United Stjafes '  ; ' t
             Environmental Prgtecfen
             .Agency      \ '•-'}
       ' EnforcetnenOrici  '* - ,• "
       Complianee Assuraince.
       (2223A) ,11"   ' • " .
October2000
              Profile Of The
              Oil And Gas Extraction
              Industry
SECTOR
 ,
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                 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
                               WASHINGTON, D.C. 20460
     ,0*
                                     NOV f 8 /997
                                                                         THE ADMINISTRATOR

Message from the Administrator

Since EPA's founding over 25 years ago, our nation has made tremendous progress in protecting
public health and our environment while promoting economic prosperity. Businesses as large as
iron and steel plants and those as small as the dry cleaner on the corner have worked with EPA to
find ways to operate cleaner, cheaper and smarter.  As a result, we no longer have rivers catching
fire. Our skies are clearer.  American environmental technology and expertise are in demand
around the world.

The Clinton Administration recognizes that to continue this progress, we must move beyond the
pollutant-by-pollutant approaches of the past to comprehensive, facility-wide approaches for the
future.  Industry by industry and community by community, we must build a new generation of
environmental protection.

The Environmental Protection Agency has undertaken its Sector Notebook Project to compile,
for major industries, information about environmental problems and solutions, case studies and
tips about complying with regulations. We called on industry leaders, state regulators, and EPA
staff with many years of experience in these industries and with their unique environmental issues.
Together with an extensive series covering other industries, the notebook you hold in your hand is
the result.

These notebooks will help business managers to understand better their regulatory requirements,
and learn more about how others in their industry have achieved regulatory compliance and the
innovative methods some have found to prevent pollution in the first instance. These notebooks
will give useful information to state regulatory agencies moving toward industry-based programs.
Across EPA we will use this manual to better integrate our programs and improve our compliance
assistance efforts.

I encourage you to use this notebook to evaluate and improve the way that we together achieve
our important environmental protection goals. I am confident that these notebooks will help us to
move forward in ensuring that — in industry after industry, community after community —
environmental protection and economic prosperity go hajs4 in hand.
            Rocyckd/Recyclable -Printed with Vegetable Oil Based Inks on 100% Recycled Paper (40% Postconsumer)

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Oil and Gas Extraction
Sector Notebook Project
                                                            EPA/310-R-99-006
             EPA Office of Compliance Sector Notebook Project

            Profile of the Oil and Gas Extraction Industry
                                October 2000
                             Office of Compliance
                  Office of Enforcement and Compliance Assurance
                      U.S. Environmental Protection Agency
                               401 M St., SW
                            Washington, DC 20460

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 Oil and Gas Extraction
Sector Notebook Project
 This report is one in a series of volumes published by the U.S. Environmental Protection Agency
 (EPA) to provide information of general interest regarding environmental issues associated with
 specific industrial sectors.  The documents were developed under contract by Abt Associates
 (Cambridge, MA), Science Applications International Corporation (McLean, VA), and Booz-Allen
 & Hamilton, Inc. (McLean, VA).  A listing of available Sector Notebooks is included on the
 following page.

 Obtaining copies:

 Electronic versions of all sector notebooks are available via Internet on the Enviro$en$e World
 Wide Web at www. epa. gov/oeca/sector.  Enviro$en$e is a free, public, environmental exchange
 system operated by EPA's Office of Enforcement and Compliance Assurance and Office of Research
 and Development. The Network allows regulators, the regulated community, technical experts, and
 the general public to share information regarding: pollution prevention and innovative technologies;
 environmental enforcement and  compliance assistance;  laws, executive orders, regulations, and
 policies; points of contact for services and equipment;  and other related topics.  The Network
 welcomes receipt of environmental messages, information, and data from any public or private
 person or organization. Direct technical questions to the "Feedback" button on the bottom of the
 web page.

 Purchase printed bound copies from the Government Printing Office (GPO) by consulting the
 order form at the back of this document or order via the Internet by visiting the on-line GPO Sales
 Product Catalog at https.://orders.access.gpo.gov/su_docs/sale/prf/prf.html. Search using the exact
 title of the document "Profile of the XXXX Industry" or simply "Sector Notebook." When ordering,
 use the GPO document number found on the order form at the back of this document.

 Complimentary volumes are available to  certain groups or subscribers, including public and
 academic libraries; federal, state, tribal, and local governments; and the media from EPA's National
 Service Center for Environmental Publications at (800) 490-9198.  When ordering, use the EPA
publication number found on the following page.

The Sector Notebooks were developed by the EPA's Office of Compliance. Direct general questions
about the Sector Notebook Project to:

       Seth Heminway, Coordinator, Sector Notebook Project
       US EPA Office of Compliance
       401 M St., SW (2223-A)
       Washington, DC  20460
       (202) 564-7017

For further information, and for answers to questions pertaining to these documents, please refer to
the contact names listed on the following page.
Sector Notebook Project
          October 2000

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Oil and Gas Extraction
                                                  Sector Notebook Project
                        SECTOR NOTEBOOK CONTACTS

Questions and comments regarding the individual documents should be directed to the specialists listed
below. See the Notebook web page at: www.epa.gov/oeca/sector for the most recent titles and staff
contacts.
EPA Publication
    Number
EPA/310-R-95-001.
EPA/310-R-95-002.
EPA/310-R-95-003.
EPA/310-R-95-004.
EPA/310-R-95-005.
EPA/310-R-95-006.
EPA/310-R-95-007.
EPA/310-R-95-008.
EPA/310-R-95-009.
EPA/310-R-95-010.
EPA/310-R-95-011.
EPA/310-R-95-012.
EPA/310-R-95-013.
EPA/310-R-95-014.
EPA/310-R-95-015.
EPA/310-R-95-016.
EPA/310-R-95-017.
EPA/310-R-95-018.
EPA/310-R-97-001.
EPA/310-R-97-002.
EPA/310-R-97-003.
EPA/310-R-97-004.
EPA/310-R-97-005.
EPA/310-R-97-006.
EPA/310-R-97-007.

EPA/310-R-97-008.
EPA/310-R-97-009.
EPA/310-R-98-001.
EPA/310-R-97-010.
EPA/310-R-99-003.

EPA/310-R-99-004.
EPA/310-R-99-005.

EPA/310-R-00-004.
EPA/310-R-99-001.
               Industry
Profile of the Dry Cleaning Industry
Profile of the Electronics and Computer Industry*
Profile of the Wood Furniture and Fixtures Industry
Profile of the Inorganic Chemical Industry*
Profile of the Iron and Steel Industry
Profile of the Lumber and Wood Products Industry
Profile of the Fabricated Metal Products Industry*
Profile of the Metal Mining Industry
Profile of the Motor Vehicle Assembly Industry
Profile of the Nonferrous Metals Industry
Profile of the Non-Fuel, Non-Metal Mining Industry
Profile of the Organic Chemical Industry *
Profile of the Petroleum Refining Industry
Profile of the Printing Industry
Profile of the Pulp and Paper Industry
Profile of the Rubber and Plastic Industry
Profile of the Stone, Clay, Glass, and Concrete Ind.
Profile of the Transportation Equipment Cleaning Ind.
Profile of the Air Transportation Industry
Profile of the Ground Transportation Industry
Profile of the Water Transportation Industry
Profile of the Metal Casting Industry
Profile of the Pharmaceuticals Industry
Profile of the Plastic Resin and  Man-made Fiber Ind.
Profile of the Fossil Fuel Electric Power Generation
   Industry
Profile of the Shipbuilding and  Repair Industry
Profile of the Textile Industry
Profile of the Aerospace Industry
Sector Notebook Data Refresh-1997 **
Profile of the Agricultural Chemical, Pesticide and
   Fertilizer Industry
Profile of the Agricultural Crop Production Industry
Profile of the Agricultural Livestock Production
   Industry
Profile of the Oil and Gas Extraction Industry

               Government Series
Profile of Local Government Operations
Contact Phone (202)
Joyce Chandler
Steve Hoover
Bob Marshall
Walter DeRieux
Maria Malave
Seth Heminway
Scott Throwe
Maria Malave
Anthony Raia
Debbie Thomas
Rob Lischinsky
Walter DeRieux
Tom Ripp
Ginger Gotliffe
Seth Heminway

Scott Throwe
Virginia Lathrop
Virginia Lathrop
Virginia Lathrop
Virginia Lathrop
Steve Hoover
Emily Chow
Sally Sasnett
Rafael Sanchez
Anthony Raia

Anthony Raia
Seth Heminway
Michelle Yaras
564-7073
564-7007
564-7021
564-7067
564-7027
564-7017
564-7013
564-5027
564-6045
564-5041
564-2628
564-7067
564-7003
564-7072
564-7017
564-2310
564-7013
564-7057
564-7057
564-7057
564-7057
564-7007
564-7071
564-7074
564-7028
564-6045
564-2310
564-6045
564-7017
564-4153
Ginah Mortensen    913-551 -5211
Ginah Mortensen    913-551-5211
Dan Chadwick
564-7054
                  564-2310
 *   Spanish translations available.
 **  This document revises compliance, enforcement, and toxic release inventory data for all profiles published in
    1995.
 Sector Notebook Project
                            11
                                                               October 2000

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Oil and Gas Extraction
Sector Notebook Project
                       Oil and Gas Extraction Industry
                                   (SIC 13)
                           TABLE OF CONTENTS
LIST OF FIGURES	v

LIST OF TABLES	v

LIST OF ACRONYMS	vi

I. INTRODUCTION TO THE SECTOR NOTEBOOK PROJECT	1
      A. Summary of the Sector Notebook Project	1
      B. Additional Information	2

II. INTRODUCTION TO THE OIL AND GAS EXTRACTION INDUSTRY	3
      A. Introduction, Background, and Scope of the Notebook	3
      B. Characterization of the Oil and Gas Extraction Industry	4
            1.  Product Characterization	4
            2.  Industry Size and Distribution 	6
            3.  Economic Trends 	10

III.  INDUSTRIAL PROCESS DESCRIPTION	15
      A. Industrial Processes in the Oil and Gas Extraction Industry	15
            1.  Exploration	16
            2.  Well Development  	17
            3.  Petroleum Production	28
            4.  Maintenance  	32
            5.  Well Shut-in/Well Abandonment	33
            6.  Spill and Blowout Mitigation	34
      B. Raw Material Inputs and Pollution Outputs	37
      C. Management of Wastestreams	45

IV.  WASTE RELEASE PROFILE	52
      A. Available Data on Produced Water	52
      B. Available Data on Drilling Waste for the Oil and Gas Extraction Industry	56
      C. Available Data on Miscellaneous and Minor Wastes (Associated Wastes)	59
            1.  Workover, Treatment, and Completion Fluids	59
            2.  Minor Wastes  		61
      D. Other Data Sources  	63

V. POLLUTION PREVENTION OPPORTUNITIES	65
      A. Exploration	67
      B. Well Development	69
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Oil and Gas Extraction
                    Sector Notebook Project
      C. Petroleum Production	,	74
      D. Maintenance	77

VI. SUMMARY OF FEDERAL STATUTES AND REGULATIONS 	81
      A. General Description of Major Statutes	81
      B. Industry Specific Requirements	99
             1. Onshore Requirements	99
             2. Offshore Requirements	108
             3. Stripper Well Requirements	Ill
             4. State Statutes	Ill
      C. Pending and Proposed Regulatory Requirements  	113

VII. COMPLIANCE AND ENFORCEMENT HISTORY	115
      A. Oil and Gas Extraction Industry Compliance History	119
      B. Comparison of Enforcement Activity Between Selected Industries  	121
      C. Review of Major Legal Actions	126
             1. Review of Major Cases	126
             2. Supplementary Environmental Projects (SEPs)	 127

VIII. COMPLIANCE ASSURANCE ACTIVITIES AND INITIATIVES	129
      A. Sector-related Environmental Programs and Activities	129
             1. Federal Activities  	129
             2. State Activities 	132
      B. EPA Voluntary Programs	134
      C. Trade Association/Industry Sponsored Activity	140
             1. Industry Research Programs	140
             2. Trade Associations  	142

IX. CONTACTS/ACKNOWLEDGMENTS/RESOURCE MATERIALS  	147
Sector Notebook Project
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Oil and Gas Extraction
Sector Notebook Project
                                LIST OF FIGURES

Figure 1: Employment and Value of Shipments and Receipts in the Oil and Gas Industry	7
Figure 2: 1996 U.S. Crude Oil Production (Million Barrels per Year)	8
Figure 3: 1996 U.S. Natural Gas Production (Billion Cubic Feet per Year)	9
Figure 4: U.S. Oil Consumption and Percent Produced Domestically 	10
Figure 5: U.S. Natural Gas Consumption and Percent Produced Domestically  	11
Figure 6: Number of Exploratory Wells Drilled and Percent That Enter Production	12
Figure 7: Domestic Crude Oil and Natural Gas Production  	13
Figure 8: Wellhead Crude Oil and Natural Gas Prices, Fixed 1998 Dollars	14
Figure 9: Common Oil and Gas Structural Traps  	17
Figure 10: Cross Section of a Cased Well	22
Figure 11: Typical Rotary Drilling Rig	24
Figure 12: Secondary Recovery Using Pumps and Water Injection	29



                                LIST OF TABLES

Table 1: Types of Associated Waste	42
Table 2: Potential Material Outputs from Selected Oil and Gas Extraction Processes	45
Table 3: Summary of 1995 Disposal Practices for Onshore Produced Water	48
Table 4: Management of Associated Wastes in 1995  	51
Table 5: Produced Water Effluent Concentrations - Gulf of Mexico	53
Table 6: Oil Well Brine (Produced Water) from Primary Recovery Operations — Venango
       County, Pennsylvania	54
Table 7: Gas Well Brine (Produced Water) Characteristics - Devonian Formation of
       Pennsylvania  	55
Table 8: Cook Inlet Drilling Waste Characteristics	57
Table 9: Drilling Fluids Characteristics — Devonian Gas Wells 	58
Table 10: Typical Volumes from Well Treatment, Workover, and Completion Operations  ... 59
Table 11: Pollutant Concentrations in  Treatment, Workover, and Completion Fluids	60
Table 12: Pollutant Concentrations in  Produced Water Pit Sediments in Pennsylvania	62
Table 13: Air Pollutant Releases by Industry Sector (tons/year)	63
Table 14: Five-Year Enforcement and Compliance Summary for the Oil and Gas Industry  . . 120
Table 15: Five-Year Enforcement and Compliance Summary for Selected Industries	122
Table 16: One-Year Enforcement and  Compliance Summary for Selected Industries	123
Table 17: Five-Year Inspection and Enforcement Summary by Statute for Selected Industries 124
Table 18: One-Year Inspection and Enforcement Summary by Statute for Selected Industries 125
Table 19: Oil and Gas Industry Participation in the 33/50 Program	137
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Oil and Gas Extraction
                   Sector Notebook Project
                             LIST OF ACRONYMS

ACS -        Automatic Casing Swab
AFS -        AIRS Facility Subsystem (CAA database)
AIRS -       Aerometric Information Retrieval System (CAA database)
AOR -        Area of Review (SD WA)
AOSC -      Association of Oilwell Servicing Contractors
API -        American Petroleum Institute
API ES -     American Petroleum Institute Environmental Statement
BAT -        Best Available Technology Economically Achievable
bbl -         Barrel (42 US gallons)
Bcf -        Billion Cubic Feet
BCT -        Best Conventional Pollutant Control Technology
bpd -        Barrels per Day
BIA -        Bureau of Indian Affairs (Department of the Interior)
BIFs -        Boilers and Industrial Furnaces (RCRA)
BLM -       Bureau of Land Management (Department of the Interior)
BMP -        Best Management Practice
BOD -        Biochemical Oxygen Demand
BOP -        Blowout Preventer
BPT -        Best Practicable Technology Currently Available
BS&W -     Basic Sediment and Water
BTEX -      Benzene, Toluene, Ethylbenzene and Xylene
CAA -        Clean Air Act
CAAA -     Clean Air Act Amendments of 1990
CERCLA -   Comprehensive Environmental Response, Compensation and Liability Act
CERCLIS -   CERCLA Information System
CFCs -       Chlorofluorocarbons
CFR-        Code of Federal Regulations
CGP -        Construction General Permit (CWA)
CO -        Carbon Monoxide
CO2 -        Carbon Dioxide
COE -        Army Corps of Engineers (Department of Defense)
CZMA -     Coastal Zone Management Act
CWA -       Clean Water Act
DOC -       United States Department of Commerce
DOE -        United States Department of Energy
DOI -        United States Department of the Interior
E&P -        Exploration and Production
EIA -        Energy Information Administration (Department of Energy)
EIS -        Environmental Impact Statement
EOR -        Enhanced Oil Recovery
EPA -        United States Environmental Protection Agency
EPCRA -    Emergency Planning and Community Right-to-Know Act
ESA -        Endangered Species Act
 Sector Notebook Project
VI
                              October 2000

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 Oil and Gas Extraction
                     Sector Notebook Project
EST -        Eastern Standard Time
FIFRA -     Federal Insecticide, Fungicide, and Rodenticide Act
FINDS -     Facility Indexing System
FLPMA-     Federal Land Policy and Management Act
FPSO-       Floating Production, Storage, and Offloading system
FR -         Federal Register
FRP -        Facility Response Plan
H2S -        Hydrogen Sulfide
HAPs -       Hazardous Air Pollutants (CAA)
HSWA -     Hazardous and Solid Waste Amendments
IDEA -       Integrated Data for Enforcement Analysis
IOGCC -     Interstate Oil and Gas Compact Commission
IPAA -       Independent Petroleum Association of America
LDR -       Land Disposal Restrictions (RCRA)
LEPCs -     Local Emergency Planning Committees
MACT -     Maximum Achievable Control Technology (CAA)
Mcf-        Thousand Cubic Feet
MCLs -      Maximum Contaminant Levels
MCLGs -     Maximum Contaminant Level Goals
MFC -       Magnetic Fluid Conditioner
MIT -        Mechanical Integrity Test
MMPA -     Marine Mammal Protection Act
MMS -       Minerals Management Service (Department of the Interior)
MMTCE -    Million Metric Tons of Carbon Equivalent
MPRSA-     Marine Protection, Research, and Sanctuaries Act
MSDSs -     Material Safety Data Sheets
MSGP -      Multi-Sector General Permit (CWA)
NAAQS -     National Ambient Air Quality Standards (CAA)
NAICS -     North American Industrial Classification System
NCDB -      National Compliance Database (for TSCA, FIFRA, EPCRA)
NCP -        National Oil and Hazardous Substances Pollution Contingency Plan
NEC -        Not Elsewhere Classified
NEPA -      National Environmental Policy Act
NESHAP -    National Emission Standards for Hazardous  Air Pollutants
NICE3 -      National Industrial Competitiveness Through Energy, Environment and Economics
NO2 -        Nitrogen Dioxide
NOI-        Notice of Intent
NORM -     Naturally Occurring Radioactive Material
NOT-        Notice of Termination
NPDES -     National Pollution Discharge Elimination System (CWA)
NPL -        National Priorities List
NRC -        National Response Center
NSPS -       New Source Performance Standards (CAA)
OAQPS -     Office of Air Quality Planning and Standards
OCS -        Outer Continental Shelf
OCSLA -     Outer Continental Shelf Lands Act
Sector Notebook Project
vn
October 2000

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Oil and Gas Extraction
                    Sector Notebook Project
OECA -      Office of Enforcement and Compliance Assurance
OMB -       Office of Management and Budget
OOC -       Offshore Operators Committee
OPPTS -     Office of Prevention, Pesticides, and Toxic Substances
OSHA -      Occupational Safety and Health Administration
OS W -       Office of Solid Waste
OSWER -    Office of Solid Waste and Emergency Response
OW-        Office of Water
PAH -        Polyaromatic Hydrocarbon
PCB -        Polychlorinated Byphenyls
PCS -        Permit Compliance System (CWA Database)
PDC -        Polycrystalline Diamond Compact Drill Bit
PM10 -       Particulate Matter of 10 microns or less
PMN -       Premanufacture Notice
POP -        Problem Oil Pit
POTW -     Publicly Owned Treatments Works
PSD -        Prevention of Significant Deterioration (CAA)
PT -         Total Participates
PTTC -       Petroleum Technology Transfer Council
RCRA -      Resource Conservation and Recovery Act
RCRIS -     RCRA Information System
RQ -        Reportable Quantity (CERCLA)
SARA -      Superfund Amendments and Reauthorization Act
SBF -        Synthetic-Based Drilling Fluid
SDWA -     Safe Drinking Water Act
SEPs -       Supplementary Environmental Projects
SERCs -     State Emergency Response Commissions
SIC -        Standard Industrial Classification
SIP -        State Implementation Plan
SO2 -        Sulfur Dioxide
SPCC -       Spill Prevention Control and Countermeasure
STEP -       Strategies for Today's Environmental Partnership
SWPPP -     Storm Water Pollution Prevention Plan (CWA)
TRI -        Toxic Release Inventory
TRIS -       Toxic Release Inventory  System
TSCA -      Toxic Substances Control Act
TSD -        Treatment Storage and Disposal
TSP -        Total Suspended Particulates
TSS -        Total Suspended Solids
UIC -        Underground Injection Control (SDWA)
USDW -     Underground Sources of Drinking Water (SDWA)
USFS -       United States Forest Service (Department of Agriculture)
USFWS -    United States Fish and Wildlife Service (Department of the Interior)
UST -       Underground Storage Tanks (RCRA)
VOCs -      Volatile Organic Compounds
WSPA -     Western States Petroleum Association
 Sector Notebook Project
vni
                               October 2000

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Oil and Gas Extraction
                     Sector Notebook Project
I. INTRODUCTION TO THE SECTOR NOTEBOOK PROJECT

I. A. Summary of the Sector Notebook Project

                     Environmental policies based upon comprehensive analysis of air, water and
                     land pollution (such as economic sector, and community-based approaches)
                     are becoming an important supplement to traditional single-media approaches
                     to environmental protection.  Environmental regulatory  agencies are
                     beginning  to  embrace comprehensive, multi-statute solutions to facility
                     permitting,  compliance  assurance,  education/outreach, research,  and
                     regulatory development issues. The central concepts driving the new policy
                     direction are that pollutant releases to each environmental medium (air, water
                     and  land) affect each other, and that environmental strategies must actively
                     identify and address these interrelationships by designing policies for the
                     "whole" facility.  One  way to achieve a whole facility focus is to design
                     environmental policies for  similar industrial facilities.  By doing so,
                     environmental concerns that are common to the manufacturing of similar
                     products can be addressed in a comprehensive manner.  Recognition of the
                     need to develop the industrial "sector-based" approach within the EPA Office
                     of Compliance led to the creation of this document.

                     The  Sector Notebook Project was initiated by the Office of Compliance
                     within the Office of Enforcement  and Compliance Assurance (OECA) to
                     provide its staff  and managers with summary information  for eighteen
                     specific industrial sectors.   As other EPA offices,  states, the regulated
                     community, environmental groups, and the public became interested in this
                     project, the scope of the original project was expanded. The ability to design
                     comprehensive, common sense environmental protection measures for
                     specific industries is dependent on knowledge of several interrelated topics.
                     For the purposes of this project, the key elements chosen for inclusion are:
                     general industry information (economic and geographic); a description of
                     industrial processes; pollution outputs; pollution prevention opportunities;
                     federal statutory  and regulatory framework;  compliance history; and a
                     description of partnerships that have  been  formed between  regulatory
                     agencies, the regulated community and the public.

                     For any given industry,  each topic listed above could alone be the subject of
                     a lengthy volume.  However, in order to produce a manageable document,
                     this project focuses on providing summary information for each topic.  This
                     format provides the reader with a synopsis of each issue, and references
                     where more in-depth information is available.  Text within each profile was
                     researched from a variety of sources, and was usually condensed from more
                     detailed sources pertaining to specific topics.  This approach allows for a
                     wide coverage of activities that can be further explored based upon the
Sector Notebook Project
1
October 2000

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Oil and Gas Extraction
Sector Notebook Project
                    references listed at the end of this profile.  As a check on the information
                    included, each notebook went through an external document review process.
                    The Office of Compliance appreciates the efforts of all those that participated
                    in this process and enabled us to develop more complete, accurate and up-to-
                    date summaries. Many of those who reviewed this notebook are listed as
                    contacts in Section IX and may be sources of additional information.  The
                    individuals and groups  on this  list do not necessarily  concur with all
                    statements within this notebook.

I.B.  Additional Information

       Providing Comments

                    OECA's Office of Compliance plans to periodically review and update the
                    notebooks and will make  these updates available both in hard copy and
                    electronically. If you have any comments on the existing notebook, or if you
                    would like to provide additional information, please send a hard copy and
                    computer disk to the EPA  Office of Compliance, Sector Notebook Project
                    (2223-A), 401 M St., SW, Washington, DC 20460. Comments can also be
                    sent via the web page.

       Adapting Notebooks to Particular Needs

                    The scope of the industry sector described in this notebook approximates the
                    national occurrence of facility types within the sector.  In many instances,
                    industries within specific  geographic  regions or  states may have unique
                    characteristics that are not fully captured in these profiles.  The Office of
                    Compliance encourages state and local environmental agencies and other
                    groups to supplement or re-package the information included in this notebook
                    to include more specific industrial and regulatory information that may be
                    available.  Additionally,  interested states may want to supplement the
                    " Summary of Applicable Federal Statutes and Regulations" section with state
                    and local requirements.  Compliance or technical assistance providers may
                    also want to develop the  "Pollution Prevention"  section in more detail.
                    Please contact the appropriate specialist listed on the opening page of this
                    notebook if your office is interested in assisting us in the further development
                    of the information or policies addressed within this volume.  If you are
                    interested in assisting in the development of new notebooks, please contact
                    the Office of Compliance at (202) 564-2310.
Sector Notebook Project
            October 2000

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 Oil and Gas Extraction
Introduction, Background, and Scope
 II. INTRODUCTION TO THE OIL AND GAS EXTRACTION INDUSTRY

                     This section provides background  information on the  size, geographic
                     distribution, employment, production, sales, and economic condition of the
                     oil and gas extraction industry. Facilities described within the document are
                     described in terms of their Standard Industrial Classification (SIC) codes.

 II.A. Introduction, Background, and Scope of the Notebook

                     This industry sector profile provides an overview of the oil and gas industry
                     as listed under SIC code 13.  The SIC code 13 encompasses the oil and gas
                     extraction process from the exploration for petroleum deposits up until the
                     transportation of the product from the production site. There are five major
                     groups within SIC code 13:

                     SIC 1311. Crude petroleum and natural gas. Establishments in this industry
                     are  primarily involved in the operation of oil and gas  field properties.
                     Establishments under this category might also perform exploration for crude
                     oil and natural gas, drill and complete wells, and separate the crude oil and
                     natural gas components from the natural gas liquids and produced fluids.

                     SIC 1321. Natural gas liquids. This industry is comprised of establishments
                     that separate natural gas liquids from crude oil and natural gas at the site of
                     production. Examples of these gases are propane and butane. Natural gas
                     liquids producers that remove additional material at petroleum refineries are
                     classified under SIC code 29, and establishments that recover other salable
                     contaminants such as helium are classified under SIC code 28.

                     SIC 1381. Drilling oil and gas wells.  This industry is  made up of
                     establishments that drill wells on a contract or fee basis.

                     SIC 1382. Oil and gas field exploration services. Establishments in this
                     industry perform geological, geophysical and other exploration services for
                     oil and gas on a contract or fee basis.

                     SIC 1389. Oil and gas field services,  not elsewhere classified  (NEC).
                     Establishments in this industry perform services on a contract or fee basis that
                     are not elsewhere classified. These include the preparation of drilling sites
                     by building foundations and excavating pits, the completion of wells and
                     preparation for production, and the performing of maintenance.

                     While this notebook covers all of the SIC codes listed above, the diverse
                     nature of the industries will not allow a detailed description of each. Since
                     the service industries  (SIC codes 1381, 1382, and 1389) and natural gas
                     liquids industry (SIC code 1321) are tied to the economic, geographic, and
Sector Notebook Project
                       October 2000

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Oil and Gas Extraction
Introduction, Background, and Scope
                    production trends of SIC code 1311, most attention is focused on the crude
                    petroleum and natural gas industry. Although certain products under these
                    SIC codes may not be specifically mentioned, the sector-wide economic,
                    pollutant output, and enforcement and compliance  data in this notebook
                    covers all establishments involved with oil and gas extraction.

                    SIC codes were established by the Office of Management and Budget (OMB)
                    to track the flow of goods and services within the economy.  OMB is in the
                    process of changing the SIC code system to a system based on similar
                    production processes called the North American Industrial Classification
                    System (NAICS). In the NAICS, the SIC codes for the oil and gas extraction
                    industry correspond to the following NAICS codes:
1987
SIC
1311
1321
1381
1382
1389
U.S. SIC Description
Crude Petroleum and
Natural Gas
Natural Gas Liquids
Drilling Oil and Gas
Wells
Oil and Gas Field
Exploration Services
Oil and Gas Field
Services, NEC
1997
NAICS
211111
211112
213111
54136
213112
213112
NAICS Description
Crude Petroleum and
Natural Gas Extraction
Natural Gas Liquid
Extraction
Drilling Oil and Gas
Wells
Geophysical Surveying
and Mapping Services
Support Activities for Oil
and Gas Operations
Support Activities for Oil
and Gas Operations
H.B. Characterization of the Oil and Gas Extraction Industry

       II.B.l. Product Characterization
                     The primary products of the industry are crude oil, natural gas liquids, and
                     natural gas. Crude oil is a mixture of many different hydrocarbon compounds
                     that must be processed to produce a wide range of products. U.S. refinery
                     processing of crude oil yields, on average, motor gasoline (approximately 40
                     percent), diesel fuel and home heating oil (20 percent), jet fuels (10 percent),
                     waxes, asphalts and  other nonfuel products (5 percent), feedstocks for the
                     petrochemical  industry (3 percent), and other  lesser components [U.S.
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                     Department of Energy, Energy Information Administration (EIA), 1999].
                     Volumes of oil and refined products typically are reported in barrels (bbl),
                     which are equal to 42 gallons.

                     When crude oil is first brought to the surface, it may contain a mixture of
                     natural gas and produced fluids such as salt water and both dissolved and
                     suspended solids.  On land (and at many offshore operations) Natural gas is
                     separated at the well site and is processed for sale if natural gas pipelines (or
                     other transportation vehicles) are nearby, or is flared as a waste (at onshore
                     operations only).   Water (which can  be more than 90 percent of the fluid
                     extracted in older wells) is separated out, as are solids. Only about one-third
                     of the production platforms offshore in the Gulf of Mexico separate water.
                     The other offshore Gulf platforms transport full well stream, sometimes great
                     distances, to central processing facilities. The crude oil is at least 98 percent
                     free of solids after it passes through this onsite treatment and is prepared for
                     shipment to storage facilities and ultimately refineries (Sittig, 1978).

                     Natural gas can be produced from oil wells (called associated gas), or wells
                     can be drilled with natural gas as the primary obj ecti ve (called non-associated
                     gas).  Methane is the predominant component of natural gas (approximately
                     85 percent), but ethane (10 percent), propane, and butane are also significant
                     components. The heavier components, including propane and butane, exist
                     as liquids when cooled and compressed; these are  often separated and
                     processed as natural gas liquids.

                     Less frequently, oil and gas can be produced by other methods. Oil can be
                     found in tar sands, which are porous rock (sandstone) structures on the
                     surface to  100 meters deep.  The material is fairly viscous and also is fairly
                     high in sulfur and metals. Although the Athabasca region in Canada is the
                     primary area of significant tar sand mining, there are some deposits in the
                     western United States.

                     Oil may also be extracted from oil shale. These deposits may be  10 to 800
                     feet below the surface and can be removed by surface mining or subsurface
                     excavation.  The oil, in a highly viscous form called kerogen, is usually
                     heated to allow it to flow. Because only approximately 30 gallons (less than
                     a barrel) are produced per ton of shale,  the process is costly, and the oil shale
                     mining industry is  currently only a minor contribution to the domestic oil
                     supply.

                     A small but increasingly significant source of natural gas is coalbed methane.
                     In all  coal deposits, methane is found as a byproduct of the coalification
                     process and is loosely bound to coal surface areas. This methane historically
                     was considered a safety hazard in the coal mining process and was vented,
                     but recently it has been recovered in conjunction with mining or produced
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                    independently via wells in deposits that are too deep for mining.  Generally,
                    coalbed methane is collected by drilling  a well similar to those used for
                    conventional oil and gas deposits, but with some adaptations to accommodate
                    mining operations and different rock characteristics (EPA, 1992). In 1997,
                    coalbed methane production accounted for six percent  of the total U.S.
                    natural gas production (EIA, 1998).

                    Methane hydrates are another form of natural  gas, for which economically
                    viable recovery methods are still in development. Methane hydrates are
                    structures in which methane molecules are trapped within a lattice of ice.
                    They are found principally in cold and/or pressurized conditions: on land in
                    permafrost regions, or beneath the ocean at depths greater than 1,500 feet
                    below the water surface.  These eventually could be an immense resource;
                    estimated amounts of methane in these structures in the United States is
                    200,000 trillion cubic feet, compared to an estimated 1,400 trillion cubic feet
                    in conventional natural gas deposits.  A goal of the U.S. Department of
                    Energy methane hydrates research program  is to develop  a commercial
                    production system by the year 2015 (U.S. DOE, 1998).
       II.B.2. Industry Size and Distribution

                     The oil and gas extraction industry is an important link in the energy supply
                     of the United States. Petroleum and natural gas supply 65 percent of the
                     energy consumed in the United States, and domestic producers supply
                     approximately 40 percent of the petroleum and 90 percent of the natural gas
                     [EIA and Independent Petroleum Association of America (IPAA),  1999].
                     According to the 1992 Census of Mining Industries, the industry employed
                     345,000 people and had yearly revenues of $112 billion.

                     Several factors influence the size  of the industry, including  technology
                     development and crude oil prices (which are set in world markets) (EIA,
                     1999). Employment in the industry is also affected by the recent trend in
                     mergers and consolidation among companies in the industry.

                     Within the overall oil and gas extraction industry group (SIC code 13), SIC
                     1311 (crude petroleum and natural gas) is the largest. As shown in Figure 1,
                     this industry employs half of the total workers in this SIC group, and accounts
                     for about 60 percent of the sales.   SIC  code 1389 (services not elsewhere
                     classified) is the next largest employer, but SIC code 1321 (natural gas
                     liquids) is more significant with respect to sales.
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                      Figure 1: Employment and Value of Shipments and Receipts in the
                      Oil and Gas Industry
                                  Employment
                                    174,800
                             12,200
                               47,700
     Value of Shipments and Receipts
                (millions)

           $72,245.4	
                                   13,700
                                               96,400
                     BMl I/ $7,515.3

                         V  $964.6
                           $3,583.6

                     $27,213.8
                                |	|   Crude Petroleum and Natural Gas
                                |  |   Drilling
                                ITfl   Services NEC
           Natural Gas Liquids
           Exploration Services
                      Source: 1992 Census of Mineral Industries, U.S. Department of Commerce, 1995.
                      The major oil and gas producing areas in the United States are in the Gulf of
                      Mexico region (onshore and offshore), California, and Alaska (see Figure 2).
                      The  Gulf of Mexico  and surrounding land  in particular  is the  most
                      concentrated area of production; in 1998, Texas (onshore and offshore)
                      produced 23 percent of the nation's crude oil, Louisiana produced 5 percent,
                      and the Federal offshore region produced 14 percent.1

                      The geographic distribution is similar for natural gas; Texas, Louisiana, and
                      the Gulf of Mexico are the major producing locations  (Figure 3).  New
                      Mexico, Oklahoma, Wyoming, and Kansas are also important gas-producing
                      states, while California and Alaska are less important with respect to natural
                      gas production than they are for crude oil.
1  The Federal Offshore Region, or Outer Continental Shelf (OCS), is seaward of State jurisdiction (3 nautical
miles, or approximately 3.3 statute miles, from an established baseline except for Texas and the Gulf coast of
Florida, for which the boundary is 3 marine leagues, or approximately 10 statute miles), and landward of a line
defined by international law at a minimum of 200 nautical miles (MMS, 1997) (See plOl for more details).
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Figure 2: 1996 U.S. Crude Oil Production (Million Barrels per Year)
                                              n	
Note: Small quantities are also produced in Arizona, Missouri, Nevada, New York, South Dakota, Tennessee, and
Virginia.
Source: £/.£ Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report, EIA, 1997.
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Figure 3: 1996 U.S. Natural Gas Production (Billion Cubic Feet per Year)
Note: Small quantities are also produced in Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon,
South Dakota, and Tennessee.
Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report, EIA, 1997.
                     The oil and gas industry has a unique standing for census purposes because
                     of the sheer number of wells in the country. For the purposes of simplifying
                     reporting  procedures  under  SIC  code  1311,  the census  defines an
                     establishment as all activities of an operating company in an entire state.
                     Therefore, these data give no information on the number of individual wells.
                     Data collected by the  Independent Petroleum  Association  of America,
                     however, indicated that in 1997 there were 573,504 active wells extracting
                     primarily crude oil, and 303,724 wells producing primarily natural gas in the
                     United States (IPAA, 1999).

                     Another unique  aspect of the industry is the marginal nature  of many
                     operations. Oil and  gas wells can have very long lives (20 years or more);
                     some wells drilled in the early years  of this century are still producing, but
                     only in small volumes.  Wells typically have higher production in the early
                     years, then decline and can level off at a low level of production that can be
                     sustained for a long period (API, 1999).  Wells  that produce less than 10
                     barrels of oil per day are called "stripper wells."  As of 1997, there were
                     436,000 active stripper  wells (76 percent of all  active domestic wells)
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                    producing an average of 2.2 barrels each daily.  Together stripper wells
                    account for about 15 percent of domestic production (IPAA, 1999).

II.B.3. Economic Trends

       Domestic Consumption

                    The consumption of oil and gas in the United States is closely linked to the
                    overall  economy of the country.  Between 1990  and 1998, crude  oil
                    consumption increased approximately 1.4 percent each year, and natural gas
                    consumption increased at a rate of 2.0 percent per year. The rate of natural
                    gas consumption is expected to continue growing, mostly at the expense of
                    coal. Natural gas is expected to become an important source of energy in the
                    future and will be accelerated by government policies and the development
                    of the natural gas transportation infrastructure.  In the past  several years,
                    however, the percent of the domestic consumption of both oil and gas met by
                    domestic producers generally has decreased (Figures 4 and 5).
 Figure 4: U.S. Oil Consumption and Percent Produced Domestically
                                                                              60%
              1978
1982
                                      1986
                        1990
                                                              1994
                                                1998
                              I U.& Consumption .
                     . % Produced Domestically
 Source: EIA and IPAA, 1999.
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 Figure 5: U.S. Natural Gas Consumption and Percent Produced Domestically
25,000
                                                                              100%
               1978  1980  1982  1984   1986   1988   1990  1992  1994  1996   1998
                             a U.S. Consumption
                                      . % Produced Domestically
Source: EIA and IPAA, 1999.
       Exploration and Reserves
                    The industry is exhibiting a general trend in exploration from domestic to
                    foreign locations. In 1986, U.S. petroleum companies spent $17 billion on
                    exploration and development within the United States and $7.5 billion
                    abroad.  In 1995, these firms spent $12.4 billion in the United States and
                    $13.2 billion abroad (U.S. Department of Commerce (U.S. DOC), 1998).
                    This shift in funds has placed an emphasis on drilling exploratory wells only
                    at the most promising sites in the U.S.  The results can be seen in Figure 6;
                    many fewer exploratory wells are being drilled, but the success rate is higher.
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Figure 6: Number of Exploratory Wells Drilled and Percent That Enter Production
         20,000
                                                                              40%
                                                                              0%
               1978   1980   1982   1984  1986  1988  1990   1992   1994   1996  1998
                               ii Number of Wells Drilled .
         . % Productive
Note: Includes both oil and natural gas wells.
Source: American Petroleum Institute, 1999.
                     The most active areas of exploration are the Gulf of Mexico and Alaska.  In
                     the Gulf of Mexico, the development of technology that facilitates drilling in
                     deeper  water  (including  floating  structures,   drillships  and  subsea
                     completions) has made it more feasible to explore deep water sites. Another
                     new source for potential reserves2 is in Alaska, where roughly 87 percent of
                     the Northeast  National Petroleum  Reserve was opened  in 1998  for
                     exploration  and  leasing (DOI,  1998).   Developments  such  as these
                     temporarily have boosted hydrocarbon reserves above production levels. In
                     1997, for the first time in a decade, crude oil reserves were added at a level
                     greater  than the amount depleted through  production.  However, it is
                     expected that in the future reserves will again decline relative to production
                     (EIA, 1998).

                     Natural gas  exploration  efforts  in the United  States  have  been more
                     successful than crude oil  exploration at keeping pace  with production.
                     Between 1994 and 1997, the industry added more reserves than it extracted
                     in production. In 1997, about 64 percent of the new reserves of natural gas
                     were found in the Gulf of Mexico Federal Offshore region and Texas (EIA,
                     1998).
2 The Energy Information Administration of the U.S. Department of Energy defines proved reserves as those
volumes of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable
in future years from known reservoirs under existing economic and operating conditions (EIA, 1998).
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                                                 Introduction, Background, and Scope
       Domestic Production and Prices
                     Production of crude oil is showing  a decreasing trend, and natural gas
                     production is showing an increasing trend. As shown in Figure 7, crude oil
                     production is decreasing at an approximate rate of 1.5 percent per year.
                     Leading the decline is Alaska, where production has declined approximately
                     three percent per year in the past decade and six percent in 1997.

                     The production  of natural gas,  however, has been increasing steadily.
                     Historically, growth has been about 1 percent per year, and is expected to
                     grow at a rate of 1.6 percent per year through 2002 (U.S. DOC, 1998).
Figure 7: Domestic Crude Oil and Natural Gas Production
      3,500
a  3,000 .

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Oil and Gas Extraction
        Introduction, Background, and Scope
Figure 8: Wellhead Crude Oil and Natural Gas Prices, Fixed 1998 Dollars
      $60
   o
   Q
       $0
          1978   1980   1982   1984   1986   1988   1990   1992   1994   1996   1998
                                  . Crude Oil
  . Natural Gas
Source: EIA and IPAA, 1999.
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                Industrial Process Description
III.  INDUSTRIAL PROCESS DESCRIPTION
                     This section describes the major industrial processes within the oil and gas
                     extraction industry, including the materials and equipment used and the
                     processes employed.  Specifically, this section contains a description of
                     commonly used drilling and production processes, associated raw materials,
                     the byproducts produced or discharges  released, and the materials either
                     recycled or transferred off-site.  This discussion also provides a concise
                     description of both the production and the potential fate of wastes produced
                     in each process.

                     The  section is  designed for  those  interested in  gaining a  general
                     understanding of the industry, and for those interested in the inter-relationship
                     between the industrial process and the topics described in subsequent sections
                     concerning waste outputs, pollution prevention opportunities, and federal
                     regulations. This section does not attempt to replicate published engineering
                     information that is available for this industry.  Refer to Section IX for a list
                     of reference documents that are available to supplement this document.
III.A.  Industrial Processes in the Oil and Gas Extraction Industry

                     The oil and gas extraction  industry can be  classified  into four major
                     processes: (1) exploration, (2) well development, (3) production, and (4) site
                     abandonment. Exploration involves the search for rock formations associated
                     with oil or natural gas deposits, and involves geophysical prospecting and/or
                     exploratory drilling.  Well development occurs after exploration has located
                     an economically recoverable field, and involves the construction of one or
                     more wells from the beginning (called spudding) to either abandonment if no
                     hydrocarbons are found, or to well completion if hydrocarbons are found in
                     sufficient quantities.

                     Production is the process of extracting the hydrocarbons and separating the
                     mixture  of liquid hydrocarbons, gas, water,  and  solids,  removing the
                     constituents that are  non-saleable, and selling the liquid hydrocarbons and
                     gas. Production sites often handle crude oil from more than one well. Oil is
                     nearly always processed at a refinery; natural gas may be processed to remove
                     impurities either in the field or at a natural gas processing plant.

                     Finally, site abandonment involves plugging the well(s) and restoring the site
                     when  a recently-drilled well lacks the  potential to produce economic
                     quantities of oil or gas, or when a production well is no longer economically
                     viable.
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                     Two ancillary processes are also discussed in this section because they have
                     significant economic and environmental implications.  Maintenance of the
                     well and reservoir is important in sustaining the safety and productivity of the
                     operation and in ensuring protection of the environment. Spill mitigation is
                     important in the oil and gas production industry because spills and other types
                     of accidents  can have  serious implications for  worker safety and  the
                     environment.

       HI.A.1. Exploration

                     Oil and natural gas deposits are located almost exclusively in sedimentary
                     rock and are often associated with certain geological structures. Geophysical
                     exploration is the process of locating these structures in the subsurface via
                     methods that fall under the category of remote  sensing.  In particular,
                     common hydrocarbon-containing structures are those where a relatively
                     porous rock has an overlying low-permeability rock that would trap the
                     hydrocarbons (Berger and Anderson, 1992).  Two common structural traps
                     are found in Figure 9: anticlines are upward folds in the rock layers, while
                     faults are fractures in the Earth's surface where layers are shifted.

                     Geophysicists search for these structures by taking advantage of the fact that
                     seismic waves will travel through, bend, absorb, and reflect differently off of
                     various layers of rock (Berger and Anderson, 1992). Geophysicists generate
                     these seismic waves at the earth's surface, and measure the reflected seismic
                     waves with a series of sensors known as geophones. Seismic waves can be
                     generated by a variety of sources ranging from explosives that are detonated
                     in holes drilled below the surface, to land vibroseis and marine airguns. Land
                     vibroseis is  typically used  near  populated  areas  and near  sensitive
                     environmental areas where detonations are not desirable. In the vibroseis
                     process, trucks are used to drop a heavy weight on hard surfaces such as
                     paved roads in order to create seismic waves.

                     In marine  locations, explosives are less  effective and have  deleterious
                     environmental impacts.  In addition, vibroseis is impractical in water that is
                     hundreds of feet deep.  Seismic energy is therefore created by an airgun, a
                     large device that can be emptied of air and water to create a vacuum. Seismic
                     waves  are created when water is allowed into the device at a very fast rate.
                     It should be stressed that geophysical remote sensing cannot identify oil or
                     gas accumulations directly; it can only indicate the potential for reserves via
                     the presence or absence of certain rock characteristics that may be worthy of
                     exploration.

                     After a site has been judged to have a reasonable  chance of discovering a
                     sufficient amount of hydrocarbons an exploratory well is drilled.  It should
                     be  noted that although  seismic  exploration  technology is  constantly
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                     improving, it is not perfect. The only true way to discover the presence and
                     quantity of petroleum is by drilling a well into the formation or structure
                     suspected of containing hydrocarbons.

                     Figure 9: Common Oil and Gas Structural Traps
                    Source: EPA, 1992.

       III.A.2. Well Development

       Drilling
                    During the drilling process, wellsite geologists will augment the remote
                    geophysical data with wireline logs, which are taken by means of devices
                    lowered into the wellbore with wires. Wireline logs include several types of
                    measurements that help to characterize the depths and thickness of subsurface
                    formations and the type of fluids that they may contain.  As an example, one
                    type of log analyzes the resistance of the formation to electrical current,
                    which helps to indicate the type of fluid and the porosity of the formation.
                    For exploratory wells, mud logs may also be developed, which document the
                    drill rate, types of rocks encountered, and any hydrocarbons encountered.
                    The range of depths of well holes, or wellbores, is anywhere between 1,000
                    and 30,000 feet, with an average depth of all U.S. wells drilled in 1997 of
                    5,601 feet (API, 1998a).

                    For both onshore and offshore sites, the subterranean aspects of the drilling
                    procedure are very similar. The drill bit is the component in direct  contact
                    with the rock at the bottom of the hole, and increases the depth of the hole by
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                     chipping off pieces of rock. The bit may be anywhere from three and three-
                     fourths inches to two feet in diameter, and is usually studded with hardened
                     steel or diamond.  The selection of the drill bit can vary, depending on the
                     type of rock and desired drilling speed. For example, a large-toothed steel bit
                     may be used if the formation is soft and speed is important, while a diamond-
                     studded bit may be used for hard formations or when a long drill life is
                     desired (Kennedy, 1983). The drill bit is connected to the surface by several
                     segments of hollow pipe, which together are called the drill string. The drill
                     string is usually about 4 inches in diameter; drilling fluid is pumped down
                     through its center and returns to the surface through the space, called the
                     annulus, between the drill string and the rock formations or casing.
       Drilling Fluids
                     Drilling fluid is an important component in the drilling process. A fluid is
                     required in the wellbore to: (1) to cool and lubricate the drill bit; (2) remove
                     the rock fragments, or drill cuttings, from the drilling area and transport them
                     to the surface; (3) counterbalance formation pressure to prevent formation
                     fluids (i.e. oil, gas, and water) from entering the well prematurely, and (4)
                     prevent the open (uncased) wellbore from caving in (Berger and Anderson,
                     1992; Souders,  1998). Different properties may be required of the drilling
                     fluid, depending upon the drilling conditions. For example, a higher-density
                     fluid may be needed in high-pressure zones, and a more temperature-resistant
                     fluid may be desired in high-temperature conditions.  While  drilling fluid
                     may be a gas or foam, liquid-based fluids (called drilling muds) are used for
                     approximately 93 percent of wells (API, 1997). In addition to liquid, drilling
                     muds usually contain bentonite clay that increases the viscosity and alters the
                     density of the fluid.  Drilling mud may also contain additional additives that
                     alter the properties of the fluid.  The most significant additives are described
                     later in this section.  The American Petroleum Institute (API) environmental
                     guidance document "Waste  Management in Exploration and Production
                     Operations," (API E5) considers the three general categories of drilling fluid
                     (muds) to be water-based, oil-based, and synthetic-based. Synthetic-based
                     muds  are used  as  substitutes for oil-based muds,  but also may be  an
                     advantageous replacement for water-based muds in some situations.

                     Water-based muds are used most frequently.  The base may be either fresh or
                     salt water, for onshore and offshore wells, respectively.  The primary benefit
                     of water-based muds is cost; they are the least expensive of the major types
                     of drilling fluids, and in general they are less expensive to use since the
                     resultant drilling waste can be discharged onsite provided these wastes pass
                     regulatory requirements (EPA, 1999). The significant drawback with water-
                     based muds is their limited lubricity and reactivity with some shales. In deep
                     holes or high-angle directional drilling, water-based muds are not able to
                     supply sufficient lubricity to avoid sticking of the drill pipe. Reactivity with
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                     clay shale can cause the destabilization of the wellbore.  In these cases, oil-
                     based and synthetic muds are needed.

                     In 1993 EPA estimated that about 15 percent of wells drilled deeper than
                     10,000 feet used some oil-based muds (USEPA, 1993b). Oil-based muds are
                     composed primarily of diesel oil  or mineral oil  and are therefore more
                     expensive than water-based muds.  This higher cost, which includes the
                     added burden of removing  the oil from drill cuttings, and the required
                     disposal options make oil-based muds a less frequently used option.  Oil-
                     based muds are well suited for the high temperature conditions found in deep
                     wells because oil components have a higher boiling point than water, and oil-
                     based muds can avoid the pore-clogging that may occur with water-based
                     muds. Also oil-based muds are used when drilling through reactive (or high
                     pressure) shales, high-angle directional drilling, and drilling  in deep water.
                     These situations encountered while drilling can slow down the drilling rate,
                     increase drilling costs or even be impossible if water-based muds are used.
                     In cases when oil-based muds are necessary, the upper section of a well
                     generally is drilled with water-based muds and the conversion is made to oil-
                     based mud when the situation requires  it.  It is predicted  that since the
                     industry trend is toward deeper wells, oil-based muds may  become more
                     prominent. However, because oil-based muds and their cuttings can not be
                     discharged this may not be the case.

                     Since about 1990, the oil and gas extraction industry has developed many
                     new oleaginous (oil-like)  base materials from which to formulate high
                     performance drilling fluids.  A general class of these fluids  are  called
                     synthetic materials, such as the vegetable esters, poly alpha olefins, internal
                     olefins, linear alpha olefins, synthetic paraffins, ethers, linear alkylbenzenes,
                     and others. Other oleaginous materials have also been developed for this
                     purpose, such as enhanced mineral oils and non-synthetic paraffins.  Industry
                     developed synthetic-based fluids with these synthetic  and  non-synthetic
                     oleaginous materials as the base fluid to provide the drilling performance
                     characteristics of traditional oil-based fluids based on diesel and mineral oil,
                     but with the potential for lower environmental impact and greater worker
                     safety through lower toxicity, elimination of Polyaromatic  hydrocarbons
                     (PAH), faster biodegradability, lower bioaccumulation potential and in some
                     drilling situations decreased drilling waste volume (FR 66086,  December 16,
                     1996).

                     On land, air and foam fluids may be used  in drilling wells.  These fluids are
                     less viscous than drilling muds and can enter smaller pores more easily. They
                     are used when a higher rate of penetration into the  formation is desired.
                     Because air is less dense than a liquid, however, these fluids cannot exert the
                     same pressure  in the hole as liquid, and their viscosity can be altered if
                     drilling encounters liquid in the formation. For this reason, air and foam
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                     fluids are used  only in relatively  low-pressure  and water-free  drilling
                     locations, but are preferred in these situations because these fluids are much
                     less expensive than other fluids (Kennedy, 1983; Souders, 1998). Air and
                     foam fluids currently are used in the drilling of about seven percent of the
                     wells in the United States (API, 1997).

                     Drilling muds typically have several additives. (Air and foam fluids typically
                     do not contain many additives because the additives are either liquid or solid,
                     and will not mix with air and foam drilling fluids.) The following is a list of
                     the more significant additives:

                     •      Weighting materials, primarily barite (barium sulfate), may be used
                            to increase the density of the mud in order to equilibrate the
                            pressure between the wellbore and formation when drilling through
                            particularly pressurized zones. Hematite (Fe2O3) sometimes is
                            used as a weighting agent in oil-based muds (Souders, 1998).

                     •      Corrosion inhibitors such as iron oxide, aluminum bisulfate, zinc
                            carbonate, and zinc chromate protect pipes and other metallic
                            components from acidic compounds encountered in the formation.

                     •      Dispersants, including iron lignosulfonates, break up solid clusters
                            into small particles so they can be carried by the fluid.

                     «      Flocculants, primarily acrylic polymers, cause suspended particles
                            to group together so they can be removed from the fluid at the
                            surface.

                     •      Surfactants, like fatty acids and soaps, defoam and emulsify the
                            mud.

                     •      Biocides, typically organic amines, chlorophenols, or
                            formaldehydes, kill bacteria that may produce toxic hydrogen
                            sulfide gas.

                     •      Fluid loss reducers include starch and organic polymers and limit
                            the loss of drilling mud to under-pressurized or high-permeability
                            formations (EPA, Office of Solid Waste, 1987).
       Casing
                     As the hole is drilled, casing is placed in the well to stabilize the hole and
                     prevent caving. The casing also isolates  water bearing and hydrocarbon
                     bearing zones.  As shown in Figure 10, three or four separate casing "strings"
                     (lengths of tubing of a given diameter) may be used in intermediate-depth
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                    wells.  In locations where surface soils may cave in during drilling, a
                    "conductor" casing may be placed at the surface, extending only twenty to
                    one hundred feet from the surface. This string is often placed prior to the
                    commencement of drilling with a pile driver (Berger and Anderson, 1992).
                    The next string, or "surface" casing, begins at the surface and may penetrate
                    two thousand to three thousand feet. Its primary purpose is to protect the
                    surrounding fresh-water aquifer(s) from the incursion of oil or brine from
                    greater depths.  The "intermediate" string begins at the surface and ends
                    within a couple thousand feet of the bottom of the wellbore.  This section
                    prevents the hole from caving in and facilitates the movement of equipment
                    used in the hole, e.g., drill strings and logging tools.  The final "production"
                    string extends the full length of the wellbore and encases the downhole
                    production equipment. Shallow wells may have only two casing strings, and
                    deeper wells may have multiple intermediate casings.  After  each casing
                    string has been installed, cement is forced out through the bottom of the
                    casing up the annulus to hold it in place and surface casing is cemented to the
                    surface. Casing is cemented to prevent migration of fluids behind the casing
                    and to prevent communication of higher pressure productive formations with
                    lower pressure non-productive  formations.    Additional  features  and
                    equipment shown in Figure 10 will be installed during the completion process
                    for production: perforations will allow reservoir fluid to enter the wellbore;
                    tubing strings will carry the fluid to the surface; and packers (removable
                    plugs) may be installed to isolate producing zones.

                    Casing is important for both the drilling and production phases of operation,
                    and must therefore  be designed properly. It prevents natural gas,  oil, and
                    associated brine from leaking out into the surrounding fresh-water aquifer(s),
                    limits sediment from entering the wellbore, and facilitates the movement of
                    equipment up and down the hole.  Several considerations are involved in
                    planning the casing. First, the bottom of the wellbore must be large enough
                    to accommodate any pumping equipment that will be needed either upon
                    commencement of pumping, or in the  later  years of production. Also,
                    unusually pressurized zones will require thicker casing in that immediate
                    area.  Any casing strings that must fit within this string must then be smaller,
                    but must still accommodate the downhole equipment.  Finally,  the driller is
                    encouraged to keep the hole size to a minimum; as size increases,  so does
                    cost and waste.
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                     Figure 10: Cross Section of a Cased Well
                            Surface
                            Casing
     .Production
     Cuing
                       Conductor
                       Casing  '
                      Ground Surface


                    •Water Table

                    Fresh Water Zone
                                                                  Confining
                                                                   Zone
                                                                 Zooel
                                                                 Zone 2
                            Perforations
                     Source: EPA, 1992.
       Drilling Infrastructure
                     In addition to the well and its accouterments,  infrastructure including
                     construction and equipment is necessary at the surface. Roads and a pad are
                     built at onshore sites; a ship, floating structure, or a fixed platform is needed
                     for offshore operations. In addition, devices are needed to lift and lower the
                     drilling equipment, filter rock cuttings from the  drilling fluid, and store
                     excess fluid and waste. The following sections  describe the equipment
                     required for onshore and offshore sites, respectively.

                     Onshore Drilling
                     Because the majority of onshore drilling sites are accessed by road, the
                     equipment is geared toward mobility.  First, an access road is built.  In many
                     locations the building of an access road is not difficult, but some areas
                     present complications. On the North Slope of Alaska, for example, building
                     a road that does not melt the permafrost can be both challenging and
                     expensive. Board roads are used in some locations where soil conditions are
                     not stable. Next, a footing for the equipment, usually gravel, is created in
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                     areas where the ground may be either unstable or subject to freeze/thaw
                     cycles. Finally, the drilling rig is brought in. For shallow wells, the drill rig
                     may be self-contained on a single truck; for deeper wells, the rig may be
                     brought to the site in several pieces and assembled at the site.

                     A basic arrangement of the actual drilling equipment, or rig, is shown in
                     Figure 11. The derrick (sometimes referred to as the mast) is the centerpiece
                     of the operation, and is the frame from  which the  drill  string is lifted,
                     lowered, and turned. The hoisting equipment, kelly, and drill pipe connect the
                     bit to the derrick.  The drawworks and engines next to the derrick lift and
                     drive the drill string, by turning  the rotary table.  The  drilling mud is
                     circulated through the wellbore via the mud hose (also called a gooseneck),
                     down through the rotary hose (not shown), kelly, and drillpipe, out nozzles
                     in the  drill bit, and back up to the  surface between the drill string and the
                     wellbore. The mud is pumped by the mud pump, and is stored in the mud (or
                     reserve) pit or in mud tanks.  Finally,  blowout preventers, which are
                     described later in this section, are installed as a safety measure to prevent the
                     drill pipe and subsurface fluids from being blown out of the hole if a high-
                     pressure formation is encountered during drilling. Rigs will often have much
                     more equipment, including a shale shaker which separates rock cuttings, a
                     desander  and desilter,  which remove smaller  particles,  and a vacuum
                     degasser, which removes entrained gas (Berger and Anderson, 1992).
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                      Figure 11: Typical Rotary Drilling Rig
                                                     Hoisting Equipment-
                                                     including Line. Travelling Block,
                                                     Swivel, and Hook
                                                     Mud Hose
                                                     Kelly

                                                           Draw/works and Engines
                      Source: Energy Information Administration, Department of Energy, 1991.
                      Offshore Drilling
                      For offshore sites, selecting the type of drilling rig needed is very important.
                      Two primary considerations in rig selection are: (1) the size of the rig needed
                      for the depth drilled, and (2) the depth of the water. Exploratory wells (called
                      wildcat wells) may be located far from established oil and natural gas fields,
                      and the rig must be transported over a significant distance.   Mobility is
                      therefore a primary concern in these situations.  The depth of water at the
                      drilling site is also important.  If the water is  fairly shallow, a ground-
                      supported rig may be used. If the water is deep (typically over 400 feet), a
                      floating rig may be necessary.  The following  is  a description  of the
                      significant offshore rig types:
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                     Drillships are a popular choice for drilling in deep water, because they are
                     the most mobile of the rig types and have a large capacity for drill strings,
                     casing, and similar supplies.  A drillship has a standard ship hull, with the
                     derrick extending from its center. The ship is kept in place by anchors or by
                     dynamic positioning, a system in which propellers on each side of the ship are
                     coordinated to keep the ship in the same location despite wind, currents, and
                     the torsion caused by drill activities.

                     Semi-submersible drilling rigs are another option at deep water sites. The
                     rig is usually a rectangular structure that holds the drilling equipment, with
                     ballast containers underneath. These containers can be filled with air to float
                     the rig when moving it.  The rig is  held in place by anchors  or dynamic
                     positioning. The semi-submersible rig is more stable than a drillship, but it
                     is also more cumbersome to move from site to site.

                     Jack-up rigs float and are very mobile, but rest on the sea floor when
                     drilling. For this reason, they are used in relatively shallow water (i.e., under
                     400 feet). The rig is towed into place floating, and legs, previously raised for
                     transportation, are lowered to the ocean bottom so that the rig is raised above
                     the water and supported on the ocean floor.  The legs may be raised and
                     lowered independently to compensate for an uneven sea floor.   In an
                     alternative footing method, mat support, the legs are attached to a mat on the
                     sea floor; this mat distributes the weight over a larger area and minimizes the
                     risk of the rig sinking into the soft ocean floor.

                     Fixed structures are commonly used after exploratory or  developmental
                     drilling prove a site has economically recoverable hydrocarbons. In these
                     cases, offshore drilling rigs are mounted onto the production platform, which
                     are securely pinned to the sea floor by concrete, steel, or tension legs.
                     Tension legs are hollow steel tendons that allow no vertical movement, but
                     some horizontal movement. They are the largest and most complex offshore
                     structures and can be used in water in depths  of over 500 feet (usually less
                     than 1,000 feet).  Platforms are very stable and can withstand waves greater
                     than 60 feet high, and winds in excess of 90 knots.  Assembling a fixed
                     platform is a sizeable investment; some platforms have been reported to cost
                     over $ 1 billion (Berger and Anderson, 1992). For this reason, multiple wells
                     are usually drilled at outward angles from a single platform. The centralizing
                     of pumps and separation equipment also make this a convenient arrangement
                     for production (Kennedy, 1983).

                     Lake and Wetland Drilling
                     Inland regions of water often require additional engineering techniques and
                     special adaptations other than the onshore and offshore practices mentioned
                     above. In places of deeper and more open water, barge rigs may be used for
                     drilling. In shallow areas or wetlands, stationary rigs can be constructed or
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                     the area can be backfilled and drilled with a land-based rig. Canals may also
                     be dredged to bring in floating or submergible drilling rigs.  It is common
                     while drilling in wetlands to use the directional drilling technique in order to
                     disrupt as little of the wetland as possible while developing a field.  Often
                     supplies and equipment must be transported by helicopter, or  dredging is
                     required for access by barge rigs.  Regardless of the approach used, these
                     areas often pose challenges for erecting the rig and transporting materials and
                     personnel to and from the site,  and involves compliance with Clean Water
                     Act wetlands regulations (See Section VLB for additional information)
                     (Kennedy, 1983, and EPA, 1995).
       Well Completion
                     When drilling has been completed, several steps may be needed before
                     production begins.   First,  testing is performed to  verify whether the
                     hydrocarbon-bearing  formations   are  capable  of  producing  enough
                     hydrocarbons to warrant well completion and production. As many as three
                     types of tests may be performed before the final (production) string of casing
                     is installed. These tests are coring, wireline logging, and drill stem testing.

                     Coring is typically performed only in exploratory wells, and not in fields
                     where several wells have already been drilled. A special drill removes an
                     intact sample, or core, of rock at the depth where oil or gas is most likely to
                     be.  The core can be as short as 15 feet or as long as 90 feet. Special side-
                     wall coring techniques may be employed in some wells. Unlike the more
                     indirect testing methods described below, a core allows a geologist to observe
                     the rock type directly, and measure its porosity, or the volume of fluid-
                     occupying space relative to the volume of rock, and permeability, the ease
                     with which fluids can flow through a porous rock.

                     Wireline logging refers to the recording of acoustical, electrical resistivity,
                     and other geophysical measurements within a wellbore. These measurements
                     provide detailed information on the geologic formations encountered by the
                     well, and augment the seismic data recorded prior to the well drilling and the
                     mud log for that well. These data often help to determine more precisely the
                     depth at which oil and gas could be produced.   A logging of  electrical
                     resistivity  takes advantage  of the  fact that some compounds are  better
                     insulators  of electrical charge than others.  For example, oil,  gas, and
                     consolidated  rock  resist  electrical  current  better than  water and
                     unconsolidated rock. Additional tests may be used; radioactivity logs can
                     differentiate between types of rock, and neutron logs can measure the amount
                     of liquid in the formation (but not differentiate between  oil and water).
                     Logging is performed on nearly all wells, and multiple forms of logging may
                     be used in conjunction with each other to attain a more complete analysis.
                     For example, a neutron log will indicate the amount of liquid in a formation,
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                     and a resistivity log may help to determine what percentage of that liquid is
                     oil. Certain types of logs may be conducted during drilling with a special tool
                     located on the drillstring above the bit.

                     Drill stem testing may be the most important and definitive test  Equipment
                     attached to the bottom of a drill string traps a sample of formation fluid.
                     Measuring the pressure at which the fluid enters the chamber and the pressure
                     required to expel that fluid back into the formation yields an estimate of the
                     flow rate of formation fluid to be expected during production. If the flow rate
                     is expected to be too low, procedures such as stimulation (see below) may be
                     required to increase the flow before production equipment is installed.

                     Perforation
                     When the production casing is cemented in the wellbore, the casing is sealed
                     between the casing and the walls of the well. For formation fluid (oil, gas,
                     and water) to enter the well, the casing must be perforated. The depth of the
                     producing zone is determined by analyzing the logging data; small, directed
                     explosive charges are detonated at this depth, thereby perforating the casing,
                     cement, and formation. The result is that formation fluid enters the well, yet
                     the rest of the well's casing remains intact.

                     Stimulation
                     Some formations may have a large amount of oil as indicated by coring and
                     logging, but may have a poor flow rate. This may be because the production
                     zone is not have sufficient permeability, or because the formation was
                     damaged or clogged during drilling operations.  In these cases, pores are
                     opened in the formation to allow fluid to flow more easily into the well. The
                     hydraulic fracturing method involves introducing liquid at high pressure into
                     the formation, thereby causing the formation to crack. Sand or a similar
                     porous substance is then emplaced into the cracks to prop the fractures open.
                     Another method, acidizing,  involves  pumping acid,  most  frequently
                     hydrochloric acid, to the formation, which dissolves soluble material so that
                     pores open and fluid flows more quickly into the well.  Both fracturing and
                     acidizing may be performed simultaneously if desired, in an acid fracture
                     treatment. Stimulation may be performed during well  completion, or later
                     during maintenance, or  workover, operations, if the oil-carrying channels
                     become clogged with time (EPA, 1992).

                     Production equipment installation
                     When drilling, casing, and testing operations are completed, the drilling rig
                     is removed and the production rig is installed.  In most cases, tubing is
                     installed in the well which carries the liquids and gas to the surface. At the
                     surface, a series of valves, collectively called the Christmas tree because of
                     its appearance, is installed to control the flow of fluid from the well. Pumps
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                     are added if the formation pressure is not sufficient to force the formation
                     fluid to the surface.   Different types  of pumps  are available; the most
                     common is the rod pump. The rod pump is suspended on a string of rods
                     from a pumping unit,  and the prime mover for pumping units can be an
                     electric motor, or  a gas engine. Equipment is usually installed onsite to
                     separate natural gas  and liquid phases of the production and  remove
                     impurities.   Finally, a pipeline connection or storage container (tank) is
                     connected to the well to facilitate transport or store the product. In the case
                     of natural  gas,  which cannot be stored easily, a pipeline connection is
                     necessary before the well can be placed on production.

                     Although the practice is becoming less common, one or more pits may be
                     constructed for onshore facilities. These may include a skimming pit, which
                     reclaims residual oil removed with water that has been removed from the
                     product stream; a sediment pit,  which stores solids that have settled out in
                     storage tanks; or  an evaporation or percolation pit, which disposes  of
                     produced water (EPA,  1992).

       III.A.3. Petroleum Production

                     The major activities of petroleum production are bringing the fluid to the
                     surface, separating the liquid and gas components, and removing impurities.
                     Frequently, oil and natural gas  are produced from the same reservoir.  As
                     wells deplete the reservoirs into which they are drilled, the gas to oil ratio
                     increases (as well as the ratio of water to hydrocarbons). This increase of gas
                     over oil occurs because natural gas usually is in the top of the oil formation,
                     while the well usually is drilled into the bottom portion to recover most of the
                     liquid.  Although the following discussion is geared toward wells producing
                     both oil and  gas, the majority of the discussion also applies to  wells
                     producing exclusively one or the other.

       Primary Production

                     Primary recovery is the first  stage of hydrocarbon production, and natural
                     reservoir pressure is often used to recover oil. When natural pressure is not
                     sufficiently capable of forcing oil to the surface, artificial lift equipment is
                     then employed. This includes various types of pumps, gas lift valves, and
                     may occasionally  include oil stimulation.  When pumping is employed,
                     motors may be used at the surface or inside the wellbore to assist in lifting the
                     fluid to the surface.  Primary production accounts for less than 25 percent
                     of the original oil in place.
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       Secondary Recovery
                     Secondary  recovery  enhances the recovery of  liquid hydrocarbons  by
                     repressurizing the reservoir and reestablishing or supporting the natural water
                     drive. Usually water which is produced with the oil is reinjected, but other
                     sources  of water may also be used.  This type of secondary recovery is
                     generally called a "waterflood" (See Figure 12). Produced water inj ection for
                     enhanced recovery of crude oil and natural gas  is recognized as a form of
                     recycling of this waste.  Furthermore, produced water is more commonly
                     injected for the purpose of secondary recovery than in an injection well that
                     is only used for disposal (in Texas, approximately 61 percent of injected
                     produced water is  for enhanced recovery) (Texas Railroad Commission,
                     1999). This procedure is described further in Section III.C., Management of
                     Wastestreams. Gas is injected to enhance gas cap drive in some reservoirs.
                     Figure 12: Secondary Recovery Using Pumps and Water Injection
                       Water
                                                                                  Water
                    Source: Energy Information Administration, Department of Energy, 1991.
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       Tertiary Recovery
                     A final method for removing the last extractable oil and gas is tertiary
                     recovery. In contrast to primary and secondary recovery techniques, tertiary
                     recovery  involves  the addition of materials not normally found in the
                     reservoir  (Lake, 1989).  These methods are often expensive and energy-
                     intensive (Sittig, 1978).   In most cases, a substance is injected into the
                     reservoir, mobilizes the  oil  or gas,  and is  removed with the product.
                     Examples include:

                     •      Thermal recovery, in which the reservoir fluid is heated either with
                           the injection of steam or by controlled burning in the reservoir, which
                           makes the fluid less viscous and more conducive to flow;
                     •      Miscible injection, in which an oil-miscible fluid, such as carbon
                           dioxide or an alcohol, is injected to reduce the oil density and cause
                           it to rise to the surface more easily;
                     •      Surfactants, which essentially wash the oil from the reservoir; and
                     •      Microbial enhanced recovery,  in which special organic-digesting
                           microbes are injected along with oxygen into the formation to digest
                           heavy oil and asphalt, thereby allowing lighter oil to flow (Lake,
                            1989; EPA, 1992)

       Crude Oil Separation

                     When the formation fluid is brought to the surface, it may contain a spectrum
                     of substances including natural gas, water, sand, silt, and any additives used
                     to enhance extraction.  The general order of separation with respect to oil is
                     the following: the separation of gaseous components, the removal of solids
                     and water, and the breaking up of oil-water emulsions.  (The conditioning of
                     the natural gas that is removed in the first step will be discussed in the next
                     subsection.)

                     The removal of gaseous components primarily is intended to remove natural
                     gas from the liquid; however, gaseous contaminants such as hydrogen sulfide
                     (H2S) also may be produced in some fields during this process.  The gases
                     are removed by passing the pressurized fluid through one or two decreasing
                     pressure  chambers; less and less gas will remain dissolved in the solution as
                     the  pressure is lowered.

                     The liquids and solids that remain are usually a complex mix of water, oil,
                     and sand. Water and oil are generally immiscible; however, the extraction
                     process is usually very turbulent and may cause the water and oil to form an
                     emulsion, in which the oil forms tiny droplets in the water (or vice versa).
                     Fluid separation often produces a layer of sand, a layer of relatively oil-free
                     water, a layer of emulsion, and a (small) layer of relatively pure oil. The free

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                     water and sand, or basic sediment and water (BS&W) are generally removed
                     by a process called free water knockout, in which the BS&W are removed
                     primarily by gravity. Finally, emulsions are broken by heating the fluid in a
                     heater-treater to a temperature of 100-160 degrees fahrenheit, or by treating
                     it with emulsion-breaking chemicals (Arnold and Stewart, 1998).  Following
                     the emulsion breaking, the oil is about 98 percent pure, which is sufficient for
                     storage or transportation to the refinery (Sittig,  1978).

       Natural Gas Conditioning

                     Natural gas conditioning is the process of removing impurities from the gas
                     stream so that it  is of high enough quality to pass through transportation
                     systems. It should be noted that conditioning is  not always required; natural
                     gas from some formations emerges from the well sufficiently pure that it can
                     pass directly to the pipeline.  As the natural gas  is separated from the liquid
                     components, it may contain impurities  that  pose  potential  hazards or
                     problems. The most significant is hydrogen sulfide (H2S), which may or may
                     not be contained  in natural gas. Hydrogen sulfide is toxic (and potentially
                     fatal at certain concentrations)  to humans and corrosive for  pipes;  it is
                     therefore desirable to remove it as soon as  possible in the conditioning
                     process. Another concern is that posed by water vapor.  At high pressures,
                     water can react with components in the gas to form gas hydrates, which are
                     solids that can clog pipes, valves,  and gauges (Manning  and  Thompson,
                     1991).  Nitrogen  and other gases may also be  mixed with the natural gas
                     (methane) in the subsurface.  These other gases  must be separated from the
                     methane prior to  sale. At cold temperatures  the water can freeze,  also
                     clogging pipes, valves, and gauges.  High vapor pressure hydrocarbons that
                     are found to be liquids at surface temperature and pressure (benzene, toluene,
                     ethylbenzene, and xylene, or BTEX) are removed and processed separately.
                     Two significant natural gas conditioning processes are dehydration  and
                     sweetening.

                     Dehydration is performed to remove water from the gas stream. Three main
                     approaches toward dehydration are the use of a liquid or solid desiccant, and
                     refrigeration. When using a liquid desiccant, the gas is exposed to a glycol
                     that absorbs the water. The  water can be evaporated from the glycol by a
                     process called heat regeneration, and the glycol can then be reused.  Solid
                     desiccants, often materials called molecular sieves, are crystals with high
                     surface areas that attract the water molecules. The solids can be regenerated
                     simply by heating  them above the boiling point of water. Finally, particularly
                     for gas extracted from deep, hot wells, simply cooling the gas to  a
                     temperature below the condensation point of water can remove enough water
                     to transport the gas.  Of the three approaches mentioned above, glycol
                     dehydration is the most common when processing occurs in the field (at or
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                    near the well). At natural gas plants, solid desiccants are most commonly
                    used (Smith, 1999).

                    Sweetening is the procedure in which H2S and sometimes CO2 are removed
                    from the gas stream. The most common method is amine treatment.  In this
                    process, the gas stream is exposed to an amine solution, which will react with
                    the H2S  and separate them from the natural gas.  The contaminant gas
                    solution is then heated, thereby separating the gases and regenerating the
                    amine. The sulfur gas may be disposed of by flaring, incinerating, or when
                    a market exists, sending it to a sulfur-recovery facility to generate elemental
                    sulfur as a salable product.  Another method of sweetening involves the use
                    of iron sponge, which reacts with H2S to form iron  sulfide and later is
                    oxidized, then buried or incinerated (EPA, 1992).

       III.A.4. Maintenance

                    Production wells periodically require significant maintenance sessions, called
                    workovers.  During a workover, several tasks may be undertaken: repairing
                    leaks in the casing or tubing, replacing motors or other downhole equipment,
                    stimulating the well, perforating a different section of casing to produce from
                    a different formation in the well, and painting and cleaning the equipment.
                    The procedure often requires bringing in a rig for the downhole work.  This
                    rig can be smaller than those used for initially drilling a well.

                    Two procedures performed to improve the flow of fluid during workovers are
                    removing accumulated  salts (called  scale) and paraffin,  and treating
                    production tubing, gathering lines, and valves for corrosion with corrosion-
                    prevention compounds. As fluids are withdrawn from the formation, the salts
                    that are dissolved in the produced water precipitate out of solution as the
                    solution approaches the surface and cools. The resulting scale buildup can
                    significantly reduce the flow of fluid through the tubing, gathering lines, and
                    valves.   Examples of scale removal chemicals  are  hydrochloric and
                    hydrofluoric acids,  organic acids, and phosphates (EPA, 1994).  These
                    solvents are added to the bottom of the wellbore and pumped through the
                    tubing through which extracted fluid passes.  In a similar fashion, corrosion
                    inhibitors may be passed through the  system to mitigate and prevent the
                    effects of acidic components of the formation fluid, such as H2S and CO2.
                    These corrosion inhibitors, such as ammonium bisulfite or several forms of
                    zinc, may serve to neutralize acid or form a corrosion-resistant coating along
                    the production tubing and gathering lines. Corrosion control activities can be
                     continuous, not just at workover.
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       III.A.5. Well Shut-in/Well Abandonment

                    Production may be stopped for several reasons. If it is a temporary stoppage,
                    the well is shut-in.  If the closure is to be permanent, the well is either
                    converted to a UIC Class II injection well, or it is plugged and abandoned.

                    A temporary shut-in is an option when the conditions causing the interruption
                    in production are anticipated to be short-term.  Examples include situations
                    when the well may be awaiting a workover crew or a connection to a
                    pipeline, or there may be a (temporary) lack of a market (Williams and
                    Meyers, 1997). A well is shut in by closing the valves on the Christmas tree.
                    Depending on the duration, the stoppage may  be called a  temporary
                    abandonment, and regulatory approval and testing, including a mechanical
                    integrity test (MIT), may be required in order to be idle (IOGCC, 1996). It
                    is much more desirable to shut-in a well rather than plug it if production is
                    still viable, because once the well is permanently plugged and abandoned, it
                    is highly impractical to re-access the remaining oil in the reservoir.

                    If the well is part of a production field with many nearby wells still in
                    production, the well may be converted to a UIC Class II injection well, which
                    is regulated under the Safe Drinking Water Act (see Section VLB, Sector-
                    Specific Requirements for more information). Such a well can be used either
                    for disposal of the produced water from these other wells, or may be part of
                    a coordinated Enhanced Oil Recovery (EOR) effort in the field.

                    The final option is to plug and abandon the well. The goal of this procedure
                    is to prevent fluid migration within the wellbore, which could contaminate
                    aquifers or surface water. Oil and gas producing states all have specific
                    regulations governing the plugging and abandonment of wells (see Section
                    VI.B.4., State  Regulations).   When  a well is  plugged,  the  downhole
                    equipment is removed and the perforated parts of the wellbore are cleaned of
                    fill, scale and other debris.  A minimum of three cement plugs  are then
                    placed,  each of which are 100 to 200 feet long. The first is pumped into the
                    perforated (production) zone of the well, in order to prevent the inflow of
                    fluid. A second is placed in the middle of the wellbore.  A third plug is
                    placed within a couple hundred feet of the surface. Additional plugs may be
                    placed  anywhere within the wellbore when necessary.   Fluid  with  an
                    appropriate density is placed between the cement plugs in order to maintain
                    adequate pressure. During this process, the plugs are tested to verify plug
                    placement and integrity (Fields and Martin, 1998). Finally, the casing is  cut
                    off below the surface, capped with a steel plate welded to the casing, and at
                    onshore sites, surface reclamation is undertaken to restore natural soil
                    consistency and plant cover (EPA, 1992).
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                    Problems are  sometimes  encountered with  wells that have  stopped
                    production, yet neither have government approval nor have been plugged.
                    These are generally called idle wells, or when the owners are not known or
                    are insolvent, are called orphan wells.  Please see Section III.B for the
                    possible environmental impacts of such wells.

                    Offshore Platform Decommissioning
                    For offshore, the structure itself must be decommissioned in addition to
                    plugging the well. Several options exist:

                    •      Complete removal of the structure and disposing of the structure
                           onshore
                    •      Removing the structure and placing it in an approved location in the
                           ocean
                    •      Reuse of the structure elsewhere (National Research Council, 1996).

                    The method used will vary with the type of structure and water depth, but the
                    most common approach is  the complete removal of the structure, with
                    removal at a minimum of 15 feet below the mudline  (seafloor).  Other
                    approaches are less expensive and less intrusive to the existing environment,
                    but can be more dangerous for commercial ships, military submarines, fishing
                    trawlers, and recreational boaters. In Texas and Louisiana, however, it may
                    be possible to participate in the states' "rigs-to-reefs" programs, which under
                    the National Fishing Enhancement Act of 1984 seek to convert  offshore
                    structures to permanent artificial reefs (MMS, 1999).

                    When removing the structure, the most common approach is to sever the leg
                    piles with explosives. Explosives must be placed at least five feet below the
                    mud line (sea floor). Explosives are  less expensive and are less risky to
                    divers than alternatives such as manual or mechanical cutting, but concern
                    has been raised about the use of explosives and their effect on marine life
                    (National Research Council, 1996).

       m.A.6. Spill and Blowout Mitigation

                    Accidental releases  at oil and gas production facilities may come in two
                    forms:  spills or blowouts.   Oil spills (usually consisting of crude oil or
                    condensate) may come from several sources at production sites (and in some
                    cases at drilling sites): leaking tanks, during transfers,  or from leaking
                    flowlines, valves, joints, or gauges.  Other spills of oil have occurred such as
                    diesel from drilling operations, oily drilling muds while being offloaded, and
                    production chemicals (MMS, 1998).  Spills  are the most common type of
                    accident and are often small in quantity.
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                     Well blowouts are rare, but can be quite serious. They are most likely to
                     occur during drilling and workovers, but can occur during any phase of well
                     development including production operations. When the drill encounters an
                     unusually pressurized zone or when equipment is being removed from the
                     hole, the pressure exerted by the formation may become considerably higher
                     than that exerted by the drilling or workover fluid. When this happens, the
                     formation fluid and drilling or workover fluid may rise uncontrollably
                     through the well to the surface. Downhole equipment may also be thrust to
                     the surface.  Especially if there is a significant quantity of associated natural
                     gas,  the fluid may ignite from an engine spark or other source of flame.
                     Blowouts have been  known to completely destroy rigs  and  kill  nearby
                     workers. Some blowouts can be controlled in a matter of days, but some -
                     particularly offshore -- may take months to cap and control (Kennedy, 1983).

                     Drilled  wells and  many workover  wells are  equipped with a blowout
                     preventer. These blowout preventers (BOPs) are hydraulically operated, and
                     serve to close off the drill pipe. BOPs can be operated manually, or can be
                     automatically triggered.  Most rigs have regular blowout drills and training
                     sessions so that workers can  operate the BOPs and escape as  safely  as
                     possible.

                     Should a spill occur despite precautions, established responses should be
                     undertaken.  If the facility is subject to Spill Prevention  Control and
                     Countermeasure (SPCC) regulation (see  Section  VLB  for  additional
                     information), the facility will be equipped with secondary containment and
                     diversionary structures to prevent the spill from reaching  drains, ditches,
                     rivers, and navigable waters.  These structures may be berms,  retention
                     ponds, absorbent material, weirs, booms, or other barriers or  equivalent
                     preventive systems.  Should these secondary containment  devices not be
                     adequate, the response will be different for onshore and offshore spills  (EPA,
                     1999). In both cases, the goals are to stop the flow of oil, recover as much as
                     possible of the material as a salable product,  then minimize the impact on
                     navigable waterways or groundwater.

                     Onshore Spills
                     For onshore spills, concern is for both surface runoff to streams, and for
                     seepage into groundwater. The first considerations are to stop the source of
                     the leakage and  to contain the spill.  Containment may either be achieved
                     with pre-existing structures, or by using bulldozers at the time of response
                     (Blaikley,  1979). Pooled oil would then be collected, pumped  out, and
                     whenever possible, processed for sale. When treating the contaminated soil,
                     the remediation  approach taken may vary considerably depending on the
                     porosity  of the soil and composition of the spilled fluid.   If the spill has
                     permeated  less than about 6-10 inches of soil, bioremediation may be the
                     most  appropriate approach.  With bioremediation, hydrocarbon-digesting
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                     microbes found naturally in soil are enhanced with fertilizers and moisture
                     to degrade the material. The site would be tilled periodically and watered to
                     maintain proper amounts of air and moisture.  Should the temperature at the
                     site be too cold or should the spill be too deep for bioremediation to be fully
                     effective,  approaches  such  as composting,  or  soil  excavation with
                     landspreading  or  landfilling,  may  be used either  exclusively  or in
                     combination (Deuel and Holliday, 1997). Another option in remote locations
                     or in situations when other options  have not been successful is  in-situ
                     burning.  In these situations, primarily when there is little surrounding
                     vegetation, calm winds, and difficulty in transporting the equipment required
                     for other methods, the oil is concentrated as much as possible and ignited by
                     any of a variety of methods (Zengel, et al., 1998; Fingas, 1998). Application
                     of in situ burning is still being refined.

                     Offshore Spills
                     The conditions for an offshore  spill cleanup can vary substantially; from
                     deep-water to coastal, from calm water to very choppy seas. As with onshore
                     spills, initial priorities are to contain spilled oil and prevent further leakage.
                     The oil is usually contained by booms, or floating devices that block the
                     movement of surface oil. The booms may then be moved to concentrate the
                     oil, at which point skimmers collect the oil.  Booms may also be placed along
                     a shoreline to minimize the amount of oil that reaches shore.  For the  oil that
                     cannot be collected in this fashion, other approaches are used to minimize
                     environmental impact,  including sorbents,  dispersants, or oil-digesting
                     bacteria (EPA, 1993).  In-situ burning also may be an option for offshore
                     spills.  This option  may be  best suited to arctic conditions, where cold
                     temperatures keep the oil relatively concentrated and where ice may hinder
                     the use of other methods. Depending on the thickness of the oil, the calmness
                     of the seas, and other factors, the destruction rate can be over 90 percent
                     (Fingas, 1998; Buist, 1998). This technique has not been widely used and is
                     still considered experimental.
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III.B. Raw Material Inputs and Pollution Outputs
       Drilling
                    This section describes the impacts that individual steps in the extraction
                    process may have on adding contaminants to the environment.  Relevant
                    inputs and significant output wastes are presented, with outputs summarized
                    in Table 2.  The management techniques used to handle the wastes are
                    discussed in Section III.C, and more information on the magnitude and
                    qualities of the releases are found in Section IV.

                    Oil and gas extraction generates a substantial volume of byproducts and
                    wastes that must be managed. Relatively small volumes of chemicals may
                    be used as additives to facilitate drilling and alter the characteristics of the
                    hydrocarbon flow.  For example, acids may be used to increase rock
                    permeability, or biocides may be added to wells to prevent the growth of
                    harmful bacteria.  The industry also contends with many naturally occurring
                    chemical substances. Byproducts and wastes result from the separation of
                    impurities found in the extracted hydrocarbons or from accidents when oil is
                    spilled.  In addition, most processes involving machinery will  produce
                    relatively small quantities of waste lubricating oils and emissions from fossil
                    fuel combustion,  and inhabited facilities will  produce sanitary wastes.
                    Finally, formation oil contamination may be present  in the spent drilling
                    fluids and cuttings.
                    There are a number of possible environmental impacts from the wastes
                    generated during the well drilling and completion/stimulation processes. In
                    the drilling process, rock fragments (cuttings) are brought to the surface in the
                    drilling fluid.  These cuttings pose a problem both in the large volume
                    produced and the muds that coat the cuttings as they are extracted. Oil-based
                    fluids have the added stigma of having oil frequently coating the cuttings.
                    The volume of rock cuttings produced from drilling is primarily a function
                    of the depth of the well and the diameter of the wellbore.  It has been
                    estimated that between 0.2 barrels and 2.0 barrels (8.4 and 84.0 gallons) of
                    total drilling waste are produced for each vertical foot drilled (EPA, 1987).

                    Drilling mud disposal generally becomes an issue at the end of the drilling
                    process. However, sometimes drilling mud is disposed of during the drilling
                    process when the mud viscosity or density needs to be changed to meet the
                    demands  of formation  pressures.  This can create special concerns for
                    offshore operations where the disposal of a large volume of mud over a short
                    period can create a mud blanket on the seafloor that can have an impact on
                    benthic organisms.  Industry is limited to using barite stock for the making
                    of drilling mud, which passes 40 CFR 435 requirements (less than or equal
                    to 1 ug/kg dry weight maximum mercury and 3 mg/kg dry weight maximum
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                    cadmium). The muds are combined, however, with dissolved and suspended
                    contaminants  including  mercury,  cadmium, arsenic  and  hydrocarbons
                    (typically found in trace amounts). The additives listed in Section III.A may
                    be  found in waste mud, and components  from the formation,  such as
                    hydrogen sulfide and natural gas, may also be dissolved in the mud. Rock
                    cuttings from the formations overlying the target formation may contribute
                    contaminants to the drilling mud such as arsenic or metals.  Also rock
                    cuttings create a large volume of waste and for water-based fluids the rock
                    cuttings may be discharged to surface waters offshore.  Oil-based mud will
                    also contain diesel oil that must be disposed of properly, or more typically,
                    conditioned for reuse. Oil-based muds and cuttings cannot be discharged to
                    surface waters. Both oil-based and synthetic-based fluid are conditioned and
                    reused, which reduces waste volume from drilling operations.

                    Drilling operations also produce air emissions, such as exhaust from diesel
                    engines and turbines that power the drilling equipment. The air pollutants
                    from these devices will be those traditionally associated with combustion
                    sources, including nitrogen oxides, particulates, ozone, and carbon monoxide.
                    Additionally, hydrogen sulfide may be released during the drilling process
                    (EPA, 1992).

                    Some steps in the well completion process may produce waste. The most
                    prominent is stimulation. Unused hydrochloric acid must be neutralized if
                    acid stimulation is being used, and paraffins  and any  other dissolved
                    materials brought to the surface from the formation must be disposed of as
                    well. In addition, solid wastes such as waste cement  and metal casing may
                    remain from the casing process.                                    *
       Production
                    The primary byproduct from the production process (and the dominant one
                    on a volume basis in the industry) is produced water. Other wastes that may
                    be generated during production include the residual wastes that remain after
                    separation of the oil and natural gas.

                    Produced Water
                    The largest volume byproduct by far in the extraction process is water
                    extracted with oil. In wells nearing the end of their productive lives, water
                    can comprise 98 percent of the material brought to the surface (Wiedeman,
                    1996).  The American Petroleum Institute estimates that over 15 billion
                    barrels of water are produced annually. This is nearly eight barrels of water
                    for every barrel of oil produced. Natural gas  wells typically produce much
                    lower volumes of water than oil wells, with the exception of certain types of
                    gas resources  such as coalbed methane or Devonian/Antrim shales (API,
                    1997).
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                    Although many petroleum components are separated from the water easily,
                    some components and impurities are water-soluble and difficult to remove.
                    Some substances may be found in high concentrations, including chloride,
                    sodium, calcium, magnesium and potassium. Others found are:

                    •      Organic compounds: benzene, naphthalene, toluene, phenanthrene,
                           bromodichloromethane, and pentachlorophenol;
                    •      Inorganics: lead, arsenic, barium, antimony, sulfur, and zinc;
                    •      Radionuclides: uranium, radon, and radium (EPA, 1992).

                    It  should  be  noted  that concentrations  of these pollutants will vary
                    considerably depending on the location of the well and the extent of treatment
                    of the water. Geography can be a key factor in whether a substance may exist
                    in produced water. For example, radionuclides are found only in some areas
                    of the country.

                    The risks of water pollution due to produced water management differ for
                    onshore and offshore operations, and are discussed separately.

                    Onshore operations, and coastal and shallow offshore areas,  may pose a
                    risk to the environment if produced water with high saline concentrations is
                    not properly managed. The saline concentration of produced water varies
                    widely. In some locations, the produced water can have salt concentrations
                    of 200,000 mg/L (Stephenson, 1992). However, in some areas west of the
                    98th Meridian, produced water may contain low enough levels of salt that it
                    may be used (upon meeting regulatory limits for oil and grease) for beneficial
                    use for irrigation or livestock watering (EPA, 1992; Railroad Commission of
                    Texas, 1999).

                    The  discharge of produced water inappropriately onto soil can result in
                    salinity levels too high to sustain plant growth.  If introduced to  a water
                    supply, the water can be unusable for human consumption. The introduction
                    of metals and organic compounds from produced water are also a concern.
                    (See Section IV for more details on contaminants  in produced water.)
                    However, over 90 percent of onshore produced water is injected for enhanced
                    recovery or disposal (Smith, 1999). This injection involves a closed system
                    from the producing wellbore to the injection wellbore, so  the potential for
                    release to the soil is minimized.

                    Offshore operations may impact the area immediately  surrounding the
                    platform if produced water effluents are not properly treated and discharged.
                    The concentration of metals, radionuclides, residual oily materials and high
                    BOD in the produced water may be higher than the surrounding water.
                    However, the impact is reduced significantly at greater distances from the
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                     well; research in the Gulf of Mexico has indicated that produced water can
                     be diluted 100-fold within 100 meters of the discharge (Neff and Sauer,
                     1996).

                     Natural Gas Processing
                     Wastes  are  generated when  natural  gas undergoes  dehydration  and
                     sweetening.   For dehydration,  triethylene glycol  is the most common
                     desiccant. Although glycol is reused, it becomes less effective over time and
                     must be replaced periodically.  Glycols are volatile and can be hazardous if
                     inhaled as a vapor.  At larger natural gas processing plants,  the solid
                     molecular sieves that are used also require periodic replacement.

                     The wastes from gas sweetening will  vary depending on the method used.
                     Possible wastes include spent amine solution, iron sponge, and elemental
                     sulfur. When there is a market for sulfur, it is sold.

                     Air Emissions
                     There are several sources of air emissions in the production process. Leaking
                     tubing, valves, tanks, or open pits will release volatile organic compounds
                     (VOCs). When natural gas produced  from the well is not sold or used on-
                     site, it is usually flared, thereby releasing carbon monoxide, nitrogen oxides,
                     and possible sulfur dioxide if the gas is sour (see Section III.C. for more
                     information on flaring). Finally, production involves the use of machinery
                     including pumps, heater-treaters, and motors which require fuel combustion.
                     Emissions from these include nitrogen oxides, sulfur oxides, ozone, carbon
                     monoxide, and particulates (EPA, 1992).  Where electricity is available,
                     electric-powered equipment may be  used.   Emissions  from natural gas
                     processing plants (SIC 1321) are larger than field production operations due
                     to the greater scale and concentration of equipment. Even at gas plants most
                     engines are powered by natural gas or electricity.

                     Other Wastes
                     The sand that is separated from produced water must be disposed of properly.
                     Similar to the sand removed during the drilling process, this sand is often
                     contaminated with oil  and trace amounts of metals or other  naturally
                     occurring constituents.

                     Most oil and gas operations include tanks for the temporary storage of oil,
                     natural gas liquids, and/or produced water.  While  stored, small solid
                     particles that were entrained in the liquids can settle out, forming a sludge on
                     the bottom of the tank. These "tank bottoms," or "basic sediment and water"
                     (BS&W) wastes, may be periodically removed from the tank and disposed of.
                     Some tanks may require cleaning a few times per year; others may require
                     cleaning once every 10 years. The need for tank cleaning, and therefore the
                     generation of these wastes, is dependent upon the characteristics of the fluids
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                    being  handled and the operation.   Because  they are removed  from
                    hydrocarbon storage tanks, tank bottoms are likely to contain oil and smaller
                    amounts  of other constituents (see  Section  IV  for an  example of
                    concentrations of contaminants in these sediments.)
       Maintenance
                    The workover process requires many of the same inputs and produces similar
                    outputs as the drilling process. .In particular, workover fluid, which is similar
                    to drilling fluid, is required to control downhole pressure. Also, emissions
                    will result from the combustion of fuels to power the rig.

                    Workovers also use additional inputs and produce other pollutants, some of
                    which are toxic. The compounds usually appear in the produced water when
                    production resumes, or in the case of cleaning fluids, may be spilled from
                    equipment at the surface.

                    Scale removal requires strong acids, such as hydrochloric or hydrofluoric
                    acids.   When carried to the surface in produced water,  any acids not
                    neutralized during use must be neutralized before being disposed, usually in
                    a Class II injection well.  Scale is primarily comprised of sodium, calcium,
                    chloride  and carbonate; however, trace contaminants  such as barium,
                    strontium, and radium may be present.

                    Also, corrosion inhibitors and stimulation compounds are flushed through the
                    well.  Corrosion-resistant compounds of concern include zinc carbonate and
                    aluminum bisulfate. Stimulation may require acidic fluids.

                    In addition, painting- and cleaning-related wastes may be generated during
                    workovers.  Paint fumes and cleaning solvent vapor may produce gaseous
                    emissions, paint and cleaning solvents with suspended oil and grease must be
                    disposed of properly, and paint containers will require disposal as a solid.

                    Collectively, wastes produced by the industry other than drilling wastes and
                    produced water are called associated wastes. The volume is usually small,
                    about one barrel per well per year (DOE, 1993). Because associated wastes
                    are those associated with chemical treatment or wells or produced fluids,
                    post-treatment materials, and residual waste streams, they are more likely to
                    have higher hydrocarbon or chemical constituent content than produced water
                    or waste drilling fluids.

                    In 1985, API estimated that approximately 12 billion barrels of associated
                    wastes were generated annually (Wakim, 1987). API estimates that in 1995,
                    the annual volume of associated wastes is 22 millions barrels (API, 1997).
                    The higher volume is  attributed primarily to  a  difference in definitions
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                    between the two studies (i.e., the 1995 study includes wastes form gas plants
                    that were not included in 1985). On a comparable basis, there has been only
                    a slight increase in associated waste volumes over the past decade.  This
                    increase can be attributed primarily to aging wells requiring more stimulation
                    or workover treatments to remain on production. Table 1 summarizes the
                    types of associated wastes and their relative volume based on a 1985 API
                    industry survey.
Table 1: Types of Associated Waste
Material
Workover wastes (mud and other
completion fluids, oil, chemicals,
acid water, cement, sand)
Produced sand, separator sludges
Other production fluid waste
Oily debris, filters, contaminated
soils
Cooling water, engine and other
waste water
Dehydration and sweetening unit
wastes
Untreatable emulsions
Used solvents and cleaners
Other production solid waste
Used lubricating or hydraulic oils
Process
Maintenance
Production
Production
All
All
Production
Production
Maintenance
Production
All
Percent of Total Associated
Waste Volume
34%
21%
14%
12%
8%
4%
2%
2%
1%
1%
                     Source: U.S. Department of Energy, 1993. (Based on a 1985 API survey)
       Idle/Orphan Wells
                     Idle wells are wells that have ceased production (either temporarily or
                     permanently) but have not been plugged.  Generally the state regulatory
                     agency knows the operator who is responsible for these wells, and in most
                     states, wells require regulatory approval to  be idle.  However, a small
                     percentage of these are orphan wells, for which no responsible party exists.
                     This may be because the operator is unknown (in the case of wells drilled in
                     the early part of the century) or because the operator has gone bankrupt and
                     has no assets available.

                     Wells that  have stopped production yet neither have  state government
                     approval nor have been plugged are uncommon.  Approximately 134,000 of
                     the nearly 2.7 million total wells drilled by 1995 in the United States are in
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                     this category (IOGCC, 1996). These wells may pose problems with respect
                     to migrating reservoir fluid. With these wells, the mechanical integrity of the
                     casing is not known, and therefore it may be possible for reservoir fluid to
                     migrate  to fresh water aquifers.  In such cases, the primary contaminant
                     would be saline formation water that could pollute fresh water aquifers and
                     possibly surface waters.

                     It should be noted that not all of these wells will necessarily cause pollution;
                     rather, the concern is that the risk posed by these wells is variable. Currently,
                     most oil- and gas-producing states are handling the issue by prioritizing
                     among these wells, and have established programs to plug dangerous orphan
                     wells and clean up any contamination that may have already occurred. One
                     way in which this prioritization is achieved is through area of review (AOR)
                     studies that are required for the approval of new UIC wells.  Under this
                     requirement, the operator of the new well must study  all active,  idle and
                     abandoned wells within an  area (often a 1/4 mile radius) to determine
                     whether they pose a risk  of contamination (IOGCC,  1996).

       Spills and Blowouts

                     Based on data from the U.S. Coast Guard and other sources, the American
                     Petroleum Institute reported that in 1996, 1,276 onshore facilities  reported
                     spills of crude oil for a total of 131,000 gallons. This total would include
                     spills from field operations, but also would include spills of crude oil at
                     refineries, terminals, and other types of facilities. Spill volumes specifically
                     for crude oil are not available. According to the Coast Guard, 78 percent of
                     spills in  1996 were less than 10 gallons (API, 1998b).

                     Production facilities often have systems in place for handling larger accidents
                     such as blowouts, and many onshore oil and gas operations must have a Spill
                     Prevention  Control and Countermeasures  (SPCC) Plan in  place for
                     addressing spills. Under the CWA only spills above a certain threshold must
                     be reported (see Section IV for more details on SPCC and CWA regulations).
                     However, smaller spills appear to account for most  reported crude oil
                     releases. These are most likely to occur due to poor connections in filling or
                     removing materials from tanks (Smith, 1999).

                     Offshore, the Marine Minerals Service collects data on oil spills. According
                     to MMS, in 1995 there were 34 spills from production operations in the Gulf
                     of Mexico, totaling 773 barrels. There was also one spill of one barrel of oil
                     on the Pacific Coast (MMS, 1995).

                     In addition to oil spills, well blowouts can result in accidental releases of
                     material. In a blowout, the pollutant can be produced water and oil, or
                     drilling fluids and workover fluids, such that possible components of concern
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                    are salt, heavy metals, and oil. The produced water and oil mixture can be
                    spread in a wide area around the rig possibly leaching through the soil to a
                    fresh water aquifer or running off into nearby surface waters.  Onshore,
                    statistics on the number of blowouts annually are not available. Offshore,
                    according to data from MMS, there was only one blowout in 1995, and 15
                    blowouts between 1991 and 1995. The total amount of oil spilled as a result
                    of those blowouts was 100 barrels,  all in 1992.  It is assumed from the
                    historical distribution that  14 percent of all blowouts could result in the
                    spillage of crude oil or condensate, with 4 percent of the blowouts resulting
                    in spills greater  than 50 barrels.   Since 1992, all blowouts have been
                    controlled without any spills (MMS,  1995).

                    Accidental releases  can  also include air emissions.   Crude  oil contains
                    organic compounds that may volatilize and be emitted before the spill can be
                    cleaned up.  In-situ  burning of crude oil is one approach for cleaning up
                    spills. Use of burning can result in emissions from the combustion, including
                    particulates and carbon monoxide. Blowouts can result in the emission of
                    methane (natural gas).  If the well ignites, combustion outputs would be
                    expected. In rare cases, process upsets at facilities that process sour natural
                    gas could result in the release of hydrogen sulfide.
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Table 2: Potential Material Outputs from Selected Oil and Gas Extraction Processes
Process
Well Development
Production
Maintenance
Abandoned Wells, Spills
and Blowouts
Air Emissions
fugitive natural gas, other
volatile organic
compounds (VOCs),
Polyaromatic
hydrocarbons (PAHs),
carbon dioxide, carbon
monoxide, hydrogen
sulfide
fugitive natural gas, other
VOCs, PAHs, carbon
dioxide, carbon
monoxide, hydrogen
sulfide, fugitive BTEX
(benzene, toluene,
ethylbenzene, and xylene)
from natural gas
conditioning
volatile cleaning agents,
paints, other VOCs,
hydrochloric acid gas
fugitive'natural gas and
other VOCs, PAHs,
particulate matter, sulfur
compounds, carbon
dioxide, carbon
monoxide
Process Waste Water
drilling muds, organic
acids, alkalis, diesel oil,
crankcase oils, acidic
stimulation fluids
(hydrochloric and
hydrofluoric acids)
produced water possibly
containing heavy metals,
radionuclides, dissolved
solids, oxygen-^
demanding organic
compounds, and high
levels of salts, also may
contain additives
including biocides,
lubricants, corrosion
inhibitors, wastewater
containing glycol,
amines, salts, and
untreatable emulsions
completion fluid,
wastewater containing
well-cleaning solvents
(detergents and
degreasers), paint,
stimulation agents
escaping oil and brine
Residual Wastes
Generated
drill cuttings (some oil-
coated), drilling mud
solids, weighting agents,
dispersants, corrosion
inhibitors, surfactants,
flocculating agents,
concrete, casing,
paraffins
produced sand, elemental
sulfur, spent catalysts,
separator sludge, tank
bottoms, used filters,
sanitary wastes
pipe scale, waste paints, "
paraffins, cement, sand
contaminated soils,
sorbents
Sources: Sittig, 1978, EPA Office of Solid Waste, 1987.
III.C.  Management of Wastestreams
                    The primary wastestreams are those associated with drilling wastes and
                    produced water. As a result, most disposal options are oriented toward these
                    two waste categories. The management of associated wastes and of gases is
                    also briefly described.
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Oil and Gas Extraction
               Industrial Process Description
       Liquids
                    Underground Injection
                    Underground injection is the most common disposal method of produced
                    water; over 90 percent of onshore produced water is disposed of through
                    injection wells (API, 1997), but it is rare at offshore facilities. For disposal
                    of produced water by underground injection, two options are available: to
                    inject the water as a waste disposal method, or to use the produced water as
                    part of a waterflooding effort for enhanced recovery. Water being disposed
                    of typically is injected into known formations, such as a former producing
                    formation. In a few Appalachian states, annular injection of produced water
                    may be used, in which case the fluid is pumped into the space between tubing
                    and casing (or uncased formation) within the well (EPA, 1992).

                    The second option, implemented especially in locations where formation
                    pressure may be relatively low, is reinjecting produced water into the oil- and
                    gas-producing formation. (See Figure 12 on page 29 for an illustration.) The
                    volume of produced water used for enhanced recovery is approximately 57
                    percent of total produced water volumes (API, 1997). This method increases
                    pressure in the formation to force oil toward  the well and contributes to
                    secondary recovery efforts. It requires that water be more thoroughly treated
                    before injection; the water should be free of solids, bacteria, and oxygen, all
                    of which could potentially contaminate the oil reservoir and, in the case of
                    sulfur-reducing bacteria,  could   lead  to  increased  hydrogen  sulfide
                    concentrations in the extracted oil. Please see Section VLB, Sector-Specific
                    Requirements for UIC regulations that apply to produced water underground
                    injection.

                    Liquid wastes bought onshore may include produced water that fails NPDES
                    toxicity requirements; water extracted from sludge; or treatment, workover,
                    and completion fluids. At commercial waste treatment facilities liquid wastes
                    are usually injected into disposal wells. As of February  1997, there are 94
                    disposal wells located in the Texas  coastal zone and 17 in the Louisiana
                    coastal zone. These wells could be used for disposal of OCS-generated liquid
                    wastes (MMS, 1998).

                    Roadspreading
                    If the fluid has the characteristics of materials used for dust suppressants,
                    road oils, deicing materials, or road compaction, the fluid may be used for
                    roadspreading. In this procedure, water is applied to roads at approved rates,
                    in order to prevent pooling or runoff and to minimize the risk of surface water
                    or groundwater contamination. This practice may be subject to testing to
                    ensure that the fluid is similar to the conventional road materials mentioned
                    above, and also to ensure that the level of radioactive material is not above
                    regulatory action levels (IOGCC,  1994). Roadspreading is declining as a
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Oil and Gas Extraction
                Industrial Process Description
                    disposal option, and accounts for less than 1 percent of produced water
                    volumes (API, 1997).

                    Use of Produced Water for Irrigation
                    In areas west of the 98th meridian, produced water from onshore wells that are
                    in the Agricultural and Wildlife Beneficial Use Subcategory may be used as
                    a beneficial use with agriculture.  In these cases, treated water that meets
                    water quality standards may be released directly to agricultural canals for use
                    in irrigation or livestock watering (EPA, 1992; Texas Railroad Commission,
                    1999).  Beneficial use of produced water currently accounts for around 4
                    percent of onshore produced water volumes in the United States (API, 1997).

                    Evaporation or Percolation Pits
                    In this approach, produced water is placed in the pit and allowed to either
                    evaporate to the air or percolate into the surrounding soil. These pits can only
                    be used when the fluid will not adversely impact groundwater or surface
                    water, and  restrictions may be imposed on water salinity, hydrocarbon
                    content, pH, and radionuclide content. This approach is declining because of
                    potential environmental contamination of groundwater and the potential
                    hazard posed to birds and waterfowl by residual oil in these open pits
                    (IOGCC, 1994; Buckner, 1998).  About 2 percent of produced water is
                    currently disposed of using evaporation or percolation pits (API, 1997). Most
                    of this volume is disposed of in percolation pits in arid portions of California.

                    Treat and Discharge
                    For this disposal method the water must meet standards for oil and grease
                    content and pass a toxicity test prior to discharge. In 1997, 1 percent of
                    onshore produced water was disposed of in this manner (API, 1997). Until
                    recently, this method was also used at coastal facilities, but has been largely
                    phased out since 1995. The only coastal area where discharge of produced
                    water is currently allowed is Cook Inlet, Alaska.

                    Treatment and discharge is the primary method  for disposing of produced
                    water at offshore operations. Produced water discharges are not expected to
                    take place at every platform or well.  The trend in the Gulf of Mexico is for
                    water treatment and separation of the well stream to occur only at designated
                    locations.   An industry  survey of 1992  discharge  monitoring reports
                    submitted annually to USEPA (Shell Oil Company, 1994) found that only 29
                    percent of existing platforms contain water treatment systems and discharge
                    their produced  waters.  As industry uses more sophisticated  methods of
                    developing  shallow oil and gas fields and  is required to  conduct more
                    complex treatment protocols, it is likely that operators will increasingly use
                    central processing facilities (MMS, 1998).
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Oil and Gas Extraction
                Industrial Process Description
       Solids
                     Industry's projections (Deepstar, 1994) for deepwater are that the oil and gas
                     produced in deepwater will most likely be piped from subsea completions
                     through mixed line pipelines to large processing facilities primarily operating
                     at the shelf break. These processing facilities will separate and process the
                     production streams into  oil, gas and water, and then discharge the treated
                     water.   The  exception  to  this process would be whenever a floating
                     production," storage and offloading system (FPSO) is chosen as the surface
                     facility receiving oil and gas  from subsea completions.  An FPSO is  a
                     converted tanker used for  a production and storage base, usually  at  a
                     deepwater (greater than 400 meters) production site. These FPSO's, able to
                     operate at any depth, would process the well stream prior to the transport of
                     the products to shallower locations (MMS, 1998).
Table 3: Summary of 1995 Disposal Practices for Onshore
Produced Water
Method
Injected for Enhanced Recovery
Injection for Disposal
Beneficial Use
Evaporation and Percolation Ponds
Treat and Discharge
Roadspreading
Percent of Onshore Produced Water
57%
36%
4%
2%
1%
<1%
                     Source: API, 1997.
                     The primary solid waste-generating process is drilling, and therefore the solid
                     waste disposal processes are geared toward drilling waste. However, solid
                     waste is also generated during production and maintenance. Production and
                     maintenance wastes are usually transported offsite. Offshore, solids are often
                     treated and discharged in accordance with Clean Water Act regulations.

                     In the Gulf of Mexico, offshore oil field wastes that are not discharged or
                     disposed of onsite are brought onshore for disposal and taken to specifically.
                     designated commercial oil field waste disposal facilities. In Texas there are
                     ten existing commercial oil field waste disposal facilities that receive all of
                     the types of wastes that would come from the OCS operations (4 stationary
                     treatment, 5 landfarms, and 1 commercial pit); in Louisiana there are seven
                     facilities  (5 land treatment,'!  incinerator, and 1 chemical stabilization
                     facility); and in Alabama there are two landfarm/landtreatment facilities.
                     Included in these numbers are one site in Texas  and two sites in Louisiana
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Oil and Gas Extraction
                Industrial Process Description
                     that process naturally occurring radioactive material (NORM)-contaminated
                     oil field wastes (MMS, 1998).

                     Reserve Pit
                     During drilling on land, a pit is usually constructed onsite to hold drill
                     cuttings and extra drilling fluid.  Depending on geology and hydrogeology,
                     states might require reserve pits to be lined with geosynthetic or synthetic
                     liners.  Often the pit is intended only as a temporary holding vessel for
                     drilling waste before being moved offsite for treatment and disposal;
                     however, at some sites the reserve pit is used as the final disposal site. When
                     used as a disposal method after drilling is completed, the liquid is removed
                     (by suction or by evaporation if in  a dry climate) and the solid remnants
                     covered over with dirt.  The liquids account for 62 percent of drilling waste
                     by volume.  Over two-thirds of the remaining drilling  waste solids are
                     disposed  of by burying them onsite in the reserve pit (API, 1997).

                     Solidification
                     This is a modification of the reserve pit disposal method.  When drilling is
                     completed, a mixture of cement,  flyash (from coal-fired utility boilers),
                     and/or lime or cement kiln dust is added to the contents of the pit. The liquid
                     in the pit does not necessarily need to be removed. The contents of the pit
                     solidify into a concrete-like  block,  which immobilizes  the heavy metal
                     components. The process adds significantly to the bulk of the waste, but it
                     prevents the mobilization of potential pollutants. In API's  1995 survey, less
                     than 1 percent of drilling waste volumes were disposed of in this manner
                     (API, 1997).

                     Landfarming or Landspreading
                     In,this procedure, solids from the reserve pit (and potentially other solids
                     from production) are broken up and thinly applied to soil,  and tilled to mix
                     the waste and soil. In theory, Volatile components evaporate off, metal ions
                     bind to the clay, and heavy organic components are broken down by
                     biological activity.  State agencies  do not use consistent terminology in
                     referring  to this process: some call it landfarming, others landspreading, and
                     others use different terms. The disposal of solid wastes by spreading them
                     on the land surface can occur either as a one-time application or in multiple
                     applications. One-time application is most likely to be near the well site, and
                     would most likely involve application  of material from the reserve pit.
                     Multiple  applications  of waste are often  approved  for centralized or
                     commercial operations. In these cases, monitoring of soil constituents (e.g.,
                     pH, chlorides, and total hydrocarbons) is required by state agencies and once
                     certain levels are reached, no more wastes may be applied on that site. In
                     either one-time or multiple application operations, fertilizer may be added to
                     enhance biodegradation of hydrocarbons. Land farming operations must be
                     controlled to ensure that the hydrocarbons, salts and metals do not present a
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Oil and Gas Extraction
                Industrial Process Description
                    threat to  groundwater  or surface water,  and that the  hydrocarbon
                    concentration does not inhibit biological activity. Approximately 10 percent
                    of drilling waste solids are disposed of in landfarming operations (API, 1997;
                    Smith, 1999).

                    Commercial Disposal
                    Offsite disposal of drilling wastes by commercial enterprises accounts for
                    around 15  percent of drilling waste solids (API, 1997).  This commercial
                    disposal takes two formats. In major oil and gas producing areas of the
                    country, dedicated facilities for managing exploration and production wastes
                    exist.  These facilities manage drilling waste and some associated waste
                    streams using a range of processes from landfarming to slurry injection of
                    solids to disposal in salt caverns. Drilling wastes from offshore that cannot
                    be discharged (e.g., from oil-based muds) typically are barged to shore and
                    disposed of in these commercial facilities. In areas of the country with less
                    oil and gas activity, municipal or commercial landfills may accept drilling
                    waste and certain other waste streams.

                    Reuse/Recycling
                    A growing share  of drilling wastes .are reused or recycled.  It is currently
                    estimated that around 10 percent of total drilling waste volume (solids and
                    liquids) are reused or recycled.  The liquids (mud) are reconditioned, with
                    solids and other impurities removed, then used in the drilling of other wells.
                    Because of the high cost of the base material,  reuse of oil-based and
                    synthetic-based muds is more common. Drilling waste is also used as landfill
                    cover,  roadbed  construction,   dike  stabilization,  and  plugging  and
                    abandonment of other wells.

       Associated Waste Disposal

                    Because associated wastes encompass such a diverse set of waste streams,
                    generalizing about disposal options is difficult. What is appropriate for one
                    stream may not  be  appropriate for another.  Associated waste may be
                    disposed of onsite or offsite.  Some waste streams (e.g., waste solvents,
                    unused acids, and painting wastes) are not unique to oil and gas exploration
                    and production. These waste streams must be segregated from other wastes
                    and managed the same as they would be at other industrial facilities. If these
                    wastes exhibit hazardous characteristics they must be disposed of as RCRA
                    hazardous  wastes.  (See Section VLB. for more information on whether
                    specific waste streams are exempt or non-exempt from RCRA hazardous
                    waste requirements).  Table 4  summarizes the general  management  of
                    associated  wastes across all waste streams.
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Oil and Gas Extraction
             Chemical Releases and Transfers
Table 4: Management of Associated Wastes in 1995
Management Technique
Underground Injection
Commercial Facility
Evaporation
Recycling/Beneficial Use
Municipal or Commercial Facility
Landspreading
Roadspreading
Crude Oil Reclaimer
Incineration
Other (including hazardous waste disposal)
Percent
58%
9%
8%
8%
4%
4%
3%
2%
2%
3%
                     Source: API, 1997. Data are based on a survey that may not fully represent a few lower
                     producing areas of the country.
       Gases
                    Although most gas emissions are minimized through prevention, flaring can
                    be used to reduce the impact of gaseous releases that are unavoidable or are
                    too  small to warrant the cost of capture.  Nearly  all drilling rigs and
                    production wells are equipped with a vent and flare to release unusual
                    pressure, and some wells that produce only a small amount of natural gas will
                    flare it when there is no on-site use for the gas (e.g., to power engines) and
                    no pipeline nearby to transport the gas to market.  Since natural gas has
                    economic value, flaring it is usually a last resort. Approval of state regulatory
                    agencies is required prior to flaring.

                    When a  gas is flared, it passes through the vent away from the well, and is
                    burned in the presence of a pilot light. Although it is preferable to prevent
                    the emission in the first place, flaring has benefits over simple venting of
                    unburned material. First, by burning the gas, the health and safety risks in the
                    vicinity of the well posed by combustible and poisonous gases like methane
                    and hydrogen sulfide are reduced.  Second, flaring reduces the potential
                    contribution to climate change; methane is a much more potent greenhouse
                    gas than carbon dioxide, the primary product of the combustion.
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Oil and Gas Extraction
             Chemical Releases and Transfers
V. WASTE RELEASE PROFILE
                    This section provides estimates and reported quantities of wastes released
                    from oil and gas extraction industries. Unlike facilities covered by SIC codes
                    20-39 (manufacturing facilities), oil and gas extraction  facilities are not
                    required by the Emergency Planning and Community Right-to-Know Act to
                    report to the Toxic Release Inventory (TRI).  Because TRI reporting is not
                    required for the oil and gas extraction industry, other sources of waste release
                    data have been identified for this profile. EPA is considering expanding TRI
                    reporting requirements in the future which- may affect industries that are
                    currently not required to report to TRI, such as oil and gas extraction.

                    Much of the published data on wastes generated at oil and gas extraction
                    facilities is specific to the various oil producing regions of the United States,
                    including onshore arid offshore sites.  In 1996, EPA developed effluent
                    limitation  guidelines for the  Coastal  Subcategory of the Oil and  Gas
                    Extraction Point Source Category. Much of the information presented below
                    was collected as supporting  technical information for the guidelines.
                    Additional data reflecting the releases of onshore wells were provided by the
                    Pennsylvania Department of Environmental Protection.
IV.A. Available Data on Produced Water
                    Produced water is the largest volume waste generated in oil  and gas
                    extraction operations.  In 1985, the American Petroleum Institute (API)
                    estimated that 20.8 billion barrels of produced water were generated per year
                    by the U.S.  onshore oil and gas production industry (Souders, 1998). API
                    conducted an updated survey of the industry in 1995.  Based on preliminary
                    results, API estimates  current produced water volumes at over 15 billion
                    barrels annually (API, 1997).  The decline can be attributed primarily to a 32
                    percent decrease in oil production over the decade.  While natural gas
                    production has risen, natural gas wells produce much less water than do oil
                    wells.

                    The concentration of C9ntaminants in produced water varies from region to
                    region and depends on the depth of the production zone and the age of the
                    well, among other factors. Since most contaminants found in produced water
                    are naturally occurring,  they will vary based on what is present in the
                    subsurface at a particular location.  Three tables are presented below that
                    indicate both the relative concentrations of pollutants and the variation that
                    can occur among  samples from different locations  and product streams.
                    Table 5 presents the results of analyses performed on produced water from
                    -XX- Venango County, Pennsylvania. Table 7 presents data from natural gas
                    wells in the Devonian formation of Pennsylvania.
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Oil and Gas Extraction
            Chemical Releases and Transfers
Table 5: Produced Water Effluent Concentrations - Gulf of Mexico
("Coastal Waters')
Pollutant
Oil and Grease
Total Suspended Solids (TSS)
Settling Effluent
Improved Gas Flotation Effluent
Concentrations (Micrograms/L)
26,600
141,000
23,500
30,000
Priority Organic Pollutants
2,4-Dimethylphenol
Benzene
Ethylbenzene
Naphthalene
Phenol
Toluene
148
5,200
110
184
723
4,310
148
1,226
62.18
92.02
536
827.80
Priority Metal Pollutants
Cadmium
Chromium
Copper
Lead
Nickel
Silver
Zinc
31.50
180.00
236.00
726.00
151.00
359.00
462.00
14.47
180.00
236.00
124.86
151.00
359.00
133.85
Other Non-Conventional Pollutants
Aluminum
Ammonia
Barium
Benzoic acid
Boron
Calcium
Chlorides
Cobalt
Hexanoic acid
2-Hexanone
Iron
Magnesium
Manganese
2-Methylnapthalene
Molybdenum
n-Decane
n-Dodecane
n-Eicosane
n-Hexadecane
n-Octadecane
n-Tetradecane
o-Cresol
p-Cresol
Strontium
Sulfur
Tin
Titanium
m-Xylene
o +• p-Xylene
Vanadium
Yttrium
Lead 210
Radium 226
Radium 228
1,410
41,900
52,800
5,360
22,800
2,490,000
57,400,000
117
1,110
34.50
17,000
601,000
1,680
78
121
152
288
78.80
316
78.80
119
152
164
287,000
12,200
430
43.80
147
110
135
35.30
5.49e-07
1.91e-04
9.77e-07
49.93
41,900
35,561
5,360
16,473
2,490,000
57,400,000
117
1,110
34.50
3,146
601,000
74.16
77.70
121
152
288
78.80
316
78.80
119
152
164
287,000
12,200
430
4.48
147
110
135
35.30
5.49e-07
1.91e-04
9.77e-07
Source: EPA Office of Water, Development Document for Final Effluent Limitations Guidelines and Standards for the
Coastal Subcateenrv of the Oil and Gas Extraction Point Source Catesrorv October 1 996. Table VIII-7.
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Oil and Gas Extraction
            Chemical Releases and Transfers
Table 6: Oil Well Brine (Produced Water) from Primary Recovery
Operations - Venango County, Pennsylvania
Parameter
PH
Osmotic pressure
(milliosmoles)
Specific conductance
(umhos/cm)
Sulfates (mg/L)
Surfactants (mg/L)
Total Alkalinity
(mg/L)
Total dissolved solids
(mg/L)
Total suspended solids
(mg/L)
Oil & grease (mg/L)
Ammonia (mg/L)
Hardness (mg/L)
Calcium (mg/L)
Bromide (mg/L)
Chlorides (mg/L)
Magnesium (mg/L)
Sodium (mg/L)
Aluminum (ug/L)
Arsenic (ug/L)
Barium (mg/L)
Beryllium (ug/L)
Cadmium (ug/L)
Copper (ug/L)
Iron (mg/L)
Lead (ug/L)
Manganese (ug/L)
Nickel (ug/L)
Silver (ug/L)
Zinc (ug/L)
Lithium (ug/L)
Phenols (|ig/L)
Benzene (ug/L)
Toluene (|ig/L)
Ethylbenzene (ug/L)
Xylene (ug/L)
Number of
Samnles
28
18
28
13
22
19
27
19
16
17
27
26
17
29
28
27
15
15
29
11
5
16
27
4
27
9
8
11
22
16
12
10
7
11
Average
6.4
1,445
73,426
96
1.1
104
58,839
130
'18.6
9.3
13,075
3,602
283
33,356
670
13,417
730
273
55.7
11.4
36
78
34
288
1,294
150
2,676
93
1,418
454
1,907
1,885
107
1,057
Minimum
5.2
340
14,980
1
0.1
5.8
14,210
20
2.74
2.22
2,199
10.8
57
6,350
87
6
156
24
0.04
0.2
0.3
15
3.97
13.9
175
26
0.59
14
273
28
79
540
55
200
Maximum
7.4
2,740
128,900
584
2.5
251
135,506
614
78
17
30,720
6,750
538
63,700
1820
26,700
1730
992
670
95
150
264
140
910
7,500
790
21,100
310
3,660
875
3,236
3,214
174
2,117
No. Samples <
reoortine limit

2>2,000

10
2



3







1
9

11
19
9

19

16
12
5
1



2

Source: Pennsvlvania DEP. Draft Oil Brine Characteristics Revort. 1999.
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Table 7: Gas Well Brine (Produced Water) Characteristics - Devonian
Formation of Pennsylvania
Parameter
pH
Specific Conductance (umhos/cm)
Range
3.1-6.47
136,000 - 586,000
Number of Samples
16
12
Pollutants (mg/L)
Alkalinity
Bromide
Chloride
Sulfate
Surfactants
Total dissolved solids
Total suspended solids
Aluminum
Arsenic
Barium
Cadmium
Calcium
Copper
Iron
Lead
Lithium
Magnesium
Manganese
Nickel
Potassium
Silver
Sodium
Zinc
0-285
150-1149
81,500 - 167,448
<1.0-47
0.08 - 1200
139,000 - 360,000
8 - 5484
<0.50 - 83
O.005-1.S1
9.65 - 1740
<0.02-1.21
9400 - 51,300
<0.02 - 5.0
39.0-680
<0.20 - 10.2
18.6-235
1300 - 3900
3.59-65
<0.08 - 9.2
149-3870
0.047 - 7.0
37,500 - 120,000
<0.02 - 5.0
13
5
22
13
13
15
5
19
5
28
19
19
14
21
18
18
18
21
18
16
4
21
20
Source' Pennsvlvania DEP 1999
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             Chemical Releases and Transfers
IV.B. Available Data on Drilling Waste for the Oil and Gas Extraction Industry

                    According to API, 361 million barrels of drilling waste were produced in
                     1985.  Due to a reduction in the number of wells drilled, for  1995 API
                    preliminary findings indicate an estimated 146 million barrels of drilling
                    waste (API, 1997).  Drilling fluids (muds and rock cuttings) are the largest
                    sources of drilling wastes. For offshore Gulf of Mexico, EPA estimates from
                     1993 assumed that 7,861  barrels of drilling fluids and 2,681 barrels  of
                    cuttings are discharged overboard per exploratory well, and 5,808 barrels of
                    drilling fluids and 1,628 barrels of cuttings are discharged per development
                    well (USEPA, 1993b).  The different volumes are based on the average
                    depths for the two types of wells. These volumes exclude the volumes of any
                    drilling wastes not discharged offshore but transported to shore for disposal.
                    Historically, on average, about 12 percent of the mud and 2 percent of the
                    cuttings fail permit limits (USEPA, 1993b.) and thus cannot be discharged.
                    Table 8 below summarizes some of the characteristics of drilling waste  in
                    Cook Inlet, Alaska as reported in the Development Document for Final
                    Effluent Limitations Guidelines and Standards for the Coastal Subcategory
                    of the Oil and Gas Extraction Point Source Category. Table 9 presents the
                    characteristics of drilling fluids used in the  drilling of gas  wells into the
                    Devonian formation of Pennsylvania.
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Oil and Gas Extraction
            Chemical Releases and Transfers
Table 8: Cook Inlet Drilling Waste Characteristics
Waste Characteristics
Percent of cuttings in waste drilling fluid
Average density of dry cuttings
Average density of waste drilling fluid
Percent of dry solids in waste drilling fluid, by volume
Average density of dry solids in waste drilling fluids
Value
19%
980 pounds per barrel
420 pounds per barrel
11%
1 ,025 pounds per barrel
Drilling Fluid Pollutant Concentration Data
Conventionals
Total Oil
Total Suspended Solids (TSS)
mg/kg drilling fluid
142
269,042
Priority Metals
Cadmium
Mercury
Antimony
Arsenic
Beryllium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
1.1
0.1
5.7
7.1
0.7
240
18.7
35.1
13.5
1.1
0.7
1.2
200.5
Priority Organics
Naphthalene
Fluorene
Phenanthrene
0.008
0.134
0.020
Non-Conventional Metals
Aluminum
Barium
Iron
Tin
Titanium
9,069.9
120,000
15,344.3
14.6
87.5
Non-Conventional Organics
Alkylated benzenes (a)
Alkylated naphthalenes (b)
Alkylated fluorenes (b)
Alkylated phenanthrenes (b)
Total byphenyls (b)
Total dibenzothiophenes
5.004
0.082
0:290
0.034
0.324
0.001
Source: EPA Office of Water, 1996, Table VIM.
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            Chemical Releases and Transfers
Table 9: Drilling Fluids Characteristics - Devonian Gas Wells
Parameter
pH
Osmotic pressure (mosm)
Specific Conductance
(umhos/cm)
Average
9.57
76
4,788
Range
3.1 - 12.2
4.3 - 629
383-38,600
# Samples
Above
Detection
Limits
61
32
62
ft Samples
Below
Detection
Limits



Pollutants (mg/L)
Oil & grease
Alkalinity
Bromide
Chloride
Phenols
Sulfate
Surfactants
Total dissolved solids
Total suspended solids
Aluminum
Arsenic
Barium
Calcium
Copper
Iron
Lead
Lithium
Magnesium
Manganese
Nickel
Silver
Sodium
Zinc
11.9
276
10.2
1,547
0.288
144
25
3,399
87
4.601
0.032
2.5
290
0.049
145
0.785
0.46
59
2.284
0.945
0.035
111
0.502
2.3-38.8
18-1,594
2-56.1
12 - 14,700
0.025-0.137
6-785
1.5-200
386-24,882
2-395
0.170-16.9
0.00082-0.117
0.078 - 37.7
8.7 - 1,900
0.012 - 0.268
0.08 - 3,970
0.07-3.46
0.037-2.04
0.12-1,700
0.01-46.6
0.025-2.4
0.035
53.7 - 5,800
0.014-1.55
20
60
30
62
19
46
23
61
34
17
21
37
60
12
41
5
8
61
40
7
1
59
14
2
0
4
0
3
0
13
0
0
16
13
13
0
22
4
29
12
1
20
27
7
0
20
Source: Pennsvlvania DEP. 1999.
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Oil and Gas Extraction
             Chemical Releases and Transfers
IV.C. Available Data on Miscellaneous and Minor Wastes (Associated Wastes)

                    Associated wastes are a relatively small but significant category of waste
                    from the oil and gas extraction industry.  The term "associated wastes"
                    encompasses a wide range of small volume waste streams essential to oil and
                    gas extraction.  Because of their nature, these waste streams are the most
                    likely to contain constituents of concern.  Preliminary data from a 1995
                    survey estimate that  22 million barrels of associated wastes are generated
                    annually (API, 1997). Four particular associated waste streams are discussed
                    below.

       IV.C.l. Workover, Treatment, and  Completion Fluids

                    Well maintenance, including workover, treatment, and completion, requires
                    the use of fluids similar to drilling fluid and is the largest miscellaneous
                    source of waste. These fluids may contain a range of chemicals (depending
                    on the maintenance activity undertaken) and naturally occurring materials
                    (i.e., trace metals). Because of the presence of these constituents, the wastes
                    require proper  disposal.  Onshore, most of these wastes are disposed of
                    through Class II injection wells.  Offshore, they may be discharged if they
                    meet the standards in applicable NPDES permits. Otherwise, they are barged
                    to shore and typically disposed of in an injection well. Table 10 presents the
                    relative amounts  of liquid and solid wastes from  well maintenance
                    operations. Table 11 contains the range and average pollutant concentrations
                    from workover, treatment and completion fluid samples collected from wells
                    in Texas, New Mexico, and Oklahoma.
Table 10: Typical Volumes from Well Treatment, Workover, and
Completion Operations
Operation
Completion and Workover
Well Treatment
Type of Material
Completion/Workover
Fluids
Formation Sand
Filtration Solids-
Excess Cement
Casing Fragments
Neutralized Spent Acids
Completion/Workover
Fluids
Estimated Waste
Volume (barrels)
200 to 1000
Ito50
10 to 50
<10
<1
10 to 500
10 to 200
Source: EPA Office of Water, 1996, Table IX-2.
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            Chemical Releases and Transfers
Table 11: Pollutant Concentrations in Treatment, Workover, and
Completion Fluids
Pollutant Parameter
Pollutant Concentration (Micrograms/L)
Ranee
Average
Convcntionals
Oil and Grease
Total Suspended Solids
15,000-722,000
65,500-1,620,000
231,688
520,375
Priority Pollutant Organics
Benzene
Ethylbenzene
Methyl Chloride (Chloromethane)
Toluene
Fluorene
Naphthalene
Phenanthrene
Phenol
477 - 2,204
154-2,144
0-57
298 - 1,484
0-123
0- 1,050
0-128
255-271
1,341
1,149
29
891
62
525
64
263
Priority Pollutant Metals
Antimony
Arsenic
Beryllium
Cadmium
Chromium
Copper
Lead
Nickel
Selenium
Silver
Thallium
Zinc
0-148
0-693
0-25.1
7.6 - 82.3
48 - 1,320
0-1,780
0 - 6,880
0-467
0-139
0-8
0 - 67.3
0-1330
29.60
166
8.64
26.08
616.82
277.20
1,376
115.52
42.94
1.60
13.46
362.94
Other Non-Conventionals
Aluminum
Barium
Boron
Calcium
Cobalt
Cyanide
Iron
Manganese
Magnesium
Molybdenum
Sodium
Strontium
Sulfur
Tin
Titanium
Vanadium
Yttrium
Acetone
Methyl Ethyl Ketone (2-Butanone)
m-Xylene
o+p-Xylene
4-Methyl-2-Pentanone
Dibenzofuran
Dibenzothiophene
n-Decane
n-Docosane
n-Dodecane
n-Eicosane
n-Hexacosane
n-Hexadecane
n-Tetradecane
p-Cymene
Pentamethylbenzene
1-Methylfluorene
2-Methylnaphthalene
0-13,100
66.5 - 3,360
4,840 - 45,200
1,070,000-28,000,000
0 - 40.9
0-52
7,190-906,000
187- 18,800
10,400-13,500,000
0-167
7,170,000-45,200,000
21,100-343,000
72,600 - 646,000
0-135
0-283
0 - 4,850
0-131
908 - 13,508
0-115
335 - 3,235
161 -1,619
198 - 5,862
136-138
0-222
0-550
237 - 1,304
0-1,152
0-451
173-789
0-808
513 - 1,961
0-144
0- 108
0-163
0-1,634
6,468.40
498.10
15,042
10,284,000
8.18
52
384,412
5,146
5,052,280
63
18,886,000
142,720
245,300
27
. 74.58
1,156
41.92
7,205
58
1,785
890
3,028
137
111
275
771
576
226
481
404
1,237
72
54
82
817
Source: EPA Office of Water, 1996, Table IX-7.
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             Chemical Releases and Transfers
       IV.C.2. Minor Wastes
                    Smaller waste streams of concern for the oil and gas extraction industry that
                    are discussed below are drainage from drilling and production sites, solids
                    brought to the surface with oil and gas (produced sand, also referred to as
                    tank bottoms), and domestic and sanitary wastes at coastal and offshore sites.
       Deck Drainage
                    Drainage from the production site, or deck drainage, is a concern particularly
                    in areas with high precipitation. When water from rainfall or from equipment
                    cleaning comes in contact with oil-coated surfaces, the water becomes
                    contaminated and must be treated and disposed of. The fluids can contain oil
                    from leaking equipment, wastes from cleaning  operations, and spilled
                    chemicals  from treatment processes.   Some locations will collect deck
                    drainage, treat it separately in a skim tank, and discharge it, while others
                    might combine the water with produced water and dispose of the fluids
                    together.  In the coastal areas of the Gulf of Mexico, the average facility
                    generates approximately 12,000 barrels of deck drainage each year, but this
                    figure would be significantly lower for facilities hi drier climates (EPA,
                    1996).
       Produced Sand
                    Produced sand consists  of the accumulated formation sands and other
                    particles generated during production as well as the slurried particles used in
                    hydraulic fracturing. The waste stream also includes sludges produced from
                    chemical flocculation procedures during produced water treatment. Produced
                    sand typically  contains crude oil.  The amount  will vary based  on the
                    handling and separation processes used, but can comprise as much as 19
                    percent by volume (EPA, 1996). Table 12 presents an analysis of samples of
                    basic sediment taken from pits containing produced water in Pennsylvania.
                    Like for produced water, it should be noted that concentrations will vary for
                    different locations, particularly  with  respect  to  Naturally Occurring
                    Radioactive Material (NORM).
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Oil and Gas Extraction
             Chemical Releases and Transfers
Table 12: Pollutant Concentrations in Produced Water Pit
Sediments in Pennsylvania
Material
Oil and Grease (mg/kg)
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Benzene
Toluene
Ethylbenzene
Naphthalene
Xylene
Range (mg/L)
640 - 540,000
<0.0 1-0.031
0.07- 19.1
<0.05
<0.05
<0. 1-0.27
<0.001
<0.01- 0.016
<0.05
0.0006 - .25
0.001-0.27
0.0013 - 0.049
0.001 - 0.076
.0011-1.78
Average
fme/L>
68,056

1.8











# Samples Above
DetectionJLimits
49
19
51
0
0
4
0
8
0
25
25
17
5
34
# Samples Below
Detection Limits
0
32
0
51
51
47
51
43
51
21
21
29
41
12
Naturally-Occurring Radioactive Materials
Natural Uranium (ug/kg)
n6Radium (pCi/kg)
228Radium (pCi/kg)
"Manganese (pCi/kg)
51ron (pCi/kg)
58Cobalt+»Cobalt (pCi/kg) •
"Zinc (pCi/kg)
"Zirconium (pCi/kg)
"Niobium (pCi/kg)
"'Iodine (pCi/kg)
'"Cesium (pCi/kg)
140Barium (pCi/kg)
""Lanthanum (pCi/kg)
Thorium (total) (pCi/kg)
873.87-2,945.97
6.57 - 1,344.88
13.8-1639.11
0
0
0
0
0
0
0
0-46
0
0
860 - 4,868
1,658.86
593.8196
770.3883







17.15789


2,908.826
9
23
23
0
0
0
0
0
0
0
19
0
0
23
0
0
0
23
23
23
23
23
23
23
4
23
23
0
Source: PA DEP. Characterization and Disposal Ootions for Oilfield Wastes in Pennsvlvania. 1994.
       Domestic and Sanitary Wastes
                    Domestic and  sanitary wastes are issues at coastal and offshore  sites.
                    Domestic wastes  are water  from sinks,  showers, laundry, and  food
                    preparation areas. Domestic waste also includes solid materials such as paper
                    and cardboard which must be disposed of properly. Because domestic waste
                    does  not contain  fecal coliform bacteria,  most NPDES permits allow
                    untreated discharge so long as floating solids are not produced.  Sanitary
                    wastes are generated from toilets, and must be either treated or stored for
                    disposal on land.  Most offshore facilities  treat  the  wastes through a
                    combination of chlorination and biological digesters or physical maceration,
                    and discharge the waste at the site.  Offshore facilities discharge an average
                    of approximately 2,050 barrels of domestic/sanitary waste per facility per
                    year (EPA, 1996).
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Oil and Gas Extraction
             Chemical Releases and Transfers
IV.D. Other Data Sources
                    The Aerometric Retrieval System (AIRS) is an air pollution data delivery
                    system managed by the Technical Support Division in EPA's Office of Air
                    Quality Planning and Standards (OAQPS), located in Research Triangle Park,
                    North Carolina.  The AIRS is a national repository of data related to air
                    pollution monitoring and control.  The AIRS contains a wide range of
                    information related to stationary sources  of air pollution, including the
                    emissions of a number of air pollutants which may be of concern within a
                    particular industry.  Table 13 summarizes annual releases (from the industries
                    for which Sector Notebook Profiles have been prepared) of carbon monoxide
                    (CO), nitrogen dioxide (NO2), particulate  matter of 10 microns  or  less
                    (PM10), particulate matter, all sizes reported in lieu of PM10 (PT), sulfur
                    dioxide (SO2), and volatile organic compounds (VOCs).
Table 13: Air Pollutant Releases by Industry Sector (tons/year)
Industry Sector
Metal Mining
Oil and Gas Extraction
Non-Fuel, Non-Metal Mining
Textiles
Lumber and Wood Products
Wood Furniture and Fixtures
Pulp and Paper
Printing
Inorganic Chemicals
Plastic Resins and Man-made Fibers
Pharmaceuticals
Organic Chemicals
Agricultural Chemicals
Petroleum Refining
Rubber and Plastic
Stone, Clay, Glass and Concrete
Iron and Steel
Metal Castings
Nonferrous Metals
Fabricated Metal Products
Electronics and Computers
Motor Vehicle Assembly
Aerospace
Shipbuilding and Repair
Ground Transportation
Water Transportation
Air Transportation
Fossil Fuel Electric Power
Dry Cleaning
CO
4,951
132,747
31,008
8,164
139,175
3,659
584,817
8,847
242,834
15,022
6,389
112,999
12,906
299,546
2,463
92,463
982,410
115,269
311,733
7,135
27,702
19,700
4,261
109
153,631
179
1,244
399,585
145
N02
49,252
389,686
21,660
33,053
45,533
3,267
365,901
3,629
93,763
36,424
17,091
177,094
38,102
334,795
10,977
335,290
158,020
10,435
31,121
11,729
7,223
31,127
5,705
866
594,672
476
960
5,661,468
781
PM10
21,732
4,576
44,305
1,819
30,818
2,950
37,869
539
6,984
2,027
1,623
13,245
4,733
25,271
3,391
58,398
36,973
14,667
12,545
2,811
1,230
3,900
890
762
2,338
676
133
221,787
10
PT
9,478
3,441
16,433
38,505
18,461
3,042
535,712
1,772
150,971
65,875
24,506
129,144
14,426
592,117
24,366
290,017
241,436
4,881
303,599
17,535
8,568
29,766
757
2,862
9,555
712
147
13,477,367
725
SOZ
1,202
238,872
9,183
26,326
95,228
84,036
177,937
88,788
52,973
71,416
31,645
162,488
62,848
292,167
110,739
21,092
67,682
17,301
7,882
108,228
46,444
125,755
3,705
4,345
101,775
3,514
1,815
42,726
7,920
voc
119,761
114,601
138,684
7,113
74,028
5,895
107,676
1,291
34,885
7,580
4,733
17,765
8,312
36,421
6,302
198,404
85,608
21,554
23,811
5,043
3,464
6,212
10,804
707
5,542
3,775
144
719,644
40
Source- EPA Office of Air and Radiation ATRS Database 1997
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            Chemical Releases and Transfers
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Oil and Gas Extraction
                         Pollution Prevention
POLLUTION PREVENTION OPPORTUNITIES
                    The best way to reduce pollution is to prevent it in the first place.  Some
                    companies have creatively implemented pollution prevention techniques that
                    improve efficiency and increase profits while at the same time minimizing
                    environmental impacts. This can be done in many ways such as reducing
                    material inputs, re-engineering processes to reuse by-products, improving
                    management practices, and employing substitution of toxic chemicals.  Some
                    smaller facilities are able to actually get below regulatory thresholds just by
                    reducing pollutant releases through aggressive pollution prevention policies.

                    The Pollution Prevention Act of 1990 established  a national policy  of
                    managing waste through source reduction, which means preventing the
                    generation of waste.  The Pollution Prevention Act also  established  as
                    national policy a hierarchy of waste management options for situations in
                    which source reduction cannot be  implemented feasiblely.  In the  waste
                    management hierarchy, if source reduction is not feasible, the next alternative
                    is recycling of wastes, followed by energy recovery, with waste treatment as
                    a last alternative.

                    In order to encourage these approaches, this section provides both general and
                    company-specific descriptions of some pollution prevention advances that
                    have been implemented within the oil and gas extraction industry. While the
                    list is not exhaustive, it does provide core information that can be used as the
                    starting point for facilities interested in beginning their own pollution
                    prevention projects.   This section provides summary information from
                    activities that may be, or are being implemented by  this  sector.  When
                    possible, information is  provided that gives  the context in which the
                    technique can be used effectively. Please note that the activities described in
                    this section do not necessarily apply to all facilities that fall within this sector.
                    Facility-specific  conditions must be carefully considered when pollution
                    prevention options are evaluated, and the full impacts of the change must
                    examine how each option affects air, land and water pollutant releases.
       Waste Management Plans
                    Pollution  prevention  opportunities  are most  effective when they  are
                    coordinated in  a facility-wide waste management plan.  The American
                    Petroleum Institute (API) has published guidelines for waste management
                    plans, in which pollution prevention is an integral part (API, 1991). The ten-
                    step plan involves the following:

                    1. Company management approval: Management should establish goals for
                    the waste management plan, identify key personnel and resources that are
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Oil and Gas Extraction
                        Pollution Prevention
                    committed to the plan, and develop a mission statement for its environmental
                    policies.

                    2. Area Definition: The waste management plan should be designed for a
                    specific area to account for differing regulations and conditions; in most
                    cases, the area would be limited to within one state.

                    3. Regulatory  Analysis: Federal, state and local laws, and landowner and
                    lease agreements, should be evaluated. Based on these evaluations, operating
                    conditions and requirements should be defined.

                    4. Waste Identification: The source, nature, and quantity of generated wastes
                    within the plan's area should be identified, and a brief description of each
                    type of waste should be written.

                    5. Waste Classification: Each waste stream should be classified according to
                    its regulatory status, including whether it is a hazardous waste subject to
                    regulation under the Resource Conservation and Recovery Act (RCRA).

                    6. List and Evaluate Waste Management and Disposal Options: List all waste
                    management practices and determine the environmental acceptability of each
                    option. Consider regulatory restrictions, engineering limitations, economics,
                    and intangible benefits when determining their feasibility.

                    7.   Waste  Minimization:  Analyze  each waste-generating process  for
                    opportunities to reduce the volume generated or ways to  reuse or recycle
                    wastes.   Note  that  the waste  minimization or pollution prevention
                    opportunities that are presented in this section can be used for this step.

                    8.  Select Preferred Waste  Management Practices: Choose the preferred
                    management  practices  identified in Step  6  and  incorporate  waste
                    minimization options from Step 7 wherever feasible.  Specific instructions
                    for implementation should be developed.

                    9. Prepare and Implement an Area Waste Management Plan: Compile all
                    preferred waste  management and minimization practices  and write waste
                    management summaries for each waste. Implement the plan on a field level.

                     10. Review and Update Waste Management Plan:  Establish a procedure to
                    periodically review and revise the plan.
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Oil and Gas Extraction
                         Pollution Prevention
V.A.  Exploration
                     Several approaches or technologies can be used by exploration companies to
                     drill more efficiently and to maximize the recovery of oil and natural gas. Oil
                     and gas Exploration is not a waste-intensive activity per se, but efforts made
                     by those involved with exploration can assist in minimizing the number of
                     dry wells that are later drilled.
       Drill Site Selection
                    The volume of drilling waste is directly related to the number of wells drilled.
                    Thus, if fewer wells can be drilled to  efficiently produce a discovered
                    reservoir, and if the number of dry holes (wells  drilled that do not find
                    commercial quantities of oil or gas) can be minimized, then the total volume
                    of drilling wastes will be reduced.  Site selection is a key component of this
                    reduction.

                    Modeling Software
                    New computer software is available that converts seismic data into models
                    of subterranean  formations. Until 15 years ago,  modeling software was
                    limited to large mainframe computers and was inaccessible for small-scale
                    projects.  In recent years, software has been created for use on personal
                    computers that can incorporate the various components of remote sensing and
                    logging. Three-dimensional models can now be produced from data that
                    geophysicists previously would have had to analyze manually.
 The U.S. Department of Energy has created several significant computer programs for the oil and
 gas exploration industry. KINETICS models the chemical reactions that take place over millions
 of years that lead to the creation of oil and gas, and therefore assists in interpreting whether
 conditions at a site are favorable for oil.  Programs like BOAST and MASTER can be used in
 wells already in production to model flow patterns to determine the best approach for secondary
 or tertiary recovery efforts. It is estimated that computer programs such as these can result in an
 increase of three billion barrels of domestic  reserves, generate increased tax revenue for the
 government, and reduce the drilling of unnecessary or unproductive wells (U.S. Department of
 Energy, 1998).
                    Iodine Sensing
                    Empirical evidence indicates that unusual concentrations of iodine on the
                    earth's surface are nearly always associated with petroleum that seeps from
                    subsurface formations.  Although the process is still in the experimental
                    stage, surface geochemical analyses can be performed to test for the presence
                    of unusually high concentrations of iodine, which in turn indicates the
                    presence of oil or gas.  The iodine test can be used in conjunction with
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                        Pollution Prevention
                    traditional seismic processes to determine favorable drilling sites. Seismic
                    tests measure for geological formations that can potentially contain large
                    amounts of oil orgas7but can't directly detect these products. Conversely,
                    high iodine levels may indicate that petroleum is present, but not that the
                    geological structures are favorable for petroleum extraction.   These two
                    processes therefore can be used in conjunction with each other to better
                    determine the probability of being able to produce oil at a given site before
                    a well is drilled.

       Drill Site Construction

                    Storm Water Runoff Impact Reduction
                    Measures that can be taken to reduce the impacts associated with storm water
                    runoff can apply to all aspects of oil and gas exploration and production. The
                    following are a few examples of such measures.

                    •      Reduce exposure of materials . such as  drilling fluids and  other
                           chemicals stored on-site to rainfall and storm water runoff. This can
                           be accomplished by storing drums and other materials under cover
                           (such as in a trailer, in a shed or covering with tarps).
                    •      Utilize best management practices (BMPs) such as diversion dikes,
                           containment diking, and curbing to reduce exposure of storm water
                           runoff to cuttings and other waste storage areas.
                    •      Utilize BMPs such as sediment traps, swales, and mulching during
                           construction activities (such as during road building or construction
                           of buildings) to reduce loss of sediment and contamination of runoff.
                    •      Insure that adequate materials and equipment are available to contain
                           and control spills in order to prevent contamination of runoff. An
                           effort should be made here to go beyond any SPCC requirements and
                           be prepared to contain and control all spills (of any waste) on site.

                    Two references that may be useful for oil and gas exploration and production
                    operations to prevent contamination of storm water runoff are 1) Storm Water
                    Management  for Industrial Activities - Developing Pollution  Prevention
                    Plans and Best Management Practices (EPA 832-R-92-006) and  2) Storm
                    Water Management for Construction Activities - Developing Pollution
                    Prevention Plans and Best Management Practices (EPA 832-R-92-005).

       Downhole Analysis

                    Recently, several technologies have emerged that allow for more accurate
                    analysis of an oil or gas-bearing formation via equipment lowered into the
                    wellbore of producing wells.  These either can  lead to improvements  in
                    production of the well in question, or assist in determining the best location
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                         Pollution Prevention
                     for an additional well.  In either case, the technology helps to reduce the
                     number of wells drilled that do not produce.

                     Formation Analysis Through Old Well Casings
                     Some of the geophysical logging procedures and tools now hi use for new
                     wells were not available for wells drilled 30 years ago. Therefore, data for
                     the zones between the surface and the production zone of the well may be
                     incomplete.  Typically the metal casing limits analysis of the formations in
                     these sealed-off zones. New tools have been developed that allow surveying
                     through casing and that may lead to the discovery of production zones that
                     were missed during the original drilling. The procedure can extend the life
                     of old wells and reduce the need for drilling new ones.

                     Crosswell Seismic Imaging
                     Geological imaging techniques via the surface are limited by the thousands
                     of feet of rock between the equipment and the potential production zone. As
                     a result, the best resolution obtainable is approximately 50  feet.  -With
                     crosswell seismic imaging, sound wave generators and receivers are lowered
                     into several wellbores in a production field. Because the waves need to travel
                     a shorter distance between the generator  and receivers, the resolution can be
                     as accurate as five feet. This process can be useful in ensuring that additional
                     wells drilled in a producing field are placed accurately.

V.B. Well Development
       Drilling
                     Closed Loop Drilling Fluid System
                     When drilling a well that will be shallow and likely will not encounter
                     unusual zones of pressure, a closed system for drilling fluids can be used. At
                     a conventional drilling site, drilling fluid is circulated through the wellbore,
                     then deposited in a reserve pit dug next to the well.  This pit is open to the
                     atmosphere, and serves to store excess fluid and to separate out contaminants.
                     While the large storage capacity is important for wells that encounter high
                     pressure and therefore might experience fluctuations in the amount of fluid
                     needed, a reserve pit can be the source of considerable costs at a drilling  site.
                     The pit itself must be constructed at the beginning of drilling, and must be
                     closed properly when drilling is completed.   Also, because the pit may
                     release higher levels of VOCs and  can leak  liquids into surface or
                     ground water, there are increased health, environmental, and financial risks.

                     In a closed-loop drilling fluid system, the reserve pit is replaced with a series
                     of storage tanks. The tanks represent an additional cost, but because they
                     preclude the need for constructing a pit, reduce the amount of environmental
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                    releases, and result in more efficient use of drilling fluid, the technology can
                    save the operator money when conditions allow its use.
 A small independent operator in Texas was concerned that reserve pits for drilling fluid were
 increasing -waste management costs and exposing it to liability for surface and ground -water
 contamination. Because the -wells to be drilled -were relatively shallow and few complications
 were expected, the operator negotiated with the drilling contractors to use a closed-loop fluid
 system. The operator realized savings of about $10,000 per well because reserve pits were not
 constructed and  waste management costs were reduced.  The operator's liability was also
 reduced (Texas Railroad Commission,  1997).
                     Pit Design
                     If the closed-loop drilling system is not used for drilling fluids, another
                     approach may be to use a V-shaped pit instead of the traditional rectangular
                     pit. The open end of the "V" faces the drilling rig and the cross-sectional
                     view resembles a squared-off funnel (about 10 feet deep with the upper 5 feet
                     having slanted walls to a width of about 20  feet).  Because the fluid must
                     travel the full length of the pit, this design prevents mud from channeling
                     between the discharge point and the suction point, and reduces the amount of
                     water that needs to be added to maintain the desired fluid characteristics.  In
                     addition, because the V-shaped pit is long and narrow, it is easier to construct
                     and leaves a smaller "footprint" at the site.
  A company installed a V-shaped reserve pit and compared the costs with those incurred at
  similar-sized wells using a traditional pit. The company determined that pit construction time
  was reduced by about 40 percent, water costs for the well were reduced by about 38 percent, and
  pit liner costs were reduced by about 43 percent. The total cost savings were about $10,800 per
  well (Texas Railroad Commission, 1999).
                     Substitution of Drilling Fluid Additives
                     Some traditional drilling fluid additives are toxic and require extra care in
                     disposal. In response, the drilling fluid industry has developed replacements
                     for some of the more toxic compounds.  These include:

                     •      Replacement of chrome lignosulfonate dispersants with chrome-free
                            lignosulfonates and polysaccharide polymers.

                     •      Use of amines instead of pentachlorophenols and paraformaldehyde
                            as biocides.

                     •      Lubrication with mineral oil and lubra-beads instead of diesel oil.
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                     Substitutions such as those described above can minimize the toxicity of
                     drilling wastes and reduce the risks and costs associated with drilling fluid
                     disposal.

                     Material Balance and Mud System Monitoring
                     Monitoring devices used at various points in the drilling fluid circulation
                     system may be used to check for the decrease of fluid levels or other changes
                     in fluid characteristics. Such devices may reduce the need for the addition of
                     water and additives to the fluid, thereby reducing  the  costs and  waste
                     associated with drilling fluid.

                     Removal of Solids from Drilling Fluid
                     Careful removal of drill cuttings and other contaminating solids can reduce
                     the need to dilute or replace  drilling fluid.   Furthermore, if the separated
                     solids are treated thoroughly to remove moisture, the weight of waste can be
                     significantly reduced. In addition to using shale shakers, which are always
                     used to remove rocks and larger fragments, drilling rigs can reduce waste by
                     including several optional components in their mud treatment systems.
                     Desanders and desilters separate increasingly smaller particles. Centrifuges
                     remove the smallest suspended pieces. Finally, mud  cleaners break oil-water
                     emulsions and remove many dissolved components. If these devices are in
                     optimal working condition, the drilling mud can be nearly free of suspended
                     materials, and the solid waste can be less than 30 percent moisture by weight.

                     Polvcrvstalline Diamond Compact TPDQ Drill Bit
                     Pulling the drill string to replace the drill bit is one of the more inefficient and
                     potentially dangerous procedures in drilling.  Quite  a bit of time and energy
                     can be wasted in pulling the entire drill string to the surface and lowering it
                     back into the wellbore. In addition, it is when the drill string is being raised
                     and lowered that well blowouts are an increased risk if not properly done. It
                     is therefore desirable for both efficiency and blowout prevention to minimize
                     drill bit replacement.

                     PDC bits have been viable commercially for about a decade, and are the most
                     durable bits available.  The bit is primarily steel with interlocked diamond
                     studs. The bits typically last between 230 and 260  drilling hours, but have
                     lasted over 1,000 hours without  replacement. Because of their durability,
                     diamond bits account for one-third of the drill bit market, and can save
                     drilling companies  as much as $1 million per well  (U.S. Department of
                     Energy, 1998).

                     Downhole Drilling Telemetry
                     Traditionally,  drillers have determined the  position of the drill bit by
                     removing the  drill string from the well, lowering  an instrument into the
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                     wellbore, retrieving the instrument, then lowering the drill string back into
                     the wellbore. This process is inefficient and increases the risk of a blowout.

                     The Department of Energy has helped to develop a wireless system that sends
                     pulses through the drilling mud from the drill bit to the surface, in a process
                     called mudpulse telemetry. The technology presents several benefits for wells
                     in which its use is practical: data can be collected during drilling, the data are
                     more complete than those from periodic measurements because the pulsing
                     can occur continuously, and advance warnings can be received of impending
                     drill hazards.  Without considering the benefit of decreased environmental
                     and health risks, mudpulse technology saves the industry over $400 million
                     per year.

                     Horizontal Drilling
                     Oil and natural gas bearing formations typically have a small vertical profile
                     (i.e., are confined to a narrow range of depth), but are spread over a large
                     horizontal area.  As a result, wellbores that intersect  the oil-producing
                     formation at an angle can drain more of the formation and reduce the need to
                     drill additional wells compared to purely vertical wells.

                     Horizontal drilling is costly, because it requires advanced geological sensing
                     equipment and constant attention to the placement of the drill bit. However,
                     the increased cost is  often more than offset by increased production and the
                     reduced need for drilling multiple wells.
  In the Dundee Formation of Michigan, as much as 85 percent of the known oil remained in the
  formation after many years of production. Many wells were on the verge of being plugged, with
  production near five barrels  of oil per day per well. A DOE  co-sponsored project drilled a
  horizontal well in the formation, which produced 100 barrels per day, and had  estimated
  recoverable reserves of 200,000 barrels of oil. The program attracted other well developers, and
  20 to 30 additional horizontal wells are being drilled in the formation.  It is estimated that the
  application of horizontal drilling to this formation may yield an additional 80 to 100 million
  barrels of oil (Department of Energy, 1998).
                     Reuse of Drilling Fluids
                     Drilling fluid is often disposed of when a well is completed, and fresh fluid
                     used for any adjacent wells. Filtration processes have allowed drilling fluid
                     to be reconditioned, so that it can be used for multiple wells before being
                     discarded.   Other possible uses  for used drilling fluids are  to  plug
                     unproductive wells or to  spud in new  wells.  Reuse of oil-based and
                     synthetic-based drilling fluids to drill additional wells is common because of
                     the high cost of the base fluids.
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  One drilling company in Alaska sought to filter and recondition its drilling fluid in order to use
  it for several wells. The fluid was used on average over two times, resulting in a decrease of fluid
  used from 50,000 barrels of fluid to 22,000 barrels. Because the cost of filtering is only six
  percent of the cost of purchasing new fluid, the fluid treatment system reduced the fluid costs for
  this operator from $7 million to $3.25 million (SAIC, 1997).
                    Preventive Maintenance and Leak Containment
                    Engines, tanks, pumps and other equipment used in the drilling process may
                    leak lubricating oil or fuel. Soil contamination and waste generation may be
                    avoided and valuable chemicals may be recovered by performing regular
                    preventive maintenance and installing leak containment devices. Examples
                    of preventive maintenance include routine checks and replacement of leaking
                    valves, hoses, or connections, while containment measures may include the
                    installation of drip pans underneath engines, containers, valves, and other
                    potential sources of leaks.  These practices and devices are important
                    pollution prevention options at production and maintenance operations as
                    well as at drilling sites.

                    Inventory Control
                    Facilities may maintain an excess on-site volume of chemicals and materials.
                    This may lead to unnecessary regulatory compliance concerns, operating
                    costs, and waste generation. By tracking the inventory of chemicals and
                    materials, particularly with the use of computer programs, an operator may
                    use materials more efficiently and reduce waste generation.  In addition, an
                    operator may negotiate with vendors to  accept empty and partially-filled
                    containers for reclamation and reuse, because commercial chemical products
                    that are returned to a vendor or manufacturer may not be considered solid
                    wastes.
 An operation encompassing drilling, gas production, and compression activities determined that
 its on-site supply of chemicals was excessive and that much of its hazardous waste generation
 was  unnecessary.  The company made  several changes:  it identified alternative, less toxic
 chemicals; eliminated the use of organic solvents; identified processes for which individual
 chemicals could be used in multiple situations; established a purchasing procedure in which a
 new chemical is purchased only after evaluating information including material safety data sheets
 (MSDSs) and other information sources supplied by  vendors;  and tracked  all purchased
 chemicals to ensure efficient usage. As a result of the program, the company eliminated the use
 of 32 unnecessary chemicals and products, reduced regulatory concerns,  minimized waste
 disposal costs, and achieved the cooperation of vendors, who worked to supply the company with
 satisfactory chemicals (Texas Railroad Commission, 1999).
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       Completion
                    Lead-Free Pipe Dope
                    Pipe dope is used in drill string connections.  The American Petroleum
                    Institute (API)-specified pipe dope contains approximately 30 percent lead,
                    which raises human health and environmental concerns.  New lead-free,
                    biodegradable pipe dopes are now available, however, which may be used
                    when conditions do not require the use of the API-specified material. In
                    particular, the use of pipe  dope on thread protectors may allow for the
                    recycling of thread protectors with fewer regulatory concerns.

                    Cementing "On-the-Flv"
                    When well casing is cemented in, the cement used is often pre-mixed with
                    additives to specification.  There may be a substantial surplus of unused, pre-
                    mixed cement if the quantity required for the project was overestimated.  One
                    solution used by some service companies is to mix neat (concentrated)
                    cement with additives on-the-fly, through the use of automatic density control
                    systems.  The mixing process can be stopped as soon as the cementing job is
                    complete, and the unused raw materials can be used at a later cementing job
                    rather than disposed of as waste. Cementing on-the-fly is becoming common
                    practice.
V.C.  Petroleum Production
       Produced Water Management
                    Produced water constitutes the vast majority of oil and gas extraction waste,
                    and traditionally the volume has been fixed and unavoidable. However, there
                    have been developments that might help to reduce the amount of produced
                    water that is brought to the surface, and reduce the wastes associated with
                    treating produced water that does reach the surface.

                    Downhole Produced Water Separation
                    A new procedure made possible by the miniaturization of motors is the
                    separating and pumping of produced water downhole, without bringing it to
                    the surface. There are three significant variations, but in each case excess
                    water is separated from the desired product in the wellbore and injected into
                    another geological formation, typically below the production zone.

                    In formations where oil and water are mostly separate, two perforations in the
                    well can be made; oil is removed through one and transported to the surface,
                    and water  is removed through the other perforation and injected in the
                    disposal zone.  It should be noted that the water disposal system must be
                    monitored to ensure that oil is not lost.
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                    In another method, a hydrocyclone is used downhole to separate free water
                    from any oil- or gas-containing fluid by centrifugal force.  The water is
                    injected into a disposal zone, and the product is pumped to the surface.

                    Finally, in gas wells, simple gravity can be used to remove a substantial
                    amount of water.  Gas rises to the surface of the separation device, and water
                    is injected from the bottom into a lower disposal zone.

                    With these methods, some water is always still brought to the surface. Also,
                    the technology is still in development. Nevertheless, downhole separation
                    can be an effective and economically attractive method of reducing produced
                    water volumes.

                    Produced Water Filter Management
                    Many wells employ filters to remove some waste from produced water before
                    the water is injected into an underground well.  Because the water may
                    contain varying amounts of filterable components, the filters must be changed
                    regularly in order to prevent the system from backing up. Many wells replace
                    the filters at fixed intervals; for example, twice a month. However, it is
                    possible to reduce the frequency of filter changes by measuring the difference
                    in pressure between the input and output sides of the filter, and only changing
                    the filter when a certain pressure is reached. Costs are incurred when valves
                    are installed,  but the savings involved in labor, filters, and filter  disposal
                    often offset the cost of valve installation.
 A small independent operator wanted to reduce the number of filters used for its produced water
 injection system.  Previously, the operator had changed the filters twice a month at its 36
 injection wells, at a cost of $4,148 per year (1,700 filters at $2.44 per filter). The operator
 installed valves on the filter units, at a total cost of $ 1,800.  The following year, the operator only
 generated 28 waste filters, and saved about $4,000 per year in filter purchases, plus additional
 labor time and waste management costs (Texas Railroad Commission, 1997).
       Natural Gas Conditioning
                    Reducing Glycol Circulation Rates
                    Glycol is used to remove water from natural gas.  However, methane and
                    VOCs are removed as well, in proportion to the amount of glycol circulated
                    through the system. These methane and VOC components are removed from
                    the glycol during a reconditioning process, and may be either returned to the
                    production stream or vented to the atmosphere.

                    Research by the EPA voluntary industry partnership Natural Gas STAR has
                    indicated that operators often maintain a circulation rate that is at least two
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                    times higher than is needed to attain  mandated water  content  levels.
                    Therefore, it is desirable to perform calculations to determine the minimum
                    circulation rate needed. Savings can be realized on several fronts:

                    •      Less salable methane lost to the atmosphere
                    •      Less glycol needed
                    •      Improved dehydrator unit efficiency
                    •      Lower fuel pump use.

                    The potential savings for a dehydrator unit can range from $260 to $26,280
                    per year (Natural Gas STAR, 1997).

                    Adjusting Pneumatic Devices
                    For both oil and gas field operations pressurized natural gas is used regularly
                    hi pneumatic devices to regulate pressure, control valves, and equilibrate
                    liquid levels.   Leaks and releases  from this practice, particularly from
                    inefficient or "high-bleed" devices, are the single largest source of methane
                    emissions by the industry. Methane is released at the estimated rate of 31
                    billion cubic feet (Bcf) per year from pneumatic devices. Several strategies
                    exist to reduce such emissions, including the replacement of high-bleed
                    devices with equivalent low-bleed ones and maintenance of existing devices
                    to replace leaking seals and tune valves.  Natural Gas STAR estimates that
                    partners of the program have saved 11.2 Bcf to date through improvements
                    to pneumatic devices, saving approximately $22.4 million.  For most of the
                    improvements, the payback period is between six months and a year (Natural
                    Gas STAR, 1997).

       Energy-Efficient Production

                    Automatic Casing Swab
                    In wells where natural formation pressure is insufficient to lift the product to
                    the surface, it might be possible to install a small device downhole to delay
                    the purchase of costly pumping or  injection  equipment.  The Automatic
                    Casing Swab (ACS) seals off the production zone of the well, which causes
                    pressure to build up in the formation.  At a threshold pressure, the ACS
                    opens, and product flows to the surface without mechanical assistance. When
                    the  flow slows and pressure decreases, the  ACS closes until pressure
                    increases again.  The device was created by the Sandia National Laboratories
                    under a grant from DOE, and as of the end of 1997 has been applied to  350
                    wells. These wells are producing more than 3.5 million cubic feet of natural
                    gas per year that otherwise would have been uneconomical to extract.  The
                    device may also lead to decreased energy consumption in other wells in
                    situations where it reduces the need for energy-intensive mechanical pumps.
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       Solid Waste Reduction
                     Oily Sludge Minimization
                     When oil first is brought to the surface, fine particles, oil, and water form a
                     stable sludge that settles out in storage tanks and separation equipment.
                     There are two approaches to minimizing the loss of product that occurs when
                     oil becomes entrained in the sludge: preventing the formation of sludge and
                     treating the sludge to recover the oil.

                     Two significant methods can minimize the formation of sludge in a storage
                     tank at a production site.  First, recirculating pumps can be installed in tanks.
                     By increasing circulation, heavier components remain in suspension longer
                     and do not collect on the bottom of the tanks as quickly.  Second, eliminating
                     air contact with oil in the tanks can reduce the formation of sludge.  Oxygen
                     can play a role in the formation of sludge, so minimizing the introduction of
                     atmospheric oxygen can reduce sludge levels. Furthermore, reducing contact
                     to the atmosphere can minimize emissions of VOCs.

                     In many locations, recyclers can treat sludge to  remove oil at a crude oil
                     reclamation plant. Crude oil reclamation serves two purposes; the extracted
                     oil can be sold, and disposal costs for sludge is minimized because much of
                     the  liquid component is removed.  In addition, salable material that has
                     solidified, e.g., paraffin, may be  reclaimed  during  this process.   The
                     separation process typically is performed with the use of centrifuges, heat, or
                     filters.  One example is a filter press, which presses solids into a cake and
                     extracts oil and water as an aqueous filtrate. The water and oil are then
                     separated further.
  A facility on the West Coast installed a filter press to retrieve oil from sludge and reduce disposal
  costs. The press reduced the volume of waste from 44,900 to 13,500 barrels per year, a reduction
  of 70 percent. Disposal costs were reduced by $564,200 per year. Approximately 81 percent of
  the oil  in the sludge was recovered, so that at a price  of $15 per barrel, the recovered oil
  represented additional revenues of $108,000 per year.  Based on a capital cost for the press of
  approximately $3,000,000 and operating  costs of $400,000 per year, the  system is saving
  approximately $272,000 per year and the capital cost has a payoff period of about 3.5  years.
V.D.  Maintenance
                    Maintenance procedures, particularly workovers, may be a source of potential
                    pollutants for industry including acids,  VOCs, and solutions with high
                    concentrations of salts and metals.  The  following opportunities describe
                    steps that can minimize the need for workovers, or help notify operators when
                    maintenance is necessary to limit releases.
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                    Preplanning
                    Careful preplanning efforts undertaken prior to a workover may reduce the
                    amount of materials necessary at the site, and therefore may reduce waste and
                    the chance of spilling.  For example, by estimating the amount of acid
                    required for acid stimulation based on the known reservoir conditions, the
                    transportation, storage, and disposal of excess acid may be reduced.

                    Paraffin and Scale Accumulation Prevention
                    The buildup of paraffins in production equipment, particularly in older wells,
                    is a serious concern, and when untreated,  paraffin buildups  can damage
                    pumping equipment and rupture flowlines.  Therefore, it is  desirable  to
                    minimize the buildup of paraffins.  One possible solution is the installation
                    of a magnetic fluid conditioner (MFC), which creates a strong permanent
                    magnetic field around the pump. This magnetic field alters the solubility and
                    viscosity of crude oil, so mat paraffin, scale, and other contaminants do not
                    precipitate in the flowlines.  The device requires a  significant capital
                    investment, must be custom-made for each well, and is not always successful,
                    but the reduced frequency of maintenance and the reduced risk of flowline
                    rupture (and the associated mitigation costs) can make an MFC a wise choice
                    for wells with paraffin and scale buildup problems.
  A small independent operator was suffering from damaged pumping equipment and ruptured
  flowlines as a result of paraffin buildup, and had to treat the well every ten days with solvent/hot
  oil to remove the deposits.  The operator installed an MFC in the well for $5,000. Seven weeks
  later for an unrelated reason, the operator pulled the tubing from the well, and minimal paraffin
  deposition was observed.   The  investment was recovered in six months  due to reduced
  maintenance costs, and because flow had improved, revenue increased as well (Texas Railroad
  Commission, 1997).
                     High-level alarm
                     A helpful device for preventing releases and loss of product is an alarm and
                     automatic shut-off that shuts-in production equipment when an irregularity
                     is detected. The equipment can only be restarted manually, to ensure that the
                     problem is addressed.  A facility-wide alarm is particularly important when
                     the operator is offsite and the well is only monitored periodically.

                     Microbially-Treated Produced Water
                     The separation of oil from produced water is not completely efficient; oil
                     concentrations in produced water can be at least 10 ppm.  This oil can clog
                     disposal wells and increase electricity costs because injection pumps must
                     contend with increased pressure in  these  clogged  wells.   If  oil-eating
                     microbes are introduced to the produced water, oil content can be reduced,
                     injection wells may become clogged less frequently  (thereby reducing
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                     workover costs), and electricity costs are reduced because the pump can work
                     more efficiently.
  A small operator wanted to reduce the frequency of workovers and trim electricity costs due to
  oil clogging in two injection wells. For approximately $150 per month for the two wells, the
  company added oil-scavenging microbes to the produced water.  The operator realized a
  reduction of $400 per month in electricity costs due to the reduced pressure in the injection well,
  for a net savings of $250 per month. The procedure also has helped to minimize the number of
  injection well workovers.
                     Coiled Tubing Units
                     As mentioned in previous sections, pulling the drill string or production
                     tubing can increase the chance of a blowout or other spills. Coiled tubing
                     units allow workovers to be performed while keeping production tubing in
                     place. By using coiled tubing units during workovers, the use of a workover
                     rig and the pulling of production tubing are avoided.

                     Product Substitution
                     Many materials used in the workover process, particularly solvents used for
                     cleaning and  for paints, are classified as hazardous wastes when spent.
                     Alternatives are available that are not classified as hazardous waste,  and
                     which are safer for the environment and present fewer regulatory concerns.
                     Alternatives for cleaning solvents include citrus-based cleaning compounds
                     and steam, or a substitute for the solvent Varsol (also called petroleum spirits
                     or Stoddard solvent) is available as a "high flash point  Varsol," thereby
                     sufficiently reducing the solution's ignitability hazardous waste characteristic.
                     For solvent-based paints, a common substitution is the use of water-based
                     paints, which reduce or eliminate the need for solvents and organic thinners.
                     Chemical Metering or Dosing Systems
                     The dispensing of some workover fluids, such as corrosion inhibitors, by an
                     occasional bulk addition can result in the inefficient use of the chemical and
                     an inadequate workover job. As an alternative, an automatic dosing system
                     that releases a small, continuous stream of fluid can reduce the amount of
                     needed fluid and may improve workover results.
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VI.  SUMMARY OF FEDERAL STATUTES AND REGULATIONS

                     This section discusses the federal regulations that may apply to this sector.
                     The purpose of this section is to highlight and briefly describe the applicable
                     federal requirements, and to provide citations for more detailed information.
                     The three following sections are included:

                     •      Section VI. A contains a general overview of major statutes
                     •      Section VLB contains a list of regulations specific to this industry
                     •      Section VI.C contains a list of pending and proposed regulatory
                           requirements.

                     The  descriptions within  Section VI  are  intended solely  for  general
                     information.  Depending upon the nature or scope of the activities  at a
                     particular facility, these summaries may or may not necessarily describe all
                     applicable environmental requirements.  Moreover, they do not constitute
                     formal interpretations or clarifications of the statutes and regulations.  For
                     further information, readers should consult the Code of Federal Regulations
                     and other state or local regulatory  agencies.  EPA Hotline contacts are also
                     provided for each major statute.

VI.A.  General Description of Major Statutes

       Clean Water Act

                     The primary objective of the Federal Water Pollution Control Act, commonly
                     referred to as the Clean Water Act (CWA), is to restore and maintain the
                     chemical, physical, and biological integrity  of the nation's  surface waters.
                     Pollutants regulated under the  CWA are classified  as  either  "toxic"
                     pollutants; "conventional" pollutants, such as biochemical oxygen demand
                     (BOD), total suspended solids (TSS), fecal coliform, oil and grease, and pH;
                     or "non-conventional" pollutants,  including  any pollutant not identified as
                     either conventional or priority.

                     The CWA regulates both direct  and "indirect" dischargers  (those  who
                     discharge  to  publicly owned treatment works).  The National Pollutant
                     Discharge Elimination System (NPDES) permitting program (CWA section
                     402) controls direct discharges into navigable waters. Direct discharges or
                     "point source" discharges are from sources such as pipes and sewers. NPDES
                     permits, issued by either EPA or an authorized state (EPA has authorized 43
                     states and 1 territory to administer the NPDES program), contain industry-
                     specific, technology-based and water quality-based limits and establish
                     pollutant monitoring and reporting requirements. A facility that proposes to
                     discharge into the nation's waters must obtain a permit prior to initiating a
                     discharge.  A permit  applicant must provide quantitative  analytical  data
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                     identifying the types  of pollutants present* in the facility's effluent.  The
                     permit will then set forth the conditions and effluent limitations under which
                     a facility may make a discharge.

                     Water quality-based discharge limits are based on federal or state water
                     quality criteria or standards, that were designed to protect designated uses of
                     surface waters, such as supporting aquatic life or recreation. These standards,
                     unlike the technology-based standards, generally do not take into account
                     technological-feasibility or costs.  Water quality criteria and standards vary
                     from state to state, and site to site, depending on the use classification of the
                     receiving body of water. Most states follow EPA guidelines which propose
                     aquatic life and human health criteria for many of the 126 priority pollutants.

                     Storm Water Discharges
                     In 1987 the CWA was amended to require EPA to establish a program to
                     address storm water discharges.   In  response, EPA promulgated NPDES
                     permitting regulations for storm water discharges. These regulations require
                     that facilities with the following  types of storm water discharges, among
                     others, apply for an NPDES permit: (1) a discharge associated with industrial
                     activity;  (2) a discharge from a  large or medium municipal storm sewer
                     system; or (3) a discharge which EPA or the state determines to contribute to
                     a violation of a water quality standard or is a significant contributor of
                     pollutants to waters of the United States.

                     The term "storm water discharge associated with industrial activity" means
                     a storm water discharge from one of 11  categories of industrial activity
                     defined at 40 CFR Part 122.26.   Six of the categories are defined by SIC
                     codes while the other five are identified through narrative descriptions of the
                     regulated industrial activity. If the primary SIC code of the facility is one of
                     those identified in the regulations, the facility is subject to the storm water
                     permit application requirements. If any activity at a facility is covered by one
                     of the five narrative categories,  storm water discharges from those areas
                     where the activities occur are subject  to storm  water discharge permit
                     application requirements.

                     Those facilities/activities that are subject to storm water discharge permit
                     application requirements are identified below.  To determine whether a
                     particular facility falls within one of these categories, the regulation should
                     be consulted.

                     Category i:  Facilities subject to storm water effluent guidelines, new source
                     performance standards, or toxic pollutant effluent standards.

                     Category ii:  Facilities classified as SIC 24-lumber and wood products
                     (except wood kitchen cabinets);  SIC 26-paper and allied products (except
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              Federal Statutes and Regulations
                     paperboard containers and products); SIC 28-chemicals and allied products
                     (except drugs and paints); SIC 29-petroleum refining; SIC 311-leather
                     tanning and finishing; SIC 32 (except 323)-stone, clay, glass, and concrete;
                     SIC 33-primary metals; SIC 3441-fabricated structural metal; and SIC 373-
                     ship and boat building and repairing.

                     Category iii:  Facilities  classified as SIC 10-metal mining; SIC 12-coal
                     mining; SIC  13-oil and gas extraction; and SIC 14-nonmetallic  mineral
                     mining.

                     Category iv:  Hazardous waste treatment, storage, or disposal facilities.

                     Category v: Landfills, land application sites, and open dumps that receive
                     or have received industrial wastes.

                     Category vi:  Facilities classified as SIC 5015-used motor vehicle parts; and
                     SIC 5093-automotive scrap and waste material recycling facilities.

                     Category vii:  Steam electric power generating facilities.

                     Category viii: Facilities classified as SIC 40-railroad transportation; SIC 41-
                     local passenger transportation; SIC 42-trucking and warehousing (except
                     public warehousing and storage); SIC 43-U.S. Postal Service; SIC 44-water
                     transportation; SIC 45-transportation by air; and SIC 5171-petroleum bulk
                     storage stations and terminals.

                     Category ix:  Sewage treatment works.

                     Category x:  Construction activities except operations that result in the
                     disturbance of less than five acres of total land area.

                     Category xi:  Facilities classified as SIC 20-food and kindred products; SIC
                     21-tobacco  products; SIC 22-textile mill products; SIC 23-apparel related
                     products; SIC 243 4-wood kitchen cabinets manufacturing; SIC 25-furniture
                     and fixtures; SIC 265-paperboard containers and boxes; SIC 267-converted
                     paper and paperboard products; SIC  27-printing, publishing, and allied
                     industries; SIC 283-drugs; SIC 285-paints, varnishes, lacquer, enamels, and
                     allied products; SIC 30-rubber  and plastics;  SIC 31-leather  and leather
                     products (except leather and tanning and finishing); SIC 323-glass products;
                     SIC 34-fabricated metal products (except fabricated structural metal); SIC 35-
                     industrial and  commercial machinery and computer equipment; SIC 36-
                     electronic and other  electrical  equipment  and  components;  SIC 37-
                     transportation equipment (except ship and boat building and repairing); SIC
                     38-measuring, analyzing, and controlling instruments; SIC 39-miscellaneous
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                    manufacturing  industries; and  SIC 4221-4225-public warehousing and
                    storage.

                    Pretreatment Program
                    Another type of discharge that is regulated by the CWA is one that goes to a
                    publicly owned treatment works (POTW). The national pretreatment program
                    (CWA section 307(b)) controls the indirect discharge of pollutants to POTWs
                    by "industrial users."  Facilities regulated under section 307(b) must meet
                    certain pretreatment standards. The goal of the pretreatment program is to
                    protect municipal wastewater treatment plants from damage that may occur
                    when hazardous, toxic, or other wastes are discharged into a sewer system
                    and to protect the quality of sludge generated by these plants.

                    EPA has developed technology-based standards  for industrial users  of
                    POTWs. Different standards apply to existing and new sources within each
                    category. "Categorical" pretreatment standards applicable to an industry on
                    a nationwide basis are developed by EPA. In addition, another kind of
                    pretreatment standard, "local limits," are developed by the POTW in order to
                    assist the POTW in achieving the effluent limitations in its NPDES permit.

                    Regardless of whether a state is authorized to implement either the NPDES
                    or the pretreatment program, if it develops its own program, it may enforce
                    requirements more stringent than federal standards.

                    Wetlands
                    Wetlands, commonly called swamps,  marshes, fens, bogs, vernal pools,
                    playas, and prairie potholes, are a subset of "waters of the United States," as
                    defined in Section 404 of the CWA. The  placement  of  dredge and fill
                    material into wetlands and other water bodies  (i.e., waters of the United
                    States) is regulated by the U.S. Army Corps of Engineers (Corps) under 33
                    CFR Part 328.  The Corps regulates wetlands by administering the CWA
                    Section 404 permit program for activities that impact wetlands. EPA's
                    authority under Section 404 includes veto power of Corps permits, authority
                    to interpret statutory exemptions and jurisdiction, enforcement actions, and
                    delegating the Section 404 program to the states.

                    EPA's Office of Water, at (202) 260-5700, will direct callers with questions
                    about the CWA to the appropriate EPA office.   EPA also maintains  a
                    bibliographic  database of Office  of Water publications which can  be
                    accessed through the Ground Water and Drinking Water Resource Center,
                    at (202) 260-7786.
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       Oil Pollution Prevention Regulation
                     Section 31 l(b) of the CWA prohibits the discharge of oil, in such quantities
                     as may be harmful, into the navigable waters of the United States and
                     adjoining shorelines. The EPA Discharge of Oil regulation, 40 CFR Part
                     110, provides information regarding these discharges.  The  Oil Pollution
                     Prevention regulation, 40 CFR Part 112, under the authority of Section 31 l(j)
                     of the CWA, requires regulated facilities to prepare and implement Spill
                     Prevention Control and Countermeasure (SPCC) plans. The intent of a SPCC
                     plan is to prevent the discharge of oil from onshore and offshore non-
                     transportation-related facilities.  In 1990 Congress passed the Oil Pollution
                     Act which amended Section 311Q) of the CWA  to require facilities that
                     because of their location could reasonably be expected to cause "substantial
                     harm" to the environment by a discharge of oil to develop and implement
                     Facility Response Plans (FRP). The intent of a FRP is to provide for planned
                     responses to discharges of oil.

                     A facility is SPCC-regulated if the  facility, due to its location, could
                     reasonably be expected to discharge oil into or upon the navigable waters of
                     the United States or adjoining shorelines, and the facility meets one of the
                     following criteria regarding oil storage: (1) the capacity of any aboveground
                     storage tank exceeds 660 gallons,  or (2) the total aboveground storage
                     capacity exceeds 1,320  gallons, or  (3) the underground storage capacity
                     exceeds 42,000 gallons.  40 CFR Part 112.7 contains the format and content
                     requirements for a SPCC plan. In New Jersey, SPCC plans can be combined
                     with DPCC plans, required by the state, provided there is an appropriate
                     cross-reference index to the requirements of both regulations at the front of
                     the plan.

                     According to the FRP regulation, a facility can cause "substantial harm" if it
                     meets one of the following criteria:  (1) the facility has a total oil storage
                     capacity greater than or equal to 42,000 gallons and transfers oil over water
                     to or from vessels; or (2) the facility has a total oil storage capacity greater
                     than or equal to 1 million gallons  and meets any one of the following
                     conditions: (i) does not have adequate secondary containment, (ii) a discharge
                     could cause "injury" to fish and wildlife and sensitive environments, (iii) shut
                     down a public drinking  water intake, or (iv) has had a reportable oil spill
                     greater than or equal to 10,000 gallons in the past 5 years. Appendix F of 40
                     CFR Part 112 contains the format and content requirements for a FRP. FRPs
                     that meet EPA's requirements can be combined with U.S. Coast Guard FRPs
                     or other contingency plans, provided there is an appropriate cross-reference
                     index to the requirements of all applicable regulations at the front of the plan.

                     For  additional information regarding SPCC plans, contact EPA's RCRA,
                     Superfund, and EPCRA Hotline, at (800) 424-9346. Additional documents
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                    and resources  can  be  obtained from  the  hotline's homepage  at
                    www. epa. gov/epaoswer/hotline. The hotline operates -weekdays from 9:00
                    a.m. to 6:00 p.m., EST, excluding federal holidays.

       Safe Drinking Water Act

                    The Safe Drinking Water Act (SDWA)  mandates that EPA establish
                    regulations to protect  human health from contaminants in drinking water.
                    The law authorizes EPA to develop national drinking water standards and to
                    create a joint federal-state system to ensure compliance with these standards.
                    The SDWA also directs EPA to protect underground sources of drinking
                    water through the control of underground injection of fluid wastes.

                    EPA has developed primary and secondary drinking water standards under
                    its SDWA authority. EPA and authorized states enforce the primary drinking
                    water standards, which are contaminant-specific concentration limits that
                    apply to certain public drinking water supplies.  Primary drinking water
                    standards consist of maximum contaminant level goals (MCLGs), which are
                    non-enforceable health-based  goals, and  maximum  contaminant levels
                    (MCLs), which are enforceable limits set generally  as close to MCLGs as
                    possible, considering cost and feasibility of attainment.

                    Part C of the SDWA mandates EPA to protect underground sources of
                    drinking water from inadequate injection  practices.  EPA has published
                    regulations codified hi 40 CFR Parts 144 to 148 to comply with this mandate.
                    The Underground Injection Control (UIC) regulations break down injection
                    wells into  five different types, depending on the  fluid  injected and the
                    formation that receives it.   The regulations also include construction,
                    monitoring, testing, and operating requirements for injection well operators.
                    All injection wells have to be authorized by permit or by rule depending on
                    their potential to threaten Underground Sources of Drinking Water (USDW).
                    RCRA also regulates  hazardous waste injection wells and a UIC permit is
                    considered to meet the requirements of a RCRA permit. EPA has authorized
                    delegation of the UIC for all wells in 35 states, implements the program in 10
                    states and all Indian lands, and shares responsibility with 5 states.

                    The SDWA also provides for a federally-implemented Sole Source Aquifer
                    program, which prohibits federal funds from being expended on projects that
                    may contaminate the sole or principal source of drinking  water for a given
                    area, and for a state-implemented Wellhead Protection program, designed to
                    protect drinking water wells and drinking water recharge areas.

                    The SDWA Amendments of 1996 require states to develop and implement
                    source water assessment programs (S WAPs) to analyze existing and potential
                    threats to the quality of the public drinking water throughout the state. Every
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                    state is required to submit a program to EPA and to complete all assessments
                    within 3 Vz years of EPA approval of the program.  SWAPs include: (1)
                    delineating the source water protection area, (2) conducting a contaminant
                    source inventory, (3) determining the susceptibility of the public water supply
                    to contamination from the inventories sources, and (4) releasing the results
                    of the assessments to the public.

                    EPA's Safe Drinking Water Hotline, at (800) 426-4791, answers questions
                    and distributes guidance pertaining  to SDWA  standards.  The  Hotline
                    operates from 9:00a.m. through 5:30 p.m., EST, excluding federal holidays.
                    Visit the website at www. epa. gov/ogwdw for additional material.

       Resource Conservation and Recovery Act

                    The Solid Waste Disposal Act (SWDA),  as amended by the Resource
                    Conservation and Recovery Act (RCRA)  of 1976, addresses  solid and
                    hazardous waste management activities. The Act is commonly referred to as
                    RCRA. The Hazardous and Solid Waste Amendments (HSWA) of 1984
                    strengthened RCRA's waste management provisions and added Subtitle I,
                    which governs underground storage tanks (USTs).

                    Regulations promulgated pursuant to  Subtitle C  of RCRA (40  CFR Parts
                    260-299) establish a "cradle-to-grave" system governing hazardous waste
                    from the point of generation to disposal. RCRA hazardous wastes include the
                    specific materials listed in the regulations (discarded commercial chemical
                    products, designated with the  code "P"  or "U"; hazardous wastes from
                    specific industries/sources, designated with the code "K"; or hazardous
                    wastes from non-specific sources, designated with the code "F") or materials
                    which exhibit a hazardous  waste characteristic  (ignitability, corrosivity,
                    reactivity, or toxicity and designated with the code "D").

                    Entities that generate hazardous waste are subject to waste accumulation,
                    manifesting, and recordkeeping standards.  A hazardous waste facility may
                    accumulate hazardous waste for up to 90 days (or 180 days depending on the
                    amount generated per month) without a permit or interim status. Generators
                    may also treat hazardous waste in accumulation tanks or containers (in
                    accordance with the requirements of 40 CFR Part 262.34) without a permit
                    or interim status.  Facilities that treat, store, or dispose of hazardous waste are
                    generally required to obtain a RCRA permit.

                    Subtitle C permits are required for treatment, storage, or disposal facilities.
                    These permits contain general facility  standards such as contingency plans,
                    emergency procedures, recordkeeping and reporting requirements, financial
                    assurance mechanisms, and unit-specific standards.  RCRA also contains
                    provisions (40 CFR Subparts I and S) for conducting corrective actions which
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                    govern the cleanup of releases of hazardous waste or constituents from solid
                    waste management units at RCRA treatment, storage, or disposal facilities.

                    Although RCRA is a federal statute, many states implement the RCRA
                    program.  Currently, EPA has delegated its authority to implement various
                    provisions of RCRA  to 47 of the 50  states and two  U.S. territories.
                    Delegation has not been given to Alaska, Hawaii, or Iowa.

                    Most RCRA requirements are not industry specific but apply to any company
                    that generates, transports, treats, stores, or disposes of hazardous waste. Here
                    are some important RCRA regulatory requirements:

                    •      Criteria for Classification of Solid Waste Disposal Facilities and
                           Practices (40 CFR Part 257) establishes the criteria for determining
                           which solid waste disposal facilities and practices pose a reasonable
                           probability of adverse effects on health or the environment.  The
                           criteria were adopted to ensure non-municipal, non-hazardous waste
                           disposal  units  mat  receive conditionally exempt small quantity
                           generator waste  do not  present  risks  to  human  health  and
                           environment.

                           Criteria for Municipal Solid Waste Landfills (40 CFR Part 258)
                           establishes minimum national criteria for all municipal solid waste
                           landfill units, including those that are used to dispose of sewage
                           sludge.

                           Identification of Solid and Hazardous Wastes (40 CFR Part 261)
                           establishes the standard to determine whether the material in question
                           is considered a solid waste and, if so, whether it is a hazardous waste
                           or is exempted from regulation.

                           Standards for Generators of Hazardous Waste (40 CFR Part 262)
                           establishes the responsibilities of  hazardous waste generators
                           including obtaining an EPA identification number,  preparing a
                           manifest, ensuring proper packaging and labeling, meeting standards
                           for waste accumulation units, and  recordkeeping  and reporting
                           requirements. Generators can accumulate hazardous waste on-site for
                           up to 90 days  (or 180 days depending on the  amount  of waste
                           generated) without obtaining a permit.

                           Land  Disposal Restrictions  (LDRs) (40  CFR Part 268)  are
                           regulations prohibiting the disposal of hazardous waste on  land
                           without prior treatment. Under the LDRs program, materials must
                           meet treatment standards prior to placement in a RCRA land disposal
                           unit  (landfill,  land  treatment  unit, waste  pile,  or  surface
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                           impoundment).  Generators of waste subject to the LDRs must
                           provide notification of such to the designated TSD facility to ensure
                           proper treatment prior to disposal.

                           Used Oil Management Standards  (40 CFR Part 279) impose
                           management requirements affecting the storage,  transportation,
                           burning, processing, and re-refining of the used oil. For parties that
                           merely generate used oil, regulations establish storage standards. For
                           a party considered a used oil processor, re-refiner, burner, or marketer
                           (one who generates and sells off-specification used oil directly to a
                           used oil burner), additional tracking and paperwork requirements
                           must be satisfied.

                    •      RCRA contains unit-specific standards for all units used to store,
                           treat, or dispose  of hazardous  waste, including Tanks  and
                           Containers. Tanks and containers used to store hazardous waste with
                           a high volatile organic concentration must meet emission standards
                           under RCRA.  Regulations  (40 CFR Part 264-265, Subpart CC)
                           require generators to test the waste to determine the concentration of
                           the waste, to satisfy tank and container emissions standards, and to
                           inspect and monitor regulated units. These regulations apply to all
                           facilities who store such waste, including large quantity generators
                           accumulating waste prior to shipment offsite.

                           Underground Storage Tanks (USTs) containing petroleum products
                           (including gasoline, diesel, and used oil)  and hazardous substances
                           are regulated under Subtitle I of RCRA.  Subtitle I regulations (40
                           CFR  Part   280)  contain  tank  design and  release  detection
                           requirements, as well as financial responsibility and corrective action
                           standards for  USTs.  The UST program  also  includes upgrade
                           requirements for existing tanks that were to be met by December 22,
                           1998.

                    •      Boilers and Industrial Furnaces (BIFs) that use or burn fuel
                           containing hazardous waste must comply  with design and operating
                           standards. BIF regulations (40 CFR Part 266, Subpart H) address unit
                           design, provide performance standards, require emissions monitoring,
                           and, in some cases, restrict the type of waste that may be burned.

                    EPA'sRCRA, Superfund, andEPCRA Hotline, at (800) 424-9346, responds
                    to questions  and distributes guidance  regarding all RCRA regulations.
                    Additional documents and resources can be obtained from the hotline's
                    homepage at www. epa. gov/epaoswer/hotline.  The RCRA Hotline operates
                    weekdays from 9:00 a.m. to 6:00 p.m., EST, excluding federal holidays.
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       Comprehensive Environmental Response, Compensation, and Liability Act

                    The Comprehensive Environmental Response, Compensation, and Liability
                    Act (CERCLA), a 1980 law commonly known as Superfund, authorizes EPA
                    to respond to releases, or threatened releases, of hazardous substances that
                    may endanger public health, welfare, or the environment.  CERCLA also
                    enables EPA to force parties responsible for environmental contamination to
                    clean it up or to reimburse the Superfund for response or remediation costs
                    incurred by EPA.  The Superfund Amendments and Reauthorization Act
                    (SARA) of 1986 revised various sections of CERCLA, extended the taxing
                    authority for the Superfund, and created a free-standing law, SARA Title III,
                    also known as the Emergency Planning and Community Right-to-Know Act
                    (EPCRA).

                    The CERCLA hazardous substance release reporting regulations (40 CFR
                    Part 302) direct the person in charge of a facility to report to the National
                    Response Center (NRC) any environmental release of a hazardous substance
                    which equals or exceeds a reportable quantity. Reportable quantities are
                    listed in 40 CFR Part 302.4.  A release report may trigger a response by EPA
                    or by one or more federal or state emergency response authorities.

                    EPA implements hazardous substance responses  according to procedures
                    outlined in the National Oil and Hazardous Substances Pollution Contingency
                    Plan (NCP) (40 CFR Part 300).  The NCP includes provisions for cleanups.
                    The National Priorities List (NPL) currently includes approximately 1,300
                    sites.  Both EPA and states  can act at other sites; however, EPA provides
                    responsible parties the opportunity to conduct cleanups and encourages
                    community involvement throughout the Superfund response process.

                    EPA'sRCRA, Superfund and EPCRA Hotline, at (800) 424-9346, answers
                    questions and references guidance pertaining to  the Superfund program.
                    Documents and resources can be obtained from the hotline's homepage at
                    www. epa. gov/epaoswer/hotline. The Superfund Hotline operates weekdays
                    from 9:00 a.m. to 6:00 p.m., EST, excluding federal holidays.

       Emergency Planning And Community Right-To-Know Act

                    The Superfund Amendments and Reauthorization Act (SARA) of 1986
                    created  the Emergency Planning  and Community  Right-to-Know Act
                    (EPCRA, also known as SARA Title III), a statute designed to improve
                    community access to information about chemical hazards and to facilitate the
                    development of chemical emergency response plans by state and local
                    governments. Under EPCRA,  states establish  State Emergency Response
                    Commissions (SERCs), responsible for coordinating certain emergency
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                    response activities and for appointing Local Emergency Planning Committees
                    (LEPCs).

                    EPCRA and the EPCRA regulations (40 CFR Parts 350-372) establish four
                    types of reporting obligations for facilities which store or manage specified
                    chemicals:

                           EPCRA section 302 requires facilities to notify the SERC and LEPC
                           of the presence of any extremely hazardous substance at the facility
                           in an amount in excess of the established threshold planning quantity.
                           The  list of extremely hazardous substances and their threshold
                           planning quantities is found at 40 CFR Part 355, Appendices A and
                           B.

                    •      EPCRA section 303 requires that each LEPC develop an emergency
                           plan. The plan must contain (but is not limited to) the identification
                           of facilities within the planning district, likely routes for transporting
                           extremely hazardous substances, a description of the methods and
                           procedures to be followed by facility owners and operators, and the
                           designation of community  and  facility   emergency  response
                           coordinators.

                           EPCRA section 304 requires the facility to notify the SERC and the
                           LEPC in the event of a release exceeding the reportable quantity of a
                           CERCLA hazardous substance (defined at 40 CFR Part 302) or an
                           EPCRA extremely hazardous substance.

                           EPCRA sections 311 and 312 require a facility at which a hazardous
                           chemical, as defined by the Occupational Safety and Health Act, is
                           present in an amount exceeding a specified threshold to submit to the
                           SERC,  LEPC and local fire department material safety data sheets
                           (MSDSs) or lists of MSDSs and hazardous chemical inventory forms
                           (also known as Tier I and II forms). This information helps the local
                           government respond in the event of a spill or release of the chemical.

                    •      EPCRA section 313 requires certain covered facilities, including
                           SIC codes 20 through 39 and, the seven industry groups added in
                           1997 (including metal mining (SIC code 10,  except for SIC codes
                           1011, 1081, and 1094), coal mining (SIC code 12, except for SIC
                           code 1241 and extraction activities), electrical utilities that combust
                           coal and/or oil (SIC codes 4911,4931, and 4939), RCRA Subtitle C
                           hazardous waste treatment and disposal facilities (SIC code 4953),
                           chemicals and allied products wholesale distributors (SIC code 5169),
                           petroleum bulk plants and terminals (SIC code 5171), and solvent
                           recovery services  (SIC code 7389)), which have ten  or more
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                           employees, and which  manufacture,  process,  or  use specified
                           chemicals in amounts greater than threshold quantities, to submit an
                           annual toxic chemical release report. This report, commonly known
                           as the Form R, covers releases and transfers of toxic chemicals to
                           various facilities and environmental media.  EPA maintains the data
                           reported in a publically  accessible database known as the Toxics
                           Release Inventory (TRI).

                           All information submitted pursuant to EPCRA regulations is publicly
                           accessible, unless protected by a trade secret claim.

                    EPA'sRCRA, Superfund and EPCRA Hotline, at (800) 535-0202, answers
                    questions and distributes guidance regarding the emergency planning and
                    community right-to-know regulations.  Documents and resources can be
                    obtained from the  hotline's homepage at www. epa. gov/epaoswer/hotline.
                    The EPCRA Hotline operates weekdays from 9:00 a.m. to 6:00 p.m., EST,
                    excluding federal holidays.
       Clean Air Act
                    The Clean Air Act (CAA) and its amendments are designed to "protect and
                    enhance the nation's air resources so as to promote the public health and
                    welfare and the productive capacity of the population." The CAA consists
                    of six sections, known as Titles, which direct EPA to establish national
                    standards for ambient air quality and for EPA and the states to implement,
                    maintain, and enforce these standards through a variety of mechanisms.
                    Under the CAA, many facilities are required to obtain operating permits that
                    consolidate their air emission requirements.  State and local governments
                    oversee, manage, and enforce many of the requirements of the CAA. CAA
                    regulations appear at 40 CFR Parts 50-99.

                    Pursuant to Title I of the CAA,, EPA has established national ambient air
                    quality standards (NAAQSs) to limit levels of "criteria pollutants," including
                    carbon monoxide, lead, nitrogen dioxide, particulate matter, ozone, and sulfur
                    dioxide.  Geographic areas that meet NAAQSs for  a given pollutant are
                    designated as attainment areas; those that do not meet NAAQSs are
                    designated as non-attainment areas. Under sectionl 10 and other provisions
                    of the CAA, each state must develop a State Implementation Plan (SIP) to
                    identify sources of air pollution and to determine what reductions are required
                    to meet federal air quality standards. Revised NAAQSs for particulates and
                    ozone were proposed in 1996 and will become effective in 2001.

                    Title I also authorizes EPA to establish New Source Performance Standards
                    (NSPS), which are  nationally  uniform emission standards for new and
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                     modified stationary sources falling within particular industrial categories.
                     NSPSs are based on the pollution control technology available to that
                     category of industrial source (see 40 CFR Part 60).

                     Under Title I, EPA establishes and enforces National Emission Standards for
                     Hazardous Air Pollutants (NESHAPs), nationally uniform standards oriented
                     toward controlling specific hazardous air pollutants (HAPs). Section 112(c)
                     of the CAA further directs EPA to develop a list of sources that emit any of
                     188 HAPs, and to develop regulations for these categories of sources.  To
                     date EPA has listed 185 source categories and developed a schedule for the
                     establishment of emission standards.  The emission standards are being
                     developed for both new and existing sources based on "maximum achievable
                     control technology"  (MACT).   The MACT is defined as the control
                     technology achieving the maximum degree of reduction in the emission of the
                     HAPs, taking into account cost and other factors.

                     Title II of the CAA pertains to mobile sources, such as cars, trucks, buses,
                     and planes. Reformulated gasoline, automobile pollution control devices,
                     and vapor recovery nozzles on  gas pumps are a few of the mechanisms EPA
                     uses to regulate mobile air emission sources.

                     Title IV-A establishes a  sulfur dioxide and nitrogen oxides emissions
                     program designed to reduce the formation of acid rain. Reduction of sulfur
                     dioxide releases will be obtained by granting to  certain sources limited
                     emissions allowances that are  set below previous levels of sulfur dioxide
                     releases.

                     Title V of the CAA establishes an operating permit program for all "major
                     sources" (and certain other sources) regulated under the CAA.  One purpose
                     of the operating permit is to include in a single document all air emissions
                     requirements that apply to a given facility.  States have developed the permit
                     programs in accordance with guidance and regulations from EPA.  Once a
                     state program is approved by EPA, permits are issued and monitored by that
                     state.

                     Title VI is  intended  to protect  stratospheric ozone  by phasing out the
                     manufacture  of ozone-depleting chemicals  and restricting their  use and
                     distribution.  Production of Class  I substances, including  15 kinds  of
                     chlorofluorocarbons (CFCs), were phased out (except for essential uses) in
                     1996.

                     EPA's  Clean   Air   Technology  Center,  at  (919)   541-0800  or
                     •www. epa. sov/ttn/catc. provides general assistance and information on CAA
                     standards. The Stratospheric Ozone Information Hotline, at (800) 296-1996
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                     or www. epa. gov/ozone. provides general information  about regulations
                    promulgated under Title VI of the CAA; EPA's EPCRA Hotline, at (800)
                     535-0202  or  www. epa. gov/epaoswer/hotline,  answers questions about
                     accidental release prevention under CAA sectioning); and information on
                     air toxics can be accessed through  the  Unified Air  Toxics website at
                     www.epa.gov/ttn/uatw.  In addition, the Clean Air Technology Center's
                     •website includes recent CAA rules, EPA guidance documents, and updates
                     of EPA activities.

       Federal Insecticide, Fungicide, and Rodenticide Act

                     The Federal Insecticide, Fungicide, and Rodenticide Act (FIFRA) was first
                     passed in 1947, and amended  numerous times, most recently by the Food
                     Quality Protection Act (FQPA) of 1996.  FIFRA provides EPA with the
                     authority to oversee, among other things, the registration, distribution, sale
                     and use of pesticides.  The Act applies to all types of pesticides, including
                     insecticides, herbicides, fungicides, rodenticides and antimicrobials. FIFRA
                     covers both intrastate and interstate commerce.

                     Establishment Registration
                     Section 7 of FIFRA requires  that establishments producing pesticides, or
                     active ingredients used in producing a pesticide subject to FIFRA, register
                     with EPA. Registered establishments must report the types and amounts of
                     pesticides and active ingredients they produce. The Act also provides EPA
                     inspection authority and enables the  agency to take enforcement actions
                     against facilities that are not in compliance with FIFRA.

                     Product Registration
                     Under section 3 of FIFRA, all pesticides (with few exceptions) sold or
                     distributed in the U.S. must be registered by EPA. Pesticide registration is
                     very specific and generally allows use of the product only as specified on the
                     label. Each registration specifies the use site i.e., where the product may be
                     used and the amount that may  be applied.  The person who seeks to register
                     the pesticide must file an application for registration. The application process
                     often requires either the citation or submission of extensive environmental,
                     health and safety data.

                     To  register a pesticide, the EPA Administrator must  make a  number of
                     findings, one of which is that the pesticide, when used in accordance with
                     widespread and commonly recognized practice, will not generally cause
                     unreasonable adverse effects on the environment.

                     FIFRA defines "unreasonable  adverse effects on the environment" as "(1) any
                     unreasonable risk to man or the environment, taking into account the
                     economic, social, and environmental costs and benefits of the use of the
                     pesticide, or (2) a human dietary risk from residues that result from a use of
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                     a pesticide in or on any food inconsistent with the standard under section 408
                     of the Federal Food, Drug, and Cosmetic Act (21 U.S.C. 346a)."

                     Under FIFRA section 6(a)(2), after a pesticide is registered, the registrant
                     must also notify EPA of any additional facts and information concerning
                     unreasonable adverse environmental effects of the pesticide. Also, if EPA
                     determines that additional data are needed to support a registered pesticide,
                     registrants may be requested to provide additional data. If EPA determines
                     that the registrant(s) did not comply with their request for more information,
                     the registration can be suspended under FIFRA section 3(c)(2)(B).

                     Use Restrictions
                     As a part of the pesticide registration, EPA must classify the product for
                     general use, restricted use, or general for some uses and restricted for others
                     (Miller, 1993). For pesticides that may cause  unreasonable adverse effects
                     on the environment, including injury to the applicator, EPA may require that
                     the pesticide be applied either by or under the direct supervision of a certified
                     applicator.

                     Reregistration
                     Due  to  concerns that much  of  the safety data underlying pesticide
                     registrations becomes outdated and inadequate, in addition to providing that
                     registrations be reviewed every 15 years, FIFRA requires EPA to reregister
                     all pesticides that were registered prior to 1984 (section 4). After reviewing
                     existing data, EPA may approve the reregistration, request additional data to
                     support the registration, cancel, or suspend the pesticide.

                     Tolerances and Exemptions
                     A tolerance is the maximum amount of pesticide residue that can be on a raw
                     product and still be considered safe.  Before EPA can register a pesticide that
                     is used on raw agricultural products, it must grant a tolerance or exemption
                     from a tolerance (40 CFR Parts 163.10 through 163.12).  Under the Federal
                     Food, Drug, and Cosmetic Act (FFDCA), a raw  agricultural product is
                     deemed unsafe if it contains a pesticide residue, unless the residue is within
                     the limits  of a tolerance  established by EPA or is  exempt  from the
                     requirement.

                     Cancellation and Suspension
                     EPA  can cancel a registration if it is  determined that the pesticide  or its
                     labeling does not comply with the  requirements  of FIFRA or causes
                     unreasonable adverse effects on the environment (Haugrud,  1993).

                     In cases where EPA believes that an "imminent hazard" would exist if a
                     pesticide were to continue to be used through the cancellation proceedings,
                     EPA may suspend the pesticide registration through an order and thereby halt
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                    the sale, distribution, and usage of the pesticide. An "imminent hazard" is
                    defined as an unreasonable adverse effect on the  environment or an
                    unreasonable hazard to the survival of a threatened or endangered species that
                    would be the likely result of allowing continued use of a pesticide during a
                    cancellation process.

                    When EPA believes an emergency exists that does not permit a hearing to be
                    held prior to suspending, EPA can issue an emergency order which makes the
                    suspension immediately effective.

                    Imports and Exports
                    Under FIFRA section 17(a),   pesticides not registered  in the U.S. and
                    intended solely for export are not required to be registered provided that the
                    exporter obtains and submits to EPA, prior to export, a statement from the
                    foreign purchaser acknowledging that the purchaser is aware that the product
                    is not registered in the United States and cannot be sold for use there. EPA
                    sends these statements to the government of the importing country. FIFRA
                    sets forth additional requirements that must be met by pesticides intended
                    solely for export. The enforcement policy for exports is codified at 40 CFR
                    Parts  168.65, 168.75, and 168.85.

                    Under FIFRA section 17(c), imported pesticides and devices must comply
                    with U.S. pesticide law.  Except where exempted by regulation or statute,
                    imported pesticides must be registered.   FIFRA section 17(c) requires that
                    EPA be notified of the arrival of imported pesticides and devices.  This is
                    accomplished through the Notice of Arrival (NO A) (EPA Form 3540-1),
                    which is filled out by the importer prior to importation and submitted to the
                    EPA regional office applicable to the intended port of entry. U.S. Customs
                    regulations prohibit the importation of pesticides without a completed NO A.
                    The  EPA-reviewed and  signed form  is returned to the importer for
                    presentation to U.S. Customs when the shipment arrives in the U.S.  NO A
                    forms can be obtained from contacts  in the  EPA Regional Offices or
                         . epa. sov/oppfeadl/international/noalist. htm.
                    Additional information on FIFRA and the regulation of pesticides can be
                    obtained from a variety of sources, including EPA's Office of Pesticide
                    Programs www. epa. gov/pesticides, EPA 's Office ofQompliance, Agriculture
                    and Ecosystem Division  es. epa. gov/oeca/agecodiv. htm, or  The National
                    Agriculture  Compliance  Assistance   Center,   (888)   663-2155  or
                    es. epa. gov/oeca/as.   Other  sources  include  the  National Pesticide
                    Telecommunications  Network,   (800)  858-7378,   and  the National
                    Antimicrobial Information Network, (800) 447-6349.
       Toxic Substances Control Act
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                    The Toxic Substances Control Act (TSCA) granted EPA authority to create
                    a regulatory framework to collect data on chemicals in order to evaluate,
                    assess, mitigate, and control risks which may be posed by their manufacture,
                    processing, and use. TSCA provides a variety of control methods to prevent
                    chemicals from posing unreasonable risk.  It is important to  note that
                    pesticides as defined in FIFRA  are not included  in the definition of a
                    "chemical substance" when manufactured,  processed, or distributed in
                    commerce for use as a pesticide.

                    TSCA standards may apply at any point during a chemical's life cycle.  Under
                    TSCA section 5, EPA has established an inventory of chemical substances.
                    If a chemical is not already on the inventory, and has not been excluded by
                    TSCA, a premanufacture notice (PMN) must be submitted to EPA prior to
                    manufacture or import.  The PMN must identify the chemical and provide
                    available information on health and environmental effects. If available data
                    are not sufficient to evaluate  the chemical's effects,  EPA can impose
                    restrictions pending the development  of information on its health and
                    environmental effects.   EPA can also restrict significant  new uses  of
                    chemicals based upon factors such as the projected  volume and use  of the
                    chemical.

                    Under TSCA section 6, EPA can ban the manufacture or distribution in
                    commerce,  limit the  use, require labeling, or place other restrictions on
                    chemicals that pose unreasonable risks. Among the chemicals EPA regulates
                    under section 6 authority are asbestos, chlorofluorocarbons (CFCs), lead, and
                    polychlorinated biphenyls (PCBs).

                    Under TSCA section  8(e), EPA requires the producers and importers (and
                    others) of chemicals to report information on a chemicals' production, use,
                    exposure, and risks. Companies producing and importing chemicals can be
                    required to report unpublished health and safety studies on listed chemicals
                    and to collect and record any allegations of adverse reactions or any
                    information indicating that a substance may pose a substantial risk to humans
                    or the environment.

                    EPA's TSCA Assistance Information Service, at (202) 554-1404, answers
                    questions and distributes guidance pertaining to Toxic Substances Control
                    Act standards. The Service operates from 8:30 a.m. through 4:30'p.m., EST,
                    excluding federal holidays.

             Coastal Zone Management Act

                    The Coastal Zone Management Act (CZMA) encourages states/tribes to
                    preserve, protect, develop, and where possible, restore or enhance valuable
                    natural coastal resources such as wetlands, floodplains, estuaries, beaches,
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                    dunes, barrier islands, and coral reefs, as well as the fish and wildlife using
                    those habitats. It includes areas bordering the Atlantic, Pacific, and Arctic
                    Oceans, Gulf of Mexico, Long Island Sound, and Great Lakes.  A unique
                    feature of this law is that participation by states/tribes is voluntary.

                    In the  Coastal Zone  Management Act Reauthorization Amendments
                    (CZARA) of 1990, Congress identified nonpoint source pollution as a major
                    factor in the continuing degradation of coastal waters.  Congress also
                    recognized that effective solutions to nonpoint source pollution could be
                    implemented at the state/tribe and local levels. In CZARA, Congress added
                    Section 6217 (16 U.S.C. section 1455b), which calls upon states/tribes with
                    federally-approved coastal  zone management  programs to develop  and
                    implement coastal nonpoint pollution control programs. The Section 6217
                    program is administered at the federal level jointly by EPA and the National
                    Oceanic and Atmospheric Agency (NOAA).

                    Section 6217(g) called for  EPA, in consultation with other agencies, to
                    develop guidance on "management measures" for sources of nonpoint source
                    pollution in coastal  waters. Under Section  6217, EPA is responsible for
                    developing technical guidance to assist states/tribes in designing coastal
                    nonpoint pollution control programs. On January 19, 1993, EPA issued its
                    Guidance Specifying Management Measures For  Sources of Nonpoint
                    Pollution in Coastal Waters, which addresses five major source categories of
                    nonpoint pollution:  (1)  urban runoff, (2) agriculture runoff, (3) forestry
                    runoff, (4) marinas and recreational boating,  and (5) hydromodification.

                    Additional information on coastal zone management may be obtained from
                    EPA's Office ofWetlands, Oceans, and Watersheds, www. epa. gov/owow, or
                    from the Watershed Information Network www. epa. gov/win.  The NOAA
                    •website, MWW. nos. noaa. gov/ocrm/czm/, also contains additional information
                    on coastal zone management.
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VLB. Industry Specific Requirements

                    The onshore and offshore segments of the oil and gas extraction industry are
                    subject to different sets of regulations. Onshore, releases primarily are under
                    the authority of EPA. Federal land leases are managed by the Bureau of Land
                    Management (BLM) in the Department of the Interior (DOT).  States  also
                    impose regulations and play a crucial role in exploration and production solid
                    waste regulation because of the RCRA exemption.  Offshore, on the Outer
                    Continental Shelf (OCS), the Minerals Management Service (MMS) of DOI
                    is the designated regulatory agency. MMS oversees leasing operations and
                    shares responsibility for environmental regulation with EPA.

                    Because of these differences, onshore and offshore regulations are discussed
                    in separate sections. In addition, regulatory differences associated with
                    stripper wells (wells that produce less  than 10 barrels of oil per day)  and
                    selected state regulations are presented.

      VI.B.1.  Onshore Requirements

      Laws Regulating Oil and Gas Exploration and Production on Federal Lands

                    Many regulations controlling the location of onshore oil and gas production
                    stem from the Federal Land Policy and Management Act (FLPMA) of 1 976.
                    Production is barred at national monuments, national rivers, and areas of
                    critical environmental concern.  On Federal land where oil production is
                    allowed, the Bureau of Land Management (BLM), under the Department of
                    the Interior (DOI), is authorized under 43 CFR Parts 3 160-92 to regulate the
                    siting,  drilling and production activities; an exception is oh lands within the
                    National Forest System, where BLM must obtain the consent of the Secretary
                    of Agriculture.  Oil and gas production regulation is achieved through the
                    distribution of leases and the issuance of drilling permits.  Most procedures
                    are established under the Federal Oil and Gas Leasing Reform Act of 1987.
                    Included in this Act are bonding regulations, presented in 43 CFR Part 3 1 04,
                    that require submission of a surety or personal bond to ensure compliance
                    with requirements for the plugging of wells, reclamation of the leased areas,
                    and restoration of any lands or surface waters adversely  affected by lease
                    operations. The BLM is revising its regulations.  A proposed rule was
                    promulgated in early 1999.

                    National Environmental Policy Act
                    NEP A requires that all Federal agencies prepare detailed statements assessing
                    the environmental impact of, and alternatives to, major Federal actions that
                    may "significantly affect" the environment.  An environmental impact
                    statement (EIS)  must provide a fair and  full discussion of significant
                    environmental impacts and inform both decision-makers and the public about
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                    the reasonable alternatives that would avoid or minimize adverse impacts on
                    the environment; EISs must explore and evaluate all reasonable alternatives,
                    even if they are not within the authority of the lead agency. NEP A authorities
                    are solely procedural; NEPA cannot compel selection of the environmentally
                    preferred alternative.  For offshore operations new sources require NEPA
                    analysis.

                    Federal actions specifically related to oil and gas exploration and production
                    that may require EISs include Federal land management agency (e.g., BLM
                    and  Forest Service) approval of plans of operations for  exploration or
                    production on Federally-managed lands. All affected media (e.g., air, water,
                    soil, geologic, cultural, economic resources, etc.) must be addressed. The EIS
                    provides the basis for the permit decision; for example, an NPDES permit
                    may be issued or denied based on EPA's review of the overall impacts, not
                    just discharge-related impacts, of the proposed  project and alternatives.
                    Issues may include the potential for surface or groundwater contamination,
                    aquatic and  terrestrial  habitat value and  losses,  sediment  production,
                    mitigation, and reclamation.

       Clean Air Act (CAA)

                    The oil and  gas  production industry is  subject to recently-promulgated
                    National Emission Standards for Hazardous Air  Pollutants  (NESHAP)
                    (Federal Register, Vol. 64, No. 116, June 17,1999).  The regulation calls for
                    the application of maximum achievable control technology (MACT) in order
                    to reduce  the emissions of hazardous air  pollutants (HAP)  at  facilities
                    classified as major sources. The primary HAPs released by the industry are
                    benzene, toluene, ethyl benzene, and mixed xylenes (BTEX) and n-heptane.
                    The technology requirements involve the following emission points: process
                    vents on glycol dehydration units, storage vessels with flash emissions, and
                    equipment leaks at natural gas processing plants.  Additional requirements
                    include the installation of air emission control devices, and adherence to test
                    methods and procedures, monitoring and inspection requirements,  and
                    recordkeeping and reporting requirements.

                    In  addition,  New  Source  Performance  Standards  (NSPS)  may affect
                    exploration and production facilities: Standards apply to devices used at
                    these facilities, including gas turbines, steam generators, storage vessels for
                    petroleum liquids, volatile organic liquid storage vessels, and gas processing
                    plants (see 40 CFR Part 60).  Requirements will depend on whether the
                    region in which the particular facility is located is  in compliance with the
                    National Ambient Air Quality Standards (NAAQS) and whether Prevention
                    of Significant Deterioration (PSD) requirements apply (EPA, 1992).
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        Clean Water Act
                     Onshore exploration and production facilities may be subject to four aspects
                     of the CWA: national effluent limitation guidelines, stormwater regulations,
                     and wetlands regulations, and Spill Prevention Control and Countermeasure
                     (SPCC) requirements.

                     National effluent limitation guidelines have been issued for two subcategories
                     of onshore  (non-stripper) wells.   The  Onshore Subcategory guidelines
                     prohibit the discharge of water pollutants from any source associated with
                     production, field exploration, drilling, well completion, or well treatment (40
                     CFR Part 435.30).   Agriculture and  Wildlife Water Use  Subcategory
                     guidelines apply to facilities in the continental United States west of the 98th
                     meridian for which produced water may be used beneficially for irrigation or
                     wildlife propagation. For facilities in this Subcategory, produced water may
                     be discharged into navigable waters so long as it does not exceed limitations
                     for oil and grease, and is put to use for agricultural purposes. Discharge of
                     waste pollutants excluding produced water is prohibited (40 CFR Part
                     435.50).

                     Oil and gas exploration and production facilities are exempt from  CWA
                     stormwater Phase I regulations under most conditions, but there are two
                     exceptions: (1) if the facility has a reportable quantity spill that could be
                     carried to waters of the United States via a storm event, or (2)  if the
                     stormwater runoff violates a water quality standard. (See 40 CFR Parts 117
                     and/or 302 for reportable quantities of hazardous substances or Part 110 for
                     the reportable quantity of spilled oil.) If either of these two scenarios should
                     happen, the facility would be required to apply for a Multi-Sector General
                     Permit (MSGP) stormwater permit and develop a pollution prevention plan.
                     However, if a reportable quantity spill  were to be cleaned up quickly or
                     containment were so total that there would be no threat of a product release
                     as a result of storm water event, there would be no permit requirement.  In
                     addition,  coverage  is mandatory under  the  Construction General Permit
                     (CGP) for earth-disturbing activities of five acres or more. This is  relevant
                     during exploration or site expansion efforts  (EPA Region VI Stormwater
                     Hotline, 1999; Rittenhouse, 1999). See Section VI.C. for proposed  Phase II
                     regulations that may impact the industry.

                     Wetlands
                     During the course of petroleum exploration wetlands may be encountered.
                     Under the CWA wetlands are defined by the frequency and length of time
                     they are saturated with water, by the type of vegetation they support, and by
                     soil characteristics. Also by definition wetlands are part of the "waters of the
                     United States" and as such all discharges of pollutants to wetlands require a
                     CWA permit.  However, the CWA regulates  not only the discharges of
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                     dissolved pollutants but also the discharge of solids, dredge and fill materials
                     or dirt to waters of the United States. Permits are required for the filling of
                     wetlands (dredging is regulated under the 1899 Rivers and Harbors Act).
                     Permits are of two types: general (a standard permit for certain classes of
                     activities) or site-specific.

                     Enforcement of the CWA provisions for wetlands is overseen by the Army
                     Corps of Engineers, EPA and in some cases the States.  Most of the day to
                     day administration of the program is implemented by the Corps of Engineers
                     (COE). The COE issues and enforces permits, and is also responsible for
                     delineating wetlands.  EPA regions comment on permits  and can enforce the
                     provisions of the Act. EPA also helps to develop environmental criteria for
                     wetlands.  The COE can approve a state to operate the  CWA wetlands
                     program (only Maryland and New  Jersey are currently approved). If a state
                     is authorized to operate the CWA wetlands program it may issue a permit in
                     addition to the  COE issued permit. Any state can comment  on wetland
                     permits prior to issuance.

                     Spill Prevention Control and Countermeasure Plans
                     An oil and gas production, drilling, or workover facility will be subject to
                     Spill Prevention Control and Countermeasure (SPCC) requirements if it
                     meets the following specifications: the facility could reasonably be expected
                     to discharge oil into  or upon the navigable waters of the United States or
                     adjoining shorelines, and have (1) a total underground buried storage capacity
                     of more than 42,000 gallons; (2) a  total aboveground oil storage capacity of
                     more than 1,320 gallons; or (3) an aboveground oil storage capacity of more
                     than 660 gallons in a single container.  SPCC applicability is dependent on
                     the tank's maximum design storage volume and not "safe" operating or other
                     lesser operational volumes.  For  purposes of the regulation,  an onshore
                     production facility may include all wells, flowlines, separation equipment,
                     storage facilities, gathering lines,  and auxiliary non-transportation-related
                     equipment and facilities in a single geographical oil or gas field operated by
                     a single operator.

                     All facilities subject to SPCC requirements must prepare a site-specific spill
                     prevention plan that incorporates requirements specified in 40 CFR Part
                     112.7.  For production facilities, these include considerations  for the
                     following processes and procedures:

                     •      Drainage
                     •      Tank materials
                     •      Secondary containment
                     •      Visual inspection of tanks
                     •      Fail-safe engineering methods for tank battery installations
                     •      Tank repair and maintenance
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                            Facility transfer operations
                            Inspection and testing measures
                            Record-keeping
                            Security
                            Personnel training.
                     In addition, the plan must discuss spill history and spill prediction (i.e., the
                     anticipated direction of flow).  The SPCC plan must be approved by a
                     Registered Professional Engineer who is familiar with SPCC requirements,
                     be fully implemented, and be modified when changes are made to the facility
                     (e.g., installation of a new tank). Regardless of whether changes have been
                     made to the facility, the plan must be reviewed at least once every three years,
                     and amended if new, field-proven technology may reduce the likelihood of
                     a spill.

                     The SPCC plan must also address oil  drilling  and workover facility
                     equipment. This portion of the plan requires that the equipment be positioned
                     or located so as to prevent spilled oil from reaching navigable waters, that
                     catchment basins or diversionary structures be in place, and that blowout
                     preventers (BOPs) are installed according to state regulatory requirements.

                     A portion of SPCC-regulated facilities may also be  subject to Facility
                     Response Planning (FRP) requirements if they pose a threat of "substantial
                     harm" to navigable waters. The determination of a "substantial harm" facility
                     is made on the basis of meeting either of two sets of criteria — one involving
                     transfer over water, and the other involving oil  storage capacity or other
                     factors. If the facility were subject to FRP requirements, it would be required
                     to develop a facility response plan which would involve, among other
                     requirements, identification of small, medium  and worst-case discharge
                     scenarios  and  response actions;  a description of discharge detection
                     procedures and equipment; detailed implementation plans for containment
                     and disposal; diagrams of facility and surrounding layout, topography, and
                     evacuation paths; and employee training, exercises,  and drills.
       Safe Drinking Water Act (SDWA)
                    The Underground Injection Control (UIC) program of the SDWA regulates
                    injection wells used in the oil and gas production process for produced water
                    disposal or for enhanced recovery. Wells used in this industry for produced
                    water are classified as Class II. Minimum UIC Class II well requirements, as
                    outlined in 40 CFR Part 144, involve specific construction, operation, and
                    closure standards, as well as provisions for ensuring that the owner, operator
                    and/or transferor of the well maintain financial responsibility and resources
                    to plug  and abandon the well.   Included are casing and  cementing
                    requirements based on the depth to the injection zone, location of aquifers,
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                    and estimated injection pressures as well as other possible considerations.
                    Operational standards  involve regular (at least once every five  years)
                    mechanical integrity tests (MITs); monitoring of injection pressure, flow rate,
                    and volume; monitoring of the nature of injected fluid as needed; and annual
                    reporting  of monitoring results.   Finally,  closure procedures must be
                    performed in accordance with an approved plugging and abandonment plan,
                    which includes the placement and composition of cement plugs, the amount
                    of casing  to be left in the hole, the estimated cost of plugging, and any
                    proposed tests or measurements. Additional requirements may be imposed
                    in states that have been delegated implementation of the UIC program.

       Comprehensive Environmental Response, Compensation and Liability Act (CERCLA)

                    The  "petroleum  exclusion" is  an important exemption under CERCLA
                    requirements for the oil and gas extraction industry.  Under the "hazardous
                    substance" definition,  "petroleum, including  crude oil  or  any fraction
                    thereof," is exempted unless specifically listed or designated under CERCLA
                    (CERCLA section 101 (14)). Subsequent interpretation has concluded that
                    listed hazardous  substances that are normally found in crude oil, such as
                    benzene, do not invalidate the exemption unless the concentration of these
                    substances is increased by contamination or by addition after refining.
                    However, specifically listed waste oils (e.g., F010, and K042 through K048)
                    are subject to reporting requirements if spilled in excess of their established
                    Reportable Quantities (RQs) (EPA, 1998).

       Emergency Planning and Community Right-to-Know Act (EPCRA)

                    The oil and gas extraction industry is currently not required to report to TRI
                    under EPCRA section 313, which requires facilities under certain SIC codes
                    to submit annual  reports  of toxic chemical releases to the Toxic Release
                    Inventory (TRI).   (Please see  Section  VI.C., Pending and  Proposed
                    Regulatory Requirements, of this document, however, for possible future
                    changes to  this  status.)  However, oil and gas extraction  facilities are
                    generally responsible for other reporting obligations of EPCRA if the facility
                    stores or manages threshold levels of specified chemicals.

       Resource Conservation and Recovery Act (RCRA)

                    Under the 1980 Amendments to RCRA, Congress conditionally exempted
                    certain categories of solid waste from regulation as hazardous wastes under
                    RCRA Subtitle C including drilling fluids, produced waters, and other wastes
                    associated with the exploration, development, or production of crude oil or
                    natural  gas.  The Amendments required  EPA  to  study these wastes to
                    determine whether their regulation as hazardous wastes was warranted and
                    to submit a report to Congress. In its report to Congress and in a July 1988
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                    regulatory determination (53 FR 25446, July 6,1988), the Agency stated that
                    regulation as hazardous wastes under Subtitle C was not warranted and that
                    these wastes could be controlled under other federal and state regulatory
                    programs including a tailored RCRA Subtitle D program.

                    Specifically, EPA's regulatory determination for exploration and production
                    (E&P) wastes found that the following wastes  are exempt from RCRA
                    hazardous waste management requirements. The list below identifies many,
                    but not all, exempt wastes.  In general, E&P exempt wastes are generated in
                    "primary  field operations,"  and not  as a  result  of maintenance or
                    transportation activities. Exempt wastes are typically limited to those that are
                    intrinsically related to the production of oil or natural gas.

                    •      Produced water;
                           Drilling fluids;
                    •      Drill cuttings;
                    •      Rigwash;
                    •      Drilling fluids and cuttings from offshore operations disposed of
                           onshore;
                    •      Well completion, treatment, and stimulation fluids;
                    •      Basic sediment and water, and other tank bottoms from storage
                           facilities that hold product and exempt waste;
                    «      Accumulated materials such as hydrocarbons, solids, sand, and
                           emulsion from production separators,  fluid treating vessels, and
                           production impoundments;
                    •      Pit sludges and contaminated bottoms from storage or disposal of
                           exempt wastes;
                    •      Wbrkover wastes;
                    •      Gas plant sweetening wastes for sulfur removal, including amine,
                           amine filters, amine  filter media, backwash,  precipitated  amine
                           sludge, iron sponge, and hydrogen sulfide scrubber liquid and sludge;
                    •      Cooling tower blowdown;
                           Spent filters, filter media, and backwash (assuming the filter itself is
                           not hazardous and the residue in it is from an exempt waste stream);
                    •      Packing fluids;
                    •      Produced sand;
                    •      Pipe scale, hydrocarbon solids, hydrates, and other deposits removed
                           from piping and equipment prior to transportation;
                           Hydrocarbon-bearing  soil;
                    •      Pigging wastes from gathering lines;
                    •      Wastes from subsurface gas storage and retrieval, except for the listed
                           non-exempt wastes;
                    •      Constituents removed from produced water before it is injected or
                           otherwise disposed of;
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                    •      Liquid hydrocarbons removed from the production stream but not
                           from oil refining;
                    •      Gases removed from the production stream, such as hydrogen sulfide
                           and carbon dioxide, and volatilized hydrocarbons;
                    •      Materials ej ected from a producing well during the process known as
                           blowdown;
                           Waste crude oil from primary field operations and production; and
                    •      Light organics volatilized from exempt wastes  in reserve pits or
                           impoundments or production equipment.

                    On March 22,1993, EPA provided "clarification" regarding the scope of the
                    E&P waste exemption for waste streams generated by crude oil and  tank
                    bottom reclaimers, oil and gas service companies, crude oil pipelines, and gas
                    processing plants and their associated field gathering lines.  (See 58 FR
                    15284-15287.) EPA stated that certain waste streams from these operations
                    are "uniquely associated" with  primary field operations and as such are
                    within the scope of the RCRA Subtitle C exemption.  EPA's clarification
                    cautioned, however, that these wastes may not be exempt if they are mixed
                    with non-exempt materials or wastes.

                    EPA's 1988 regulatory determination lists the following wastes as non-
                    exempt.  The list below identifies many, but not all non-exempt wastes, as
                    well as transportation (pipeline and trucking) activities.  While the following
                    wastes are non-exempt, their regulatory status as "hazardous wastes"  is
                    dependent upon a determination of their characteristics or whether they are
                    specifically listed as RCRA hazardous waste.

                    •      Unused fracturing fluids  or acids;
                    •      Gas plant cooling tower cleaning wastes;
                    •      Painting wastes;
                    •      Oil and gas service company wastes, such as empty drums, drum
                           rinsate, vacuum truck rinsate, sandblast media, painting wastes, spent
                           solvents, spilled chemicals, and waste acids;
                    •      Vacuum truck and drum rinsate from trucks and drums transporting
                           or containing non-exempt waste;
                    •      Refinery wastes;
                    •      Liquid and solid wastes  generated by crude oil and tank bottom
                           reclaimers;
                    •      Used equipment lubrication oils;
                    •      Waste compressor oil, filters, and blowdown;
                    •      Used hydraulic fluids;
                    •      Waste solvents;
                    •      Waste in transportation pipeline-related pits;
                    •      Caustic or acid cleaners;
                    •      Boiler cleaning wastes;
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                     •      Boiler refractory bricks;
                            Incinerator ash;
                     •      Laboratory wastes;
                     •      Sanitary wastes;
                     •      Pesticide wastes;
                            Radioactive tracer wastes; and
                     •      Drums, insulation, and miscellaneous solids.

                     EPA did not specifically address, in its 1988 regulatory determination, the
                     status of hydrocarbon-bearing material that is recycled or reclaimed by
                     reinjection into a crude stream. However, under existing EPA regulations,
                     recycled oil, even if it were otherwise hazardous, could be reintroduced into
                     the crude stream, if it is from normal operations and is to be refined along
                     with normal process streams at a petroleum refinery facility  (40 CFR Part
                     261.6 (a)(3)(vi).)

                     The Agency also determined that produced water injected for enhanced
                     recovery is not a waste for purposes of RCRA regulation and therefore is not
                     subject to control under RCRA Subtitle C or Subtitle D. Produced water used
                     in this manner is considered beneficially recycled and is an integral part of
                     some crude oil and natural gas production processes. Produced water injected
                     in this manner is already regulated by the Underground Injection Control
                     program under the SDWA. However, if produced water is stored in surface
                     impoundments prior to injection, it may be subject to RCRA Subtitle D
                     regulations.

                     It is important to note that some states have  adopted hazardous waste
                     regulations  which differ from those that EPA has promulgated.  While
                     different in many specific areas, those state programs, by law, still must be
                     at least as stringent as the federal programs.

       Endangered Species Act (ESA)

                     The ESA provides a means to protect threatened or endangered species and
                     the ecosystems that support them. It requires Federal agencies to ensure that
                     activities undertaken on either Federal or non-Federal property do not have
                     adverse impacts on threatened or endangered species or their habitat.  In a
                     1995 ruling, the U.S. Supreme Court upheld interpretations of the Act that
                     allow agencies to consider impact on habitat as a potential form of prohibited
                     "harm" to endangered species.  Agencies undertaking a Federal action (such
                     as a BLM or MMS review of proposed  oil and gas extraction production
                     operations) must consult with the U.S. Fish and Wildlife Service, and an EIS
                     must be prepared if "any major part of a new source will have significant
                     adverse effect on the habitat" of a Federally- or State-listed threatened or
                     endangered  species.
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       VI.B.2. Offshore Requirements
                     This section describes laws and regulations applying to offshore production
                     facilities that differ from those presented above for onshore facilities. It
                     should be noted that several regulations presented in the onshore section will
                     apply to offshore sites as well. Offshore facilities are: 1) those which are
                     found within the Federal jurisdiction of the Outer Continental Shelf and are
                     operated under Minerals Management Service (MMS) leases, and 2) those
                     that are found in territorial seas and are operated under state leases. Facilities
                     in the territorial seas are operated under both state and federal regulations and
                     therefore some regulations discussed below may not be applicable.  In
                     addition,  coastal facilities, which  are  generally landward of the inner
                     boundary of the territorial seas (approximated by the shoreline) are operated
                     under state regulations and therefore some regulations discussed below may
                     not be applicable.

       Offshore Jurisdictions

                     The Outer Continental Shelf (OCS) consists of the submerged lands, subsoil,
                     and seabed, lying between the seaward extent of the states' jurisdiction and
                     the seaward extent of federal jurisdiction. The continental shelf is the gently
                     sloping undersea plain between a continent and the deep ocean. The United
                     States OCS has been divided into four leasing regions.  They are the Gulf of
                     Mexico Region, the Atlantic OCS Region, the Pacific OCS Region, and the
                     Alaska OCS Region.  State jurisdiction is defined as follows.  Texas and the
                     Gulf Coast of Florida are extended  3  marine leagues (approximately 9
                     nautical miles)  seaward from the baseline from which the breadth of the
                     territorial sea is measured. Louisiana is extended 3 imperial nautical miles
                     (imperial nautical miles are 6,080.2 feet) seaward of the baseline from which
                     the breadth of the territorial sea is measured. All other states' seaward limits
                     are extended 3 nautical miles (approximately 3.3 statute miles) seaward of the
                     baseline from which the breadth of the territorial sea is measured. Federal
                     jurisdiction is defined under accepted principals of international law.  The
                     seaward limit is defined as the farthest of 200 nautical miles seaward of the
                     baseline from which the breadth of the territorial sea is measured.

       Outer Continental Shelf Lands Act (OSCLA)

                     OCSLA establishes Federal jurisdiction over submerged lands on the Outer
                     Continental Shelf (OCS) and requires the Secretary  of the  Interior to
                     administer mineral leasing, exploration, and development on the OCS. Under
                     the Act, leases are granted to the highest qualified responsible bidder(s), on
                     the basis of sealed competitive bids.  Objectives  of the OCSLA include
                     allowing for expeditious and orderly development of OCS  resources,
                     encouraging the development of new technology to minimize the likelihood
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                     of accidents or events that might damage the environment or endanger life or
                     health, and ensuring that a State's regulatory protection for land, air, and
                     water uses are considered within its jurisdiction (MMS, 1999; National
                     Research Council, 1996).

                     In offshore locations, the production is limited under Title III of the Marine
                     Protection, Research, and Sanctuaries Act (MPRS A), which provides for the
                     designation of sanctuaries for areas of conservation, recreational, ecological,
                     or aesthetic value. The Marine Mammal Protection Act (MMPA) and the
                     Endangered Species Act (ESA) prohibit the taking of species, and can also
                     limit the placement of offshore wells.
        Clean Air Act
                     In offshore areas, both the CAA and regulations of the MMS govern air
                     quality. Coastal areas and the offshore regions of the Pacific, Atlantic, and
                     Arctic  Oceans, as well as the region of the Gulf of Mexico adjacent to
                     Florida, are subject to the CAA. Important regulations include the NESHAP
                     and NSPS standards described above for onshore facilities.

                     The sections of the Gulf of Mexico adjacent to Texas, Louisiana, Mississippi,
                     and Alabama are exempt from the 1990 CAA amendments, and instead must
                     adhere to MMS air quality standards.  These standards set limits for VOC,
                     CO, NO2, SO2, and Total Suspended Particulate (TSP) pollutants, and require
                     limits for sources that significantly affect the quality of a nonattainment area
                     (30 CFR Part 250.45).

                     Additional MMS air regulations apply to offshore sites. Blowout prevention
                     regulations (in the form of safety practices and equipment requirements)
                     attempt to reduce accidental releases. The venting and flaring of natural gas
                     is limited under MMS rules so that natural gas may be  released only when
                     required for safety or when the volume is small (Sustainable Environmental
                     Law and 30 CFR Part 250.175).
       Clean Water Act
                    In offshore locations, facilities must acquire National Pollutant Discharge
                    Elimination System (NPDES) permits before any pollutant can be discharged
                    from a point source in U.S. waters.  Standards differ for the offshore and
                    coastal subcategories. For offshore facilities, permits require the use of best
                    available technology economically achievable (BAT) or best conventional
                    pollutant control technology (BCT). Discharges from coastal facilities, which
                    are landward  of the  inner boundary  of .the  territorial seas,  are  mostly
                    prohibited (Jordan, 1998; note that the definition of the coastal category for
                    the purposes of the CWA is different than that, for mineral rights, presented
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                     in Section II).  An exception to the coastal discharge prohibition is for
                     facilities in Cook Inlet, Alaska, where discharges may be made in accordance
                     with BPT, BAT, or BCT effluent limitations.

                     Facilities located offshore of EPA Region 6 (and some in Regions 9 and 10)
                     are  subject to a general CWA permit that covers all facilities in certain
                     geographic locations.  Offshore  exploration and production facilities in
                     Regions 4, 9 and  10 are also permitted individually in some cases.  EPA
                     Regions 6 and 9 have an MOA with MMS whereby MMS agrees to conduct
                     CWA preliminary inspections for EPA.

                     In addition to NPDES permitting requirements, offshore facilities may be
                     subject to CWA Section 403.  This section is intended to ensure that no
                     unreasonable degradation of the marine environment occurs as a result of
                     permitted discharges, and to ensure that sensitive ecological communities are
                     protected.  Requirements may involve ambient  monitoring programs to
                     determine degradation of marine waters, alternative assessments designed to
                     further evaluate the consequences of various disposal options, and pollution
                     prevention techniques designed to further reduce the quantities of pollutants
                     requiring disposal and thereby reduce the potential for harm to the marine
                     environment. If section 403 requirements for protection of the ecological
                     health of marine waters are not met, an NPDES permit will not be issued.

       Spill Prevention Control and Countermeasure Plans

                     Many aspects of SPCC rule described above for onshore facilities apply to
                     offshore facilities as well. 40 CFR Part 112.7(e)(7) provides additional spill
                     prevention and control measures to be addressed in SPCC plans for offshore
                     facilities.  These include:

                     •      Oil drainage collection equipment around pumps, joints, valves,
                            separators, tanks, etc.
                     •      Adequately-sized sump systems
                     •      Dump valves installed with oil-water separators and treaters
                     •      High-level sensing devices  for  atmospheric  storage tanks and
                            corrosion protection for all tanks
                     •      High pressure  sensing device  and shut-in valve for pipelines
                            appurtenant to the facility.

        Oil Spill Contingency Plans

                     Pursuant to 30 CFR 250.203,250.204 and 254, a lessee is required to submit
                     an  Oil Spill Contingency Plan (OSCP) to MMS for approval.  This plan
                     identifies the response capabilities of lease and pipeline operators in the event
                     an  accidental  oil spill  occurs during  drilling  or  production activities.
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                     Additionally, the Oil Pollution Act of 1990 authorizes the MMS to require
                     Oil Spill Contingency Plans from oil and gas lessees operating in state waters
                     seaward of the coastline.  Operators must join a cooperative with oil spill
                     equipment available to members, or obtain a letter of agreement for rental of
                     oil spill equipment.  Oil Spill Coordinators must be trained.  The entire Oil
                     Spill Response Team must attend annual drills. The Plan requires annual
                     review and update.

       VI.B.3. Stripper Well Requirements

                     Stripper wells are identified as an individual subcategory in Clean Water Act
                     NPDES requirements.  In addition,  stripper wells may be exempt from
                     requirements under other  statutes or regulations by virtue of their low
                     production volume. For example, they may not meet the threshold of a major
                     source of HAP for NESHAP requirements,  or they may have less than the
                     specified storage volume for SPCC rules. States and Federal agencies may
                     also provide incentives to stripper well operators to maximize the number of
                     these marginally profitable wells that remain operational. Reductions of
                     severance taxes  are available in some states, and BLM offers royalty rate
                     reductions for qualifying stripper wells (Williams and Meyers, 1997; 43 CFR
                     Part 3103.4-2).
       Clean Water Act
                     Stripper wells are defined as onshore wells that produce less than 10 barrels
                     of oil per day, are operating at the maximum feasible rate of production, and
                     operate in accordance with recognized conservation practices (40 CFR Part
                     435.60)  They are currently exempt from onshore point source discharge
                     restrictions discussed above in Section VLB. 1. As a result, technology-based
                     limitations instead are developed on a case-by-case basis or in a state-wide
                     general permit.
       VI.B.4. State Statutes
                    In addition to the federal laws described above, most oil-producing states
                    develop other laws affecting oil and gas extraction and production. These
                    include permitting, bonding, temporary abandonment, and plans for plugging
                    orphan wells. Each oil-producing state has a regulatory body, and most
                    require operators to obtain  a well  permit  before drilling.  Historically,
                    permitting has been required in these places in order to ensure an efficient
                    and safe mechanism for withdrawing oil from reservoirs by preventing wells
                    from being drilled too close together (Williams and Meyers, 1997).

                    Nearly all oil-producing states require some form of security or financial
                    assurance for those operators seeking a permit,  in order  to ensure proper
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                    plugging and abandonment. The form of assurance varies from state to state,
                    but the most commonly accepted are surety bonds, certificates of deposit, and
                    cash.  The amount of money required for security can vary as well; the
                    amounts range from $10,000 in Kentucky and Tennessee to a minimum of
                    $200,000 in Alaska (IOGCC, 1996).

                    Laws for temporary abandonment of wells differ among states. (See Section
                    III.B. for a discussion of temporary abandonment.)  In general, States are
                    reluctant to require plugging of wells that have significant potential for oil
                    production (and state revenues), yet they seek to avoid problems associated
                    with inactive and unattended wells. As a result, most states require inactive
                    wells to gain state approval for temporary  abandonment.  (The ter,m
                    temporary abandonment is used  for wells that are  inactive with state
                    approval.) Most states allow some period of time of inactivity (usually six
                    months to one year) without approval. At this point, however, states may
                    require  a statement of future use from the operator; this statement  might
                    include extensive geological and engineering information and a schedule for
                    returning the well to production.  As part of a temporary abandonment
                    permit,  a state may require periodical mechanical integrity tests (MITs) to
                    ensure that the temporarily abandoned well does not pose a threat  to the
                    environment (IOGCC, 1996).

                    Finally, many states have established plugging funds to ensure that wells that
                    pose a threat to  the environment but are without financial assurance are
                    properly plugged. These wells, often called orphan wells (see Section III.C.),
                    are identified and prioritized by any number of methods, and are plugged as
                    funds become available and procurement issues are settled. Funding sources
                    vary among states; in some states,  such as Arkansas, California,  and
                    Mississippi, funding comes directly from the government's general fund or
                    from the regulatory body's budget, while in others the programs are funded
                    through permit fees, portions of oil taxes, bond forfeitures, or penalties
                    (IOGCC, 1996).

                    In 1990,  the  Interstate Oil and Gas  Compact Commission  (IOGCC)
                    developed guidelines for state oil and gas exploration and production waste
                    management program.  In 1991, IOGCC began  reviewing state programs
                    against the guidelines. State reviews were conducted by stakeholder teams.
                    Review teams wrote reports of their findings, including strengths and
                    weaknesses,  and made recommendations for  program  improvements.
                    Seventeen state programs were reviewed between 1991 and 1997.  These
                    reports are an excellent source of state-specific regulations and programs.
                    State reviews can be obtained from IOGCC by calling (405) 525-3556 and
                    from the IOGCC Website at www. iogcc. oklaosf. state, ok. us/. The state review
                    program has subsequently been managed by STRONGER, Inc., a non-profit
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                    corporation. For more information on IOGCC and STRONGER, Inc., see
                    Section VIII.A.2., State Activities.
VI.C. Pending and Proposed Regulatory Requirements

       Clean Water Act (CWA)

                    Proposed Phase IINPDES Storm Water Regulations
                    Under this proposal, construction sites between one and five acres would be
                    regulated  under the NPDES storm water program.   The  oil and gas
                    exploration and production industry might be  impacted by this rule during
                    onshore drilling site preparations.  Possible requirements  include: the
                    submission  of a Notice of Intent (NOT) that would include general
                    information and a certification that the activity will not impact endangered or
                    threatened species,  development and implementation of a Storm Water
                    Pollution Prevention Plan (S WPPP) and use of best management practices
                    (BMP) to minimize the discharge of pollutants from the site, and submission
                    of a Notice of Termination (NOT) when final stabilization of the site has
                    been achieved as defined in the permit. Finalization of the rule is anticipated
                    in November 1999 (George Utting, EPA, Office of Water, (202) 260-9530 or
                    John Kosco, EPA, Office of Water, (202) 260-6385).

                    Proposed Effluent Limitations Guidelines and Standards for Synthetic-Based
                    Drilling Fluids
                    This proposed rule would amend the technology-based effluent limitations
                    guidelines and standards for the discharge of pollutants from oil and gas
                    drilling operations associated with the use of synthetic-based drilling fluids
                    (SBFs) and other non-aqueous drilling fluids into the waters of the United
                    States. This proposed rule would apply to existing and new facilities in the
                    offshore subcategory and the Cook Inlet portion of the coastal subcategory of
                    the oil and gas extraction point source category. The final rule is scheduled
                    for December 2000. (Carey A. Johnston, EPA, Office of Water, (202)  260-
                    7186).

                    Revisions to the Oil Pollution Prevention Regulation
                    Three separate proposals, in  1991, 1993, and 1997, had been  offered to
                    amend the text of 40 CFR Part 112,  which includes requirements for sites to
                    develop spill prevention control  and countermeasures (SPCC) plans.  The
                    current proposed rule is a consolidation of the three proposals.  The goals of
                    the new rule are to give more flexibility with paperwork and to reduce the
                    burden of information collection for some facilities. Two considerations will
                    be emphasized during the rule development:  the importance of good
                    engineering practices and the value of site-specific flexibility. A final rule is
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                    expected during Spring, 2000. (Hugo Fleischman, EPA, Office of Solid
                    Waste and Emergency Response, (703) 603-8769).

      Emergency Planning and Community Right-To-Know Act (EPCRA)

                    Addition of Oil and Gas Exploration and Production to the Toxic Release
                    Inventory
                    A long-term consideration is the addition  of the oil and gas extraction
                    industry to regulation under EPCRA section 313, which requires reporting to
                    the Toxics Release Inventory (TRI).  The possible addition of the industry
                    was considered carefully in 1996, but was not added at that time.  The
                    proposal may enter the proposed rule stage in December, 2000, but no
                    definite schedule had been set at the time of the publication of this document.
                    (Tim Crawford, EPA, Office of Prevention, Pesticides, and Toxic Substances,
                    (202)260-1715).
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         Compliance and Enforcement History
VII. COMPLIANCE AND ENFORCEMENT HISTORY

       Background

                    Until recently, EPA  has  focused much of its attention on measuring
                    compliance with specific environmental statutes.  This approach allows the
                    Agency  to track  compliance with the Clean  Air Act,  the  Resource
                    Conservation  and  Recovery  Act,  the  Clean  Water Act,  and  other
                    environmental statutes. Within the last several years, the Agency has begun
                    to supplement single-media compliance  indicators with facility-specific,
                    multimedia indicators of compliance. In doing so, EPA is in a better position
                    to track compliance with all statutes at the facility level, and within specific
                    industrial sectors.                                         .

                    A major step in building the capacity to compile multimedia data for
                    industrial sectors was the creation of EPA's Integrated Data for Enforcement
                    Analysis (IDEA) system. IDEA has the capacity to "read into" the Agency's
                    single-media databases, extract compliance records, and match the records to
                    individual  facilities.   The IDEA system can  match Air,  Water,  Waste,
                    Toxics/Pesticides/EPCRA, TRI, and Enforcement Docket records for a given
                    facility, and generate a list of historical permit, inspection, and enforcement
                    activity. IDEA also has the capability to analyze data by geographic area and
                    corporate holder. As the capacity to  generate multimedia compliance data
                    improves,  EPA  will  make  available more  in-depth  compliance  and
                    enforcement information. Additionally, sector-specific measures of success
                    for compliance assistance efforts are under development.

       Compliance and Enforcement Profile Description

                    Using inspection, violation and enforcement data from the IDEA system, this
                    section provides information  regarding  the historical compliance  and
                    enforcement activity of this sector. In order to mirror the facility universe
                    reported in the Toxic Chemical Profile, the data reported within this section
                    consists of records only from the TRI reporting universe. With this decision,
                    the selection criteria are consistent across sectors with certain exceptions.
                    For the sectors that do not normally  report to the TRI program, data have
                    been provided from EPA's Facility Indexing System (FINDS) which tracks
                    facilities in all media databases. Please note, in this section, EPA does not
                    attempt to define the actual number of facilities that fall within each sector.
                    Instead, the section portrays the records of a subset of facilities within the
                    sector that are well  defined within EPA databases.

                    As a check on the relative size of the full  sector universe, most notebooks
                    contain an estimated number of facilities within the sector according to the
                    Bureau of Census  (See Section  II).   With sectors dominated  by small
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                    businesses, such as metal finishers and printers, the reporting universe within
                    the EPA databases may be small in comparison to Census data. However, the
                    group selected for inclusion in this data analysis section should be consistent
                    with this sector's general make-up.

                    Following this introduction is  a list defining each data column presented
                    within this section.  These values represent a retrospective summary of
                    inspections and enforcement actions, and reflect solely EPA, State, and local
                    compliance assurance activities that have been entered into EPA databases.
                    To identify any changes in trends, the EPA .ran two data queries, one for the
                    past five calendar years (April 1, 1992 to March 31, 1997) and the other for
                    the most recent twelve-month period (April 1,1996 to March 31,1997). The
                    five-year analysis gives an average level of activity for that period for
                    comparison to the more recent activity.

                    Because most inspections focus on single-media requirements, the data
                    queries presented in this section are taken from single media databases.
                    These databases do not provide data on whether inspections are state/local or
                    EPA-led. However, the table breaking down the universe of violations does
                    give the reader a crude measurement of the EPA's and states' efforts within
                    each media program. The presented data illustrate the variations across EPA
                    Regions for certain sectors.3 This variation may be attributable to state/local
                    data  entry variations, specific geographic concentrations,  proximity to
                    population centers, sensitive ecosystems, highly toxic chemicals used in
                    production, or historical noncompliance. Hence, the  exhibited data do not
                    rank regional performance or necessarily reflect which regions may have the
                    most compliance problems.

       Compliance and Enforcement Data Definitions

              General Definitions

                    Facility Indexing System (FINDS) — assigns a common facility number to
                    EPA single-media permit records. The FINDS identification number allows
                    EPA to compile and review all  permit, compliance, enforcement  and
                    pollutant release data for any given regulated facility.

                    Integrated Data for Enforcement Analysis (IDEA)  ~ is a data integration
                    system that can retrieve information from the major EPA program office
                    databases. IDEA uses the FINDS identification number to link separate data
3 EPA Regions include the following states: I (CT, MA, ME, RI, NH, VT); II (NJ, NY, PR, VI); III (DC, DE, MD,
PA, VA, WV); IV (AL, FL, GA, KY, MS, NC, SC, TN); V (IL, IN, MI, MN, OH, WI); VI (AR, LA, NM, OK,
TX); VII (IA, KS, MO, NE); VIII (CO, MT, ND, SD, UT, WY); IX (AZ, CA, HI, NV, Pacific Trust Territories); X
(AK, ID, OR, WA).
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                     records from EPA's databases. This allows retrieval of records from across
                     media or statutes for any given facility, thus  creating a "master  list" of
                     records for that facility.  Some of the data systems accessible through IDEA
                     are: AFS (Air Facility Indexing and Retrieval System, Office of Air and
                     Radiation),  PCS  (Permit Compliance System, Office of Water),  RCRIS
                     (Resource Conservation and Recovery Information System, Office of Solid
                     Waste), NCDB (National Compliance Data Base, Office of Prevention,
                     Pesticides, and Toxic Substances), CERCLIS (Comprehensive Environmental
                     Response, Compensation, and Liability Information System, Office of Solid
                     Waste and Emergency Response), and TRIS  (Toxics Release Inventory
                     System). IDEA also contains information from outside sources such as Dun
                     and Bradstreet and the Occupational Safety and Health Administration
                     (OSHA). Most data queries displayed in notebook sections IV and VII were
                     conducted using IDEA.

       Data Table Column Heading Definitions

                     Facilities in Search - are based on the universe of Toxic Release Inventory
                     (TRI) reporters within the listed SIC code range. For industries not covered
                     under TRI  reporting requirements (oil and gas extraction, metal mining,
                     nonmetallic mineral mining, electric power generation, ground transportation,
                     water transportation, and dry cleaning), or industries in which only a very
                     small fraction of facilities report to TRI (e.g., printing), the notebook uses the
                     FINDS universe for executing data queries. The  SIC code range selected for
                     each search is  defined by  each notebook's selected SIC code coverage
                     described in Section II.

                     Facilities Inspected  - indicates the  level of EPA and  state agency
                     inspections for the facilities in this data search.  These values show what
                     percentage of the facility universe is inspected in a one-year or five-year
                     period.

                     Number of Inspections — measures the total  number of inspections
                     conducted in this  sector.  An inspection event  is counted each time it is
                     entered into a single media database.

                     Average Time Between Inspections — provides an average length of time,
                     expressed in months, between compliance inspections at a facility within the
                     defined universe.

                     Facilities with One or More Enforcement Actions - expresses the number
                     of facilities that were the subject of at least one enforcement action within the
                     defined time period. This category is broken down further into federal and
                     state actions. Data are obtained for administrative, civil/judicial, and criminal
                     enforcement actions. A facility with multiple enforcement actions is only
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                    counted once in this column, e.g., a facility with 3 enforcement actions counts
                    as 1 facility.

                    Total Enforcement Actions -- describes the total number of enforcement
                    actions identified for an industrial sector across all environmental statutes.
                    A facility with multiple enforcement actions is counted multiple times, e.g.,
                    a facility with 3 enforcement actions counts as 3.

                    State Lead Actions — shows what percentage  of the total enforcement
                    actions are taken by state and local environmental agencies. Varying levels
                    of use by states of EPA data systems may limit the volume of actions
                    recorded as state enforcement activity.   Some  states extensively  report
                    enforcement activities into EPA data systems, while other states may use
                    their own data systems.

                    Federal  Lead Actions - shows what percentage of the total enforcement
                    actions are taken by the United States Environmental Protection Agency.
                    This value includes referrals from state agencies. Many of these actions
                    result from coordinated or joint state/federal efforts.

                    Enforcement to Inspection Rate ~ is a  ratio of enforcement actions to
                    inspections, and is presented for comparative purposes only. This ratio is a
                    rough indicator of the relationship between inspections and enforcement. It
                    relates the number of enforcement actions and the number of inspections that
                    occurred within the one-year or five-year period. This ratio  includes the
                    inspections and enforcement actions reported under the Clean Water Act
                    (CWA),  the Clean Air Act (CAA)  and the Resource Conservation and
                    Recovery Act (RCRA).  Inspections and  actions from the TSCA/FIFRA/
                    EPCRA  database are not factored into this  ratio because most of the actions
                    taken under these programs are not the result of facility inspections. Also,
                    this ratio does not account for enforcement actions arising from non-
                    inspection  compliance  monitoring  activities  (e.g.,  self-reported water
                    discharges) that can result in enforcement action within the CAA, CWA, and
                    RCRA.

                    Facilities with One or More Violations Identified   ~ indicates the
                    percentage of inspected facilities having a violation identified  in one of the
                    following  data categories:  In Violation  or Significant Violation Status
                    (CAA);  Reportable  Noncompliance, Current Year  Noncompliance,
                    Significant Noncompliance (CWA);  Noncompliance  and  Significant
                    Noncompliance (FIFRA, TSCA, and EPCRA); Unresolved Violation and
                    Unresolved High Priority Violation (RCRA). The values presented for this
                     column reflect the extent of noncompliance within the measured time frame,
                     but do not distinguish between the severity of the noncompliance. Violation
 Sector Notebook Project
118
October 2000

-------
 Oil and Gas Extraction
         Compliance and Enforcement History
                     status may be a precursor to an enforcement action, but does not necessarily
                     indicate that an enforcement action will occur.

                     Media Breakdown  of Enforcement Actions and  Inspections -- four
                     columns identify the proportion of total inspections and enforcement actions
                     within EPA Air, Water, Waste, and TSCA/FIFRA/EPCRA databases. Each
                     column is a percentage of either the "Total Inspections," or the "Total
                     Actions" column.

VILA.  Oil and Gas Extraction Industry Compliance History

                     Table 14 provides an overview of the reported compliance and enforcement
                     data for the oil and gas extraction industry over the past five years (April
                     1992 to April 1997). These data are also broken out by EPA Regions thereby
                     permitting geographical comparisons. A few points evident from the data are
                     listed below.

                     •      Over half of the inspections (3,094) and amajority of the enforcement
                           actions (175) during the five year period were conducted in Region
                           VI, which comprises Texas, Oklahoma, Louisiana, New Mexico, and
                           Arkansas.  More than half of the oil and gas production activity for
                          the nation is centered in these states.

                     •     Region II has  among the  fewest facilities,  but held the most
                          inspections per facility (an average of an inspection per 12 months at
                          each facility)  and had the highest enforcement to inspection ratio
                          (0.17).

                     •     Region VIII had the least frequent inspections (an average of 69
                          months between inspections) and one of the lowest enforcement to
                          inspection ratios (0.04).

                     •     Nearly  80 percent of the  enforcement actions were state-led.  The
                          only Region where the majority of actions were federally-led was
                          Region X, in which many oil fields are on Federal land in Alaska.
Sector Notebook Project
119
October 2000

-------
Oil and Gas Extraction
       Compliance and Enforcement History




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 Sector Notebook Project
120
October 2000

-------
 Oil and Gas Extraction
          Compliance and Enforcement History
 VII.B.  Comparison of Enforcement Activity Between Selected Industries

                     Tables 15 and 16 allow the compliance history of the oil and gas sector to be
                     compared to the other industries covered by the industry sector notebooks.
                     Comparisons between Tables 15 and 16 permit the identification of trends in
                     compliance and enforcement records of the various industries by comparing
                     data covering the last five years (April 1992 to April 1997) to that of the past
                     year (April 1996 to April 1997).  Some points evident from the data are listed
                     below.

                     •      Oil and gas extraction facilities are inspected much less frequently
                           (46 months between inspections on average) than facilities in most
                           other industries included in the following tables, and the enforcement
                           to inspection  ratio  (0.05) is among the lowest of the included
                           industries.

                     •      Oil  and gas  extraction  facilities  have the lowest percentage of
                           facilities with one or more violations (15 percent) and have one of the
                           lowest percentages  of facilities with enforcement actions  (three
                           percent).

                     •      The  one-year enforcement to inspection ratio (0.03) is significantly
                           less than the five-year ratio (0.05), indicating that enforcement actions
                           may be becoming less frequent per given number of inspections.

                     Tables 17 and 18 provide a more in-depth comparison between the oil and
                     gas extraction industry and other sectors by breaking out the compliance and
                     enforcement data by  environmental statute.  As in the previous Tables
                     (Tables 15 and 16), the data cover the last five years (Table 17) and last one
                    year (Table  18) to facilitate the identification of recent trends. A few points
                    evident from the data are listed below.

                    •      The  vast majority of both inspections and actions were performed
                           under the Clean Air Act, much more so than in other industries.

                    •      RCRA accounted for a relatively low percentage of the industry's
                           inspections and enforcement actions compared to other industries.

                    •      The inspections performed under RCRA yielded proportionately more
                           actions  than  those  performed  under either  CAA  or CWA.
Sector Notebook Project
121
October 2000

-------
Oil and Gas Extraction
       Compliance and Enforcement History









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October 2000

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October 2000

-------
         Oil and Gas Extraction
                                    Compliance and Enforcement History

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        Sector Notebook Project
                           125
                                                       October 2000

-------
Oil and Gas Extraction
       Compliance and Enforcement History
VII.C. Review of Major Legal Actions

       Major Cases/Supplemental Environmental Projects
                    This section provides summary information about major cases that have
                    affected this  sector,  and a list  of Supplemental Environmental  Projects
                    (SEPs).
       VII.C.1. Review of Major Cases
                    As indicated in EPA's Enforcement Accomplishments Report publications for
                    FY 1996, FY 1997, and FY 1998 and a U.S. Department of Justice press
                    release, seven significant enforcement actions have been resolved recently for
                    the oil and gas extraction industry.

                    Three cases involved violations of the Clean Water Act. Two cases involved
                    violations of National Pollution Discharge Elimination System (NPDES)
                    discharge limits. The Cook Inlet Oil and Gas Platforms (owned by Marathon,
                    Shell, and Unocal) agreed to pay $212,000 for allegedly violating NPDES
                    permits for  18 offshore platforms in Cook Inlet, Alaska.  In a separate
                    settlement, BP Exploration, Inc.  agreed to pay $59,900 in response to an
                    administrative complaint that the levels of fecal coliform bacteria, BOD,
                    TRC, pH and flow were beyond its NPDES permit levels between January
                     1992 and October 1995.

                    The CWA violation settled in U.S. v.  Berry Petroleum was part of a multi-
                    agency (federal and state) case relating to a crude oil spill of 2,000  barrels
                    from an oil  production facility  in a wetland area located adjacent  to  a
                    California state beach. The spill contaminated the wetlands, adjacent ocean,
                     and nearby beaches. It was determined that the spill occurred, in large part,
                     because the facility failed to implement its EP A-mandated SPCC plan. Berry
                     Petroleum paid $800,000 to EPA for the CWA violation in addition to $1.06
                     million in penalties to the California Regional Water Quality Control Board,
                     the U.S. Fish and Wildlife  Service, and other federal and state agencies.
                     Berry also transferred $ 1,315,000 to a trust fund administered by the National
                     Fish and Wildlife Foundation that will be used for long term restoration of
                     the site.

                     A settlement in U.S. CSac and Fox Nation) v. Tenneco Oil Company was
                     reached over an alleged SDWA violation.  Surface and groundwater on land
                     of the Sac  and  Fox Nation was contaminated  near areas of oil leases
                     maintained by Tenneco between 1924 and 1989.  Tenneco is required to
                     provide the Sac and  Fox  Nation with a potable water supply  of 207
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                     sustainable gallons per minute and $1.16 million in cash. The overall dollar
                     value of the settlement is over $3.5 million.

                     An alleged CAA violation was settled with Vastar Resources, Inc.  and
                     ARCO, regarding their facility on the Southern Ute Indian Reservation in La
                     Plata County, CO.  Vastar (the current owner) and ARCO (the previous
                     owner) failed to install  pollution control equipment  on gas production
                     engines at the facility. The results were large emissions of carbon monoxide
                     (CO) and  savings of $657,412  on the part  of Vastar by operating the
                     equipment without the required air emission controls. Vastar complied with
                     EPA self-policing policies, and as a result the company only paid $ 137,949
                     plus $247,000 for the pollution control equipment. Although ARCO came
                     forward at the same time as Vastar, it did not report the emissions while it
                     owned the facility, and  as a result did not meet  EPA's  self-disclosure
                     standards.  ARCO did not admit to the allegations, but settled for $519,463,
                     which includes money saved from not using the equipment plus a penalty.

                     In September 1999, the Department of Justice announced that BP Exploration
                     (Alaska) Inc. pleaded guilty to one felony count related to the illegal disposal
                     of hazardous waste on Alaska's North Slope in violation of CERCLA. BP
                     Exploration had contracted with Doyan Drilling Inc. to drill production wells
                     on Endicott Island. Between 1993 and 1995  Doylan employees illegally
                     injected wastes  down the outer  rim,  or  annuli, of  the oil wells.  BP
                     Exploration failed to report the illegal injections as soon as it learned of the
                     conduct. The wastes included paint thinner and toxic solvents containing lead
                     and chemicals such as benzene, toluene, and methyl chloride. BP Exploration
                     was fined $500,000 and agreed to spend a total of $22 million to resolve the
                     criminal case and related civil claims. The civil settlement  requires  BP
                     Exploration to pay $6.5 million in penalties to resolve allegations that BP
                     illegally disposed of the hazardous waste and violated the Safe Drinking
                     Water Act. Also under the terms  of the agreement, BP Exploration will
                     establish an  environmental management  system at all  of BP Amoco's
                     facilities in the U.S. and Gulf of Mexico that are engaged in the exploration,
                     drilling, or production of oil (U.S. Department of Justice, September  23,
                     1999).

       VII.C.2.  Supplementary Environmental Projects (SEPs)

                     SEPs are compliance agreements that reduce  a facility's non-compliance
                    penalty in return for an environmental project that exceeds the value of the
                    reduction.  Often, these projects fund pollution prevention activities that can
                    reduce the future pollutant loadings of a facility. Information on SEP cases
                    can  be accessed  via the  internet  at  the  SEP National Database,
                    es. epa. gov/oeca/sep/. This information is not comprehensive and provides
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                    only a sample of the types of SEPs developed for the oil and gas extraction
                    industry.

                    One agreement was listed for SIC code 13.  George Perry Exploration and
                    Production, in Oceana County, MI, performed a SEP in response to violations
                    of sections 1421 and 1422 of SDWA, in which the company violated the state
                    underground injection control (UIC) program regulations and failed to submit
                    an application  for implementation of a UIC  program.  As a pollution
                    reduction SEP, the company plugged three abandoned production wells to
                    prevent the possible contamination of underground sources of drinking water.
                    The cost of the project was valued at $6,000.
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VIII. COMPLIANCE ASSURANCE ACTIVITIES AND INITIATIVES

                    This section highlights the activities undertaken by this industry sector and
                    public  agencies  to  voluntarily   improve  the  sector's  environmental
                    performance.  These activities include those initiated independently by
                    industrial trade associations. In this section, the notebook also contains a
                    listing and description of national and regional trade associations.

VIII.A. Sector-related Environmental Programs and Activities

       VIII.A.1.  Federal Activities

       EPA Regional Compliance and Enforcement Activities

                    Several significant regional activities  relating' to the oil and gas extraction
                    industry were reported in the 1997 Enforcement and Compliance Assurance
                    Reports. Region VI provided assistance to offshore oil and gas exploration
                    and production facilities with regard  to NPDES permits. Region VI sent
                    reporting forms to more than 2,000 facilities for compliance monitoring and
                    reporting  of the effluent quality of waste water discharges from offshore
                    platforms to the Gulf of Mexico. General permitting and reporting questions
                    were explained to increase compliance through approximately 300 telephone
                    conversations with facility  operators, consultant, and state and federal
                    agencies.   Finally,  a presentation  on NPDES Offshore General Permit
                    compliance and enforcement was given to approximately 100 permittees in
                    Dallas. Partially as a result of these  efforts, the compliance reporting rate is
                    approximately 98 percent.

                    Region VI also created a work group that addressed the compliance  and
                    reporting of over 3,000 injection wells operated by 500 to 600 oil producers
                    in the Osage Mineral Reserve. The group created Osage Operators'
                    Environmental Handbook and Osage Operators' Environmental Manual, in
                    order to assist small oil producers in complying with Bureau of Indian Affairs
                    (BIA) and EPA requirements.

                    Region VIII, the U.S. Fish and Wildlife Service (USFWS) and associated
                    states implemented a pilot program regarding problem oil pits (POPs). POPs
                    are open-air pits  along with tanks and associated spills at drilling  and
                    production sites that lack devices (such as proper netting) to prevent birds
                    from landing on (and becoming stuck in) the layer of oil. This program seeks
                    to address impacts to ground water  and surface water as well as impacts to
                    wildlife. The program cooperated with federal and state regulators (Bureau
                    of Land Management, state environmental agencies, and state oil and gas
                    commissions) to perform aerial surveys and  ground surveys of oil pits in
                    Colorado, Montana, and Wyoming.  The  states  had the lead  whenever
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                    possible. It was found that a large number of the pits would be considered
                    POPs and were in noncompliance with applicable federal and state statutes
                    or regulations.  To address the high rate of noncompliance,  the relevant
                    agencies  are  mobilizing  to  offer  compliance  assistance,  informal
                    enforcement, or formal enforcement. All EPA Region VIII states have been
                    completed for this POP effort except Utah, which is planned for completion
                    in 1999 and EPA regions 5 and 7 are pursuing POP programs.

       U.S. Department of Energy Oil and Gas Environmental Research and Analysis Program

                    The Office of Fossil Energy of the Department of Energy (DOE) has initiated
                    several programs that address environmental and regulatory issues in the oil
                    and gas industry. The efforts primarily center around streamlining regulatory
                    procedures that affect the industry and performing research on cost-effective
                    environmental compliance technologies.

                    The regulatory  streamlining efforts attempt three major tasks:  coordinating
                    the many federal and state agencies involved with oil and gas regulation,
                    including EPA, the Bureau of Land Management (BLM), and relevant state
                    agencies; incorporating  more risk-based decision making  into regulatory,
                    enforcement, and  compliance decisions;  and  reducing  impediments to
                    technology implementation.

                    In its efforts to coordinate regulatory agencies, DOE worked with a group
                    including the Interstate Oil and Gas Compact Commission (IOGCC), BLM,
                    industry, and environmental groups to standardize permit applications in
                    different states  and on federal lands. The group also identified seven areas
                    of regulatory responsibility that could be transferred from federal to state
                    agencies to reduce overlapping activities within states.

                    DOE is also attempting to broaden the use of risk-based decision making. In
                    one project, DOE is working with California, Kansas, and Oklahoma to
                    expand exemptions for costly Area of Review (AOR) analyses of surrounding
                    areas prior to the permitting of a disposal or injection well. AOR analyses
                    investigate the  potential of aquifer contamination by a proposed disposal
                    well; new DOE methodology would limit the necessity of AOR studies in
                    areas predetermined to have little risk.

                    The DOE environmental program also works to remove  impediments to
                    technology implementation. An example is shown in the case of newly
                    developed synthetic drilling fluids, which show promise in increasing drilling
                    efficiency and  safety, particularly in deepwater drilling.   Existing EPA
                    regulations, however, limit their use. In 1994, DOE worked with industry
                    and EPA to  re-evaluate the regulations that affect these synthetic fluids.
                    Consequently,  EPA is in the process of revising regulations to clarify the
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                    terms under which industry may be allowed to use the technology. The use
                    of these fluids could save the industry over $50 million annually.

                    Finally, DOE is assisting in the development of pollution prevention and
                    waste management technologies. DOE's Sandia National Laboratories are
                    developing a laser-equipped camera that can detect methane leaks in pipes.
                    Argonne National Laboratory is undertaking a study to determine whether
                    naturally occurring radioactive material  (NORM), which may be found in
                    well fluids, can be disposed of on-site in some locations, in order to reduce
                    disposal costs. DOE also performs or funds research on produced water
                    disposal; this includes  further investigation into underground injection
                    systems and development of a treatment for produced water into potable
                    water  in arid regions  such as  California.    (Contact:  www.fe. doe, gov/
                    oil_gas/oilgas7.html  or William Hochheiser, Environmental Scientist, at
                    (202) 586-5614 or e-mail william.hochheiser@hq.doe.gov.)

       U.S. EPA Voluntary Self-Disclosure Policy

                    In 1996, EPA adopted its final policy on incentives for self-evaluation and
                    self-disclosure of violations. Through this policy, the Agency aims to protect
                    public health and the environment by  reducing civil penalties and not
                    recommending criminal prosecution for regulated entities that voluntarily
                    discover, disclose and correct violations under the environmental laws that
                    EPA administers.

                    Under the final  policy, where violations are found through voluntary
                    environmental audits or efforts that reflect a regulated entity's due diligence
                    (i.e., systematic efforts to prevent, detect and correct violations, as defined in
                    the policy),  and all of the policy's conditions are met, EPA will not seek
                    gravity-based penalties  and will  generally  not recommend criminal
                    prosecution   against  the company if  the  violation results from the
         ,           unauthorized criminal conduct of an employee.  Where violations are
                    discovered by means other than environmental audits or due diligence efforts,
                    but are promptly disclosed and expeditiously corrected,  EPA will reduce
                    gravity-based penalties by 75 percent provided that all of the other conditions
                    of the policy are met. EPA retains its discretion to recover economic benefit
                    gained as a  result of noncompliance, so that companies  won't be able to
                    obtain an economic advantage over their competitors by delaying their
                    investment in compliance.

                    In  addition  to prompt disclosure and correction, the  policy requires
                    companies to prevent recurrence of the  violation and to  remedy any
                    environmental harm. Repeated violations or those which may have presented
                    an imminent and  substantial endangerment or resulted in serious harm are
                    excluded from the policy's coverage. Corporations remain criminally liable
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                    for violations resulting from conscious disregard of their legal duties, and
                    individuals remain liable for criminal wrongdoing.

                    Although the final policy restates EPA's practice of not routinely requesting
                    environmental audit reports, it does contain two provisions ensuring public
                    access to information. First, EPA may require as a condition of penalty
                    mitigation that a description of the regulated entity's due diligence efforts be
                    made publicly available. Second, where EPA requires that a regulated entity
                    enter into a written agreement, administrative consent order or judicial
                    consent decree to satisfy the policy's conditions, those agreements will be
                    made publicly available.

       Vni.A.2.  State Activities

                    The oil and gas industry  is primarily  regulated at the state  level.  Four
                    organizations  are discussed in this section that strongly influence state
                    compliance assurance and waste minimization initiatives. Interstate Oil and
                    Gas Compact Commission (IOGCC) coordinates oil and gas issues among oil
                    and gas producing states, including environmental concerns. State Review
                    of Oil and Natural Gas Environmental Regulations, Inc. (STRONGER, Inc.)
                    is a non-profit corporation that develops guidelines for state oil and gas
                    production waste regulatory programs and coordinates state reviews.  The
                    Ground Water Protection Council (GWPC) brings together state and federal
                    regulators, industry, and others to address both underground inj ection control
                    and groundwater protection issues. Finally, the Waste Minimization Program
                    of the Texas Railroad Commission is in many ways a model for other states
                    in disseminating cost-effective waste minimization solutions. While many
                    states have waste minimization programs for underground inj ection wells, the
                    Texas Railroad Commission has a unique structure among state governments
                    of oil producing states as the regulator of nearly every aspect of the oil and
                    gas extraction industry.  The Waste Minimization Program therefore has a
                    wider reach over the industry in the state.

       Interstate Oil and Gas Compact Commission (IOGCC)

                    The IOGCC is an organization of the governors of 30 member states and
                    seven associate  states concerned with many aspects of the oil and  gas
                    industry. The primary purpose of the compact is to conserve oil and gas by
                    the prevention of physical waste.  IOGCC advocates for the rights of the
                    states to govern oil and gas issues within their own borders, and coordinates
                    regulatory efforts among the states to protect oil and gas resources and protect
                    the environment.   The  organization serves as a forum for government,
                    industry, environmentalists and others to share  information and voice
                    opinions on a wide  range of topics.
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                     Specifically relating to environmental issues, IOGCC is active in developing
                     state regulatory standards, guidelines, and models for many aspects of the oil
                     and gas  industry,  including  bioremediation,  waste  disposal,  waste
                     minimization, beneficial use of waste, water and air quality, and abandoned
                     sites. One of the most prominent of the lOGCC's efforts with respect to
                     environmental issues has been the development of guidelines and reviews of
                     state extraction and production waste management regulatory programs.
                     Seventeen states representing over 90 percent of the onshore production in
                     the United States have undergone these reviews, and summaries  of the
                     reviews are published in individual reports. These reports, in addition to
                     other IOGCC  publications, are  an excellent source of state-specific
                     regulations and programs.  State reviews can be obtained from IOGCC by
                     calling   (405)   525-3556,  and   from  the   IOGCC   Website   at:
                     www. iogcc. oklaosf.state. ok us/. Since mid-1999, the state review program
                     has been managed by STRONGER, Inc., a non-profit organization. Also, the
                     IOGCC, through its annual Environmental Stewardship Awards recognizes
                     major and independent operators  that are performing environmentally
                     beneficial projects.

       State Review of Oil and Natural Gas Environmental Regulations,  Inc.  (STRONGER, Inc.)

                     The state review process described above, established by IOGCC, developed
                     guidelines for state oil and gas exploration and production waste regulatory
                    programs  and coordinated reviews of state programs until 1997, when the
                    process  was  terminated.   During  1998,  several  meetings of interested
                     stakeholders  were conducted to determine how the process could be
                    revitalized. In early 1999, the IOGCC proposed to EPA that the program be
                    managed by a separate group of stakeholders equally representing the states,
                    industry, and environmental organizations.  Such a group was formed, and in
                    June, 1999, was incorporated as a non-profit corporation, State Review of Oil
                    and Natural  Gas Environmental Regulations, Inc. (STRONGER, Inc.).
                    STRONGER, Inc. develops updated and revised guidelines for adoption by
                    IOGCC and coordinates state reviews.  Guidelines, documents and state
                    review reports are published and distributed by IOGCC. State participation
                    in STRONGER, Inc.  is coordinated through the IOGCC State Review
                    Committee.

       Ground Water Protection Council (GWPC)

                    The Ground Water Protection Council (GWPC) is a nonprofit organization
                    whose members consist of state and federal ground  water agencies, industry
                    representatives, environmentalists, and concerned citizens. The council seeks
                    to promote and ensure the use of best management practices and fair but
                    effective laws regarding comprehensive ground  water protection.   The
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                    GWPC works with the oil and gas industry via its UIC Class II Division.
                    GWPC can be contacted by calling (405) 516-4972 or visiting their website
                    at http://gwpc.site.net/.

       Texas Waste Minimization Program

                    The Waste Minimization Program, run by the Texas Railroad Commission,
                    is a voluntary program intended to provide oil and gas well operators with
                    cost effective waste minimization solutions.  The program serves as a
                    technology transfer clearinghouse for information on specific waste streams,
                    such as fugitive VOCs or produced water.  The program also performs
                    several forms of outreach:

                    •      A manual outlining general techniques, Waste Minimization in the Oil
                           Field.

                    •      One-day workshops.

                    •      A Waste Minimization Newsletter, which illustrates case studies of
                           cost-effective programs implemented by operators (the newsletter is
                           published two or three times a year).

                    •      On-site assistance to help operators assess their operations and to
                           develop individualized waste minimization programs.

                    •      WasteMin, an easy-to-use waste minimization planning software
                           package.

                    The program focuses on discovering and spreading innovative techniques that
                    will add revenue for operators in addition to reducing environmental impacts.
                    (Contact: Jack Ward, (512) 475-4580, or www.rrc.state.tx.us/divisions/
                   , og/key-programs/ogkwast. html.~)

 VIII.B. EPA Voluntary Programs

       Natural Gas STAR

                    Natural Gas STAR is a voluntary partnership between EPA and the natural
                    gas industry  that was formed to find cost-effective ways of reducing
                    emissions of methane. Methane is a significant concern with regard to the
                    climate change issue; it is second only to carbon dioxide as a component of
                    so-called "greenhouse gases."

                    Fugitive emissions from the natural gas industry are a substantial source of
                    anthropogenic methane. Natural Gas STAR has two programs: one focusing
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                     on production and the other concentrating on distribution and transmission.
                     The program for producers was launched in 1995, and participants represent
                     approximately 35 percent of the U.S. natural gas production. The primary
                     goals of the producers program are to promote technology transfer and
                     implement best management practices (BMPs) that are cost-effective and that
                     reduce methane emissions.  Partners perform the following:

                     •      Submit and execute BMP implementation plans
                     •      Assist in the testing of emerging technologies
                     •      Design new facilities to include BMPs when cost effective.

                     EPA serves to facilitate the transfer of new technology between members,
                     perform outreach to inform and attract non-members, and address regulatory
                     barriers that may threaten BMP implementation.

                     By mid-1998, partners had prevented the release of roughly 50 billion cubic
                     feet (Bcf) of methane, worth approximately $100 million. The program has
                     achieved this mark and  plans to continue  improvements by holding
                     workshops for satellite offices of both member and non-member companies
                     and updating members on new developments through newsletters and reports,
                     among other activities. (Contact: www.epa. gov/sasstar or Paul Gunning at
                     (202) 564-9736).

       33/50 Program

                     The  33/50  Program is a  groundbreaking  program that has focused on
                     reducing pollution from seventeen high-priority chemicals through voluntary
                     partnerships with industry.  The program's name stems from its goals:  a 33%
                     reduction in toxic releases by 1992, and a 50% reduction by 1995, against a
                     baseline of 1.5 billion pounds of releases and transfers in 1988. The results
                     have  been  impressive:  1,300  companies joined the 33/50 Program
                     (representing over 6,000 facilities) and reached the national targets  a year
                     ahead of schedule. The 33% goal was reached in 1991, and the 50% goal ~
                     a reduction of 745 million pounds of toxic wastes — was reached in 1994.

                     Table 19 lists those companies participating in the 33/50 program that
                     reported four-digit SIC codes within 13 to TRI. Some of the companies
                     shown also listed facilities that are not producing oil and gas. The number
                     of facilities within each company that are participating in the 33/50 program
                     and that report oil and gas extraction SIC codes is shown.

                     Since oil and gas facilities are not currently required to report to TRI under
                     EPCRA section 313 reporting requirements (TRI), only a few oil and gas
                     extraction companies participated in the 33/50 program. Where available and
                     quantifiable against 1988 releases and transfers, each company's 33/50 goals

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                    for 1995 and the actual total releases and transfers and percent reduction
                    between 1988 and 1995 are presented. In each case, the participating oil and
                    gas extraction operations of the partner companies performed significantly
                    better than the company-wide goals, and nearly all facilities attained greater
                    than 50 percent reductions in 33/50 chemicals.

                    Table 19 shows that six companies comprised of 80 facilities reporting SIC
                    13 participated in the 33/50 program. For those companies shown with more
                    than one oil and gas facility, all facilities may not have participated in 33/50.
                    The 33/50 goals shown for companies with multiple oil and gas facilities,
                    however, are company-wide, potentially aggregating more than one facility
                    and facilities not carrying out oil and gas extraction operations. In addition
                    to company-wide goals, individual facilities within a company may have had
                    their own 33/50 goals or may be specifically listed as not participating in the
                    33/50 program. Since the actual percent reductions shown in the last column
                    apply to all of the companies'  oil and gas facilities and only oil  and gas
                    facilities, direct comparisons to those company goals incorporating non-oil
                    and gas facilities may not be possible. For information on specific facilities
                    participating  in  33/50, or  to  review case  studies  on  corporate
                    accomplishments in reducing waste contact David Sarokin, (202) 260-6907,
                    at the 33/50 Program Office.

                    With the completion of the  33/50 program, several lessons were  learned.
                    Industry and the environment benefitted by this program for several  reasons.
                    Companies  were willing to participate because cost savings and  risk
                    reduction were measurable and no additional record keeping and reporting
                    was required. The goals of the program were clear and simple and EPA
                    allowed industry to achieve the goals in whatever manner they could.
                    Therefore, when companies can see the benefits of environmental programs
                    and be an active part of the decision-making process, they are more  likely to
                    participate.
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Table 19: Oil and Gas Industry Participation in the 33/50 Program
Parent Company
(Headquarters Location)
Amerada Hess Corp.
New York, NY
Atlantic Richfield Co.
Los Angeles, CA
Dresser Industries, Inc.
Dallas, TX
Exxon Corp.
Irving, TX
Texaco, Inc.
White Plains, NY
USX Corp.
Pittsburgh, PA
TOTAL
Company-Owned
Oil and Gas
Facilities
Reporting 33/50
Chemicals
4
11
10
17
14
24
80
Company-
Wide %
Reduction
Goal1
(1988-1995)
50%
23%
47%
50%
49%
25%
-
1988TRI
Releases and
Transfers of
33/50 Chemicals
(pounds)
2,241,601
835,443
230,202
5,155,264
713,136
9,873,833
19,049,479
1995 TRI
Releases and
Transfers of
33/50 Chemicals
(pounds)
567,251
451,818
17,578
2,159,535
251,152
1,246,246
4,693,580
Actual %
Reduction for
Oil and Gas
Facilities
(1988-1995)
75%
46%
92%
58%
65%
87%
75%
Source: U.S. EPA, OPPTS, 33/50 Program 1998
1 Company- Wide Reduction Goals aggregate all company-owned facilities which may include facilities not involved
with oil and gas production.
       Project XL
                    Project XL was initiated in March 1995 as a part of President Clinton's
                    Reinventing Environmental Regulation initiative.  The projects seek  to
                    achieve cost effective environmental benefits by providing participants
                    regulatory flexibility on the condition that they produce greater environmental
                    benefits.  EPA and program participants will negotiate and sign a Final
                    Project Agreement, detailing specific  environmental objectives that the
                    regulated entity shall satisfy. EPA will provide regulatory flexibility as  an
                    incentive  for  the  participants'  superior  environmental  performance.
                    Participants are  encouraged  to  seek  stakeholder  support  from  local
                    governments,  businesses,  and environmental groups.   EPA  hopes  to
                    implement fifty  pilot projects in four  categories,  including  industrial
                    facilities, communities,  and  government  facilities  regulated  by  EPA.
                    Applications will be accepted on a rolling basis. For additional information
                    regarding XL projects, including application procedures and criteria, see the
                    May 23, 1995 Federal Register Notice.  (Contact: Fax-on-Demand Hotline
                    (202) 260-8590, Web: www. epa.sov/ProjectXL, or Christopher Knopes  in
                    EPA's Office of Reinvention, (202) 260-9298).
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       Energy Star® Buildings and Green Lights® Partnership

                    In 1991, EPA introduced Green Lights®, a program designed for businesses
                    and organizations to  proactively combat pollution by installing energy-
                    efficient lighting technologies in their commercial and industrial buildings.
                    In April 1995, Green Lights® expanded into Energy Star® Buildings- a
                    strategy that optimizes whole-building energy-efficiency opportunities.

                    The energy needed to run commercial and industrial buildings in the United
                    States produces 19 percent of U.S. carbon dioxide emissions, 12 percent of
                    nitrogen oxides, and 25 percent of sulfur dioxide, at a cost of 110 billion
                    dollars  a year.  If implemented in every U.S. commercial and  industrial
                    building, Energy Star® Buildings' upgrade approach could prevent up to 35
                    percent of the emissions associated with these buildings and cut the nation's
                    energy bill by up to 25 billion dollars annually.

                    The  over  2,500  participants  include  corporations,  small businesses,
                    universities, health care facilities, nonprofit organizations, school districts,
                    and federal  and local  governments.   As  of January 1,  1998,  Energy
                    Star®Buildings and Green Lights® Program participants have reduced their
                    annual energy use by  7 billion kilowatt hours and annually save more than
                    517 million dollars. By joining, participants agree to upgrade 90 percent of
                    their owned facilities with energy-efficient lighting and 50 percent of their
                    owned  facilities with whole-building  upgrades, where profitable, over a
                    seven-year period. Energy Star participants first reduce their energy loads
                    with the Green Lights approach to building  tune-ups, then focus on "right
                    sizing" their heating and cooling equipment to match their new energy needs.
                    EPA predicts this strategy will  prevent more than 5.5  MMTCE  of carbon
                    dioxide by the year 2000. EPA's Office of Air and Radiation is responsible
                    for operating the Energy Star Buildings and Green Lights Program. (Contact
                    the Energy  Star Hotline number, (888) STAR-YES ((888) 872-7937) or
                    Maria Tikoff Vargas,  Co-Director at (202) 564-9178 or visit the website at
                    www. epa. gov/buildings.}

       WasteWi$e Program

                    The WasteWi$e Program was  started in 1994 by EPA's Office of Solid
                    Waste  and  Emergency Response.  The program is  aimed at reducing
                    municipal solid wastes by promoting waste prevention, recycling collection
                    and the manufacturing and purchase of recycled products. As of 1998, the
                    program had about 700 business, government, and institutional partners.
                    Partners agree to identify and implement actions to reduce their solid wastes
                    setting waste reduction goals and providing EPA with yearly progress reports
                    for  a three  year period.  EPA, in turn, provides partners with technical
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                     assistance, publications, networking opportunities, and national and regional
                     recognition. (Contact: WasteWi$e Hotline at (800) 372-9473).

       NICE3

                    The U.S. Department of Energy sponsors a grant program called National
                    Industrial Competitiveness through Energy, Environment, and Economics
                    (NICE3).    The NICE3 program provides  funding to state  and industry
                    partnerships (large and small business) for projects demonstrating advances
                    in energy efficiency and clean production technologies. The goal of the NICE3
                    program is to demonstrate the performance and economics of innovative
                    technologies  in the U.S., leading to the commercialization  of improved
                    industrial manufacturing processes. These processes should conserve energy,
                    reduce  waste,  and improve industrial  cost-competitiveness.    Industry
                    applicants must submit project proposals through a state  energy, pollution
                    prevention, or business development office. The following focus industries,
                    which represent the dominant energy users and waste generators in the U.S.
                    manufacturing sector, are of particular interest to the program: Aluminum,
                    Chemicals, Forest Products, Glass, Metal-casting,  and Steel.  Awardees
                    receive a one-time, three-year grant of up to $400,000, representing up to 50
                    percent of a project's total cost. In addition, up to $25,000 is available to
                    support   the   state   applicant's   cost   share.   (Contact:
                    www. oit. doe. gov/Access/nice3, Steve Blazek, DOE, (303)  275-4723 or Eric
                    Hass, DOE, (303) 275-4728)

       Design for the Environment (DfE) Program

                    DfE is working with several industries to identify cost-effective pollution
                    prevention strategies that reduce risks to workers and the environment. DfE
                    helps businesses compare and evaluate  the performance,  cost,  pollution
                    prevention benefits, and human health and environmental risks associated with
                    existing and alternative technologies. The  goal of these projects is to
                    encourage businesses to consider and use cleaner products, processes,  and
                    technologies.  For more information about the DfE Program, call (202) 260-
                    1678.  To obtain copies of DfE materials or for general information about
                    DfE, contact EPA's Pollution Prevention Information Clearinghouse at (202)
                    260-1023 or visit the DfE Website at www. epa. gov/dfe.

       Small Business Compliance Assistance Centers

                    The  Office  of  Compliance,  in partnership  with  industry,   academic
                    institutions, environmental groups, and other federal and state agencies, has
                    established national Compliance Assistance Centers for nine specific industry
                    sectors heavily populated with small businesses that face substantial federal
                    regulation. These sectors are printing, metal finishing, automotive services

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                    and  repair, agriculture,  commercial transportation,  paint  and coating
                    applications, the printed wiring board industry, municipalities and small
                    chemical manufacturers.

                    The purpose of the Centers is to improve compliance of the customers they
                    serve by Increasing  their awareness of the pertinent federal regulatory
                    requirements and by providing the information that will enable them to
                    achieve compliance. The Centers accomplish this by offering the following:

                    •      "First-Stop Shopping" - serve as the first place that small businesses
                           and technical  assistance providers go to get comprehensive, easy to
                           understand compliance information targeted specifically to industry
                           sectors.

                    •      "Improved Information Transfer" - via the Internet and other means,
                           create linkages between the small business community and providers
                           of technical and regulatory  assistance  and among the providers
                           themselves to share tools and knowledge and prevent duplication of
                           efforts.

                    •      "Compliance  Assistance Tools" - develop and disseminate plain-
                           English guides, consolidated  checklists, fact sheets, and other tools
                           where needed by small businesses and their information providers.

                    •      "Links Between Pollution Prevention and Compliance Goals" -
                           provide easy access to information and technical assistance on
                           technologies  to help minimize waste generation and maximize
                           environmental performance.

                    •      "Information on Ways to Reduce the Costs of Compliance" - identify
                           technologies and best management practices that reduce pollution
                           while saving money.

                    For  general information regarding EPA's compliance assistance centers,
                    contact Tracy Back at (202) 564-7076.

VIII.C.  Trade Association/Industry Sponsored Activity

      VHI.C.l. Industry Research Programs

      American Petroleum Institute- Strategies for Today's Environmental Partnership (STEP)

                    The STEP (Strategies for Today's Environmental Partnership) program was
                    developed by API member companies to  address public environmental
                    concerns by improving the industry's environmental, health, and safety
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                    performance; documenting performance improvements; and communicating
                    them to the public.  The foundation for STEP is the API Environmental
                    Mission and the API Guiding Environmental Principles.  The program also
                    includes a series of environmental strategic plans; a review and revision of
                    existing industry standards; documentation of industry environmental, health,
                    and safety performance; and mechanisms for obtaining public input. In 1992,
                    API endorsed, as part of STEP, adoption of management practices as an API
                    recommended practice.  The management practices contain the following
                    elements: pollution prevention, operating and process safety, community
                    awareness, crisis  readiness, product stewardship, proactive government
                    interaction, and resource conservation.  The management practices are an
                    outline of actions to help companies incorporate environmental health and
                    safety concerns into their planning and decision making. Each company will
                    make its own decisions on how and whether to change its operations. API
                    has developed a compilation of resources that provide recommendations and
                    guidance on various operational areas of the  oil  industry to  assist API
                    members with their implementation of the management practices.

                    STEP is a program of the American Petroleum Institute (API) that strives to
                    improve and promote the industry's commitment to environmental, health,
                    and safety issues.  The program encompasses many projects performed by
                    member companies, plus research performed by API. STEP is involved with
                    environmental issues on two fronts: research, and communications with both
                    member companies and external entities.

                    STEP sponsors a wide range of research on environmental issues, including
                    studies on releases, exposure  assessments,  and  pollution prevention
                    assessments. In many cases, the data leads toward the setting of API industry
                    standards, which are often cited in EPA regulations.

                    The program also serves to disseminate information about environmental and
                    health issues to the public.  An example is the Petroleum"Industry
                    Environmental Performance Annual Report, which presents statistics on the
                    progress of the industry in reducing its environmental impacts.

                    API's Upstream Department undertakes  a range of activities focused on
                    environmental issues facing the oil and gas extraction industry.  Sponsored
                    research may identify available, cost-effective techniques for  control of
                    emissions or remediation of a spill.  Workshops are  sponsored to assist
                    companies (both members  and  nonmembers) in complying  with new
                    regulations or applying new technologies. As an example, API sponsored
                    research on the remediation of soils affected by salt resulting from decades-
                    old discharges or more recent spills of produced water. From this research
                    has grown a series of workshops to transfer this information to companies
                    and state agencies working to address these sites.
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      Gas Research Institute (GRI)
                    The Gas Research Institute is headquartered in Chicago and manages a
                    cooperative research, development, and commercialization program for the
                    mutual benefit of the  natural gas industry.  GRI works  with research
                    organizations, manufacturers  and its member companies to develop gas
                    technologies  and  to transfer new  products  and  information to the
                    marketplace.

                    GRI has published studies of waste generation and management in the natural
                    gas industry. "Waste Minimization in the Natural Gas Industry: Regulations,
                    Methodology, and Assessment of Alternatives" is of particular interest. The
                    publication provides a thorough overview of waste generation in the industry
                    and methods  for  minimizing many of the waste streams.  (Contact:
                    www.grz.org/or (773) 399-8100.)
      Vin.C.2. Trade Associations
                     American Petroleum Institute (API)
                     1220 L Street, NW
                     Washington, DC 20005
                     Phone: (202) 682-8000
                     Fax:   (202) 962-4797
               Members: 500
               Staff: 300
               Budget: $40,000,000
               Contact: Mark Rubin
               www.avi.ors/
                    The American Petroleum Institute (API) is the largest trade group for the oil
                    and gas industry, with the largest membership and budget.  API represents
                    major oil companies, and independent oil producers, refiners, marketers, and
                    transporters of crude oil, lubricating oil, gasoline,  and natural gas.  API
                    conducts and promotes research in the oil and gas industry and collects data
                    and publishes statistical reports on oil production and refining.  Numerous
                    manuals,  booklets, and other materials are published on oil  and gas
                    exploration and production.
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                     Independent Petroleum Association
                     of America (IPAA)
                     1101 16th St., NW
                     Washington, DC 20036
                     Phone: (202)'857-4722
                     Fax:   (202) 857-4799
               Members: 6,000
               Staff: 25
               Contact: Gil Thrum
               www. inaa. ore/
                    IPAA was founded in 1929 to represent small oil and natural gas producers
                    in legislative and regulatory issues at the federal level.  Its members are
                    principally well operators and royalty owners, plus others involved in the
                    industry  such as suppliers,  and  drilling  contractors.   IPAA  collects
                    production, consumption, and economic data on the industry and publishes
                    documents including The Oil and Natural Gas Producing Industry in Your
                    State.
                     Society of Petroleum Engineers
                     (SPE)
                     PO Box 833836
                     Richardson, TX 75083-3836
                     Phone: (214) 952-9393
                     Fax:   (214) 952-9435
               Members: 53,000
               Staff: 92
               Budget: $15,000,000
               Regional Groups: 13
               Local Groups: 137
               Contact: Dan K. Adamson
               www.spe.ore/
                    SPE was founded in 1922 to serve petroleum engineers involved with oil and
                    gas exploration and production.  The organization has 53,000 members and
                    abudgetof $15 million. SPE publishes severaljournals and books, including
                    the monthly Journal  of Petroleum  Technology, that report on reservoir
                    characterization and management methods and industry statistics.
                     Association of Oilwell Servicing
                     Contractors (AOSC)
                     6060 N. Central Expy., Ste. 428
                     Dallas, TX 75206
                     Phone: (214) 692-0771
                     Fax:   (214)692-0162
               Members: 600
               Staff: 4
               Budget: $500,000
               Regional Groups: 16
               Contact: M.L. Clark
                    AOSC was founded in 1956, and represents oil well servicing and workover
                    contractors, equipment manufacturers, and others related to the well servicing
                    industry. The organization publishes the monthly AOSC Newsletter, which
                    includes industry news, rig activity information, and legislative updates, and
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                    Well Servicing, a bimonthly journal that includes articles on new technology,
                    equipment and products.
                     Mid-Continent Oil and Gas
                     Association (MCOGA)
                     801 Pennsylvania Ave NW, Ste. 840
                     Washington, DC 20004-2604
                     Phone: (202) 638-4400
                     Fax:   (202) 638-5967
               Members: 7,500
               Staff: 6
               State Groups: 4
               Contact: Albert Modiano
                    The Mid-Continent Oil and Gas Association was founded in  1917 and
                    represents oil and  gas producers,  royalty owners,  refiners,  gasoline
                    manufacturers, transporters, drilling  contractors, supply and equipment
                    dealers and wholesalers, bankers, and other individuals interested in oil
                    business.
                     Western States Petroleum
                     Association (WSPA)
                     505 N. Brand Blvd., Ste. 1400
                     Glendale, CA 91203-1925
                     Phone:(818)545-4105
                     Fax:   (818) 545-0954
               Members: 35
               Staff: 32
               Regional  Groups: 4
               Contact: Douglas Henderson
               www.wspa.org/
                    The Western States Petroleum  Association was  founded in 1907  and
                    represents companies involved with petroleum exploration,  production,
                    refining, transportation, and wholesale marketing in Arizona, California,
                    Hawaii, Nevada, Oregon, and Washington.  WSPA offers advisory services
                    for industry members.
                     Offshore Operators Committee (OOC)
                     P.O. Box 50751
                     New Orleans, LA 70150
                     Phone: (504) 593-7443
                     Fax:   (504)593-7544
                Members: 110
                Staff: 1
                Contact: Mr. Virgil Harris
                e-mail:
                virsil  a harris(d),cnsD.cns.com
                    OOC is an industry cooperative representing nearly all of the operators in the
                    Gulf of Mexico.  They sponsor research on the effects of oil and gas
                    operations offshore and work with EPA on updates to  offshore NPDES
                    permits.
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                     Activities and Initiatives
                     Petroleum Technology Transfer
                     Council (PTTC)
                     1101 16th Street, NW, Suite 1-C
                     Washington, DC 20036
                     Phone: (202) 785-2225 or
                     (800)THE-PTTC
                     Fax: (202) 785-2240
                Regional Centers: 10
                Contact: Deborah Rowell
                www.vttc.ors/
                    The Petroleum Technology Transfer Council (PTTC) was formed in 1994 by
                    the U.S. oil and natural gas exploration and production industry to identify
                    and transfer upstream technologies to domestic producers. PTTC's technology
                    programs help producers reduce costs, improve operating efficiency, increase
                    ultimate recovery, enhance environmental compliance, and add new oil and
                    gas reserves. Through its 10 regional resource centers located at universities
                    around the country, PTTC offers expert assistance, information resources,
                    inter-disciplinary referrals, and demonstrations of E&P software solutions.
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                      Contacts and References
IX.  CONTACTS/ACKNOWLEDGMENTS/RESOURCE MATERIALS
For further information on selected topics within the oil and gas extraction industry, a list of contacts
and publications are provided below.

Contacts4
Name
Dan Chadwick
Steve Souders
Dan Derkics
Bruce Kobelski
Tom Aalto
Ron Jordan
Greg Nizich
Ralph Russell
Mike Miller
Charles Koch
James Erb
Jack Ward
Organization
EPA/OECA (Office of
Enforcement and Compliance
Assurance)
EPA/OS WER (Office of Solid
Waste and Emergency Response)
EPA/OSWER (Office of Solid
Waste and Emergency Response)
EPA/OW (Office of Water)
EPA/Region VIII
EPA/OW (Office of Water)
EPA/OAQPS (Office of Air
Quality Planning and Standards)
DOE/EIA (Department of Energy,
Energy Information
Administration)
Louisiana Department of
Environmental Quality
North Dakota Industrial
Commission, Oil and Gas Division
Pennsylvania Department of
Environmental Protection
Texas Railroad Commission, Oil
and Gas Division
Telephone
(202) 564-7054
(703)308-8431
(703) 308-8409
(202)260-7275
(303)312-6949
(202)260-7115
(919) 541-3078
(214) 720-6196
(225) 765-0272
(701) 328-8020
(717)772-2199
(512)475-4580
Subject
Compliance Assurance
Oil and Gas Wastes
Oil and Gas Wastes
Underground Injection
RCRA/ Problem Oil Pits
NPDES Issues
Air Issues
Industry Processes
Industry Processes,
State Waste Minimization
Program
Industry Processes
Industry Processes
State Waste Minimization
Programs,
Pollution Prevention
4 Many of the contacts listed above have provided valuable information and comments during the development of
this document. EPA appreciates this support and acknowledges that the individuals listed do not necessarily
endorse all statements made within this notebook.
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Oil and Gas Extraction 	Contacts and References

Section II: Introduction to the Oil and Gas Extraction Industry    	

EIA,  The  U.S.  Petroleum  Industry:  Past  as  Prologue^  1970-1992, Energy  Information
Administration, US Department of Energy, 1993.

EIA, Natural Gas Annual, Energy Information Administration, U.S. Department of Energy, 1997.

EIA,  U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Report, Energy
Information Administration, US Department of Energy, 1998.

EIA,  Petroleum: An Energy Profile, Energy  Information Administration, U.S.  Department of
Energy,   1999.  www.eia. doe.gov/pub/oil_gas/petr oleum/analysis publications/
petroleum profile 1999/profile99v8.pdf

IPAA, United States Petroleum Statistics:  1998 Data, Independent Petroleum  Association of
America. April 1999. ww\v.ipaa.ors/departm.ents/information_services/USPS.htm

Sittig, Marshall, Petroleum Transportation and Production: Oil Spill and Pollution Control, Park
Ridge, NJ: Noyes Data Corporation, 1978.

Smith, Glenda, American Petroleum Institute, written comments to Dan Chadwick, USEPA/OCEA,
September 22,1999.

US DOC, 1992 Census of Mineral Industries, Bureau of the Census, Economics and Statistics
Administration, US Department of Commerce,  1995.

US DOC, U.S. Industry and Trade Outlook '98, International Trade Commission, U.S. Department
of Commerce, McGraw-Hill, 1998.

US DOE, A Strategy for Methane Hydrates Research and Development, Office of Fossil Energy,
U.S. Department of Energy, August 1998.

US DOI, "Press Release: Babbitt Signs  Decision for Alaska Petroleum Reserve that Balances
Protection for Wildlife Habitat With Oil and Gas Development," Office of the Secretary, U.S.
Department of the Interior, October 7,1998,  www. doi. gov/news/98100 7. html

US EPA, Office  of Solid Waste, Background for NEPA Reviewers: Crude Oil and Natural Gas
Exploration, Development, and Production, U.S. Environmental Protection Agency, 1992.

Section HI; Industrial Process Description	

API, Oil and Gas Waste Management - Preliminary Results from API Survey, American Petroleum
Institute, 1997.

API, 1997 Joint Association Survey on Drilling Costs, American Petroleum Institute, 1998a.

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Oil and Gas Extraction
                      Contacts and References
API, Petroleum Industry Environmental Performance Sixth Annual Report, American Petroleum
Institute, 1998b.

Berger, Bill D. and Kenneth E. Anderson, Modern Petroleum — A Basic Primer of the Industry,
Third Edition, Tulsa, OK: PennWell Publishing Company, 1992.

Buckner, Edwin, EPA Region VII, e-mail to Dan Chadwick, EPA/OECA, December 15,1998.

Buist, Ian, "Window of Opportunity for In Situ Burning," in In Situ Burning of Oil Spills Workshop
Proceedings, New Orleans, Louisiana, November 2-4, 1998, William D. Walton and Nora H. Jason,
eds., Gaithersburg, MD: Building and Fire Research Laboratory, National Institute of Standards and
Technology, February 1999.

Deepstar, Proprietary information on platform/pipeline infrastructure and capacities in deepwater.
This information is part of a series of reports on future deep-water technologies and hypothetic
scenarios generated by a consortium of industry, academia, and the regulatory participants, 1994.

Deuel, Lloyd E. and George H. Holliday, Soil Remediation for the Petroleum Extraction Industry,
Second Edition, Tulsa, OK: PennWell Publishing Company, 1997.

EIA, Petroleum: An  Energy Profile, Energy Information Administration,  U.S. Department of
Energy, 1991.

Federal Register, vol. 61, no. 242, December 16, 1996, "Oil and Gas Extraction Point Source
Category; Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory; Final
Rule."

Fields, Stephen and Max Martin,  "The Plugging Process: Securing Old Gas & Oil Wells for the
Protection of the Environment," in Proceedings: Public Workshop, Decommissioning and Removal
of Oil and Gas Facilities Offshore California, F. Manage and B. Williamson, eds., Santa Barbara,
CA: Marine Science Institute, University of California, Santa Barbara, May 1998.

Fingas, M.L., "In Situ Burning of Oil Spills: A Historical Perspective," in In Situ Burning of Oil
Spills Workshop Proceedings, New Orleans, Louisiana, November 2-4, 1998, William D. Walton
and Nora H. Jason, eds.,  Gaithersburg, MD: Building and Fire Research Laboratory, National
Institute of Standards and Technology, February  1999.

IOGCC and US DOE, ^4 Study of Idle Oil and Gas Wells in the United States, Interstate Oil and Gas
Compact Commission, 1992.

IOGCC, IOGCC Environmental Guidelines for State Oil & Gas Regulatory Programs, Interstate Oil
and Gas Compact Commission, May  1994.

IOGCC, Produce or Plug: The Dilemma over the Nation's Idle Oil and Gas Wells, Interstate Oil and
Gas Compact Commission, December 1996.
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Oil and Gas Extraction
                    Contacts and References
Jordan, Ronald, EPA/OW, written comments to Dan Chadwick, EPA/OECA, 1999.

Kennedy, John L., Fundamentals of Drilling, Tulsa, OK: PennWell Publishing Company, 1983.

Lake, Larry W., Enhanced Oil Recovery, Englewood Cliffs, NJ: Prentice-Hall, Inc., 1989.

MMS, Federal Offshore Statistics, Minerals Management Service, U.S. Department of the Interior,
1995.

MMS, Gulf of Mexico OCS Oil and Gas Lease Sales 171, 174, 177, and 180 (Western Planning
Area) - Final Environmental Impact Statement, 1998.

MMS, Decommissioning Structures, Minerals Management Service, U.S. Department of the Interior,
\v\vw. mms. gov/tarp/es2a. htm. 1999.

National Research Council, An Assessment of Techniques for Removing Offshore Structures,
Washington, DC: Marine Board, Commission on Engineering and Technical Systems, National
Research Council, 1996.

Neff, Jerry M. and Theodor C. Sauer, Jr., "An Ecological Risk Assessment for Polycyclic Aromatic
Hydrocarbons in Produced Water Discharges to the Western Gulf of Mexico," in Produced Water
2: Environmental Issues and Mitigation Technologies, International Produced Water Symposium,
Mark Reed and Stale Johnsen, eds., New York: Plenum Press, 1996.

Rabalais, N.N., B.A. McKee, D.J. Reed, and  J.C. Means, "Fate and Effects of Produced Water
Discharges in  Coastal Louisiana, Gulf of Mexico, USA,"  in Produced Water: Technological/
Environmental Issues and Solutions, International Produced Water Symposium, James P. Ray and
F. Rainer Engelhardt, eds., New York: Plenum Press, 1992.

Shell Oil Company, Specific comments for draft EIS 152 and 155 (Section V). Data derived by
Shell Oil Company from discharge monitoring reports submitted to USEPA, Region 6 for 1992,
1994.

Sittig, Marshall, Petroleum Transportation and Production: Oil Spill and Pollution Control, Park
Ridge, NJ: Noyes Data Corporation, 1978.

Souders, Stephen, USEPA/OSW, written comments to Dan Chadwick, USEPA/OECA, December
30,1998.

Stephenson, M.T., "A Survey of Produced Water Studies," in Produced Water:  Technological/
Environmental Issues and Solutions, International Produced Water Symposium, James P. Ray and
F. Rainer Engelhardt, eds., New York:  Plenum Press, 1992.

Texas Railroad Commission, written comments to Dan Chadwick, EPA/OECA, January 9,  1999.
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Oil and Gas Extraction
                     Contacts and References
US DOE and IOGCC, Oil and Gas Exploration and Production Waste Management: A 17-State
Study, Office of Fossil Energy, U.S. Department of Energy, and Interstate Oil and Gas Compact
Commission, June, 1993.

US EPA, Office  of Solid Waste, Management of Wastes From Oil and Gas Exploration,
Development, and Production, Report to Congress, U.S. Environmental Protection Agency, 1987.

US EPA, Office of Solid Waste, Background for NEPA Reviewers: Crude Oil and Natural Gas
Exploration, Development, and Production, U.S. Environmental Protection Agency, 1992.

US EPA, Office of Solid Waste and Emergency Response, Understanding Oil Spills and Oil Spill
Response, U.S. Environmental Protection Agency, July 1993a.

U.S. EPA Office of Solid Waste and Emergency Response, SPCC Requirements and Pollution
Prevention  Practices   for   Oil  Production,  Drilling  and  Workover  Facilities,
www. epa. gov/oilspill/spcc/index. htm.

US EPA, Office of Water, Supplemental information for effluent limitation guidelines and new
source performance standards for the offshore subcategory of the oil and gas extraction point source
category (40 CFR 435), 1993b .

US EPA, Office of Water, Development  Document For Effluent Limitations Guidelines And
Standards For The Coastal Subcategory Of The Oil And Gas Extraction Point Source Category, US
Environmental Protection Agency, 1996.

US EPA, Office of Water, written comments to Dan Chadwick, EPA/OECA, September, 1999.

Wakim, Paul, API 1985 Production Waste Survey, American Petroleum Institute, 1987.

Wiedeman, Allison, "Regulation of Produced Water by the U. S. Environmental Protection Agency,"
in Produced Water 2: Environmental Issues and Mitigation Technologies, International Produced
Water Symposium, Mark Reed and Stale Johnsen, eds., New York: Plenum Press, 1996.

Williams, Howard R. and Charles J. Meyers, Manual of Oil and Gas Terms — Tenth Edition, rev. by
Patrick Martin and Bruce Kramer, New York: Matthew Bender & Company, 1997.

Zengel, Scott A. et al., Environmental Effects of In Situ Burning of Oil Spills in Inland and Upland
Habitats," in In Situ Burning  of Oil Spills  Workshop Proceedings, New Orleans, Louisiana,
November 2-4, 1998, William D. Walton and Nora H. Jason, eds., Gaithersburg, MD: Building and
Fire Research Laboratory, National Institute of Standards and Technology, February 1999.

Section IV; Chemical Release and Transfer Profile	

API, Oil and Gas Waste Management —Preliminary Results from API Survey, American Petroleum
Institute, 1997.
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Oil and Gas Extraction
                    Contacts and References
Pennsylvania DEP, Characterization and Disposal Options for Oilfield Wastes in Pennsylvania,
Bureau of Oil and Gas Management, Pennsylvania Department of Environmental Protection, June
1994.

Pennsylvania DEP, Oil Brine Characteristics Report, Working Draft, Bureau of Oil and Gas
Management, Pennsylvania Department of Environmental Protection, July 31, 1999.

US EPA, Office of Water, Development Document for Final Effluent Limitations Guidelines and
Standards for the Coastal Subcategory of the Oil and Gas Extraction Point Source Category, US
Environmental Protection Agency, 1996.

Section V; Pollution Prevention Opportunities	

API, Developing Area-Specific Waste Management Plans for E&P Operations, 1st ed., American
Petroleum Institute, Washington, DC, 1991.

County Sanitation Districts of Los Angeles County, Oil and Gas Extraction: Pollution Prevention
Opportunities Checklist, Industrial Waste Section, County Sanitation Districts of Los Angeles
County, 1990.

Michelet, J.F. "Down Hole Separation  Technology," in Produced Water 2: Environmental Issues
and Mitigation Technologies, International Produced Water Symposium, Mark Reed and  Stale
Johnsen, eds., New York: Plenum Press, 1996.

NETA, Keepin' It All Clean in the  Oil Patch - Field Guide, Phoenix: National Environmental
Training Association, 1995.

Petroleum Technology Transfer Council, New Technology Summaries, www.pttc.org/.

Souders, Stephen, USEPA/OSW, written comments to Dan Chadwick, USEPA/OECA, December
30,1998.

Texas Railroad Commission, Oil and Gas Division, Waste Minimization in the Oil Field, Revised
April 1999.

Texas Railroad Commission, Oil and Gas Division, Waste Minimization Case Histories-Drilling
Operations, \vww. rrc. state, tx. us/divisions/og/key-programs/.

U.S.  DOE-Fossil Energy: OilandNatural Gas Program, www.fe. doe. gov/programs/oil_gas. html.

U.S.  EPA Enviro$en$e website, http://es. epa. gov/.

U.S. EPA Natural Gas STAR Program, Lessons Learned, www. epa. gov/gasstar/.
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Oil and Gas Extraction
                    Contacts and References
Section VI; Summary of Federal Statutes and Regulations
Arbuckle, J. Gordon, et al. Environmental Law Handbook, 12th ed., Rockville, MD: Government
Institutes, Inc., 1993.

Environmental Law Institute, Sustainable Environmental Law, CeliaCampbell-Mohn, ed., St. Paul,
MN: West Publishing Co., 1993.

IOGCC, Produce or Plug: The Dilemma over the Nation's Idle Oil and Gas Wells, Interstate Oil and
Gas Compact Commission, December 1996.

MMS, "Outer Continental Shelf Lands Act," Minerals Management Service, U.S. Department of the
Interior, www. mms. gov/ocslands. htm, 1999.

National Research Council, An Assessment of Techniques for Removing Offshore Structures,
Washington, DC: Marine Board, Commission on Engineering and Technical Systems, National
Research Council, 1996.

Rittenhouse, Bryan, USEPA/OW, written comments to Dan Chadwick, USEPA/OECA, September
21, 1999.

US EPA, Office of Solid Waste, Background for NEPA Reviewers: Crude Oil and Natural Gas
Exploration, Development, and Production, U.S. Environmental Protection Agency, 1992.

US EPA, Office of Solid Waste and Emergency Response, "FAQ: What Substances are Covered?
Petroleum  Exclusion,"   U.S.  Environmental  Protection  Agency,   1998,  •www.epa.gov/
oerrpage/superfund/programs/er/triggers/haztrigs/whatsub3. htm.

US EPA, Office of Water, "Clean Water Act Section 403: A Framework for Ecological Risk
Assessment," U.S.  Environmental  Protection  Agency, 1999,  www.epa.gov/OWOW/oceans/
discharges/403, html.

Williams, Howard R. and Charles J. Meyers, Manual of Oil and Gas Terms — Tenth Edition, rev. by
Patrick Martin and Bruce Kramer, New York: Matthew Bender & Company, 1997.

Section VIII: Compliance Activities and Initiatives	

Interstate Oil and Gas Compact Commission, www.iogcc.oklaosf.state.ok.us/.

Sandra Jaszczak, ed., Gale Encyclopedia of Associations, 31st ed., International Thomson Publishing
Co.,  1996.

U.S. DOE, Office of Fossil Energy, Oil and Gas Environmental Research and Analysis Program,
www. fe.doe. sov/oil sas/oilsas 7. html.
Sector Notebook Project
153
October 2000

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Oil and Gas Extraction
                     Contacts and References
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Sector Notebook Project
154
October 2000

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