r/EPA
United States
Environmental Protection
Agency
Office of Solid Waste
and Emergency Response
Washington, DC 20400
EPA/530-SW-88-003
December 1987
Solid Waste
Report to Congress
Management of Wastes from the
Exploration, Development, and
Production of Crude Oil, Natural Gas,
and Geothermal Energy
Executive Summaries
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REPORT TO CONGRESS
MANAGEMENT OF WASTES FROM THE
EXPLORATION, DEVELOPMENT, AND PRODUCTION
OF CRUDE OIL, NATURAL GAS, AND GEOTHERMAL ENERGY
EXECUTIVE SUMMARIES
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Office of Solid Waste and Emergency Response
Washington, D.C. 20460
U.S. Environmental Protection Agency
December 1987 Re8ion 5- L'brarv (PL-12J)
77 West Jackson Boulevard, 12th Floor
Chicago, IL 60604-3590
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This Report to Congress is dedicated to the memory of Susan L. de Nagy,
United States Environmental Protection Agency, and John F. Catlin, United
States Department of the Interior.
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EXECUTIVE SUMMARY
MANAGEMENT OF WASTES FROM THE OIL AND GAS INDUSTRY
Under Section 3001(b)(2)(A) of the 1980 Amendments to the Resource
Conservation and Recovery Act (RCRA), Congress temporarily exempted
several types of solid wastes from regulation as hazardous wastes,
pending further study by the Environmental Protection Agency (EPA).
Among the categories of wastes exempted were "drilling fluids, produced
waters, and other wastes associated with the exploration, development, or
production of crude oil or natural gas." Section 8002(m) of the 1980
Amendments requires the Administrator to study these wastes and submit a
report to Congress evaluating the status of their management. This
report must include appropriate findings and recommendations for Federal
and non-Federal actions concerning the effects of such wastes on human
health and the environment.
RCRA defines a specific sequence of events that would precede the
promulgation of any new Federal regulations (including use of Subtitle C):
1. Study of issues and submission of Report to Congress with
appropriate recommendations;
2. Formal public comment period on Report to Congress;
3. A formal regulatory determination by EPA; and
4. If regulations are to be developed:
a. Proposal of regulations;
b. Formal public comment period on proposed regulations; and
c. Revision of proposal.
Should regulations be developed, the statute provides that they shall
take effect only when authorized by act of Congress.
The current report is the first step in this sequence. Recognizing
that this class of wastes is temporarily exempt because of the complexity
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of its impacts and the problems of its management, EPA has sought to be
as comprehensive as possible in its discussion of issues for Congress.
Further steps noted above will progressively refine the issues of
concern. Congress retains ultimate control over the scope and direction
of any additional Federal actions that might be taken to improve the
management of these wastes.
SPECIAL WASTES
Oil and gas wastes fall within a general category of wastes that RCRA
regards as "special" because of their unusually high volume, which could
make the application of some RCRA regulatory requirements technically
infeasible or impractical, and because of their relatively low level of
apparent environmental hazard (based on data available in 1980). The
issues raised by all special wastes are complex, requiring the balancing
of environmental, logistical, and economic considerations.
Congress' intent in temporarily exempting these wastes from
regulation under RCRA Subtitle C was to provide an opportunity for
developing an appropriate strategy for their management, should new or
additional measures prove to be needed.
PURPOSE OF THIS STUDY
This study is intended to respond as fully as possible to each of the
study factors described by Congress in the various paragraphs of Section
8002(m). The Agency has designed this report to respond specifically to
each study factor within separate chapters or sections of chapters.
Although every study factor has been weighed in arriving at the
conclusions and recommendations of this report, no factor has had a
determining influence on the study's conclusions and recommendations.
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Identifying Exempt Wastes: Chapter II, "Overview of the Industry,"
interprets the scope of the exemption as defined in the statute.
Specifying the Sources and Volumes of Wastes: Estimates of volumes
of wastes are also presented in Chapter II.
Characterizing Wastes: EPA conducted a national screening type of
sampling program of facilities to compile relevant data on waste
characteristics. Simultaneously, the American Petroleum Institute
(API) sampled the same sites except for central treatment locations
and central pit locations, and wastes covered by the EPA survey.
Chapter II of this report summarizes the results of these programs.
Describing Current Disposal Practices: The Agency has described the
principal and common methods of managing field-generated wastes and
discusses these practices in general qualitative terms in relation to
their effectiveness in protecting human health and the environment.
This discussion is presented in Chapter III, "Current and Alternative
Practices."
Documenting Evidence of Damage to Human Health and the Environment
Caused by Oil and Gas Wastes: Chapter IV, "Damage Cases," summarizes
EPA's effort to collect documented evidence of danger to human health
or damage to the environment or valuable resources. This collection
of case studies is not intended to estimate the frequency or extent
of damages associated with typical operations, nor to judge the
effectiveness of current State programs in preventing these damages.
It is intended only to define the nature and range of damages that
are known to have occurred.
Assessing Potential Danger to Human Health or the Environment from
the Wastes: Qualitative and quantitative risk modeling is presented
in Chapter V, "Risk Modeling."
Reviewing the Adequacy of Government and Private Measures to Prevent
and/or Mitigate Adverse Effects: This review is based on both a
qualitative assessment of all the materials gathered during the
course of assembling the report and a review of State and other
Federal regulatory programs presented in Chapter VII, "Current
Regulatory Programs." Chapter VII reviews the elements of programs
and highlights possible inconsistencies, lack of specificity,
potential problems in implementation, or gaps in coverage.
Interpretation of the adequacy of these control efforts is presented
in Chapter VIII, "Conclusions."
Identifying Alternatives to Current Waste Management Practices:
EPA's discussion in response to this study factor is incorporated in
Chapter III, "Current and Alternative Practices." This chapter
merges the concepts of current and alternative waste management
practices.
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Estimating the Costs of Alternative Practices: The first several
sections of Chapter VI, "Economic Impacts of Alternative Waste
Management Practices," present the Agency's analysis of this study
factor.
Estimating the Economic Impacts on Industry of Alternative
Practices: The final two sections of Chapter VI present the Agency's
analysis of the potential economic impacts of nationwide imposition
of the hypothetical control scenarios analyzed at the project level.
ISSUES SPECIFIC TO THE OIL AND GAS INDUSTRY
To bring this study into perspective, it is important to note a
number of issues specific to the oil and gas industry that affect how
this study was conducted and how Congress may interpret its results.
First, the oil and gas industry is extremely large and varied. In
1985, there were approximately 842,000 producing oil and gas wells in the
U.S., distributed throughout 38 States. They produced 8.4 million
barrels of oil, 1.6 million barrels of natural gas liquids, and 44
billion cubic feet of natural gas daily. The petroleum exploration,
development, and production industries employed approximately 421,000
people in 1985.
All aspects of exploration, development, and production vary markedly
from region to region and from State to State. Well depths range from as
little as 30 feet to over 30,000 feet. Pennsylvania has been producing
oil for 128 years; Alaska for only 15 years. Maryland has approximately
14 producing wells; Texas has over 269,000 and completed another 25,721
in 1985 alone. Production from a single well can vary from a high of
about 11,500 barrels per day (the 1985 average for wells on the Alaska
North Slope) to less than 10 barrels per day in many thousands of
"stripper" wells. (Overall, 70 percent of U.S. oil wells are strippers,
which account for roughly 14 percent of total U.S. production.)
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These variations make it extremely difficult to fully represent the
scope and breadth of the industry in detail at the national level. EPA
has consulted extensively with State regulatory agencies, other Federal
agencies, and industry in assembling data and materials on which to base
this report. The generalizations that it must necessarily draw in order
to respond to Congress' directives are, however, the Agency's own.
Second, although wastes from the oil and gas industry have never been
subject to RCRA regulation as hazardous wastes, they have long been
regulated at the State level and are also regulated in part under the
Federal Clean Water Act and the Federal Safe Drinking Water Act. The
questions posed by Section 8002(m) must therefore be interpreted in
relation to a complex and long-established background of existing
requirements. Furthermore, State programs controlling the management of
high-volume wastes have improved significantly over the past decade and,
especially over the last 2 or 3 years, have reflected the national trend
of increased concern about environmental protection. However, judging
the environmental success of these recent improvements is difficult. EPA
recognizes the difficulty of analyzing changing State requirements in
relation to the regional variations of the industry and therefore wishes
to pursue this issue further before arriving at a final regulatory
determination on these wastes.
DEFINITION OF EXEMPT WASTES
The following discussion presents EPA's tentative working definition
of the scope of the exemption.
Scope of the Exemption
The current statutory exemption originated in EPA's proposed
hazardous waste regulations of December 8, 1978 (43 FR 58946). Proposed
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40 CFR 250.46 contained standards for "special wastes," which reduced
requirements for several types of wastes that are produced in large
volume and that EPA believed may be lower in toxicity than other wastes
regulated as hazardous wastes under RCRA. One of these categories of
special wastes was "gas and oil drilling muds and oil production brines."
In the RCRA amendments of 1980, Congress exempted most of these
special wastes from the hazardous waste requirements of Subtitle C,
pending further study by EPA. The oil and gas exemption, Section
3001(b)(2)(A), is directed at "drilling fluids, produced waters, and
other wastes associated with the exploration, development, or production
of crude oil or natural gas." EPA defined the exemption in its
regulations at 40 CFR 261.4(6) to include these wastes. The legislative
history does not elaborate on the definition of drilling fluids or
produced waters, but it does discuss "other wastes" as follows:
The term "other wastes associated" is specifically included to
designate waste materials intrinsically derived from primary fieTd
operations associated with the exploration, development, or
production of crude oil, natural gas or geothermal energy. It would
cover such substances as: hydrocarbon bearing soil in and around
related facilities; drill cuttings; and materials (such as
hydrocarbons, water, sand, and emulsion) produced from a well in
conjunction with crude oil, natural gas or geothermal energy; and the
accumulated material (such as hydrocarbons, water, sand and emulsion)
from production separators, fluid treating vessels, storage vessels,
and production impoundments.
The phrase "intrinsically derived from the primary field operations"
is intended to differentiate exploration, development, and production
operations from transportation (from the point of custody transfer or
of production separation and dehydration) and manufacturing
operations.
In order to arrive at a clear working definition of the scope of the
exemption under Section 8002(m), EPA has used these statements in
conjunction with the definitions and guidelines included in statutory
language of RCRA as a basis for determining which oil and gas wastes
should be included in the present study.
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The test of whether a particular waste qualifies under the exemption
can be made in relation to the following three separate criteria. No one
criterion can be used as a standard when defining specific waste streams
that are exempt. These criteria are as follows:
1. Exempt wastes must be associated with measures (1) to locate oil
or gas deposits, (2) to remove oil or natural gas from the ground,
or (3) to remove impurities from such substances, provided that
the purification process is an integral part of primary field
operations.1
2. Only waste streams intrinsic to the exploration for, or the
development and production of, crude oil or natural gas are
subject to exemption. Waste streams generated at oil or gas
facilities that are not uniquely associated with exploration,
development, or production activities are not exempt. (Examples
would include spent solvents from equipment cleanup, or air
emissions from diesel engines used to operate drilling rigs.)
Those substances that are extracted from the ground or injected
into the ground to facilitate the drilling, operation, or
maintenance of a well or to enhance the recovery of oil and gas
are considered to. be uniquely associated with exploration,
development, or production activities. Additionally, the
injection into the wellbore of materials that keep the pipes from
freezing or serve as solvents to prevent paraffin accumulation is
intrinsically associated with exploration, development, or
production activities. With regard to injection for enhanced
recovery, the injected materials must function primarily to
enhance recovery of oil and gas and must be recognized by the
Agency as being appropriate for enhanced recovery. An example
would be produced water. In this context, "function primarily"
means that the main reason for injecting the materials is to
enhance recovery of oil and gas rather than to serve as a means
for disposing of the injected materials.
3. Drilling fluids, produced waters, and other wastes intrinsically
derived from primary field operations associated with the
exploration, development, or production of crude oil, natural gas
or geothermal energy are subject to exemption. Primary field
operations encompass production-related activities but not
transportation or manufacturing activities. With respect to oil
production, primary field operations encompass those activities
usually occurring at or near the wellhead, but prior to the
Thus, wastes associated with such processes as oil refining and petrochemical-related
manufacturing are not exempt because those processes are not an integral part of primary field
operations.
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transfer of oil from an individual field facility or a centrally
located facility to a carrier (i.e., pipeline or trucking concern)
for transport to a refinery or to a refiner.
With respect to natural gas production, primary field operations
are those activities occurring at or near the wellhead or at the
gas plant but prior to the point at which the gas is transferred
from an individual field facility, a centrally located facility,
or a gas plant to a carrier for transport to market. Primary
field operations encompass the primary, secondary, and tertiary
production of oil or gas.
Wastes generated by the transportation process itself are not
exempt because they are not intrinsically associated with primary
field operations. An example would be pigging waste from pipeline
pumping stations. Transportation (for the oil and gas industry)
may be for short or long distances.
Wastes associated with manufacturing are not exempt because they
are not associated with exploration, development, or production
and hence are not intrinsically .associated with primary field
operations. Manufacturing (for the oil and gas industry) is
defined as any activity occurring within a refinery or other
manufacturing facility the purpose of which is to render the
product commercially saleable.
Using these definitions, Table 1 presents definitions of exempt
wastes as defined by EPA for the purposes of this study. Note that this
is only a partial list. Although it includes all the major waste streams
that EPA has considered in the preparation of this report, others may
exist. In that case, the definitions listed above would be applied to
determine the status of these wastes under Section 8002(m).
CHARACTERIZATION OF WASTES
Organic constituents, present at levels of potential concern in oil
and gas wastes, are shown on Table 2. These include the hydrocarbons
benzene and phenanthrene. Inorganic constituents of concern include
lead, arsenic, barium, antimony, and fluoride.
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Table 1
•ill cuttings
•illing fluids
.01 completion, treatment,
id stimulation fluids
icking fluids
ind, hydrocarbon solids,
id other deposits removed
'om production wells
ipe scale, hydrocarbon
)lids, hydrates, and other
jposits removed from
iping and equipment
/drocarbon-bearing soil
igging wastes from
athering 1ines
astes from subsurface
as storage and retrieval
EXEMPT WASTES
Basic sediment and water
and other tank bottoms
from storage facilities
and separators
Produced water
Constituents removed from
produced water
before it is injected or
otherwise disposed of
Accumulated materials (such
as hydrocarbons, solids,
sand, and emulsion) from
production separators,
fluid-treating vessels,
and production impoundments
that are not mixed with
separation or treatment
media
Drilling muds from offshore
operations
Appropriate fluids injected
downhole for secondary and
tertiary recovery operations
Liquid hydrocarbons removed
from the production stream
but not from oil refining
Gases removed from the
production stream, such as
hydrogen sulfide, carbon
dioxide, and volatilized
hydrocarbons
Materials ejected from a
production well during well
blowdown
Waste crude oil from
primary field operations
Light organics volatilized
from recovered hydrocarbons
or from solvents or other
chemicals used for cleaning,
fracturing, or well completi
aste lubricants, hydraulic
luids, motor oil, and
aint
aste solvents from clean-
p operations
ff-specification and
nused materials intended
or disposal
ncinerator ash
igging wastes from
ransportation pipelines
NONEXEMPT WASTES
Sanitary wastes, trash, and
gray water
Gases, such as SOx, NOx,
and particulates from gas
turbines or other machinery
Drums - (filled, partially
filled, or cleaned) whose
contents are not intended
for use
Waste iron sponge, glycol, a
other separation media
Filters
Spent catalysts
Wastes from truck- and drum-
cleaning operations
Waste solvents from equipmen
maintenance
Spills from pipelines or
other transport methods
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Chemical
Constituents
Primary concern
Benzene
Phenanthrene
Lead
Barium
Secondary concern
Arsenic
Fluoride
Antimony
Production
Midpoint
L*
Tank bottom
S# S+
s#
s
Endpolnt
L L#«
L L#-
L
L
L-
Central treatment
Influent
S#
s#
s
Tank
S#
s#
s#
Effluent
L S
S#
S*
S
s
Central pit
Central pit
S0
S#
s#
s#
s
s
Drilling
Drilling mud
S
S*
Tank bottoms
5#
s#
L*
L
Pit
s s.
L# L« S# S#-
L# L#« S# S#-
S S-
L S
Legend:
L: Liquid sample > 100 x health-based number
S: Sludge sample > 100 x health-based number
#: Denotes > 1,000 x health-based number
L,S: EPA samples
L',S«: API samples
+: TCLP extraction
— All values determined from direct samples except as denoted by"+"
Table 2 Constituents of Concern Found In Waste Streams Sampled by EPA and API
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WASTE VOLUME ESTIMATION METHODOLOGY AND ESTIMATED VOLUMES
Information concerning volumes of wastes from oil and gas
exploration, development, and production operations is not routinely
collected nationwide, making it necessary to develop a means for
estimating these volumes by indirect methods in order to comply with the
Section 8002(m) requirement to present such estimates to Congress.
After careful review, estimates of waste volumes compiled by API were
used in the Quantitative Analyses in this report. API estimates that 361
million barrels of drilling waste were generated from drilling 69,734
wells, for an average of 5,183 barrels of waste per well in 1985 and that
20.9 billion barrels of produced water were generated in 1985.
CURRENT AND ALTERNATIVE WASTE MANAGEMENT PRACTICES
It is convenient to divide oil and gas wastes into two broad
categories. The first category includes drilling muds, wellbore
cuttings, and chemical additives related to the drilling and well
completion process; the second includes all wastes associated with oil
and gas production, primarily produced water.
Section 8002 (m) requires EPA to consider both current and
alternative technologies in carrying out the present study. Sharp
distinctions are difficult to make because of the wide variation in
practices among States and among different types of operations. Waste
management technology in the oil and gas industry is fairly simple. For
the major high-volume streams, EPA has found no newly invented
technologies in the research or development stage that offer promise for
wide application in the near term. Virtually every waste management
practice that exists can be considered "current" in one specific
situation or another.
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Of the waste management methods in common use today, some pose the
potential for adverse environmental impact if improperly implemented.
Reserve Pits
Reserve pits are an integral part of the drilling process. Usually
one reserve pit is constructed per drill site. Where pits are unlined
and constructed above unconfined ground-water aquifers, the potential
exists for ground-water degradation because of leaching of reserve pit
constituents into ground water.
Annular Disposal of Produced Waters
Although it is not a very widespread practice, some produced water is
.disposed of through the use of annular injection into producing wells.
Using this method, produced water is injected through the annular space
between the production casing and the production tubing. This method has
the potential to adversely affect underground sources of drinking water
(USDWs) because of the vulnerability of the single protective string of
casing. However, it is usually restricted to low-volume wastes injected
at little or no pressure. Testing of annular disposal wells is involved
and expensive.
Disposal of Produced Water in Injection Wells
Injection wells used for the disposal of produced water have the
potential to degrade fresh ground water in the vicinity if they are
inadequately designed, .constructed, or operated. Highly mobile chloride
ions can migrate into freshwater aquifers through corrosion holes in
injection tubing, casing, and cement. The Federal Underground Injection
Control (UIC) program requires mechanical integrity testing of all Class
II injection wells every 5 years. All States meet this requirement,
although some States have requirements for more frequent testing.
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Many States have primacy for the UIC program. Both the criteria used
for passing or failing an integrity test for a Class II well and the
testing procedure itself can vary. There is considerable variation in
the actual construction of Class II wells in operation nationwide, both
because many wells in operation today were constructed prior to the
enactment of current programs and because current State programs vary
significantly. State requirements for new injection wells can be quite
extensive. However, State requirements for construction of injection
wells prior to the enactment of the UIC program have evolved over time,
and construction ranges from injection wells in which all ground-water
zones are fully protected with casing and cementing to shallow injection
wells with one casing string and little or no cement.
Disposal of Produced Water in Unlined Pits
Use of unlined pits for the disposal of produced water is now allowed
in only a few States. The use of these pits has the potential to degrade
usable ground water through seepage of produced water constituents into
unconfined, freshwater aquifers underlying such a pit.
Discharge of Produced Water to Sensitive Surface Waters
Discharge of produced waters to surface water bodies must meet State
or Federal permit standards. Although pollutants such as total organic
carbon are limited in these discharges, large volumes of discharges
containing low levels of such pollutants may be damaging to aquatic
communities.
Drilling Wastes on the Alaska North Slope
Drilling waste disposal practices on the North Slope of Alaska are
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very different from disposal practices elsewhere. Production-related
reserve pits on the North Slope are semipermanent, and their contents
need to be disposed of periodically. This is generally done by pumping
the aqueous phase of the pit onto the tundra after the pit contents have
been allowed to settle for a period of 1 year. This discharge is done
under permitted effluent limits set by the State of Alaska. The National
Pollutant Discharge Elimination System (NPDES) currently does not
regulate these discharges. The long-term effects of discharging large
quantities of liquid reserve pit waste on the sensitive tundra
environment is of concern to EPA, Alaska Department of Environmental
Conservation, and officials from other Federal agencies. The existing
body of scientific evidence is insufficient to conclusively demonstrate
whether or not there are adverse environmental impacts resulting from
this practice.
Improperly Plugged and Unplugged Abandoned Wells
There are an estimated 1,200,000 abandoned oil or gas wells in the
United States. To avoid degradation of ground water it is vital that
abandoned wells be properly plugged. Lack of plugging or improper
plugging of a well may allow high-chloride produced water or injected
wastes to migrate to freshwater aquifers.
DAMAGE CASES
The purpose of the damage case study was to respond to the
requirements of Section 8002(m)(1)(C) by providing an overview of the
nature of damages associated with oil and gas exploration, development,
or production activities. In general, case studies were used to gain
familiarity with ranges of issues involved in a particular study topic,
not to provide a statistical representation of the scope or nature of
damages. In addition, although many of the cases involved violations of
State or Federal regulations, or would involve violations of a State or
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Federal regulation if they were to occur today, EPA did not consider this
to be relevant to whether or not those cases should be included in this
report.
Types of damage of concern to this study were human health effects
(acute and chronic), environmental effects, effects on wildlife, effects
on livestock, and impairment of other natural resources. Case
information was assembled from the major petroleum-producing States:
Alaska, Arkansas, California, Kansas, Louisiana, Michigan, New Mexico,
Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. The
damage case effort focused on gathering information on cases that had
occurred most recently. Ninety-five percent of all cases used in the
report date from 1981 to the present, and approximately half of these
involved violations of State regulations.
Test of Proof for Cases Used in the Study
All cases were classified according to whether they met one or more
formal tests of proof, a classification that was to some extent
judgmental. Three tests were used; cases were considered to meet the
documentation standards of Section 8002(m)(l)(C) if they met one or more
of them, and most met more than one. The tests were as follows:
1. Scientific investigation: Scientific investigations could
include either a qualitative scientific evaluation of a case, in
which a conclusion of damage might be reached by the author(s) of
the study, or through the results of scientific measurements, such
as a monitoring study, or both. In the latter event, damage could
be accepted as documented if the levels of contamination reported
exceeded applicable State or Federal standards or guidelines for
the pollutant involved.
2. Administrative finding: Damage was accepted as documented if it
was reported by a State or Federal official in the course of
official duties and if that report was not later invalidated or
withdrawn.
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3. Court decision: Court rulings finding presence of health or
environmental damages were accepted as conclusive.
EPA distributed draft versions of the case studies, based on an
interpretation of the documentation gathered in the initial phases of the
study, for review and validation. The Agency received voluminous
responses on these cases from the States, from industry, and sometimes
from third parties. The cases were extensively revised and expanded to
incorporate all commentary; where issues of fact or interpretation could
not be resolved, EPA has provided numerous footnotes within the report so
as to present all sides of the issues.
Several patterns became apparent after analysis was performed on the
damage cases collected. They are described below:
Ground-Water Degradation
Degradation of ground water from improper operation of injection
wells for the purpose of disposal or enhanced recovery is a potential
hazard and has important implications given the large number of wells
used for injection, either for enhanced recovery of oil or for final
disposal of oil and gas wastes. Damage to ground water from improperly
operated injection wells tends to be long-term since it is difficult and
costly to remediate contaminated ground water. Such damage can result in
loss of domestic water supplies and damage to agricultural land and crops
through irrigation with saline water.
Many States have primacy under the Federal Underground Injection
Control program. In order to obtain primacy, the State has to
demonstrate that its programs are effective in protecting underground
sources of drinking water, meet all requirements of Section 1421
(b)(l)(A) through (D) of the Safe Drinking Water Act (SDWA) and in
general conform to guidance issued by EPA pursuant to Section 1425 of
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SDWA. Individual State programs however, may vary in their specific
requirements within the discretion allowed under this program.
The only State with significant oil and gas production that allows
annular disposal of produced water is Ohio. This practice makes ground
water in the vicinity of a disposal well especially vulnerable to
degradation because the ground water is protected with only one string of
casing.
Ground-Water Contamination from Leaching of Reserve Pit Contents
Contamination of ground water from leaching of reserve pit contents
is a situation found in many areas of the U.S. Where reserve pits are
overlying unconfined aquifers, the potential exists for seepage or
leaching of potentially toxic reserve pit constituents into the ground
water. Such leaching can result in lost domestic and agricultural water
supplies and irrigation water supplies and can endanger human health.
Reserve pits may contain high levels of chlorides, barium, chromium,
cadmium, copper, arsenic, lead, zinc, and organic toxic constituents,
which can be mobile in ground water.
Discharge of Drilling Fluids and Produced Water into Bays and
Estuaries
Discharge of waste drilling mud and produced water into bays and
estuaries of the Gulf of Mexico is allowed by Gulf Coast States (Texas
and Louisiana). This practice has been shown to be detrimental to
aquatic life in the affected bays and estuaries, with the potential for
contamination of aquatic life and bird life with heavy metals and
polycyclic aromatic hydrocarbons (PAHs). Of greater concern is the
potential for heavy metals, taken up in such organisms as clams and
oysters, to travel up the food chain, possibly endangering human health
through consumption of contaminated fish and shellfish. EPA has not yet
issued NPDES permits for these discharges. Permits for such discharges
may be issued by the States.
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Discharge of Oily Wastes to Unlined Pits
California permits the discharge of oily wastes to large, unlined
sumps or pits and ephemeral streams. This practice has resulted in
mortality to wildlife, including some endangered species, when exposed to
the oily waste.
Unlined Produced Water Disposal Pits
The use of unlined produced water disposal pits is still allowed in
some western States. Studies have illustrated how produced water
constituents, including benzene and chlorides, migrate into
unconsolidated soil surrounding some such disposal pits and seep into
shallow ground water.
Discharge of Produced Water to Surface Streams
Under the NPDES permit system, discharge of produced water to live
and ephemeral streams is allowed in some western states. Studies have
shown that high-volume discharges containing low levels of organic carbon
can have severe impacts on fish in receiving streams.
Illegal Disposal
Illegal disposal is a pervasive problem that may result in damage to
surface water, wetlands, native aquatic life, soil, ground water,
wildlife, crops, and livestock and may endanger human health. Damages
may be temporary, but they can be significant at the time of the
incident. Incidents of illegal disposal of oil and gas wastes are found
throughout the U.S. About half the damage cases used in the Report
appear to involve violations of State regulations, and a smaller number
involve violations of Federal regulations. Detailed information on
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compliance status was not always available and, in many cases, practices
that may have been legal at the time of an incident may now be illegal
under revised State regulations.
Practices on the Alaska North Slope
Waste disposal practices on the North Slope of Alaska are very
different from those in other areas of the U.S. Discharge of excess
liquid directly onto the tundra and roads from production reserve pits is
permitted under regulations of the Alaska Department of Environmental
Conservation (ADEC). ADEC estimates that 100 million gallons of this
liquid are pumped onto the tundra and roadways on the North Slope each
year, potentially carrying with it reserve pit constituents such as
chromium, barium, chlorides, and oil. Scientists who have studied the
area believe this practice has the potential to lead to bioaccumulation
of heavy metals and other contaminants in local wildlife, thus affecting
the food chain. Results from recently released studies suggest that the
possibility exists for adverse impact on Arctic wildlife because of
discharge of reserve pit liquid to the tundra; however, these studies are
inconclusive. New regulations recently enacted by the State of Alaska
should significantly reduce the potential for tundra and wildlife impacts.
Improperly Plugged and Unplugged Abandoned Wells
Degradation of ground water caused by waste seepage through
improperly plugged and unplugged abandoned wells is known to occur in
various parts of the U.S. Improperly plugged and unplugged abandoned
wells can also enable native brine to migrate up the wellbore and into
freshwater aquifers. The damage to ground water can be extensive,
resulting in lost domestic water and irrigation water supplies. When
agricultural land is irrigated with this water, long-term damage to the
soil is sustained. Because thousands of wells were abandoned throughout
19
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the U.S. before there were any State regulatory plugging requirements,
the potential for environmental and resource damage through ground-water
degradation is high. Existing State regulations concerning plugging and
abandonment of oil and gas wells vary widely. Some States have adequate
regulations currently in place.
RISK MODELING
"EPA used quantitative modeling and a review of scientific literature
to evaluate health and environmental risks associated with management of
oil and gas wastes. The Agency did not attempt to estimate absolute
risks in terms of the number of persons in the U.S. likely to experience
health problems, or the volume of ground water likely to suffer various
degrees of degradation, because of a lack of adequate sample data on
regional waste characterization and inadequate empirical information on
waste management system failure probabilities. Rather, the principal
purpose of this effort was to investigate, and compare potential risks to
human health and the environment under a wide variety of current waste
management conditions.
The specific objectives of the risk analysis were to (1) characterize
and classify the major risk-influencing factors (e.g., waste types, waste
management practices, environmental settings) associated with current
operations at oil and gas facilities; (2) estimate distributions of these
risk-influencing factors across the population of oil and gas facilities
within various geographic zones; (3) evaluate these factors in terms of
their relative effect on risks; and (4) develop, for different geographic
zones of the U.S., initial quantitative estimates of the possible range
of baseline health and environmental risks for the variety of conditions
found. A qualitative review of the potential human health and ecological
damage on Alaska's North Slope, and of the proximity of oil and gas
activities to environments of special interest (i.e., endangered species
habitats, wetlands, and public lands).
20
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Methodology
Model scenarios were defined to simulate over 3,000 realistic
combinations of variables representing waste streams, management
practices, and environmental settings at oil and gas facilities. The
focus was on the principal large-volume waste streams, including mixed
drilling muds, liquids, and cuttings managed in conventional lined and
unlined reserve pits, and produced water disposed by injection in Class
II deep injection wells and by surface water discharge. Several other
waste streams and current management practices were not included in the
quantitative modeling analysis, but the ones considered represent the
major waste streams and the most common management practices within the
scope of this study. Also, no attempt was made to examine all release
and migration pathways for the waste streams that were
considered.2 EPA evaluated scenarios under both "best-estimate"
(typical) and "conservative" (i.e., higher risk, but not necessarily
worst-case) assumptions. In general, the practices modeled correspond
reasonably well with the baseline requirements of existing State and
Federal regulatory programs. Risks from illegal disposal or other
compliance problems were not specifically studied in this modeling
project.
EPA selected eight constituents for modeling: arsenic, benzene,
boron, sodium, chloride, cadmium, chromium, and mobile ions (including
chloride, sodium, potassium, calcium, magnesium, and sulfate). The
constituents were selected because they were detected frequently and in
elevated concentrations in EPA's waste samples, and because they have a
relatively high potential to migrate through ground water and cause
adverse environmental and human health effects. The Agency modeled
median and upper 90th percentile concentrations of these constituents
For instance, no attempt was made to model the migration of reinjected produced water
along fractures, or through unplugged abandoned wells, after being injected underground.
21
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based on existing sample data. Waste releases, environmental transport
and fate, and risks effects via ground-water and surface water pathways
were modeled for a 200-year period using a modified version of the
Agency's Liner Location Risk and Cost Analysis Model (LLM). Chemical
transport in rivers was modeled using equations developed for performing
waste load allocations in rivers and streams. All risks were calculated
for the "most exposed individual" at downgradient center line plume
concentrations.
General Findings
• For the vast majority of model scenarios evaluated in this
study, only very small to negligible risks would be expected to
occur even under the conservative set of assumptions modeled in
this analysis. Risk levels of concern would be expected at only a
small percentage of oil and gas sites.
• Of the hundreds of chemical constituents detected in both
reserve pits and produced water, only a few from either source
appear to be of primary concern relative to health or
environmental damage.
• Both for reserve pit waste and produced water, there is a wide
(generally five or more orders of magnitude) variation in
estimated health risks across model scenarios, depending on
concentrations of toxic chemicals present, hydrogeologic
parameters, waste amounts, management practices, and distances to
exposure points.
• Modeling of resource damages to surface water, in terms of both
ecological impact and resource degradation, generally did not show
significant risk values.
Drilling Waste Disposal in Onsite Reserve Pits
• Health risk estimates for cancer (arsenic) never exceeded 1 x
10"5 (one in 100,000) for reserve pit wastes. Roughly 2 percent
of the reserve pit scenarios, analyzed under a conservative set of
assumptions, had cancer risks greater than 1 x 10"7. For
noncancer effects, sodium concentrations in drinking water
exceeded threshold levels for hypertension in only 1 to 2 percent
of the scenarios examined. The highest sodium concentration
estimated at an exposure point was 32 times the threshold. The
22
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higher risk cases occurred for a large unlined reserve pit, a
60-meter exposure distance, and high subsurface permeability and
infiltration.
• Differences in risk across geographic zones generally did not
vary by more than one order of magnitude, but this may have
reflected limitations of the study approach to estimating regional
risk distributions and lack of data on regional variation in waste
composition.
• Ground-water flow field type and exposure distances had the
greatest influence on risk (several orders of magnitude).
Recharge rate, subsurface permeability, and pit size had less
impact. Depth to ground water and presence/absence of a single
synthetic liner had virtually no measurable influence over the
200-year modeling period; however, risk estimated over shorter
time periods, such as 50 years, would likely be lower for lined
pits compared to unlined pits.
• Ground-water resource risk from leaching of reserve pit contents
was very limited and was confined to the closest modeling distance
(60 meters). No surface-water damage was predicted for the
seepage of leachate-contaminated ground water into flowing surface
water.
Produced Water Disposal in Injection Wells
• Health risk estimates for both cancer and noncancer effects were
substantially below levels of possible concern in a majority of
scenarios under both best-estimate and conservative modeling
assumptions. Under conservative assumptions, from 22 to 35
percent of the scenarios had cancer risks (caused by the ingestion
of arsenic and benzene) greater than 1 x 10"', and from 0.4 to 5
percent of the scenarios had cancer risks greater than 1 x
10~4. The highest cancer risk estimate was 9 x 10 . Also
under the conservative modeling assumptions, the sodium
concentration in drinking water wells was predicted to exceed the
threshold for hypertension for a maximum of 22 percent of the
scenarios
• In general, the highest risk scenarios correspond to a short
(60-meter) exposure distance, as relatively high injection
pressure or rate, and a few specific ground-water flow fields.
The highest cancer risks were associated with relatively high
ground-water velocities and flow rates, while the highest
noncancer risks were associated with relatively low ground-water
velocities and flow rates.
23
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• As for the reserve pit results, there was little variation of
risk among zones.
• Exposure distance and ground-water velocity flow had the
greatest influence on risk. Injection rate and pressure had less,
but still measurable, influence.
• Risk of ground-water degradation from injection well failure was
predicted to be extremely limited, but modeling did not take into
account seepage through abandoned boreholes or fractures in
confining layers, leaching from brine pits, or spills.
• No risk of degradation of surface water was predicted for
seepage into flowing surface water of ground water contaminated by
direct release from injection wells.
Discharge of Produced Water to Surface Water by Stripper Wells
• Substantial risks to human health or aquatic habitats were not
predicted by the model scenarios for the normal range of stripper
well discharges (under 100 barrels per day), except for the
possible combination of high (90th percentile) waste
concentrations and very small (generally less than 5 cubic feet
per second) receiving water stream flows.
Drilling and Production Wastes Disposed on Alaska's North Slope
• Adverse effects to human health caused by drilling and
production wastes on the North Slope are expected to be
negligible. The greatest potential for adverse environmental
impacts is caused by discharge and seepage of reserve pit fluids
containing toxic substances onto the tundra. A 1983 Fish and
Wildlife Service study and industry investigations indicate that
these fluids can adversely effect water quality, vegetation, and
tundra invertebrates in nearby surrounding areas. Strengthened
State regulations concerning drilling waste disposal, however,
reduce the potential for these impacts today. The Fish and
Wildlife Service is in the process of studying the effects of
reserve pit fluids on tundra organisms, and these studies need to
be completed before more definitive conclusions can be made with
respect to environmental impacts on the North Slope.
Locations of Oil and Gas Activities in Relation to Environments of
Special Interest
• As would be expected with any large and widespread industry,
there are numerous oil and gas sites in the vicinity of endangered
and threatened species habitats and wetlands. In accordance with
existing controls for the management of public lands, a small
24
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portion of the country's National Forests and Parks also have
existing and potential oil and gas activities within their
boundaries. More detailed study is needed to determine what
effect, if any, oil and gas wastes may actually have on these
environments of special interest.
COST AND ECONOMIC IMPACTS
EPA developed estimates of the compliance costs and economic impacts
of implementing alternative waste management practices in the oil and gas
industry by modeling three waste management scenarios: (1) a "baseline"
scenario reflecting current waste management practices; (2) an
"intermediate" scenario, in which somewhat stricter controls on waste
disposal practices are assumed, and (3) a "Subtitle C" scenario, in which
full RCRA requirements must be met. EPA estimated total annual costs for
each scenario based on the cost of management using practices that
conform to the requirements of the scenario.
The Baseline Scenario represents the current situation and
encompasses the waste management practices now permitted under State and
Federal regulations. These waste management practices are principally
disposal onsite in lined and unlined pits for drilling wastes and either
deepwell injection (for disposal or enhanced energy recovery) or surface
disposal (e.g., discharge to water bodies, evaporation pits, or land) for
produced water.
The hypothetical alternative regulatory scenarios require additional
waste management controls on wastes considered hazardous. In the absence
of regulatory determination or detailed regional waste categorization,
EPA made two separate estimates of the costs of each scenario based on
rough assumptions that either 10 percent of 70 percent of wastes would be
considered hazardous for costing purposes.
25
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In the Intermediate Scenario, hazardous drilling wastes would be
disposed of in reserve pits with single synthetic liners, and hazardous
produced waters would be injected into Class II wells. For the Subtitle
C Scenario, all wastes considered hazardous (using the same 10 percent
and 70 percent assumptions) would have to meet pollution control
requirements consistent with existing Subtitle C regulations. Under this
scenario, drilling wastes considered hazardous would be disposed of in
Subtitle C facilities (e.g., a synthetic lined facility with leachate
collection and monitoring (SCLC) impoundment, hazardous waste
incinerator), and hazardous produced water would be injected into Class I
injection wells.
A second Subtitle C scenario (the Subtitle C-l Scenario) was also
considered. The requirements of this scenario are exactly the same as
those of the Subtitle C Scenario, except that produced water used in
waterflood operations for enhanced oil recovery (EOR) is considered part
of the production process. Under this scenario, produced water injected
into producing zones for oil recovery would not be considered a waste and
would therefore be exempt from Subtitle C (i.e., Class I disposal well)
requirements. Produced water injected for disposal purposes would still
be subject to Subtitle C requirements.
The Subtitle C Scenarios do not, however, impose all of the potential
technological requirements of the Solid Waste Act amendments, such as the
land ban and corrective action requirements, for which EPA regulatory
proposals are currently under development.
To determine the incremental cost of waste disposal under the
alternative waste management scenarios, the Agency calculated capital and
operating costs for the array, of individual waste management practices
that might be used in the different scenarios. These costs were
developed using literature sources, EPA engineering models, original
engineering estimates, vendor quotations, and other sources. Capital
26
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costs were annualized at an 8 percent discount rate, the approximate
after-tax real costs of capital in the industry, and were added to O&M
costs. The results are expressed in dollar-per-barrel disposal costs and
are presented in Table 3 for the lower 48 States (Lower 48).
Drilling waste disposal costs for the Lower 48 were found to range
from $2.04 per barrel for onsite unlined pit disposal to $157.50 per
barrel for incineration. Costs of injecting produced water were
estimated to vary between $0.10 per barrel for Class II disposal and
$0.92 per barrel for Class I disposal. Costs for Class I facilities are
substantially higher because of increased drilling, completion,
monitoring, and surface equipment costs associated with waste management
facilities that accept hazardous waste.
After selecting the waste management practices appropriate under each
scenario, the least-cost methods for each scenario were identified. In
this way, such options as landfarming or incineration under the Subtitle
C scenario were eliminated as viable waste management options.
EPA then estimated the incremental costs of these alternative waste
disposal practices under each scenario for representative oil and gas
projects in each of 9 major regions of the U.S. For each "model
project," the after-tax rate of return and the cost of production per
barrel of oil were calculated under each scenario, including the
baseline. Table 4 shows the impacts of waste management costs on a
weighted average model oil and gas project designed to represent the
Lower 48 States, for each of the six alternative regulatory scenarios
relative to the 1985 baseline.
National costs for each scenario were estimated by extrapolating the
waste management costs for model projects in each region to the national
level. Table 4 shows these annual national costs to range from $49
million in the Intermediate 10% case to over $12 billion for the Subtitle
C 70% case.
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Table 3 Cost of Waste Disposal Options
in the Lower 48 States
Disposal Option $/bbl
Drilling Wastes
Surface impoundment
- unlined (0.25 acre) 2.04
- single liner (0.25 acre) 4.46
- SCLC facility (15 acre)a 15.42
Landfarming
- current 15.47
- Subtitle C 37.12
Solidification 8.00
Incineration 157.50
Volume Reduction a
- single liner disposal 6.74
- SCLC disposal 11.95
Produced Water
Class II injection
- EOR 0.10
- disposal 0.14
Class I injection
- EOR 0.78
- disposal13 0.92
Note: Base year for costs is 1985.
a Costs include equipment rental, transport and disposal of reduced
volume of waste. All costs are allocated over the original volume of
waste so that per-barrel costs of waste disposal are comparable to the
other cost estimates in the table.
k Includes transportation and loading/unloading charges.
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Table 4 Impact of Waste Management Cost
on Oi 1 and Gas Projects
Inter- Inter-
mediate mediate Subtitle Subtitle Subtitle Subtitle
Factor Baseline 10% 70% C 10% C 70% C-l 10% C-l 70%
Weighted 28.9 28.8 28.0 26.6 13.0 27.6 19.7
average internal
rate of
return (%)a
Weighted $0.01 $0.11 $0.40 $2.88 $0.20 $0.55
average
incremental
cost of
production
($/BOŁ)a
Total annual — $49 $420 $1,710 $12,125 $980 $6,671
national
compliance cost
($ mi 1 lion)
Note: Base year for costs is 1985.
For typical lower 48 oi-l and gas projects.
29
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EPA then estimated short-term and long-term production declines that
could be linked to these increased waste disposal costs using Department
of Energy production forecasting models. Long-term results are shown in
Table 5. In the year 2000, no detectable change was seen for the
intermediate scenario when 10 percent of the wastes were considered
hazardous; the decline was 1 percent, however, when 70 percent of wastes
were assumed hazardous. Under the Subtitle C scenario, production
decline ranged from 4 to 18 percent in the year 2000; under the Subtitle
C-l Scenario (waterflcoding operations exempt from Subtitle C
requirements), the projected decline ranged from 1 to 12.5 percent.
The Agency estimated the impact of the projected production declines
on several economic aggregates, including oil price, balance of trade,
oil imports, Federal revenues, and State revenues. The impacts vary
greatly, depending on the cost of the waste management scenarios.
Increases in oil imports range from a "not detectable" level to 1.1
million barrels per day because of the U.S. production decline.
Increases in oil prices under the alternative scenarios range from a
negligible change to $1.08 per barrel because of the declining supply and
increasing cost of U.S. production. This shifting of oil supply and
price results in a deterioration in the U.S. balance of trade ranging
from "not detectable" to $17.5 billion per year and a cost to U.S.
consumers of up to $6.4 billion per year.
CURRENT STATE AND FEDERAL REGULATORY PROGRAMS
A variety of programs exist at the State level to control the
environmental impacts of waste management related to the oil and gas
industry. State programs have been in effect for many years, and many
have evolved significantly over the last decade. Chapter VII provides a
brief overview of the requirements of these programs and presents summary
statistics on the implementation of these programs, contrasting the
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Table 5 Long-term Impacts on Production of Cost
Increases Under Waste Management Scenarios
(Percent decrease from Baseline)
Scenario 1990 2000 2010
Intermediate 10%
Intermediate 70%
Subtitle C 10%
Subtitle C 70%
Subtitle C-l 10%
Subtitle C-l 70%
ND
NO
ND
, 3.2%
ND
2.1%
ND
1.4%
4.2%
18.1%
1.4%
12.5%
ND
1.6%
6.3%
28.6%
3.2%
19.0%
ND = Not detected.
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numbers of wells and other operations regulated by these programs with
resources available to implement regulatory requirements. In an effort
to characterize these State programs, EPA evaluated programs in the major
oil- and gas-producing States: Alaska, Arkansas, California, Colorado,
Kansas, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Texas, West
Virginia, and Wyoming. Chapter VII presents the results of this analysis.
Almost all of the States evaluated have general performance standards
that require reserve and produced water pits to be designed and operated
to prevent ground-water or surface-water degradation. Furthermore, most
of the States have liner and permit requirements for these pits.
Specific pit requirements generally depend on the pit's location, size,
and contents. Deadlines for pit closure range from 60 days to 1 year
after drilling has ceased.
Practices for the disposal of reserve pit wastes vary widely across
the nation. Most of the States studied in this report have established
concentration limits for land application.and surface-water discharge of
reserve pit contents, while a few States prohibit these disposal methods
altogether. Nearly all of the States allow annular injection of reserve
pits contents but place limits on the injection pressure and require that
the surface casing extend below freshwater aquifers.
Disposal of produced water is also closely regulated by many of the
States studied in this report. A majority of the States do not allow
produced water discharge by nonstripper wells to onshore surface waters;
however, discharge to coastal waters and discharges for beneficial uses
are more common. Where discharges are allowed, the States generally
require permits and compliance with established concentration limits.
Most of the surveyed States have general standards that require
underground injection operations to be protective of freshwater
aquifers. These States generally require casings that extend below the
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lowest underground sources of drinking water and mechanical integrity
tests that must be conducted before injection begins and every 5 years
thereafter. Areas of review for identification of improperly plugged
abandoned wells range from 1/4 mile to 2 1/2 miles. Finally, all of the
surveyed States require plugging of oil and gas wells within 60 days to 1
year from the time at which operations ceased.
The only current information on implementation of these programs that
EPA was able to gather relates to enforcement capabilities. The surveyed
States have designated from 8 to 120 positions per State* for enforcement
of their oil and gas waste requirements.
The Federal Underground Injection Control Program
The Underground Injection Control (UIC) program was established under
Part C of the Safe Drinking Water Act (SDWA) to protect USDWs from
endangerment by subsurface emplacement of fluids. Part C of the SDWA.
requires EPA to promulgate regulations establishing minimum requirements
for State programs and, in cases where States cannot or will not assume
primary enforcement responsibility, to promulgate State-specific Federal
regulations.
In 1980, Congress amended the SDWA by adding Section 1425. This
section allows States to demonstrate the effectiveness of their in-place
regulatory programs for Class II (oil- and gas-related) wells in lieu of
demonstrating that they meet the minimum requirements specified in the
UIC regulations. In order to be deemed effective, State Class II
programs have to meet the same statutory requirements as the other
classes of wells, including prohibition of unauthorized injection and
protect-ion of USDWs. All Class II programs currently approved by EPA
were approved under Section 1425.
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Because of the large number of Class II wells, the Federal
regulations allow for authorization by rule for existing enhanced
recovery wells (i.e., wells that were injecting at the time that a State
program was approved or prescribed by EPA). Wells authorized by rule are
subject to requirements similar to those of permitted wells but are not
subject to the administrative difficulties of obtaining a permit. During
the first 5 years of the program, EPA and the States have been conducting
file reviews on all wells authorized by rule. File reviews are
assessments of technical issues that would normally be part of a permit
decision and are conducted to ensure that injection wells not subject to
permitting are technically adequate and will not endanger USDWs.
In approving programs under Section 1425 the Agency has accepted
variations among States. This is consistent with the requirements of the
SDWA. However, the program has been in place for several years now and
the Agency has acquired experience in implementation of the regulations.
Based on this experience, the Agency has begun to look at the adequacy of
the current requirements and may eventually require more specificity and
less variation among States.
Bureau of Land Management
Exploration, development, drilling, and production of onshore oil and
gas on Federal and Indian lands are regulated separately from non-Federal
lands. This separation of authority is significant for western States
where oil and gas activity on Federal and Indian lands is a large portion
of statewide activity. The Department of Interior administers its
regulatory program through the Bureau of Land Management (BLM) offices in
the producing States. These offices generally have procedures in place
for coordination with State agencies on regulatory requirements. The
Bureau works closely with the U.S. Forest Service to define surface
stipulations for using Federal forests and Federal grasslands.
34
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Historically, BLM has controlled oil and gas activities through
Notices to Lessees (NTLs) and through the issuance of permits. Leases,
where drilling is to take place, must be covered by a bond. A single
lease bond is currently $10,000. Statewide bonds are $25,000;
nationwide bonds are $150,000. BLM considers reserve pits to be
temporary, and except in special circumstances they do not have to be
lined. Produced waters may be disposed of by underground injection, by
disposal into lined pits, or "by other acceptable methods." When a dry
hole is drilled, plugging must take place before removal of the drilling
equipment. Ninety days after a well ceases production, the operator may
request approval for temporary abandonment. Thereafter, reapproval for
abandonment status may be required every 1 to 2 years. Plugging
requirements for wells are determined by the BLM District Office.
Implementation of State and Federal Programs
Tables 6 and 7 present statistics for State and Federal
implementation of regulatory programs.
CONCLUSIONS
From the analysis conducted for this report, it is possible to draw a
number of general conclusions concerning the management of oil and gas
wastes. The conclusions are presented below.
Available waste management practices vary in their environmental
performance.
Based on its review of current and alternative waste management
practices, EPA concludes that the environmental performance of existing
waste management practices and technologies varies significantly. The
reliability- of waste management practices will depend largely on the
environmental setting. However, some methods will generally be less
35
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Table 6 Slat* Enforcement Matrix
Slat* Gas Production
OH Production Gas wells Oil walls Injection wells
New wells
Agency
Personnel*
Alaska
Arkansas
Caiomia
Kansas
Louisiana
New Mexico
Ohio
Oklahoma
Pennsylvania
Texas
West Virginia
Wyoming
316.000 Mmd 1986
194.483 Mmd 1985
493,000 Mmd 1985
466.600 Mmd 1984
5.867,000 Mmd 1984
893.300 Mmd 1985
182.200 Mmd 1985
1.996,000 Mmd 1984
166,000 Mmd 1984
5,805,000 Mmd 1985
142.500 Mmd 1986
597.896 Mmd 1985
681.309.821 bW 1986
19.715.691 bbl 1985
423.900.000 bbl 1985
75.723.000 bbl 1984
449.545.000 bbl 1984
78,500.000 bo) 1985
14.987.592 bbl 1985
153.250,000 bbl 1984
4,825,000 bbl 1984
830,000,000 bbl 1985
3,600.000 bbl 1986
130.984.917 bbl 1985
104
2,492
1.566
12,680
14,436
18.308
31.343
23.647
24,050
68,811
32,500
2,220
1.191
9.490
55.079
57.633
25.823
21.986
29.210
99,030
20,739
210,000
15.895
12.218
472 Class II
425 EOR
47Dtsposa
1.211 Class H
239 EOR
972 Dispose
11.066 Class!
10.047 EOR
1,0190isposa
14.902 Class II
9.366 EOR
5,536 Disposal
4.436 Class II
1.283 EOR
3,153 Disposal
3,671 Class II
3.506 EOR
363 Disposal
3.956 Class II
127 EOR
3,829 Disposal
22,803 Class II
14,901 EOR
7,902 Disposal
6.183 Class II
4.315 EOR
1 ,868 Disposal
53, 141 Class II
45.223 EOR
7,918 Disposal
761 Class II
687 EOR
74 Disposal
5.880 Class II
5.257 EOR
623 Disposal
100 new onshore weds
completed In 1985
1.055 new weds
completed In 1985
3,413 new weds
compleled In 1985
6.025 new wells
completed in 1985
5,447 new onshore
weds compleled 1985
1.747 new weds
compleled In 1985
6.297 new wets
compleled In 1985
9.1 76 new weds
compleled In 1985
4.627 new wete
compleled in 1985
25.721 newweUs
compleled In 1985
1,839 new wete
compleled in 1985
1,735 new wells
compleled in 1985
Oi and Gas Conservation Commission
Department of Environmental Conservation
Arkansas Oil and Gas Commission
Department of PoluUon Control and Ecology
Conservation Depl.. Division of Oil and Gas
Department of fish and Game
Kansas Corporation Commission
Department of Environmental Quality
Of lice ol Conservation - Injection and Mining
Energy and Minerals Department,
Oil Conservation Division
Ohio Department ol Natural Resources.
Division of Oil and Gas
Oklahoma Corporation Commission
Department ol Environmental Resources.
Bureau of Oil and Gas Management
Texas Railroad Commission
West Virginia Department of Energy
Oi and Gas Conservation Commission
Department of Environmental Quality
8 enforcement positions
6 enforcement positions
7 enforcement positions
2 enforcement positions
31 enforcement positions
30 enforcement positions
32 enforcement positions
36 enforcement positions
10 enforcement positions
66 enforcement positions
52 enforcement positions
34 enforcement positions
120 enforcement positions
15 enforcement positions
7 enforcement positions
4.5 enforcement positions
OJ
en
'Only held stall are included in total enforcement positions.
-------
Historically, BLM has controlled oil and gas activities through
Notices to Lessees (NTLs) and through the issuance of permits. Leases,
where drilling is to take place, must be covered by a bond. A single
lease bond is currently $10,000. Statewide bonds are $25,000;
nationwide bonds are $150,000. BLM considers reserve pits to be
temporary, and except in special circumstances they do not have to be
lined. Produced waters may be disposed of by underground injection, by
disposal into lined pits, or "by other acceptable methods." When a dry
hole is drilled, plugging must take place before removal of the drilling
equipment. Ninety days after a well ceases production, the operator may
request approval for temporary abandonment. Thereafter, reapproval for
abandonment status may be required every 1 to 2 years. Plugging
requirements for wells are determined by the BLM District Office.
Implementation of State and Federal Programs
Tables 6 and 7 present statistics for State and Federal
implementation of regulatory programs.
CONCLUSIONS
From the analysis conducted for this report, it is possible to draw a
number of general conclusions concerning the management of oil and gas
wastes. The conclusions are presented below.
Available waste management practices vary in their environmental
performance.
Based on its review of current and alternative waste management
practices, EPA concludes that the environmental performance of existing
waste management practices and technologies varies significantly. The
reliability of waste management practices will depend largely on the
environmental setting. However, some methods will generally be less
35
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Table 6 State Enforcement Matrix
State
Ga* Production
Oil Production Ga* wells Oil well* Injection wells
New wells
Agency
Personnel*
Alaska
Arkansas
CaUomia
Kansas
Louisiana
New Mexico
Ohio
Oklahoma
Pennsylvania
Texas
West Virginia
Wyoming
316,000 Mmcf 1986
194,483 Mmd 1985
493.000 Mmd 1985
466,600 Mmd 1984
5,867.000 Mmd 1984
893,300 Mmd 1985
182.200 Mmd 1985
1,996.000 Mmd 1984
166,000 Mmd 1984
5,805,000 Mmd 1985
142,500 Mmd 1986
597.896 Mmd 1985
681,309.821 bbl 1986
19.715.691 bbl 1985
423.900,000 bbl 1985
75~.723.000 bbl 1984
449.545.000 bbl 1984
78,500.000 bbl 1985
14,987.592 bbl 1985
153.250,000 bbl 1984
4,825.000 bbl 1984
830.000.000 bbl 1985
3,600.000 bbl 1986
130.984.917 bbl 1985
104
2.492
1.566
12,680
14.436
18.308
31,343
23.647
24,050
68,811
32.500
2.220
1.191
9.490
55.079
57.633
25.823
21.986
29.210
99,030
20,739
210,000
15,895
12,218
472 Class N
425 EOR
47 Disposal
1.211 Class II
239 EOR
972 Disposal
11, 066 Class II
10.047 EOR
1,019 Disposal
14.902 Class II
9.366 EOR
5,536 Disposal
4.436 Class II
1.283 EOR
3,153 Disposal
3.871 Class II
3.508 EOR
363 Disposal
3,956 Class II
127 EOR
3,829 Disposal
22.803 Class II
14.901 EOR
7,902 Disposal
6.183 Class II
4.315 EOR
1,868 Disposal
53,141 Class II
45,223 EOR
7,918 Disposal
761 Class II
687 EOR
74 Disposal
5,880 Class II
5.257 EOR
623 Disposal
100 new onshore wells
completed in 1985
1.055 new wells
completed in 1985
3.413 new wells
completed in 1985
6,025 new wells
completed in 1985
5.447 new onshore
wells completed 1985
1,747 new wells
completed in 1985
6,297 new wells
completed in 1985
9, 176 new wells
completed in 1985
4.627 new wells
completed in 1985
25.721 new wells
completed in 1985
1,839 new wells
completed in 1985
1,735 new wells
completed in 1985
Oil and Gas Conservation Commission
Department of Environmental Conservation
Arkansas Oil and Gas Commission
Department of Potation Control and Ecology
Conservation Dept., Division of Oil and Gas
Department of Fish and Game
Kansas Corporation Commission
Department of Environmental Quality
Office of Conservation - Injection and Mining
Energy and Minerals Department,
Oil Conservation Division
Ohio Department of Natural Resources,
Division of Oi and Gas
Oklahoma Corporation Commission
Department of Environmental Resources,
Bureau of Oil and Gas Management
Texas Railroad Commission
West Virginia Department of Energy
Oil and Gas Conservation Commission
Department of Environmental Quality
8 enforcement positions
8 enforcement positions
7 enforcement positions
2 enforcement positions
31 enforcement positions
30 enforcement positions
32 enforcement positions
36 enlorcemeni positions
10 enforcement positions
66 enforcement positions
52 enforcement positions
34 enforcement positions
120 enforcement positions
15 enforcement positions
7 enforcement positions
4 5 enforcement positions
OJ
CTl
'Only field stall are included in lolal enforcement positions.
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Table 7 BLM Enforcement Matrix*
Office Other States Producing oil and gas Nonproduclng oil and gas Personnel
location for which office leases leases" (for producing leases only)
Is responsible
Alaska
California
Colorado
Idaho
Mississippi
Alabama
Arkansas
Florida
Kentucky
Louisiana
Virginia
Total
Montana
North Dakota
South Dakota
Total
Nevada
New Mexico
Arizona
Kansas
Oklahoma
Texas
Total
Oregon
Utah
Wisconsin
Maryland
Michigan
Missouri
Ohio
Pennsylania
West Virginia
Total
Nebraska
Total
Total
43
305
3,973
0
116
12
161
1
13
121
1
425
958
456
98
1,512
43
5.725
10
150
2,767
61
8,713
0
1,654
0
2
28
1
33
6
46
116
5,037
42
5,079
22,037
8,443
1.383
4,463
471
1.519
567
1,099
0
65
487
523
4260
4,721
1,991
572
7284
3,045
9,306
396
227
2,754
279
12,952
1,513
7222
0
11
603
6
69
1
54
844
28,044
582
28,626
102251
1 enforcement position
7 enforcement positions
1 0 enforcement positions
0 enforcement positions
3 enforcement positions
12 enforcement positions
1 enforcement position
43 enforcement positions
0
10 enforcement positions
27 enforcement positions
* Oil and gas inspectors working in the field as of March 30,1987. At that time
there were eight vacancies nationwide.
** Includes leases that have never been drilled, have been drilled and abandoned,
or are producing wells that have been temporarily shut down.
37
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reliable than others because of more direct routes of potential exposure
to contaminants, lower maintenance and operational requirements,
inferiority of design, or other factors. Dependence on less reliable
methods can in certain vulnerable locations increase the potential for
environmental damage related to malfunctions and improper maintenance.
Examples of technologies or practices that are less reliable in locations
vulnerable to environmental damage include:
• Annular disposal of produced water (see damage case OH 38,
page IV-16);
• Landspreading or roadspreading of reserve pit contents (see
damage case WV 13, page IV-24);
• Use of produced water storage pits (see damage case AR 10,
page IV-36); and
• Surface discharges of drilling waste and produced water to
sensitive systems such as estuaries or ephemeral streams (see
damage cases TX 55, page IV-49; TX 31, page IV-50; TX 29,
page IV-51; WY 07, page IV-60; and CA 21, page IV-68).
Any program to improve management of oil and gas wastes in the near
term will be based largely on technologies and practices in current use.
Current technologies and practices for the management of wastes from
oil and gas operations are well established, and their environmental
performance is generally understood. Improvements in State regulatory
requirements over the past several years are tending to increase use of
more desirable technologies and practices and reduce reliance on others.
Examples include increased use of closed systems and underground
injection and reduced reliance on produced water storage and disposal
pits.
Long-term improvements in waste management need not rely, however,
purely on increasing the use of better existing technology. The Agency
does foresee the possibility of significant technical improvements in
future technologies and practices. Examples include incineration and
other thermal treatment processes for drilling fluids; conservation,
recycling, reuse, and other waste minimization techniques; and wet air
oxidation and other proven technologies that have not yet been applied to
oil and gas operations.
38
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Because of Alaska's unique and sensitive tundra environment, there
has been special concern about the environmental performance of waste
management practices on the North Slope. Although there are limited and
preliminary data that indicate some environmental impacts may occur,
these data and EPA's initial analysis do not indicate the need to curtail
current or future oil exploration, development, and production operations
on the North Slope. However, there is a need for more environmental data
on the performance of existing technology to provide assurance that
future operations can proceed with minimal possible adverse impacts on
this sensitive and unique environment. The State of Alaska has recently
enacted new regulations which will provide additional data on these
practices.
EPA is concerned in particular about the environmental desirability
of two waste management practices used in Alaska: discharge of reserve
pit supernatant onto tundra and road application of reserve pit contents
as a dust suppressant. Available data suggest that applicable discharge
limits have sometimes been exceeded. This, coupled with preliminary
biological data on wildlife impacts and tundra and surface water
impairment, suggests the need for further examination of these two
practices with respect to current and future operations. The new
regulations recently enacted by the State of Alaska should significantly
reduce the potential for tundra and wildlife impacts.
Increased segregation of waste may help improve management of oil and
gas wastes.
The scope of the exemption, as interpreted by EPA in Chapter II of
this report, excludes certain relatively low-volume but possibly
high-toxicity wastes, such as unused pipe dope, motor oil, and similar
materials. Because some such wastes could be hazardous and could be
segregated from the large-volume wastes, it may be appropriate to require
39
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that they be segregated and that some of these low-volume wastes be
managed in accordance with hazardous waste regulations. While the Agency
recognizes that small amounts of these materials may necessarily become
mixed with exempt wastes through normal operations, it seeks to avoid any
deliberate and unnecessary use of reserve pits as a disposal mechanism.
Segregation of these wastes from high-volume exempt wastes appears to be
desirable and should be encouraged where practical.
Although this issue is not explicitly covered in Chapter VII, EPA is
aware that some States do require segregation of certain of these
low-volume wastes. EPA does not have adequate data on which to judge
whether these State requirements are adequate in coverage, are
enforceable, are environmentally effective, or could be extended to
general operations across the country. The Agency concludes that further
study of this issue is desirable.
Stripper operations constitute a special subcategory of the oil and gas
industry.
Strippers cumulatively contribute approximately 14 percent of total
domestic oil production. As such, they represent an economically
important component of the U.S. petroleum industry. Two aspects of the
stripper industry raise issues of consequence to this study.
First, generation of production wastes by strippers is more
significant than their total petroleum production would indicate. Some
stripper wells yield more than 100 barrels of produced water for each
barrel of oil, far higher on a percentage production basis than a typical
new well, which may produce little or no water for each barrel of oil.
Second, stripper operations as a rule are highly sensitive to small
fluctuations in market prices and cannot easily absorb additional costs
for waste management.
40
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Because of these two factors — inherently high waste-production rates
coupled with economic vulnerability--EPA concludes that stripper
operations constitute a special subcategory of the oil and gas industry
that should be considered independently when developing recommendations
for possible improvements in the management of oil and gas wastes. In
the event that additional Federal regulatory action is contemplated, such
special consideration could indicate the need for separate regulatory
actions specifically tailored to stripper operations.
Documented damage cases and quantitative modeling results indicate
that, when managed in accordance with State and Federal requirements,
exempted oil and gas wastes rarely pose significant threats to human
health and the environment.
Generalized modeling of human health risks from current waste
management practices suggests that risks from properly managed operations
are low. The damage cases researched in the course of this project,
however, indicate that exempt wastes from oil and gas exploration,
development, and production can endanger human health and cause
environmental damage when managed in violation of existing State
requirements.
Damage Cases
In a large portion of the cases developed for this study, the types
of mismanagement that lead to such damages are illegal under current
State regulations although a few were legal under State programs at the
time when the damage originally occurred. Evidence suggests that
violations of regulations do lead to damages. It is not possible to
determine from available data how frequently violations occur or whether
violations would be less frequent if new Federal regulations were imposed.
Documented damages suggest that all major types of wastes and waste
management practices have been associated to some degree with
41
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endangerment of human health and damage to the environment. The
principal types of wastes responsible for the damage cases include
general reserve pit wastes (primarily drilling fluids and drill cuttings,
but also miscellaneous wastes such as pipe dope, rigwash, diesel fuel,
and crude oil); fracturing fluids; production chemicals; waste crude oil;
produced water; and a variety of miscellaneous wastes associated with
exploration, development, or production. The principal types of damage
sometimes caused by these wastes include contamination of drinking-water
aquifers and foods above levels considered safe for consumption, chemical
contamination of livestock, reduction of property values, damage to
native vegetation, destruction of wetlands, and endangerment of wildlife
and impairment of wildlife habitat.
Risk Model ing
The results of the risk modeling suggest that of the hundreds of
chemical constituents detected in both reserve pits and produced fluids,
only a few from either source appear to be of concern to human health and
the environment via ground-water and surface water pathways. The
principal constituents of potential concern, based on an analysis of
their toxicological data, their frequency of occurrence, and their
mobility in ground water, include arsenic, benzene, sodium, chloride,
boron, cadmium, chromium, and mobile salts. All of these constituents
were included in the quantitative risk modeling; however, boron, cadmium,
and chromium did not produce risks or resource damages under the
conditions modeled.
For these constituents of potential concern, the quantitative risk
modeling indicates that risks to human health and the environment are
very small to negligible when wastes are properly managed. However,
although the risk modeling employed several conservative assumptions, it
was based on a relatively small sample of sites and was limited in scope
to the management of drilling waste in reserve pits, the underground
injection of produced water, and the surface water discharge of produced
water from stripper wells. Also, the risk analysis did not consider
42
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migration of produced water contaminants through fractures or unplugged
or improperly plugged and abandoned wells. Nevertheless, the relatively
low risks calculated by the risk modeling effort suggest that complete
adherence to existing State requirements would preclude most types of
damages.
Damages may occur in some instances even where wastes are managed in
accordance with currently applicable State and Federal requirements.
There appear to be some instances in which endangerment of human
health and damage to the environment may occur even where operations are
in compliance with currently applicable State and Federal requirements.
Damage Cases
Some documented damage cases illustrate the potential for human
health endangerment or environmental damage from such legal practices as
discharge to ephemeral- streams, surface water discharges in estuaries in
the Gulf Coast region, road application of reserve pit contents and
discharge to tundra in the Arctic, annular disposal of produced waters,
and landspreading of reserve pit contents.
Risk Modeling
For the constituents of potential concern, the quantitative
evaluation did indicate some situations (less than 5 percent of those
studied) with carcinogenic risks to maximally exposed individuals higher
A
then 1 in 10,000 (1x10 ) and sodium levels in excess of interim limits
for public drinking water supplies. Although these higher risks resulted
only under conservative modeling assumptions, including high (90th
percentile) concentration levels for the toxic constituents, they do
indicate potential for health or environmental impairment even under the
43
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general assumption of compliance with standard waste management
procedures and applicable State and Federal requirements. Quantitative
risk modeling indicates that there is an extremely wide variation (six or
more orders of magnitude) in health and environmental damage potential
among different sites and locations, depending on waste volumes, wide
differences in measured toxic constituent concentrations, management
practices, local hydrogeological conditions, and distances to exposure
points.
Unplugged and improperly plugged abandoned wells can pose significant
environmental problems.
Documentation assembled for the damage cases and contacts with State
officials indicate that ground-water damages associated with unplugged
and improperly plugged abandoned wells are a significant concern.
Abandoned disposal wells may leak disposed wastes back to the surface or
to usable ground water. Abandoned production wells may leak native
brine, potentially leading to contamination of usable subsurface strata
or surface waters.
Many older wells, drilled and abandoned prior to current improved
requirements on well closure, have never been properly plugged. Many
States have adequate regulations currently in place; however, even under
some States' current regulations, wells are abandoned every year without
being properly plugged.
Occasionally companies may file for bankruptcy prior to implementing
correct plugging procedures and neglect to plug wells. Even when wells
are correctly plugged, they may eventually leak in some circumstances in
the presence of corrosive produced waters. The potential for
environmental damage occurs wherever a well can act as a conduit between
usable ground-water supplies and strata containing water with high
44
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chloride levels. This may occur when the high-chloride strata are
pressurized naturally or are pressurized artificially by disposal or
enhanced recovery operations, thereby allowing the chloride-rich waters
to migrate easily into usable ground water.
Discharges of drilling muds and produced waters to surface waters have
caused locally significant environmental damage where discharges are not
in compliance with State and Federal statutes and regulations or where
NPDES permits have not been issued.
Damage cases indicate that surface water discharges of wastes from
exploration, development, and production operations have caused damage or
danger to lakes, ephemeral streams, estuaries, and sensitive environments
when such discharges are not carried out properly under applicable
Federal and State programs and regulations. This is particularly an
issue in areas where operations have not yet received permits under the
Federal NPDES program, particularly along the Gulf Coast, where permit
applications have been received but permits have not yet been issued, and
on the Alaskan North Slope, where no NPDES permits have been issued.
For the Nation as a whole, Regulation of all oil and gas field wastes
under unmodified Subtitle C of RCRA would have a substantial impact on
the U.S. economy.
The most costly hypothetical hazardous waste management program
evaluated by EPA could reduce total domestic oil production by as much as
18 percent by the year 2000. Because of attendant world price increases,
this would result in an annual direct cost passed on to consumers of over
$6 billion per year. This scenario assumes that 70 percent of all
drilling and production wastes would be subject to the current
requirements of Subtitle C of RCRA. If only 10 percent of drilling
wastes and produced waters were found to be hazardous, Subtitle C
regulation would result in a decline of 4 percent in U.S. production and
45
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a $1.2 billion cost increase to consumers, compared with baseline costs,
in the year 2000.
EPA also examined the cost of a Subtitle C scenario in which produced
waters injected for the purpose of enhanced oil recovery would be exempt
from Subtitle C requirements. This scenario yielded production declines
ranging from about 1.4 to 12 percent and costs passed on to consumers
ranging from $0.7 to $4.5 billion per year, depending on whether 10
percent or 70 percent of the wastes (excluding produced waters injected
for enhanced oil recovery) were regulated as hazardous wastes.
These Subtitle C estimates do not, however, factor in all of the
Hazardous and Solid Waste Act Amendments relating to Subtitle C land
disposal restrictions and corrective action requirements currently under
regulatory development. If these two requirements were to apply to oil
and gas field wastes, the impacts of Subtitle C regulation would be
substantially increased.
The Agency also evaluated compliance costs and economic impacts for
an intermediate regulatory scenario in which moderately toxic drilling
wastes and produced waters would be subject to special RCRA requirements
less stringent than those of Subtitle C. Under this scenario, affeted
drilling wastes would be managed in pits with synthetic liners, caps, and
ground-water monitoring programs and regulated produced waters would
continue to be injected into Class II wells (with no surface discharges
allowed for produced waters exceeding prescribed constituent
concentration limits). This scenario would result in a domestic
production decline, and a cost passed on to consumers in the year 2000,
of 1.4 percent and $400 million per year, respectively, if 70 percent of
46
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the wastes were regulated. If only 10 percent of the wastes were subject
to regulation, this intermediate scenario would result in a production
decline of less than 1 percent and an increased cost to consumers of
under $100 million per year.
The economic impact analysis also estimates effects on U.S. foreign
trade and State tax revenues. By the year 2000, based on U.S. Department
of Energy models, the EPA cost results projected an increase in national
petroleum imports ranging from less than 100 thousand to 1.1 million
barrels per day and a corresponding increase in the U.S. balance of
payments deficit ranging from less than $100 thousand to $18 billion
annually, depending on differences in regulatory scenarios evaluated.
Because of the decline in domestic production, aggregated State tax
revenues would be depressed by an annual amount ranging from a few
million to almost a billion dollars, depending on regulatory assumptions.
Regulation of all exempt wastes under full, unmodified RCRA Subtitle C
appears unnecessary and impractical at this time.
There appears to be no need for the imposition of full, unmodified
RCRA Subtitle C regulation of hazardous waste for all high-volume exempt
oil and gas wastes. Based on knowledge of the size and diversity of the
industry, such regulations could be logistically difficult to enforce and
could pose a substantial financial burden on the oil and gas industry,
particularly on small producers and stripper operations. Nevertheless,
elements of the Subtitle C regulatory program may be appropriate in
select circumstances. Reasons for the above tentative conclusion are
described below.
The Agency considers imposition of full, unmodified Subtitle C
regulations for all oil and gas exploration, development, and production
wastes to be unnecessary because of factors such as the following.
47
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• Damages and risks posed by oil and gas operations appear to be
linked, in the majority of cases, to violations of existing State
and Federal regulations. This suggests that implementation and
enforcement of existing authorities are critical to proper
management of these wastes. Significant additional environmental
protection could be achieved through a program to enhance
compliance with existing requirements.
• State programs exist to regulate the management of oil and gas
wastes. Although improvements may be needed in some areas of
design, implementation, or enforcement of these programs, EPA
believes that these deficiencies are correctable.
• Existing Federal programs to control underground injection and
surface water discharges provide sufficient legal authority to
handle most problems posed by oil and gas wastes within their
purview.
The Agency considers the imposition of full Subtitle C regulations
for all oil and gas exploration, development, and production wastes to be
impractical because of factors such as the following:
• EPA estimates that the economic impacts of imposition of full
Subtitle C regulations (excluding the corrective action and land
disposal restriction requirements), as they would apply without
modification, would significantly reduce U.S. oil and gas
production, possibly by as much as 18 percent.
• If reserve pits were considered to be hazardous waste management
facilities, requiring permitting as Subtitle C land disposal
facilities, the administrative procedures and lengthy application
processes necessary to issue these permits would have a drastic
impact on development and production.
• Adding oil and gas operations to the universe of hazardous waste
generators would potentially add hundreds of thousands of sites to
the universe of hazardous waste generators, with many thousands of
units being added and subtracted annually.
• Manifesting of all drilling fluids and produced waters offsite to
RCRA Subtitle C disposal facilities would pose difficult logistical
and administrative problems, especially for stripper operations,
because of the large number of wells now in operation.
48
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States have adopted variable approaches to waste management.
State regulations governing proper management of Federally exempt oil
and gas wastes vary to some extent to accommodate important regional
differences in geological and climatic conditions, but these regional
environmental variations do not fully explain significant variations in
the content, specificity, and coverage of State regulations. For
example, State well-plugging requirements for abandoned production wells
range from a requirement to plug within 6 months of shutdown of
operations to no time limit on plugging prior to abandonment.
Implementation of existing State and Federal requirements is a central
issue in formulating recommendations in response to Section 8002(m).
A preliminary review of State and Federal programs indicates that
most States have adequate regulations to control the management of oil
and gas wastes. Generally, these State programs are improving. Alaska,
for example, has just promulgated new regulations. It would be
desirable, however, to enhance the implementation of, and compliance
with, certain waste management requirements.
Regulations exist in most States to prohibit the use of improper
waste management practices that have been shown by the damage cases to
lead to environmental damages and endangerment of human health.
Nevertheless, the extent to which these regulations are implemented and
enforced must be one of the key factors in forming recommendations to
Congress on appropriate Federal and non-Federal actions..
49
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RECOMMENDATIONS
Following public hearings on this report, EPA will draw more
specific conclusions and make final recommendations to Congress regarding
whether there is a need for new Federal regulations or other actions.
These recommendations will be made to Congress and the public within
6 months of the publication of this report.
Use of Subtitle D and other Federal and State authorities should be
explored as a means for implementing any necessary additional controls on
oil and gas wastes.
EPA has concluded that imposition of full, unmodified RCRA Subtitle C
regulation of hazardous waste for all exempt oil and gas wastes may be
neither desirable nor feasible. The Agency believes, however, that
further review of the current and potential additional future use of
other Federal and State authorities (such as Subtitle D authority under
RCRA and authorities under the Clean Water Act and the Safe Drinking
Water Act) is desirable. These authorities could be appropriate for
improved management of both exempt and nonexempt, high-volume or
low-volume oil and gas wastes.
EPA may consider undertaking cooperative efforts with States to review
and improve the design, implementation, and enforcement of existing State
and Federal programs to manage oil and gas wastes.
EPA has concluded that most States have adequate regulations to
control most impacts associated with the management of oil and gas
wastes, but it would be desirable to enhance the implementation of, and
compliance with, existing waste management requirements. EPA has also
50
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concluded that variations among States in the design and implementation
of regulatory programs warrant review to identify successful measures in
some States that might be attractive to other States. For example, EPA
may want to explore whether changes in State regulatory reporting
requirements would make enforcement easier or more effective. EPA
therefore recommends additional work, in cooperation with the States, to
explore these issues and to develop improvements in the design,
implementation, and enforcement of State programs.
During this 'review, EPA and the States should also explore
nonregulatory approaches to support current programs. These might
include development of training standards, inspector training and
certification programs, or technical assistance efforts. They might also
involve development of interstate commissions or other organizational
approaches to address waste management issues common to operations in
major geological regions (such as the Gulf Coast, Appalachia, or the
Southwest). Such commissions.might serve as a forum for discussion of
regional waste management efforts and provide a focus for development and
delivery of nonregulatory programs.
The industry should explore the potential use of waste minimization,
recycling, waste treatment, innovative technologies, and materials
substitution as long-term improvements in the management of oil and gas
wastes.
Although in the near term it appears that no new technologies are
available for making significant technical improvements in the management
of exempt wastes from oil and gas operations, over the long term various
innovative technologies and practices may emerge. The industry should
explore the use of innovative approaches, which might include
conservation and waste minimization techniques for reducing generation of
drilling fluid wastes, use of incineration or other treatment
technologies, and substitution of less toxic compounds wherever possible
in oil and gas operations generally.
51
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EXECUTIVE SUMMARY
MANAGEMENT OF WASTES FROM GEOTHERMAL ENERGY
Under Section 3001(b)(2)(A) of the 1980 Amendments to the Resource
Conservation and Recovery Act (RCRA), Congress temporarily exempted
several types of solid wastes from regulation as hazardous wastes,
pending further study by the Environmental Protection Agency (EPA).
Among the categories of exempt wastes were "drilling fluids, produced
waters, and other wastes associated with the exploration, development, or
production of crude oil or natural gas or geothermal energy." Section
8002(m) of the 1980 Amendments requires the Administrator to study these
wastes and submit a final report to Congress. This report is in partial
response to those requirements.
STUDY APPROACH AND STUDY FACTORS
EPA has gone to great lengths to respond to all of the study factors
listed in the various paragraphs of Section 8002(m). Although each study
factor has been considered in arriving at the conclusions and
recommendations of this report, no single study factor has a determining
influence on the results. The following study factors are considered in
this report.
Defining exempt wastes: RCRA describes the exempt wastes in rather broad
terms. Where the legislative history does not provide guidance, EPA has
had to make assumptions and interpretations. These assumptions are set
forth in Chapter III.
Specifying the sources and volumes of exempt wastes: Statistics on the
volumes of exempt wastes from geothermal operations are not routinely
collected nationwide, causing EPA to develop estimates of the sources and
volumes of.all exempt wastes; these are presented in Chapter III.
Characterizing wastes: Analysis of the principal high volume exempt
wastes can help determine whether any of the wastes may be hazardous
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under the definitions of RCRA Subtitle C. This study is particularly
concerned with toxicity, the factor most likely to contribute to
potential health and environmental damage under field conditions.
Describing current disposal practices: Chapter IV summarizes EPA's
review of current disposal practices for exempt wastes. The principal
and common methods of managing field-generated wastes are listed,
described, and discussed in general and qualitative terms.
Documenting evidence of damage to human health and the environment caused
bv management of geothermal wastes: No significant damage cases were
found to have resulted from geothermal energy operations (see discussion
in Chapter V).
Assessing potential danger to human health or the environment from the
wastes: EPA has qualitatively assessed the risk associated with
geothermal operations, primarily by comparing the risk-influencing
factors at geothermal sites with those expected at oil and gas sites.
The results of the geothermal risk assessment, presented in Chapter VI,
are useful for characterizing the interactions of technological,
geological, and climatic differences as they influence the potential
damages.
Reviewing the adequacy of government and private measures to prevent
and/or mitigate anv adverse effects: Because it is impossible to compare
damages in any quantitative way to the presence and effectiveness of
control efforts, EPA has assessed current regulatory programs in a
qualitative manner (Chapter VII). The approach has been to review the
elements of existing regulatory programs so as to highlight areas of
coverage and approaches to implementation.
Defining alternatives to current waste management practices: Waste
management technology in the geothermal industry is fairly simple; there
are no significant "innovative" or "emerging" technologies. Utilizing
this background knowledge, Chapter IV addresses alternative waste
management practices and the basis for future improvements in waste
management.
Estimating the costs of alternative practices: Because the geothermal
industry is not considering alternative waste management practices, EPA
has postulated a number of alternative approaches, many of which are
simply more stringent applications of current practices. These
alternatives are presented in Chapter IV.
Estimating the economic impacts of alternative practices on industry:
The Agency's analysis of the potential economic impacts of nationwide
imposition of alternative practices is included in Chapter IV. However,
the price of fossil fuels and alternative fuels has a major influence on
the economics of the geothermal industry, and it is difficult to draw
conclusions concerning the impacts of modified waste management practices.
-------
DESCRIPTION OF THE GEOTHERMAL INDUSTRY
Geothermal Exploration and Development Operations
The category of geothermal energy receiving the most attention is
hydrothermal systems because the technology is available to economically
extract energy from these systems. The locations of hydrothermal and
geopressured resource areas are shown in Figure 1.
Geothermal Well Drilling
Rapid, low-cost surface reconnaissance techniques are employed in the
early stages of geothermal exploration to screen large land areas for
commercial potential. Surface reconnaissance may include geophysical,
geological, geochemical, and remote-sensing surveys. Wells are drilled
Only after potential geothermal resources are identified. Table 1
presents data on the locations of geothermal drilling activities in the
United States during the years 1981 through 1985.
Dril1 ing Mud
Methods and equipment used for geothermal well drilling are similar
to those used in the petroleum industry. The drilling fluid, usually
mud, is a formulation of clay and chemical additives in a water base.
Drilling mud serves multiple purposes. It cools and lubricates the drill
bit, flushes rock chips from the borehole, and helps prevent blowouts.
liquid-dominated geothermal systems are usually drilled with conventional
drilling muds. Compressed air rather than mud is sometimes used as the
circulating mediur.i for vapor-dominated systems because water-based muds
can solidify and .lamage the producing formation. After drilling
operations are completed, the used drilling fluids constitute the major
waste source.
-------
Ft.
-------
Table 1 Summary of Geothermal Drilling Activity by
State from 1981 to 1985, Including
Production, Injection, and Wildcat Wells
Number of wells
1981
1982
1983
1984
1985
Total
Alaska
California
Colorado
Hawaii
Idaho
Louisiana
Montana
New Mexico
Nevada
New York
Oregon
Texas
Utah
Washington
Total
-
55
1
2
6
1
-
6 .
14
-
3
-
-
2
90
4
67
-
1
-
-
1
3
2
1
-
1
2
_!
, 83
-
47
-
-
3
-
1
3
4
-
1
1
1
~
61
4
88 64 321
1
3
9
1
2
12
3 3 26
1
1 5
2
2 - 5
3
93 68 395
Source: Williams 1986.
-------
Electrical Power Production Operations
The high-temperature steam found in vapor-dominated hydrothermal
systems can be used directly to generate electricity. The steam provides
direct power to drive the turbine generator. Hot, saline waters found in
liquid-dominated geothermal systems can be converted to steam by a flash
process, or can transfer heat to a secondary working fluid with the
binary process.
The flash process uses the conventional steam cycle in which
geothermal brine is converted ("flashed") to steam. Hot liquid brine is
partially evaporated to steam by a sudden reduction of pressure in the
system. The steam is then fed directly into the turbine.
The binary process is a simple binary cycle conversion consisting of
three fluid loops: a geothermal fluid loop, a hydrocarbon working fluid
loop, and a cooling water loop. Geothermal fluid is withdrawn from the
reservoir into the production well. The fluid then passes through two
parallel brine/hydrocarbon heat exchangers. The hydrocarbon vapor
expands through the turbine, driving the electric generator.
Direct Use of Geothermal Energy
Heat exchangers are used to extract geothermal energy for direct
use. Downhole heat exchangers consist of one- or two-tube loops
suspended in the wellbore, in direct contact with the hydrothermal
fluid. Water inside the heat exchanger cycles thermally, eliminating the
need for fluid disposal. Surface heat exchangers require the extraction
of geothermal fluid from the reservoir. Subsequently, they need some
means of disposing of the spent fluid or brine.
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IDENTIFICATION AND CHARACTERIZATION OF EXEMPT WASTES
Exempt versus Nonexempt Wastes
EPA has tentatively identified those waste streams resulting from
geothermal exploration, development, and production operations that are
exempt under RCRA 3001(b)(2). Exempt waste streams include: waste
streams produced from materials passing through the turbine in dry-steam
power generation; waste streams resulting from a geothermal fluid or gas
that passed through the turbine in flashed-steam and binary power plants;
waste streams resulting from the geothermal products, passing through
only the heat exchanger in binary operations or through the flash
separator in the flash process; and most direct use waste streams.
Exempt wastes include: drilling media and cuttings; fluids from
geothermal reservoirs; piping scale and flash tank solids; precipitated
solids from brine effluent; settling pond wastes; hydrogen sulfide
wastes; cooling tower drift; and cooling tower blowdown. Nonexempt
wastes include: wastes originating in the electric generator, waste
lubricants, waste hydraulic fluids, waste solvents, waste paints, and
sanitary wastes.
Geothermal Exploration and Development Waste Volumes
Well-drill ing activities generate the bulk of the wastes from
geothermal exploration and development operations. In general, exempt
wastes from well drilling are drilling muds and drill cuttings, which are
generated in large quantities during drilling operations. Documentation
of the volumes of drilling muds and cuttings generated is very sparse.
Because of this scarcity of data, a methodology was developed to estimate
waste volumes of drilling muds and cuttings. Cuttings volumes for
specific geothermal areas were calculated from the number of wells in the
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area and the average depths and diameters of the wells. An associated
mud volume was computed from this calculation, based upon a
cuttings/drilling mud conversion or correlation factor derived from
site-specific drilling information. Table 2 summarizes the estimated
cuttings and drilling mud waste volumes for the years 1981 through 1985.
Geothermal Power Plant Waste Volumes
Wastes generated from geothermal power production include spent
brine, flash tank scale, separated solids from pre-injection treatment of
spent brines, and hydrogen sulfide abatement wastes.
Liquid Waste Estimation
Very little information describing and quantifying these wastes was
found in the literature review. Brine flows for both binary and flash
power production processes were calculated from equations derived from a
plot of hydrothermal fluid requirements versus fluid temperature. An
annual operating factor of 90 to 95 percent was applied to the da'ily flow
throughput to obtain brine volume for individual facilities (Table 3).
Solid Waste Estimation
No attempt was made to quantify the solid waste generated from power
generation facilities because data are limited. Based on the review of
the literature, several facilities in California are the sole source of
any significant generation of solids.
Waste Generation from Direct Users
The primary waste generated from using geothermal energy as a direct
source of heat is the spent geothermal fluid remaining after usable heat
-------
Table 2 Estimated Waste Volumes for Drilling Activities
Associated with Exploration and
Development of Geothermal Resources
Total mud and cuttings volume
California
The Geysers
Imp. Valley
Other
Nevada
Idaho
Montana
New Mexico
Oregon
Washington
Utah
Hawaii
Total U.S.
(thousands of barrel
1981
97.3
49.8
47.2
0.3
7.2
0.6
NA
2.8
0.3
0.2
NA.
5.1
113.5
1982
103.8
59.5
43.3
1.0
1.0
NA
0.1
1.4
0.1
0.1
2.3
2.5
111.3
1983
51.2
46.2
3.9
1.1
2.0
0.3
0.1
NA
0.1
NA
1.2
. NA
54.9
s)
1984
198.9
52.2
145.6
1.1
1.0
NA
NA
NA
NA
NA
2.3
NA
202.2
1985
109.3
53.4
55.1
0.8
1.5
NA
NA
NA
0.1
NA
NA
NA
110.9
NA - No Activity.
Source: See Appendix A.
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Table 3 Estimated Liquid Waste Volumes from Both
Binary and Flash Process Plants*
Bill ions of
State Number of sites gallons per year
California 9 43.70
Nevada 5 9.26
New Mexico 1 .24
Hawaii 1 .06
Utah _2 3.17
Total 18 56.43
*Plants that are currently operational; does not include the estimated
volume for three facilities under construction.
Source: See Appendix A.
10
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has been extracted. The quality of the spent geothermal fluids is often
high enough that these fluids can be discharged into nearby surface water
bodies and even into community water supplies. Waste generated by direct
applications was calculated similarly to waste quantities from power
generation facilities. Industrial direct users were estimated to be
operating about 80 percent of the year. All other types of direct users
were estimated to operate 25 percent of the year or less. Table 4 shows
estimated liquid waste volumes for 104 direct users in 12 States.
Waste Characterization
Analytical data found in the literature for both liquid and solid
wastes were summarized and compared to current RCRA characteristic
thresholds for those wastes.
Ltquid Wastes
Liquid wastes of selected waste streams from geothermal plants, power
generation, and direct use of geothermal energy were analyzed for
temperature, pH, and chemical constituents. For facilities using the
binary and flash processes, the concentration levels of various
constituents were measured for the incoming brine, with the exception of
temperature, which was the measured discharge value. Geothermal liquids
from several test wells were also tested for major and trace
constituents. Contaminants from the RCRA extraction procedure (EP)
toxicity test for determining whether a waste is hazardous were included
in the chemical analyses.
Sol id Wastes
Preliminary analyses have been performed on solid wastes from several
geothermal operations. Concentrations for major constituents were
11
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Table 4 Estimated Liquid Waste Volumes Resulting
from Direct Use of Geothermal Energy
Billions of
State Number of sites gallons per year
California 18 1.41
Oregon 14 .60
Idaho 27 3.02
Montana 7 .09
South Dakota 4 .78
Utah 4 .31
Wyoming 3 .15
New Mexico • 8 .50
Nevada 10 .61
Colorado 6 .50
New York 1 .01
Washington 2 .10
Totals . 104 8.09
Source: See Appendix A.
12
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analyzed for total constituent content, neutral and acid extractable
values, pH, percent moisture, and radium concentrations. Trace
constituents were also analyzed, including the eight EP toxicity
contaminants.
Analysis of Waste Constituents
Analyses of the constituents from several exempt geothermal waste
streams indicate that some of the wastes failed the EP characteristics
test and could be considered hazardous wastes. The hazardous
characteristics present include corrosivity and EP toxicity for certain
metals. Sufficient data are not presently available to accurately
characterize or precisely quantify the volumes of wastes generated from
power production and drilling activities related to geothermal
operations. Data are also insufficient to project future total volumes
of wastes expected to be generated by the geothermal industry. To
predict future waste disposal requirements and associated potential
problems, information must be obtained concerning volume,
characteristics, and chemical constituents of mud pit solids, drill
cuttings, and injected fluids.
WASTE MANAGEMENT PRACTICES
Current Management Practices for Waste Products from Drilling
Operations
The primary wastes from both geothermal and petroleum industry
drilling activities are drilling muds and drill cuttings. Methods
currently practiced by the geothermal industry for handling and disposing
of these materials have largely been developed by the petroleum
industry. In most cases, wastes from geothermal drilling activities are
discharged into a reserve pit. Wastes can then be collected for offsite
13
-------
disposal or the reserve pit can be dewatered and backfilled. Any
remaining liquids are allowed to evaporate during dewatering and before
backfilling. Associated with this method, however, is the potential for
future contamination that could result from leachate waste sludge which
remains buried at the site. A vacuum truck is used to remove the waste
from the reserve pit and transport it to an offsite pit.
Landfarming is another reserve pit disposal option: This practice
involves the mechanical distribution and mixing of reserve pit waste into
soils in the vicinity of the drill site.
Stringent permitting requirements and State prohibitions limit the
downhole disposal of drilling wastes. This method is not particularly
effective for geothermal drilling operations and might actually have an
adverse effect on the development of the geothermal well.
Solidification of reserve pit wastes typically involves mixing fly
ash or kiln,dust with the wastes to decrease the overall moisture content
and to stabilize the mixture. This method may be economically more
attractive than backfilling the reserve pit wastes; however, there may be
associated problems with leaching of constituents into ground water.
Practices for Power Generation Facilities
The literature describes seven types of liquid waste disposal for
power generation facilities, four of which are being practiced or will be
implemented at facilities that are currently operational or under
construction.
Direct release of liquid wastes to surface waters is the simplest
disposal method. This method consists of discharging spent fluid to
local drainage systems. Current environmental constraints, however, have
14
-------
made this method almost nonexistent for facilities in the United States.
Treatment and release to surface waters can be a relatively simple
process, but it can become costly, depending on the type of treatment
required. No power facilities were identified as using this type of
brine treatment. In closed-cycle ponding, spent brine is cycled through
one or more ponds to induce evaporation. While the practice is not in
use at present, it does have potential application in arid climates.
The injection of liquid wastes into the producing horizon is
necessary to maintain reservoir fluid volumes. It is the most frequently
used liquid waste management practice for U.S. power generation
facilities. Injection into a nonproducing zone is used where the
production zone can be easily contaminated by the cooler injection
fluid. This method involves drilling the injection well to a zone that
is separated from the production well. The method has been tested
successfully at one Utah facility. The treatment and injection method is
used where brine quality may cause plugging or when a usable byproduct
could be recovered from the brine. Several examples of pretreatment to
prevent plugging are currently operational in the United States.
Consumptive secondary use is effective when the spent fluid can be
reused as part of the power generation process or by some adjacent
facility (i.e., used as makeup water to the cooling towers). Several
facilities currently practice this disposal method.
Solid wastes can be managed by onsite or offsite disposal, or the
solids may accumulate in brine holding ponds onsite; then the material is
excavated and hauled to a landfill.
Practices for Direct Users
Only four of the liquid waste disposal methods for power generation
facilities are utilized by direct users. These include: direct release
15
-------
to surface waters, injection of liquid wastes into the producing horizon,
injection into a nonproducing zone, and consumptive secondary use.
Direct release to surface waters is the most common method of liquid
waste disposal for direct users. The practice is safe and effective
because of the low flow rates and the high quality of the geothermal
fluid that is discharged. Injection of liquid wastes into the producing
horizon is the second most common method of liquid disposal, whereas
injection into a nonproducing zone is currently used at only one
location. Consumptive secondary use is practiced at two locations where
liquid wastes are discharged into holding basins and collected for
irrigation.
Alternative Waste Management Practices
Although several refinements to existing processes have been
mentioned in the literature, very little information is available on new
disposal methods. Alternative, more stringent disposal methods might be
developed if damage cases resulting from geothermal wastes begin to occur.
If alternative methods are developed, liquid wastes that are
currently injected into Class V wells most likely would be injected into
Class II wells. Solid nonhazardous wastes would be disposed of offsite
in Class II or III waste management units, while facilities could
landfarm, dispose of wastes offsite in Class I facilities, or solidify
solid-designated wastes. Solid hazardous wastes could be disposed of
through solidification. The Aquatech proprietary evaporation process is
a new liquid waste disposal method. Small direct users could use this
method if their flow rates are less than 16,800 gallons per day.
16
-------
Economic Analysis of Waste Management Practices
The geothermal industry is not pursuing alternatives to the current
practices of disposing of geothermal energy wastes. Nevertheless, some
available cost data are presented and the gross cost impacts of the more
likely alternative practices have been calculated. This analysis is
limited to residual drilling wastes, however, because they comprise most
of the exempt wastes. Although alternative treatment and disposal
methods are not being pursued by the geothermal industry at present,
alternative practices may be required in the future. The costs of
several waste management practices for drilling wastes are presented in
Table 5.
Under current energy market conditions, future development will be
restricted to expanding existing economic fields. When existing older
plants reach the end of their economic life and are phased out,
geothermal electrical power generation capacity may actually decrease.
Poor economics and higher economic risk may preclude the construction of
new facilities in the current energy market. The future profitability of
the geothermal industry is tied directly to the price of energy available
from other sources, primarily hydrocarbon fuels. When the price of these
fuels rises again, the level of new geothermal field development will
increase as well.
DAMAGES CAUSED BY GEOTHERMAL OPERATIONS
No significant cases of damages were found associated with the
exploration, development, or production of geothermal energy. The lack
of significant damage cases indicates that existing regulatory programs
are probably effective.
17
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Table 5 Total Annual Cost of Alternative Waste Management Practices3
(In 1985 dollars, based on 1985 waste volumes)
Location
Waste management alternative
One-quarter acre, unlined surface impoundment
One-quarter acre, single-lined, surface impoundment
Fifteen acre, single-lined, surface impoundment
Fifteen acre, triple-lined, surface impoundment
Thirty-five acre, pre-interim status landfarm
Thirty-five acre. Part 264 compliance landfarm
b,c
Solidification
The Geysers Imperial Valley Other
$ 108,936 $ 112.404 $ 4,896
238,164 245,746 10,704
55,536 57,304 2,496
363,120 374,680 16,320
853,866 881,049 38,376
1,942,692 2,004,538 87,312
320,400 330,600 14,400
transportation cost excluded from all alternatives.
Final disposal cost not included.
C8ased on an average cost of $6 per barrel.
18
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RISK ASSOCIATED WITH GEOTHERMAL OPERATIONS
For the geothermal energy industry, a qualitative analysis rather
than a quantitative risk modeling analysis was conducted. EPA has
determined that the quantity and quality of data available do not warrant
quantitative risk modeling at this time. The risk assessment report on
the oil and gas industry prepared by EPA is based primarily on
quantitative risk modeling. Because the waste types and waste management
practices for the two industries are similar, EPA used the initial risk
results for oil and gas activities as a reference for a qualitative
assessment of the potential risks posed by the geothermal energy model
facilities.
Characterization of Major Risk-Influencing Factors
The two large-volume waste types associated with geothermal drilling
(i.e., exploration and development) and production are drilling pit
wastes (drilling mud and well cuttings) and production waste fluids.
Produced fluid wastes can be divided into two categories—power plant
fluids and direct user fluids.
Waste Streams
Power plant wastes are categorized according to the processes used to
convert geothermal energy into electric power: the conventional steam
cycle, the binary process, and the flash process. In the conventional
steam cycle process, the waste is generated downstream of the turbine
when exhaust steam is condensed in direct contact condensers or in
surface condensers located beneath the turbine.
In the binary process, hot geothermal fluids heat and vaporize a
hydrocarbon heating medium. The hydrocarbon vapor then drives the power
19
-------
turbine. All fluid wastes produced are generated upstream of the
turbine. Table 6 includes two model waste streams developed from
produced fluid analyses from five binary process power plants. The first
model waste stream contains the median concentration of each constituent
in the five analyses and may be considered a "best estimate." The second
stream may be considered a conservative waste stream because it is
composed of the highest concentration of each constituent in the produced
fluid analyses. Two constituents, benzene and arsenic, were not found in
the geothermal fluid analyses, unlike the oil and gas model waste
streams. Trace analyses of samples from several test wells, however,
suggest that arsenic is likely to be present in these waste streams as a
trace constituent.
In the flash process, steam is produced by subjecting fluids produced
from a liquid-dominated reservoir to a sudden pressure reduction. The
loss of some water to steam concentrates the dissolved solids in the
remaining geothermal fluid. This remaining fluid is generated upstream
of the power turbine and is an exempt waste. A waste stream analysis of
the exempt fluid waste produced from one flash process power plant was
used to analyze the risk associated with fluids produced from flash
process power plants in general (Table 6). Although arsenic levels are
not reported in the major constituent analysis, test well analyses
indicate that arsenic is likely to be present in these wastes. The
levels of arsenic may be higher in the waste stream than are shown in the
test well analyses because flashing concentrates the dissolved solids in
the fluid.
Direct User Fluid Wastes
Based on chemical analysis data, the produced fluid wastes from
direct user applications generally contain lower levels of chemical
constituents than do fluids from power plants. Table 6 shows the range
20
-------
Table 6 Model Production_Flu id Waste Stream Analyses
Model oil and gas waste
stream concent rat ions (mq/L)
Model geothermal power plant
waste stream concentrations (mq/L)
Geothermal direct user
operation waste stream
concentrations (mq/L)
Waste stream
constituent
Median
Upper 90th %
Binary process Binary process Flash
best estimate3 conservative3 process
Range
Median
IX)
Arsenic
Benzene
Boron
Chloride
Sodiurn
Mobile Salts6
0.0
0.5
9.9
7.300
9.400
23.000
1.7
2.9
120.0
35.000
67.000
110,000
NAU
NA
5.0
865
653
1.694
NA
NA
49
9.000
4.720
14.842
NA
NA
210
93.650
36.340
153.198
NA
NA
0.0 - 277
0.0 - 11.000
4.0 - 7.000
8.6 - 20.568
NA
NA
0.6
58
195
474
Based on produced fluid analyses of samples from five binary process power plants.
Based on the produced fluid sample analysis from a flash process power plant.
C6ased on produced fluid sample analyses from 43 direct user operations in 13 States identified in the literature.
NA - Not available. In the case of arsenic, however, trace analyses of samples from several test wells suggest that arsenic is
present in produced geothermal fluids.
BMobile Salts = Na + Cl + K + Mg + Ca + S04.
-------
of concentrations and the median concentration of each major constituent
found in analyses of produced fluids from 43 direct user operations in
13 States.
Drilling Pit Solid Wastes
Two model waste streams were characterized from analyses of drilling
pit solid wastes from eight sites (Table 7). The first waste stream is a
"best estimate" composed of the median concentration of each constituent;
the second is a "conservative" model waste stream characterized by the
maximum concentration of each constituent. Although arsenic
concentrations are not given, extract analyses show the presence of
arsenic in some geothermal drilling pit wastes.
Waste Management Practices
Waste management practices for the geothermal energy industry were
characterized based on data compiled from a review of the literature and,
in a few cases, data collected during site visits. When data were not
available on the basic design, operating parameters, and/or unit
size/waste throughput, EPA characterized waste management practices with
the values used for similar practices in the oil and gas risk analysis.
Production Fluid Wastes — Power Plants
Methods currently used to dispose of produced fluids from geothermal
energy power plants include direct release to surface waters, injection
(or treatment and injection) into underground strata, and consumptive
secondary use. Of the waste management practices in current use,
injection is the most frequently employed. Injection is the primary
geothermal fluid disposal method for 21 of the 23 operating power plants
that generate exempt wastes. Because the overwhelming majority of power
22
-------
Table 7 Drilling Pit Solid Wastes: Bulk Composition
Model oil and gas waste
stream concentrations
fl
Pit solids - Direct (mq/kq) Geothermal energy drilling sites (mq/kq)
Waste stream
constituent Median Upper 90th X A B C D E FGH
Arsenic 0 0.01 NAb NA NA NA NA NA NA NA
Cadmium 2 5.4 NA NA NA NA NA NA NA NA
Sodium 8.500 59,000 7,700 4,000 20,000 12.500 2.400 900 1,100 1,900
-o
~° Chloride 17.000 88.000 9.800 1,000 53,000 20,000 1,000 100 100 400
Fluoride c c 240 340 290 420 230 180 240 150
Chromium VI 22 190 NA MA NA NA NA NA NA NA
Mobile
Saltsd 100,000 250.000 32.600 36.700 111.600 77.000 27.800 33.200 26.300 31,600
Best
estimate Conservative
NA NA
NA NA
3.200 20.000
1.000 53.000
235 420
NA NA
32.900 111.600
The constituent concentrations in waste streams A through H are based on analyses of drilling pit wastes at eight geothermal energy industry drilling
sites These drilling sites are associated with geothermal energy power plants. The best-estimate waste stream comprises the median concentration of each
constituent in waste streams A through H. The conservative waste stream comprises the highest concentration of each constituent in waste streams
A through H.
bNA = Not available.
Fluoride was not a model constituent in the oil and gas study.
dMobile Salts = Na + C1 + K + Mg + Ca + S04.
-------
generation facilities dispose of produced fluid wastes by underground
injection, EPA analyzed the risks associated with this waste management
practice at power plants. The two key variables that influence the risk
posed by injection of wastes are injection rate per well and injection
pressure.
Based on the limited data on injection rates and numbers of wells
available for a few sites, EPA estimated the injection rate per well for
a flash process facility and for a binary power plant. The estimated
injection rates per well for binary process plants and flash process
plants are 950 Mgal/yr and 610 Mgal/yr, respectively. Because no data
were available on geothermal field injection pressures, EPA evaluated the
potential risk posed by the reinjection of geothermal wastes for
injection pressures ranging from 400 to 2,000 psi (taken from the modeled
oil and gas scenarios).
Production Fluid Wastes—Direct Users
The primary disposal method for produced fluid wastes from direct
users is direct discharge to surface water. The vast majority of these
operations are covered under NPDES permits. Because these releases are
regulated and permitted under a Federal program other than RCRA, they are
not within the scope of this study. Injection is the second most
frequently employed geothermal fluid waste management practice for direct
users. For direct users injecting geothermal fluid wastes, the annual
waste generation rate per facility ranges from 9 to 500 Mgal/yr; the
median rate is 55 Mgal/yr. These fluid rates could be handled by one
injection well at each site. Assuming one injection well at each site,
the median rate was used to evaluate the potential risk from direct user
injection. The injection pressure was assumed to vary between 400 and
2,000 psi, which is the same pressure used in the analysis of power
plants.
24
-------
Drilling Pit Solid Wastes
Data on the waste management practices for geothermal drilling wastes
were not available to determine the one most frequently employed.
Consequently, EPA elected to characterize model geothermal sites by the
same disposal methods that are used to characterize the oil and gas
sites. These methods are onsite burial of dewatered drilling pit solid
wastes in unlined and synthetically lined pits. The two risk-influencing
variables modeled for onsite reserve pits in the oil and gas analysis
were pit size and the presence or absence of synthetic liners. The
average volume of geothermal drilling waste per pit is 3,200 barrels,
which falls between the medium-sized (5,900 barrels) and small-sized
(1,650 barrels) oil and gas drilling pits modeled. Risks were evaluated
for both the unlined and synthetic-lined pits modeled.
Environmental Settings
Based on previous risk analyses, EPA identified the following
environmental variables as having significant potential for influencing
risks resulting from waste releases to ground and surface water:
hydrogeologic variables, surface water variables, and exposure point
characteristics. The distributions of values for each variable within
20 geothermal field sites were analyzed to develop a best-estimate (most
common) environmental setting and a conservative (but not worst-case)
setting. Table 8 lists the values of the environmental variables for
each setting.
Qualitative Risk Assessment Results
Underground Injection of Produced Fluids
There are at least four release pathways whereby underground
injection of produced fluids can lead to contamination of near-surface
25
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Table 8 Environmental Settings at Geothermal Energy Facilities
Environmental variable
Ground-Water Velocity
Aquifer Configuration
Recharge Rate
Depth to Ground Water
Unsaturated Zone Permeability
Distance to Nearest Downgradient
Drinking Water Well
Distance to Surface Water
Average Surface Water Flow Rate
Distance to Nearest Downstream
Surface Water Intake
Values
Best estimate
100 m/yr
Unconfined
1 in/yr
20 m
10"2 cm/sec
> 2,000 m
> 2,000 m
0
10 kmb
for variables
Conservative
1 m/yr
100 m/yr
1,000 m/yra
Unconfined
20 in/yr
5 m
10~2 cm/sec
200 m
60 -m
40 cfs
1 kmb
aA range of velocities was examined to analyze the range of risks caused by
different chemical constituents in the conservative setting. For some
constituents, a slow velocity is conservative (i.e., yields higher risk
results), while for other constituents, a fast velocity is conservative.
DBecause of lack of data, these assumed values were chosen to reflect a
reasonable range of distances.
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aquifers: (1) release through failure of the well casing; (2) release
through failure of grout seals separating injection zones from
near-surface aquifers; (3) upward contaminant migration through abandoned
wells; and (4) upward contaminant migration through fractures or faults.
Because of technical constraints and data limitations, however, only
releases through failure of the well casing and releases through failure
of grout seals separating injection zones from near-surface aquifers are
considered here.
Power Plants
At the majority of existing geothermal power plants (roughly
70 percent), an injection well failure that releases produced fluids into
near-surface aquifers would not be expected to pose significant human
health risks because few drinking water wells are within 2,000 meters in
a downgradient direction. The potential for exposure is much greater,
however, at the few facilities estimated to have private drinking water
wells within 2,000 meters downgradient.
Injection well failures associated with geothermal power plants could
-4
result in cancer risks ranging from zero to approximately 10 , if the
geothermal produced fluids have the same arsenic concentrations estimated
for oil and gas industry produced fluids. Injection well failures at a
few power plants could also result in sodium concentrations in
downgradient drinking water wells that are high enough to cause
hypertension in sensitive individuals. Produced fluids from the flash
process have significantly higher sodium concentrations than do fluids
from the binary process, and therefore pose a greater risk for
hypertension.
The relatively high concentrations of chloride, boron, and mobile
salts in geothermal produced fluids from power plants, and the relatively
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high rate at which these fluids are injected, create the potential for
injection well failures to damage ground-water resources. It is
presently uncertain, however, how far these contaminants could migrate in
ground water before dilution would cause the concentration to drop below
levels of concern. Results from the oil and gas modeling study suggest
that releases of produced fluids from the binary process could result in
harmful concentrations up to 60 meters away, while releases of produced
fluids from the flash process could result in harmful concentrations at
an even greater distance.
Direct Users
When downhole heat exchangers are used by direct users, the need for
fluid disposal is eliminated and the potential for adverse health or
environmental impacts is very small. At direct-use facilities using
surface heat exchange systems, the potential for geothermal fluids to
cause adverse health and environmental effects is considered small
because they are unlikely to come in contact with people or biota.
Available data on the composition of produced fluid disposed of by direct
users are presently insufficient, however, to estimate quantitatively the
potential for adverse effects. In general, if an injection well failure
occurred during direct user operations, the magnitude of resulting
impacts is expected to be smaller than that associated with similar
releases from power plants. The principal health threats probably would
be the potential for cancer and hypertension caused by ingestion of
ground water contaminated with arsenic and sodium, respectively.
Concentrations of chloride, boron, and mobile salts could also render
ground water in the vicinity of releases unsuitable for certain uses.
Onsite Reserve Pits — Solid Drilling Wastes
Because most geothermal power plants do not have private drinking
water wells within 2,000 meters, seepage of reserve pit contaminants into
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surface aquifers at most plant sites would not be expected to pose a
significant health risk. Even at those plants where drinking water wells
may be within range to be affected, seepage of reserve pit contaminants
is expected to cause very low risks of cancer. Results from the oil and
gas modeling study indicate that cancer risk caused by the leachate
should be zero in most cases, and probably never more than 10" .
Reserve pit seepage appears to present a greater potential for
noncarcinogenic risk. For a few of the oil and gas scenarios that
reasonably represent conditions that exist at geothermal power plants,
sodium concentrations in downgradient drinking water wells were predicted
to exceed a threshold that could cause hypertension in sensitive
individuals. Reserve pits at geothermal power plants should not cause
significant ground-water resource damage. Because concentrations of the
main constituents of concern appear to be lower in geothermal reserve
pits than in oil and gas reserve pits, ground-water contamination
resulting from geothermal reserve pits would probably be even less.
(Concentrations of drilling waste contaminants in ground'water were
predicted to be below levels of concern 60 meters away from most oil and
gas reserve pits.)
Conclusions
Because of the lack of reliable data on the composition of geothermal
energy waste streams, strong conclusions about the risk associated with
these wastes cannot be drawn at this time. Conclusions have been based
on comparisons with the oil and gas risk analysis and on the waste .
management practices and environmental settings expected at geothermal
sites.
• Of the 20 or so U.S. geothermal power plants, it was estimated
that 13 currently have no drinking water wells within 2,000 meters
downgradient. As a result, even if produced fluid or drilling
waste contaminants were released to near-surface aquifers at the
majority of these power plants, the potential for adverse health
effects is small, because it is unlikely that an individual would
ingest ground water contaminated by such a release.
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If geothermal produced fluids have an arsenic concentration
similar to that estimated for oil and gas produced fluids, releases
from failed injection wells at geothermal power plants could cause
cancer risk levels greater than 10"** in a few cases. (It is
emphasized, however, that arsenic concentrations in geothermal
produced fluids are unknown.) Risk levels of concern would be
expected primarily at sites having nearby drinking water wells
(e.g., within approximately 200 meters) and relatively high
ground-water velocities (e.g., 100 to 1,000 meters/year).
If an injection well failure released geothermal produced fluids
into a near-surface aquifer, resulting sodium concentrations in
downgradient drinking water wells could exceed levels that may
cause hypertension in sensitive individuals. This noncancer risk
is greatest for releases of produced fluids from flash process
power plants, which appear to have much higher sodium
concentrations than geothermal produced fluids from plants using
the binary process. Greater noncancer risks would be expected at
sites having nearby drinking water wells (e.g., within
approximately 200 meters) and relatively slow ground-water
velocities (e.g., 1 to 10 meters/year).
Adverse health and environmental impacts from injection well
failures (if they occur) at direct user sites could be similar in
nature to those expected from injection well failures at power
plants; this is highly unlikely, however, as water quality is
generally better in direct use operations. Because direct users
dispose of smaller volumes of waste by underground injection,
injection well failures at direct user sites would be expected to
release smaller quantities of contaminants than do releases from
power plants. Although releases from direct users would probably
occur closer to drinking water wells, drinking water wells in the
vicinity of direct use operations often tap the same aquifer.
Therefore, waters having similar qualities are used for domestic
use and direct use applications.
If injection well failure occurred at geothermal power plants or
direct user sites, released produced fluids could sufficiently
contaminate surrounding ground water to render it unsuitable for
certain uses. In particular, chloride concentrations could result
in objectionable taste (making it unsuitable for drinking), and
resulting concentrations of mobile salts could be harmful to
sensitive crops (making it unsuitable for irrigation). In most
cases, concentrations of concern are not expected to be exceeded
60 meters downgradient, although there could be instances in which
potentially harmful concentrations exist farther away.
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• Based on the limited information available on the composition of
wastes from geothermal well drilling, seepage of drilling waste
contaminants from geothermal reserve pits would be expected to
cause only minor (if any) cancer risk, noncancer risk, and
ground-water resource damage.
CURRENT REGULATORY PROGRAMS
Federal Regulations
Regulatory Agencies
The Geothermal Steam Act of 1970, as amended (U.S.C. 1001-1025),
authorizes the U.S. Department of the Interior to issue leases for the
development and use of geothermal resources. The implementing
regulations (43 CFR, Part. 3200) are now administered almost exclusively
by the Bureau of Land Management (BLM). The BLM may issue leases on
Federal lands under its jurisdiction and on lands administered by the
U.S. Forest Service, with the consent of the latter. In addition, the
BLM evaluates and classifies geothermal resources on Federal land and
supervises all pre- and post-leasing operations, including exploration,
development, and production.
Geothermal Resources Operational Orders
Geothermal Resources Operational (GRO) Orders are formal, enforceable
orders, originally issued by the U.S. Geological Survey, to supplement
the general regulations found in 43 CFR, Part 3200. They detail the
procedures that lessees must follow in a given area or region.
Geothermal Resources Order No. 1 outlines the BLM requirements for
conducting exploratory operations on Federal lands. Standards for
drilling, completion, and spacing of wells are set forth in GRO Order
No. 2. Geothermal Resources Order No. 3 regulates plugging and
abandonment procedures. GRO Order No. 4 requires the lessee to comply
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with all applicable Federal and State standards with respect to the
control of air, land, water, and noise pollution, including the control
of erosion and the disposal of liquid, solid, and gaseous wastes. The
lessee is required by GRO Order No. 4 to provide and use pits and sumps
to retain all wastes generated during drilling, production, and other
operations, unless other specifications are made by the Authorized
Officer.
Underground Injection Control Program
The Safe Drinking Water Act of 1974, as amended, requires EPA to
establish a national program to ensure that underground injection of
wastes will not endanger underground sources of drinking water. EPA
implemented this mandate by enacting the Underground Injection Control
(UIC) Program for Federal, Indian, State, and private lands. EPA has
primary enforcement authority and responsibility for the program for all
States, except for those that have approved UIC programs. Geothermal
injection w.ells are considered Class V under the UIC classification
system; this class includes electric power industry injection welts,
direct heat user injection wells, heat pump and air conditioning return
flow wells, and ground-water aquaculture return flow wells. The BLM
defers to EPA or the primacy State the task of determining whether
underground freshwater sources are safe from the effects of these
operations. .
Summary of State Requirements
Regulatory Requirements
State rules and regulations obtained from 35 States have been
examined for their applicability to geothermal energy exploration and
development. Thirteen State legislatures have passed laws mandating the
implementation of geothermal rules and regulations. Typically, these
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regulations are very comprehensive and, in general, address permitting,
solid and liquid waste disposal, well design, well plugging, and
restoration of surface. The requirements of the 13 States that have
specific geothermal regulations are summarized in Chapter VII. The
geothermal regulations of California are presented in greater detail
because they are considered "model regulations" for geothermal operations
and because of the extensive use of geothermal resources in California.
CONCLUSIONS •
• There is no record of significant damages, danger, or risks to
human health and the environment resulting from the exploration,
development, and production of geothermal energy.
• Geothermal operations are regional by nature, with the bulk of
activities confined to California.
• Existing regulations appear to be effective in protecting human
health and the environment.
• There is no indication that additional Federal regulations are
necessary.
RECOMMENDATIONS
EPA recommends that Subtitle C regulations not be applied to
geothermal wastes. Further, at present, the Agency sees no need for
additional regulations under Subtitle 0.
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