OIL AND GAS BACKGROUND FOR NEPA REVIEWERS
BACKGROUND FOR NEPA REVIEWERS:
CRUDE OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT, AND PRODUCTION
Submitted to:
U.S. Environmental Protection Agency
Office of Solid Waste
Special Waste Branch
Crystal Station
2800 Crystal Drive
Crystal City, VA 20202
Submitted by:
Science Applications International Corporation
Environmental and Health Sciences Group
7600-A Leesburg Pike
Falls Church, VA 22043
December 10, 1991 Preliminary
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OIL AND GAS BACKGROUND FOR NEPA REVIEWERS
DISCLAIMER AND ACKNOWLEDGEMENTS
The mention of company or product names is not to be considered an
endorsement by the U.S. Government or by the U.S. Environmental
Protection Agency (EPA). This document was prepared by Science
Applications International Corporation (SAIC) in partial fulfillment of
EPA Contract Number 68-WO-0025, Work Assignment 61.
December 10, 1991 Preliminary Drarr
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BACKGROUND FOR NEPA REVIEWERS
TABLE OF CONTENTS
Page
INTRODUCTION 1
OVERVIEW OF OIL AND GAS EXPLORATION AND PRODUCTION 1
STATUTORY AND REGULATORY BACKGROUND 5
Leasing on Federal Lands 5
Safe Drinking Water Act
Clean Water Act 8
Clean Air Act (CAA) 9
Resource Conservation and Recovery Act 10
TECHNICAL DESCRIPTION OF EXPLORATION
AND PRODUCTION OPERATIONS 11
EXPLORATION AND DEVELOPMENT 11
Road Construction and Maintenance 11
Preliminary Exploration 11
Well Drilling l3
Drilling Fluids 16
Drilling Fluid Wastes I"7
Formation Evaluation 18
Well Completion |s
Completion Wastes :o
Well Stimulation ;°
Stimulation Wastes ^ 1
Well Abandonment ^1
Abandonment Wastes -l
OIL AND GAS PRODUCTION ;;
Field Design ^
Recovery --
Product Collection (Gathering) ^3
Produced Fluid Treatment ^
Two-phase Separator ^4
Three-phase Separator ^4
Free-Water Knockout ^6
Heater Treater ;6
Gas Dehydration ^6
Sweetening/Sulfur Recovery -6
Natural Gas Liquids Recovery ^7
Compression ^7
.Skimming Pit
Solids Removal ;jj
Produced Water -8
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OIL AND GAS
Waste Management 29
Exploration and Production Wastes 29
Reserve Pits 30
Annular Disposal of Drilling Wastes 31
Centralized Disposal Pits 31
Drilling Waste Minimization 31
Storage, Settling, and Skimming Pits and Tanks 32
Underground Injection 32
Discharge of Produced Waters to Surface Water 33
Evaporation and Percolation Pits 33
Land Farming 33
Surface Spreading of Produced Waters 33
Use of Produced Water for Irrigation 3-*
Central Treatment Facilities 34
Crude Oil Reclaimers 34
Road Building Materials 34
Casing Vent Gas Recovery 34
Gas Flares 35
Miscellaneous and Nonexempt Oil Field Wastes 35
Site Closure 35
POTENTIAL SIGNIFICANT ENVIRONMENTAL IMPACTS 36
POTENTIAL IMPACTS ON GROUND WATER 36
Exploratory and Development Drilling 36
Vertical Migration of Contaminants 3"
Ground-water Drawdown 3"
Production 3"
Migration of Stimulation Fluid to Ground Water 37
Damage and Blowout of Existing Wells 37
Migration of Injected Water to Ground Water 38
Migration of Steam and Other Injected Solutions to Ground Water 38
Potential Damages from In-situ Combustion 38
Migration of Gathering Line Spills to Ground Water 38
Product Stock Tank Leakage 38
Waste Management -W
Migration of Deep Well Injected Fluids 40
Migration of Annular Injected Fluids 40
Migration of Sweetening Wastes 40
Vertical Migration from Surface Treatment Sites 41
Site Closure 41
Vertical Migration of Closed Pit Contents to Ground Water 41
POTENTIAL IMPACTS ON SURFACE WATER 4J
Exploration and Development 4-
Site Runoff to Surface Waters 4-
Production 4-
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BACKGROUND FOR NEPA REVIEWERS
Migration of Product Stock Tank Leaks 42
Migration of Gathering Line Leaks 42
Venical Migration of Injection Fluids 42
Waste Management 42
Surface Water Discharges of Produced Water 42
Migration of Commingled Wastes 43
Runoff from Surface Treatment Sites 43
Migration of Sweetening Wastes 43
Site Closure 43
Sedimentation of Surface Waters 43
POTENTIAL IMPACTS ON SOIL 44
Exploration and Development 44
Compaction and Erosion from Road Building 44
Site Runoff 44
Production 44
Compaction and Erosion During Production 44
Product Stock Tank Leaks 44
Gathering Line Leaks 45
Injection Fluids and Saltwater Breakout 45
Waste Management 45
Pit Excavation, Overtopping and Seepage 45
Sweetening Wastes 45
Onsite Burial of Pit Wastes 45
Landfarming of Pit Wastes 46
Evaporation of Produced Water 46
Site Closure 46
Sedimentation of Surface Waters from Site Runoff 46
POTENTIAL IMPACTS ON AIR 46
Exploration and Development Drilling 47
Hydrogen Sulfide Emissions from Active Operations 47
Fugitive Dust Emissions 47
Machinery Exhaust Emissions 47
Production 47
Emissions from Gas Raring 47
Volatilization of Petroleum Fractions 47
Release of Hydrogen Sulfide from Sour Gas 47
Machinery Exhaust Emissions 48
Waste Management 48
Volatilization During Evaporation and Landfarming 48
POTENTIAL IMPACTS ON ECOSYSTEMS 48
Abiotic Ecosystem Parameters 48
Temperature 49
Water 49
Nutrients . . . , 49
Topography 50
Soils 50
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OIL AND GAS
Light 50
Flushing of Aquatic Ecosystems 51
Salinity 51
Turbidity and Suspended Sediments 51
Biotic Ecosystem Parameters 51
Rare and Endangered Species 51
Dominant or Important Species 52
Habitat . . 52
Terrestial Ecosystems 52
Environmental Release of Toxic Chemicals 52
Environmental Release of Other Chemicals 53
Physical Disturbance - Woodlands 53
Loss of Habitat Structure 53
Loss of Minimum Habitat Areas 54
Changes in Runoff 54
Physical Disturbance - Grasslands and Scrublands 55
Physical Disturbance - Tundra 55
Other Disturbances 56
Aquatic Ecosystems 56
Discharges to Open Waters and Wetlands 57
Drilling Muds and Cuttings 57
Produced Water 57
Summary 58
POTENTIAL IMPACTS ON LAND USE 58
Loss of Agricultural Land 59
Loss of Agricultural Irrigation 59
POSSIBLE PREVENTION/MITIGATION MEASURES .". 60
SUMMARY OF INFORMATION THAT SHOULD BE ADDRESSED
IN NEPA DOCUMENTATION 63
OTHER WASTES NOT UNIQUELY ASSOCIATED WITH
OIL AND GAS EXPLORATION AND PRODUCTION 66
IDENTIFICATION OF ADDITIONAL POTENTIAL IMPACTS 67
LIST OF CONTACTS 68
U.S. ENVIRONMENTAL PROTECTION AGENCY 68
U.S. DEPARTMENT OF THE INTERIOR 68
U.S. FOREST SERVICE 68
GLOSSARY ?0
December 10, 1991 Preliminary Draft
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BACKGROUND FOR NEPA REVIEWERS
REFERENCES
81
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BACKGROUND FOR NEPA REVIEWERS
BACKGROUND FOR NEPA REVIEWERS - CRUDE OIL AND NATURAL GAS
EXPLORATION, DEVELOPMENT, AND PRODUCTION
INTRODUCTION
The primary purpose of this document is to assist U.S. Environmental Protection Agency (EPA) staff
in providing scoping comments and comments on National Environmental Policy Act (NEPA)
documents for oil and gas exploration, development, and production activities proposed for Federal
lands. Pursuant to NEPA and Section 309 of the Clean Air Act (CAA), EPA reviews and comments
on proposed major Federal agency actions significantly affecting the environment. This document
was developed to assist the EPA reviewer in considering those issues most appropriate to oil and gas
operations in the development of NEPA/Seciion 309 comments. Ultimately, the document was also
intended to assist operators in planning their work on Federal lands and to assist Federal land
managers in the preparation of Environmental Impact Statements (EISs).
This document is not intended to be all-inclusive: rather, the document focuses on EPA's major
concerns with surface and ground water, air, and ecosystems and sensitive receptors as related to oil
and gas. It does not restate traditional NEPA concerns about impacts on floodpiains. archaeological
resources, etc., since they may occur at any development. Furthermore, it does not discuss (in detail)
human health risks associated with oil and gas practices, since such risks are very site-specific.
Finally, it addresses only onshore operations, and does not address offshore drilling and development.
The document is organized to provide a general description of site operations, potential environmental
impacts associated with each operation, possible prevention/mitigation measures, and types of
questions to be posed as pan of the Agency's response. EPA recognizes that each oil and gas
operation and each EIS is unique. Thus, reviewers may have to conduct additional analyses to fully
understand projected impacts. The reviewer should not rely solely on this document as a definitive
list of potential impacts or areas that should be covered by NEPA documentation. The particular
operations that are stressed include areas that, overall, have significant impact on the environment
These operations include reserve pits, drilling fluids/cuttings management, produced water disposal.
well site and road construction, product gathering systems (storage tanks and pipelines), and
production operations.
OVERVIEW OF OIL AND GAS EXPLORATION AND PRODUCTION
Oil and gas exploration and production includes all activities related to the search for and extraction
of liquid and gas petroleum from beneath the Earth's surface. Found almost exclusively in
sedimentary rocks, oil and natural gas accumulate in geologic confinements called traps which, by
virtue of an impermeable overlying layer, have stopped the migration of the fluid. The volume of
petroleum contained in a trap can vary from negligible to billions of barrels. The major areas of
onshore production in the United States include the southwest (including California), midwest and
Alaska, with lessor contribution from the Appalachians. (See Figure 1.)
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ligurc I. l.uciliun »f Major (HI and (ins 1'rodutlioii in the U.S.
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BACKGROUND FOR NEPA REVIEWERS
Though at one time such traps may have been close enough to the surface to allow easy detection
(i.e.. surface seepage), modern exploration relies on sophisticated geophysical testing techniques to
locate potentially producible formations. Gravitational and seismic surveys of subsurface geology
provide indirect indications of the likelihood of finding promising geological formations. This
process is complicated by the fact that, at least in the U.S., the average depth at which one may
reasonably expect to find oil is increasing since many of the largest shallow formations are assumed
to have been found already.
If geophysical evidence suggests the possibility of finding oil is good, operators secure the required
surface and mineral rights to the claim and prepare for drilling. If drilling is approved (by the
appropriate land management agencies) an exploratory, or 'wildcat" well is drilled. In spite of the
high level of effort dedicated to locating potential oil reserves, only 1 in 7 wildcats finds
hydrocarbons, and even less find enough oil under the right conditions to make production
economically feasible. Typically, oil and gas are found commingled in the same reservoirs and are
produced together. In addition, gas occurs in unique areas not associated with economic oil
production. In these cases, natural gas may be produced and marketed without the product treatment
facilities associated with oil production.
Modern well drilling involves the use of a rotary drill to bore through soil and rock to the desired
well depth. The drill bit is constantly washed with a circulating drilling fluid, or "mud." which
serves to cool and lubricate the bit and remove the cuttings to the surface. If the drill reaches the
desired depth and fails to locate a producible deposit of oil or gas, the well must be plugged and the
site abandoned. Even if oil and/or gas is found the well may not be producible. If the formation
fails to exhibit the right combination of expected volume, porosity, and permeability, the costs of
extraction would be prohibitive.
If an operator determines a well to be producible, the welV must be completed and prepared for
production. In instances where the reservoir is sufficiently large, "delineation" wells are drilled to
determine the boundary of the reservoir and additional "development" wells are drilled to increase the
rate of production from the "field." Because few new wells in the U.S. have sufficient energy
(pressure) to force oil all the way to the surface, submersible pumps are placed in the wells and
production begins.
This first phase of production, primary production, may continue for several to many years, requiring
only routine maintenance to die wells as they channel oil to the surface for delivery to refineries.
However, as the oil is removed from the formation the formation pressure decreases until the wells
will no longer produce. Because 70 percent of the total recoverable oil may remain in the formation.
additional energy may be supplied by the controlled injection of water from the surface into the
formation. The injected water acts to push the oil toward the well bores. Such secondary recovery
or "water flooding" projects may employ from a few to hundreds of injection wells throughout a field
to extend the life of the wells. Much of the water used for injection is water pumped along with oil
from the producing well, separated from the oil; and reinjected.
Often, service companies are hired by the oil company to perform many of the activities described
above. Typically these contractors drill the wells and perform other specific tasks such as installing
casing, conducting formation tests, and managing wastes, etc. (See Figure 2.) When a well or field
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OIL AND GAS
Figure 2. Interrelationship of Operator, Drilling Contractor,
and Service Companies
oPERATING
1 COMPANY
EXPLORATION
PRODUCTION
DIVISION
31
DRILLING DIVISION
>
COMPANY
REPRESENTATIVE
COMPANY
ENGINEER
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1
DRILLING
CONTRACTOR
RIG SUPERINTENDENT
-,--<
TOOLPUSHER
J
1
_ j
SERVICE
COMPANIES
(CONTRACTORS)
CEMENTING
TESTING
CASING
WASTE MANAGEMENT
DIRECTIONAL DRILLING
FEHINO
MUD ENG!NEERINO ""
.MUD LOGGING _
WIRELINE LOGGING
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i ,
(Adapted from Field Geologist's Training Guide. Expkxaooe Logging. 1980)
December 10, 1991
Prelimmarv Dr
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BACKGROUND FOR NEPA REVIEWERS
ceases to produce oil or gas at an economically feasible rate, the field must be abandoned and
reclaimed. Site closure includes the final disposal of the often considerable burden of wastes
generated during the life of the project. Wastes generated during drilling and production include
drilling tluids and cuttings and produced water.
The volume of drilling fluids and cuttings is in part a function of the depth of the well, which may
range from 1,000 to over 10.000 feet. (The average depth of well drilled today is somewhat less than
5.000 feet with estimated drilling wastes at approximately 2 barrels per foot (bbl/ft). The largest of
these wastes is formation water (called produced water), which is co-produced with oil in increasing
amounts as the well ages. The average rate of water production for U.S. wells is approximately 10
bbl water/bbl oil although this varies significantly in different parts of the country. Additional wastes
produced by oil and gas facilities include produced sand and pipe scale, wastes associated with well
workovers and completions, cementing wastes, residual oils, machinery wastes, and chemical
additives for a variety of uses. Wastes are sometimes disposed of in pits onsite. Produced water is
often injected either for secondary oil recovery or as a disposal method. Additional waste disposal
methods include land application, evaporation, or discharge to surface water.
A later section provides a detailed discussion of exploration and production operations as well as
typical methods used for waste management throughout the lifetime of a project.
STATUTORY AND REGULATORY BACKGROUND
Oil and gas operations are addressed under several Federal statutes. As described below, the
requirements of the National Environmental Policy Act are generally triggered during leasing actions
on Federal lands. In addition, several Federal environmental statutes supply requirements intended to
protect human health and the environment that are applicable to oil and gas operations. These include
the Safe Drinking Water Act, the Clean Water Act, the Clean Air Act and the Resource Conservation
and Recovery Act, which are discussed in more detail below. States may also have statutes and
regulations applicable to oil and gas regulation, however these are not addressed in this report.
Leasing on Federal Lands
Oil and gas development on United States lands is conducted pursuant to a leasing system under
which the lessee pays either a royalty on all oil and gas produced from the Federal land or a rental on
those leased Federal lands that are not in production.
The Mineral Leasing Act of 1920 [30 United States Code (USC) Section 180, a jfifl., as amended and
supplemented] is the law which provides the authority to lease oil and gas deposits on Federal lands.
Under it, the Secretary of the Interior is responsible for issuing and managing Federal oil and gas
leases. However, the Secretary can lease oil and gas deposits on lands within me National Forest
System only if the Secretary of Agriculture consents. Further, all surface operations under oil and
gas leases on National Forest System lands are subject to the prior approval by the Secretary of
Agriculture.
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OIL AND CAS
The Bureau of Land Management (BLM), the agency within the Department of the Interior which
administers the leasing program, also generally requires the consent of any other agency responsible
for managing a given Federal parcel (e.g., the Department of Defense or the Department of Energy)
before it will issue a lease for the oil and gas deposits. However, the BLM will not necessarily
require the consent .of agencies other than the Department of Agriculture before approving specific
surface operations once the lease has been issued.
The BLM regulations for administering the Federal oil and gas leasing program are found in 43 Code
of Federal Regulations (CFR) Pan 3100. For lands within the National Forest System, these
regulations are supplemented by the United States Forest Service regulations in 36 CFR Pans 228 and
261.
Since passage of the Federal Oil and Gas Leasing Reform Act of 1987 (which amended the Mineral
Leasing Act) most oil and gas leasing on Federal lands is conducted by competitive bid at oral auction
under the regulations in 43 CFR Pan 3110. Members of the public may nominate parcels for
inclusion in a competitive lease sale, or the BLM may identify appropriate parcels on its own motion.
Prior to actually offering lands for lease, the BLM must verify that they are legally eligible for
leasing, (i.e., they are not closed to leasing by law), and mat they are otherwise administratively
available and appropriate for leasing. To do this, the BLM initially uses the Resource Management
Plan to identify the general area to be leased. Resource Management Plans cover broad geographic
areas, and are designed to provide general guidance on future uses of BLM-managed lands, including
considerations of whether certain areas may be appropriate for oil and gas leasing. Under the BLM
planning regulations in 43 CFR Pans 1600 and 1601, the BLM must conduct a full scale
environmental analysis in accordance with NEPA prior to finalizing any Resource Management Plan
Lands which are considered appropriate for leasing under a Resource Management Plan will further
be reviewed by the BLM prior to being included in a lease sale. Traditionally, the BLM has not done
a full-scale NEPA review for specific parcels prior to lease issuance, rather, it has delayed full-scale
environmental review until a lessee requests permission to drill a well or initiate other surface-
disturbing activities. See 43 CFR 3162.5-1. Some courts, however, have required the BLM to do a
full-scale NEPA environmental impact statement prior to issuing specific leases unless the BLM
reserves the absolute right (by appropriate stipulation in the lease) to prohibit any and ail development
under the lease at some later date if necessary to protect environmental values. Therefore, the BLM
may conduct a full-scale NEPA review, either through an environmental assessment or an
environment^' impact statement, prior to lease issuance or only when the lessee seeks to begin
surface-disturbing activfcyr
The Forest Service regulations for determining which National Forest System lands are available for
lease are found in 36-FR-Ban 224. Under Forest Service regulations, the Forest Service issues
plans for management of all or part of a National Forest. As part of a Forest Plan, the Forest Service
will decide which lands, if any, should remain open to oil and gas leasing. The Forest Service will
conduct a full-scale NEPA analysis at me Forest Plan stage, and will also conduct a later NEPA
analysis, if appropriate, when the BLM proposes specific parcels for inclusion in an oil and gas lease
sale. Under its regulations, the Forest Service will consent to lease a given parcel only if it
determines that the environmental effects of leasing have been adequately addressed, and that leasing
is consistent with the applicable Forest Plan. The Forest Service, like the BLM, has authority to
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BACKGROUND FOR NEPA REVIEWERS
require that specific leases conuin special stipulations to protect the environment. Lands offered for
competitive sale which do not receive an adequate bid may then be offered for noncompetitive lease
sale to the first qualified offerer. See 43 CFR Pan 3110.
The BLM regulations in 43 CFR Part 3160 govern all aspects of production and development
operations on the leased Federal lands (including drilling, road construction, waste disposal,
reclamation, etc.). These regulations also govern operations on oil and gas leases on Indian lands.
although Indian oil and gas leases are not issued by the BLM; they are issued by the Bureau of Indian
Affairs within the Department of the Interior (under separate regulations). The Forest Service
regulations in 36 CFR Part 228 establish the criteria for Forest Service approval or rejection of
surface-use plans for operations on National Forest System lands.
Under the Oil and Gas Leasing Reform Act, the BLM and the Forest Service must require a bond
adequate to ensure reclamation of leased areas. The BLM bonding regulations are found in 43 CFR
Subpart 3104. They require submission of a surety or personal bond which will ensure compliance
with the Mineral Leasing Act and regulations, including complete and timely plugging of wells.
reclamation of the leased areas according to a plan approved by the BLM (or the Forest Service, for
National Forest System lands) as required in 43 CFR Subpart 3161, and the restoration of any lands
or surface waters adversely affected by lease operations after the abandonment or cessation of
operations. For National Forest System lands, the Forest Service regulations in 36 CFR Part 228
provide that the Forest Service may require additional bonding if it finds the BLM bond is inadequate
to reclaim and/or restore any lands or surface waters adversely affected by lease operations after
cessation of operations on the leased property.
Safe Drinking Water Act
The Safe Drinking Water Act (SDWA) specifically addresses oil and gas operations under its
Underground Injection Control (UIC) Program. This program is intended to protect usable
groundwater from contamination by injected fluids. Underground injection wells used in the
production of oil and gas are classified as Class II wells and are used to dispose of produced waters.
to inject fluids for enhanced recovery, and to store hydrocarbons (that are liquid at standard
temperature and pressure). Minimum requirements for UIC programs are established in 40 CFR
Parts 144. 145, and 146. State UIC programs must meet these minimum requirements in order to
achieve primacy.
These minimum requirements stipulate that underground injection, except as permitted by the UIC
program, is prohibited. In addition, the UIC program establishes specific construction, operation, and
closure requirements, such as casing and cementing, plugging and abandonment, and monitoring ot
injected fluids and mechanical integrity of wells. Despite these measures, contamination of drinking
water occurs via improperly plugged abandoned wells, casings, and through direct injection into
aquifers. In 1989, EPA initiated evaluation of the UIC program. A Mid-course Evaluation
workgroup convened to evaluate the effectiveness of the technical aspects of the UIC regulations.
The workgroup recommended revision of the operating, monitoring, and construction requirements.
In December 1990, EPA established a Federal Advisory Committee consisting of representatives rrom
EPA industry, the states, and environmental groups to implement the recommendations put torth by
the Work Group. This committee is currently developing three guidances that are expected to be
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December 10, 1991 '
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OIL AND GAS
released in 1992: (1) Operating. Monitoring and Reporting for Class IID Commercial Salt Water
Disposal Wells; (2) Management and Monitoring Requirements for Class II Wells in Temporary
Abandoned Status.; and (3) Follow-up to Class II Well Mechanical Integrity Failures.
Clean Water Act
Under the Clean Water Act, discharges to surface waters by oil and gas exploration and production
activities are primarily addressed under the National Pollutant Discharge Elimination System
(NPDES). EPA has promulgated national effluent guidelines for point source discharges from active
oil and gas exploration and production operations in three categories: sites in territorial waters, on-
shore, and coastal discharges. Coastal discharges are from operations located in waterbodies (or
wetlands areas adjacent to waterbodies) that are inside the territorial waters. Coastal discharges are
required to meet the technology-based effluent guidelines listed at 40 CFR §435.42. On-shore
discharges, including potentially contaminated runoff, are prohibited, except for stripper oil wells (10
barrels per well per day) and discharges of produced water that are determined to be beneficial to
agriculture or wildlife propagation (see 40 CFR §435.30). To date, the Agency has not promulgated
discharge limitations for stripper welts. As a result, technology-based permit limitations for stripper
wells are developed on a case-by-case basis or in a State-wide general permit. In all cases where
discharges from oil and gas operations are allowed. NPDES permit writers must ensure that effluent
limits provide for compliance with applicable water quality standards.
Under section 319 of the Clean Water Act. each State has been required to develop and implement
programs that identify and regulate non-point source discharges from industrial facilities, including oil
and gas exploration and production sites. EPA's role has generally been limited to reviewing Sute
plans and providing program guidance. It should be noted that, under 19 amendments to the Coasul
Zone Management Act. EPA is required to develop and publish guidance identifying "management
measures" for sources of non-point pollution in coastal waters. These measures must reflect the
greatest degree of pollutant reduction achievable through the application of the best available non-
point pollution control practices, technologies, processes, siting criteria, operating methods, or other
alternatives.
Under Section 402(p) of the Clean Water Act, EPA is required to issue NPDES permits for
contaminated storm water discharges from oil and gas operations. Only oil and gas facilities that
have had a discharge of storm water resulting in the discharge of a reportable quantity (as evidenced
by a sheen) for which notification is or was required pursuant to 40 CFR 110.6. 117.21. or 3026 at
any time since November 16, 1987, QJ contributes to a violation of a water quality standards are
required to apply for a NPDES permit.
Finally, oil and gas exploration and production operations, which involve placing dredged or fill
material in water in the United States (including many wetlands areas), must submit an application to
the U.S. Army Corps of Engineers under Section 404 of the Clean Water Act. The Corps and EPA
evaluate the Section 404 application according criteria developed by EPA to determine whether to
allow the proposed action.
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BACKGROUND FOR NEPA REVIEWERS
Clean Air Act (CAA)
L7nder the Clean Air Act (Section 109, 42 USC §7409), EPA established national primary and
secondary air quality standards for six criteria pollutant*. These National Ambient Air Quality
Standards (NAAQS) set maximum acceptable concentration limits for specific airborne pollutants.
including lead, nitrogen oxides, sulfur dioxide, carbon monoxide, ozone, and suspended paniculate
matter of less than 10 microns in diameter. State and local authorities were given the responsibility
of bringing their regions into compliance with the NAAQSs. The primary vehicles for attainment are
State Implementation Plans (SIPs). States were also given the authority to promulgate more stringent
requirements.
The CAA also defines enforceable emission limitations for seven hazardous pollutants. National
Emissions Standards for Hazardous Airborne Pollutants (NESHAPs) include benzene. However, none
of these limitations applies to exploration and production. The 1990 amendments to CAA
significantly expand the list of the specific pollutants for which national emissions standards must be
determined.
New Source Performance Standards (NSPS), authorized by Section 111 of the CAA, set forth
allowable emissions for new major sources and major modifications to existing sources. NSPS can
extend to pollutants not included in the NAAQS and the NESHAPs. (Of particular interest to the
exploration and production industry are volatile organic compounds (VOCs) and hydrogen sulfide.)
NSPSs have been promulgated for a number of source categories which may affect exploration and
production operations. (See 40 CFR Part 60. a sfifl.) These include industrial steam generators.
storage vessels for petroleum liquids, volatile organic liquid storage vessels (including petroleum
liquid storage vessels), and gas processing plants (VOCs and SCX). Specific NSPSs depend on
whether the region has achieved compliance with the NAAQS and whether Non-Significant
Deterioration (NSD) restrictions apply.
Under the 1990 amendments to CAA, Congress requires EPA to establish technology-based standards
for a variety of hazardous air pollutants. EPA is required to publish a list of source categories by
November 1991, present a schedule for settmg standards by April 1992, and establish specific
technology based standard* for the selected sources between 1993 and the year 2090. Note that the
list of categories may extend to exploration and production facilities such as flaring units and drilling
fluid and cutting storage pits. Additionally, section 112(n)(5) of the Clean Air Act Amendments of
1990 requires the Administrator of EPA to conduct an assessment of the hazards to public health and
the environment resulting from the emission of hydrogen sulfide associated with the extraction ot oil
and natural gas resources and submit a report to Congress containing findings and recommendations
within 24 months of the enactment of the Amendments. This section also authorizes the
Administrator to develop and implement a control strategy under this section and section 111 for these
emissions based on the findings of the study. Section 112(n)(4) contains certain constraints on
categorization of oil and gas wells and pipeline facilities as major sources.
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December 10, 1991 y
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OIL AND GAS
Resource Conservation and Recovery Act
Under Section 300l(b)(2)(A) of the 1980 Amendments to the Resource Conservation and Recovery
Act (RCRA), Congress conditionally exempted several types of solid waste from regulation as
hazardous wastes. Among, the categories of waste exempted were "drilling fluids, produced waters,
and other wastes associated with the exploration, development, or production of crude oil or natural
gas..." Section 8002(m) of the 1980 Amendments required EPA to study these wastes as well as
existing State and Federal regulatory programs and submit a report to Congress. The Amendments
also required EPA to determine whether the regulation of these wastes as hazardous wastes was
warranted.
EPA determined the extent of the statutory exemption and thus, the scope of its Report to Congress
on Oil and Gas Wastes, based on RCRA's statutory language and legislative history. EPA conclude
that there are three criteria for determining whether a waste is exempt. First, the scope of the
exemption covers wastes related to activities that locate, recover, and purify oil or gas, provided tha
the purification process is an integral part of primary field operations. Secondly, primary field
operations include production-related activities, but do not encompass transportation or manufacrurm
activities (e.g., pigging wastes from transportation pipelines with respect to oil production; primary
field operations encompass operations at or near the well head prior to transport to a refinery scope
the exemption). Finally, wastes must be intrinsic to and uniquely associated with these activities
(e.g., wastes solvents from cleaning operations are not exempted) and must not result from
transportation or manufacturing to maintain the exemption. With respect to gas production, wastes
associated with production (including purification through a gas plant) but prior to transport of tne g;
to market, are excluded.
With EPA's 1987 "Report to Congress on Management of Wastes from the Exploration.
Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy* and the July !98i
regulatory determination, the Agency completed these activities stating that regulation as hazardous
wastes under Subtitle C was not warranted. Instead, wastes could be better controlled through State
and Federal regulatory programs including Subtitle D of RCRA. Currently, EPA is in the early
stages of developing a Federal Subtitle D program to address oil and gas wastes exempt from Submit
C.
As stated in the July 6, 1988 Regulatory Determination (53 £R 25454), the Agency believes that
produced water, drilling fluids and cuttings, and certain associated wastes should be exempt from
Subtitle C. Examples of the exempted associated wastes include: well completion, treatment, and
stimulation fluids; basic sediment and water and other tank bottoms from storage facilities that hold
product or exempt waste; workover wastes: packing fluids; and constituents removed from produced
water before it is injected or otherwise disposed of. However, the Agency believes that some
associated wastes were not contained in the original exemption. These include: unused fracturing
fluids or acids; gas plant cooling tower cleaning 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; and others, most of which are not uniquely associated with oil *n<
gas activities. These wastes may be regulated under Subtitle C as hazardous wastes if they are listed
or exhibit a characteristic (see 40 CFR 260-271).
December 10, 1991 10 Prel.rmrun
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BACKGROUND FOR NEPA REVIEWERS
TECHNICAL DESCRIPTION OF EXPLORATION
AND PRODUCTION OPERATIONS
EXPLORATION AND DEVELOPMENT
Exploration and development activities described below include well drilling, completion, stimulation.
abandonment, and waste management. Production operations, which begin after well completion
(and, if necessary, stimulation), include primary and secondary recovery, product collection.
produced fluid treatment, and waste management. Exploration and production operations and major
activities that may occur during each, are described in the following subsections.
Road Construction and Maintenance
Initial land disturbance associated with oil and gas operations usually occurs when roads are
constructed to access areas for exploration, drilling and development. In some exploration off-road
vehicles may be used, avoiding the necessity of road building; however, to move many drill rigs and
other equipment to drill sites, graded roads are constructed and maintained. In constructing roads,
grading, installing culverts, and building berms may affect surface drainage patterns. In an effort to
control dust, roads are often sprayed with water or other liquids on a regular basis.
Preliminary Exploration
Based on initial geologic research, areas that have promising geologic structure and composition are
identified. Geophysical exploration or prospecting is then conducted, typically using seismic surveys
to delineate the subsurface structure and identify potential traps where hydrocarbons may have
accumulated. (See Figure 3.)
Seismic surveys delineate stratigraphy by measuring the speed of shock waves as they propagate
through the subsurface, reflecting, refracting (bending) and traveling at different speeds through
different rock types. Generally, the shock is caused by a charge set below the surface (usually a 50
pound charge at a depth of 100 - 200 feet) or slightly above the surface (2.5 to 5 pound charge). In
some cases, a thumper truck may be used in place of a charge. As the shock waves travel, a sensor
called a geophone, located a set distance from the shock initiation point, detects the shock waves as
they surface. The shock waves, after they are reflected or refracted, appear at the surface as a
portion of their initial energy and are correlated with the time and distance traveled to delineate
subsurface structures. Typically, seismic surveys are conducted along transects with repeated trips
along the survey line necessary to maintain lines and equipment. This may in turn require road
construction or at a minimum create 4-wheel drive trails along each transect.
A less popular method of collecting geophysical information is through gravity surveys which detect
small variations in gravitational attraction that correspond to differences in the density of various rock
types-
December 10, 1991 11 Prelimiiurs
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i >
~u
|
( )
Figure 3. Typical Oil and Gas Structural Laps
l,ow Permeability
Formation
o
p
O
fc
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BACKGROUND FOR NEPA REVIEWERS
Seismic surveys or other indirect prospecting can be confirmed with direct explorations such as
mapping of rock outcrops and oil seeps and review of drill cores. All available information is used in
determining whether to drill a well and in selecting the well site.
Well Drilling
A well site is selected on the basis of seismic and gravity surveys, known geologic data, topography,
accessibility, and lease requirements. Typically, a drilling contractor is hired to do the actual field
work with supervision by the operator's geologist and drilling engineer. In addition to drilling, which
is generally contracted to an outside firm, other outside contractors provide services such as well
logging, mud engineering, and well stimulation.
Drilling operations require construction of access roads, drill pads, mud pits, and possibly work
camps or temporary trailers. Typically, drilling operations continue 24 hours a day, 7 days a week.
A portable lab trailer is onsite to determine initial oil and gas shows (traces of oil and gas) from
cuttings (pieces of rock cut from the formation at depth) obtained at the depths of interest.
After the well site is selected, the drill pad is prepared. Drill pads generally range from 2 to 5 acres;
they are level areas used to stage the drilling operation. Usually, the pad accommodates the rig and
associated facilities (i.e., pumps, mud tanks, the reserve pit, generators, pipe racks, etc.). (See
Figure 4.) The most commonly used rig is the rotary drilling ng, which is usually powered by a
diesel engine. The rig employs a hoist system (which consists of a derrick, crown block, and
traveling block) to lift and lower the drill. The drill bit is fastened to (and rotated by) a hollow drill
string, with new sections or joints being added as drilling progresses. The cuttings are lifted from the
hole by drilling fluid, which is continuously circulated down the inside of die drill string through
nozzles in the bit. and upward in the annular space between the drill pipe and the borehole or casing.
The drilling fluid or mud lubricates and cools the bit. maintains downhole pressure control, and helps
bring the cuttings to the surface. (See Figure 5.)
At the surface, the returning fluid (mud) is typically diverted through a series of tanks or pits, where
the cuttings separate from the mud. In many cases, cuttings shale shakers, desanders. and desilters
are also used to aid in separating cuttings from fluid. The waste sand and silt removed from the mud
is typically disposed of in a reserve pit. After the cuttings are removed, the mud is picked up by the
pump suction, and the cycle is repeated. Drill cuttings are one of the largest wastes associated with
drilling. Mostly rock, the cuttings discharged to the reserve pit may contain up to 10% adhered
drilling fluid solids. As a result, potential pollutants generally mimic those of the drilling fluids used.
as discussed in the next section.
The initial hole is drilled to a depth of about 100 feet, and a conductor pipe or casing is cemented in.
The required depth of the conductor pipe is a function of the potential for washout of the hole while
drilling to surface casing depth (see below), formation pressure, and the location of any USDWs.
The pipe must be set in rock that is strong enough to handle the maximum anticipated pressure. A
series of Blowout Preventer (BOP) valves are attached to the well. A blowout occurs when formation
pressure exceeds the mud column pressure, which allows the formation fluids to blow out of the hole.
This is a costly, highly feared hazard of drilling. Proper mud design is essential to prevent this
problem.
December 10, 1991 13 Preliminary Draft
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OIL AND CAS
Figure 4. Aerial View of a Typical Well Site
Mud
Pit
Mud Pump
Drilling Rig
Well
Mixing Tank
Shale Shaker
Reserve Pit
Spent Mud and
Cuomgs
After W«fc». A£. The Oil md G- Book. 1985
December 10. 1991
14
Preliminarv Dr.ii
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Ngure 5. Ruiary Drilling Rig
R
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OIL AND GAS
Drilling is resumed after the installation of casing and BOP valves, using a smaller bit. When the
drilling depth reaches several hundred feet, the drill string and the bit are pulled out of the hole and
surface casing is lowered into the hole and cemented in. (The depth of surface casing depends on the
location of USDWs, formation pressures, and the tendency of the bore to slough.) This operation
prevents any sloughing of the surface formation into the hole: it is also intended to protect any
aquifers from being contaminated. If deeper fresh-water aquifers are present, cement can be squeezed
through cubing to plug off the fresh-water zones and prevent dilution of the mud column (and possibly
intrusion of contaminants into the freshwater zone). This prevents alteration of the mud density and
the swelling of clays encountered in some formations.
During the drilling process, the drilling string is pulled from the hole periodically to change the bit,
install casing, and/or remove core samples from the well bore. As explained previously, first the
conductor pipe is installed to a depth of approximately 100 feet and BOP valves are installed. Then,
when drilling reaches below the fresh-water zones or aquifers, the surface casing is installed. In
exploratory wells, after the surface casing is set, the well is drilled to its final depth prior to installing
the final casing. Because well casing is costly, deeper casing strings will not be installed until the
production potential of the well is determined. Conversely, development well casing may be set as
the well is drilled to prevent caving of the bore. In these wells, as the drilling proceeds, additional
casings of smaller diameter are lowered into die well and cemented in. Usually, 90-foot joints made
of three 30-foot sections are successively lowered into the hole until they reach the final depth. As
casing is set, waste drilling muds and cement returns are circulated to the surface. The setting of
casing and preparation of the well for production is called completion and is described in further
detail in a following section.
Drilling Fluids
Although drilling can be conducted without using fluids (muds), most drilling requires a fluid mud to
cool the bit and control downhole pressure. In soft-rock areas, successful completion of a well may
require very precise control of mud properties. In hard-rock areas, water may be satisfactory and is
sometimes even a superior drilling fluid. In addition to liquid muds, both air and gas are used as
drilling fluids in many areas. Therefore, the selection of mud type is governed by the specific
requirement of the geologic area. It also depends on the drilling fluid's ability to cool and lubricate
the bit and drilling string; remove and transport cuttings from the bottom of the hole to the surface;
suspend cuttings during times when circulation is stopped; control encountered subsurface pressures;
and wall the hole with a low-permeability filter cake in poorly consolidated formations.
A typical mud consists of a continuous phase (liquid phase), a dispersed gel-forming phase such as
colloidal solids and/or emulsified liquids, which furnish the desired viscosity, and wall cake. Muds
may be either water- or oil-based with other dispersed solids such as weighting materials and various
chemicals added to control the mud properties.
A water-based mud may consist of either fresh-water or salt-water mud. Fresh-water mud can simply
be a clay-water mixture, a chemically treated clay-water mixture, or calcium-treated muds. In a salt-
water mud, the clay mineral (attapulgite) hydrates and forms a stable suspension in salt water. Such
clays are commonly called salt-clays and are used in saline water in about the same manner as
December 10, 1991 16 Preliminary Dr.rt
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BACKGROUND FOR NEPA REVIEWERS
bentonite is used in fresh water. In general, the difference between fresh- and salt-water muds is the
type of clay used as the gel-forming phase.
Oil-based muds are expensive and are used as a special-purpose drilling fluid. They are insensitive to
common contaminants such as salt, gypsum, and anhydrite, since these compounds are insoluble in
oil. The principal use of the oil-based muds are:
Drilling and coring of possible production zones to determine the water content, permeability,
and porosity of the formation
Drilling of bentonitic (heaving) shales that continually hydrate, swell, and slough into the hole
when contacted with water
High-temperature drilling, where possible solidification or other problems make other muds
undesirable
As a perforating fluid (normally, a few barrels spotted opposite the zone to be perforated will
prevent contamination of the section after it is perforated) (See below for description of
perforation)
Freeing of stuck pipe, lubricity control, corrosion prevention, and remedial work on
producing wells.
The alteration of mud density may prevent problems due to lost mud circulation. This approach
includes the use of air and natural gas as drilling fluids. The main benefit of using such practices is
the economy from a large increase in penetration rate. However, there are hazards involved (i.e..
explosions and fires); and extra safety precautions are necessary.
Drilling Fluid Wastes
Because of the wide range of mud designs in use, the potential contaminants to be found in used
drilling fluids varies substantially from site to site. Further, since used muds are stored in the reserve
pit, they may be exposed to other contaminants from the operation.
Chlorides from downhole brines, salt domes, or salt water based muds can be found in high
concentrations. Muds in the reserve pit may have chloride concentrations of 1.5 to 30.0 ppt (EPA,
1987). Barium, from barite used as a weighting agent, may reach 400,000 mgA in muds used for
deeper wells (Neff; EPA). Because of contact with petroleum bearing formations (as well as the use
of petroleum as an additive), used drilling fluids may contain a number of organic compounds of
potential concern. These include naphthalene, toluene, ethyl benzene, phenol, benzene, and
phenanthrene. Finally, used drilling fluids may contain a number of inorganic compounds, either
from additives or from downhole exposure. Such substances include arsenic, chromium, lead,
aluminum, sulfur, and various sulfates.
December 10, 1991 17 Preliminary Dran
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OIL AND GAS
Formation Evaluation
Formation evaluation methods such as well logging and drill stem testing are means of determining
whether or not a well can be completed for commercial production. These methods are also useful in
defining individual characteristics of the pay zone, which dictate the completion method. Well
logging consists of graphical portrayal of drilling conditions or subsurface features encountered that
relate to the progress or evaluation of potential zones. Wireline logs are specific types of well logs
that are generated by lowering sensors down the well on a wireline. These sensors remotely measure
electric, acoustic, and/or radioactive properties of the rocks and their fluids. Drill-stem testing uses
the temporary isolation of a prospective formation (from other formations that have been penetrated)
by means of relieving the mud pressure so the fluids can flow into the drill stem. Coring consists of
cutting and retrieving a relatively large, intact chunk of the formation rock to determine porosity,
permeability, and fluid content.
If an exploratory well is successful and has sufficient reserves to be economically developed, the well
is completed (see next section), and depending on the reserves characteristics, an oil field may be
developed by installing more wells. However, if the exp; atory well does not show signs of
potential economic production, the well is plugged and abandoned (see section on abandonment).
Well Completion
After reaching the desired depth and determining that the well has tapped sufficient reserves to be
economically developed, the well is completed. Cased holes are the most common type of well
completion. First, casing strings are cemented in the hole (casing strings are joints of casing, and
each joint is approximately 30 feet long). Then production tubing strings are set inside the casing
(tubing strings are joints of tubing or piping through which the hydrocarbons flow; each joint is about
30 to 32 feet long). Packers (removable plugs) are set to separate producing zones (if desired).
Before the tubing strings are set, to let the pay-zone fluids enter the cemented casing strings,
operators use perforating guns to perforate the casing down hole. A perforating gun is lowered into
the hole on a conductor cable (a cable that transmits electrical signals) by wireline until it reaches the
depth of the pay zone or zone to be perforated. The perforating gun is then fired, penetrating the
casing with bullets fired from the gun and creating channels from the formation to the well bore. At
this time, the pressure exerted by the fluid within the casing typically exceeds the formation pressure
so no formation fluids can enter the casing. To allow formation fluids to enter the well, fluid inside
the well bore (brine solution with chemical additives to control flow from the formation) is swabbed
by a cylindrical rubber cup on a cable through the tubing strings. This waste (brine and chemical
additives) is usually discharged to the reserve pit.
A well may be completed with single completion (completed in one formation); multiple completion
(completed in separate formations at the same time with separate production equipment for each
formation); or commingled completion (completed in more than one formation at the same time using
a common production system). (See Figure 6.)
In some parts of the country, formation sands affect production by interfering with surface production
equipment. This occurs most often in West Coast and Gulf Coast areas that produce from zones
December 10, 1991 18 Preliminary Dran
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BACKGROUND FOR NEPA REVIEWERS
Figure 6. Cross Section of a Weil with Multiple Completion
Surface
Casing
n
Production
Casing
Conductor
Casing
Casing Spool
as ing Head
Product!on Casing
Tubing Strings.
, Ground Surface
Water Table
Fresh Waier Zone
Confining
Zone
Zone 1
ZoneZ
Perforations
December 10. 1991
19
Prelimmar. 2'j".
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OIL AND GAS
where the sand grains have poor cohesive properties. The sand is produced with the oil and water,
causing problems in the treating and separating process (e.g., sand grains destroy production
equipment). Downhole installation of a gravel-packed liner helps reduce the sand entry into the
production line. The gravel-packed liner is made from production casing with small screens instead
of holes or slots. The space between the screen and the sides of the borehole is filled with coarse
sand, which helps filter out the formation sand.
Completion Wastes
Wastes from well completion include fluids placed in the well to control pressure. These fluids may
be water with or without additives (salts, organic polymers, or corrosion inhibitors) used to control
density, viscosity, and filtration rates; prevent gelling of the fluid; and reduce corrosion. Generally
discharged to the reserve pit or a dedicated completion pit, completion wastes also include waste
cement, residual oil, paraffins, and other materials cleaned out of the bore.
Well Stimulation
In some cases, after a well is completed, the formation does not show a promising amount of
petroleum products as indicated on a well log or core samples. The porosity or permeability of the
zones may be too low for the flow to take place, or the drilling mud may have damaged the formation
by plugging up the pores and reducing the permeability near the well bore. Operators use a variety
of well-stimulation techniques to correct these problems during the exploratory and development
phases of the well. Usually well-stimulation activities are contracted out to service companies Well
stimulation is often conducted initially when the well is completed, and may be conducted on a
routine basis throughout the operating life of the well to maintain the flow rate. Stimulation
conducted on an actively producing well is often referred to as a "workover."
The two most often used techniques for stimulating a well are acidizing and fracturing. Acidizing
increases the permeability of the formation in the area near the well bore and increases local pore
size. Acidizing dissolves waxes, carbonates, and other materials clogging the area near the bore
After the acid treatment, the "spent" acid is allowed to flow back. If the well will not flow, it is
swabbed to draw liquids out (by means of a rubber cup lowered into a well by a cable). Today.
acidizing is applied primarily to carbonate (limestone and dolomite) rock. Hydrochloric acid (HCI) is
by far the most common acid because it is economical and leaves no insoluble reaction product
Other acids used are formic acid, acetic acid, and hydrofluoric acid, and mixtures of these acids
Acidizing is a localized stimulation method. Depending on the formation, type of acid used, volume
of acid used, and pump rate, the extent of stimulation varies. Usually between 200 and 2.000
gallons, the spent acid is usually trucked away for disposal at proper facilities by the service company
providing the work. The swabbed fluid from the well bore is usually brine, and is handled like
produced water.
Another method used to stimulate a well is hydraulic fracturing. Hydraulic fracturing involves
pumping a fluid (acid, oil, water, or foam) into the rormation at a rate that is faster than the existing
formation pore space can accept. The formation will crack due to the high pressure induced by the
December 10, 1991 20 Preliminary
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BACKGROUND FOR NEPA REVIEWERS
fracturing process. A proppant material such as sand, glass beads, or ground walnut shells is pumped
with the treating fluid to prevent the fracture from closing (i.e., they prop open the fractures).
After the desired stimulation technique has been applied, the well is retested for flow rate. If the
results are poor, the well is plugged. If the formation shows improvement and it becomes economic
to operate, production equipment will be installed to lift the petroleum to the surface where it can be
treated to remove impurities and marketed.
Stimulation Wastes
Wastes generated from stimulation are spent fluids including weighting agents, surfactants, muds,
produced water, acids, inhibitors, gels, solvents, and other materials. These fluids are generally
produced with petroleum as formation pressure forces the fluids back to the well bore. As a result.
much of the material is removed from the production stream at the production treatment facilities
described later. Initial returns may be discharged to the reserve pit or a dedicated workover pit.
Alternatively, some of the fluids may be removed by vacuum truck to off site disposal facilities.
Well Abandonment
As discussed above, if a wildcat well is not a success, it is plugged and abandoned. In addition,
production wells may be plugged or abandoned if the lease is no longer economically feasible, and
facilities may be removed to other leased properties where they can be utilized more efficiently.
For wildcat wells that are not successful, the procedure used to plug a drilled hole varies, depending
on hole conditions and regulatory requirements. The objective in plugging a hole is to prevent cross
flow between major geological formations. A cement slurry, circulated in place with the driil string,
is often used to plug dry holes. In some cases, rather than fill the entire hole with cement, operators
may plug only those particular formations that regulatory agencies specify must be isolated. The
remainder of the borehole space between the cement plugs is then filled with muds chemically treated
to degrade more slowly than typical drilling mud.
In cases of production wells that are no longer economical, tubing and liners are pulled out of the
well after the well-head assembly is removed. Cement plugs may be installed above and below the
fresh-water aquifers, and across all perforated zones (extending some distance above and below the
area). A cement mixture or sometimes an upgraded mud mixture is circulated downhole to balance
the back pressure or formation pressure. Casing is cut and pulled from about 100 to 200 feet from
the surface or ground level depending on local requirements. A final cement plug is set all the way
to the surface and. finally, a concrete slab is placed on top of the cement plug at ground level.
Abandonment Wastes
Well abandonment generally includes site closure. Wastes such as residual muds and excess cement
may be added to the reserve pit prior to final pit closure. Pit closure is discussed later under Waste
Management.
December 10. 1991 21 Preliminary Drart
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OIL AND GAS
OIL AND GAS PRODUCTION
Field Design
Once a reservoir is determined to be economically producible, field design is required. The wildcat
well provides information such as depth of producing zones, water cut, oil and gas quality, and
reservoir properties. Additional holes called delineation wells are drilled to determine reservoir
boundaries. Depending on the data provided, a recovery method is selected and well spacing and
pattern is mapped out to achieve optimum recovery of the petroleum, while also complying with State
requirements for well spacing. The network of wells is designed to drain the reservoir while
preserving as much downhole pressure as possible. Factors involved include viscosity of the oil and
the geological structure and natural flow conditions of the reservoir.
Dedicated gas field development may proceed based on different factors. Because gas produces (rises
to the surface) on its own, a field will not be developed until a buyer for the gas is secured. Thus,
the number and spacing of the wells must in pan be based upon contracted delivery rate in addition to
the physical characteristics of the reservoir.
Recovery
After wells are drilled and completed, they are ready to be produced. There are several types of
recovery methods in production operations. The fust is primary recovery, which uses natural flow
and artificial lift to get the hydrocarbons to the surface. Artificial lift may consist of submersible
pumping units to pump the hydrocarbons to the surface or gas lift where gas is injected into the
tubing/casing annular space of a well. In gas-lift situations, special valves in the tubing allow the gas
to enter the tubing at selected depths and mix with the produced fluid in the tubing. This lightens the
weight of the produced fluid and helps the well flow by using the available reservoir pressure.
Most fields initially produce by primary recovery methods, but the natural decline rate of wells
generally indicates when workovers or other methods of recovery are needed to maintain or improve
production.
Secondary recovery methods are used when the natural energy of the reservoir has been depleted and
primary production is no longer efficient. Methods include waterflooding or gas injection into the
reservoir to maintain pressure. In waterflooding, the produced water may be treated to meet
guidelines (set up by the local agencies) for injection. A pattern of injection wells and production
wells are mapped out to achieve maximum sweep efficiency (all the producers are receiving th-ir
required amount of pressure maintenance). The source of water can be produced water or water from
a nearby lake. Gas injection or immiscible-gas injection involves injecting a gaseous substance that
will not mix with oil into the reservoir. The process is similar to waterflooding except that it uses
methane, ethane, or nitrogen gas as an injection fluid.
Tertiary recovery refers to the recovery of the last portion of economically recoverable oil (by
manipulating characteristics of the oil as well as the reservoir). Generally, tertiary recovery involves
the injection of a fluid other than water to increase pore pressure of the formation and help thicker or
heavier hydrocarbons to flow. Steam injection, and in some rare cases microbial treatment (use ot
December 10. 1991 22 Preliminary Dr.n
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BACKGROUND FOR NEPA REVIEWERS
bacteria that break long-chain hydrocarbons) or ins itu-combustion may also be used for tertiary
recovery.
Miscible injection, a method of tertiary recovery, involves injecting a fluid that will readily mix with
the oil in a reservoir. The injection fluid may be alcohol, refined hydrocarbons, propane, butane, or
carbon dioxide. Polymer flooding involves injection of polymers Cong-chained molecules that thicken
water) such as polysaccharides and poly aery ianudes. Once the water is thickened, the process
continues like a waterflood project. Due to the high cost of the polymers, this method is restricted to
thick oil reservoirs that do not respond well to waterflooding.
In steamflooding (like waterflooding) both injection and production wells are used. Water is heated
within surface steam generators until it changes to steam. The steam is then injected into the
reservoir through injection wells. This method is used for heavy oil (thicker than the polymer-
flooding reservoirs), and often a portion of the produced crude oil is used as fuel to run the
generators.
Cyclic steam (push-and-pull or "huff and puff) injection uses the production wells for injection. A
single well bore serves as a temporary steam injection well. Then, it is convened for use as a
temporary producing well. The well may be shut in for a few days so that the energy stored in the
reservoir is not depleted too quickly. This injection/production cycle is repeated until the economic
limit is reached.
In-sim (in place) combustion (burning) involves burning the oil while it is still within the reservoir
pore space. The combination of oxygen (supplied by injected air from an injection well) and fuel
(supplied by the reservoir oil) creates a flammable mixture that will burn until the supply of oxygen
or fuel is exhausted. The burning of a small portion of the underground oil increases the formation
pressure pushing the remaining unburned oil toward the.production well. This is not a very popular
method of recovery because of high operating costs and massive operational problems (i.e., melted
casings); it is uneconomic in most instances. Both secondary and tertiary recovery are often referred
to as "enhanced* oil recovery.
Stripper wells constitute a special case of recovery methods, usually near the end of the life of a well.
Stripper wells are defined as wells that produce less than ten barrels of oil per day. Relative to
nonstripper wells, the water cut for strippers may be high, well over 10 barrels of water for each
barrel of oil recovered. Marginally economical to produce, most stripper operations are very
sensitive to the price of oil. As a result, they are candidates for various regulatory exemptions
regarding waste management. Generally owned and operated by independent companies, the nature
of surface treatment facilities may differ from larger operations. Note that stripper wells account for
nearly 75 percent of all United States producing wells and produced IS percent of United States
domestic oil in 1989.
Product Collection (Gathering)
As oil and gas is recovered from wells,-itis collected or gathered in pipelines for transport to
produced fluid treatment facilities (discussed in the next section). Generally, gathering lines (flow
lines) are routed from the wellhead to the treatment units and on to storage. The flow lines may be
December 10. 1991 23 Prelimmar> Draft
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OIL AND GAS
above or below ground. If below ground, they may be equipped with leak-detection systems to
prevent damage to the environment and loss of product.
Occasionally, gathering lines may become clogged with the build-up of paraffins and pipe scale
(carbonates and other materials on the pipe wall). In such cases, pipeline 'pigs* or heated oil are
used to remove the blockage. Pigs are cylindrical solid blocks having the same diameter as the inside
diameter of the pipeline. Forced through the pipe by the pressure of the crude, the pig scrapes the
walls of the flow line and pushes the build-up to a pig trap where the scale and other wastes are
removed for recovery or disposal. Alternatively, heated oil injected into the flow line melts the
paraffins.
Produced Fluid Treatment
Produced fluid at the wellhead is a complex mixture of gas, oil, water (often called produced water),
and other impurities (such as sand and scale). A series of gravitational, chemical, and thermal
treatment steps may be used to separate marketable gas and crude oil from the produced water and
sand. The goal of treatment is to meet the delivery specifications of oil destined for the refinery or
gas destined for the pipeline. Specific treatment units are described below. (See Figure 7.)
Two-phase Separator
Generally, produced fluid is first treated in a two-phase separator, which separates gas from the fluid
phase of the mixture. In a two-phase separator, gas is allowed to rise above the produced fluids to a
gas outlet while the remaining oil/water mixture is removed at the base. The gas flows to additional
treatment units for dehydration, sweetening, and compression as described below. The oil/water
mixture removed from a two-phase separator usually contains a high percentage of water. Much or
this may be free water easily separated by gravity. If so. the fluids will be piped to a free-water
knockout.
Three-phase Separator
If the lease is a gas producer (or produces a large quantity of gas with oil) the production facility will
include a three-phase separator. Like a two-phase separator, gas and liquid phase fractions of the
production stream are separated by gravity; the gas is removed from the top. The three-phase
separator further splits the gas condensates or natural gas liquids (NGLs) from the water by gravity
Water is heavier than NGLs and so may be removed from the lowest portion of the tank, while NGLs
may be skimmed from the fluid surface. More information on gas plants is presented below. At a
gas field, when the only produced hydrocarbon is natural gas, an inlet separator may be used rather
than a three-phase separator. For safety reasons, inlet separators are equipped with relief valves that
vent to emergency containment (usually pits). In the event natural gas is flared, reporting to air
quality and oil and gas regulatory agencies may be required depending on the composition and
volume of the flare gas.
December 10, 1991 24 Preliminary Dran
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D
8
OIL AND (IAS
nuioornoN
WEli
2.
3
I
D
RESERVOIII
Figure 7. Flowchart of a Typical Oil and Gas Fluid Treatment System
Butane, Propane lo Mattel
To Storage or
Pipeline
HoUixm
CO
o
8
90
O
R
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OIL AND GAS
Free-Water Knockout
A free-water knockout relies on gravity to separate gas, oil. and easily removed or "free" water to
different outlets for separate treatment and to avoid unnecessarily heating too much water in
subsequent treatments. The free-water knockout has a gas outlet at the top, ou outlet in the middle.
and water outlet at the bottom. Gas removed from the free-water knockout is sent to a gas treatment
facility while water is discharged to a skimming pit for further settling. The remaining oil/water
mixture is piped to a heater treater.
Heater Treater
After removal of free water from the produced fluid, the remaining fluid is an emulsion, which is sent
to a heater treater. Because of its polarity, water suspended in oil tends to form small droplets that
are difficult to separate by gravity. Such emulsions, therefore, require heat to facilitate the water
removal. So-called heater/treaters expose the fluid to a heat source in a closed tank. The heavier
water falls to the bottom of the tank for removal. Any trapped gas or light hydrocarbons evaporated
in the process rise to a gas outlet at the top of the tank. The resulting treated oil is then ready for
storage and transport. The water is discharged to a skimming pit or produced water storage facility.
Gas Dehydration
Gas removed from either type of separator described above may still contain water in vapor form: this
requires removal by dehydration. Gas dehydration typically uses a desiccant compound such as silica
gel, glycol. methanol. or alumina to strip water from the product. If no sweetening (removal of
hydrogen sulftde) is required, the gas is then ready for compression and storage or delivery. Water
removed from the gas is piped to produced water storage facilities. The dehydration process may
generate other wastes or require treatment for reclamation of dehydration compounds.
Sweetening/Sulfur Recovery
Some natural gas contains hydrogen sulfide, carbon dioxide, or other impurities that must be removed
to meet specifications for pipeline sales and requirements for field fuel use. Sweetening consists of
lowering the hydrogen sulfide and carbon dioxide content in natural gas. Hydrogen sulfide is
removed from natural gas by contact with amine, suifinol, iron sponge, caustic solutions, and other
sulfur-convening chemicals. Heal regenerates amine or suifinol for reuse.
The most popular method of hydrogen sulfide removal is amine treatment. This process is based on
the concept that aliphatic alkanolamines will react with acid gases at moderate temperatures, and that
the acid gases are released at slightly higher temperatures. Wastes generated in amine sweetening
include spent amine, used filter media, and acid gas which must be flared, incinerated, or sent to a
sulfur-recovery facility. Amine can be regenerated by heating and recycled to the process.
In the iron-sponge treatment, iron oxide reacts with hydrogen sulfide to form iron sulfide. Iron
sponge is composed of finely divided iron oxide, coated on a carrier such as wood shavings. This
process is generally used for treating gas at relatively modest pressure and hydrogen sulfide content
Wastes generated in the iron-sponge process are iron sulfide and wood shavings. Typically, in iron
December 10, 1991 26 Preliminary
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BACKGROUND FOR NEPA REVIEWER
sponge operations, after the iron is consumed the waste iron sponge is removed and allowed to
undergo oxidation, it is then buried onsite or taken to an offsite disposal facility. While incineration
of spent iron sponge is possible, it is usually done in small quantities in locations where commercial
incineration facilities are generally not available.
In caustic treatment, IS to 20 percent (by weight) sodium hydroxide solution is typically used. Most
caustic treatment consists of a simple vessel holding the caustic solution through which gas is allowed
to bubble. Spent caustic is generated as a waste in this operation.
Dedicated sulfur-recovery facilities for high hydrogen-sulfide-content gas may use catalytic processes.
Hydrogen sulfide is removed from sour gas using amine or sulfinol solutions. As pan of the
regeneration process, hydrogen sulfide is driven out of solution. The hydrogen sulfide is then burned
in the presence of oxygen to produce sulfur dioxide. A mixture of hydrogen sulfide and sulfur
dioxide, when passed over a heated catalyst, forms elemental sulfur. This is known as the Claus
process. It uses inert aluminum oxide, in pellet form, as a catalyst. The catalyst does not react in the
sulfur-making process. It simply provides a greater surface area to speed and assist the process.
Wastes associated with gas production include giycol. amine. sulfinol, caustic filter media, spent iron
sponge, and/or slurries of sulfur and sodium salts. These wastes may contain light hydrocarbons and
salts. Water from the dehydration process may be released as water vapor or, if it condenses.
disposed of via Class II injection wells. National Pollutant Discharge Elimination System (NPDES)
discharges, or in evaporation pits.
Natural Gas Liquids Recovery
Natural gas liquids recovery uses either compression and/or cooling processes, absorption processes.
or cryogenic processes to separate butane, propane, and other natural gas liquids from methane.
These processes either absorb heavier molecular compounds from the process stream with an
absorption oil that is recycled or use temperature and pressure to separate fractions with different
boiling points. Wastes generated include lubrication oils, spent or degraded absorption oil, waste
waters, cooling-tower water, and botler-blowdown water.
Compression
Plant compression and utility systems (fuel, electrical generators, steam equipment, pump, and sump
systems) are necessary to operate gas plants and to raise the pressure of gas to match gas pipeline
pressure. Compressors are driven by electric motors, internal combustion, or turbine engines.
Wastes generated include lubrication oils, cooling waters, and debris such as rags, sorbents, and
filters.
Skimming Pit
During the treatment stages described, the emphasis has been on the removal of produced water from
gas and oil. In the process, however, a meaningful amount of petroleum may have been removed
with the water. The primary function of the skimming pit, therefore, is to reclaim residual oil
removed with the produced water. Because of the relatively high residence time for fluids in the
December 10, 1991 27 Preliminary Draii
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OIL AND GAS
skimming pit, much of the residual oil will rise to the surface where it may be recaptured and
returned to the product flow line.
Solids Removal
An additional, valuable function has been served in treatment, the removal of produced sand and
other paniculates from the production stream. Each treatment vessel is equipped for the removal of
accumulated sand and precipitates which settle by gravity at its base. These settled solids are
removed to a sediment pit.
Because the settling of solids during treatment is incomplete, product-storage tanks tend to accumulate
solids from further gravity precipitation. Tank bottoms, as they are called, are periodically removed
from storage tanks by trap doors designed for this purpose. Tank-bottom material is stored in a
sediment pit for later disposal.
Produced Water
Produced water may contain a number of pollutants in sufficient concentrations to pose environmental
concern. The largest constituent of concern is generally chloride. Chloride concentrations may range
from 50 ppt to well over 150 ppt, depending on specific geologic conditions. Cation concentrations
typically associated with high chlorides in produced water are sodium, calcium, magnesium, and
potassium, in decreasing order of abundance.
Because formation water is coproduced with hydrocarbons, the concentration of organics in the water
removed from the production stream may be high. In addition to oil and grease, specific fractions
found in produced water (as well as tank bottoms and pit sludges) may include benzene, naphthalene,
toluene, phenanthrene, bromodichloromethane, 1,2 trichloroethane, and pentachlorophenol.
Additional pollutants are often found in produced water, arising both from downhole conditions and
from production activities. Inorganic pollutants may include lead, arsenic, barium, antimony,
sulphur, and zinc. Production chemicals such as acidizing and fracturing fluids, corrosion inhibitors,
surfactants, and caustics will also generally be coproduced with formation fluids after being placed in
a formation.
Finally, Naturally Occurring Radioactive Material (NORM) is often found in produced fluids.
Uranium, radon, and radium are among the most common radioactive species found to occur in
formation fluids, with strontium and thorium detectable less frequently. Uranium tends to be resident
in crude, while radon is divided in crude, gas, and water in decreasing concentrations. Radium is
most often in produced water and scales.
Pipe scales, or cement-like solid precipitates found in production tubing, flowlines, and separator
bottoms may contain barium, strontium, and radium sulfates. One industry analysis found the activity
range of scales to be 50 to 30,000 pico Curies per gram (pCi/gm). Additionally, formation sand,
found in tank bottoms, separators, and heater/treaters. may have an activity range of 0 to 250
pCi/gm. Soil contamination around production wells can range from 0 to 2,000 pCi/gm.
December 10, 1991 28 Preliminary Drari
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BACKGROUND FOR NEPA REVIEWERS
Waste Management
Exploration and Production Wastes
Exploration and production operations generate a number of wastes in conjunction with drilling
activities, production of fluids, and treatment of produced fluids. Such wastes include used drilling
fluids and drill cuttings, produced water, separator sludges and tank bottoms, produced sand, and so
forth. The management of such wastes is typically an ongoing activity, often closely linked to the
drilling or production process. As a result, the volume and characteristics of generically denned
waste streams (such as separator sludges or pit contents) may differ dramatically from operator to
operator both from geological factors as well as from the waste management techniques employed.
Used drilling fluids and drill cuttings are the largest waste streams associated with drilling. The
coproduction of uneconomic substances with petroleum accounts for the greatest portion of wastes
generated during production operations. Produced water, produced sand, sulfur compounds. NORM.
and metals can occur in substantial quantities in petroleum bearing formations and must be separated
from the production stream before delivery of crude or gas. Thus, depending on the water cut
(percentage of produced fluids accounted for by water) and other qualities of the produced fluids.
operators may face management of large volumes of waste.
In general, waste management at exploration and production sites revolves around the use of various
pits and tanks for onsite storage of materials prior to disposal. Historically, the number of pits was
small, sometimes only one, into which produced water and other accumulated wastes were placed
However, increasing regulations and costs of disposal for some waste types has generated an increase
in attention paid to the potentially undesirable qualities of some wastes versus others. As a result.
many operators employ multiple pits and tanks to sequester easily disposed materials from more
problematic wastes.
A number of regulatory, economic, hydroiogic, and geologic factors combine to determine final
disposal options for wastes generated from exploration and production. For instance, any
contemplated discharge of wastes (such as produced water or drilling fluids) to surface waters must be
able to meet NPDES effluent criteria. Waste streams exceeding effluent criteria may require
pretreatment which may be prohibitively expensive relative to other disposal options, such as deep
well injection. Similarly, evaporation pits or surface spreading of tank bottoms may not be
appropriate in areas with shallow ground water or nearby surface water, requiring alternative
methods.
In some instances, exploratioa and production wastes may be disposed in fashions beneficial to some
other uses. Beneficial uses of produced water include road spreading for ice and dust control, and
irrigation with low chloride content waters. Tank bottoms may be used for road building. Among
the most lucrative, beneficial uses of unwanted production stream contaminants is the production of
elemental sulfur at gas sweetening plants. Recovered sulfur from natural gas processing accounted
for roughly 15% of all U.S. sulfur production in 1988 (U.S. Bureau of Mines. Annual Report tor
Sulfur, 1990). Such beneficial uses stand to reduce overall waste disposal and site operation costs
December 10, 1991 29
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OIL AND GAS
As discussed previously, the current RCRA exemption of many exploration and production wastes
mav have significant influence over operator decisions with respect to waste management. Because of
RCRA, operators often try to sequester exempt and non-exempt wastes subject to regulation. For
example, unused stimulation fluids are explicitly specified as non-exempt wastes. Mixing unused
acids with spent workover fluids may trigger RCRA inclusion such that the total volume of workover
wastes would require handling as under Subtitle C rather than only the (presumably) much smaller
volume of unused acids.
Aside from RCRA, other state and local regulations may tend to promote source separation at drilling
and production sites. For instance, mixing low Ph workover wastes with produced waters may make
it difficult to achieve permitted NPDES effluent limitations. Similarly, mixing high chloride or
hydrocarbon content wastes with drilling muds may affect loading rates for landfarming, increasing
the area or time needed for disposal, and hence the costs.
Since both prevailing regulations and waste constituents can influence disposal options and costs,
waste management strategies may be closely linked to typically engineering-dominated operation
decisions. This relationship is typified in waste minimization efforts increasingly practiced at
exploration and production sites. Closed cycle mud systems reduce both mud and waste management
costs by reducing the total volume of drilling fluids employed. Water flooding projects
simultaneously dispose of produced waters while using them to increase oil recovery. Casing vent
gas recovery systems sometimes used in conjunction with steam flooding projects can increase
production flow rates and NGL recovery while eliminating a source of air emissions.
The following sections describe predominant waste management practices employed in conjunction
with exploration and production operations.
Reserve Pits
During drilling operations used drilling fluids, cuttings, and other wastes accumulate onsite. The
reserve pit serves as the primary storage unit for such wastes, often along with make-up water used in
mud preparation. Usually located next to the rig, reserve pits can generally accommodate 2 or 3
times the projected total mud volume for the well being drilled. Depending on regulatory constraints.
hydrogeological conditions and mud design, reserve pits may require clay or synthetic liners to
prevent vertical migration of pit contents. In some instances an above-ground basin or tank may
replace the more typical excavated pit.
Pit contents vary with mud design, formation geology, and operator practices. In addition to used
drilling fluids and cuttings, the pit may receive cement returns, rain water, unused mud additives, rig
wash and miscellaneous oil field chemicals. If salt water muds are used, or if drilling encounters salt
domes the chloride content of pit wastes may be quite high. Similarly, oil based drilling muds may
substantially increase the hydrocarbon content of drilling wastes. Since the reserve pit may rema.n
open for some time after the initiation of production (6-12 months in modern operations) the
possibility exists for the commingling of various completion and/or production related wastes with
drilling wastes.
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30 Preliminary Drjrr
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BACKGROUND FOR NEPA REVIEWERS
Reserve pits have been found to contain chloride concentrations from 570 to 135,000 mg/1. Oil and
grease concentrations may range from 800 to 280,00 mg/1. Barium (resulting from the use of barue
as a weighting agent in muds) can range from 30 to 56.200 mg/1. Other constituents of concern
include benzene, phenanthrene, naphthalene, toluene, and other volatile and semivolatile organics.
Various metals may be present including aluminum, iron, cadmium, chromium, and lead.
Reserve pits may serve as temporary or permanent disposal units for some or all of the wastes they
contain. Depending on prevailing regulatory conditions as well as hydrogeoiogical conditions and pit
contents, some or all of the wastes may be buried in the pit. Alternatively, a number of onsite and
offsite disposal practices may be utilized.
In many instances, operators backfill reserve pits with native soil for permanent disposal of drilling
wastes. Generally, burial is preceded by dewatering of pit contents. In situ solidification of wastes
using commercial cement, flash or lime kiln dust may serve to reduce waste constituent mobility prior
to burial.
Reserve pit wastes may be disposed of in additional ways, such as surface water discharge
landfarming. These methods are discussed separately in conjunction with management of production
related wastes.
Annular Disposal of Drilling Wastes
In instances where onsite burial is not feasible (e.g., high chloride or metals concentrations) operators
may dispose of pit wastes via annular injection. Pumpable reserve pit wastes are injected into the
annular space of the well. This is different from underground injection in that wastes are contained in
the well bore and not in an underground formation. Annular injection does not remove the need to
cement plug USDWs.
Centralized Disposal Pits
For economic, lease restriction, or regulatory reasons some operators may dispose of reserve pit
wastes at offsite disposal pits. Wastes are transported to such centralized facilities in vacuum trucks.
(Additional information on centralized facilities appears below.)
Drilling Waste Minimization
Because of the potentially high costs of transportation and/or disposal or large volumes of drilling
wastes, some operators reduce waste burdens through the use of closed mud systems and mud
recycling, dosed mud systems can reduce die total volume of drilling fluids used (and hence
disposed) by efficiently recirculating mud returns after removal of cuttings. Such systems may
recirculate either liquid or solid mud phases or both, depending on design.
Alternatively, some operators may reduce mud and waste disposal costs through recycling of used
muds. Most appropriate for higher cost, oil-based muds, areas where onsite or near-site disposal is
difficult, or in fields with multiple wells scheduled for drilling, mud recycling relies on the removal
December 10, 1991 31 Preliminary Drart
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OIL AND GAS
of cuttings and chemical reconditioning to retain needed mud properties. Only drill cuttings and
residual muds require disposal.
t
Storage. Sealing, and Skimming Pits and Tanks
Wastes removed from the production stream require onsite storage prior to disposal. Such wastes
include produced water from separators and dehydrators. unbeatable emulsions from the
heater/treater, separator sludges, tank bottoms, and sweetening and dehydration wastes. They may be
stored in pits or tanks, separately or together.
Produced water discharged from the various treatment units onsite can vary with respect to solids
content, oil and grease, and emulsions (among other things). Water with high solids or hydrocarbons
content may require additional settling time for solids removal and skimming of petroleum for
recovery. Settling/skimming pits receive such waters prior to storage in tanks or other pits.
Removed hydrocarbons return to the production stream while settled solids may periodically be
removed from the pit and stored in a sediment pit.
Two- and three-phase separators, free-water knockouts, and heater/treaters continuously accumulate
solid material precipitating from the production stream. Produced sand, silt, paraffins, sulfates and
other substances along with water and residual hydrocarbons account for the bulk of these sludges.
Separator sludges must be removed periodically, usually discharged to a sediment pit or tank. Both
produced water and product storage tanks also accumulate settled solids over time, requiring removal.
These tank bottoms may be added to settling pit contents.
Underground Injection
As described earlier, produced water is the largest volume waste generated from oil and gas
production activities. Nationally, approximately 90 percent of all produced water is disposed through
injection wells permitted under EPA's UIC program. Much of this water is injected in conjunction
with water or steam flooding enhanced oil recovery. The remainder of the 90 percent is disposed in
deep injection disposal wells or through annular injection.
The use of produced water for water or stream flooding generally requires pretreatment of water.
Depending on water quality, pretreatment may involve little more than the addition of corrosion
inhibitors to protect the integrity of injection wells. In some cases, however, solids, oil and grease.
and other impurities in the waste could damage wells and foul injectors. As a result, water and
stream flooding projects may require installation of onsite water treatment facilities. Wastes removed
from the injection water may be stored in tanks or pits with other oil field wastes or injected in deep
disposal wells.
Deep well and annular injection of produced water involves pumping waste fluids to some formation
for permanent disposal. In deep well injection, the injection zone is known. The injection may be
the original producing formation, salt water formations, or older depleted formations. The UIC
program requirements typically specify design, monitoring, and injection pressure restrictions tor
injection well operators.
rx u m inni i"> Preliminary Drart
December 10, 1991 >-
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BACKGROUND FOR NEPA REVIEWERS
Annular injection involves the injection of produced water down the cubing/casing or surface
casing/intermediate casing annulus of a nonproducing well. While the specific injection zone may not
be known, all known USDWs generally must still be protected with cement plugs.
Discharge of Produced Waters to Surface Water
In some cases, operators may discharge produced water to surface receiving waters. Such discharges
require NPDES permits stipulating allowable concentrations of contaminants in the effluent. As a
result, produced waters may require pretreatment before release. Typical constituents which may
exceed permitted levels include chlorides, oil and grease, total dissolved solids (TDS), pH and
sulfates.
Evaporation and Percolation Pits
Evaporation and percolation pits are used for disposal of produced waters. Evaporation pits are
typically lined with a clay or synthetic liner, while percolation pits are uniined. allowing waters to
seep into soils. The feasibility of either evaporation or percolation pits depends in pan on area
hydrology and constituent concentrations of the wastes. Operators may construct individual
evaporation pits for each site or field, or may haul or pipe waters to centralized facilities servicing
multiple operations.
Land Farming
As alternatives to burial of reserve pit solids, pit sludges and other solid and semi-solid wastes, land
application may be employed for disposal of these wastes. Land fanning of pit wastes typically
involves the thin spreading of wastes over soil with or without mechanical tilling to promote
biological degradation, adsorption, and dilution of constituents. Depending on intended uses of the
area of treatment, loading rates may be modified. Some state and local regulations restrict loading
rates according to the total burden of given constituents per unit area of treatment (e.g., kilogram oil
and grease per hectare, Kg/Ha).
Often practiced in conjunction with final reserve pit or site closure, land farming may allow rapid
revegetation of the affected area. Factors influencing site soil quality and productivity include total
chloride deposition, oil and grease concentrations, and the presence of plant-specific phytotoxic
constituents. Commercial land fanning facilities present additional options for operators.
Surface Spreading of Produced Waters
Several surface spreading methods of produced water disposal may be practiced by operators. For
low to moderate salt content waters, produced water may be used for road spreading, both as a dust
suppressant as well as a surface deicer. Road spreading may require some level of treatment prior to
use. Oil and grease concentrations. Ph. and NORM may be regulated by state or local agencies.
December 10, 1991 33 Preliminary Drart
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OH. AND GAS
Use of Produced Water for Irrigation
The NPDES program exempts from permitting requirements surface discharges of waters determined
to be beneficial to agriculture (limited to west half of U.S.). Therefore, treated produced water may
be discharged to irrigation canals or other conduits for agricultural purposes. Some operators dispose
of produced waters arter treatment in water recycling plants directly to irrigation canals. The level of
water treatment often required for stream flooding projects may be sufficient to allow such
discharges, providing lease operators with the option of disposing of excess treated water in this
manner.
Central Treatment Facilities
Many operators utilize central treatment facilities for disposal of non-exempt and some exempt
wastes. Such central facilities may have both Class I and Class Q injection wells, incinerators,
evaporation pits, land treatment areas, and/or reclamation capabilities. Utilized by small operators
and in areas where specific disposal problems exist, central treatment facilities generally have
sufficient capacity to handle wastes from several production operations.
Crude Oil Reclaimers
Crude oil reclaimers are independent operators who handle various oil field wastes in an effort to
collect and resell residual oils from the wastes. Candidate wastes include paraffins and pigging
wastes and tank bottoms. Reclaimers use gravitational, thermal, and chemical means to separate
crude from produced water and sludges and to "break" tight emulsions.
Note that crude oil reclaimer wastes are not categorically exempted from RCRA Subtitle C. Pending
a final notice of clarification, EPA has tentatively concluded that wastes derived from the processing
of only exempt wastes are themselves exempt, thus, commingling of exempt and nonexempt wastes
either prior to or after processing could result in the entire waste stream becoming subject to costly
Subtitle C requirements.
Road Building Materials
As an alternative to burial or offsite disposal of tank bottom and settling pit wastes, some operators
use these materials for the paving of on-lease road surfaces. This use may require pretreatment of
tank bottoms to neutralize heavy metals or other hazardous substances prior to application. Typically.
sediments are dewatered prior to mixing with other road construction materials, and then applied to
road surfaces.
Casing Vent Gas Recovery
Steam flooding projects typically result in an increase in the pressure of formation gases entering
production well casings. Gases present may include natural gas, hydrogen sulfide, and lighter organic
compounds volatilized with the increased formation temperatures resulting from the infusion of steam.
Historically vented from casing vents directly to the atmosphere, these waste gases may be regulated
under CAA authorized state implementation plans or other regulations. Some operators control the
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34 Preliminary Drin
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BACKGROUND FOR NEPA REVIEWERS
emission of casing vent gas by drawing the gases into a recovery system. The system separates
condensible NGLs from H-S and other gases and returns them to production flow lines.
Concurrently, sulfur dioxide scrubbers remove sulfur compounds from the exhaust of a natural gas
flaring unit. Such systems can increase NGL recovery and increase product flow rates by reducing
well back pressure otherwise created by the gases. Additionally, hydrocarbon and SO, emissions are
substantially reduced.
Gas Flares
Oil fields may produce gas below a level at which it would be economical to collect. Left to escape
to the air uncombusted. vented natural gas can create a risk of explosion at the site. As a result.
some operators will flare (burn) the waste gas. Because waste gas may contain hydrogen suifide.
some operators may be required to scrub flare exhaust for removal of sulfur dioxide produced in
combustion of hydrogen suifide.
Miscellaneous and Nonexempt Oil Field Wastes
Exploration and production operations require the operation of industrial machinery and the handling
of a variety of compounds for cleaning, product and waste treatment, maintenance of systems, etc.
Many of these wastes may be nonhazardous industrial wastes disposable at conventional landfills or
onsite. Others may be nonexempt substances subject to RCRA Subtitle C requirements. Failure to
segregate nonexempt wastes may void the exemption for commingled exempt wastes.
Site Closure
As a particular well or well field's reserves diminish and it becomes uneconomical to continue to
produce, the operator may decide to stop production and close or abandon the site. Closing the
facility may entail properly abandoning the wells by removing equipment and plugging the borehole.
as discussed in the well abandonment section. Reserve pits and other excavations associated with the
site may be closed (see the waste management section) and the site may be regraded. Typically, any
pumping, gathering, or production equipment onsite is removed for use at other operating sites. The
drill pad may be regraded and any roads may be ripped to break up the hard packed surface and
restore natural soil consistency. If wastes have been disposed of onsite (e.g.. land application, burial
in reserve pits, etc.), special consideration of permanent containment capability may be necessary.
After site closure (demanding of equipment and closure of onsite waste units), reclamation may be
conducted. If top soil was segregated and stored during initial land disturbing operations, this top soil
is spread over the disturbed areas, and the entire site may be reseeded (possibly with native species)
Effective reclamation may take several growing seasons to accomplish.
The activities undertaken during site closure and reclamation may depend on state and/or Federal
reclamation requirements and the amount of bond held by these authorities to ensure proper closure
and reclamation.
December 10, 1991 35 Preliminary Dr.rt
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OIL AND GAS
POTENTIAL SIGNIFICANT ENVIRONMENTAL IMPACTS
The descriptions of potential environmental impacts below are based on specific examples of
documented damages caused by oil and gas exploration and production activities. The list of impacts
is not comprehensive, nor does every oil and gas activity provide the potential to cause each possible
impact described. Rather, potential impacts are identified and discussed in a conceptual framework.
with the variables associated with each concept described where possible. In general, research may
be necessary to determine site-specific potential impacts.
This section is organized first by media or topic (ground water, surface water, soil, air, ecosystems
and land use). The media-specific sections are then organized by oil and gas activity (exploration and
development, production, and waste management) with specific issues or concepts that identify
potential impacts described under each activity. The ecosystems section is described in terms of
ecosystems (coastal, inland), with concepts and their variables described, and the land use section
identifies typical land use activities (e.g., grazing, etc.) and how they might be impacted by oil and
gas activities.
POTENTIAL IMPACTS ON GROUND WATER
Ground water refers to water saturating an area or zone below the surface. This zone is referred to
as an aquifer if it is capable of producing usable quantities of fresh or potable water. Approximately
half of the U.S. population and 95 percent of the rural population use ground water as drinking water.
Typically, ground water flows at a very slow rate compared to surface water, and may be recharged
by surface water and precipitation. Groundwater may naturally discharge to surfaces waters through
springs to the ground's surface or to existing surface water bodies (lakes, streams, etc.).
Identified below are many of the potential impacts to ground water associated with oil and gas
operations. These impacts represent pathways for ground-water contamination with possible
subsequent impacts to human health and the environment or loss of available ground water with
subsequent impacts on availability of potable water and potential dewatermg of surface water bodies
(e.g., wetlands, etc.). It is again emphasized that site-specific factors (e.g., activities, environmental
setting, etc.) determine potential and actual impacts at individual sites.
Exploratory and Development Drilling
Potential impacts to ground water from exploration and development may be a direct result of drilling
a hole from the surface, through the unsaturated zone, through the saturated zones (aquifers) and into
potential oil producing formations. Often, oil producing zones are also saline water zones, with
potential constituents of concern not limited to hydrocarbons, but also including salts and metals.
Specific potential impacts are described below.
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BACKGROUND FOR NEPA REVIEWERS
Venical Migration of Contaminants
Potential for ground water impacts steins from the storage of drilling fluids, reserve pit wastes, and
other fluid stocks (diesel fuel, mud additives) on the surface with the well acting as a potential conduit
for released contaminants. Tank or pit seepage or failure, and site runoff may result in migration of
contaminants to sufficiai aquifers. The historic practice of using unlined reserve and mud pits
(possibly excavated to below the water table), still used today in some areas, has resulted in instances
of ground-water contamination. In addition, the well may act as a conduit between production
formations (with hydrocarbon and other contaminants) and usable aquifers. If the well is not cased or
the casing and grouting have failed, there is increased potential for migration of contaminants. The
extent of potential impacts depends on the volume and constituents of escaping fluids, the depth to
ground water, and soil characteristics. Constituents of concern include hydrocarbons, heavy metals.
and chlorides.
Jround-water Drawdown
As the well is drilled through water bearing zones, water may discharge from these zones (possibly
aquifers) and be pumped to the surface with the mud. potentially resulting in localized aquifer
drawdown. However, when water bearing zones are encountered, operators may aciempt to quickly
prevent the discharge of fresh water to the mud column, as this may cause the clays (e.g., bentonite)
in the mud to swell and lose their effectiveness.
Production
For the purposes of the section below, primary production is taken to include artificial lift production
with no manipulation of formation energy or downhote properties of the product. Potential impacts
from downhote activities associated with each phase of production are discussed prior to potential
impacts from surface activities common to all phases of production. Some of the methods discussed
do not apply to gas production.
Migration of Stimulation Fluid to Ground Water
Stimulation of production zones through hydraulic fracturing may result in impacts to ground water.
In general, stimulation attempts to enhance die movement of formation fluids .toward the well bore by
increasing formation permeability or creating channels (fractures) along which fluids may travel. If
pressure-taducftd fraourtt extend beyond the production zone, impacts to ground water may occur
due to miftWNfc of fracturing fluids to aquifers.
Damage and Blowout of Existing Weils
In some instances, the downhole pressure created by hydraulic or explosive fracturing may cause
damages to nearby water wells or abandoned wells. If the pressure is great enough, well blowouts
can occur, resulting in contamination of ground water with fracturing fluids and hydrocarbons.
December 10. 1991 37 Preliminary Drart
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OIL AND GAS
Migration of Injected Water to Ground Water
Waterflooding presents the potential for contamination of ground water with injected water (often
produced brines). Thief zones (naturally fractured shales) or other formation irregularities may allow
the migration of injected waters to freshwater zones. Migration may also arise from leaks in injection
well casing. Constituents of concern include brines, trace contaminants of produced waters, and
hydrocarbons. (See Figure 8.)
Of additional concern is the possible location of abandoned, improperly plugged wells or freshwater
wells in hydrologic contact with the injection zones, which may act as conduits of injected waters or
may be impacted by the increase in formation pressure. The potential for impacts from injected
waters via abandoned wells depends on the geology in the area, the relative pressures of the injection
zone and the aquifer in question, and the type, location, and condition of the abandoned well.
Migration of Steam and Other Injected Solutions to Ground Water
Both steam injection and chemical flooding present the potential for the unintended migration of
injected fluids and/or hydrocarbons to aquifers or nearby wells. The extent of potential impacts
depends on, among other factors, the nature of the injected fluids. Steam, often from produced
water, may be highly saline. Chemical flooding may contain surfactants, polymers, and alkaline
solutions. As with waterflooding, abandoned wells drilled to the same formation may serve as
conductors of injected solutions to aquifers.
Potential Damages from In-situ Combustion
In-situ combustion, rarely used, presents potential impacts similar to those from the methods
described above. In addition, in-situ combustion may result in significant damage to well casings.
promoting the communication of fluids between fluid-bearing zones.
Migration of Gathering Line Spills to Ground Water
Product pumped to the surface from one or many wells on a lease must be collected in gathering lines
leading to treatment and storage facilities. Corrosion, chronic leaks or failure of gathering lines may
result in migration of hydrocarbons to shallow ground water.
Product Stock Tank Leakage
Oil and gas stocks may be stored in surface or underground tanks prior to delivery. Leakage from
storage tanks may result in migration to ground waters. The extent of potential impacts depends on
the extent and duration of any release.
December 10, 1991
38 Preliminary Drari
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o
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i
figure 8. Schematic Diagram ol Contamination of an Aquifer with Urine
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OIL AND GAS
Waste Management
Some waste management activities at oii and gas operations are closely intertwined with general fluid
management practices. For instance, maintenance of mud and reserve pits serves a need for storage
ot fluids in use as well as storage of waste materials generated during drilling activities. Landfarm.ne
ot drilling muds after pit closure, on the other hand, is performed explicitly for the purposes of waste
management. Some fluid management practices as well as explicit waste management practices mav
potentially impact ground waters.
Migration of Deep Well Injected Fluids
Nationwide, roughly 90* of produced waters are injected in deep wells, either for enhanced oil
recovery or deep well disposal. Additionally, other oil field fluids may be deep well injected. As
with waterfiooding, discussed above, improper casing installation and/or corrosion of casing can lead
to migration of wastes from the injection formation or the well to aquifers. Further, the presence of
abandoned wells drilled to the same formation presents the potential for migration of injected fluids 10
aquifers.
Migration of Annular Injected Fluids
Annular injection is sometimes used for the disposal produced waters and drilling muds. Improper
casing cementing, damaged casing, or aquifer plugging can result in migration of fluids to usable
aquifers.
Migration of Tank and Pit Wastes
While the reserve or mud pit is often closed soon after the outset of production, other waste sumps
may remain in use for the life of the operation. Typically,"the largest pan of reserve pit contents is
muds and cuttings, but nearly any other wastes may be present in pits (including produced water.
emulsions, oily debris, etc.). Seepage or failure of reserve pit walls, and/or the absence of pit Imers
may allow the migration of fluids to ground water of and surface water. Constituents of concern
include chlorides, metals, and hydrocarbons. Commingling of wastes in reserve pits or tanks may
increase the potential impacts to ground water. The disposal of separator sludges, unbeatable
emulsions, tank bottoms, and odier separator and treatment wastes along with produced water in a
produced water pit increases the range of constituents which may migrate to ground water m the event
of a release.
Migration of Sweetening Wastes
If the lease requires gas sweetening treatment, the possibility exists for the migration of stored
sweetening wastes to ground water and (surface water). The sweetening process may generate
elemental sulfur, spent iron sponge, other amine compounds, and glycol compounds in its waste
stream. Commingling of these wastes with produced water or other liquid wastes in pits may increase
the potential for impact to ground water.
December 10, 1991 40 Prelimmor% D'
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BACKGROUND FOR NEPA REVIEWER
Vertical Migration from Surface Treatment Sites
Excess drilling fluids and produced waters may be disposed via various surface treatments, such as
road spreading, land fanning, and evaporation. Runoff in areas where road spreading of saline
waters is practiced may allow the seepage of chlorides to shallow aquifers. Similarly, evaporation
facilities may allow the vertical migration of saline waters to shallow ground waters. Finally,
landfarming of wastes (the surface spreading and tilling of liquid and solid wastes such as produced
waters and drilling fluids) may allow the seepage of chlorides and oily wastes to shallow ground
waters.
Site Closure
In this section site closure will include only those potential impacts from activities not covered
elsewhere. For instance, burial of drilling muds is covered under waste management, though this
activity may occur as part of final closure operations.
Vertical Migration of Closed Pit Contents to Ground Water
During site closure, on site pits may be backfilled with soil for permanent disposal. Failure to
dewater pit contents and/or grade the covering soil to minimize infiltration of rain water may result in
downward migration of contaminants to shallow aquifers. Constituents of concern include chlorides.
hydrocarbons, metals, NORM, and other oil field waste materials.
POTENTIAL IMPACTS ON SURFACE WATER
Surface water occurs in lakes, streams, rivers, wetlands, etc. and may support a plethora of wildlife
and vegetation. In addition, many land uses are dependant on surface water including grazing,
forestry, and recreation. Surface water and ground water exist in a dynamic system where surface
water may discharge to ground water, replenishing surficial aquifers; ground water may also
discharge to surface water, keeping surface water flowing even in times of little or no precipitation.
Typical impacts to surface water include heavy loads of total suspended or dissolved solids (often
associated with runoff) and contamination with salts, toxics or bacteria. Fish and other in-stream
species (flora and fauna) may be especially sensitive to specific toxics (See Ambient Water Quality
Criteria in Table 1).
Identified below are potential impacts to surface water associated with oil and gas operations. These
impacts represent pathways for surface water contamination with possible subsequent impacts to
human health and the environment. It is again emphasized that site-specific factors (e.g., activities.
environmental setting, etc.) determine potential and actual impacts at individual sites.
December 10, 1991 41 Preliminary Drari
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OIL AND GAS
Exploration and Development
Site Runoff to Surface Waters
Road construction may cause erosion and transport of soil and sediments to surface water, resulting in
high suspended solids and more rapid sedimentation. In addition, reserve and mud pit seepage and
overtopping may result in migration of contaminants to surface waters. Similarly, once drilling
activities have begun at the site, oily wastes and miscellaneous chemicals (mud additives, diesel oil.
lubrication oil, rigwash, etc.) may accumulate in soils. Seepage or failure of onsite storage tanks may
add to the deposition of wastes. Surface runoff may transport such wastes to surface waters,
potentially impacting aquatic populations and degrading surface water quality. Potential impacts
depend on the contents of the pits, but waste constituents of concern include drill cuttings and other
solids, mud additives, brine, NORM, oily wastes, and metals.
Production
Migration of Product Stock Tank Leaks
Oil and gas stocks may be stored in surface or underground tanks prior to delivery. Leakage from
storage tanks may result in migration of contaminants to surface waters directly or through runoff
from contaminated soils. The extent of potential impacts depends on the constituents, extent and
duration of any release.
Migration of Gathering Line Leaks
Product pumped to the surface from one or many wells on a lease must be collected in gathering lines
leading to treatment and storage facilities. Chronic leaks or failure of gathering lines may result in
migration of oil to surface receiving waters directly or through runoff from contaminated soils,
Constituents of concern include hydrocarbons and aromatic hydrocarbons.
Vertical Migration of Injection Fluids
The injection of water into producing formations for secondary recovery may result in the unintended
migration of water by way of abandoned or improperly plugged wells in the area. Salt water
breakout (surface appearance of downhole waters) may occur, with the possibility of migration to
surface waters. This potential may be amplified during tertiary recovery with the higher pressures
accompanying steam drive production. Constituents of concern include chlorides, injection fluid
additives, and hydrocarbons.
Waste Management
Surface Water Discharges of Produced Water
The production of formation water along with oil and gas is common to all phases of production, and
may begin as early as the first day of production. Typically the largest volume waste stream
associated with oil and gas production, produced water requires significant surface storage and
^ m if»ni 4"> Preliminary Drart
December 10. 1991 4-
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BACKGROUND FOR NEPA REVIEWERS
treatment capacity prior to disposal by any number of means. Direct surface water discharge, pit or
tank seepage or failure, or runoff from surface evaporation facilities all present the potential for
impacts to surface waters. Constituents of concern include residual oily materials, metals, chlorides,
and NORM.
Migration of Commingled Wastes
Commingling of wastes in pits or tanks may increase the potential impacts to surface water. The
disposal of separator sludges, unbeatable emulsions, tank bottoms, and other separator and treatment
wastes along with produced water in the reserve pit may mobilize these wastes and increase the range
of constituents that may migrate to surface water in the event of a release.
Runoff from Surface Treatment Sites
Excess drilling fluids and produced waters may be disposed via various surface treatments, such as
road spreading, land farming, and evaporation. Runoff in areas where road spreading of saline
waters is practiced may allow the migration of chlorides to surface waters. Similarly, runoff from
evaporation facilities may allow the migration of saline waters to surface waters. Finally,
landfarming of wastes (the surface spreading and tilling of liquid and solid wastes such as produced
water and drilling fluids) may allow the surface migration of chlorides and oily wastes to surface
waters.
Migration of Sweetening Wastes
If the lease requires gas sweetening treatment, the possibility exists for the migration of stored
sweetening wastes to surface water. The sweetening process may generate elemental sulfur, spent
iron sponge, other amine compounds, and glycol compounds in its waste stream. Commingling of
these wastes with produced water or other liquid wastes in pits may increase the potential for impact
to surface water.
Site Closure
In this section, site closure includes only those potential impacts from activities not covered
elsewhere. For instance, burial of drilling muds is covered under waste management, though this
activity may occur as part of final closure operations.
Sedimentation of Surface Waters
Failure to regrade and revegetate abandoned oil field sites may allow runoff and erosion to transport
soils to surface waters. In addition, this erosion can increase the risk of surface water contamination
from other sources (e.g., closed disposal sites, contaminated soil, etc.).
December 10, 1991 43 Preliminary Drari
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0EL AND GAS
POTENTIAL IMPACTS ON SOIL
Typical impacts to soils associated with oil and gas operation are identified below and include
compaction (and damage of the root zone of surfkiai soils), erosion and loss of soils (due to loss of
vegetation and runoff), and contamination with organics (e.g.. hydrocarbons, etc.) and inorganics
(salts and sulfur), resulting in toxicity to plants and contaminated runoff. It is again emphasized that
site-specific factors (e.g.. activities, environmental setting, etc.) determine potential and actual
impacts at individual sites.
Exploration and Development
Compaction and Erosion from Road Building
Typically, unimproved roads are constructed to access areas during exploration and to transport the
rig and other equipment for drilling and development. Land disturbance such as leveling areas for
roads may result in soil erosion and subsequent travel on these roads may compact the remaining soils
such that soil productivity is decreased. Root zones can become damaged and may not support native
vegetation. In addition, repeated travel along an area without constructed roads may result in similar
compaction and damage to vegetation. Removal of or damage to vegetation and soil may result in
increased runoff and further erosion.
Site Runoff
Site runoff from storm events presents the possibility of transporting pit contents and uncomamed
wastes offsite, with the resulting impacts to soils. Constituents of concern include oily wastes.
drilling muds, and salts. If drilling encounters salt domes or other high salt content formations, the
contents of the pits may contain high salt concentrations: increasing the potential damages to soils
Production
Compaction and Erosion During Production
The initiation of production requires additional site preparation, from development drilling to
installation of gathering facilities and road construction for transportation of product. In general such
site preparations may directly impact site and area soils, as well as increase the area of potential
impacts Further, the increased use of roads consistent with product and waste transportation may
result in greater compaction of soils on and near roads.
Product Stock Tank Leaks
Oil and gas stocks may be stored in surface or underground tanks prior to delivery. Leakage from
storage tanks may result in migration to area sous. The extent of potential impacts depends on the
extent and duration of any release.
11 Preiiminarv Dun
December 10, 1991 **
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BACKGROUND FOR NEPA REVIEWERS
Gathering Line Leaks
Product pumped to the surface from one or many wells on a lease must be collected in gathering lines
leading to treatment and storage facilities. Chronic leaks or failure of gathering lines may result in
impacts to soil both onsite and beyond site boundaries. Constituents of concern include hydrocarbons
and aromatic hydrocarbons.
Injection Fluids and Saltwater Breakout
The injection of water into producing formations for secondary recovery may result in the unintended
migration of water to area abandoned or improperly plugged wells in the area. Salt water breakout
(surface appearance of downhole waters) may occur, with the possibility of damage to affected soils.
This potential may be amplified during tertiary recovery with the higher pressures accompanying
steam drive production. Constituents of concern include chlorides, injection fluid additives, and
hydrocarbons.
Waste Management
Pit Excavation, Overtopping and Seepage
As previously discussed, drilling activities require the maintenance of onsite drilling mud and reserve
pits for the storage and temporary disposal of muds and drilling wastes. Excavation of these pits has
a direct impact on soils through land disturbance. If top soils are not segregated from underlying
material during excavation, their productivity and effectiveness in reclamation may be lost. In
addition, absence of or damage to pit liners may allow seepage of fluids to underlying soils.
Similarly, pit wall seepage or failure, and overtopping may allow seepage of wastes into surface soil
both onsite and beyond site boundaries. The extent of potential impacts depends on pit fluid
constituents and the volume of any releases. Note that brine contamination of soils may lead to soil
sterilization. Other impacts to soil may result from ground deposition of rigwash and other oil field
wastes, and storage tank leakage or failure.
Sweetening Wastes
If the lease requires gas sweetening, the possibility exists for contamination of soils with stored
sweetening wastes. The sweetening process may generate elemental sulfur, spent iron sponge, other
amine compounds, and glycol compounds in its waste stream. Commingling of these wastes with
produced water or other liquid wastes in pits may increase the potential for impact to soils.
Historically, sulphur discharged from sweeteners was often released directly to the ground, forming a
storage pad for subsequent releases of sulphur. Water running off the storage area was highly acidic
and damaging to soils. Such practices may still be in use.
Onsite Burial of Pit Wastes
Shallow burial of drilling wastes and other pit wastes accumulated during production can result in the
vertical migration of salts and hydrocarbons to top soils, resulting in damages to plants and loss of
soil productivity.
December 10. 1991 45 Preliminary Dun
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OIL AND GAS
Landfarming of Pit Wastes
Landfarming of pit wastes, (tilling of sludges and solids into soils), may result in long term damages
to soil productivity if the wastes are high in total dissolved salts, especially sodium chloride, or
contain oil and grease in significant amounts, or if the natural capacity of the soil to degrade wastes is
exceeded. Sensitivity to salts and hydrocarbons varies with soil type and plant type. However,
damages may result with electrical conductivity and oil and grease concentrations as low as 4 mmhos
cm and 2 mg/1, respectively.
Evaporation of Produced Water
Evaporation of produced water on land may result in accumulation of salt contamination in affected
soils. Significant salt concentrations can reduce productivity of soils for many years.
Site Closure
In this section site closure will include only those potential impacts from activities not covered
elsewhere. For instance, burial of drilling muds is covered under waste management, though this
activity may occur as part of final closure operations.
Sedimentation of Surface Waters from Site Runoff
Failure to regrade and revegetate abandoned oil field sites may promote erosion of surface soils.
These soils, by virtue of the site's use, may contain wastes and constituents (e.g. oily debris,
hydrocarbons, metals, etc.) that have the potential to migrate to beyond site boundaries, resulting in
contamination.
POTENTIAL IMPACTS ON AIR
Impacts to air include release of both toxic and nontoxic pollutants during oil and gas drilling,
production and waste management. Toxic gases that occur in the producing formations, especially
hydrogen sulfide and poly-aromatic hydrocarbons, may be emitted from active operations. In
addition, conventional air pollutants, such as particulates, ozone, carbon monoxide, etc., associated
with diesel engines that power the operation are released.
Identified below are potential impacts to air associated with oil and gas operations. These impacts
represent pathways for air contamination with possible subsequent impacts caused by deposition of
pollutants to soil, in addition to impacts on human health and the environment. It is again
emphasized that site-specific factors (e.g., activities, environmental setting, etc.) determine potential
and actual impacts at individual sites.
December 10, 1991 46 Preliminary Dr.r.
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BACKGROUND FOR NEPA REVIEWER
Exploration and Development Drilling
Hydrogen Sulfide Emissions from Active Operations
In some areas of die U.S., hydrogen sulfide occurs as a natural contaminant in oil and gas producing
formations. Uncontrolled releases during drilling may threaten human health. Typically, drill rigs
are evacuated when hydrogen sulfide is detected in ambient air near the rig.
Fugitive Dust Emissions
Road construction, site clearing, transportation on din roads during exploration to and from the well
site, and onsite mixing of muds generate fugitive dust.
Machinery Exhaust Emissions
Operation of heavy machinery during site preparation as well as running the rig. the return mud
shakers, and other machinery during drilling operations will be accompanied by the emission of fossil
fuel combustion exhausts always associated with such equipment. Such exhausts will include oxides
of nitrogen, oxides of sulfur, ozone, carbon monoxide, and particulars.
Production
Emissions from Gas Flaring
Some oil leases may co-produce natural gas at rates below what is economical to collect for sale. If
no other use for the gas is found, such gas may be flared (burned in the air) for disposal. Flaring of
gas will result in the release of carbon monoxide, nitrogen oxides, and. if the gas is sour, sulfur
dioxide. Additional emissions may include products on incomplete combustion.
Volatilization of Petroleum Fractions
Crude oil generally contains some fractions that will volatilize at ambient temperatures and pressures.
Storage of crude in open tanks as well the accumulation of waste oil and grease in reserve pits may
allow the release of volatile organic compounds (VOCs) to the air. Further, fugitive leaks from
pipes, closed tanks, and treatment equipment may contribute to the release of VOCs to the air. Such
releases may be of particular concern in areas that are not in attainment of ambient air standards for
ozone.
Release of Hydrogen Sulfide from Sour Gas
Hydrogen sulfide, with its inherent toxic effects, may be released from sour gas plants. Impacts
would be localized and dependent on concentration in ambient air.
December 10, 1991 47 Preliminary Drari
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OIL AND GAS
Machinery Exhaust Emissions
Operation of production equipment such as pumps, separator motors, heater treaters, generators, and
boilers may result in the release of fossil fuel combustion emissions. Such exhausts will include
oxides of nitrogen,.oxides of sulfur, ozone, carbon monoxide, and paniculates. Typical industry
practice is to utilize fuel sources produced on sue, such that machinery exhausts may contain grater
amounts of paniculates than from refined fuels. Additional emissions may include products of
incomplete combustion.
Waste Management
Volatilization During Evaporation and Landfarming
By design, evaporation pits for produced water or other wastes release water and VOCs to the air.
This also may occur during spraying or otherwise applying produced water or other wastes to the soil
for landfarming or road spreading.
POTENTIAL IMPACTS ON ECOSYSTEMS
This section is organized differently from previous sections. First, it provides a summary of abiotic
and biotic parameters and how they relate to ecosystems. Following this, two subsections discuss the
impacts on terrestial ecosystems, and on aquatic ecosystems. Because environmental impacts resulting
from oil and gas exploration or development activities are often localized in nature, mitigation of
these impacts can best be accomplished by careful siting of the facilities within the ecosystem, and by
minimizing the extent of the area impacted. Siting decisions should include consideration of the
presence of sensitive areas such as rare habitats, sensitive species, waterbodies. and so on. Where
disruptions due to oil and gas activities are unavoidable, ail efforts should be made to limit damages
through minimizing the area that will be disturbed, and by timing activities to avoid disturbing plants
and animals during crucial seasons in their life cycle. This could mean temporarily halting or
delaying activities to avoid disturbance to animals during migrations or breeding seasons.
An EIS or EA should address potential impacts on a number of biotic and abiotic characteristics of
habitats. These characteristics define the nature of the environment, and in some ways, also define
the sensitivity of the environment to man-made stress. Without a basic understanding of the ranges of
these characteristics and how they vary by season, it will be nearly impossible to determine whether
the most important impacts have been identified or not. Even when these characteristics are discussed
thoroughly, however, it may be necessary to contact local ecological experts to determine whether the
changes in characteristics associated with exploration or drilling are likely to be significant or minor.
Experts can generally be found through contact with local universities, or state universities in nearby
locations.
Abiotic Ecosystem Parameters
Abiotic parameters that are important determinants of terrestrial ecosystem type and function. These
include the temperature regime and climate, water regime and rainfall, topography, soils, nutrients.
December 10, 1991 48 Preliminary Drart
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BACKGROUND FOR NEPA REVIEWER?
and light. Some of the most important abiotic parameters in aquatic ecosystems are size of water
body, water flow and flushing, temperature, salinity, and nutrient availability. Each of these
parameters is discussed below.
Temperature
The ability to withstand temperature extremes varies widely among animals and plants. Because the
optimum temperature for completion of several stages of the life cycle of many organisms varies.
temperature and climate impose a restriction on the distribution of species. Generally, the range of
many species is limited by the lowest or highest temperature in the most vulnerable stage of its life
cycle, usually the reproductive stage.
Water
The means of obtaining and conserving water shape the nature of terrestrial communities. In a
practical sense it is difficult to separate a discussion of water from the discussion of temperature or
climate because organisms use water for temperature control.
Moisture relationships within an ecosystem are often closely associated with the distribution of
rainfall. Because of this, seasonal distribution of rainfall is generally more important than average
annual precipitation. For example, organisms do not usually face water stress in a region receiving
SO inches of rainfall spread over the year, but the same rainfall falling over only a few months results
in extended periods of drought that may be difficult to survive.
Water is often a limiting factor in defining a habitat. Moisture, or lack of it, influences the
distribution of plants on a geographic or local basis. Alteration in the water regime thus may be
detrimental to existing populations.
Humidity, water in the air, affects the rate at which water is lost by plants and by soils. Humidity
varies with ground-cover and with topography. Relative humidity is generally greater under a forest
canopy than on the outside during the day, and the daily range of humidity is greatest in valleys,
decreasing with altitude. Local humidity regimes can be altered by the removal of ground-cover.
resulting in a pronounced effect on the composition of plant species in nearby areas.
Nutrients
Living organisms require at least 30 to 40 elements for their growth and development. Macro and
micronutrients are necessary for plant and animal life. These include calcium, magnesium.
phosphorus, potassium, sulfur, sodium, chorine, and trace dements such as copper, zinc, boron.
manganese, molybdenum, cobalt, vanadium, and iron. Plants are able to obtain these nutrients
directly from the soil. Animals are all ultimately dependent on plant life for their nutrients.
Each plant species has a requirement for a specific quantity of essential elements, and each species is
able to exploit the nutrient supply in a manner that may not be duplicated by other species. This
enables different plants growing in the same environment to exploit slightly different nutrient sources
For example, shallow rooted species may use the nutrient supply on the upper soil surface, while
December 10, 1991 49 Preliminary Dran
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OIL AND GAS
those with deep tap-roots may draw on deeper supplies of nutrients. Some species are successful in
nutrient poor soil, but are less able to compete against other species on richer soils. Therefore,
nutrient levels in soil have a pronounced influence on the local distribution of plants.
Soil acidity influences the uptake of nutrients by plants, and therefore has a strong influence on plant
distribution. Plants that are tolerant to acid conditions are generally more tolerant to metal ions than
plants that are adapted to high pH levels.
Because all animals depend directly or indirectly on plants for food, the quantity and quality of plants
can affect the well being of the animals. Where quantities are insufficient, animals may suffer from
malnutrition, starvation, or leave the area. Where the quality of the food is insufficient, reproductive
ability /success, health and longevity of the animals may be impacted.
In aquatic ecosystems, nutrients are generally introduced from land. Plants growing on river banks or
on shore retain nutrient-rich soil and absorb nutrients. The placement of an oil and gas facility may
require the removal of vegetation, and can increase the nutrient load to a water body, increasing the
probability of eutrophication.
Topography
As discussed above, topography influences the temperature regime and moisture regime of an area.
and therefore can be a determinant of plant communities and distribution. In dry areas, small-scale
changes in topography must be considered in siting an oil and gas facility. Low-lying areas may be
subject to flooding and may accumulate runoff and sustain plant and animal communities that are not
found in the surrounding areas.
Soils
Soils are formed from organic and inorganic materials and generally have a clearly defined structure.
This structure is a layering of materials of various characteristics, with each layer varying in thickness
within certain ranges. Plant communities are dependent on particular soil structures and other tactors
such as grain size, pH, and nutrient content. Removal of ground-cover may result in soil erosion.
removing the surface soil layer, resulting in and changes in plant communities. Mitigating measures
must be determined prior to any removal of existing soils and vegetation to limit the area affected by
erosion.
Light
Light is important in the biological function of plants. Light energy is used by plants for
photosynthesis. Some species require more light than others, and the amount of light or shading has
a fe at impact on the reproductive stages of plants. Some plants require large amounts of sunlight to
flower or to germinate. Others are less tolerant to bright sunlight and can only germinate in the
shade. Therefore, the removal of ground-cover may prevent some species from reproducing or
germinating, and open an area to less desirable, opportunistic species.
a
December 10. 1991
50 Preliminary
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BACKGROUND FOR NEPA REVIEWED
Flushing of Aquatic Ecosystems
Freshwater aquatic ecosystems may range from seasonal ponds and streams to rivers and lakes.
Saltwater systems include estuaries, coastal areas and oceans. The rate at which water moves through
those systems determines, to some extent, their ability to withstand discharges without serious effects.
In rivers and streams the flow of a water body can be characterized as a mean flow, x year low flow.
and x year high flow. Lakes and ponds can be characterized by the water turnover rate, the rate at
which water gets replaced. Extreme flows in streams (that are 3 orders of magnitude or more above
mean flows), indicate a propensity for flooding, and can be an important factor to consider in siting a
facility.
Salinity
The distribution of aquatic biota is influenced by the salinity of water bodies. Freshwater organisms
are generally sensitive to increases in salinity, and this is important when determining whether
produced waters should be discharged or re-injected. Even in more saline areas, discharge of saline
produced waters is important because transitions between fresh water and the sea consist of brackish
waters containing unique species assemblages that require specific salinity regimes for their survival
Turbidity and Suspended Sediments
Increases in turbidity can occur in an aquatic ecosystem as a result of a discharge, increase in soil
erosion, or through the resuspension of sediments. Increased turbidity can adversely impact
photosynthesis in aquatic systems by decreasing the light available to phytoplankton. Furthermore.
because turbidity is caused by suspended panicles, it can interfere with feeding efficiency of niter
feeders. Finally, as the suspended sediment settles, it can smother existing bottom vegetation and
alter flow regimes.
Biotic Ecosystem Parameters
Biotic ecosystem parameters provide an indication of the health of the ecosystem, and information on
the possible impacts of oil and gas operations on individual species or communities. Biotic
parameters that should be considered in an EIS or EA include rare and endangered species, and
dominant species, along with their relative populations sizes and habitats.
Rare and Endangered Species
Every EIS or EA should consider impacts on rare or endangered species. Generally, a list of sudi
species alone is inadequate to evaluate potential impacts. Information is also needed on the sue of the
population, and to the extent possible, on their preferred habitats, and the local distribution of that
habitat. Locally rare species are sometimes common in other areas of the country, but advene
impacts of oil and gas operations on populations of such species should not be discounted.
December 10, 1991 51 Prelimiiun
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OIL
Dominant or Important Species
Certain species can be considered dominant because of their large populations, while others are
dominant because they exert control beyond their numbers through their voraciousness or specialized
niche (food and/or shelter requirements). Dominant species can only be determined with a knowledge
of the local ecosystem. It may be necessary to consult wirn a local expert (e.g. member of the
ecology, botany, or zoology department of a local university or college, state fish and wildlife
service, etc.). Typically, EISs or EAs generally do not have information on the dominant species,
but may identify certain commercially or recreationally important species. Such designations
generally have no bearing on the ecological importance of these species. As with rare and
endangered species, lists of important or local species alone are inadequate to evaluate the potential
impacts of oil and gas activities on their populations.
Habitat
Each habitat, or place where a species lives, is defined by an assemblage of biotic and abiotic factors.
A habitat is by no means limited to a particular species, although some species have more specific
habitat requirements than others. While some habitat types are common in some areas of the country,
the locally rare habitats are typically more at risk. Some species require a minimum area of suitable
habitat in order to maintain their population sizes, and any decrease in that area will result in
decreases in numbers.
Terrestial Ecosystems
Generally, environmental impacts of oil and gas exploration or production can be tied to one of three
environmental changes: the release of toxic (or foreign) chemicals to the environment; the removal of
native vegetation to make room for drilling rigs, treatment facilities, or pits; or the modification of
the surface topography or soil structure in ways that modify surface and subsurface water flows or
indirectly modify the vegetation or animals that can be supported by an area. These are discussed
below.
Environmental Release of Toxic Chemicals
A great deal is known about the effects that individual toxic chemicals can have on individual
organisms or groups of organisms. Various toxicity tests are designed to measure the concentration
of toxicants in soils, water, or air that could have deleterious effects on a number of species of plants
and animals. Test results, expressed in terms of EC* or LC», indicate the concentration at which 50
percent of the organisms demonstrate an effect (EC») or die (LC») because of exposure to a
chemical. These data provide rough guidelines as to the safe environmental concentrations of various
chemicals. As a rule of thumb, divide the EC« or LC» by 100 to determine a safe concentration.
The factor of 100 is necessary to account for the many factors that are not measured in toxicity tests
such as extreme temperatures, exposure to more than one toxic chemical, or low availability of
habitat. If there are species that would be exposed to concentrations approaching an EC,, or LC» as
the result of releases of toxic chemicals, then those species will be severely impacted at the site.
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BACKGROUND FOR NEPA REVIEWER*
Generally, the effects of toxic substances are isolated to areas near spills. This is particularly true for
substances such as heavy metals (copper, lead, zinc, etc.), and some of the heavier hydrocarbons
(e.g., tars, etc.). For volatile organic compounds and those that are soluble in water, the point of
release can be some distance from the site of potential impact. Communities downslope,
downgradient, or downwind from the release point should be identified to ensure releases have
minimal impact or, especially if sensitive communities or locally rare habitats are present, that
suitable precautions are taken against accidental releases.
Downslope, downgradient and downwind communities are targeted because the scale of toxic
contamination is often site-specific, isolated to within a few hundred yards of a rig or reserve pit.
Thus, it may be necessary to know where rigs and pits are to be located in order to understand their
relationship to surrounding habitats. Generally, in order to adequately assess environmental impacts.
it is necessary to know specifically where drilling is likely to occur. Sites of potential releases can
thus be placed where the effects of any potential releases are minimized.
Environmental Release of Other Chemicals
A limited subset of chemicals is considered toxic by EPA at concentrations found in the environment.
Toxic chemicals include a variety of materials found in crude oil or drilling fluids, and include metals
such as chromium and zinc and various forms of hydrocarbons including PAHs (PNAs). Organic
chemicals, however, are generally of concern more because of their potential carcinogenic (cancer
producing) characteristics than because of their direct toxiciry. There are a whole range of
compounds that are integral to oil and gas exploration and production that are not generally
considered toxic to flora or fauna but may cause extensive environmental impacts. Also some
relatively non-toxic chemicals may be transformed into more toxic forms through interaction with
bacteria, or through environmental degradation (e.g. hydrolysis, photolysis). Crude oil, many of the
components of crude oil, and saline water are three types of. materials that are not generally
considered toxins but kill plants, mainly through altering their ability to take up and hold water
Because of the significance of the saline wastes that comprise most produced water, they should
receive special attention. In oil and gas production, produced water has a greater volume and
potential for mobility than do sediments. Some constituents associated with sediments (heavy metals.
hydrocarbons) might migrate depending on factors such as the pH of the soil. eH, porosity, and water
saturation. Saline waters readily percolate through soils, and can cause extensive contamination of
natural areas around reserve pits when sufficient precautions are not taken to prevent their release.
Trees and shrubs (and most other terrestrial vegetation) are readily killed by contact with soil or water'
that has a high salt content. The killing of vegetation around a facility by elevated salt levels in the
soil and the subsequent leaching of saline wastes through rainfall runoff lead to a wider area of
vegetation loss than caused by direct clearing. The greater the loss of vegetation, the greater the
potential for damage to odier resident species mat rely on the vegetation of a particular habitat (e.g.
woodland, meadow) for food or shelter.
Physical Disturbance - Woodlands
Loss of Habfrat Structure. Many of the characteristics of ecosystems are defined and preserved by
their structure. Forests and woodlands are characterized, for example, by varying amounts of
December 10. 1991 53 Preliminary Dratt
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OIL AND CAS
above-ground structure comprising the limbs and leaves (needles) of the dominant trees, perhaps
including an understory of different species. It is this vertical structure that provides appropriate
habitat for different species of birds and other wildlife, and there is a large group of invertebrate
species that typically inhabit the woodland canopy or the litter on the woodland floor. Removal of
this structure has ramifications for many plant and animal species, not just those obviously present.
For example, wildflowers that grow up annually from seeds, and that may provide food for wildlife.
may not grow if the woodland canopy is removed.
Removal of trees and associated understory has several effects. First, removal of trees allows more
sunlight to reach the ground. This alters the temperature regime of the liner layer, causing higher
temperatures to be reached during the day, and possibly lower temperatures to be reached at nigh:.
The increase in range of temperatures may not be suitable for the extant flora and fauna of the forest
floor, and therefore die native organisms may be replaced by opportunistic "nuisance" species, or the
total amount of living matter on the forest floor may be reduced. For small areas, such changes may
have minimal significancy (there are exceptions, see below), but with increasing removal of trees and
shrubs, changes become more extreme and can affect more than just the area where the trees were
removed. However, limiting disturbance to small areas does not always work to limit impacts, as
disturbance to many small areas may result in a large cumulative impact.
Loss of Minipum Habitat Areas. Most wildlife species prefer some minimum size of a specific
habitat type (or habitat types). Without a minimum area of habitat, they either cannot find sufficient
food to feed themselves and their offspring, cannot find nesting sites sufficiently distant from other
individuals of the same species, or cannot find sufficient protection from predators. Also, specialized
habitats are sometimes required in certain areas to provide resting locations for migrating birds or
animals. Thus, reducing the amount of habitat in a give area must be given careful consideration
One of the most damaging activities is the fragmentation of a limited habitat into two or more pans
Contiguous habitat can be divided by clearing a large area in its center for rigs, treatment facilities.
reserve pits or by building a road through it (for small areas). By dividing an area of habitat into two
pieces, it is possible to cause effects that are out of proportion to the amount of land being cleared
If, for example, an area supporting six pairs of a species is divided into two areas of equal size by a
road tiiat removes only 1% of the area, only four pairs might be able to survive in the remaining
area, depending on its shape. Because of the possibility of creating greater disturbances by dividing
up habitats, it is generally better to place facilities and roads at some distance from, or along the
edges of habitats that are locally limited in distribution.
rhang« in Runoff. Trees and shrubs intercept rainfall, slowing the rate at which it hits the ground
and providing a ground-level environment that reduces the rate of surface runoff. Ram hitting a
woodland is much more likely to be retained at the site and be incorporated into plants and animals
than rain hitting a cleared woodland. This has several benefits: first, the propensity for flooding m
downstream area* is maintained at a low level; second, erosion of soils necessary to support plant
growth is minimized; and third, nearby streams, lakes, and ponds are protected from high loads ot
sediments and nutrients that can cause permanent changes in their flora and fauna.
or
_ u m toot
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BACKGROUND FOR NEPA REVIEWERS
Physical Disturbance Grasslands and Scrublands
Grasslands and scrublands are dominant ecosystems in various parts of the country primarily based on
the amount of rainfall they receive. Grasslands typically dominate with rainfall of about 20 inches
per year (depending of the seasonally of precipitation), and scrublands (deserts) dominate with less
than 10 inches of rainfall per year. In both of these ecosystem types, water plays a key role in
determining not only the type of vegetation that occurs, but the kinds and abundance of animals as
well.
Grasslands and scrublands have structures similar to those of woodlands, but the scale of the
structures is smaller. Both of these types of ecosy^ems are generally "patchy* in distribution, and
isolated patches of locally rare habitats may significantly affect the viability of locally rare,
threatened, or endangered species. Thus, the location of exploratory wells and the relationships
among the various supporting facilities around exploratory wells can make significant differences in
the environmental effects realized by exploration and production.
While the scale of the patchiness of grasslands and scrublands varies (patchiness has been observed on
several different scales, from grids of a few square meters to grids of hectares), the scale of
significance with exploratory drilling is on the order of an acre, and with production facilities, several
acres. To avoid unnecessary disturbance of existing habitats, mitigating measures should be identified
in environmental documentation. These measures should be implemented so that decisions to locate
drilling or processing facilities take account of the identity of the types of vegetation at potential sites,
and the determination of whether this vegetation is relatively abundant or relatively rare in nearby
areas. If the species are relatively rare, alternative sites should be chosen in order to preserve the
existing large-scale structure of the ecosystem as much as possible.
In general terms, rigs and other facilities should not be located at the lowest point of land in the area
(this is a place where water is likely to accumulate, and thus have unique local importance), at the
lowest point of a swale or gully (for the same reason), or on significant slopes (unless necessary).
Placing structures (rigs, reserve pits, etc.) on slopes where they can interrupt the flow of water over
the land surface can sometimes have unexpected effects. Some localized habitats rely on water being
provided by overland sheet flow, flow in channels that are indistinct (small or shallow and broad) and
are not normally noticed. In drier areas, such overland flow during rain storms may provide critical
water to low-lying land in sufficient amounts to nourish more diverse habitats and sustain more
diverse communities in an environment that is normally considered to be inhospitable to them.
Physical Disturbance - Tundra
The tundra is the dominant ecosystem on the north slope of Alaska. A tundra is a treeless plain
characterized by low temperatures, a soon growing season, and low precipitation. Arctic tundras are
unique in that their shallow soil is underlain by a permanently frozen layer (permafrost) that is
impenetrable to water or roots. The vegetation of the tundra is structurally simple, consisting
primarily of grasses and sedges, and protects the permafrost by shading, which in turn reduces the
heating of the soil.
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OIL AND GAS
The permafrost is extremely sensitive to temperature changes and physical disturbance. Any
disturbance, however slight can cause the permafrost to melt. Since the permafrost itself is
impervious to water, it forces all the water to move above it. resulting in a cover of shallow lakes and
bogs in arctic flatlands. Because of the shallow soil and extremely short growing season, any
disturbed area of tundra regenerates very slowly.
In order to protect the permafrost, oil and gas exploration facilities, including structures such as
buildings and roads should be insulated from the permafrost. Current industry practice is to insulate
the tundra from roads or drilling pads using several feet of gravel. Buildings are built on gravel pads
or on raised pilings to prevent damage to the permafrost. Mitigation of damage on the tundra can be
accomplished by the appropriate timing of oil and gas activities and by insuring that a minimum area
is disturbed. An example of mitigation through timing is the transport of heavy equipment over the
tundra in winter when there is a protective layer of snow and ice, rather than summer, when the
tundra is most sensitive to physical disturbance.
Other Disturbances
Physical modification pose the greatest threat to ecosystems, but increased human activity resulting
from oil and gas operations can be equally disruptive to wildlife. Human activity may cause wildlife
to move out of an area or relocate in less desirable habitats. The effects of human activity can be
mitigated by judicious timing of activities to avoid sensitive stages in the animal's life cycle (e.g.,
migration or reproduction).
Aquatic Ecosystems
Unlike terrestrial ecosystems, where the primary effects of oil and gas exploration and production are
realized through physical disturbances or changing water relationships, the effects in the aquatic
environment are related primarily to chemical and physical alterations caused by waste disposal The
plan for disposal of drilling muds and cuttings and produced water determines potential effects
(barring accidents or spills caused by inadequate implementation of the disposal procedures).
When evaluating the effects on aquatic habitats, it is important to remember that aquatic environments
include flowing bodies of water such as rivers, streams, and estuaries and relatively quiescent water
bodies such as lakes, swamps, marshes, and ponds. In general terms, the potential for environmental
damage is related to the amount of water flowing through a system, and shallow, slow-flowing
systems, such as wetlands (marshes, swamps), are generally more sensitive to discharges and physical
disruption than other systems. Seasonal wetlands are particularly vulnerable to physical disruption
because their location is often not identified until the "wet" season, after the environment has been
disturbed. Since wetlands provide a unique habitat for wildlife and are among the most productive of
the aquatic environments, their identification and location should be of primary importance in
discussions of environmental effects.
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BACKGROUND FOR NEPA REVIEWERS
Discharges to Open Waters and Wetlands
A state may require that drilling muds and cuttings be contained in land-based facilities adjacent to the
body of water in which drilling is occurring. This is generally the preferred alternative for the
following reasons.
Drilling Muds and Cuttings. First, when drilling muds and cuttings are discharged directly into water
bodies, the turbidity of the water is increased, reducing the amount of light that can penetrate through
the water, and thus reducing the amount of plant production that occurs. This essentially reduces the
ability of the aquatic ecosystem to produce biomass and support a diverse and abundant flora and
fauna. Second, the nature of the drilling muds and cuttings is often substantially different from the
nature of the sediments at the drill site. Since most plants and animals inhabit sediments with a
limited range in grain sizes, changing the grain size of sediments around the drilling rig will cause the
local removal or replacement of native species with other species. While in some cases, species
replacement may have little effect, it is not usually possible to predict the species that would colonize
the new sediments, and thus it would be difficult to determine whether there would be significant
influence on rare, threatened, or endangered species in the area.
A third effect of the discharge of the drilling muds and cuttings into receiving waters is the potential
for the alteration of water flow. In marine environments, the muds form a barrier to water passage
(by forming a delta-like series of small islands, for example), this can alter the salinity and nutrient
relationships in estuarine environments. Barriers to free water exchange increase the hydraulic head
of fresh water, reduce the inflow of saline water, and thus reduce the overall salinity and salinity
range in the water body. With the reduction in saline water input, there is a concomitant reduction m
the input of marine larvae to the water body, and the nature of the flora and fauna could change from
a predominantly estuarine ecosystem that supports coastal fisheries to a fresh water system that is
much more isolated from the marine environment.
The disposal of drilling muds and cuttings in a fresh water body would lead to more rapid filling ot
die lake or marsh (ail very slow-flowing aquatic environments are slowly becoming shallower by
continual deposition of sediments), hastening the loss of that habitat, and potentially altering the
nature of the flora and fauna.
Produced Water. The disposal of produced water can pose problems because it often has a different
chemical composition than surface waters. The toxic components of produced waters have already
been »mph^fiT«rf for terrestrial systems, and their effects are potentially magnified in aquatic systems
because they can be transported by water far from their point of introduction. Ail states require that
discharges not be toxic, however, and most states have promulgated Water Quality Standards for
individual toxic chemicals to control the discharge of these chemicals.
Produced waters are almost always more saline than fresh waters at selected drilling depths, and
increased salinity in fresh water environments caused by produced water discharges reduces the utility
of the water as a drinking water supply, as a source of irrigation water, and as a natural source of
water for terrestrial ecosystems and aquatic biota.
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OIL AND GAS
The discharges of produced water that are more saline than estuarine water increase the salinity of the
receiving waters. If discharges have low flow relative to the flow of the estuary (1096 of estuary flow.
or less), the change may be small. On the other hand, with relatively high volume discharges relative
to receiving water flow (half or more of the esruarme flow), the discharge would substantially
increase receiving water salinity. The suitability of such sites for spawning and rearing of estuarine
or marine species may be significantly impacted by the increased salinity. Because some species
require a particular range of salinities in order to successfully reproduce, increases in salinity might
reduce the amount of lower salinity water available for successful reproduction, thus causing declines
in those populations.
Summary
The majority of impacts on inland ecosystems are associated with clearing native vegetation from sites
for the location of drilling rigs or supporting facilities. While clearing, by itself, can be substantially
detrimental to the ecosystem, the impact of clearing can be increased through poor management of
wastes. Migration of saline produced water through reserve pit walls can contaminate soils (and
ground water), directly killing the vegetation required to maintain water balances and support animal
communities.
The greatest impacts on coastal ecosystems are associated with the discharge of drilling fluids and
cuttings (in estuarine and marine areas) and produced waters (in fresh water areas). Both of these
processes are generally regulated at the State level, and if State laws and regulations are met. little
impact is expected. If, however, the solid or saline components of rig discharges are not regulated, a
full analysis of the fate and effects of these discharges should be carried out as part of the impact
assessment.
Finally, the major mitigating actions are those that are "implemented prior to drilling: locating rigs.
reserve pits, processing facilities, and roads in areas where they will have minimal impacts, and
designing facilities while considering the environment. Since the greater the area that is disrupted by
exploration or production, the greater the environmental disruption, and the greater the chance of
severe environmental effects, it is generally best to minimize the area affected. Disruption usually
cannot be "undone" by covering an area used for exploration or production with "natural" materials
since the "natural" structure of soils and sediments can take millennia to regenerate. So the focus of
mitigation should be on finding site locations and site designs that have the smallest potential for
adverse impacts, rather than fixing a site at a poor location or with a poor design once ecosystem
damage has occurred.
POTENTIAL IMPACTS ON LAND USE
For the purposes of this discussion, land use represents the family of surface activities which may be
practiced in a given area. Typical examples of land uses include agriculture, recreation, forestry.
housing, and so forth. The practicability of any given land use depends on the land characteristics or
other qualities. As a result, current or-future land use opportunities may be affected by impacts to
December 10, 1991 58 Prel.m.nar. Don
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BACKGROUND FOR NEPA REVIEWERS
ground water, surface water, air. or a combination of these media. The following potential impacts
are not exhaustive, nor does their inclusion represent any indication of the likelihood of occurrence.
Loss of Agricultural Land
Both plant and animal agriculture depend, in part, on soil productivity. As described earlier, oil and
gas exploration and production activities may result in impacts to soil and soil productivity. Of
particular concern is the accumulation of salts in soils, which may result in short- or long-term
decreases in productivity. Thus, direct application of saline-produced waters or drilling fluids may
result in a loss of soil productivity, thereby reducing the feasibility of agricultural uses for affected
areas. Typically, Federal lands are used for grazing. Loss of soil productivity and subsequent
impacts to vegetation may affect the potential for grazing usage.
Loss of Agricultural Irrigation
In many arid regions, the feasibility of agriculture depends on the availability of ground water for
irrigation. Salt contamination from oil and gas operations to ground water in such areas may result in
short-term plant damage and long-term loss of agricultural opportunities. Historical instances of such
impacts have occurred in association with waterflooding and disposal-injection operations in proximity
to agricultural water sources.
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OIL AND GAS
POSSIBLE PREVENTION/MITIGATION MEASURES
This section identifies techniques that mav be appropriate for mitigation of potential impacts caused
by oil and gas activities. Mitigation should be evaluated on a unit-by-unit site-specific basis, and the
following measures should only be used as a guide to measures that might be available should the
reviewer determine they might be appropriate.
Construction of diversion ditches and containment berms can reduce the volume of run-off
leaving a site. Reduction of run-off can reduce the chances of erosion and surface migration
of sediments and wastes to surface waters.
Reserve and mud pits may be constructed to contain total expected mud column volumes plus
rainfall, reducing the chances of pit overtopping.
Avoiding the addition to muds of known or suspected hazardous additives with less risk-prone
substitutes can reduce the potential impacts to ground water in the event of contact, as well as
simplify waste management.
Installation of surface casing to below the deepest USDW seals die well from water bearing
formations.
The separation of wastes of known or suspected hazard from otherwise low hazard materials
may reduce die potential impacts resulting from a release of pit contents.
Lining of pits can impede percolation of fluid in the pit.
Squeezing of fresh water sands with cement while drilling can inhibit migration of
contaminants into die zone and inhibit ground water draw down.
Secondary containment for above-ground tanks and containers can reduce impacts in events of
failure.
Dewatering of rr^d and reserve pit contents before burial may reduce the chance of downward
transport of contaminant* to shallow aquifers. Similarly, grading of soils covering pits may
reduce the chances of infiltration of rain water which may migrate to ground water.
Because of the potential for migration of injected fluids via abandoned wells in some
geological settings, current Class II Well requirements generally specify die need to identify
and plug damaged or improperly plugged abandoned wells within some distance of an
injection well. This practice may reduce the chances of migration of injected fluids to
USDWs.
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BACKGROUND FOR NEPA REVIEWERS
The separation of oily material from water based drilling fluids and the skimming of oil from
the surface of produced water storage pits can serve to reduce the potential impacts which
may result from releases of these pit wastes, and increase the recovery of product.
Flaring of waste gases at high temperatures may reduce emissions of products of incomplete
combustion.
Casing integrity tests reduces the chances of migration of fluids between zones.
Directional drilling may be used in conjunction with siting. Directional drilling places the
bottom of the well under an inaccessible surface location, i.e. under a river, lake. city or
other occupied place where vertical drilling is impractical. Are extreme example is horizontal
drilling, which allow - access to allow formations. However, directional wells are more
expensive to drill than vertical wells.
Monitoring of production water percentage can alert operator to any injection water or
formation water migration so that remedial measures can be rapidly taken.
Injection tracer surveys may reduce chances of injected water going into thief zones.
Monitoring systems on underground pipelines can prevent soil/ground water contamination.
Underground piping may also be made of corrosion resistant materials, or be protected using
cathodic protection or other devices.
Before fracturing jobs are undertaken the engineer/geologist should verify well logs and
identify and assess location of nearby wells (both potable water and other wells) to maxe sure
that fluid migration from the fracturing zone will not jeopardize fresh water aquifers
Timely closure of all pits and sumps.
Contaminated soil may be removed to a proper disposal facility.
Pretreannent of wastes before landfarming can reduce the potential for plant and soil impacts
by reducing excessive chloride, oil and grease, and phytotoxic constituent concentrations
Quality of injected fluid/steam/chemical/gas should be monitored closely to prevent downhole
formation contamination and prevent downhole equipment failure.
General field facility monitoring and maintenance.
Educating field personnel on awareness of the environment and environmental requirements
Locate facilities at the edge rather than the center of habitat types as much as possible
December 10, 1991 61 Prel.m.rur.
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OIL AND CAS
Minimize the area disturbed by each activity and site activities by considering rare habitats,
sensitive species, water bodies, etc.. and how disturbance may result in cumulative impacts on
the entire ecosystem.
Time activities to avoid disturbing plants and animals during crucial seasons in their life
cycles (mating, etc.).
December 10, 1994 62 Preliminary
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BACKGROUND FOR NEPA REVIEWERS
SUMMARY OF INFORMATION THAT SHOULD BE ADDRESSED
IN NZPA DOCUMENTATION
The following is a list of questions that may be appropriate to ask: about oil and gas operations when
reviewing NEPA documentation:
Has baseline data been collected to establish .jtural flow rates of ground water prior to
disturbance? What are the designated and actual uses of ground water? Where are me
nearest users of ground water located? What are the locations of all active, inactive, and
plugged wells in the area? What are the uses of each of these wells?
Has baseline data been collected to establish natural flow rates of surface water prior to
disturbance? What are the designated and actual uses of surface water? Where are the
nearest users located? Are streams in the area "losing streams" or "gaining streams'1"
What materials will be put into the reserve pit? Will any sampling be conducted to confirm
pit contents? Is there a leak-detection system or monitoring system associated with the
reserve pit? Is the anticipated closure of the reserve pit described in detail?
What are the concentrations of all constituents in the mud to be used for drilling at each weir
Will the type of mud be changed at any time during drilling? What are the expected
constituents and volumes produced?
What are the expected constituents (and their concentrations) of any produced water at each
facility?
How will the produced water be managed? Will the water be treated prior to disposal"1 it
disposal involves land treatment or evaporation/percolation, have the areas for direct
application (and any potential associated run-off areas) been surveyed for important species"
If a potential impact is suspected, what actions will be taken? Is the closure of these units
described in detail?
Is the potential area of influence surrounding the well (e.g., aquifers that are penetrated, eu >
monitored for change in chemical compositions or flow characteristics? How often will the
monitoring take place? Who will review the results? Does the monitoring account tor
seasonal variations? Are all ground-water discharge areas (e.g., springs, etc.) monitored"1 !:
a potential impact is suspected, what actions will be taken? Is well closure described in
detail?
Will service companies at each facility or site conduct any monitoring or sampling /ground
water, surface water, air, soils, waste, ecosystems, etc.) or report these results? What is the
planned frequency?
December 10, 1991 63 Prelimirur. :'-:-
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OIL AND GAS
What is the overall water balance for the site, including drilling, production, and closure0
What is the design capacity of each pit onsite. and does this capacity account for a specific
storm event (10-year, 50-year, or 100-year)? What is the planned freeboard on each pit0
What wastes will be generated onsite during each activity (e.g., drilling, stimulation.
workcover. closure, etc.). and how will they be managed?
What baseline conditions are described? Describe the monitoring of these conditions during
active operations, closure, and reclamation (include frequency, sample methodology, sample
placement, and methods of analysis).
Are cumulative impacts over the life of the facility or field (including possible expansions i
described?
Prior to conducting a fracturing job, has the strength of the formation been determined11
What is the range of impact expected? Will any other formations be involved? Have all
wells in the area (active or abandoned) been located? What is the distance to the nearest
aquifer (vertical and/or horizontal)?
Prior to water, steam, or other injection, have any thief zones been identified? What is the
range or extent of injection expected? Will any other formations be involved? Have all wells
in the area (active or abandoned) been located? What are the constituents of the injection
fluid? What is the distance to the nearest aquifer (vertical ami/or horizontal)?
Is there a leak detection system for any gathering lines or tanks used to store produced water.
crude oil, or wastes? Do all tanks have secondary containment? Describe any formalized
plans to respond to accidental releases.
How will air emissions be minimized? What technologies will be implemented for fugitive
dust emissions control? What are die constituents of each emission stream?
Is there containment for releases from emergency or pressure-release valves associated with
any phase of the operation?
Will mere be any future consequences of cessation of oil and gas withdrawal?
Are there any endangered, threatened, or rare species or critical habitats in the area?
Are the pre- and post-oil and gas land uses compared?
Have the different types of habitat been surveyed and mapped in die area?
Will wildlife access to all pits and ponds be controlled?
Is fencing, road building, or other disturbance expected to cause impacts on species
behavioral practices (fragmentation)?
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BACKGROUND FOR NEPA REVIEWERS
Are activities timed to occur during seasons not crucial to wildlife (mating, etc.) or plants'1
How will the site be reclaimed?
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OIL AND GAS
OTHER WASTES NOT UNIQUELY ASSOCIATED WITH
OIL AND GAS EXPLORATION AND PRODUCTION
In addition to the wastes described in the above sections, oil and gas operations generate other wastes.
such as spent solvents and used oil, that are not uniquely related to the industry. These wastes do not
meet the exclusion from RCRA Subtitle C [40 CFR 26l.4(b)(5)] regulation. See the section on
RCRA Regulations for further discussion of this exclusion.
Wastes not uniquely related to oil and gas include but are not limited to: unused fracturing fluids or
acids; drum rinsaie; vacuum truck nnsate; used equipment lubrication oils; waste solvents; boiler
scrubber fluids, sludges, and ash; incinerator ash; pigging wastes from transportation lines; sanitary
wastes, and laboratory wastes.
In some cases, these wastes are co-mingled with excluded wastes such as produced water in reserve
pits, or other units. Aside from possible RCRA compliance issues, managing these wastes in reserve
pits or other units may cause potential impacts to the environment. For example, solvents may tend
to be fairly mobile and may be released to ground water if disposed of in a unit that is unlined.
Management of these wastes should be sufficiently addressed in the NEPA documentation for each oil
and gas operation, where applicable. In addition, proper monitoring of storage and disposal units for
these wastes should be described.
rx u in 1001 66 Preliminary Drar
December 10, 1991 °°
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BACKGROUND FOR NEPA REVIEWERS
roENTIHCATION OF ADDITIONAL POTENTIAL IMPACTS
Although potential environmental impacts are described in th. above text, there are additional
potential impacts that may be caused by oil and gas operations. Additional issues and their related
statutes are identified below:
Spills or releases of hazardous substances (Comprehensive Environmental Response,
Compensation, and Liability Act)
Underground tanks (Resource Conservation and Recovery Act)
PCBs or other toxic substances such as asbestos (Toxic Substance Control Act)
Access roads or other off road vehicle travel (Clean Air Act)
Endangered, direatened or otherwise protected species (Endangered Species Act. Bald and
Golden Eagle Protection Act. Migratory Bird Treaty Act, Wild and Free-Roaming Horses and
Burros Act)
Archaeological Resources (Antiquities Act, Historic Sites, Buildings, and Antiquities Act.
Archaeological And Historic Preservation Act, and National Historic Preservation Act)
Socioeconomic impacts, including impacts on Native Americans (American Indian Religious
Freedom Act).
December 10. 1991 67 . Prenmmar,
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OIL AND CAS
LIST OF CONTACTS
U.S. ENVIRONMENTAL PROTECTION AGENCY
Dan Derlcics (703) 308-8409 FTS 398-8413
Chief. Oil and Gas Industry Section
Office of Solid Waste
Bonnie Robinson (703) 308-8429 FTS 398-8429
Office of Solid Waste
Dave Powers (202) 382-5909 FTS 382-5909
Office of Federal Activities
Beth Bell ("03) 557-7324 FTS 557-7324
Office of General Counsel
Jan Auerbach (202) 382-7703 FTS 398-8010
Office of General Counsel
U.S. DEPARTMENT OF THE INTERIOR
Bernie R. Hyde, Jr. (202)208-5517 FTS268-55P
Bureau of Land Management, Hazardous Materials Start Chief
Owen Williams (303) 221-5241 FTS 268-5241
National Park Service. Water Resources Division
Chuck Hunt (505) 624-1790
Director, Roswell Resource Area, NM
U.S. FOREST SERVICE
David Ketcham (202) 447^708 FTS 447^708
Environmental Coordination of Staff Director
William (MUt) Robinson (303) 236-9477 FTS 776-9477
Rocky Mountain Region, Denver, CO
Bill Miller (801) 625-5157 FTS 586-5157
Intermountain Region, Ogden, UT
December 10, 1991 68 Preliminary Drr:
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BACKGROUND FOR VEPA REVIEWERS
Leslie Vavaculik
Bruce Kamsev
(406) 329-3592
Northern Region, Missoula, VTT
(202)205-0836
Fluid Minerals Specialist
FTS 585-3592
December 10. 1991
69
Preliminary D'£
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OIL AND GAS
GLOSSARY
Abandon: To cease producing oil or gas from a well when it becomes unprofitable. A wildcat may
be abandoned after it has been proven nonproductive. Usually, when a well is abandoned, some of
the casing is removed and salvaged and one or more cement plugs are placed in the borehole to
prevent migration of fluids between the various formations. In many States, abandonment must be
approved by an official regulatory agency before being undertaken.
Acidize: To treat oil-bearing limestone or other formations, using a chemical reaction with acid, to
increase production. Hydrochloric or other acid is injected into the formation under pressure. The
acid etches the rock, enlarging the pore spaces and passages through which the reservoir fluids flow
The acid is then pumped out and the well is swabbed and put back into production. Chemical
inhibitors combined with the acid prevent corrosion of the pipe.
Adsorption: The adhesion of a thin film of a gas or liquid to the surface of a solid. Liquid
hydrocarbons are recovered from natural gas by passing the gas through activated charcoal, which
extracts the heavier hydrocarbons. Steam treatment of the charcoal removes the adsorbed
hydrocarbons, which are then collected and recondensed.
Aeration: The technique of injecting air or other gas into a fluid. For example, air is injected into
drilling fluid to reduce the density of the fluid.
Air Drilling: A method of rotary drilling that uses compressed air as its circulation medium This
method of removing cuttings from the wellbore is as efficient or more efficient than the traditional
methods using water or drilling mud; in addition, the rate of penetration is increased considerably
when air drilling is used. However, a principal problem in air drilling is the penetration of
formations containing water, since the entry of water into the system reduces its efficiency
Alkalinity: The combining power of a base, or alkali, as measured by the number of equivalents or
an acid with which it reacts to form a salt.
Annular Injection: Long-term disposal of wastes between the outer wall of the drill stem or tubing
and the inner wall of the casing or open hole.
Annuius or Annular Space: The space around a pipe in a weilbore. the outer wall of which may be
the wall of either the borehole or the casing.
December 10, 1991 70 Prehmm.^
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BACKGROUND FOR NEPA REVIEWERS
API: The American Petroleum Institute. Founded in 1920. this national oil trade organization is the
leading standardizing organization on oil-field drilling and producing equipment. It maintains
departments of transportation, refining, and marketing in Washington, D.C., and a department of
production in Dallas.
Artificial Lift: Any method used to raise oil to the surface through a well after reservoir pressure
has declined to the point at which the well no longer produces by means of natural energy. Artificial
lift may also be used during primary recovery if the initial reservoir pressure is inadequate to bring
the hydrocarbons to the surface. Sucker-rod pumps, hydraulic pumps, submersible pumps, and gas
lift are the most common methods of artificial lift.
Attapuigite: A fibrous clay mineral that is a viscosity-building substance, used principally in
saltwater-based drilling muds.
Barite: Barium sulfate, BaS04; a mineral used to increase the weight of drilling mud. Its - :i:l<:
gravity is 4.2.
Barrel (bbl): A measure of volume for petroleum products. One barrel (1 bbl) is equivalent to *:
U.S. gallons or 158.97 liters. One cubic meter (1 m3) equals 6.2897 bbl.
Basin: A synclinal structure in the subsurface, formerly the bed of an ancient sea. Because it is
composed of sedimentary rock and its contours provide traps for petroleum, a basin is a good
prospect for exploration. For example, the Permian Basin in West Texas is a major oil producer
Bentonite: A colloidal clay, composed of montmorillonite, which swells when wet. Because of its
gel-forming properties, bentonite is a major component of drilling muds.
Blowout Preventer (BOP): Equipment installed at the wellhead at surface level on land rigs and on
the seafloor of floating offshore rigs to prevent the escape of pressure either in the annular space
between the casing and drill pipe or in an open hole during drilling and completion operations.
Blow Out: To suddenly expel oil/gas-well fluids from the borehole with great velocity.
Borehole: The wellbore; the hole made by drilling or boring.
Brine: Water that has a large quantity of salt, especially sodium chloride, dissolved in it: salt water
Casinghead Gas: Gas produced with oil.
Casing String: Casing is manufactured in lengths of about 30 ft, each length or joint being joined to
another as casing is run in a well. The entire length of all the joints of casing is called the casing
string.
Cement Plug: A portion of cement placed at some point in the wellbore to seal it.
December 10. 1991 71 Prelimirun 2r,r
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OIL AND GAS
Christmas Tree: Assembly of fittings and valves at the tip of the casing of an oil well that controls
the flow of oil from the well.
Circulate: To pass from one point throughout a system and back to the starting point. Drilling fluid
circulates from the suction pit through the drill pipe to the bottom of the well and returns through the
annulus.
Close-in: A well capable of producing oil or gas, but temporarily not producing.
Collar: A coupling device used to join two lengths of pipe. A combination collar has left-hand
threads in one end and right-hand threads in the other. A drill collar.
Completion Fluid: A special drillir? mud used when a well is being completed. It is selected not
only for its ability to control formation pressure, but also for its properties that minimize formation
damage.
Completion Operations: Work performed in an oil or gas well after the well has been drilled to the
point at which the production string of casing is to be set. This work includes setting the casing.
perforating, artificial stimulation, production testing, and equipping the well for production, all prior
to the commencement of the actual production of oil or gas in paying quantities, or in the case of an
injection or service well, prior to when the well is plugged and abandoned.
Condensate: A light hydrocarbon liquid obtained by condensation of hydrocarbon vapors. It consists
of varying proportions of butane, propane, pentane, and heavier fractions, with little or no ethane or
methane.
Conductor Pipe: A short string of large-diameter casing used offshore and in marshy locations to
keep the top of the wellbore open and to provide a means of conveying the upflowmg drilling fluid
from the wellbore to the mud pit.
Coning: The encroachment of reservoir water into the oil column and well.
Connate Water: The original water retained in the pore spaces, or interstices, of a formation from
the time the formation was created.
Crude Oil: Unrefined liquid petroleum. It ranges in gravity from 9° to 55° API and in color from
yellow to black, and it may have a paraffin, asphalt, or mixed base. If a crude oil, or crude, contains
a sizable amount of sulfur or sulfur compounds, it is called a sour crude; if it has little or no sulfur, it
is called a sweet crude. In addition, crude oils may be referred to as heavy or light according to API
gravity, the lighter oils having the higher gravities.
Cuttings: The fragments of rock dislodged by the bit and brought to the surface in the drilling mud.
Washed and dried samples of the cuttings are analyzed by geologists to obtain information about the
formations drilled.
December 10. 1991 ^ Prelimmarv Dr.r
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BACKGROUND FOR VEPA REVIEWERS
Deflocculation: The dispersion of solids that have stuck together in drilling fluid, usually by means
of chemical thinners.
Defoamer: Any chemical that prevents or lessens frothing or foaming in another agent.
Dehydrate: To remove water from a substance. Dehydration of crude oil is normally accomplished
by emulsion treating with emulsion breakers. The water vapor in natural gas must be removed to
meet pipeline requirements; a typical maximum allowable water vapor content is 11b per MMcf
Demulsify: To resolve an emulsion, especially of water and oil, into its components.
Desander: A centrifugal device used to remove fine particles of sand from drilling fluid to prevent
abrasion of the pumps. A desander usually operates on the principle of a fast-moving stream of fluid
being put into a whirling motion inside a cone-shaped vessel.
Desiccant: A substance able to remove water from another substance with which it is in contact. It
may be liquid (as thethyiene glycol) or solid (as silica gel).
Desilter: A centrifugal device, similar to a desander. used to remove very fine particles, or stlt. from
drilling fluid to keep the amount of solids in the fluid to the lowest possible level. The lower the
solids content of the mud is, the faster the rate of penetration.
Development Well: A well drilled in proven territory in a field to complete a pattern of production
Drill Collar: A heavy, thick-walled tube, usually steel, used between the drill pipe and the bit in the
drill stem to weight the bit in order to improve its performance.
Drilling Fluid: The circulating fluid (mud) used in the rotary drilling of wells to clean and condition
the hole and to counterbalance formation pressure. A water-based drilling fluid is the conventional
drilling mud in which water is the continuous phase and the suspended medium for solids, whether or
not oil is present. An oil-based drilling fluid has diesel, crude, or some other oil as its continuous
phase with water as the dispersed phase. Drilling fluids are circulated down the drill pipe and back;
up the hole between the drill pipe and the walls of the hole, usually to a surface pit. Drilling fluids
are used to lubricate the drill bit, to lift cuttings, to seal off porous zones, and to prevent blowouts
There are two basic drilling media: muds (liquid) and gases. Each medium comprises a number or
general types. The type of drilling fluid may be further broken down into numerous specific
formulations.
Drill Pipe: The heavy seamless cubing used to rotate the bit and circulate the drilling fluid. Joints of
pipe 30 ft long are coupled together by means of tool joints.
Drill Stem: The entire length of tubular pipes, composed of the kelly, the drill pipe, and drill
collars, that make up the drilling assembly from the surface to the bottom of the hole.
Drill String: The column, or string, of drill pipe, not including the drill collars or kelly. Otten.
however, the term is loosely applied to include both the drill pipe and drill collars.
December 10, 1991 "3 Prelimmar.
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OIL AND GAS
Dry Hole: Any well that does not produce oil or gas in commercial quantities. A dry hole may flow
water, gas, or even oil, but not enough to justify production.
Emulsion: A mixture in which one liquid, termed the dispersed phase, is uniformly distributed
(usually as minute globules) in another liquid, called the continuous phase or dispersion medium. In
an oil-water emulsion, the oil is the dispersed phase and the water the dispersion medium: in a water-
oil emulsion the reverse holds. A typical product of oil wells, water-oil emulsion also is used as a
drilling fluid.
Emulsion Breaker: A system, device, or process used for breaking down an emulsion and rendering
it into two or more easily separated compounds (as water and oil). Emulsion breakers may be (U
devices to heat the emulsion, thus achieving separation by lowering the viscosity of the emulsion and
allowing the water to settle out; (2) chemical compounds, which destroy or weaken the film around
each globule of water, thus uniting all the drops: (3) mechanical devices such as settling tanks and
wash tanks: or (4) electrostatic treaters. which use an electric field to cause coalescence of the water
globules. This is also called electric dehydration.
Enhanced Oil Recovery (EOR): A method or methods applied to depleted reservoirs to make them
productive once again. After an oil well has reached depletion, a certain amount of oil remains in the
reservoir, which enhanced recovery is targeted to produce. EOR can encompass secondary and
tertiary production.
Field: A geographical area in which a number of oil or gas wells produce from a continuous
reservoir. A field may refer to surface area only or to underground productive formations as well
In a single field, there may be several separate reservoirs at varying depths.
Flocculation: A property of contaminants or special additives to a drilling fluid that causes the solids
to coagulate.
Flowing Well: A well that produces oil or gas without any means of artificial lift.
Foaming Agent: A chemical used to lighten the water column in gas wells, in oil wells producing
gas, and in drilling wells in which air or gas is used as the drilling fluid so that the water can be
forced out with the air or gas to prevent its impeding the production or drilling rate.
Formation: A bed or deposit composed throughout of substantially the same kinds of rock; a
lithologic unit. Each different formation is given a name, frequently as a result of the study of the
formation outcrop at the surface.
Formation Pressure: The pressure exerted by fluids in a formation, recorded in the hole at the level
of the formation with the well shut in. It is also called reservoir pressure or shut-in bottomhole
pressure.
Formation Water: The water originally in place in a formation.
December 10. 1991
74 Preliminary Dr.irt
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BACKGROUND FOR NEPA R£VTE\VERS
Fracturing: A method of stimulating production by increasing the permeability of the producing
formation. Under extremely high hydraulic pressure, a fluid is pumped downward through tubing or
drill pipe and forced into the perforations in the casing. The fluid enters the formation and parts or
fractures it. Sand grains, aluminum pellets, glass beads, or similar materials are carried in suspension
by the fluid into the fractures. These are called propping agents. When the pressure is released at
the surface, the fracturing fluid returns to the well, and the fractures partially close on the propping
agents, leaving channels through which oil flows to the well.
Free Water: The water produced with oil. It usually settles out within 5; minutes when the well
fluids become stationary in a settling space within a vessel.
Gas Lift: The process of raising or lifting fluid from a well by injecting gas down the well through
tubing or through the tubing-casing annulus. Injected gas aerates the fluid to make it ex en less
pressure than the formation does: consequently, the higher formation pressure forces the fluid out of
the wellbore. Gas may be injected continuously or intermittently, depending on the producing
characteristics of the well and the arrangement of the gas-lift equipment.
Gas-Oil Ratio: Number of cubic feet of gas produced with a barrel of oil.
Gathering Line: A pipeline, usually of small diameter, used in gathering crude oil from the oil field
to a point on a main pipeline.
Glycol Dehydrator: A processing unit used to remove all or most of the water from gas. Usually a
glycol unit includes a tower, in which the wet gas is put into contact with glycol to remove the water.
and a reboiler. which heats the wet glycol to remove the water from it so the glycol can be recycled
Hard Water: Water that contains dissolved compounds of calcium, magnesium, or both.
Heater-treater: A vessel that heats an emulsion and removes water and gas from the oil to raise it to
a Duality acceptable for pipeline transmission. A heater-treater is a combination of a heater, free-
water knockout, and oil and gas separator.
Hydraulic Fracturing: The forcing into a formation of liquids under high pressure to open passages
for oil and gas to flow through and into the wellbore.
Hydrocarbons: Organic compounds of hydrogen and carbon, whose densities, boiling points, and
freezing points increase as meir molecular weights increase. Although composed of only two
elements, hydrocarbons exist in a variety of compounds because of the strong affinity of the carbon
atom for other atoms and for itself. The smallest molecules of hydrocarbons are gaseous; the largest
are solid.
Hydrostatic Head: The pressure exerted by a body of water at rest. The hydrostatic head of fresh
water is 0.433 per foot of height. The hydrostatic heads of other liquids may be determined by
comparing their gravities with the gravity of water.
December 10. 1991 ^ Prelim.nar> Draft
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OIL AND GAS
Inhibitor: An additive used to retard undesirable chemical action in a product: added in small
quantity to gasolines to prevent oxidation and gum formation, to lubricating oils to stop color change.
and to corrosive environments to decrease corrosive action.
Intermediate Casing String: The string of casing set in a well after the surface casing to keep the
hole from caving in. Sometimes the blowout preventers can be attached to it. The string is
sometimes called protection casing.
Interstice: A pore space in a reservoir rock.
Joint: A single length (30 ft) of drill pipe or of drill collar, casing, tubing, or rod that has threaded
connections at both ends. Several joints screwed together constitute a stand of pipe.
Kelly: The heavy metal shaft, four- or six-sided, suspended from the swivel through the rotary table
and connected to the topmost joint of drill pipe to turn the drill stem as the rotary nable turns. It has
a bored passageway that permits fluid to be circulated into the drill stem and up the annulus. or vice
versa.
Log: A systematic recording of data, as from the driller's log, mud log, electrical well log. or
radioactivity log. Many different logs are run in wells being produced or drilled to obtain
information about various characteristics of downhole formations.
Manifold: An accessory system of piping to a main piping system (or another conductor) that serves
to divide a flow into several parts, to combine several flows into one, or to reroute a flow to any one
of several possible destinations.
Marginal Well: An oil or gas well that produces such a small volume of hydrocarbons that the gross
income therefrom provides only a small margin of profit or, in many cases, does not even cover the
cost of production.
Mud: The liquid circulated through the wellbore during rotary drilling and workover operations. In
addition to its function of bringing cuttings to the surface, drilling mud cools and lubricates the bit
and drill stem, protects against blowouts by holding back subsurface pressures, and deposits a mud
cake on the wall of the borehole to prevent loss of fluids to the formation. Although it originally was
a suspension of earth solids (especially clays) in water, the mud used in modern drilling operations is
a more complex, three-phase mixture of liquids, reactive solids, and inert solids. The liquid phase
may be fresh water, diesel oil,.or crude oil and may contain one or more conditioners.
Mud Pit: A reservoir or tank, usually made of steel plates, through which the drilling mud is cycled
to allow sand and tine sediments to settle out. Additives are mixed with mud in the pit, and the fluid
is temporarily stored there before being pumped back into the well. Mud pits are also called shaker
pits, settling pits, and suction pits, depending on their main purpose.
Oil and Gas Separator: An item of production equipment used to separate the liquid components of
the well stream from the gaseous elements. Separators are vertical or horizontal and are cylindrical
or spherical in shape. Separation is accomplished principally by gravity, the heavier liquids tailing to
December 10, 1991
75 Prelimmir;. Dr.ir
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BACKGROUND FOR NEPA REVIEWERS
the bottom and the gas rising to the top. A float valve or other liquid-level control regulates the level
of oil in the bottom of the separator.
Oil-based Mud: An oil mud that contains from less than 2 percent up to 5 percent water. The water
is spread out. or dispersed, in the oil as small droplets.
Oil Field: The surface area overlying an oil reservoir or reservoirs. Commonly, the term includes
not only the surface area but also the reservoir, wells, and production equipment.
Packer: A piece of downhole equipment, consisting of a sealing device, a holding or setting device.
and an inside passage for fluids, used to block the flow of fluids through the annular space between
the tubing and the wall of the wellbore by sealing off the space. It is usually made up in the tubing
string some distance above the producing zone. A sealing element expands to prevent fluid flow
except through the inside bore of the packer and into the tubing. Packers are classified according to
configuration, use. and method of setting and whether or not they are retrievable (i.e.. whether they
can be removed when necessary, or whether they must be milled or drilled out and thus destroyed)
Packer Fluid: A liquid, usually mud but sometimes salt water or oil. used in a well when a packer is
between the tubing and casing. Packer fluid must be heavy enough to shut off the pressure or the
formation being produced, must not stiffen or settle out of suspension over long periods of time, and
must be noncorrosive.
Perforate: To pierce the casing wall and cement to provide holes through which formation fluids
may enter or to provide holes in the casing so that materials may be introduced into the annul us
between the casing and the wall of the borehole. Perforating is accomplished by lowering into :he
well a perforating gun, or perforator, that fires bullets or shaped charges electrically detonated rrom
the surface.
Permeability: A measure of the ease with which fluids can flow through a porous rock.
Pig: A scraping tool that is forced through a pipeline or flow line to clean out accumulations or * iv
scale, and so forth, from the inside walls of a pipe. A cleaning pig travels with the flow or proo_.t
in the line, cleaning the walls of the pipe with blades or brushes. A batching pig is a cylinder *iui
neoprene or plastic cups on either end used to separate different products traveling in the same
pipeline.
Porosity: The quality or state of possessing pores (as a rock formation). The ratio of the volume
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OIL AND GAS
Producing Zone: The zone or formation from which oil or gas is produced.
Production: The phase of the petroleum industry that deals with bringing the well fluids to the
surface and separating them and with storing, gauging, and otherwise preparing the product for the
pipeline.
Production Casing: The last string of casing or liner that is set in a well, inside of which is usually
suspended the tubing string.
Propping Agent: A granular substance (as sand grains, walnut shells, or other material) carried in
suspension by the fracturing fluid that serves to keep the cracks open when the fracturing fluid that
serves to keep the cracks open when the fracturing fluid is withdrawn after a fracture treatment
Radioactive Tracer: A radioactive material (often carnotite) put into a well to allow observation of
fluid or gas movements by means of a tracer survey.
Reserve Pit: Drilling related pit used to store and/or dispose of used drilling muds and drill cuttings
Reservoir: A subsurface, porous, permeable rock body in which oil or gas or both are stored Most
reservoir rocks are limestones, dolomites, sandstones, or a combination of these. The three basic
types of hydrocarbon reservoirs are oil. gas, and condensate. An oil reservoir generally contains
three fluids-gas, oil, and water-with oil the dominant product. In the typical oil reservoir, these
fluids occur in different phases because of the variance in their gravities. Gas. the lightest, occupies
the upper pan of the reservoir rocks; water, the lower pan; and oil, the intermediate section. In
addition to occurring as a cap or in solution, gas may accumulate independently of the oil; if so. the
reservoir is called a gas reservoir. Associated with the gas. in most instances, are salt water and
some oil. In a condensate reservoir, the hydrocarbons may exist as a gas, but when brought to the
surface, some of the heavier ones condense to a liquid or condensate. AT the surface the
hydrocarbons from a condensate reservoir consist of gas and a high-gravity crude (i.e.. the
condensate). Condensate wells are sometimes called gas-condensate reservoirs.
Resistivity: The electrical resistance offered to the passage of current; the opposite of conductivity
Rig: The derrick, drawworks, and attendant surface equipment of a drilling or workover unit.
Rotary: The machine used to impart rotational power to the drill stem while permitting vertical
movement of the pipe for rotary drilling. Modern rotary machines have a special component, the
rotary bushing, to turn the kelly bushing, which permits venical movement of the kelly while the
stem is turning.
Secondary Recovery: Any method by which an essentially depleted reservoir is restored to
producing status by the injection of liquids or gases (from extraneous sources) into the wellbore. This
injection effects a restoration of reservoir energy, which moves the formerly unrecoverable secondary
reserves through the reservoir to the wellbore.
December 10, 1991
7g Preliminary Drar.
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BACKGROUND FOR NTPA REVIEWERS
Sediment: The matter that settles to the bottom of a liquid: also called tank bottoms, basic sediment.
and so forth.
Shale Shaker: A series of trays with sieves that vibrate to remove cuttings from the circulating fluid
in rotary drilling operations. The size of the openings in the sieve is carefully selected to matcn the
size of the solids in the drilling fluid and the anticipated size of cuttings. It is also called a shaker.
Sour: Containing hydrogen sulfide or caused by hydrogen sulfide or another sulfur compound.
Specific Gravity: The ratio of the weight of a substance at a given temperature to the weight of an
equal volume of a standard substance at the same temperature. For example, if 1 in.3 of water at
39 F weighs 1 unit and 1 in.3 of another solid or liquid at 39°F weighs 0.95 unit, then the specific
gravity of the substance is 0.9S. In determining the specific gravity of gases, the comparison is made
with the standard of air or hydrogen.
Spud: To move the drill stem up and down in the hole over a short distance without rotation.
Careless execution of this operation creates pressure surges that can cause a formation to break down.
which results in lost circulation.
Spud In: To begin drilling; to start the hole.
Stock Tank: A crude oil storage tank.
Stripper: A well nearing depletion that produces a very small amount of oil or gas.
Sump: A low place in a vessel or tank used to accumulate settlings that are later removed through in
opening in the bottom of the vessel.
Supernatant: A liquid or fluid forming a layer above settled solids.
Surface Pipe: The first string of casing set in a-well after the conductor pipe, varying in length from
a few hundred feet to several thousand.
Surfactant: A substance that affects the properties of the surface of a liquid or solid by concentrating
on the surface layer. The use of surfactants can ensure that the surface of one substance or object is
in thorough contact with die surface of another substance.
Tank Battery: A group of production tanks located in the field that store crude oil.
Tertiary Recovery: A recovery method used to remove additional hydrocarbons after secondary
recovery methods have been applied to a reservoir. Sometimes more hydrocarbons can be removed
by injecting liquids or gases (usually different from those used in secondary recovery and applied with
different techniques) into the reservoir.
Tubing: Small-diameter pipe that is run into a well to serve as a conduit for the passage of oil and
gas to the surface.
December 10, 1991 79 Preliminar.
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OIL AND GAS
Viscosity: A measure of the resistance of a liquid to flow. Resistance is brought about by the
internal friction resulting from the combined effects of cohesion and adhesion. The viscosity of
petroleum products is commonly expressed in terms of the time required for a specific volume of the
liquid to flow through an orifice of a specific size.
Volatile: Readily vaporized.
Waterflood: A method of secondary recovery in which water is injected into a reservoir to remove
additional quantities of oil that have been left behind after primary recovery. Usually, a waterflood
involves the injection of water through wells specially set up for water injection and the removal or
the water and oil from the wells drilled adjacent to the injection wells.
Weighting Material: A material with a specific gravity greater than that of cement: used to increase
the density of drilling fluids or cement slurries.
Wellbore: A borehole: the hole drilled by the bit. A wellbore may have casing in it or may be open
(i.e.. uncased); or a portion of it may be cased and a portion of it may be open.
Well Completion: The activities and methods necessary to prepare a well for the production of oil
and gas; the method by which a flow line for hydrocarbons is established between the reservoir and
the surface, the method of well completion used by the operator depends on the individual
characteristics of the producing formation or formations. These techniques include open-hole
completions, conventional perforated completions, sand-exclusion completions, tubingless
completions, multiple completions, and miniaturized completions.
Wellhead: The equipment used to maintain surface control of a well, including the casmghead.
tubing head, and Christmas tree.
Well Spacing: The regulation of the number and location of wells over a reservoir as a conservation
measure.
Well Stimulation: Any of several operations used to increase the production of a well.
Wildcat: A well drilled in area where no oil or gas production exists.
Workover: One or more of a variety of remedial operations performed on a producing oil *ell to try
to increase production. Examples of workover operations are deepening, plugging back, pulling and
resetting the liner, squeeze-cementing, and so on.
Workover Fluidi: A special drilling mud used to keep a well under control when it is being worked
over. A workover fluid is compounded carefully so it will not cause formation damage.
December 10, 1991 80 Prelim.n^
-------
BACKGROUND FOR NEPA REVIEWERS
REFERENCES
Adamache, I. "Contaminated Sulfur Recovery by Froth Flotation." In Proceedings of the First
International Symposium on Oil and Gas Production Waste Management Practices. New Orleans.
LA. September 10 - 13, 1990.
Allen and Roberts, University of Tulsa, Oklahoma. "Production and Operations." Undated.
American Petroleum Institute. "Environmental Guidance Document: Onshore Solid Waste
Management in Exploration and Production Operations." January 15, 1989.
API Environmental. "Onshore Solid Waste Management in Exploration and Production Operations
Undated.
Boyle, C. A. "Management of Araine Process Sludges." In Proceedings of the First International
Symposium on Oil and Gas Production Waste Management Practices. New Orleans, LA. September
10- 13, 1990.
Deuel, L.E. "Evaluation of Limiting Constituents Suggested for Land Disposal of Exploration and
Production Wastes." In Proceedings of the First International Symposium on Oil and Gas Production
Waste Management Practices. New Orleans, LA. September 10 - 13, 1990.
Englehardt, F.R., Ray, J. P.. and Gillam, A. H. "Drilling Wastes." Elsevier Science Publishing
Co., Inc., New York, NY. 1989.
Fitzpatrick. M. "Common Misconceptions about the RCRA.Subtitle C Exemption for Wastes from
Crude Oil and Natural Gas Exploration, Development, and Production." In Proceedings of the First
International Svmposmm on Oil and Gas Production Waste Management Practices. New Orleans.
LA. September 10 - 13, 1990.
Gatlin, C., Department of Petroleum Engineering, University of Texas. "Petroleum Engineering,
Drilling and Well Completion." Undated.
Hall, R. "Environmental Consequences of Mismanagement of wastes from Oil and Gas Exploration.
Development, and Production." In Proceedings of the First International Symposium on Oil and Gas
Production Waste Management Practices. New Orleans, LA. September 10 - 13, 1990.
Hardisty, P. E. "Nature, Occurrence and Remediation of Groundwater Contamination at Alberta
Sour Gas' Plants." In Proceedings of the First International Symposium on Oil and Gas Production
Waste Management Practices. New Orleans, LA. September 10 - 13, 1990.
Ikoku, Chi U, Pennsylvania State University. "Natural Gas Reservoir Engineering." 1984.
December 10, 1991 81 Preliminary Dun
-------
OIL AND GAS
Interstate Oil Compact Commission. "EPA/IOCC Study of State Regulation of Oil and Gas
Exploration and Production Wastes.' December, 1990.
Macyk. T. M.. et al. "Drilling Waste Landspreading Field Trial in the Cold Lake Heavy Oil Region.
Alberta, Canada." In Proceedings of the First International Symposium on Oil and Gas Production
Waste Management Practices. New Orleans, LA. September 10 - 13. 1990.
McFarland. M. L.. et al. "Evaluation of Selective Placement Burial for Disposal of Drilling Fluids in
West Texas." In Proceedings of the First International Symposium on Oil and Gas Production Waste
Management Practices. New Orleans, LA. September 10 - 13, 1990.
Prepared for American Petroleum Institute by Battelle Ocean Sciences. "Bioaccumulanon and
Biomagnification of Chemicals from Oil Well Drilling and Production Wastes in Marine Food Webs
A Review." February 25, 1988.
Rabalais, N. N. "Fate and Effects of Produced Water Discharges in Coastal Environments " In
Proceedings of the First International Symposium on Oil and Gas Production Waste Management
Practices. New Orleans. LA. September 10 - 13, 1990.
Shirazi. G. A. "Landfarming of Drilling Muds in Conjunction with Pit/Site Reclamation: A Case
History." In Proceedings of the First International Symposium on Oil and Gas Production Waste
Management Practices. New Orleans, LA. September 10 - 13, 1990.
Texas Department of Agriculture, Office of Natural Resources. "Agricultural Land and Water
Contamination from Injection Wells, Disposal Pits, and Abandoned Wells Used in Oil and Gas
Production." Undated.
U.S. Department of Agriculture, Forest Service Region 1. "Northern Little Missouri NationaJ
Grassland. Oil and Gas Leasing Draft Environmental Impact Statement, Custer National Forest.
1991.
U. S. Department of the Interior, Bureau of Land Management and U. S. Department of Agriculture.
Forest Service. "Oil and Gas Surface Operating Standards for Oil and Gas Exploration and
Development." January 1989.
U.S. Department of the Interior. Bureau of Land Management. "Planning for Fluid Mineral
Resources" (H-1624-1). May 7, 1991.
U. S. Environmental Protection Agency. "Management of Wastes from the Exploration,
Development, and Production of Crude Oil. Natural Gas. and Geothermal Energy Report to
Congress" (EPA/530-SW-88-003). December 1987.
U.S. Environmental Protection Agency. "Environmental Progress and Challenges: EPA's Update.
(EPA-230-67-88-033). August 1988.
December 10, 1991 82 Prelimmar- 2-
-------
BACKGROUND FOR NEPA REVIEWERS
U. S. General Accounting Office. "Drinking Water: Safeguards are not Preventing Contamination
from Injected Oil and Gas Wastes.' July 1989.
U. S. General Accounting Office. "Federal Land Management: Better Oil and Gas Information
Needed to Support Land Use" (GAO/RCED-90-71). June 1990.
Wagner. T. P. "The Complete Guide to Hazardous Waste Regulations," second edition. Van
Nostrand Reinhold. New York. NY. 1991.
Warner. D. and McConnel, C. "Evaluation of the Groundwater Contamination Potential of
Abandoned Wells by Numerical Modelling." In Proceedings of the First International Symposium on
Oil and Gas Production Waste Management Practices. New Orleans, LA. September 10 - 13. 1990.
Welker. Anthony J. "The Oil and Gas Book." 1985.
December 10, 1991
53 Preliminary Drart
-------
OIL AND GAS
ANNOTATED BIBLIOGRAPHY
Adamanche, I. No date. Contaminated Sulfur Recovery by Froth Flotation.
The paper discusses the design and performance characteristics of a froth flotation
sulfur recovery cycle used to reclaim contaminated sulfur block base pad sulfur in
Canada. Comparison with "remelt and filter" processes suggests greater recovery
with less hazardous waste products may be achieved using froth flotation.
API. January 15. 1989. Environmental Guidance Document: Onshore Solid Waste Management in
Exploration and Production Operations.
This document discusses general waste and management considerations related to
onshore oil and gas operations. The emphasis of the recommendations is on the
distinction between RCRA exempt and non-exempt wastes and suggestions for
minimizing the volume of wastes which may be subject to Subtitle C review.
Separate sections describe wastes generated, waste management and fluid management
units, suggested waste management practices, and the Area Waste Management Plan
concept.
Berry, et al. An Assessment of Produced Water Impacts to Low-Energy, Brackish Water Systems in
Southeast Louisiana: A Project Summary in Proceeding of the First International Symposium
on Oil and Gas Exploration Waste Management Practices, September 10-13, 1990. pp. 3i-i:
The report presents summarized results of study of impacts of produced water
discharges to surface receiving waters in Louisiana. Hydraulic behavior. Radium 226
activity, biotoxicity, chemical characteristics, chemical impacts, and bioaccumuiation
of constituents in systems were examined.
Boyle, C.A. Management of Amine Process Sludges in Proceeding of the First International
Symposium on Oil and Gas Exploration Waste Management Practices, September 10-13. 1990.
pp. 577-589.
This paper discusses waste characteristics and waste management options for wastes
generated at sour gas processing plants using diethanolamme (DEA) of
monoethanolamine (MEA). Landfilling, land treatment, deep well disposal, surface
water discharge, and incineration options are compared. The authors recommend land
treatment of process sludges as the most desirable disposal option.
Braun. I.E., and M.A. Peavy. Control of Waste Well Casing Vent Gas from a Thermally Enhanced
Oil Recovery Operation in Proceeding of the First International Symposium on Oil and Gas
Exploration Waste Management Practices, September 10-13, 1990, pp. 199-210.
This paper discusses one operator's experience with casing vent gas recovery systems
used to reduce sulfur emissions and reclaim NGLs at its thermal enhanced oil
December 10. 1991 84 Preiim.nar> Dun
-------
BACKGROUND FOR NEPA REVIEWERS
recovery projects in California. The system separates NGLs and volatilized petroleum
fractions from the gas stream for recovery while scrubbers remove SO: from flare
exhausted. Stated benefits include increased production flow rate by reducing
downhoie back pressure. 99 percent hydrocarbon removal, and 95 percent sulfur
removal.
Buchler, P.M. The Attenuation of the Aquifer Contamination in an Oil Refinery Stabilization Pond in
Proceeding of die First International Symposium on Oil and Gas Exploration Waste
Management Practices, September 10-13, 1990. pp. 109-116.
This report discusses the modification of bentonite clays to increase adsorption of
polar organic molecules to the clays when used as pond liners. Results suggest that
treating clays with quaternary ammonium cations can attenuate migration of organics
by adsorption in addition to the normally expected reduction in permeability afforded
by the clay liners.
Bureau of Land Management. May 7, 1990. Planning for Fluid Mineral Resources.
U.S. Department of the Interior.
This document provides guidelines for the mandated preparation of Resource
Management Plans for Federal lands including BLM, Forest Service, and Indian
Lands. The document explicitly focuses on the inclusion of consideration of fluid
mineral resources in preparation of RMPs. Chapters are organized around the
sequence of administrative actions and decisions to be made in relation to proposed oii
and gas exploration and production operations.
Crawley, W.W., and R.T. Branch. Characterization of Treatment Zone Soil Conditions at a
Commercial Nonhazardous Oil Field Waste Land Treatment Unit in Proceeding of the First
International Symposium on Oil and Gas Exploration Waste Management Practices. Sepiemrer
10-13. 1990, pp. 147-158.
The paper presents the analytical methods and results for tests of the physical ind
hydrological properties of subsoils at a commercial oil field waste land treatment unit
Results indicate that die vertical mobility of contaminants, including chlorides, is very
low due to site specific conditions. After 5 years of treatment at the site, chlorides
had migrated to a maximum depth of 18 inches.
osium
Crist, D.R. Brine Management Practices in Ohio in Proceeding of the First International Symp
on Oil and Gas Exploration Waste Management Practices, September 10-13. 1990. pp
145.
This paper describes die State's UIC Class n well program as currently implemented
Disposal and water flooding injection well restrictions and practices are described m
addition to annular injection and road spreading disposal methods. Specific problems
associated widi annular injection are discussed.
December 10. 1991 85 Prelim.-.
-------
OIL AND GAS
Deuel, L.E., Jr. Evaluation of the Limiting Constituents Suggested for Land Disposal of Exploration
and Production Wastes in Proceeding of the First International Symposium on Oil and Gas
Exploration Waste Management Practices. September 10-13. 1990. pp. 41M30.
This paper discusses the technical basis for suggested threshold values of limiting
constituents for land application of exploration and production wastes. Thresholds are
presented as generic limits below which soil, plant, and ground water damages may
be minimized from burial, land farming, and road spreading disposal options.
Englehardt, F.R., J.P. Ray, A.M. Gillam, eds. 1989. Drilling Wastes. Elsevier Science Publishing
Co., Inc., New York, NY.
This book is a compilation of 42 papers presented at the 1988 International Drilling
Conference on Drilling Wastes, held in Calgary. Alberta. Canada. The papers relate
to on- and off-shore operations and focus on fate and effects, waste constituents.
management approaches, or some combination of these. Ranging from general to
fairly technical, the reports provide industry, government, and academic perspectives
on the generation and management of drilling wastes.
Hardisty P.E.. et al. Nature. Occurrence, and Remediation of Ground water Contamination at
Alberta Sour Gas Plants in Proceeding of the First International Symposium on Oil and Gas
Exploration Waste Management Practices. September 10-13, 1990, pp. 635-645.
This paper presents the results of a study of ground-water contaminant occurrence and
remediation at 55 sour gas plants in Alberta. Results indicated some level of
contamination at all but one of the plants, with remediation activities underway at very
few of the facilities. Most contamination incidents were linked to migration from
onsite ponds and landfills. Chlorides, dissolved organics, and free phase condensates
were the most commonly detected pollutants.
Kennedy AJ et al. Oil Waste Road Application Practices at the Esso Resources Canada LTD .
Cold Lake Production Project in Proceeding of the First International Symposium on Oil and
Gas Exploration Waste Management Practices. September 10-13, 1990, pp. 689-701.
This paper presents the case history of the use of separator sludge solids, tank
bottoms, and residual oil field solid wastes for road surfacing materials.
Macyk T M F I Nikiforuk. and O.K. Weiss. Drilling Waste Landspreading Field Trial in the
Cold Lake Heavy Oil Region, Alberta, Canada M Proceeding of the First International
Symposium on Oil and Gas Exploration Waste Management Practices, September 10-13. 1990.
pp. 267-279.
This naper discusses the results of field tests designed to measure the impacts of
variousloading rates for land application of freshwater gel, NaCI, and KC1 drilling
wastes EC, pH, plant yield, and various physical and chemical soil properties were
measured. As loading rates were varied according to rate Cl/umt area, no
._ .--, SA Prelimmdrv
December 10, 1991 so
-------
BACKGROUND FOR NEPA REVIEWERS
information of hydrocarbons or other constituents of the wastes was presented.
Results indicate impacts ranging from minimal to severe for lowest to highest loading
rates.
McFarland, Mark L.. D.N. Ueckert. and S. Hartman. Evaluation of Selective Placement Burial for
Disposal of Drilling Fluids in West Texas." in Proceeding of the First International
Symposium on Oil and Gas Exploration Waste Management Practices. September 10-13. 1990.
pp. 455-*66.
The paper discusses results of field trials of pit waste burial varying depths beneath
surface soil. Mobility of salts and metals as well as success of revegetation is
discussed.
Miller. H.T.. and E.D. Bruce. Pathway Exposure Analysis and the Identification of Waste Disposal
Options for Petroleum Production Wastes Containing Naturally Occurring Radioactive
Materials in Proceeding of the First International Symposium on Oil and Gas Exploration
Waste Management Practices. September 10-13, 1990, pp. 731-744.
This paper discusses the occurrence of NORM in formation fluids and gas. the
distribution of NORM in surface processing equipment (e.g.. pipes, tank bottoms.
soils) and various options for disposal of contaminated materials.
National Research Council. 1989. Land Use Planning and Oil and Gas Leasing on Onshore Federal
Lands. National Academy Press. Washington, D.C.
This document presents the results of study performed by the Committee on Onshore
Oil and Gas Leasing concerning oil and gas leasing on Federal lands. The report
specifically addresses existing BLM and Forest Service practices for granting leases
and the extent to which such practices address environmental values vis-a-vis
competing resource interests. Regulations affecting the agencies and operators are
discussed. Further, wildlife and other environmental considerations are addressed.
Nefl, J.M. No date. Bioaccumulation and Biomagnification of Chemicals from Oil Well Drilling and
Production Wastes in Marine Food Webs: A Review.
This paper presents a review of general literature related to the bioaccumulation and
biomagnifkation of exploration and production waste constituents in marine lite
Descriptions of used drilling fluids and produced waters are provided, including
typical constituent concentration ranges. Physical and biochemical pathways of
exposure and accumulation are examined.
Texas Department of Agriculture, Office of Natural Resources. No date. Agricultural Land and
Water Contamination from Injection Wells. Disposal Pits, and Abandoned Wells Used m Oil
and Gas Production.
December 10. 1991 87 Prelimmar>
-------
OIL AND GAS
This short paper discusses the results of a survey of pending and resolved complaint
reports on file with the Department of Agriculture and the Texas Railroad
Commission. The complaints allege damages from oil and gas wells. Types of
damages known or believed to have occurred are described.
U.S. Environmental Protection Agency. September 1990. Reducing Risk: Setting Priorities and
Strategies for Environmental Protection.
Reducing Risk is a report from the Science Advisory Board (SAB) to the
administrator of EPA concerning its recommendations for the inclusion of risk based
considerations in establishing EPA strategies and priorities. The SAB identifies the
potential benefit of including total risk and non-human-health related risk
considerations into the process of determining how best to allocate resources. In
particular, SAB recommends a policy of maximum risk reduction and the inclusion of
ecological risk to be considered on par with direct human health risk.
U.S. Environmental Protection Agency. September 10-13, 1990. Proceeding of the First
International Symposium on Oil and Gas Exploration and Production Waste Management
Practices. New Orleans. LA, USA.
These proceedings contain 91 papers from government, industry, and academic
sources on topics ranging from waste stream characterization to existing and novel
management and disposal practices as well as contaminant remediation and waste
minimization.
Warner, D.. and C. McConnell. Evaluation of the Groundwater Contamination Potential of
Abandoned Weils by Numerical Modelling," in Proceeding of the First International
Symposium on Oil and Gas Exploration Waste Management Practices, September 10-13. 1990.
pp. 477^83.
This paper discusses results of numerical modelling efforts to estimate the potential
for migration of pollutants via abandoned wells to subsurface waters. Results indicate
the potential may range from probable to zero depending on well condition and
geological factors.
Welker. A.J. 1985. The Oil and Gas Book.
The Oil and Gas Book is a thorough overview of oil and gas exploration and
production written for the layman. The book describes E&P from leasing through
spudding, primary recovery to thermal EDR, and abandonment. Little attention is
paid to waste and waste management.
Zimmerman, P.K., and J.D. Robert. Landfarming Oil Based Drill Cuttings in Proceeding of the
First International Symposium on Oil and Gas Exploration Waste Management Practices.
September 10-13, 1990, pp. 565-576.
December 10, 1991 88 Prelimiwrv Dr.n
-------
BACKGROUND FOR SEPA REVIEWERS
This paper discusses the methods and results of landfarming oil based drill curtmgs at
32 well sites in Alberta, Canada. After 3 years, constituent analysis revealed
adequate decreases in oil, salt, and electrical conductivity levels to expect each site to
meet or exceed government revegetation standards.
December 10. 1991 89 Preliminary
-------
TABLE 1 MAXIMUM CONTAMINANT LEVELS AND AMBIENT WATER QUALITY CRITERIA (11/6/91)
COMPOUND
PRIORITY POLLUTANTS
METALS
* *ilj»i-i _. u
mwinany
At (wife (c|
BwyWum (c)
Cadmium (H|
CtnamkMi(UI)(H)
Chiomlum (VI)
CappM(H)
Lead (H)
MM awy
Nlck*l (H)
Svlwilum
Wv«(H)
Thallium
2bM>(H)
Cyanfcto (ha*)
AatMBUM
2.3,7.0-TCDO-OloK»n(c|
VOLATILE COMPOUNDS
Aofotwn
Aciy)onilflto(c)
B«ni»n« (c)
UnMnolixm (MM. c)
FRESHWATER
Acula Chionlc
CiHatla CiHMta
|ug
-------
1ABIE I MAXIMUM CONfAMINANI IKVtl SAND AMOIEN1 WAIER QUAIIIY C' ' I MIA (11/6/91)
COMPOUND
Cuban T«li*chlarid« (c)
Chlofotwucn*
CMMuMbiamomclhaiM (HM. c)
ChtoKMthtn*
I-Chtofraf>|4w>« (Clt.c)
l.3-D(cW«opiopyl«n«(Ti«ni.c).
ClhyttMitlcn*
M*lhyt Biomld* (HM. c)
Methyl Clilufld* (HM, c)
M«lhy1*n* Chl«»ld» (c)
1 1 2.2 - TMlMlllOIMlhMM (C|
I»ti«chl«o«»M«i.» (c)
TaluMi*
1 . 1 . 1 - Tdchl«o«lh«ii«
1 . 1 ,2-Ti IchlafMlhan* (c)
TiichloKMrthyUnf (c)
Vinyl Chtokto (c)
ACIDS
2-Chl«op»i«nol
24 Dlchll»«nal
2 Methyl -4 0 C)lnrtiof>»i«fi<>«
7 4 OifiU'l>lllM><><
4 N.I..4..I.....4
FRESHWATER
Aculf Chionlc
ClHwl* Clll«ll«
(ufl/ll ("a")
38.200
_
_
26.000 * 1.240 *
_
_
16.000 * 20.000 *
11.600 '
23.000 6.700 '
_
_
32.000 '
_ _
_-
2400
6.260 ' 640 '
17.600
.
9.400 '
46.000 ' 21.000 '
4.3M ' 2000 '
2.020 ' 305 '
8.120 '
, ~~
230 ' 150 '
230 160 '
SAI IWAtER
AcuU Chnxilc
CilUiU CilUil*
(ug/l) (ugl)
60.000
__
_ _
_ _
_ _
113.000 '
224.000 '
10.300 ' 3.040 '
_
_ _
430 '
_
-
_ _
0.020
10.200 ' 460 '
6.300 6,000
«_
31.200 '
_
2.000
_
__
4150 '
4.160 '
HUMAN HE IAI1H
(10 -4) ilik f«cl
-------
TABLE 1 MAXIMUM CONTAMINANT LEVELS AND AMBIENT WATER QUALITY CRITERIA (11/6/91)
COMPOUND
PB*ilAWrtuVkt f*ntk*Mifrf InMft
Phenol
>.4.*-TrtcMonie4tenol (c)
BABE NEUTRAL COMPOUNDS
Acenephlhylene (PAH. c)
Anrhrftc*ne(PAH,e)
BentMtnetc)
B*nro(e)Anthteoene (PAH. e)
B«nio(e|Pyrene (PAH. c|
3.4-Beniotuoiwlhene (PAH. c)
B«nro(ghi}Perylene(PAH. c)
B*nio(k)Fluo(«nlhene
Ble|2-Chlaro«lhoKr)Methan«
_ _ _. . *ji._flf iA J m
BM(2-Chlorolea|>ropyl)Elher
Ble)2-Elhy*>exyi)PhtrieleU (c)
4-BromopnenylPhenyl Ether
Bulf*>ent|l PMieJeto
2 -Chloronephinel«ne
4-CMarophenyl Pnenyi Ether
ChtyMne(PAH.e)
(Mt>enzof.«.h|An«wecene (PAH c)
1 .2-Otchlotobeniene
1.3-OtehiorabenMne
1.4-Olchloiobeniene
3.3'-OlcMoroi>eruidine (c)
DMhyl Phlhelele
Dimethyl Phlhelete
Ol-n Butyl Ptithelele
7 4 Oinllii*
-------
TAMIL 1 MAXIMUM CONTAMINANT U Vtl S AND AMOItNf WAM M QUAt IIY CHIfEHIA (I I/G/9I)
COMPOUND
Di-n-Octyt PMhctoM
1 .2-DlplMnytttydf uln« (c|
FlumwttfMM
FluM«n«|PAH, c)
H*x*chk*ab«iu*n« (e)
H«MctiloralNil«Nwi* (c)
1 UimirilotocydoptnlMllitu
.. aujttmnfle |
tmtonott 2 S-edr»M"«l''*M.«»
iMftMMOO*
NapMhatan*
NHrobwtNn*
N-Nllioaodl-n-PiopylMnlfM (c)
N - NHio*odi|iti«nyl«mln« (c)
PtMitanlhian* (PAH. c)
Pyi»n« (PAH. c)
1 .2.4- Tiichloiob»n*ana
OTHER
AMiln (a)
-BHC |e|
b-BHC (c)
O-BHC(c)
d-BHC(c)
Chkxdcn* (c)
4-4 -DOT (c)
4.4 -DDE (c)
44-DOO(c|
Oicldiln (c)
EndowlUn
l> FiidcuulUn
liiiluiulUii SulUU
FRESHWATER
AcuU Chionle
CitUlla CiMMla
(ug/1) (UB/|)
_ *«»
270 '
9660
_
60 63 '
7 * M *
jjp 6<0 *
j^, _
117.000 '
2.900 620 '
27.000 *
_ __
_ _
*" """"
3
100 *
100
2 * OO»
100 '
24 0 0043 T
1 1 0001 W
1,050 '
25 00016 T
0 22 0 056
022 0 056
'
SALTWATER
AcuU Chi imlc
ClIUll* CilUila
(ugfl( (ug/l)
40 ' 16 '
_ _
_ _
32 '
7
40 '
12.600 '
t.sao
6.660 '
_
_ _
1 I
034 '
034 '
0 16 '
034 *
0 00 0 OO4 T
013 0001 W
14 '
071 0002 T
0 034 0 0017
0034 000t7
_
HUM AN HEALTH
(10 -6 lick tachM to ctrclnogcn*)
Consumption ol
WaUi ft Oiginltmt
Oiganlim* Only
(u«/n (ug/q
~~ ~~
0041 064
42 M
00021 0031
000072 * 000074 "
046 " 407 "
206
1 M 174
00026 * 00311 *
6,200 620.000
l»«00
00014 16 "
'0006 * 666 '
4M " 162 "
00026 00311
00021 00311
M6 15.366
0000074 " 0000076 "
00036 00131
00137 0046
00116 OOMS
000040 ' 00004* '
000024 " 000024 "
" ~"~
0000071 " 0000076 *'
74 156
74 ISO
_....r~ -
BK)
CONCENTRATION
FACTOR
(3H LlpldJ
WalgMwl Avg
(Mg|
246
1160
30
000
276
434
66
M
4M
106
2M
0026
0 16
IM
M
30
14
4670
ISO
130
130
IM
14100
53800
"
~
4070
270
270
EPAFISH
TISSUE
noNCENTfunof
(rnoAg)
0013
62 1
0000633
0.00643
6 136
764
077
0000639
211
636
0.600211
060164
22
0000633
0000033
2164
0000636
00017
0006
000*1
-
000*3
0.0116
.
000067
054
054
~.
DRINKING
WATER
Maximum
Conlamlnaiil
l*v^»(UCli|
(mg/l)
0001
005
_
-
0000
~
0007*
-------
TABLE 1: MAXIMUM CONTAMINANT LEVELS AND AMBIENT WATER QUALITY CRITERIA (tt/6/91)
COMPOUND
En* In
cnotHI AHMnyoO
PCfl-1242(PCB.e>
PC8-12«4(PCS.et
PCB-1221 (PCS. c)
pcB-itat(PCU.o)
PCB-12M(PCB.e)
PCS- 1 MO (PC*), c)
PCB-IOIO(PCB.e)
ToiaptMn* (c)
NON-PRIORITY POLLUTANT 8
Ammonia
ChkNkto
Chtarin* (THC)
Aluminum (pH 0 S-* 0|
Barium
Baton
ban
OteMwodlftMMOfliMhafM (HM.c)
PnOCfknOfUQ (MtMtt^OtA!)
Sulld* «S2-. HS-)
ChlotpytlfcM
0«m«4on
Qulhlon
M.l, ,!,,
M«lhu>y
Acul*
CfMwk
U
20
2«
20
I*
2*
20
20
0073
OM
1*
760
oou
FRESHWATER
Clwonlc
00023 T
a aaaa T
0014 W
14 W
14 W
14 W
14 W
14 W
0014 W
0.0001 T
023
11
7
1000
2
0041
0 1
001
0 1
003
Acul*
CfNafla
0037
n Am
A AM
to
10
to
10
10
10
10
o.ott
13
:
0011
8ALIWATER
Chiont
Cfllwli
00023
n HUM
03
03
003
003
003
003
003
00002
75
0 1
2
00084
0 1
001
001
003
TEN
Chionlc
CfHMla
(o«/lt
90023 T
DOOM T
» 0030 ' T
009 W
001 W
003 W
003 V)
003 W
003 W
003 W
l.OOOt T
75
_
_
0 1
2
. JMhCA
t OOM
0 1
001
001
003
HUMAN HEALTH
00 -« iM helm In caiclnog«ni|
Conwmpllon ol
Walw ft Oiganlmt
OtganJami Only
(u04) (U0/I)
1 -,
00002S OOOOM
OOOOtOt * 1000*14 *
0000070 ** 000007* "
000007* ' 000007* "
000007* ** 000007* "
0.00*07* '* 000007* *
000007* * 000007* "
000007* * 000007* "
000007* " 0000070 "
00071 " 0.00073 **
_ _
_ _
1000 MCL
300 MCL
M MCL 100 M«iln«
0.000 |M 00777
8 «7 470 1
07 4701
10000 * MCL
_ _
_
_
100 MCL
BIO
CONCENTRATION
FACTOR
(IHUpM)
Weighted Avg
(M>8>
3070
112OO
HMO
31*00
1NO
31200
31 MO
31200
31200
31200
13100
_
0*3
37S
379
EPA FISH
TISSUE
CONCENTRATIOfi
fmgAg)
323
00024
00024
00014
00014
00014
00014
00014
0014
00014
00000
__
000004*
1.77
177
ORiNKma
WATER
Maximum
Contemlnanl
L«v*l*(MCL4
(ma*
00004*
oooor
(ooosr
|ooȤ)-
i ooosr
IOOMI*
|0006|-
i ooo«r
IOOOBC
0003*
280*"
OS'"
2'
_-
10'
--
-
-
-
004-
-------
COMPOUND
Mliax
PMalMon
2.4 dtehto ophanwy Matte acid
2-P.M liteMwophano«y)piaptonlc acid
DlMotvad Oaaat
Dlaaotvatl BoMa (chlotUaa. auHUaa)
Ollanddraaaa
PH
Sollda (TiMbMUy)
FRESHWATER
Acula Ctuonlc
CtNaila CiHaila
(U0A) (ug/l)
0001
000* * 0013
1 10H aalutatlon
_
OOltowLCM*
9*-4 '
00* camp pi
SALTWAIER
Acula Chiunlc
ClHaila CiMtili
(ug/l) (U9/I|
0001
_ _
_ _
MOM Mluitli
~ _
0 1 low LC60
tfr-IS
OOHcomp
HUMAN HEALTH
(10 -0 ilik lacloi tui caiclnogaiti)
CmiMimpllan ol
Walai & Oio«nl«m«
OigoilHTi* Only
("0/11 (u»fl»
_
_-
100 MCL
tO MCL
fiOO.OOO MCL
_ _
BK)
CONCENTRATION
FACTOR
(3H llpld)
WclghUd AVQ
(l/Vg)
>_
~
EPA 1 ISH
TISSUE
CONCENTRATIOn
(mg(Vg)
OHINKINQ
WATER
Maximum
Cmilamlncnl
L»v*U|MCli|
|ingA|
-
--
-
_
Final MCL lo IMCOIM Itocthw July IBM
PiopoMdMCL
S*cond*iyMCl
monHof wuic* WMM, icptac* toed Mfvtc* Nn«a, «nd umtortak* pubMc ducallon piogiam
( ) Tola! chiomlum
|| Total PCBt
m mclal
c caicln>ig*n. 10-0 rlak (aval
O b*a»d on »ganolapllc data
MCL SOWAwalua
W Final Raridua Valua baaad on wlldllla laadtng Mudy
T baaad on maikalaMHly ol Hah
X not lacommandad II compound known lo ba piaaanl In Mmpla
m noliaporlad
hima high laaohillon mata apactioacopy
HM haJomatnana human haaHh ciNaila apply lo total halomaihanaa
PAH polynuclaaf aiomallc hydiocaibon. human haaMi ciMaila apply to total PAHi
V vdallla compound*
a aekMc eompounda
EC alactiofi captuia datacloi
Fl Rama kml/allon dalactof
PCB p<4ychlu(lnalad blphanyl cillaiia apply lo lotal PCBi
(Hi: m«a*ui*!( - ba*ad on conwimpllon ol watar
------- |