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
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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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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
IV
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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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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
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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
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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
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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
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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.
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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.
Sector Notebook Project
October 2000
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Oil and Gas Extraction
Introduction, Background, and Scope
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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Introduction, Background, and Scope
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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Introduction, Background, and Scope
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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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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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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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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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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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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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.
Sector Notebook Project
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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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Oil and Gas Extraction
Chemical Releases and Transfers
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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Oil and Gas Extraction
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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Oil and Gas Extraction
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.
Sector Notebook Project
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October 2000
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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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Oil and Gas Extraction
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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Oil and Gas Extraction
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).
Sector Notebook Project
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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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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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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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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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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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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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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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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).
Sector Notebook Project
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Compliance and Enforcement History
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
Sector Notebook Project
117
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Oil and Gas Extraction
Compliance and Enforcement History
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
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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
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Oil and Gas Extraction
Compliance and Enforcement History
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Sector Notebook Project
120
October 2000
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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
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-------
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Compliance and Enforcement History
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Oil and Gas Extraction
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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.
Sector Notebook Project 148 October 2000
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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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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.
Sector Notebook Project
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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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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.
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Contacts and References
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