling.
The Oil and Gas Act provides the Supervisor of Wells broad
authority to regulate the industry from "cradle to grave";  it
stresses "prevention of waste" from exploration to well aban-
donment.  The State requires a bond, an environmental assessment,
and spacing minimums.

The Water Resources Commission Act of 1929 (PA 245) regulates
discharges to and the pollution of any waters of the state;  it is
                                 A-49

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under Act 245 that National Pollution Discharge Elimination
System (NPDES) permits are issued.  Michigan is an NPDES
delegated state with such permits issued by the Surface Water
Quality Division of the Department of Natural Resources.  No
NPDES permits are issued for oil and gas wastes.

The Solid Waste Management Act of 1978 (PA 641) provides for the
licensing of solid waste disposal sites.

The State of Michigan does not require NPDES or landfill permits
for disposal of liquid or solid oil field drilling wastes; these
activities are regulated by the Supervisor of Wells.   Other
divisions of the Department of Natural Resources provide
assistance to the Geological Survey Division in enforcing the Act
by providing liaison with the Attorney General and with county
prosecutors for action by the local courts through cooperative
efforts of Department of Natural Resources law enforcement
conservation officers.  Where a groundwater problem has been
identified through investigation and monitoring by the Geological
Survey Division, and groundwater restoration is required, an
NPDES permit by the Water Quality Division is issued  on the
restored water.

When drilling is requested to occur on Federal lands, Federal
surface ownership often is severed from ownership of  mineral
rights.  When only surface rights are owned by the Federal
government, a copy of the drilling application is sent to the
Federal agency involved, generally the U.S. Forest Service.  Two
separate investigations then follow:  one by the Geological
Survey, and one by the U.S. Forest Service, which involves fish
and wildlife, geological, and other Federal experts.   A Federal
surface use permit then is issued.  The drilling application is
not approved by the State until all reviews have been completed
and pertinent comments made a part of permit conditions.  When
both surface and mineral rights are Federally owned,  a copy of
the drilling application is sent to both the U.S. Forest Service
and Bureau of Land Management.

The U.S. Environmental Protection Agency administers  the UIC
program for the State (40 CFR 147.1151).


STATE RULES AND REGULATIONS

DRILLING

A letter of instruction was issued by the Supervisor  of Wells on
April 6, 1981, which provided for a two-pit drilling  mud system
one for fresh water muds and one for salt water muds梐nd
required that all reserve pits receiving other than fresh water
fluids be lined with 20 mil PVC or an equivalent liner as
approved.  Instructions in 1985 require that all mud  pits be
lined with an impervious material that will meet or exceed
                                 A-50

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specifications for 20 mil virgin PVC.  Liners shall be one piece,
or with factory-installed seams, and shall be installed in a
manner sufficient to prevent both vertical and lateral leakage.

A revised Supervisor Instruction, effective February 1, 1985,
requires that cellars shall be sealed,  and rat holes and mouse
holes shall be equipped with a closed-end steel liner or
otherwise sealed or cased in such a manner that all fluids
entering the cellar, rat hole, and/or mouse hole shall not be
released to the ground but shall be discharged to steel tanks,
the lined reserve pit, or the mud circulation system.  Aprons  of
20 mil virgin PVC or other equivalent material shall be installed
under steel mud tanks and overlapping the mud pit apron, and in
ditches or under pipes used for brine conveyance from cellars  to
pits or to steel mud tanks.

Current required practice in Michigan is for the fluids in the
drilling pits to be pumped off prior to encapsulation of the pit
solids.  These pit fluids represent nearly 28 million gallons  per
year, and they have been used for drilling of additional wells,
disposed in approved brine disposal wells, or spread on roads  for
dust and ice control.  The best estimate for 1983 shows that 22
million gallons of pit brines were used for road dust and ice
control.  A Special Order of the Supervisor of Wells, issued
March 29, 1985, banned the use of pit brines for dust control
after September 1, 1985, and for ice control immediately.

For those pits that have been active since 1981, the fluid is
removed and the solids are encapsulated at the site with the
remaining PVC provided for such purpose, when a pit no longer  is
used.  For those pits that may have been abandoned, or that were
used prior to the Supervisor's Letter of Instruction, no action
is taken unless a contamination problem has surfaced.  When a
potential contamination problem exists, the site is investigated
by the Survey's groundwater unit.  If it can be shown that an
identifiable entity is responsible, damages are sought through
the courts.
PRODUCTION

Over 90 percent of Michigan's brines now are disposed of by
underground injection.  Earthen production pits are not allowed.
The Supervisor's Special Order of March 29,  1985,  requires that
produced brines not be used for ice control on roads and that
such brines meeting certain specifications for benzene, toluene,
and xylene content may be used for dust control under certain
testing and approval conditions until December 31,  1987.  None is
to be used for such purpose after January 1, 1988.
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OFFSITE AND COMMERCIAL PITS

No use is made of offsite or commercial pits in Michigan.  Rule
601 of Michigan's Oil and Gas Regulations provides that brine or
salt water resulting from oil and gas drilling and producing
operations shall be stored, transported, and disposed of in such
manner as may be approved by the Supervisor.  Any brine disposal
procedure which results or may result in the pollution of surface
or underground fresh water resources is prohibited.
                                 A-52

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REFERENCES

Crabtree,  Allen F.  1985.  "Drilling Mud and Brine Waste
     Disposal in Michigan."  Paper presented at the
     Reclamation Review Technical Advisory Committee
     Seminar/Workshop on Gel and Saline Based Drilling
     Wastes,  Edmonton, Alberta,  Canada, April 24,  1985.

Supervisor of Mineral Wells Instruction 1-84.  "Use of
     Liners in Earthen Drilling Pits, Sealing of Cellars,
     Rate Holes, Mouse Holes and other Procedures to Protect
     Ground Waters," effective February 1, 1985.

Order of the Supervisor of Wells, Special Order 1-85, dated
     March 29, 1985.

Summary of State Statutes and Regulations for Oil and Gas
     Production.1986.Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission (December).

Debrabander,  S.  1985.  Letter Communication to EPA.
     Geological Survey Division, Michigan Department of
     Natural Resources.

Michigan Meeting Report.  1985.   Proceedings of the Onshore
     Oil and Gas Workshop.  U.S. Environmental Protection
     Agency,  Washington, D.C. (March 26-27 in Atlanta, GA).

Personal Communications:

     Bill Shaw, DNR Office of Water Quality (517)  373-8088.

     Steve Debrabander, DNR Geological Survey Division
     (517) 334-6976.

     Rex Tefertiller, Permits, Geological Survey Division
     (517) 334-6974.
                                 A-53

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                           MISSISSIPPI
INTRODUCTION

Mississippi produced 31,879,000
barrels of oil in 1984 from
3,569 oil wells; 210 x 109
cubic feet of gas were produced
from 715 gas wells.
STATE REGULATORY AGENCIES

Four agencies regulate the oil and gas activity in Mississippi:

          State Oil and Gas Board
     -    Mississippi Department of Natural Resources, Bureau of
            Pollution Control
     -    Department of Wildlife Conservation
     -    U.S. Environmental Protection Agency, Region IV

The State Oil and Gas Board regulates the oil and gas industry
"to prevent the pollution of freshwater supplies by oil, gas or
saltwater" and to promote, encourage, and foster the oil and gas
industry (Section 53-1-17, State Statutes).  The Oil and Gas
Board does not have UIC program authority.

The Department of Natural Resources, Bureau of Pollution Control,
is responsible for the investigation of water pollution and for
the issuance of NPDES permits.  No NPDES permits are issued for
the onshore oil and gas industry.

The Department of Wildlife Conservation is responsible for the
maintenance of fish and wildlife within the State.

The U.S. Environmental Protection Agency, Region IV, issues UIC
program Class II injection well permits for Mississippi.  In this
activity area, the State Oil and Gas Board maintains a separate
well injection permitting program; a well operator must obtain an
injection permit both from the State and Federal Governments.

A 1982 Memorandum of Agreement among the Department of Natural
Resources, Department of Wildlife Conservation, and the State Oil
and Gas Board coordinates the activities of the three State
                                  A-54

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agencies related to the oil and gas industry.  The Agreement
ensures that the Mississippi Commission on Wildlife Conservation
has an opportunity to review the drill plan,  as drilling may
impact the sensitive environmental nature of the States's wetland
resources.  The Agreement, further, allows for suspension of
operations by the Oil and Gas Board where any signatory agency
determines such operations to be in violation of applicable laws
or regulations.


STATE RULES AND REGULATIONS

DRILLING

Rule 63 of the State Oil and Gas Board provides requirements
related to pits.  There are generally four types of pits (other
than reserve pits) permitted in Mississippi:

1.   Temporary saltwater storage pits are allowed at remote
     sites.  These must be lined, diked, and drained.  They
     are not allowed to be filled more than 2 feet from the
     top.  Regular inspections are required.   The permit is
     good for 1 year.  Only three such permits have been
     issued in the last 4 years.

2.   Emergency pits are not required to be lined.  They are
     permitted for 2 years.  Three or four of these pits may
     be permitted in a field.  Level must not exceed 1 foot
     in these pits.  Whenever the pit is used, the Oil and
     Gas Board must be notified within 48 hours, and they
     will inspect the pit.

3.   Burn pits are used to burn tank bottoms on site.

4.   Well test pits are used only for test purposes.  These
     are used rarely.

The use of drilling reserve pits or mud pits does not require a
special permit; the permit to drill constitutes the permit for
the drilling reserve pit.  This type of pit is subject to strict
stipulations regarding backfilling when drilling is completed.
Rule 63 was promulgated to prevent waste by pollution of air,
fresh waters, and soils.  Extensive management conditions are
presented in the Rule with each of the above pit descriptions.

Mississippi allows annular reinjection of drilling fluids.   Seven
annular reinjection wells are operating in Mississippi.  These
are used only when no other economical disposal method is avail-
able.  Mississippi requires radiological surveys of annular
reinjection wells every 6 months to determine where the rein-
jected fluids are going.  Pit muds may be pumped into a dry well
hole, or they most often are buried on site.   Land farming is
used in Mississippi.  Muds act as a low-grade fertilizer.
                                 A-5 5

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PRODUCTION

Production fluids are reinjected.  Reinjection of brines is
operationally feasible state-wide.  Since 1978, no method of
brine disposal other than reinjection has been considered
acceptable in Mississippi.


OFFSITE AND COMMERCIAL PITS

Except for two commercial pits in Southern Mississippi,  both of
which are phasing down, use is not made of offsite and commercial
pits within the State.
                                 A-56

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production"!  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Mississippi Meeting Report.  1985.  Proceedings of the
     Onshore Oil and Gas Workshop.  U.S. Environmental
     Protection Agency, Washington, D.C.  (March 26-27 in
     Atlanta, GA).

Statutes and Statewide Rules and Regulations, State of
     Mississippi, State Oil and Gas Board, Revised 7/1/86.

Personal Communication:

     Richard Lewis, Mississippi Oil and Gas Board
     (601) 359-3725.

     Jerry Cain, Mississippi Department of Natural
     Resources, Bureau of Pollution Control (601) 961-5073.
                                 A-5 7

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                            MISSOURI
INTRODUCTION

Missouri produced 131,000
barrels of oil from 557 oil
wells and no gas in 1984.  The
State has 9 evaporation pits
and 229 injection wells.  In
1984, Missouri had a total of
1.9 million barrels of produced
waters and 2.6 million barrels
were injected.  The reason for
injection exceeding production
is that two major steam oper-
ations import fresh water to
steam out the oil, which re-
sults in an increased quantity
of injectable fluids.  Missouri
has not had gas production
since 1977.
STATE REGULATORY AGENCIES

Three agencies regulate oil and gas activities in Missouri:

     -    Department of Natural Resources,  State Oil and Gas
            Council
     -    U.S. Bureau of Land Management
     -    Department of Natural Resources,  Division of
            Environmental Quality

The State Oil and Gas Council was formed by Rule 10 CSR 50-1.010
and is composed of the executive heads of the Division of Geology
and Land Survey, Division of Commerce and Industrial Development,
Missouri Public Service Commission, Clean Water Commission, the
University of Missouri, and two persons knowledgeable of the oil
and gas industry appointed by the Governor with the advice and
consent of the Senate.  The State geologist is charged with the
duty of enforcing the rules, regulations, and orders of the
Council.  The State has primacy for UIC program Class II wells.

Federal lands in Missouri are confined to U.S. Air Force bases.
There is drilling on such lands.  When a request for a permit to
drill is received, the Bureau of Land Management prepares the
draft permit, which is issued by the State Oil and Gas Council.
                                 A-5 8

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The Department of Natural Resources,  Division of Environmental
Quality becomes involved only when there is a breach of a pit
dike because of heavy rains,  or because of another reason,  and a
spill of fluids occurs.  Appropriate action under the Division of
Environmental Quality regulations then occurs.


STATE RULES AND REGULATIONS

DRILLING

Rule 10 CSR 50-2.040 provides requirements during the drilling of
wells to prevent contamination of either surface or underground
fresh water resources.  There is a bonding requirement before
commencing oil or gas drilling operations, and all wells must be
plugged when abandoned.

There are no regulations related to drill pits.  Drill pits are
not lined.  When pit muds dry, the muds are buried on site.


PRODUCTION

There are no regulations related to construction of evaporation-
percolation pits for produced waters.  About a third of the
produced waters are allowed to evaporate-percolate in such pits,
much of the produced water is injected into a Class II well,  and
some of it is trucked off property.


OFFSITE AND COMMERCIAL PITS

Some of the produced fluid is trucked off the property associated
with the producing field.  Some may cross a State line.  There is
no manifest required of the transported fluids.
                                 A-59

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Missouri Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas State/Federal Western Workshop.  U.S.
     Environmental Protection Agency, Washington, D.C.
     (December 1985).
       v

Rules and Regulations of Missouri Oil and Gas Council, June
     1985.

Personal Communication:

     Kenneth Deason, Missouri Oil and Gas Council (314) 364-1752
                                 A-60

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                             MONTANA
INTRODUCTION

Montana produced 29,762,000
barrels of oil and 56.9 x 109
cubic feet of gas in 1984.
Production is from 4,665 oil
wells and 2,152 gas wells.  A
total of 622 wells were drilled
for oil and gas in 1985.  About
320,000 barrels of brine per
day are produced from the
approximately 1,600 full
producing oil wells.  The
remaining stripper wells
produce about 40 barrels each
of brine per day.
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activities in Montana:

          Montana Department of Natural Resources and
            Conservation, Oil and Gas Conservation Division
          Montana Department of Health and Environmental
            Sciences, Water Quality Bureau
          U.S. Environmental Protection Agency,  Region VIII
     -    U.S. Bureau of Land Management

The Oil and Gas Conservation Division issues drilling permits and
regulates the oil and gas industry in Montana.  There is a
compliance bond.  Montana does not have primacy for the UIC
program.

The Montana Department of Health and Environmental Sciences,
Water Quality Bureau, controls water quality issues.  The Bureau
has primacy for the issuance of NPDES permits.

Region VIII of the Environmental Protection Agency issues UIC
permits for the injection of brines in Montana.

The Bureau of Land Management uses their own form for drilling
permits; thus, a driller must obtain a State as well as a Federal
permit to drill for oil or gas on Federal lands.  The Oil and Gas
Conservation Division has a cooperative agreement with the Bureau
of Land Management regarding treatment of Indian lands. Normally,
the State issues the permits to drill on Indian lands.
                                  A-61

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STATE RULES AND REGULATIONS

DRILLING

Permits are not required for drilling pits.   If a dry hole is
encountered, fluids from the drill pit normally are pumped to the
drill hole prior to well plugging.  Or,  the  liquids may be moved
to an oil field reserve pit.  The pit solids are allowed to dry,
the pit is closed,  and the surface reclaimed.


PRODUCTION

Rule 36.22.1227 of the Board of Oil and Gas  Conservation states
that salt or brackish water may be disposed  of by evaporation
when impounded in excavated earthen pits which may only be used
for such purpose when the pit is underlaid by tight soil such as
heavy clay or hardpan.  At no time shall salt or brackish water
impounded in earthen pits be allowed to escape over adjacent
lands or into streams.  Rule 36.22.1228 allows salt water to be
injected into the stratum from which produced or into other
proven saltwater-bearing strata.

The lining requirement of production reserve pits is decided
case by case, based upon soil composition, slope, drilling
fluids, and proximity to water sources.   Fluids may be removed
from reserve pits by several methods.  One method is to remove
fluids by truck and haul them to another drill site or disposal
facility.  No manifest is required for transporting fluids.
Another method is to allow fluids, other than oil, to remain in a
reserve pit for up to a year for evaporation.   Most produced
water is reinjected underground.  Another method is to chemically
treat the fluids so that they may be used for beneficial
purposes.  After the fluids have been removed, the remaining
solids are left to dry before backfilling.  If a plastic liner
has been used, it is folded into and buried  in the reserve pit.

NPDES discharge permits are issued by the Water Quality Bureau of
the Montana Department of Health and Environmental Sciences for
10 to 12 production reserve pits under the beneficial use
provision of the wildlife and agricultural use subcategory.  Of
those issued, only about two of the permitted facilities
discharge.  Discharges are to a closed basin in the northern part
of the State.  Discharge limits include total dissolved solids of
less than 1,000 mg/1 and an oil and grease of 15 mg/1 absolute
with an average of 10 mg/1.  Other discharge limits including
phenols and metals are imposed.


OFFSITE AND COMMERCIAL PITS

Use is not made of offsite and commercial pits in Montana.
                                 A-62

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.   1985.  Interstate Oil
     Compact Commission (December).

Personal Communications:

     Charles Maio,  Administrator,  Board of Oil and Gas
     (406) 656-0040.

     Abe Horpestad, Water Quality Bureau (406) 444-2459.
                                 A-63

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                            NEBRASKA
INTRODUCTION

Nebraska produces 6,470,000
barrels of oil and 2,347 MM
cubic feet of gas each year.
Production is from 2,072 oil
wells and 18 gas wells.  Most
of the State production is in
two areas: the five county area
in the Denver Basin, and Red
Willow and Hitchcock Counties.
Strippers account for about 85
percent of the State
production.
STATE REGULATORY AGENCIES

Three agencies regulate oil and gas activity in Nebraska:

     -    Nebraska Oil and Gas Conservation Commission
          Nebraska Department of Environmental Control
          U.S. Bureau of Land Management

The Nebraska Oil and Gas Conservation Commission regulates
industry practices and procedures with regard to construction,
location, and operation of onsite drilling.  The Commission
issues permits for oil and gas drilling and UIC Class II wells.
The Commission has three members who are appointed by the
Governor.  At least one member must have experience in oil or gas
production.

Nebraska is an NPDES-delegated State.  The Nebraska Department of
Environmental Control issues all NPDES permits and regulates all
other classes of UIC wells.

The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands.  The Bureau is addressed in a
separate section.
STATE RULES AND REGULATIONS

DRILLING

Under Commission Rule 3.022, retaining pits must be permitted.
Upon receipt of Form 15, Retaining Pit Permit,  a Commission
representative will approve or disapprove a proposed retaining
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pit.  These pits are required to be lined or constructed with
impermeable material and must have the capacity for at least 3
days of facility fluid influx.  This rule does not apply to
reserve pits, emergency pits, or burn pits.  Burn pits are
required to be a safe distance from any other structure and shall
be constructed so as to prevent any materials escaping the pit or
surface water entering the pit.  The regulations do not address
any requirements for reserve pits.  Open pit storage of oil is
not allowed unless during an emergency or by special permission
by the Director of the Commission.


PRODUCTION
       V
Commission regulations on brine disposal do not distinguish
between well types.  Under Rule 3.002, "No salt water, brackish
water, or other water unfit for domestic, livestock, irrigation
or general use shall be allowed to flow over the surface or into
any stream or underground fresh water zone."  Brine may be
disposed by evaporation pits, road spraying, or injection.  Brine
pits fall under the regulations in Rule 3.022.  Road spraying of
brine is considered on a case-by-case basis.  When allowed,
spraying must be done with a spreader bar and in such a way as
the prevent runoff.

Brine can be disposed by injection into either a disposal well or
an enhanced recovery well.  Both types of injection wells are
regulated by the Commission.  Under Rule 4.005.01, "Each enhanced
recovery well or disposal well shall be completed, equipped,
operated, and maintained in a manner that will prevent pollution
of fresh water or damage to sources of oil and/or gas and will
confine injected fluids to the formations or zones approved."
Annular injection is prohibited.  Authorization of injection into
disposal or enhanced recovery wells remains valid for the life of
the well unless revoked by the Commission.


OFFSITE AND COMMERCIAL PITS

This subject is not addressed in the Commission regulations.
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REFERENCES

Nebraska Oil and Gas Conservation Commission, Rules and
     Regulations, December 1985.

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Coubrough, Rob, State Regulatory Information Submitted in 1985,

Nebraska Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas State/Federal Western Workshop.  U.S. EPA,
     Washington,D.C.(December 1985).
                                 A-6 6

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                             NEVADA
INTRODUCTION

During 1984, Nevada produced
1,953,000 barrels of oil from a
total of 34 oil wells.  There
are no producing gas wells in
this State.  All of these wells
are on Federal land and most
use reserve pits to evaporate
drilling fluids.  Reinjection
is applied to produced waters.
Between 200,000 and 500,000
barrels per year of brine are
produced in Nevada's major
production area (the Carbonate
Belt).  Reinjection of these
waters is accomplished-*
collectively into some 5-9
injection wells.  No produced
waters are discharged under the
beneficial use subcategory.
Nevada does not have NPDES
primacy.
STATE REGULATORY AGENCIES

For agencies regulate the oil activity in Nevada:

     -    Nevada Department of Minerals
     -    Nevada Department of Conservation and Natural
            Resources, Division of Environmental Protection
     -    Bureau of Land Management
          EPA, Region IX, Underground Injection Section

The Nevada Department of Minerals, created as a single State
department by the State legislature in 1983, regulates the
industry on the State level with respect to construction,
location, and operation of onsite drilling and production.  All
operation permits are issued from this department.

The Division of Environmental Protection in the Department of
Conservation and Natural Resources currently is developing a
program to obtain UIC primacy.  The Division has regulations
pertaining to major spills.

The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands.  For such drilling, the Bureau of
                                  A-6 7

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Land Management handles all Applications to Drill.   The Bureau
requires extensive environmental documentation,  including
environmental assessments,  and develops environmental impact
statements for drilling on Federal land.

EPA's Region IX regulates the reinjection of produced fluids
under the UIC program.
STATE RULES AND REGULATIONS

The Regulations and Rules of Practice and Procedures under
Chapter 522 of the Nevada Revised Statutes of the Oil and Gas
Conservation Law were adopted by the Department of Minerals on
December 20, 1979.  Section 200.1 of these rules states that,
"Fresh water must be protected from pollution whether in
drilling, plugging or producing oil or gas or in disposing of
salt water already produced."  The -regulations govern the
"drilling, safety, casing, production, abandoning and plugging of
wells."  The regulations do not include a provision for allowing
or disallowing discharges nor is their mention of a discharge
allowance.  Section 308, however, states that all excavations
must be drained and filled and the surface leveled so as to leave
the site as near to the condition encountered when operations
were commenced as practicable.  Section 407 further states that
"Oil or oil field wastes may not be stored or retained in unlined
pits in the ground or open receptacles except with the approval
of the Division."  Section 600.1 states that, "The underground
disposal of salt water, brackish water, or other unfit for
domestic, livestock, irrigation or other use, is permitted only
upon approval of the Administrator."

Region IX regulates the underground injection of wastes from oil
wells under the UIC program.  The applicable regulations are
found in 40CFR 144 and 146.
                                 A-6 8

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REFERENCES

Proceedings of the Onshore Oil and Gas State/Federal Western
     Workshop.  Summary of presentation given by Scott
     McDaniel, Nevada Department of Minerals.  December
     1985.

Nevada Department of Conservation and Natural Resources,
     Division of Mineral Resources.  Regulations and Rules
     of Practice and Procedures.  Chapter 522.  December 20,
     1979.

Personal Communications:

     Cathy Loomis, Engineering Technician,  Nevada Department
     of Minerals, September 26, 1986 (702)  885-5050.

     Dan Gross,  Division of Environmental Protection, Department
     of Conservation and Natural Resources, September 26, 1986
     (702) 885-4670.

     Ellis Hammett, Permit Processor, Nevada Bureau of Land
     Management, September 26, 1986 (702) 784-51236.

     Nate Lau, Director, UIC Division, EPA Region IX,
     September 26, 1986 (415) 974-0893.
                                 A-6 9

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                           NEW  MEXICO
INTRODUCTION

New Mexico produced 75,532,000
barrels of oil and 965.7 x 109
cubic feet of gas in 1984,
ranking fourth in U.S. gas pro-
duction and eighth in U.S. oil
production.  Production is from
24,954 oil wells and 17,523 gas
wells.  Twenty percent of oil
production is from the stripper
well category.
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activities in New Mexico:

          New Mexico Energy and Minerals Department
          New Mexico Water Quality Control Commission
     -    U.S. Bureau of Land Management
     -    Indian Tribes

The New Mexico Energy and Minerals Department, Oil Conservation
Division, is responsible for regulating the oil and gas industry.
It regulates exploration and drilling, production, and refining
with respect to protection of water quality.

New Mexico has very few statewide specific rules relating to oil
and gas activities because of the diversity of the climate,
diversity of the geology, and diversity of the quantity and  type
of waste that is produced.  There is a plugging bond requirement
that endures until well abandonment has been approved by the
Division.

The U.S. EPA has the responsibility for NPDES permitting in  New
Mexico; however, the State Environmental Improvement Division
certifies those permits.  No NPDES permits have been issued  for
the New Mexico oil and gas industry drilling and production
facilities.

The New Mexico Water Quality Control Commission, Environmental
Improvement Division, is prohibited from taking any action which
would interfere with the exclusive authority of the Oil
Conservation Commission over all persons and things necessary to
prevent water pollution as a result of oil or gas operations.
The Environmental Improvement Division administers and enforces
Commission regulations at brine manufacturing operations and
                                  A-70

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concerning discharges to ground or surface waters at brine
manufacturing operations, including all brine production wells,
holding ponds, and tanks.  The Oil Conservation Division
regulates brine injection through its Class II UIC program if the
brine is used in the drilling for or production of oil and gas.
The Environmental Improvement Division regulates brine injection
through its UIC program if the brine is used for other purposes.

The U.S. Bureau of Land Management takes the lead on'oil and gas
drilling activities on Federal lands.  Where drilling on Federal
land occurs, two drilling permits would be issued梠ne from the
Bureau of Land Management and one from the State.  The State
would maintain primacy in waste disposal activities associated
with any such drilling or production activities.

Issues with drilling on Indian lands currently remain unresolved.
Some Tribes have issued regulations concerning oil and gas
drilling and production activities.,  Some Tribes have applied for
UIC program delegation.  The State has not waived jurisdiction in
regard to regulating the oil and gas industry on Indian lands,
however.  Where Tribe regulations go beyond those of the State,
the Tribe regulations prevail.


STATE RULES AND REGULATIONS

DRILLING

No drilling fluids are authorized to be discharged to surface
waters.  Drilling fluids must be disposed of at the well site in
a manner to prevent water contamination; they cannot be removed
to another site without approval of the District Supervisor.
There is a fine of $1,000 per day for violating this rule.  All
drilling and reserve pits must be built large enough to hold all
drilling mud and waste fluids at each well location.

The Rules and Regulations are general and allow for a great deal
of flexibility in managing day-to-day situations.  Different
district managers manage conditions with some variation from
district to district, which leads to a case-by-case approach in
management.

Commission Rule 310 requires that all oil or distillate tanks,
the location of which constitutes an objectionable hazard, be
surrounded by a dike or fire wall having a capacity one-third
larger than the capacity of the enclosed tanks.  Any tank used in
the oil and gas industry and located within 1,000 feet of a river
or irrigation canal is deemed to be a hazard under this rule and
is required to have a fire wall or dike constructed.
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PRODUCTION

In 1985, a modified statewide produced water rule was promulgated
by the Oil Conservation Division that prohibits disposal on the
surface of the ground or in any pit,  pond,  lake,  depression,
draw, stream bed, arroyo, in any water course,  or in any other
place or in any other manner which constitutes  a hazard to fresh
water supplied.  Fresh water is defined as water having 10,000
mg/1 or less of total dissolved solids, unless  it is "found that
there is no reasonably foreseeable beneficial use which would be
impaired by contamination of such water.  Produced water may be
used in road construction with approval of the  District
Supervisor.
       6
There are 1985 requirements that evaporation pit linings must be
approved.  The New Mexico Oil Conservation Division has issued
guidelines for pit liners and below-grade storage tanks, and
applications are now being accepted under the order that was
adopted in June 1985.

There are two specific orders requiring disposal of produced
water in New Mexico.  One order instituted in 1969 bans all
disposal in unlined pits in the southeastern part of the State.
The second order requires that no unlined pits  receive more than
five barrels per day in shallow groundwater areas in northwest
New Mexico.

In 1984, 337 million barrels of brine were produced from oil
wells, and another 5.5 million barrels were produced from natural
gas, for a total of 342 million barrels.  One hundred fifty-three
million barrels were disposed of in injection wells for secondary
recovery and pressure maintenance.  Approximately 43 percent of
the state's oil yield is produced through secondary recovery and
pressure maintenance wells.  One hundred fifty-nine million
barrels were injected into saltwater disposal wells.  There are
roughly 4,500 injection wells for secondary recovery and another
300 injection wells for salt water disposal.  Thirty-one million
barrels of produced water were disposed of in permitted ponds or
in unlined pits, or were used as secondary recovery makeup water.
Most of the produced water is disposed by injection and a very
small percent is disposed of using surface methods.  None of
these surface methods includes disposal into any streams or water
courses.

Contamination now is being detected related to oil and gas
activities which occurred three or four decades ago.  These cases
may be  related to improper casing, pit construction, or any
number  of practices.  Little groundwater monitoring has been
done, so the extent of damage is unknown.
                                 A-72

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OFFSITE AND COMMERCIAL PITS

Operators trucking pit contents away from a sensitive area of the
State must dispose of the fluids in a pond approved for ground-
water protection.  Some of these sites are located high atop
mesas where there are unsaturated geological strata.  Little, if
any, groundwater contamination is expected from these sites.

Three different off site disposal methods have been ap'proved.  The
first involves moving the drilling mud to another drilling pit.
The second is land application.  The third is to seal stock
watering ponds and catch ponds in the San Juan basin.  In the
latter case, the operator and the land owner coordinate with the
Soil Conservation Service, which has standards for the appli-
cation of these materials to pond soils.
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REFERENCES

New Mexico Meeting Report.  1985.   Proceedings of the
     Onshore Oil and Gas State/Federal Western Workshop.
     U.S. Environmental Protection Agency,  Washington,  D.C.
     (December 1985).

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.   1985.  Interstate Oil
     Compact Commission (December).
       K
State of New Mexico, Energy and Minerals Department, Oil
     Conservation Division.  Rules and Regulations.   April
     1, 1986.

State of New Mexico.  Water Quality Control Commission
     Regulations.  March 3, 1986.

Chavez, Frank.  1985.  "Management and Regulation of
     Drilling Waste Disposal:  The New Mexico Approach."
     Proceedings of a National Conference on Disposal of
     Drilling Wastes.  University of Oklahoma Environmental
     and Ground Water Institute, Norman, OK, pp. 151-164.

Order of the Oil Conservation Commission of the State of  New
     Mexico, Order No. R-3221.

Order of the Oil Conservation Commission of the State of  New
     Mexico, Order No. R-7940-A.

Memorandum, R. L. Stamets, Director, Oil Conservation
     Commission, regarding Hearings for Exceptions to Order
     No. R-3221, dated October 22, 1985.

Personal Communication:

     David Boyer, Hydrogeologist,  New Mexico Oil Conservation
     Division, (505) 827-5802.
                                 A-74

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                             NEW YORK
INTRODUCTION

New York is one of the pioneer
States for oil and gas produc-
tion and use.  Proven oil
reserves were documented in
1627, and drilling began in the
late 1800s.  Since then it is
estimated that 30,000 to 50,000
wells have been drilled in New
York.

New York produced 952,000
barrels of oil from 4,678 wells
in 1984.  Twenty-seven billion
cubic feet of natural gas was
produced from 3,800 gas wells
in 1984.
REGULATORY AGENCIES

BACKGROUND

In 1963 the New York legislature passed laws regarding oil and
gas operations.  A working permitting system was instituted in
1966 under the purview of the Department of Environmental
Conservation.  The regulations have been revised fairly often
over the last twenty years.  In fact, further revisions are
expected in the next year or two as a result of a Generic
Environmental Impact Statement scheduled for completion in mid-
1987.
AGENCIES

Oil and gas activities in New York are regulated by:

     -  NY Department of Environmental Conservation
        Bureau of Land Management (Federally-held mineral
          rights only)
     -  U.S. Forest Service (surface activities in U.S.
          forests)

Most oil and gas activities in New York are regulated by the
Department of Environmental Conservation.   The Department of
Environmental Conservation is authorized to regulate  the
"development, production, and utilization of natural  resources of
oil and gas ... in such a manner that a greater ultimate
recovery of oil and gas may be had."  The Department  also has
authority for "prevention of pollution and migration."  New York
                                 A-7 5

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is NPDES-delegated, with the Department of Environmental
Conservation responsible for the program.  New York does not have
UIC primacy.

The Department of Environmental Conservation is not entirely
independent.  Within the Department of Environmental Conser-
vation, the Oil, Gas, and Solution Mining Advisory Board (with a
majority of industry representatives) has input in the
development of rules and regulations.

The U.S. Bureau of Land Management has regulatory authority for
oil and gas activities when mineral rights are Federally held.
Their regulations are discussed in a separate section, Federal
Agencies.

The U.S. Forest Service has jurisdiction over surface activities
on federal forest lands even when mineral rights are held
privately.

The Water Quality Division, Fish and Wildlife Division,
Regulatory Affairs, Law Enforcement, and Lands and Forests
provide instrumental manpower and enforcement actions, when
applicable.


RULES AND REGULATIONS

DRILLING

The Division of Mineral Resources (within the Department of
Environmental Conservation) issues all oil and gas drilling
permits.  Each permit requires that the fluids generated by
drilling be "hauled away and properly disposed of."  The
regulations are unclear regarding what practices constitute
proper disposal.

"Pollution of the land and/or of surface or ground fresh water
resulting from exploration or drilling is prohibited."  Part 554
Section 554.1 of the Mineral Resources Regulations requires the
operator "to submit and receive approval for a plan for the
environmentally safe and proper ultimate disposal of such
fluids."  Drilling muds are specifically excluded from this
requirement; "Drilling muds are not considered to be polluting
fluids."  Drilling pits are dewatered and the fluid disposed of
properly prior to reclamation.  During reclamation, pit liners
are shredded or removed and the rock cuttings disposed in situ.
After drying, the cuttings are buried.

Other drilling wastes must be disposed or discharged in a manner
acceptable to the Department considering the environmental
sensitivity and geology of the area.  Historical experience with
drilling operations in the same area may also be used in
considering an application.  Permits may be required for disposal
or discharge of drilling wastes (excluding drilling muds) in


                                 A-7 6

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addition to the drilling permit.  Drilling muds are not defined
in the regulation; it is unclear whether this term is intended
specifically for rotary drilling muds, or if the term is
inclusive of all fluids used in drilling.  Ninety-five percent of
New York drilling utilizes rotary air drilling technology.

Brine and salt water generated during drilling are considered
"polluting fluids" in the Mineral Resources Regulations.  These
fluids, and other polluting fluids, may be stored in watertight
tanks or earthen pits for up to 45 days after drilling ends prior
to disposal.  An extension may be granted if the operator plans
to use^the fluids for later activities.  The regulations do not
specify what disposal alternatives may be ultimately acceptable
for disposal of brines and salt water generated during drilling.

The Department is also responsible for well construction,
spacing, and plugging requirements.


PRODUCTION

Part 556 of the Mineral Resources Regulations addresses operating
practices applicable to oil and gas wells.   Section 556.5
prohibits pollution of the land and/or surface or ground fresh
water resulting form producing, refining, transportation, or
processing of oil, gas,  and products.  Brine (i.e.,  produced
water) may be stored in water-tight tanks or in earthen pits
prior to disposition.  Although specific construction
requirements are not described in the regulation, earthen pits
must be constructed to prevent percolation into the soil, over or
into adjacent lands,  streams,  or bodies of water.

The only disposal alternative described in the regulation is
injection.  The Department of Environmental Conservation has
procedures for application and approval of permits to inject
brines.

Although the regulations do not address road spreading,  it is the
predominant brine disposal method in New York.  Road spreading is
conducted on a manifest system under a separate permit.

Although it is not discussed in the regulations,  the Department
of Environmental Conservation allows "processing [of brines] at
sewage disposal plants,  permitted onsite discharges,  and hauling
to other states with approved disposal facilities."   Brine
discharges from stripper wells is permitted under the following
limitations:
        oil and grease        15 mg/1
        pH                     6 to 9
        benzene               10 micrograms/1
        toluene               10 micrograms/1
        xylene                10 micrograms/1
                                 A-7 7

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Sampling is done infrequently on any given well.  Annular
disposal is not allowed.
OFFSITE PITS

New York regulations do not address the use of offsit'e pits for
long term storage or disposal.
                                 A-78

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REFERENCES

Interstate Oil Compact Commission, The Oil and Gas Compact
     Bulletin, Volume XLIV, Number 2, December 1985.

Cornell University,  "Oil, Gas and Solution Mining
     Legislation in New York As Amended through September
     1985."

New York State Statute 550.2, Subchapter B - "Mineral
     Resources," Parts 550 through 558, as amended.

New York State Environmental Conservation Law, Article 23,
     Title 1-5 (circa 1985).

New York Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas Workskop, U.S. EPA, Washington, D.C., March
     26-27 in Atlanta, GA) . July 1985.
                                 A-7 9

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                           NORTH DAKOTA
INTRODUCTION

North Dakota produced
52,654,000 barrels of oil and
80 x 109 cubic feet of gas in
1984.  Production is from 4,026
oil wells and 58 gas wells.
This 1984 figure for oil
production established a record
high production figure for the
State.
STATE REGULATORY AGENCIES

Three agencies regulate oil and gas activity in North Dakota:

          North Dakota Industrial Commission
          U.S. Department of Agriculture, Forest Service
     -    U.S. Bureau of Land Management

The North Dakota Industrial Commission,  Oil and Gas Division, has
the regulatory responsibility to oversee the drilling and
production of oil, protect the correlative rights of the mineral
owners, prevent waste, and protect all sources of drinking water.
Other responsibilities of the Division are to collect monthly
reports on oil, gas, and water; oversee proper disposal of brine;
and issue drilling permits.  The Division also has primacy for
UIC Class II wells and issues such permits.

The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands.  When drilling is to occur on U.S.
forestland, no additional permit is needed but additional
stipulations are placed by the U.S. Forest Service.
STATE RULES AND REGULATIONS

DRILLING

Before a drilling permit is issued by the Commission,  the
operator of the well must be bonded.   Single well bonds are
$15,000, a ten-well bond is $50,000,  and a blanket bond is
$100,000.  The Commission will release the bond after  site
                                 A-80

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restoration is approved.  Before drilling activities,  Commission
inspectors will survey the site for pit location.  The inspectors
also decide whether or not to require a pit liner at the site.

Under Commission Rule 43-02-03-19,  "Pits shall not be located in,
or hazardously near, stream courses, nor shall they block natural
drainages.  Pits shall be constructed in such manner so as to
prevent contamination of surface or subsurface waters by seepage
or flowage therefrom.  Under no circumstances shall pits be used
for disposal,  dumping or storage of fluids, wastes and other
debris not used in drilling operation."  Within 1 year after the
completion of a well, the pit site must be restored.  Pit
restoration does require approval from the Commission.  Recla-
mation includes redistributing topsoil that was removed from the
site at the beginning of drilling activities.

When drilling is on U.S. forest lands, the U.S. Forest Service
has additional stipulations on top of those of the Commission.
The Forest Service requires a complete survey and design of the
drilling site.  This survey must be approved before drilling.
All reserve pits must be lined with a material that has a minimum
burst strength of 150 psi.  Tanks must be diked.  The site
reclamation plan must also be approved by the Forest Service
before implementation.


PRODUCTION

Under Commission Rule 43-02-03-53,  "All saltwater liquids or
brines produced with oil and natural gas shall be disposed of
without pollution of freshwater supplies.  At no time shall
saltwater liquids or brines be allowed to flow over the surface
of the land or into streams."  Surface pits are not allowed for
brine storage.  Surface tanks are allowed provided they are diked
and are leak-proof.  Brine may be disposed by use of injection
wells or disposal wells; both methods require permits issued by
the Commission.

When a central tank battery or central production facility is
planned to be used, approval must be received from the Commission
or by the forest Service if on U.S. forest lands.


OFFSITE AND COMMERCIAL FACILITIES

Offsite pits are not addressed in the Commission regulations.
Offsite treatment facilities require a permit from the
Commission.  Before treatment operations commence, the facility
is required to put up a bond of $25,000 to the Commission.
                                 A-81

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REFERENCES

North Dakota Industrial Commission, Statutes and Rules for
     the Conservation of Oil and Gas.  January 1985.

Williams, Tex.  State regulatory information submitted in
     1985.

U.S. EPA.  North Dakota Meeting Report.  Proceedings of
     Onshore Oil and Gas State/Federal Western Workshop.
     U.S.EPA,Washington D.C. (December 1985).

U.S. Department of Agriculture, Special Forest Service
     stipulations, September 1986.
                                 A-8 2

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                              OHIO
INTRODUCTION

Ohio produced 15,271,000
barrels of oil and 186.5 x 109
cubic feet of gas in 1984 from
1,830 full producing oil wells
and approximately 24,263
stripper wells producing less
than 10 barrels per day, and
14,762 full producing gas wells
and approximately 60,000
stripper wells producing less
than 60,000 cubic feet per day.
STATE REGULATORY AGENCIES

Two agencies regulate oil and gas activities in Ohio:

          Ohio Department of Natural Resources
     -    Ohio Environmental Protection Agency

The Ohio Department of Natural Resources,  Division of Oil and
Gas, issues permits for oil and gas drilling and for underground
brine injection.  The statutes and rules of the Division of Oil
and Gas do not contain provisions for effluent discharges.   The
Division operates on revenues from permit and other similar fees.
Enforcement activities are dependent primarily upon approximately
50 field staff employees who inspect well sites and conduct
investigations.  The Division of Oil and Gas has authority to
review, investigate, and require corrective action related to all
oil and gas drilling and production activities.  Compliance bond
and well spacing are requirements of the Division.

Ohio has been delegated NPDES authority.  NPDES permits are
issued through the Ohio Environmental Protection Agency, Water
Quality Division; none is issued for the oil and gas drilling and
production industry.  The jurisdiction of the Ohio EPA extends to
any pollution of the waters of the State.   Where brine spills may
impair waters of the State, for example, there is coordination
between the Ohio DNR and Ohio EPA in damage assessment and
corrective measures.  When there is potential for groundwater
contamination, the Ohio Environmental Protection Agency may
assist in the investigation and joint charges may be filed with
the Ohio Department of Natural Resources.
                                 A-83

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A five-member oil and gas Board of Review was created by statute
within the Ohio Department of Natural Resources with 5-year terms
consisting of representatives of a major petroleum company, the
public, independent petroleum operators, one learned and
experienced in oil and gas law, and one learned and experienced
in geology, as appointed by the Governor.  Any person claiming to
be aggrieved or adversely affected by an order of the Chief of
the Division of Oil and Gas may appeal to the Board for an order
vacating or modifying such an order.

Rarely, there is oil and gas drilling on Federal lands.  When
application for such drilling is filed, the permittee obtains a
lease from the appropriate Federal authority prior to requesting
a permit from the Division of Oil and Gas.  The permitting
process then is managed as a standard procedure with no special
coordinating efforts.


STATE RULES AND REGULATIONS

DRILLING

Pursuant to Section 1509.22 of the Ohio Revised Code, substances
resulting, obtained, or produced in connection with the
exploration, drilling or production of oil and gas must be
injected into an underground formation approved by the Chief,
Division of Oil and Gas, or disposed by an approved alternative
method.  Alternative methods include annular disposal, disposal
in association with an enhanced recovery project, or road
spreading for dust and ice control.

Earthen brine pits may have caused most of Ohio's contamination
problems.  Pursuant to recently enacted legislation, pits are
required to be water tight either by clay or plastic liner.  A
pit life beyond 180 days is prohibited.  Pits will be allowed
only for drilling, reconditioning, plugging, or other limited
use.

In most cases, pit solids are buried on the well site when no
environmental harm is expected.  When there is a history of
groundwater problems associated with an area, a plastic liner
requirement is made a part of the drilling permit.


PRODUCTION

Recently enacted laws, which became effective on April 12, 1985,
established new standards for well operators and waste brine
transporters.  Brine disposal is one of the major problems in
Ohio.  Well drillers now are required to submit a brine disposal
plan identifying the transporter of the brine including the
transporter's address.  Anyone who transports brines must pay a
$500 one-time fee, provide a $300,000 certificate of insurance
for bodily injury and liability, post a $15,000 bond to be used
                                 A-84

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in paying for damages, and provide detailed information.  The
detailed information includes a daily log that identifies
ultimate brine disposal such as time and date of brine loading
and amount, road spreading location, disposal well permit number,
time and date of brine disposal, etc.  The driver is required to
maintain a daily log showing driver name, registration
certificate number, sites visited, and destination.  Brine
production is estimated at 160,000 barrels per day.

For road or land spreading, a township must pass a resolution to
allow brine disposal that meets five minimum requirements:  it
must regulate the rate and amount of application, prohibit
spreading when ground is water saturated, regulate the spreader
speed, 'require use of a dispersion bar,  and prohibit direct spray
on vegetation.  The resolution then is considered for approval by
the Department of Natural Resources.

When a well is abandoned, following permission for such by the
Division Chief, a detailed report containing information and
names and addresses of witnesses to the plugging of the well must
be signed and filed by the owner and operator of the well.  When
a well is plugged, the drill site must be restored, the area
including pit site is.to be returned to its natural contour, all
trash is to be removed, and the site is to be seeded.
OFFSITE AND COMMERCIAL PITS

When such a groundwater problem history exists,  pit solids may be
required to be removed and transferred to an Ohio EPA regulated
disposal site.  Or,  if there is a request to move pit solids to
an offsite area, an EP-toxicity test for hazardous waste
characteristics is required prior to a transfer to a State-
approved hazardous or nonhazardous landfill, as appropriate.
Abandoned pits are investigated when alleged to be the cause of a
groundwater problem.  When found to contribute to such a problem,
the owner of the pit is required to remove solids and transport
them to a State-approved solids disposal facility.
                                 A-85

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REFERENCES

Chapter 1509 of the Ohio Revised Code.

Chapter 1501, Rules of the Division of  Oil and Gas of the
     Ohio Department of Natural Resources.

Summary of State Statutes and Regulations for Oil and" Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.   1985.  Interstate Oil
     Compact Commission(December).

Hodges, David H.  1985.  Letter Communication to EPA.
     Division of Oil and Gas, Ohio Department of Natural
     Resources.

Ohio Meeting Report.  1985.  Proceedings of the Onshore Oil
     and Gas Workshop.  U.S. Environmental Protection
     Agency, Washington, D.C.  (March 26-27 in Atlanta, GA)

Personal Communications:

     David A. Hodges, DNR, Division of  Oil and Gas
     (614) 265-6917.

     Ted De Brosse, DNR, Division of Oil and Gas
     (614) 265-6894.
                                 A-86

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                             OKLAHOMA
INTRODUCTION

Oklahoma produced 153,250,000
barrels of oil and 1,996 x 109
cubic feet of gas in 1984.  It
ranked fifth in U.S. oil
production and third in U.S.
gas production.  Oklahoma had
99,030 producing oil wells and
23,647 producing gas wells.
There are approximately 200
million barrels of salt water
produced by the oil industry
per year.  There are about
5,200 saltwater disposal wells
and 9,900 enhanced recovery
injection wells.  Approximately
100 of the disposal wells are
commercial facilities.
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activities in Oklahoma:

     -    Oklahoma Corporation Commission, Oil and Gas
            Conservation Division
          Oklahoma Department of Health Water Resources Board
     -    Osage Indian Tribe
          U.S. Bureau of Land Management

The Oklahoma Corporation Commission has the exclusive
jurisdiction for regulating the disposal of waste from oil and
gas activities.  Pollution of surface or subsurface water during
any well activity is prohibited.  Currently, there are 55
inspectors who have the authority to shut down operations if
regulations are not followed.  Well activity is defined in Rule
3-101 as exploration, drilling, producing, refining,
transporting, or processing of oil and gas.  Oklahoma has
received primacy for the UIC program.

The Water Resources Board of the Oklahoma Department of Health
protects all surface and ground waters to ensure that pollution
does not occur and that discharges meet specified beneficial uses
outlined in water quality standards.  Oklahoma has not been
delegated NPDES authority.  However, discharges to water from oil
and gas activities are not permitted.  The Water Resources Board
issues land application permits for reserve pit fluids.
                                  A-87

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The Osage Indian Tribe has sole primacy regarding oil and gas
operations in Osage County and has been delegated UIC program
responsibility for Class II wells.

The U.S. Bureau of Land Management has primacy where both surface
and mineral rights are owned by the Bureau or by an Indian Tribe
other than the Osage Tribe.  In those cases where mineral rights
are owned by the Bureau or an Indian Tribe, but not the surface
rights, both the Bureau and the Oklahoma Corporation Commission
would become involved and would coordinate the permitting
procedures.


STATE RULES AND REGULATIONS

DRILLING

Corporation Commission Rule 3-104 specifies that pits and tanks
for drilling mud or deleterious substances used in the drilling,
completion, and recompletion of wells shall be constructed and
maintained to prevent pollution of surface and subsurface fresh
water.  A written permit is issued for the use of an onsite
earthen pit (Rule 3-110.1 ).  Any reserve mud pit used in
drilling, deepening, testing, reworking, or plugging a well must
be emptied and leveled within a maximum of 18 months after the
drilling operations cease (Rule 3-110.1(d)(2)).

Reserve drilling pit fluids are permitted on a one-time basis by
the Water Resources Board to be spray-applied to land as a part
of pit closure providing certain limits are met.  These limits
include a pH range of 6.5 to 9.0 and not to exceed:

     Chlorides                     1,000   mg/1
     Total chromium                    0.2 mg/1
     Chemical oxygen demand          250   mg/1
     Total dissolved solids        3,000   mg/1
     Oil and grease                   30   mg/1
     Total sodium                    750   mg/1
     Specific conductance          4,600   u mhos

Special field rules have been adopted that prohibit the use of
pits in certain areas.  This has caused the use of offsite
reserve pits for a particular well.

Drilling fluid must be disposed of by one of three ways:  Annular
injection, evaporation then closure of a reserve pit, or vacuum
truck removal to offsite earthen pits.  A manifest is required
for offsite transportation.  High chloride content drilling
fluids are injected into a Class II well.
                                 A-88

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PRODUCTION

Underground disposal of high chloride produced water is required
either in disposal wells or enhanced recovery injection wells.
There are about 5,200 of the former and 9,900 of the latter.  The
Oil and Gas Commission has been delegated UIC program activities
for Class II wells.
OFFSITE AND COMMERCIAL PITS

Rule 3-110.2 of the Oklahoma Corporation Commission permits the
use of "offsite earthen pits provided they are sealed with an
impervious material, do not receive outside runoff water, and are
filled and leveled within 1 year after abandonment.  The chloride
content of the contained fluids shall not exceed 3,500 mg/1.
Drilling muds containing both solids and fluids may be
transported to such commercial pits.

Offsite pits are created by excavating, damming gullies, and
using abandoned strip pits.  There are approximately 95 offsite
pits throughout Oklahoma, ranging as large as 15 acres.  They are
sampled periodically to enforce a maximum 3,500 parts per million
chloride concentration requirement,  if the pit bottom mud cannot
meet chloride limits, it must be effectively treated and hauled
to a hazardous waste disposal site.  Some offsite pits are large
and may contain over 3,000,000 barrels of waste, which calculates
to 387 acre feet of fluids.

Owners of new pits are required to install and sample monitoring
wells, principally for chlorides and pH.  There is a proposal,
currently, to made such requirement applicable to existing
offsite pits.  Three wells would be required梠ne upgradient and
two downgradient.  Any indicated change over background in the
constituent levels tested would indicate potential pollution.
                                 A-89

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REFERENCES

Oklahoma Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas State/Federal Western Workshop.  U.S.
     Environmental Protection Agency, Washington,  D.C.
     (December 1985).

Summary of State Statutes and Regulations for Oil  and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission (December).

General Rules and Regulations of the Oil and Gas
     Conservation Division, The Corporation Commission of
     the State of Oklahoma (1986).

Oklahoma Drilling Waste Conference.

Personal Communications:

     Mike Battles, Manager of Pollution Abatement, Oklahoma
     Corporation Commission (405) 521-4456

     Karen Dihrberg, Geologist, Water Resources Board
     (405) 271-2549.

     Margaret Graham,  Permits, Water Resources Board
     (405) 271-2561.
                                 A-90

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                             OREGON
INTRODUCTION

Oregon does not produce oil.
Oregon's only producing gas
field was discovered in 1979.
Eleven active gas wells
produced 2.8 x 109 cubic feet
of gas in 1984.  There are four
additional wells that are
capable of production but
currently these are not
producing wells.  There is one
saltwater injection well for
the field.  In 1984, approxi-
mately 100,000 barrels of brine
were injected underground;
about 19,000 barrels went to
surface land disposal.'
STATE REGULATORY AGENCIES

Two agencies regulate oil and gas activity in Oregon:

          Oregon Department of Geology and Mineral Industries
     -    Oregon Department of Environmental Quality

Oil and gas drilling permits are issued by the Oregon  Department
of Geology and Mineral Industries.  The State Geologist serves as
the implementor of rules, orders, and enforcement actions taken
by the Department's governing board.

The Oregon Department of Environmental Quality has delegated
authority for the NPDES program and issues UIC permits.  The
State has maintained a permitting program since 1968.   No NPDES
permits have been issued because there have been no requests to
discharge waste to public waters.

None of the gas wells is on Federal lands.  All are located where
Columbia County owns the mineral rights.  If, in the future,
drilling were to take place on Federal lands, there would be two
separate permitting actions梠ne by the U.S. Bureau of Land
Management and one by the Oregon Department of Geology and
Mineral Industries.
                                 A-91

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STATE RULES AND REGULATIONS

DRILLING

Oregon Administrative Rule 632-10-205 requires a surety bond of
up to 25,000 for one well, or a blanket bond of $150,000 for
more than one well,  conditioned upon the faithful compliance by
the principal with the rules,  regulations,  and orders, of the
Department of Geology and Mineral Industries.

Rule 632-10-140 requires that  any fluid necessary to the
drilling, production, or other operations by the permittee shall
be discharged or placed in pits and sumps approved by the State
Geologist and the State Department of Environmental Quality,  The
operator shall provide pits, sumps, or tanks of adequate capacity
and design to retain all materials.  In no event shall the
contents of a pit or sump be allowed to:

     1.   Contaminate streams, artificial canals or
          waterways, groundwaters, lakes, or rivers.

     2.   Adversely affect the environment,  persons,
          plants, fish, and wildlife and their
          population.

When no longer needed, fluid in pits and sumps is to be disposed
of in a manner approved by the Department of Environmental
Quality and the sumps filled and covered and the premises
restored to a near natural state.  The restoration need not be
done if arrangements are made  with the surface owner to leave the
site suitable for beneficial subsequent use.

Drilling mud pits are not allowed to hold over winter because of
lack of sufficient storage for winter rainfall.  If drilling muds
dry in the reserve pits before winter occurs, the pit is then
closed.

There has not been a problem with abandoned pits; the surety bond
provides a mechanism to ensure adequate pit closure.


PRODUCTION

Rule 632-10-192 of the Department of Geology and Mineral
Industries provides that brines or saltwater liquids may be:

     1.   Disposed in pits only when the pit is lined
          with impervious material and a Water
          Pollution Control Facility permit has been
          issued by the Department of Environmental
          Quality.  Earthen pits used for impounding
          brine or salt water shall be so constructed
          and maintained as to prevent the escape of
          fluid.
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     2.   Disposed by injection into the strata from
          which produced or into other proved salt-
          water bearing strata.

     3.   Disposed by ocean discharge, which may be
          permitted if water quality is acceptable and
          if such discharge is approved by the State
          Department of Environmental Quality through.
          issuance of a National Pollutant Discharge
          Elimination System waste discharge permit.

Produced brines are permitted to be spread on dirt roads
predominantly logging roads梬hen such is done in dry weather.
OFFSITE AND COMMERCIAL PITS

There are no operational offsite pits.   One dump-site has been
used as an emergency pit.  Operators must dispose of drilling
muds in a Department of Environmental Quality approved solid
waste disposal site.  Such solids may be tested prior to disposal
to determine if they contain hazardous materials.
                                A-93

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REFERENCES

Oregon Meeting Report.  1985.  Proceedings of the Onshore
     Oil and Gas State/Federal Western Workshop.   U.S.
     Environmental Protection Agency,  Washington, D.C.
     (December 1985).

Summary of State Statutes and Regulations for Oil and- Gas
     Production.1986.Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(December).

Olmstead, Dennis L.  1985.  Letter Communication to EPA.
     Oregon Department of Geology and Mineral Industries.

Personal Communications:

     Dan Wermiol, Department of Geology and Mineral Industries
     (503) 229-5580.

     Kent Ashbaker, Department of Environmental Quality
     (503) 229-5325.
                                 A-94

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                          PENNSYLVANIA
INTRODUCTION

Pennsylvania produced 4,825,000
barrels of oil and 166 x 109
cubic feet of gas in 1984.
Production was from 20,739 oil
wells and 24,050 gas wells.

Until 1955, environmental
requirements for the oil and
gas industry were minimal if
not nonexistent.  State laws
did not require permitting or
registration of oil and gas
wells.  In 1961, the statutes
were strengthened to prohibit
wasting in production wells,
establish spacing, and provide other requirements.  It was not
until 1984 that the Coal and Resource Coordination Act and the
Oil and Gas act made sweeping changes in permit review and
requirements.  There had been little uniformity in Pennsylvania
oil and gas laws until then.  Combined,  these statutes enable
Pennsylvania permitting authority to put terms and conditions on
permits, and to deny permits.  Passage of House Bill 1375 in mid-
September, 1986, further strengthens the regulatory management of
the oil and gas industry in Pennsylvania, and requires the
development of new regulations relating to solid waste management
and the disposal of wastes onsite.

The first commercial oil well was drilled near Titusville, PA,
1859.
STATE REGULATORY AGENCIES

Five agencies regulate oil and gas activities in Pennsylvania:

     -    Department of Environmental Resources, Bureau of Oil
            and Gas Management
          U.S. Environmental Protection Agency, Region III
     -    Pennsylvania Fish Commission
          U.S. Forest Service
     -    U.S. Bureau of Land Management

The Bureau of Oil and Gas Management was created in 1984 to
coordinate and combine all related regulatory activities of the
oil and gas industry.  The Oil and Gas Conservation Law, enacted
in 1961, established powers and duties of the Oil and Gas
Conservation Commission.  Those powers and duties were
                                 A-95

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transferred to the Department of Environmental Resources in 1970.
The Oil and Gas Act of 1984 created an Oil and Gas Technical
Advisory Board to advise the Department in regulatory activities
(Section 216 of 1984 Act).  The five-member board consists of
three representatives of the oil industry, one from the Citizen's
Advisory Council, and one from the coal industry.

Section 207(a) of the Act requires that the disposal of drilling
and production brines be consistent with the requirements of the
Clean Streams Law.  Section 208(a) requires that any well owner
who affects the public or private water supply by pollution or
diminution shall restore or replace the affected supply with an
alternative source.  Section 205 prohibits drilling of wells
within ,200 feet of buildings or water wells without the consent
of the owner, within 100 feet of any body of water, or within 100
feet of a wetland 1 acre or more in size.

There is a compliance bond conditioned on the operator's faithful
performance of the drilling, restoration, water supply replace-
ment, and well plugging requirements of the Oil and Gas Act.  The
passage of House Bill 1375 transferred NPDES permitting authority
in the oil and gas industry梐lready delegated to the State梩o
the Bureau.

The U.S. Environmental Protection Agency, Region III, issues UIC
program permits for underground injection and secondary recovery.
The Bureau of Oil and Gas Management has not sought primacy in
the UIC program.

The Pennsylvania Fish Commission seeks out pollution of surface
waters and takes appropriate action under the Pennsylvania Fish
and Boat Code.

The U.S. Forest Service and the U.S. Bureau of Land Management
provide requirements they may have in lease agreements.  The well
driller must demonstrate his notification of landowners and water
supply owners of the intent to drill.  Mineral rights in the
Allegheny National Forest are privately owned.  The Bureau of Oil
and Gas Management issues drilling permits on Federal lands.


STATE RULES AND REGULATIONS

DRILLING

Drilling pits to the present time have been virtually
unregulated.  Pits typically are unlined.  Such pits contain
drilling cuttings, contaminated fresh and salt water produced
during construction and well stimulation, and various additives
used during drilling and well stimulation.  Pits are not
reclaimed and no permit is required for a drill pit.  There is no
contingency fund for management of abandoned pits.
                                 A-96

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The Bureau is in the process of developing regulations to further
control oil and gas operations.  The thrust on drilling pits is
to remove liquids to an offsite and commercial treatment and
disposal facility and to dispose of solids waste on site with pit
reclamation.
PRODUCTION

It has been estimated that Pennsylvania has 17,000 impoundments
associated with oil and gas brines.  If an impoundment is
associated with an individual well, a permit has not been
required.  Permits are required for offsite and commercial
treatment systems.  The trend since 1985 has been to move in the
direction of centralized treatment facilities for oil and gas
waste fluids.  It is estimated that currently 20 percent of all
brines are transported to a treatment plant for treatment and
discharge.  No manifest is required for transporting oil and gas
waste materials.

There are other production fluid disposal alternatives, which
include:

     -    Disposal wells
     -    Annular disposal
          Treatment and discharge to surface waters
     -    Onsite treatment and land disposal of top hole water
     -    Discharge to existing treatment facility
          Road spreading
     -    Evaporation (through waste heat)
OFFSITE AND COMMERCIAL PITS

Water Quality Management Part II permits and NPDES permits are
required for treatment facilities that discharge to waters of the
Commonwealth.  Treatment afforded production fluids may include
flow equalization, pH adjustment, gravity separation and surface
skimming, retention and settling and,  if necessary, aeration.
The discharges from several offside produced-fluids treatment
facilities may be covered under a single NPDES permit,  if the
management of those facilities is under the control of one
owner/operator and the geographic area is such as to allow for
effective monitoring and surveillance.

The NPDES permit criteria and limits will be governed by
receiving water quality standards.  Generally, however, total
suspended solids will be limited to an instantaneous maximum of
60 mg/1 and an average monthly of 30 mg/1.   oil and grease will
be limited to an instantaneous maximum of 30 mg/1 and an average
monthly of 15 mg/1.  Dissolved iron has an instantaneous maximum
of 7 mg/1,  and the acidity shall be less than the alkalinity.
                                 A-97

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.1986.Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.   1985.  Interstate Oil
     Compact Commission (December).

Slack,  Peter.  1985.  Letter Communication with EPA.
     Division of Permits and Compliance, Bureau of Water
     Quality Management, Department of Environmental
     Resources.

Pennsylvania Meeting Report.  1985.  Proceedings of the
     Onshore Oil and Gas Workshop.  U.S. Environmental
     Protection Agency,  Washington, D.C.  (March 26-27 in
     Atlanta, GA).

The Oil and Gas Act, Act of 12-19-84, P.L. 1140, No. 223.

The Oil and Gas Conservation Law,  1961, P.O. 825, No. 359.

Rules and Regulations, Department of Environmental
     Resources, Chapter 97, Industrial Wastes.

Personal Communication:

     Carlyle Westlund, Bureau of Oil and Gas Management
     (717) 783-9645.
                                 A-98

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                          SOUTH DAKOTA
INTRODUCTION

South Dakota produced 710,000
barrels of oil and 2.5 x 109
cubic feet of gas in 1984.  The
State has 312 full production
and 33 stripper oil wells, and
41 full.production and 1
marginal production gas wells.
STATE REGULATORY AGENCIES

Four agencies regulate oil and gas activities in South Dakota:

          South Dakota Department of Water and Natural Resources
          South Dakota Department of School and Public Lands
          U.S. Bureau of Land Management
          U.S. Environmental Protection Agency, Region VIII

The South Dakota Department of Water and Natural Resources is the
primary regulatory agency for oil and gas operations through its
Oil and Gas Program in the Division of Environmental Quality.
The primary enforcement agency for the UIC program, and non-
delegated responsibility for NPDES compliance, is the Depart-
ment's Office of Water Quality.  The Department of Water and
Natural Resources also houses the Board of Minerals and
Environment, which has power to conduct hearings and take action
on other oil and gas program related enforcement measures.

South Dakota has not been delegated NPDES authority.  Two of the
active wells have NPDES permits because of beneficial use
associated with wastewaters.  Draft NPDES permits are prepared by
the State and issued by the Water Management Division, U.S.
Environmental Protection Agency, Region VIII.

In the event of a desire to drill on Federal lands, two
applications for drilling would be filed梠ne with the State
Department of Water and Natural Resources, and one with the U.S.
Bureau of Land Management.  The State would defer to the Bureau
regarding any pre-drilling permit investigation.  Two permits,
one from each entity, would be issued to the driller.  In the
event of a request to inject drilling fluids underground, the
Bureau would defer to the State, and the State would issue the
injection permit.  The Bureau has no means of holding hearings,
and the State Board of Minerals and Environment would hold such
hearings prior to permit issuance.
                                  A-9 9

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The South Dakota Department of School and Public Lands has
enforcement powers for lease compliance on State-owned lands and
for State-owned minerals.
STATE RULES AND REGULATIONS

DRILLING

Total retention evaporation ponds for brines,  underground
injection wells for brines and drilling muds,  and burial of
drilling muds are allowed.  There are no specific requirements
related to pit construction.

Drilling pits may become a source of groundwater pollution,
depending upon local hydrologic conditions.   There has been a
documented complaint of contamination from salt brines in an
unlined pit where groundwater was used for stock watering.  This
complaint currently is in the negotiation phase.  Currently,
also, the State is undertaking regulation revision, and con-
sideration is being given to a proposal to require that pits have
liners or be of impermeable construction.

When drilling operations cease, water in the pit is allowed to
evaporate and the mud is allowed to dry.  The time interval for
this to occur is a various and unknown factor.  When the mud has
sufficiently dried, the pit is buried and the surface is
reclaimed to natural conditions.

The Department of Water and Natural Resources requires a Plugging
and Performance Bond for wells, and a Surface Restoration Bond.
There is a well spacing requirement.


PRODUCTION

Discharge of brine from oil well production is allowed when a
beneficial use of the wastewater can be documented.  An NPDES
permit is required for such discharge.  The two NPDES permitted
discharges from wells in South Dakota are used for stock
watering.  NPDES permits contain not-to-exceed limits for oil and
grease of 10 mg/1, total dissolved solids of 5,000 mg/1, and a pH
of 6.0 to 9.0.  The flow is not to exceed 4,500 gallons per day.
OFFSITE AND COMMERCIAL PITS

There are no offsite pits in use, but if there were a request for
such usage, the request would be managed through the solid waste
permitting process.
                                A-100

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.1986.Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact  Bulletin.   1985.   Interstate Oil
     Compact Commission(December).

Pirner, S. M.  1986.   Letter Communication to EPA.   South
     Dakota Department of Water and Natural Resources,
     Office of Water Quality.
          
Personal Communications:

     Steven M. Pirner, DWNR, Office of Water Quality (605) 773-
     3351.

     Fred V.  Steece,  DWNR, Supervisor of Oil and Gas Program
     (605) 394-2385.
                                A-101

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                            TENNESSEE
INTRODUCTION

Tennessee produced about.
937,000 barrels of oil from 798
wells in 1984.  Only 54 oil
wells produced more than 10
barrels of oil per day.  Of 507
gas wells, 474 produce less
than 60 thousand cubic feet per
day.

Regulation of oil and gas
drilling operations began in
1968.  Wells drilled prior to
1968 do not have to be
permitted unless they are
deepened, reopened, or
reentered.
STATE REGULATORY AGENCIES

Three agencies regulate oil and gas activities in Tennessee:

     - State Oil and Gas Board
     - Tennessee Department of Health and Environment
     - U.S. Department of the Interior,  Bureau of Land
         Management

The state Oil and Gas Board is authorized by the Tennessee Code
Annotated (Revised 1982) for prevention of waste of petroleum
resources in Tennessee.  The State Oil and Gas Board regulates
the industry according to the General Rules and Regulations
(Tennessee State Oil and Gas Board Statewide Order No. 2).  The
State Oil and Gas Board issues drilling permits and regulates
surface disposal.

The Department of Health and Environment is the NPDES authority
in Tennessee.  They do not currently have UIC primacy, but are
working towards being granted primacy by EPA.  Discharges of oil
and gas wastes are not permitted by the Tennessee Department of
Health and Environment.

The U.S. Department of the Interior Bureau of Land Management has
jurisdiction over lease arrangements and post-lease activity on
Federal lands where the mineral rights are Federally held.
Surface rights in Federal forests and grasslands are retained by
the U.S. Forest Service.
                                A-102

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RULES AND REGULATIONS

DRILLING

The State Oil and Gas General Rules and Regulations are directed
towards prevention of waste.  The rules do not address drill pit
construction, use, or closure requirements.  The Oil jand Gas
Board has been working to develop rules with regard to waste
pits, and plans to incorporate them into its rules and
regulations.   The Oil and Gas Board has instituted a policy
requiring that proposed well sites "be inspected with regard to
its waste pits, and that those pits be approved by the gas and
oil field inspector assigned to that particular well prior to the
issuance of a drilling permit for that well."

The State Oil and Gas Board regulates spacing, casing, plugging,
and abandonment of wells.
PRODUCTION

"Produced water and plant wastes may be disposed of into
subsurface formations not productive of hydrocarbons,  ground-
water, or other mineral resources."  It is also considered
acceptable for produced water to be disposed in evaporation pits
approved by the State Oil and Gas Board Supervisor.  Criteria for
approval are not part of the rules.

The State Oil and Gas Board Assistant Supervisor maintains that
Tennessee gas wells and oil wells producing over 10 barrels of
oil per day do not produce salt water.  The Assistant Supervisor
estimates "Statewide average daily production of slightly more
than 0.1 barrels of water per day [per full producing oil well]."


OFFSITE PITS

The regulations do not specifically address offsite pits.
                                A-103

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REFERENCES

Zurawski,  Ronald P.  "1985 EPA Onshore Oil and Gas Workshop
     Request for Information on Tennessee Activity and
     Technology,"  circa mid-1985.

State of Tennessee - State Oil and Gas Board.  "General
     Rules and Regulations, Statewide Order No. 2,"
     Effective November 1972.

Zurawski,  Ronald P.  Drilling Waste Conference submittal,
     circa mid-1985.

State of Tennessee State Oil and Gas Board.  "Oil and Gas
     Laws in Tennessee and Mineral Test Hole Regulatory
     Act," Amendments added 1982.
                                A-104

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                              TEXAS
INTRODUCTION

Texas produces 856 million
barrels of oil annually from
over 200,000 wells.  Gas
production is 6,753,889 MMCF
from 43,174 gas wells.  It is
estimated that 75 percent of
all active Texas wells are
marginally-producing wells.

Regulation of the oil and gas
industry began in Texas when
the Railroad Commission was
assigned jurisdiction over oil
and gas activities in 1919.
STATE REGULATORY AGENCIES

Five agencies have jurisdiction over disposal of oil and gas
wastes in Texas:

     - Railroad Commission of Texas
     - Texas Water Commission
     - Texas Parks and Wildlife Department
     - U.S. Bureau of Land Management (and the Bureau of Indian
         Affairs)
     - U.S. Corps of Engineers

Oil and gas activities in Texas are regulated almost entirely by
the Railroad Commission of Texas.  Unlike many State oil and gas
commissions, the Railroad Commission is responsible for both
prevention of waste and for prevention of pollution.  Thus one
agency is responsible for well spacing,  construction requirements
(casing, etc.), and environmental protection (air, water, etc.).

According to the Texas Administrative Code, Title 31 as amended
July 3, 1986, the Texas Water Commission jurisdiction over
disposal activities is superceded by Railroad Commission and
Department of Health authority.

The Texas Parks and Wildlife Department, Pollution Surveillance
Branch, investigates fish kills and water pollution complaints
and evaluates the effects of discharged wastes on fish and
wildlife.  The Texas Parks and Wildlife Department has statutory
authority to recover the monetary value of damaged fish and
wildlife.  The Parks and Wildlife Department may also enforce the
Texas Water Code when permit violations, discharges in excess of
permit limitations, or discharges without a permit occur.
                                A-105

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The U.S. Department of the Interior,  Bureau of Land Management,
has jurisdiction over lease arrangements and post-lease activity
on Federal lands.  Their rules are discussed in a separate
section, Federal Agencies.  The Bureau of Indian Affairs has some
jurisdiction in limited areas of Texas.


STATE RULES AND REGULATIONS

GENERAL

Texas State Rule 8 prohibits any "person conducting activities
subject to regulation by the state" from causing or allowing
pollution of surface or subsurface waters in Texas.  Except for
underground injection (either for disposal or for enhanced
recovery), "no person may dispose of any oil and gas wastes by
any method without obtaining a permit to dispose of such wastes."


DRILLING

The Railroad Commission of Texas has the authority to permit
reserve pits, mud circulation pits, completion/workover pits,
basic sediment pits, flare pits, fresh makeup water pits, and
water condensate pits.  The use of mud pits and mud recirculation
pits for oil and gas wastes is limited to drilling fluids, drill
cuttings, wash water, drill stem test fluids, and blowout
preventer test fluids.  Pit locations are evaluated on a case-by-
case basis to determine what construction requirements are
necessary to prevent waste of oil and gas resources or pollution
of surface water, groundwater, or agricultural land.  The
requirements may or may not include liners.

Permits must carry requirements for pit operation (maintenance)
and pit closure as well.  The Railroad Commission requires that
pits be dewatered, backfilled, and compacted for closure.
Backfill requirements (for all type of pits) vary according to
the type of pit and the chloride concentration of the pit
contents.  Reserve pits (and mud recirculation pits) containing
over 6,100 mg/1 chloride must be dewatered within 30 days and
backfilled within one year of cessation of drilling operations.
The operator has up to one year to dewater and to backfill
reserve pits (and mud circulation pits) containing less than
6,100 mg/1 chlorides.

Completion and workover pits must be dewatered within 30 days and
compacted within 120 days of completion of workover operations.
Basic sediment pits must be closed "within 120 days of cessation
of use of the pits."

Pit fluids and other oil and gas wastes are tracked via a
manifest system in Texas.  Railroad Commission permits are
                                A-106

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necessary to "transport, store,  handle,  treat,  reclaim,  or
dispose of oil and gas wastes."

The Railroad Commission permits  treatment and discharge of
reserve pit fluids to land or to surface waters provided that the
discharge does not cause a violation of Texas water quality
standards.  The rule is unclear  as to what processes constitute
acceptable treatment technologies.  The permit "does -not
authorize the use of surfactants or spray adjuvants."  The
criteria for discharges to surface waters are:

        24-hour bioassay by Texas Parks and Wildlife
        Chemical oxygen demand      <_ 200 mg/1
     -y Total suspended solids      <_  50 mg/1
     -  Total dissolved solids     <_ 3000 m/1
     -  Oil and grease              <_  15 mg/1
     -  Chlorides (coastal)        <_ 1000 mg/1
     -  Chlorides (inland)          <^ 500 mg/1
     -  pH                         6.0 to 9.0
     -  Water color must be adjusted to match the receiving
          stream
     -  Volume of the discharge  must be "controlled so that a
          minimum 5:1. dilution of the wastewater by the principal
          receiving stream is maintained."
        Discharge cannot exceed  concentrations of
          hazardous metals as defined by Texas Water Development
          Board Rules 156.19.15.001-.009.

No permit is required for landfarming of water-based drilling
fluids and associated wastes with a concentration of chlorides at
or below 3000 mg/1; however, the written consent of the landowner
must be obtained.  Landfarming encompasses sprinkler irrigation,
trenching, injecting under the surface using a disc, and surface
spreading by vehicles as defined by the Railroad Commission of
Texas.  Applications for discharge permits do not require
submittal of analytical data on  wastes.

Annular injection of drilling fluids is also regulated via "minor
permits" issued by the Railroad  Commission of Texas.  Certain
conditions and limitations apply to the use annular injection for
disposal.

Drilling is allowed in wildlife  management areas and in State
parks.  Drilling muds are often  disposed on State property.

On Federal lands, the Railroad Commission of Texas has
jurisdiction whenever mineral rights are privately owned,
although the U.S Forest Service  retains surface rights.   For
Federally-owned mineral rights,  the Bureau of Land Management has
jurisdiction.
                                A-107

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PRODUCTION

Injection of produced water is the major approved disposal method
for brine.  "Texas has primacy for Class II wells and has
permitted approximately 47,000 such wells."

The Railroad Commission allows discharge of produced water into
coastal areas on an individual basis.  The application for a
discharge permit does not require submittal of analytical data
for produced water.

West of the 98th meridian, the Railroad Commission permits
"beneficial use" of produced waters where there will be no
discharge.
OFFSITE PITS

Although there are currently about 200 saltwater disposal pits
operating in Texas, these pits are not specifically addressed in
Texas Railroad Commission rules and regulations.
                                A-108

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REFERENCES

Railroad Commission of Texas, Oil and Gas Division.  Rules
     Having Statewide Application to Oil Gas and Geothermal
     Resource Operations Wit.hin the State of Texas,
     September 1985.

Interstate Oil Compact Commission, The Oil and Gas Compact.
     Bulletin, Volume XLIV, Number 2, December 1985.

Railroad Commission of Texas, Oil and Gas Division.  Water
     Protection Manual,  April 1985.

U.S. Environmental Protection Agency, Proceedings - Onshore
     Oil and Gas State/Federal Western Workshop, December
     1985.

"Texas Surface Water Quality Standards,"  TDWR Publication
     LP-71.

Railroad Commission of Texas, "Application Information -
     Casing/Annulus Disposal of Drilling Fluid." Not dated.

Railroad Commission of Texas, Letter communication to EPA,
     October 1985.
                                A-109

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                              UTAH
INTRODUCTION

Utah produced 35,750 barrels
of oil annually from 1,862
wells in 1984.  Approximately
20 percent of these oil wells
are strippers.  Utah's gas
fields produced 99.8 x 109
cubic feet of gas from 728 gas
wells in 1984.  It is not
known what proportion of these
wells are marginal producers
of gas.
STATE REGULATORY AGENCIES

Four agencies share regulatory responsibility for oil and gas
activities in Utah:

     - Utah Department of Natural Resources,  Division of Oil,
         Gas, and Mining
     - Department of Health,  Bureau of Water Pollution Control
     - U.S. Bureau of Land Management (and possibly the Bureau of
         Indian Affairs)
     - U.S. Forest Service (surface rights only)

The Division of Oil, Gas, and Mining adopted new Oil and Gas
Conservation General Rules effective December 2,  1985.  These
rules cover drilling and operating practices, UIC Class II
responsibility, and rules governing purchasing,  transportation,
refining, and rerefining.  The Department of Health currently has
regulatory authority over disposal ponds.  The Department of Oil,
Gas, and Mining is hoping to bring most aspects of oil and gas
regulations under one agency by assuming authority for disposal
ponds in the near future.

The U.S. Department of the Interior, Bureau of Land Management,
has jurisdiction over lease arrangements and post-lease activity
on Federal lands where the mineral rights are Federally held.
Surface rights in Federal forests and grasslands are retained by
the U.S. Forest Service.
                                A-110

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STATE RULES AND REGULATIONS

DRILLING

Rule 308 of the Division of Oil,  Gas,  and Mining rules requires
oil and gas operators to "take all reasonable precautions to
avoid polluting streams, reservoirs,  natural drainage, ways,  and
underground water."  This requirement is supported by a specific
rule for reserve pits (Rule 309).  "Salt water and oil field
wastes associated with the drilling process may be impounded in
excavated earthen reserve pits underlain by tight soil such as
heavy clay or hardpan or lined in a manner acceptable to the
Division."  Pit liquids are not allowed to escape onto the land
surface or into surface waters.

Since most of Utah has very rapid evaporation rates,  the reserve
pit supernatant is generally allowed to evaporate before pit
closure.  Final pit closure requirements were not found in the
rules.

In areas of net precipitation, or in areas where pit construction
is especially difficult (i.e., steep mountain sides), the
Division may allow the reserve pit supernatant to be disposed
down the annulus of the new well into a properly confined zone of
poor water quality.  This determination is made by the Division
of Oil, Gas, and Mining on a case-by-case basis.

The Division of Oil, Gas, and Mining has extensive technical
rules regarding well siting, casing requirements, and well
drilling.


PRODUCTION

Most produced water is injected for water flooding or for
disposal.  Utah has approximately 560 Class II injection wells,
including about 45 disposal wells.  The Division of Oil, Gas, and
Mining controls injection wells and onsite disposal facilities.

The Utah Department of Health regulates surface disposal of
produced water from gas and oil wells.  No pond is allowed to
discharge to the surface (land or water).  Construction
requirements seek to protect the pit from intrusion of surface
water, be constructed of impervious material, and be located at
   "Onsite disposal facilities" are presumed to include
     onsite evaporation pits. The Division of Oil,  Gas, and
     Mining rules do not include specific guidance  regarding
     onsite disposal facilities, however, their reserve pit
     guidance is probably applied to produced water pits as
     well.  There appears to be some overlap in authority
     for onsite pits between the Utah Department of Health
     and the Division of Oil, Gas, and Mining.
                                A-lll

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least 5 feet above groundwater.   Pits must be properly located
above ordinary high water marks  for surface waters.   Pits may not
be located within 200 feet of a  fault or at the bottom of creeks,
rivers, or natural drainages.

Surface disposal into unlined ponds is allowed if the wastewater
contains less than 5,000 mg/1 total dissolved solids,- and if the
wastewater does not contain "objectionable or toxic  levels of any
constituent as shown by chemical analyses."   This requirement is
waived for sites discharging less than 5 barrels of  water per
day.  Small dischargers into unlined pits are required only to
notify the Department of Health  with minimal site information.
Application for approval to discharge into unlined pits must
include an estimate of waste volume, estimate of percolation and
net evaporation rates, and information about freshwater aquifers
within a one square mile radius  of the proposed site.

For disposal ponds without artificial liners which receive more
than 100 barrels per day, the Department of Health requires a
monitoring program including monitoring wells.

For artificially-lined ponds, the Department of Health requires
"an underlying gravel-filled sump and lateral system, or other
suitable devices for detection of leaks."  The Department of
Health, Bureau of Water Pollution Control, is considering a
requirement that all ponds (lined or unlined) be equipped with a
leak detection system.  In general, the Bureau feels that pit
siting is more important than construction requirements.
                                A-112

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REFERENCES

Interstate Oil Compact Commission,  The Oil and Gas Compact
     Bulletin, Volume XLIV, Number 2,  December 1985.

U. S. Environmental Protection Agency, Proceedings - Onshore
     Oil and Gas State/Federal Western Workshop,  December
     1985.

Hunt, Gil.  Letter to Ms. Susan de Nagy with attachments
     dated September 20, 1985.

Swindel, D. B.  Letter to Kerri Kennedy with attachments
     dated June 6, 1986.

"The Oil and Gas Commission General Rules," effective
     December 2, 1985.

Utah Water Pollution Control Committee, State of Utah,
     Department of Health, Division of Environmental Health,
     Wastewater Disposal Regulations  Part VI Surface
     Disposal of Produced Water from Gas and Oil Wells,
     January 20, 1982.
                                A-113

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                            VIRGINIA
INTRODUCTION

Virginia produced 33,000
barrels of oil from 35
producing oil wells and 9 x 109
cubic feet of gas from 499 gas
wells in 1984.
STATE REGULATORY AGENCY

One agency principally regulates oil and gas activities in
Virginia:

     -    Virginia Department of Mines,  Minerals,  and Energy,
            Oil and Gas Section

The Oil and Gas Section is governed by the Virginia Oil and Gas
Act and by the Rules and Regulations for Conservation of Oil and
Gas Resources and Well Spacing as issued by the Virginia
Department of Labor and Industry.  The Oil and Gas Section issues
drilling permits and regulates the details of the  industry
through this process.  The State does not have primacy for the
UIC program Class II wells, but there is no underground injection
of fluids currently associated with the Virginia industry.  There
has been drilling on Federal lands, but such lands are owned by
the National Forest Service and the Service serves as another
surface landowner in such drilling activity.  The  Service would
manage their concerns principally through the surface lease
process.  The Virginia Water Control Board would become involved
only in the event of an incident that potentially could affect
surface water quality.
                                A-114

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STATE RULES AND REGULATIONS

DRILLING

Virginia Regulations 3.02 (f) and (g) require pits to be
associated with the drilling of a well that will preclude water
pollution.  Pits must be lined with a plastic liner,;and the
drill site and any associated pits must be reclaimed .within 1
year after drilling ceases.

In general, there is little fluid associated with the drilling
process in Virginia.  Such fluids as may be present are not high
in chloride concentration.  Generally, the fluid is tested by the
driller, the pH is adjusted if necessary, and the water is
sprayed on the surrounding land.  Pit muds are buried on site and
the pit area reclaimed.


PRODUCTION

Almost no fluid is associated with gas production in Virginia.
Very small amounts of fluids are produced with the 100 gallons of
oil produced per day statewide.  As a result, produced waters
generally are held in"steel tanks.  Dikes are required around the
tanks, and fluids generally are allowed to flow into the diked
area, where they disappear through evaporation and infiltration.


OFFSITE AND COMMERCIAL PITS

No use is made of offsite and commercial pits in Virginia.
                                A-115

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REFERENCES

Summary of State Statutes and Regulations for Oil and Gas
     Production.  1986.  Interstate Oil and Gas Commission
     (June).

The Oil and Gas Compact Bulletin.  1985.  Interstate Oil
     Compact Commission(June).

Personal Communication:

     James Henderson, State Oil  and Gas Inspector (703) 628-8115
                                 A-116

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                          WEST VIRGINIA
INTRODUCTION

West Virginia produces about
four million barrels of oil per
year from 15,475 wells.  Gas
production of 136 billion cubic
feet annually is realized from
30,700 wells.  Between 1,800
and 2,5X)0 drilling permits are
issued annually, although the
number of wells drilled has
dropped in 1986.
STATE REGULATORY AGENCIES

Two agencies regulate oil and gas acstivities in West Virginia:

          West Virginia Department of Energy
          U.S. Bureau of Land Management

The recently-created West Virginia Department of Energy has
statutory authority over oil and gas activities in the State.
The Department of Energy is in the process of assuming
responsibilities from the Department of Mines, Office of Oil and
Gas (historically the drilling permitting authority), and from
the Department of Natural Resources, Water Resources Division and
Reclamation Division.  West Virginia has proposed regulations and
hearings have been conducted regarding the oil and gas industry.
However, new regulations cannot go into effect until the State
legislature approves them and the Governor signs a proclamation.
Thus, old regulations remain in place.  In the interim, the
Department of Natural Resources and Department of Mines are
working cooperatively with the Department of Energy towards a
transition of responsibilities.

The current reorganization seriously complicates a presentation
of existing regulations.  For instance, the Department of Natural
Resources, Water Resources Division, retains NPDES delegation,
although the Department of Energy has applied for delegation
specifically limited to oil and gas wastes and certain other
industries.  This parallel permitting responsibility is
duplicated for other regulatory areas as well.
                                A-117

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The U.S. of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands.   Their
rules are discussed in a separate section,  Federal Agencies.   The
U.S. Forest Service retains surface rights  on Federal forests and
grasslands.  They coordinate surface stipulations with  the Bureau
of Land Management where applicable.


STATE RULES AND REGULATIONS

The following discussion of State rules and regulations is based
on proposed rules and regulations that are  expected to  become
effective in early 1987.  Current copies of the proposed rules
stress an outline of the authority and definitions of
responsibilities rather than specific waste handling regulations.


DRILLING

The Department of Energy issues drilling permits for all oil  and
gas wells in the State.  Suitable applications must provide
detailed information regarding locale, site, and construction
plans.  The Department of Energy has well construction
requirements which include casing, cement type, or cement
strength.  Permitted drillers are required  to keep work records
during the period of work.  Similar information is required for
applications for plugging and abandonment.


PRODUCTION

The West Virginia Department of Energy is applying for  NPDES
delegation for discharges from oil and gas  operations.   The
regulations are closely modeled after 40 CFR 124.
                                A-118

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REFERENCES

Interstate Oil and Gas Compact Commission, The Oil and Gas
     Compact Bulletin, Volume XLIV, Number 2,  December 1985,

Personal communication with Mr. Ted Streit, former head of
     Office of Oil and Gas.  September 25, 1986.

West Virginia Department of Energy, "Notice of Public
     Hearing and Comment Period on Proposed Rules," not
     dated.  Received October 1986.

Streit/ T. M.  Letter submitted to William A.  Telliard, U.
     S. EPA, May 28, 1985.

West Virginia Legislative Rule Department of Energy -
     Division of Oil and Gas Chapters 22-1 and 22B-1
     Series 2.

West Virginia Meeting Report.  1985.  Proceedings of the
     Onshore Oil and Gas Workshop. U.S. EPA, Washington,
     D.C. (March 26-27 in Atlanta, GA).
                                A-119

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                             WYOMING
INTRODUCTION

Wyoming produced 127,763,000
barrels of oil and 600,137
million cubic feet of gas in
1984.  Production is from
12,463 oil wells and 2,280 gas
wells.  Although many of these
wells had been producing for
30 to 40 years, discharges of
produced water were not
permitted until the Clean
Water Act was passed in 1972.
STATE REGULATORY AGENCIES

Three agencies regulate oil and gas activity in Wyoming:

     -  Wyoming Department of Environmental Quality
     -  Wyoming Oil and Gas Conservation Commission
     -  U.S. Department of Interior, Bureau of Land Management

The Wyoming Oil and Gas Conservation Commission has the authority
to "monitor and regulate, by the promulgation of rules and the
issuance of orders, the location, operation, and reclamation of
produced water and emergency overflow pits associated with oil
and gas production."  The Commission regulates industry practices
and procedures with regard to construction, location, and
operation of onsite drilling and onsite production pits which
serve a single well.  The Oil and Gas Conservation Commission is
chaired by the Governor of Wyoming, and four other commis-
sioners.  The Office of the State Oil and Gas Supervisor is
primarily responsible for regulation of industry practices as
described above.

Wyoming is an NPDES-delegated State.  The Wyoming Department of
Environmental Quality has NPDES authority for all discharges.
Department of Environmental Quality has "jurisdiction and
authority to regulate through monitoring and the promulgation of
rules, regulations and orders governing treatment works and
disposal systems and other facilities capable of causing or
contributing to pollution, pursuant to W.S. 35-11-301."  These
responsibilities generally cover offsite commercial ponds and
disposal pits serving two or more wells.  The Department of
Environmental Quality also has permitting authority for land
application or discharge of drilling wastes.
                                A-120

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The cooperative roles between the Wyoming Oil and Gas Commission
and the Department of Environmental Quality is described in
"Memorandum of Agreement between the Wyoming Oil and Gas
Conservation Commission and the Department of Environmental
Quality," dated September 13, 1983, and in the memorandum from
the Wyoming Attorney General's office to the Office o.f the State
Oil and Gas Supervisor dated January 18, 1982.

The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands.  For drilling on Federal land, the
U.S. Bureau of Land Management handles all Applications to Drill.
The Bureau requires extensive environmental documentation,
including environmental assessments and develops environmental
impact statements for drilling on Federal land.  For produced
water, the Bureau routinely approves discharges of produced water
up to 5 barrels per day under Notice to Lessees 2B.


STATE RULES AND REGULATIONS

DRILLING

Section 326 of the Rules and Regulations of the Wyoming Oil and
Gas Conservation Commission states, "At no time will drilling
fluids be discharged into live waters or into any drainages that
lead to live waters of the state."  Application forms for
temporary earthen pits (including reserve pits) allow only one of
three designations for final disposition of pit contents:
evaporation, hauling, or injection in a disposal well.  No
manifest system is in effect for hauled wastes.

Earthen pits are required to be constructed to "prevent pollution
of streams, underground water, or to unreasonably damage the
surface of leased premises or other lands."  The rules do not
require pit or pond liners, leak detection, or other modifi-
cations to a simple earthen pit except where "potential for
communication between the pit contents and surface water or
shallow ground water is high."  The State Supervisor makes this
determination based on the information presented in the permit
application (Form 14A or 14B).

The Department of Environmental Quality allows discharge of
drilling fluids from pits associated with the drilling of oil
and/or gas wells under exceptional conditions, including a
"complete analysis of the drilling liquid, the volume of liquid
to be discharged, the location of the proposed discharge, and the
name of the receiving water, " have been submitted to Department.
of Environmental Quality.  These requirements must meet the
approval of the Department of Environmental Quality and the
landowner prior to discharge.  (Wyoming Department of
Environmental Quality Water Quality Rules and Regulations Chapter
VII, p.5)
                                A-121

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Workover and completion pits are exempted from permit
requirements if their use is limited to containment of
oil/water.  No definition of oil/water is found in the rules;
however, the Commission staff explains that these pits are not
allowed to contain acids or other chemical fluids.  Fresh and
potable water are defined as (1) having TDS less than 10,000
milligrams per liter, (2) reasonably suited for domestic,
agricultural, or livestock use,  and (3) suitable for fish or
aquatic life.  State law adopts  these limitations at the guidance
of the Federal UIC program.

Chemical use which destroys, removes, or reduces the fluid seal
of a reserve pit is prohibited.   Chemical or mechanical treatment
of reserve pits must be specially allowed after a public hearing
before the Oil and Gas Commission.

Earthen pits must be reclaimed within 1 year of the date of last
use unless the Supervisor grants a specific variance.  Bonds
guaranteeing pit reclamation are not released until the Commis-
sion has inspected and approved  the reclaimed pit.


PRODUCTION

The Oil and Gas Commission requires permits for brine pits
receiving more that 5 barrels of water per day.  Pits receiving
less than 5 barrels of water per day (i.e., less than 76,650
gallons per year) are unregulated.  Even for larger pits, liners
are required only in special cases where "potential for
communication between the pit contents and surface water or
shallow ground water is high."

The Wyoming Department of Environmental Quality's Water Quality
Rules and Regulations, Chapter VII, describes the rules for
surface discharge of water associated with the production of oil
and gas.  Discharge of produced water may be permitted by the
Department of Environmental Quality if certain effluent
limitations are met  (including 2000 mg/1 chlorides, 3000 mg/1
sulfates, 5000 mg/1 TDS, pH between 6.5 and 8.5, 10 mg/1 oil and
grease, toxic substances, and other reserved additional
limitations).  This discharge is permitted through the NPDES
system.  Exceptions to the foregoing limitations may be granted
if "beneficial use" can be properly demonstrated to the Depart-
ment of Environmental Quality, and unless the landowner or the
Department of Environmental Quality determines that environmental
damage would result.


OFFSITE AND COMMERCIAL PITS

The Department of Environmental Quality regulates offsite and
commercial pits.  Chapter III of the Wyoming Water Quality Rules
and Regulations outlines three basic requirements for permitting
commercial pits.  First, the facility must demonstrate that its


                                 A-122

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construction will not allow a discharge to groundwater by direct
or indirect discharge, percolation,  or filtration.   Second,  the
quality of wastewater will not cause violation of any groundwater
standards.  Finally,  that existing geology will not allow a
discharge to groundwater.
                                A-123

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REFERENCES

Personal communication with Ms. Janie Nelson,  Wyoming Oil
     and Gas Commission, August 14, 1986.  Telephone (307)
     234-7147.

Personal communication with Mr. E. J. Fanning, Department of
     Environmental Quality, Water Quality Division, August
     11 and August 14, 1986.  Telephone (307)  777-7781.

Wyoming Department of Environmental Quality Water Quality
     Rules and Regulations, Chapter III, VII,  IX,  September
     5, 1978.
                                 A-124

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SUMMARY OF FEDERAL REGULATIONS
              A-125

-------
                       U.S.  FOREST SERVICE
National Forest Systems,  which include National forests and
National grasslands,  are administered by the U.S.  Forest Service
within the U.S. Department of Agriculture.   Every application to
drill for oil and gas that impacts the above lands is reviewed by
the Service.

Where a road use permit is required,  or where permit conditions
related to oil and gas drilling are appropriate,  such are
conveyed by interagency communication to the Bureau of Land
Management.  The Bureau issues the lease conditions at the
request of the U.S. Forest Service.

The nature of any lease condition depends upon case-by-case site
specific requirements.

Communication:

Craig Losche, U.S. Forest Service (703) 235-9873
                                A-126

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                    BUREAU OF LAND MANAGEMENT
INTRODUCTION

Exploration, development, drilling, and production of onshore oil
and gas on Federal and Indian lands are regulated separately from
non-Federal lands.  This separation of authority is significant
for western States where oil and gas activity on Federal and
Indian lands is a large proportion of statewide activity.


REGULATORY AGENCIES

The U.S. Department of the Interior is authorized by 30 CFR 221.4
and 221.32 for regulation of onshore oil and gas practices on
Federal and Indian lands.  The Department of Interior administers
their regulatory program through state Bureau of Land Management
or U.S. Geological Survey District offices.  These agencies
generally have procedures in place for coordination with state
agencies on regulatory requirements.  Where written agreements
are not in place, the Bureau of Land Management usually works
cooperatively with the respective state agencies.

The Bureau works closely with the U.S. Forest Service for surface
stipulations in Federal forests or Federal grasslands.  This
arrangement is also provided for in the Federal regulations.


RULES AND REGULATIONS

The Bureau of Land Management has authority over all aspects of
oil and gas activities on Federal lands.  The authority includes
leasing,  bonding, and royalty arrangements, construction and well
spacing requirements, waste handling,  waste disposal,  site
reclamation,  and site maintenance as well as others areas.  These
responsibilities are extensive and the documentation regarding
them is voluminous;  only those portions of the regulations
relating to waste handling,  treatment,  and disposal will be
summarized herein.

Historically the Bureau of Land Management has regulated oil and
gas activities through "Notice to Lessees."  The requirements of
current notices are  described below.   The Bureau is working to
revise all notices into Oil and Gas Orders, which will be Fed-
erally promulgated.   To date,  Oil and Gas Order No.  1  has been
issued.  Other oil and gas orders are expected to be promulgated
in the next year.
                               A-127

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DRILLING

The Bureau of Land Management considers reserve pits, and some
other types of pits, as temporary.  Notice to Lessees 2B contains
the following provisions for "Temporary Use of Surface Pits:"

     Unlined surface pits may be used for handling or storage
     of fluids used in drilling, redrilling, reworking,
     deepening, or plugging of a well provided that such
     facilities are promptly and properly emptied and
     restored upon completion of the operations.  Mud or
     other fluids contained in such pits shall not be
     disposed of by cutting the pits walls without the prior
     authorization of the District Engineer.  Until finally
     restored, unattended pits must be fenced to prevent
     access by livestock and wildlife.  Unless otherwise
     specified by the District Engineer, unlined pits may be
     used for well evaluation purposes for a period of 30
     days.

Land spreading of drilling and reworking wastes by breaching pit
walls is allowed when approved by the District Engineer.


PRODUCTION

Produced waters may be disposed into the subsurface, either for
enhanced recovery of hydrocarbon resources or for disposal.  The
operator must present detailed information regarding the proposed
disposal site, including subsurface configuration of the proposed
injection well, to the Bureau of Land Management prior to
approval to inject.  This documentation is required to ensure
that the injected wastes will be confined to a receiving
formation of poor quality.  Further, the operator must identify
the sources of the produced water, must submit estimated daily
quantities of produced water, and must submit an analysis of the
water.  The analysis is limited to total dissolved solids, pH,
chlorides, and sulfates.

The Bureau of Land Management also permits disposal of produced
water into lined and unlined pits.  "Lined and unlined pits
approved for water disposal shall:

     1.   Have adequate storage capacity to safely
          contain all produced water even in those
          months when evaporation rates are at a
          minimum.

     2.   Be constructed, maintained, and operated to
          prevent unauthorized surface discharges of
          water.  Unless surface discharge is
          authorized, no siphon, except between pits,
          will be permitted.
                               A-128

-------
     3.   Be fenced to prevent livestock or wildlife
          entry to the pit, when required by the
          District Engineer.

     4.   Be kept reasonable free from surface
          accumulations of liquid hydrocarbons by use
          of approved skimmer pits, settling tanks,  or
          other suitable equipment.

     5.   Be located away from the established drainage
          patterns in the area and be constructed so as
          to prevent the entrance of surface water."
       9
For disposal into lined pits, the operator must submit:

     - Site identification
     - Planned waste quantities
     - Net evaporation data
     - Method of disposal for accumulated solids
     - Information documenting the liner material
         and the impervious nature of the proposed liner
     - Method used for leak detection

The operator must submit a water analysis "which include the
concentrations of chlorides, sulfates, and other constituents
which are toxic to animal, plant, or aquatic life."    No list of
required analytes is included in the Notice.

Leak detection is required for all lined produced water disposal
pits.  The recommended detection system is an "underlying gravel-
filled sump and lateral system."  Other systems may be considered
acceptable upon application and evaluation.

Oil and gas operators may be permitted to use unlined pits on any
one of the following bases:  If the pit will receive 5 barrels or
less of water per day (monthly basis), no permit is  required.  If
the water contains less than 5,000 ppm total dissolved solids,
and does not contain "objectionable levels of any constituent
toxic to animal plant, or aquatic life," use of unlined pits is
allowed.  If the water will be used for wildlife watering,
irrigation, or livestock watering, unlined pits may be used.
Unlined pits may be used when the produced water is  of better
quality than surface or subsurface waters of the area.  Unlined
pits permitted for surface discharges under the National
Pollutant Discharge Elimination System are also allowed.

Operators are required to provide information regarding the
sources and quantities of produced water, topographic map,
evaporation rates, estimated soil percolation rates, and "depth
and extent of all usable water aquifers in the area."
                               A-129

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REFERENCES

Personal communication with Mr. Steve Spector September 23,
     1986.

U.S. Land Management, "Federal Onshore Oil and Gas Leasing
     and Operating Regulations.  Not dated.

43 CFR 3100 (entire group)

U.S. Bureau of Land Management, NTL-2B.

U.S. Department of the Interior - Geological Survey
     Division.  " Notice to Lessees and Operators of Federal
     and Indian Oil and Gas Leases (NTL-2B)," not dated.
                                A-130

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              U.S. ENVIRONMENTAL PROTECTION AGENCY
                 EFFLUENT LIMITATIONS GUIDELINES


On October 30, 1976,  the Interim Final BPT Effluent Limitations
Guidelines for the Onshore Segment of the Oil and Gas Extraction
Point Source Category were promulgated.  [41 FR 44942] The
rulemaking also proposed Best Available Technology Economically
Achievable (BAT), and New Source Performance Standards (Table
1).

On April 13, 1979, BPT Effluent Limitations Guidelines were
promulgated for the Onshore Subcategory, Coastal Subcategory, and
the Agricultural and Wildlife Water Use Subcategory of the Oil
and Gas Extraction Industry.  [44 FR 22069]    Effluent limita-
tions were reserved for the Stripper Subcategory due to lack of
technical data.

The 1979 BPT regulation established a zero discharge limitation
for all wastes under the Onshore Subcateogy.  Zero discharge
Agricultural and Wild-life Subcategory limitations were
established, except for produced water which has a 35 mg/1 oil
and grease limitation.

The American Petroleum Institute (API) challenged the 1979
regulation (including the BPT regulations for the Offshore
Subcategory).  [661 F.2D.340(1981)]  The court remanded EPA's
decision transferring 1,700 wells from the Coastal to the Onshore
Subcategory. [47 FR 31554]  The court also directed EPA to
consider special discharge limits for gas wells.  Table 2
provides regulatory details related to onshore oil and gas
activities.
                                A-131

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         TABLE  1.   SUMMARY OF MAJOR  REGULATORY ACTIVITY
                   RELATED TO ONSHORE OIL AND GAS
October 13, 1976 -  Interim Final BPT Effluent Limitations
                    Guidelines and Proposed (and Reserved) BAT
                    Effluent Limitations Guidelines and New
                    Source Performance Standards for the Onshore
                    Segment of the Oil and Gas Extraction Point
                    Source Category


April 13, 1979 -    Final Rules
                         - BPT Final Rules for the Onshore,
                           Coastal, and Wildlife and Agricultural
                           Water Use Subcategories
                         - Stripper Oil Subcategory Reserved
                         - BAT and NSPS never promulgated


July 21, 1982 -     Response to American Petroleum Institute vs
                    EPA Court Decision
                         - Recategorization of 1700 "onshore"
                           wells to Coastal Subcategory
                         - Suspension of regulations for Santa
                           Maria Basin, California
                         - Planned reexamination of marginal gas
                           wells for separate regulations
                                A-132

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             TABLE 2.  ONSHORE SEGMENT SUBCATEGORIES


o  ONSHORE:

     O  BPT LIMITATION

        - ZERO DISCHARGE

     o  DEFINED:  JJQ discharge of wastewater pollutants into
        navigable waters from ANY source associated with
        production, field exploration, drilling, well completion,
        or well treatment (i.e., produced water, drilling muds,
        drill cuttings, and produced sand).

O  STRIPPER (OIL WELLS):*

     O  CATEGORY RESERVED

     o  DEFINED:  TEN barrels per well per calendar day or less
        of crude oil.

o  COASTAL

     O  BPT LIMITATIONS

         No Discharge of Free Oil (No Sheen)

         Oil and Grease:  72 mg/1 (Daily)
                            48 mg/1 (Average Monthly)
                            (Produced Waters)

     o  DEFINED:  Any body of water landward of the territorial
        seas,  or any wetlands adjacent to such  waters.

O  WILDLIFE  AND AGRICULTURE USE

     O  BPT  LIMITATIONS

         Oil and Grease:  35 MG/L (Produced Waters)
         Zero Discharge:  ANY Waste Pollutants

     o  DEFINED:  That produced water is of good enough quality
        to be used for wildlife or livestock watering or other
        agricultural uses ...  west of the 98th  meridian.
*This subcategory does not include marginal gas wells.
                                A-133

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                  UNDERGROUND INJECTION CONTROL


The Underground Injection Control (UIC) Program was established
under Part C of the Safe Drinking Water Act (SDWA)  to provide
minimum standards for procedural and technical requirements for
individual State and Federal UIC Programs.   Part C  of the SDWA
requires the EPA to:  (1) identify a list of States for which UIC
programs may be necessary; (2) approve or disapprove, in whole or
in part, UIC programs submitted by the listed States; and (3)
develop programs and regulate those States that do  not have
approved UIC programs.  The Federal UIC Program is  defined in 40
CFR Parts 144,  145, and 146.

Table 3 is a list of States having full or partial  primacy over
their particular UIC Programs.  The second column from the left
in Table 3 lists the section of the SDWA under which the States
applied for approval of their UIC Programs.  The third column
from the left lists the classes of wells, defined in Table 4, for
which primacy has been given.  The classes of wells that a State
can regulate depend upon the SDWA section under which a State's
authority is granted.  Section 1422 was originally  designed to
cover all classes of wells. Brine disposal injection wells were
later addressed specifically in Section 1425, which was created
by Congress (Dec. 5, 1980) to further define the conditions by
which these wells would be regulated.  In essence,  a State may
show that it has a program already in place that has been
effective in protecting underground sources of drinking water and
that includes record keeping, reporting, permitting, and
inspections authority over Federal agencies, and assurance that
authorized wells do not endanger underground sources of drinking
water.

Minimum standards for UIC programs as defined in 40 CFR 144, 145,
and 146 include, respectively, permitting requirements, guidance
to obtain approval for State primacy, and technical criteria and
standards to be met in permits and authorizations.   Part 144 also
serves as part of the UIC program for States to be  administered
by EPA.  Part 147 lists and sets specific criteria  for those
States whose UIC programs are administered by EPA.
                                A-134

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                 TABLE 3.   UIC PRIMACY STATES (PROGRAMS APPROVED)

                                                  Date June 9,  1986
STATE
TYPE
CLASSES
DATE APPROVED
*Full primacyr as of date indicated
**Partial primacy
FR CITE
Oklahoma
Texas
New Mexico
Louisiana*
Texas*
Oklahoma*
Arkansas
Alabama
New Hampshire*
Utah
Wyoming
Massachusets*
Utah*
Nebraska
Florida**
California**
Guam*
New Mexico*
Wyoming*
New Jersey*
North Dakota
Ohio
Alabama*
Maine*
Mississippi**
Wisconsin*
Kansas
Missouri
West Virginia*
Illinois
Illinois*
Kansas*
Arkansas*
Connecticut*
Colorado**
Delaware*
Maryland*
North Carolina*
Georgia*
Nebraska*
Vermont*
South Carolina*
Rhode Island*
Washington*
North Dakota*
Oregon*
South Dakota**
Ohio*
Idaho*
Missouri*
CNMI*
Alaska**
1425
1422
1425
1422/25
1425
1422
1422
1425
1422
1425
1425
1422
1422
1425
1422
1425
1422
1422
1422
1422
1425
1425
1422
1422
1422
1422
1422
1425
1422/25
1425
1422
1425
1425
1422
1425
1422
1422
1422
1422
1422
1422
1422
1422
1422
1422
1422/25
1425
1422
1422
1422
1422
1425
II
I, HI,
II
I - V
II
Ir Ulr
I, IHr
II
I - V
II
II
I - V
It Hit
II
I, HI,
II
I - V
I, IH
Ir III,
I - V
II
II
If III,
I - V
If IHf
I - V
If III,
II
I - V
II
I, III,
II
II
I - V
II
I - V
I - V
I - V
I - V
If III,
I - V
I - V
I - V
I - V
If III,
I - V
II
If III,
I - V
If III,
I - V
II

TV, V



IV, V
rv, v





IV, V

IV, V


IV, V
rv, v



rv, v

IV, V

rv, v



IV, V








IV, V




IV, V


TV, V

TV, V


December 2, 1981
January 6, 1982
February 5, 1982
April 23, 1982
April 23, 1982
June 24, 1982
July 6, 1982
August 2, 1982
September 21, 1982
October 8, 1982
November 22, 1982
November 23, 1982
January 19, 1983
February 3, 1983
February 7, 1983
February 11, 1983
May 2, 1983
July 11, 1983
July 15, 1983
July 15, 1983
August 23, 1983
August 23, 1983
August 25, 1983
August 25, 1983
August 25, 1983
September 30, 1983
December 2, 1983
December 2, 1983
December 9, 1983
February 1, 1984
Feburary 1, 1984
February 9, 1984
March 26, 1984
March 26, 1984
April 2, 1984
April 5, 1984
April 19, 1984
April 19, 1984
April 19, 1984
June 12, 1984
June 22, 1984
July 10, 1984
August 1, 1984
August 9, 1984
September 21, 1984
September 25, 1984
October 24, 1984
November 29, 1984
June 7, 1985
July 17, 1985
July 17, 1985
May 6, 1986
46 FR 58488
47 FR 618
47 FR 5412
47 FR 17487
47 FR 17488
47 FR 27273
47 FR 29236
47 FR 33268
47 FR 41561
47 FR 44561
47 FR 52434
47 FR 52705
48 FR 2321
48 FR 4777
48 FR 5556
48 FR 6336
48 FR 19717
48 FR 31640
48 FR 32343
48 FR 32343
48 FR 38237
48 FR 38238
48 FR 38640
48 FR 38641
48 FR 38641
48 FR 44783
48 FR 54350
48 FR 54349
48 FR 55127
49 FR 3990
49 FR 3991
49 FR 4735
49 FR 11179
49 FR 11179
49 FR 13040
49 FR 13525
49 FR 15553
49 FR 15553
49 FR 15553
49 FR 24134
49 FR 25633
49 FR 28057
49 FR 30698
49 FR 31875
49 FR 37065
49 FR 37593
49 FR 42728
49 FR 46896
50 FR 23956
50 FR 28941
50 FR 28942
51 FR 16683
                      A-135

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           TABLE 4.  CLASSIFICATION OF INJECTION WELLS
Class I     o  Wells used by generators of hazardous waste or
               owners or operators of hazardous waste management
               facilities to inject hazardous waste beneath the
               lowermost formation containing,  within one quarter
               (1/4) mile of the well bore, an underground source
               of drinking water.

            o  Other industrial and municipal disposal wells
               which inject fluids beneath the lowermost
               formation containing, within one quarter mile of
               the well bore,  an underground source of drinking
               water.

Class II       Wells used to inject fluids:

            o  Which are brought to the surface in connection
               with conventional oil or natural gas production
               and may be commingled with waste waters from gas
               plants which are an integral part of production
               operations, unless those waters are classified as
               a hazardous waste at the time of injection;

            o  For enhanced recovery of oil or natural gas;  and

            o  For storage of hydrocarbons which are liquid at
               standard temperature and pressure.

Class III      Wells used to inject for extraction of minerals
               including:

            o  Mining of sulfur by the Frasch process.

            o  In situ production of uranium or other metals.
               This category includes only in situ production
               from ore bodies which have not been
               conventionally mined.  Solution mining of
               conventional mines such as stopes leaching is
               included in Class V.

            o  Solution mining of salts or potash.

Class IV    o  Wells used by generators of hazardous waste  or of
               radioactive waste, by owners or operators of
               hazardous waste management facilities,  or by
               owners or operators of radioactive  waste disposal
               sites to dispose of hazardous waste or radioactive
               waste into a formation which within one quarter
               (1/4) mile of the well contains an  underground
               source of drinking water.
                               A-136

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           TABLE 4.   CLASSIFICATION OF INJECTION WELLS
                           (Continued)


Class IV    o  Wells used by generators of hazardous waste or of
(Cont'd)       radioactive waste,  by owners or operators of
               hazardous waste management facilities or by owners
               or operators of radioactive waste disposal sites
               to dispose of hazardous waste or radioactive waste
               above a formation which within one quarter (1/4)
               mile of the well contains an underground source of
               drinking water.

            o  Wells used by generators of hazardous waste or
               owners or operators of hazardous waste management
               facilities to dispose of hazardous waste, which
               cannot be classified under Sect. 146.05(a)(l) or
               146.05(d) (1) and (2) (e.g., wells used to dispose
               of hazardous wastes into or above a formation
               which contains an aquifer which has been exempted
               pursuant to Sect. 146.04).

Class V     o  Injection wells not included in Class I, II, III,
               or IV.
                               A-137

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REFERENCES

Federal Register, 40 CFR Parts 144,  145, 146, and 147.

Safe Drinking Water Act, Part C, December 16, 1974, as amended by
     PL 96-502, December 5, 1980.

Personal Communication with Mr. Mario Salazar, U.S. EPA UIC
     Program, October 7, 1986.  Telephone 202- 382-5561.
                                A-138

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             Appendix B
Glossary of Terms and Abbreviations

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                                 APPENDIX B

                         GLOSSARY AND ABBREVIATIONS


Annular Injection.  Long-term  disposal  of wastes between the outer wall of
the drill stem or tubing and the inner wall of the casing or open hole.

Annulus or Annular  Space.   The space between the  drill  stem and  the  wall
of the hole or casing.

Barite.  Barium sulfate.  An additive used to weight drilling mud.

Barrel.  Forty-two United States gallons at 60癋.

Bentonite.   A clay additive used to increase the viscosity of drilling mud.

Blowout.   A  wild and  uncontrolled flow of subsurface formation  fluids at
the earth's surface.

Blowout Preventer  (BOP).   A device  to  control  formation  pressures  in  a
well  by  closing  the   annulus  when  pipe is  suspended  in  the  well or by
closing the top of the casing at other times.

Brackish Water.  Water containing low concentrations of any soluble salts.

Brine.  Water  saturated with or containing a high  concentration  of common
salt  (sodium  chloride);  also  any  strong saline  solution containing  other
salts such as calcium chloride, zinc chloride, calcium nitrate,  etc.

BS&W.   Bottom  sediment  and  water  carried  with  the   oil.   Generally,
pipeline  regulation limits BS&W to 1 percent of the volume of oil.
                                      B-l

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Casing.  Large  steel  pipe  used  to  "seal  off"  or  "shut  out"  water  and
prevent caving of  loose gravel formations when drilling  a  well.   When the
casings are  set,  drilling continues  through and below  the casing with  a
smaller bit.   The overall  length of this  casing is called the  string of
casing.  More than one string inside the other may be used  in  drilling the
same well.

Centralized  Brine  Disposal  Pit.   An  excavated  or above grade  earthen
impoundment remotely located from the oil or gas operations from  which it
receives produced  fluids  (brine).  Centralized pits usually receive fluids
from many wells,  leases, or fields.

Centralized Combined Mud/Brine  Disposal  Pit.  An excavated or above  grade
earthen impoundment  remotely located  from  the oil  or gas  operations from
which   it    receives   produced   fluids   (brine)  and   drilling   fluids.
Centralized pits usually receive fluids from many wells,  leases,  or fields.

Centralized  Mud  Disposal  Pit.   An  excavated  or  above  grade  earthen
impoundment  remotely  located from  the  drilling  operations  from which it
receives drilling  muds.   Centralized pits usually receive fluids from many
drilling sites.

Centralized  Treatment  Facilities  (Mud or Brine).   Any  facility  accepting
drilling  fluids  or  produced  fluids  for  processing.    This  definition
encompasses  municipal  treatment  plants,  private  treatment facilities,  or
publicly  owned  treatment  works  for  treatment  of  drilling  fluids  or
produced fluids.   These  facilities  usually  accept  a  spectrum  of  wastes
from  a number of  oil, gas, or geothermal  sites,  or  in  combination with
wastes from other sources.

Centrifuge.   A device  for  the mechanical  separation   of  solids  from  a
liquid.  Usually  used  on weighted  muds to recover the mud and discard
solids.  The centrifuge  uses   high-speed mechanical rotation to  achieve
this  separation as distinguished from the  cyclone-type  separator  in which
the fluid energy alone provides the separating force.

Chemical-Electrical Treater.   A  vessel   that  utilizes   surfactants,  other
chemicals,  and an electrical field to break oil-water emulsions.

Christmas Tree.  Assembly of fittings and valves at the tip of the casing
of an oil well that controls the  flow of oil from the well.

Circulate.   The movement of fluid from the suction pit through pump,  drill
pipe, bit annular space in the hole, and back again  to the suction pit.

Clean  Water  Act.   The  Federal Water Pollution Control  Act Amendments of
1972  (33 U.S.C.  1251  et sea.), as  amended  by the Clean Water Act  of 1977
(P. L. 95-217).
                                       B-2

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Closed-In.  A well  capable of  producing oil or  gas,  but  temporarily not
producing.

Completion  Operations.   Work  performed in  an  oil or  gas well  after the
well has  been drilled to the point where  the production string  of  casing
is  to  be  set,  including  setting  the  casing,  perforating,  artificial
stimulation, production  testing,  and  equipping  the  well  for  production,
all prior to the  commencement  of  the  actual  production of oil  or  gas in
paying quantities, or in the case of an injection or service  well,  prior
to when the well is plugged and abandoned.

Condensate.  Hydrocarbons  that are in  the  gaseous state  under  reservoir
conditions but which become liquid either in passage up the hole  or  at the
surface.

Conduction  Dominated  System.    A  geothermal   energy  system  created  by
thermal conduction of heat from deep within the  earth to the surface.

Connate  Water.   Water  that probably  was  laid   down  and  entrapped  with
sedimentary  deposits, as  distinguished  from  migratory  waters  that  have
flowed into deposits after they were laid down.

Cuttings.  Small pieces  of formation .that are the  result of the chipping
and/or crushing action of the bit.

Cyclone.   Equipment,  usually cyclone type, for removing  drilled  sand from
the drilling mud stream and from produced fluids.

Derrick and  Substructure.   Combined foundation and overhead structure  to
provide for the hoisting and lowering necessary  for drilling.

Desilter.  Equipment,  normally cyclone  type,  for  removing  extremely fine
drilled solids from the drilling mud stream.

Development  Facility.   Any fixed  or mobile  structure  addressed by  this
document  that  is  engaged in  the  drilling  and  completion of  productive
wells.

Disposal  Well.   A well  through  which  water   (usually  salt   water)  is
returned to subsurface formations.

Drill Cuttings.   Particles generated by drilling  into  subsurface geologic
formations and carried to the surface with the drilling fluid.
                                      B-3

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Drilling Fluid.   The circulating  fluid  (mud) used in  the  rotary drilling
of wells to  clean and condition the hole  and to  counterbalance  formation
pressure.  A water-base  drilling  fluid is the conventional  drilling mud in
which water  is  the continuous phase and the  suspended medium  for  solids,
whether  or not  oil is  present.   An  oil-base  drilling fluid  has  diesel,
crude,  or  some  other oil  as  its  continuous  phase  with water  as  the
dispersed phase.

Drilling Fluids.   Drilling  fluids  are circulated down the  drill  pipe  and
back up the hole between the drill pipe and the walls of the hole,  usually
to a  surface pit.   Drilling fluids are used to lubricate the drill bit, to
lift cuttings,  to  seal  off  porous zones,  and to prevent blowouts.   There
are two basic  drilling  media:   muds  (liquid)  and gases.    Each  medium is
comprised of a number of general types.  The type of  drilling  fluid may be
further broken down into numerous specific formulations.

Drill Pipe.   Special pipe  designed to withstand  the torsion  and  tension
loads encountered in drilling.

Emulsion.  A substantially  permanent heterogeneous mixture  of  two  or  more
liquids  (which  are not  normally  dissolved in  each other),  but  which  are
held  in  suspension  or  dispersion,  one  in  the  other,   by  mechanical
agitation or, more  frequently,  by adding small amounts of  substances known
as emulsifiers.  Emulsion may be oil-in-water or water-in-oil.

Enhanced Oil  Recovery.   The  increased recovery from a pool  achieved  by
artificial means  or by  the application of  energy extrinsic  to  the pool.
These  artificial  means  or  applications  include   pressuring,   cycling,
pressure maintenance,  or injection  to the pool of a substance or  form of
energy, but do not include  the  injection  in a well of  a substance  or  form
of  energy  for  the sole  purpose of (1) aiding in the lifting  of  fluids in
the  well,   or   (2)  stimulating  the  reservoir  at  or  near  the  well   by
mechanical, chemical, thermal, or explosive means.

EPA.  United States Environmental Protection Agency.

Exploration  Facility.    Any fixed  or  mobile  structure addressed  by  this
document that is engaged in the drilling of  wells to determine the nature
of potential hydrocarbon reservoirs.

Field.  The area around a group of producing wells.

Flocculation.  The  combination  or aggregation of suspended solid particles
in such a way that they form small clumps or tufts resembling wool.
                                       B-4

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Flowing  Well.    A well  that  produces oil  or  gas without  any means  of
artificial lift.

Fluid Injection.  Injection of  gases  or liquids into  a  reservoir to force
oil toward and into producing wells.

Formation.  Various subsurface geological strata penetrated by well bore.

Fractionation.    A process of separating various hydrocarbons from natural
gas or oil as they are produced from the ground.

Fracturing.  Application of  excessive hydrostatic   pressure  that fractures
the well bore (causing lost circulation of drilling fluids).

Free Water Knockout.   An oil/water separation tank at atmospheric pressure.

Gas-Oil Ratio.   Number of cubic feet of gas produced with a barrel of oil.

Gathering Line.   A pipeline,  usually of small  diameter,  used in gathering
crude oil from the oil field to a point on a main pipeline.

GC.  Gas chromatography.

Geothermal Energy.  Defined  broadly,  includes all  of  the heat  within the
interior  of  the  earth.  For  the  purposes  of this  report,  it includes the
potentially  useful  part  of  this  energy  supply  that  is  represented  by
crustal  rocks,  sediments,  volcanic  deposits, water, steam, and other gases
that  are at usefully  high temperatures, are  accessible from  the  earth's
surface, and from which it may be possible to extract useful heat energy.

Gun Barrel.  An oil-water separation vessel.

Header.  A  section of  pipe into which several sources of oil, such as well
streams, are combined.

Heater-Treater.  A vessel used to break oil water emulsion with heat.

Hot Igneous  System.  A geothermal energy system created by magma chambers
near the earth's surface.

Hydrocarbon  Ion  Concentration.  A measure  of the acidity or  alkalinity of
a solution, normally expressed as pH.

Hydrostatic Head.  Pressure that exists in the well bore  due  to the weight
of the column of drilling fluid; expressed in pounds per square inch (psi).
                                       B-5

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Hydrothermal  System.   A  geothermal  energy  system  consisting  of  high
temperature water and/or  steam  which is transported near to the surface by
the convective circulation through faults and fractures.

Hyperthermal  Fields.   (1) Wet  Fields  - producing pressurized  water  at
temperatures  exceeding 100癈,  so that  when  the fluid  is  brought  to  the
surface and its pressure  is reduced,  a fraction  is  flashed into  steam
while  the  majority of  it  remains  as  boiling  water.   (2)  Dry Fields  -
producing dry saturated,  or slightly superheated, steam  at  pressures above
atmospheric.

Inhibitor.   An additive  that prevents  or  retards  undesirable changes  in
the  product.   Particularly,   oxidation and  corrosion,  and  sometimes
paraffin formation.

Injection.   Introduction  of  drilling fluids  or produced  fluids  into  an
underground geologic formation,  usually for  disposal purposes.

Invert Oil  Emulsion Drilling Fluid.  A  water-in-oil emulsion  where  fresh
or salt water is  the dispersed phase and diesel, crude, or some other oil
is the  continuous  phase.  Water  increases  the  viscosity and  oil  reduces
the viscosity.

Killing a  Well.   Bringing a  well under control that is blowing out.  Also,
the procedure of  circulating water and drilling fluids into  a  completed
well before starting well servicing operations.

Location (Drill Site).  Place at which a well is to  be or has been drilled.

Low Grade  Aquifers.  Capable of  producing  useful  hot water  of  low grade
(ranging up to 70癈) because of a temperature gradient.

Marginal Well.  An  oil or gas well  that produces  such  a small  volume  of
hydrocarbons  that the  gross  income therefrom provides only a small margin
of profit  or, in  many cases, does  not  even cover the cost of production.
("Marginal  well"  should be distinguished from the definition for "stripper
well" in 44 FR 22073.)

Mud Pit.  A steel or earthen tank that is part of the  surface drilling mud
system.

Mud  Pump.    A  reciprocating,  high  pressure  pump used for  circulating
drilling mud.

Multiple  Completion.   A  well  completion  that  provides for  simultaneous
production  from separate zones.
                                       B-6

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NPDES  Permit.   A National  Pollutant Discharge  Elimination System  permit
issued under Section 402 of the Clean Water Act.

96-hr  LC-50.   The concentration  of a  test  material that  is  lethal  to 50
percent  of  the test  organisms in  a bioassay after  96  hours of  constant
exposure.

Onsite Air  Drilling  Pit.   An excavated or above  grade  earthen impoundment
on a well  site that holds fluids  produced  by or  associated with the  air
drilling process.   These fluids  include  but are not limited  to:   connate
water, fresh water  (for dust suppression),  stimulation  fluids,  completion
fluids, and drilling additives.

Onsite Drilling  Mud  (Reserve)  Pit.   An excavated  or above grade  earthen
impoundment  on  a well  site  that  holds  drilling  mud,  connate  water,
stimulation  fluids,   completion  fluids,  or  other  waste  produced  by  or
associated with drilling.

Onsite Pit  Treatment.   Treatment  of  pit  contents  in  situ,  or  on  the
drilling site  by  the operator.  Neutralization, aeration, and settling (or
some combination  thereof)  are  routine  onsite pit  treatment  technologies.
Reverse osmosis is a rare but available onsite pH treatment.

Priority Pollutants.  The  65 pollutants and classes of  pollutants declared
toxic under Section  307(a)  of the Act.  Appendix C contains  a listing  of
specific elements and compounds.

Production  Facility.   Any  platform or fixed  structure  addressed by  this
document that  is  used for active  recovery  of hydrocarbons from  producing
formations.

Produced Fluids.   All  of the  liquid  and gaseous  materials  yielded by  a
well,  excluding  fluids  introduced  into  the  well for  enhancement   of
productivity.    In this  document,  the term  "produced fluids" is  normally
construed as the non-product portion of the  fluids yielded by a  well.   In
this context,  produced fluids are principally brines.

Produced Water.  The  water  (brine) brought  up from the  hydrocarbon-bearing
strata during  the extraction  of  oil and gas.   It  can  include  formation
water, injection  water,  and  any  chemicals  added  downhole or during  the
oil/water separation process.

Produced Sand.   Slurried particles used in  hydraulic fracturing, and  the
accumulated  formation   sands   and  scale   particles   generated   during
production.
                                      B-7

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Publicly Owned  Treatment Works  (POTWs).   A treatment  facility  as defined
by Section  212  of  the  Clean Water  Act,  which  is  owned by  a  State  or
municipality.   An  "approved  POTW  treatment  program"  or  "Program"  or
"Pretreatment Program" means  a  program administered  by a POTW  that  meets
the requirements established  in 40 CFR 403, and which has been approved by
a Regional Administrator or State Director in accordance with 40 CFR 403.

RCRA.   The Resource Conservation and Recovery Act of 1976, as amended.

Semithermal Fields.  Capable  of producing hot water  at temperatures  up to
approximately 100癈 from depth of 1 to 2 km.

Separation.   A process  whereby  liquid  hydrocarbons  are separated from
gas.  The term  is  sometimes used to  describe  a relatively  simple process
distinguished from fractionation.

Stimulation.  Any  action taken by well operator to  increase  the inherent
productivity  of an oil or  gas  well  including,   but  not  limited  to,
fracturing,  shooting,  or acidizing,  but  excluding cleaning  out, bailing,
or workover operations.

Stripper Wells.   Wells  in  a  field producing  an average  of  less than  10
barrels  of  oil per calendar  day  per well.  Water  injection wells and gas
wells are  excluded from the  calculation  of  average  daily  oil  production
for a field.

Supernatant.  A liquid or fluid forming a layer above settled solids.

Tank Bottom  Sludge.   Sediment,  oil, water, and other substances that tend
to concentrate in the bottom of production  field vessels,  especially  stock
tanks, are  called  field tank bottom  sludges.  This layer of sludge may be
periodically removed to prevent oil contamination.

Treatment Works.  Any  devices and systems used in  the  storage,  treatment,
recycling,  and  reclamation of  municipal  sewage or industrial wastes of a
liquid nature to implement Section 201 of the Act,  or necessary  to recycle
or  reuse water at  the most  economical  cost of the  estimated  life of the
works,  including  intercepting  sewers,  outfall  sewers,  sewage  collection
systems,  pumping,  power,  and  other  equipment  and  their  appurtenances
thereof; extensions,  improvements,  remodeling, additions, and  alterations
thereof;  elements  essential  to providing a reliable recycled  supply such
as  standby  treatment  units  and  clear  well  facilities;  and  any  works,
including  site  acquisition of  the land  that  will  be  an  integral part of
the  treatment process   (including  land  use  for the  storage  of  treated
wastewater  in land treatment  facilities  prior to  land application)  or is
used  for ultimate  disposal  of  residues   resulting  from  such  treatment.
                                       B-8

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"Treatment  works"  means  any  other  method  or  system  for  preventing,
abating,   reducing,   storing,  treating,   separating,   or   disposing   of
municipal  waste,  including waste  combined with storm  water and  sanitary
sewer systems.

Well Completion.   In  a  potentially productive formation, the completion of
a  well  in a  manner  to permit  production of  oil;  the  walls  of the  hole
above the  producing  layer  (and within it if  necessary) must  be supported
against  collapse  and the  entry into  the  well of  fluids  from  formations
other than the producing  layer must  be prevented.   A  string of casing is
always  run and cemented at least to  the  top  of  the producing  layer,  for
this  purpose.   Some  geological  formations  require  the use  of  additional
techniques to "complete" a well such as casing the  producing formation  and
using  a   "gun  perforator"  to  make  entry  holes,  using  slotted  pipes,
consolidating   sand   layers   with  ;  chemical   treatment,    and    using
surface-actuated underwater robots for offshore wells.

Workover.  To  clean  out or otherwise  work on a well in order  to increase
or restore production.  A typical workover is cleaning out a well that  has
sanded up.  Tubing is  pulled, the casing and bottom of the hole washed out
with mud,  and  (in some  cases) explosives  set  off  in the hole  to  dislodge
the silt and sand.

Workover Fluids.   Any type of  fluid  used in the workover  operation of a
well.
                                      B-9

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