United States
Environmental Protection
Agency
Office of Solid Waste
and Emergency Response
Washington D.C. 20460
October 1986
EPA/530-SW-86-051
Solid Waste
Technical Report
Wastes from the
Exploration, Development
and Production of Crude
Oil, Natural Gas and
Geothermal Energy
An Interim Report
on Methodology
for Data Collection
and Analysis
U.S. Environmental Protection Agency
Region 5, Library (PL-12J)
77 West Jackson Boulevard, 12th Floor
Chicago, tL 60604-3590
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TABLE OF CONTENTS
Page No.
Part I: Oil and Gas Extraction
General Introduction. 1
Chapter 1 Overview of the Oil and Gas Industry and Waste
Generation 1-1-1
Industry Profile 1-1-1
Exploration and Development Operations 1-1-2
Production Operations 1-1-12
Waste Generation 1-1-27
Literature Review 1-1-28
Exploration and Development Wastes 1-1-34
Production Wastes 1-1-41
References 1-1-49
Chapter 2 Industry Waste Management Practices 1-2-1
Introduction ........ 1-2-1
Current Industry Waste Management 1-2-3
Onsite Methods of Waste Disposal , 1-2-3
Centralized Methods 1-2-18
Land Application 1-2-27
Subsurface Disposal . . 1-2-29
Ocean Discharge 1-2-35
Construction and Monitoring Requirements 1-2-41
Introduction 1-2-41
Pit Design and Construction 1-2-43
Examples of Drilling Pit/Impoundment Permit
Requirements 1-2-48
Evaluation of Waste Management Methods 1-2-54
References 1-2-58
Chapter 3 Estimating the Costs of Alternative Waste Management
Practices 1-3-1
Introduction and Overview 1-3-1
Estimation of Costs for Individual Current and
Alternative Waste Management Practices 1-3-4
Earthen Pit Storage and Disposal 1-3-5
Disposal in Lined Pits (with Installation of
an Impermeable Cap at Site Closure) 1-3-7
Monitoring and Site Management Practices 1-3-8
Offsite Disposal in a Secure Facility (i.e., Those
Employing Multiple Liner Systems and Other
Controls) 1-3-10
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TABLE OF CONTENTS (continued)
Page No.
Estimation of Waste Transportation Costs for
Centralized Disposal 1-3-12
Class II Injection Wells 1-3-14
Plans for Adapting EPA Cost Models and for Original
Cost Estimation 1-3-15
Identify Incremental Actions and Costs 1-3-16
Develop Regional and Aggregate National-Level
Cost Estimates 1-3-17
References 1-3-19
Chapter 4 Impact of Waste Management Scenarios on Petroleum
Exploration, Development, and Production 1-4-1
Introduction and Overview 1-4-1
Model Project Analysis 1-4-2
Identification of Model Projects 1-4-2
Establishing Representative Cases 1-4-3
Environmental Control Costs 1-4-6
Marginal Economic Cases 1-4-6
Economic Parameters of Model Projects 1-4-7
Marginal Economic Cases 1-4-10
Model Project Simulations 1-4-11
Corporate and Industry-Level Impacts 1-4-12
Industry-Wide Assessment 1-4-13
Financial Assessment for Representative Companies... 1-4-14
Impact on Industry Exploration, Development, and
Production 1-4-15
References 1-4-17
Part II: Geothermal Energy
Chapter 1 Industry Description II-l-l
Background II-l-l
The Nature and Occurrence of Geothermal Energy Systems II-1-2
Hot Igneous Systems II-1-4
Conduction-Dominated Systems II-1-4
Hydrothermal Systems II-1-6
Vapor-Dominated Reservoirs II-1-7
Liquid-Dominated Reservoirs II-1-9
The Geographic Distribution of Geothermal Energy
Systems II-l-ll
Exploration of Geothermal Resources II-l-ll
Preliminary Exploration II-l-ll
Geothermal Well Drilling II-1-13
Drilling Fluids (Muds) II-1-16
Distribution of Geothermal Drilling Activity II-1-19
-11-
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TABLE OF CONTENTS (continued)
Page No.
Electrical Power Generation II-1-19
Current and Planned Development II-1-24
Direct Use Applications II-1-24
Chapter 2 Waste Generation II-2-1
Waste Sources II-2-1
Drilling Wastes II-2-1
Drilling Fluid Waste II-2-2
Deck Drainings Wastes II-2-2
Drilling Fluid Cooling Tower Wastes II-2-3
Miscellaneous Small Waste Streams II-2-3
Waste Streams from Power Plants and Direct Users II-2-3
Electric Power Generation II-2-3
Reinjection Well Fluid Wastes II-2-4
Piping, Production Well Filter Waste, Scale Waste,
and Flash Tank Solids II-2-7
Brine Effluent Precipitated Solids II-2-7
Settling Pond Solids II-2-8
Cooling Tower Drift and Slowdown. II-2-9
Direct Steam Usage II-2-9
Waste Characterization, Composition, and Volumes...... II-2-9
Waste Streams from Electric Power Generation and
Direct Users II-2-10
Drilling Wastes 11-2-17
Production Waste II-2-17
Data Needs II-2-19
Chapter 3 Waste Management II-3-1
Chapter 4 Cost of Current and Alternative Disposal Practices.... II-4-1
Development of Estimates II—4—2
Bottom-up Technique 11-4-2
Parametric Technique II-4-2
Specific Analogy Technique II-4-3
Cost Review and Update Technique II-4-3
Factored Cost Technique II-4-3
Chapter 5 Economic Impacts of Alternative Methods of Treatment
and Disposal II-5-1
-111-
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TABLE OF CONTENTS (continued)
Part III: Case Damages
Page No.
Chapter 1 Introduction III-l-l
Chapter 2 Approach for Collecting Damage Cases III-2-1
Specification of Information Types Required III-2-1
Identification of Case Study Information Sources III-2-2
Specification of Procedures for Collecting Data III-2-4
Specification of Criteria for Classifying Cases III-2-6
Chapter 3 Application of Damage Case Results..- III-3-1
Part IV: Risk Assessment
Chapter 1 Introduction IV-1-1
Chapter 2 Overview of the Risk Assessment Approach IV-2-1
Overview of the Risk Assessment Methodology IV-2-1
Alternative Methodologies Considered IV-2-5
Chapter 3 Input Data for the Analysis IV-3-1
Chapter 4 Industry Characterization and Classification IV-4-1
Waste Generators IV-4-1
Waste Stream Types IV-4-2
Waste Treatment, Storage, and Disposal Practices/
Release Sources IV-4-4
Environmental Settings for Release Sources IV-4-5
Climate IV-4-6
Hydrogeology IV-4-7
Surface Water IV-4-9
Human Exposure Points IV-4-11
Environmental Exposure Points IV-4-12
Chapter 5 Exposure Pathway Analysis and Model Scenario
Development IV-5-1
Chapter 6 Development and Refinement of Modeling Techniques IV-6-1
Contaminant Release to Ground and Surface Waters IV-6-1
Underground Injection Wells IV-6-2
Surface Pits IV-6-3
Effluent Point Sources IV-6-4
-iv-
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TABLE OF CONTENTS (continued)
Page No.
Contaminant Transport and Fate IV-6-4
Ground Water IV-6-4
Surface Water IV-6-6
Exposure and Health Risks IV-6-8
Cancer Risks IV-6-8
Chronic Noncancer Health Risks IV-6-8
Environmental Damage IV-6-8
Chapter 7 Analysis of Scenarios IV-7-1
APPENDIX A
APPENDIX B
-v-
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Introduction
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GENERAL INTRODUCTION
Regulatory Background
Under Section 3001 (b)(2)(A) of the 1980 amendments to the Resource
Conservation and Recovery Act (RCRA), Congress temporarily exempted
several types of solid wastes from regulation as hazardous wastes, pending
further study by the Environmental Protection Agency (EPA). Among the
categories of wastes exempted were "drilling fluids, produced waters, and
other wastes associated with the exploration, development, or production
of crude oil or natural gas or geothermal energy."
Section 8002(m) of the amendments required the Administrator of EPA to
conduct a study and submit a final report to Congress by October 1982.
EPA did not conduct the study.
In its study of these wastes. Congress directed EPA (through RCRA
section 8002(m)) to consider:
is also required to make regulatory determinations affecting the
oil and gas and geothermal energy industries under several other major
statutes. These include designing appropriate effluent limitations
guidelines under the Clean Water Act, determining emissions standards
under the Clean Air Act, and implementing the requirements of the
underground injection control program under the Safe Drinking Water Act.
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1. The sources and volumes of discarded material generated per year
from such wastes;
2. Present disposal practices;
3. Potential danger to human health and the environment from the
surface runoff or leachate;
4. Documented cases that prove or have caused danger to human health
and the environment from surface runoff or leachate;
5. Alternatives to current disposal methods;
6. The cost of such alternatives; and
7. The impact of those alternatives on the exploration for, and
development and production of, crude oil and natural gas or
geothermal energy.
In August 1985, the Alaska Center for the Environment sued EPA (Alaska
Center for the Environment v. Lee Thomas) for its failure to conduct the
study. EPA then signed a consent order obligating it to submit the final
Report to Congress on or before August 31, 1987. In the interim, the Agency
must meet several requirements by specific dates. One such milestone is to
complete the present Technical Report by October 31, 1986.
All of the information and methods presented in this Technical Report are
preliminary and subject to revision. Comment.? are solicited and encouraged
on any portion of the document.
Pursuant to the consent degree, EPA is preparing a separate technical
report that will characterize wastes associated with oil and gas extraction.
Information and analytical data necessary for waste characterization were
collected in a nationwide screening sampling program that lasted from June
through September of 1986. This information is now being interpreted and
compiled and will be formally released, as required by the consent decree, in
January of 1987.
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Wastes Included Under the Exemptions
The legislative history of Section 3001(b)(2)(A) sheds some light on the
identity of oil and gas and geothermal energy wastes subject to exemption:
The term "other wastes associated" is specifically included to designate
waste materials intrinsically derived from the primary field operations
associated with the exploration, development, or production of crude oil,
natural gas, or geothermal energy. It would cover such substances as
hydrocarbon-bearing soil in and around facilities; drill cuttings;
materials (such as hydrocarbon, water, sand, and emulsion) produced from a
well in conjunction with crude oil, natural gas, or geothermal energy; and
the accumulated material (such as hydrocarbon, water, sand, and emulsion)
from production separators, fluid treating vessels, storage vessels, and
production impoundments.
The phrase "intrinsically derived from the primary field operation ..." is
intended to differentiate exploration, development, and production
operations from transportation (from the point of custody transfer or of
production separation and dehydration) and manufacturing operations.
Floor commentary on the exemptions consists of only a few brief
statements of general support. The speakers note that muds and brines are
exempted, and also specify that geothermal energy must be treated in a
manner consistent with oil and gas extraction (125 Congressional Record,
June 4, 1979).
Since the exact identity of the wastes exempted affects the scope of
the present study, EPA has relied on RCRA's language and the legislative
history to develop tentative criteria for determining which wastes are
included:
Conference Report, 96th Congress, 2nd Session 32 (1980)
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1. Only waste streams intrinsic to the exploration for, or development
and production of, crude oil, natural gas, or geothermal energy are
subject to exemption. Waste streams generated at oil, gas, and
geothermal energy facilities that are not uniquely associated with
exploration, development, or production activities are not exempt
(one example would be spent solvents from equipment cleanup).
2. Exempt wastes must be associated with "extraction"^ processes,
which include measures (1) to remove oil, natural gas, or
geothermal energy from the ground or (2) to remove impurities from
such substances, provided that the purification process is an
integral part of normal field operations.*
3. The proximity of waste streams to primary field operations is a
factor in determining the scope of the exemption. Process
operations that are distant from the exploration, development, or
production operations may not be subject to exemption.
4. Wastes associated with transportation are not exempt. The point of
custody transfer, or of production separation and dehydration, may
be used as evidence in making this determination.
As shown on Table 1, EPA has used these criteria to tentatively
designate various wastes as exempt or not exempt. The Agency is aware
that this table does not include all waste streams found at oil, gas, or
geothermal extraction facilities. Therefore, EPA invites commenters to
specifically describe other affected waste streams and to articulate, in
terms of the above criteria, whether or not these additional streams are
or are not subject to the Section 3001(b)(2)(A) exemption. EPA also
invites comment on the criteria themselves and on the appropriateness of
the tentative classifications shown on Table 1.
term extraction is defined to include, exploration, development,
and production activities for oil, gas, and geothermal energy.
4Thus, wastes associated with such processes as oil refining,
petrochemical-related manufacturing, or electricity generation from
geothermal energy are not exempt.
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Table l
Wastes Considered Exempt Under Section 3001(b)(2)
Oil and Gas
Geothermal Energy
Drill ing media
Drill cuttings
Well completion, treatment,
and stimulation fluids
Packing fluids
Produced waters
Produced sand
Workover fluids
Field tank bottoms
Waste crude oil and waste
gases from field operations
Waste triethylene glycol used
in field operations
Drill ing media and cuttings
Reinjection well fluid wastes
Piping scale and flash tank solids
(except for those associated with
electrical power generation)
Precipitated solids from brine effluent
Settling pond wastes
Wastes Considered Not Exempt Under Section 3001 (b)(2)
Oil and Gas
Geothermal Energy
Waste lubricants
Waste hydraulic fluids
Waste solvents
Waste paints
Sanitary wastes
Refining wastes
Waste motor oil
Wastes resulting from the generation
of electricity, such as:
- hydrogen sulfide wastes
- cooling tower drift
- cooling tower blowdown
Waste lubricants
Waste hydraulic fluids
Waste solvents
Waste paints
Sanitary wastes
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Structure of This Report
Part I of this Technical Report presents an overview of the oil and
gas extraction industry and describes EPA's proposed methodology for
addressing the study areas mandated by RCRA Section 8002(m).
Part II of this report provides an overview of the geothermal energy
industry and describes potential sources of wastes. It also identifies
additional information needed to address RCRA's mandates.
Part III presents a methodology for collecting and presenting
documented cases of damage caused by wastes associated with oil, gas, or
geothermal energy extraction.
Part IV presents a methodology for preparing a risk assessment of the
potential danger to human health and the environment from improper
management of wastes from the oil, gas, and geothermal energy extraction
industries.
Appendix A of this report summarizes State and Federal regulations
currently affecting the oil and gas extraction industry. Summaries of
State and Federal regulations affecting geothermal energy extraction have
not yet been developed, but will be included in the Report to Congress due
on August 31, 1987.
Appendix B of this report contains a brief glossary of terms and list
of abbreviations relevant to the present report.
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Parti
Oil and Gas
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CHAPTER 1
OVERVIEW OF THE OIL AND GAS INDUSTRY AND WASTE GENERATION
INDUSTRY PROFILE
The onshore oil and gas industry is responsible for the exploration,
development, and production of petroleum resources in the United States.
Petroleum is a complex mixture of hydrocarbons occurring in the earth as
gases, liquids, and solids. For the purposes of this discussion, oil is
defined as crude petroleum oil and other hydrocarbons, regardless of
gravity, which are produced at the wellhead in liquid form. Natural gas is
any hydrocarbon fluid that is produced in a natural state from the earth
and which maintains a gaseous state at 16°C (60°F) and standard
atmospheric pressure. Gas liquids are the liquid hydrocarbons known as
"natural gasoline" recovered from natural gas. In general, petroleum is a
liquid (crude oil) that is recovered from within the earth through drilled
bore holes. Liquid and gaseous petroleum occurs naturally underground,
primarily in the pore spaces of sedimentary rocks.
Chemically, crude oil is composed of carbon and hydrogen
(approximately 82-87 percent carbon, 12-17 percent hydrogen). Lesser
quantities of sulfur, oxygen, and nitrogen organic compounds account for
the balance of material. Crude oils are also classified as paraffins—
organic compounds containing methyl-CH. structure, napthenes—organic
compounds with C H, structure, and aromatics with C H_
n 2n n 2n-6
1-1-1
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structure. (The n denotes the number of carbon atoms in the hydrocarbon
molecule.) A number of inorganic substances are also commonly found in
crude oil. Sodium chloride, usually found dissolved in crude oil, comes
from the aqueous medium which nearly always coexists underground with
petroleum. Lesser quantities of free sulfur, hydrogen sulfide, and
carbonyl sulfide also are found. Two metals—nickel and vanadium—are
common to crude oils; these metals are present as metal porphyrins.
As of 1983, the earth's verified petroleum reserves totaled
9
approximately 600 x 10 barrels (Kirk-Othmer, 1985). However, the rate
of discovery of large petroleum reserves has steadily declined for the
past four decades. Future demands will be met through exploration and
discovery of new fields—operations that will become more costly as fewer
and fewer reserves are located—and through the development of new
extraction techniques to recover portions of crude petroleum left behind
by conventional extraction methods. All of these elements will result in
higher crude oil prices in the future.
Exploration and Development Operations
Exploration operations are those activities occurring in the search
for petroleum in areas previously undeveloped with regard to petroleum
reserves. These operations include activities associated with locating
potential petroleum reserves (such as seismic exploration), well drilling,
well stimulation, well completion, and/or well abandonment. Development
operations are similar to exploratory operations except that developmental
operations occur in the attempt to establish productive wells in areas
known to contain petroleum reserves. Developmental operations are
conducted in known reservoirs or oil fields, with the objective of further
enhancing the productivity of an area. The vast majority of well drilling
operations in the United States is developmental activity.
1-1-2
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Petroleum is found and recovered on all of the earth's continents
except Antarctica. In the United States, the first onshore oil well was
drilled by Col. E. T. Drake near Titusville, Pennsylvania, in 1859. Drake
struck oil at 69-1/2 feet from the surface. Since then, approximately 2.7
million oil and gas wells have been drilled in the United States.
Drilling activity in the United States is almost entirely limited to
32 States. As shown in Figure 1-1, these States are grouped by
petroleum-bearing basins, which are contiguous between many States.
Alaska and California are notable exceptions.
From 1980 to 1986, onshore drilling activity proceeded at a rate
averaging 80,000 wells per year {Oil and Gas Journal, 1985). However, in
1986 the worldwide drop in oil prices caused drilling activity to decrease
by almost 50 percent (Oil and Gas Journal, 1986b). New wells range in
depth from several hundred feet to over 20,000 feet.
Well Drilling
Rotary Mud Drilling. During the last five decades, rotary drilling
has become the predominant drilling technique. A sketch of a typical
rotary drilling rig is given in Figure 1-2. Essentially, the bit and the
drill pipe suspended above the bit are slowly rotated, gouging and
chipping away the rock at the bottom of the well. As the well becomes
deeper, additional sections of pipe are added. An advantage of rotary
drilling is that it minimizes loss of crude oil and gas. The drill core
is circulated with a weighted drilling fluid (called drilling mud) that
serves as a pressure seal for the well. As a rotary well is drilled, mud
is circulated down the drill pipe where it picks up cuttings and carries
them up the hole to the surface. At the surface, mechanical devices
separate the mud from cuttings. The mud is recirculated; cuttings are
1-1-3
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fluid* tot
_ • downhole injection
" .,» • centralized pit for long term itorage
'" '*'^ • centralized treatment and discharge
> •£•• • »°t>ile treatment and discharge
• • landspreading or landfarming
Figure 1-2. Drillino Onpration
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displaced (with associated mud) into an earthen reserve pit. The reserve
pit receives this mixture (and all the chemicals associated with these
wastes) and rig deck drainage. Depending on the site, it may also receive
sewage and other wastes. The following pits usually are associated with
rotary mud drill sites: reserve pit(s), emergency pit, and/or fresh water
pit (or tank). Most States have construction requirements or guidelines
for these pits; many States have specific pit reclamation requirements
(see Appendix A).
Rotary drilling techniques make it possible to drill wells over 20,000
feet deep. A recent development in rotary drilling has involved a fluid
powered turbine at the bottom of the bore hole to provide the rotary
motion of the bit. In this method, the drill pipe does not rotate, but is
used to weight the bit and carry the drilling mud to turn the turbine.
Pneumatic Drilling. Pneumatic drilling is another boring method used
in the Appalachian Basin, in southeastern Kansas/northeastern Oklahoma, in
the four corners area of the southwest, and in the Rocky Mountain States
(see Figure 1-1). Pneumatic drilling may be favored over rotary drilling
when the underlying formations are hard rock or in shallow locations where
the use of fluids to maintain subsurface pressure is not required. In
these circumstances, pneumatic drilling is considerably faster and less
Special chemical fluids are introduced into the bore hole to
lubricate the action of a rotary bit, to remove the cuttings, and to
prevent blow-outs. Drilling muds circulate continuously down the
drill pipe, into the bore hole, and upwards between the drill pipe
and the walls of the hole to a surface pit, where they are purified
and recycled. The composition of drilling muds may vary. They can
be oil or water base; all contain high concentrations of solids such
as barite, calcium carbonate, or clays. The mud is maintained as a
suspension with emulsifiers, wetting agents, and other specialty
chemicals.
1-1-6
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expensive than rotary mud drilling. In pneumatic drilling, air usually is
the drill medium. Compressed air drives the drill bit and lifts cuttings
back to the surface. Once the cuttings reach the surface, water is
injected into the cuttings return line for dust control. This slurry of
cuttings and water is deposited into an earthen waste pit at the drill
site. When fluids are encountered during pneumatic drilling, foaming
agents are used to bring the fluids to the surface. The fluid and foaming
agents are also displaced into the waste pit. The pit may subsequently be
treated with defoamants.
Cable-Tool Drilling. Early oil and gas wells were drilled with impact
tools by a method called cable-tool drilling. In this drilling method, a
chisel-like bit is suspended from a cable to a lever on the surface, and
an up-and-down motion of the lever causes the bit to pound the bottom of
the hole and chip away the rock. These wells must be free of liquids
during the drilling process so that the bit can remove waste rock. When
the bit penetrates the gas or oil formation, large quantities of gas and
oil can flow rapidly ("blowout") to the surface. This "gusher" appearance
gives the impression of a successful well when, in fact, these materials
are wasted and can contaminate much of the surrounding countryside.
(Drilling without protection against blowouts is now prohibited by State
regulations.)
Well Logging
After the bore hole has penetrated the petroleum-bearing formation,
the formation must be tested to determine if expensive completion
procedures (described below) should be used. These evaluations are made
with well logging measurement instruments that can detect the differences
in rock, water, and petroleum. Only a production test can establish the
1-1-7
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potential productivity of a well. In this test—called a "drill stem"
test - the bore hole is sealed above and below the petroleum formation,
with only the drill pipe open to the formation. The drill pipe is then
emptied of the drilling mud so that the crude oil can enter. After a time,
the openings to the drill pipe are closed and fluids are brought to the
surface. The fluids are then analyzed to determine their hydrocarbon
content and quality. If there is gas in the formation, the gas will flow
from the top of the drill pipe during the test.
Well Completion
If preliminary tests show that one or more of the formations in the
bore hole will be commercially productive, the well must be prepared for
the continuous production of the oil or gas. First, a large outside pipe,
or casing, slightly smaller in diameter than the drill hole, is inserted
to the full depth of the well. A cement slurry is forced between the
outside of the casing and the inside surface of the drill hole. When set,
this cement forms a seal so that fluids cannot communicate from one
portion of the well to the other through the bore hole. In the
continental U.S., the casing is usually about 23 centimeters (9 inches) in
diameter. It creates a permanent well through which the productive
formations may be reached. After the casing is in place, a production
string of smaller (8 centimeters, or 3 inches in diameter) tubing is
extended from the surface to the productive formation. A packing device
is used to seal the productive interval from the rest of the well. If
multiple productive formations are found, as many as four production
strings of tubing may be hung in the same cased well.
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Since the casing is sealed against the productive formation, openings
must be made to allow the oil or gas to enter the well. A down-hole
perforator uses an explosive to shoot holes through the casing and cement
and into the formation. The perforating tool is lowered on a wire line.
When it is in the correct position, the charges are triggered electrically
from the surface. Such perforating will be sufficient if the formation is
quite productive. If not, well stimulation techniques (described below)
may be used to encourage production.
When the subsurface equipment is in place, a network of valves (called
a "wellhead" or "Christmas tree") is installed on the surface and arranged
so that flow from the well can be regulated and measured, and tools to
perform subsurface work can be introduced through the tubing. The
wellhead may be very simple, such as might be found on a low-pressure well
that must be pumped, or it may be very complex, as in the case of a
high-pressure well with multiple producing strings. Figure 1-3 shows a
wellhead.
Well completion fluids and well treatment fluids are generated during
the processes described above. These wastes may include muds, additives,
and hydrocarbons.
Well Stimulation
After drilling is completed, well stimulation techniques may be
performed to enhance production. Acidizing is one of the original well
stimulation techniques still in modern use. The first and by far the most
successful well stimulation acidizing technique uses hydrochloric acid
introduced into the petroleum-bearing formation. Hydrochloric acid
1-1-9
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WELL HEAD
CONNECTIONS
SURFACE PIPE
CEMENTED
TUBING
OIL SAND
V ••!-•- INTERMEDIATE STRING
•'M^ CEMENTED
•PACKER
12.- OIL STRING CEMENTED
Source:
Figure 1-3.
API. 1983.
Production well
Introduction to Oil and
B°°k X of Vocational
pp. 8, 19.
1-1-10
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stimulation is used in dolomite and limestone formations. Hydrochloric
acid treatment produces carbon dioxide, calcium chloride, and/or magnesium
chloride.
Another acid treatment uses a solution of hydrochloric and
hydrofluoric acids to stimulate wells in sandstone formations. In this
instance, sodium fluoride is an additional reaction product. Other
acidizing systems include:
• Organic acids - formic and acetic acid (usually used in
combination with hydrochloric or hydrofluoric);
• Powdered acids - sulfamic acid, chloroacetic acid; and
• Retarded acid systems - gelled acids, chemical retarded
acids, emulsified acids.
Other chemical agents that are added to petroleum wells to maintain or
increase well productivity are the following:
• Corrosion inhibitors - to reduce the attack of acid on
metal. Some of these contain arsenic compounds; many
contain organic compounds.
• Surfactants - to demulsify acid and oil, reduce
interfacial tension, alter formation wettability, speed
cleanup, prevent sludge formation.
• Friction reducers - to minimize pumping energy.
Usually these are organic polymers added to the
stimulation fluids (guar, cellulose, fatty acids).
• Acid flow-loss additives - Composed of solid particles
that enter formation pores, and a gelatinous material
to plug pores, silica fluor, calcium carbonate,
polyvinyl alcohol, polyacrylamide.
• Diverting agents - to direct stimulation fluids.
1-1-11
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• Complexing agents - to solubilize iron and other pipe
or metal corrosion products that might precipitate.
Most satisfactory product is ethylene diamine
tetracetic acid (EDTA).
• Cleanup additives - to cleanse the well of the reactor
products and unusual reagents after acid treatment.
These products are flushed with water and removed by
use of nitrogen gas. Alcohols and wetting agents are
added to ease these tasks (Williams, et al., 1979).
All water-soluble reagents, sludges, and organic residue will
eventually be pumped from the well to the surface. In general, these
wastes are displaced into a holding pond for treatment and disposal.
Production Operations
Production operations include all activities associated with the
recovery of petroleum from geologic formations. Production operations are
delineated into those activities associated with downhole operations (such
as petroleum recovery techniques, workovers, and well stimulation
techniques), and those activities associated with surface operations (such
as oil/gas/water separation and treatment of oil, gas, gas liquids, or
produced water).
In the United States, approximately 28 billion barrels of crude oil
had been discovered as of December 1985. Less than one-half of these
reserves will ultimately be recovered with existing technology and
economic conditions. Unfavorable reservoir geology, adverse fluid
properties, or low oil content in the reservoir rock limit recovery
prospects for petroleum resources.
1-1-12
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By 1984, there were 864,405 producing onshore oil and gas wells in the
g
United States. These wells yielded 3.09 x 10 barrels of crude oil and
19 x 106MM cubic feet of gas annually (Kirk-Othmer, 1985; IOCC,
1985).
Approximately 70 percent of the total number of oil wells in the
United States are "stripper wells." Stripper wells are defined as those
oil wells that produced less than 10 barrels of oil per day (44 FR
22069).
In addition to this production, the United States must import crude
oil to augment its productive capacity.
Table 1-1 presents 1984 onshore oil and gas production data for each
State as reported by the Interstate Oil Compact Commission. The table
contains each State's 1984 annual oil and gas production, total number of
oil and gas wells, and number of stripper wells (IOCC, 1985; IOCC/NSWA,
1985).
Water is produced along with crude petroleum and/or natural gas. This
water, called "produced water" or "brine," is an aqueous solution
containing many dissolved chemicals, minerals such as sodium chloride and
dissolved hydrocarbons. It can present major disposal difficulties. In
several western States, produced water may be a vital source of water for
livestock, which can tolerate higher sodium chloride concentrations than
humans.
The crude oil production unit has traditionally been the barrel,
which is equivalent to 0.159M3, 42 U.S. gallons, or 5.61 ft3.
1-1-13
-------
TABLE 1-1
ONSHORE OIL AND GAS PRODUCTION - 1984
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Total #
Oil Wells
797
864
26
9r490
48,908
5,287
0
0
165
0
0
0
28,920
6,792
0
57,633
19,980
28,068
0
0
0
4,881
0
3,569
557
4,665
2,072
34
0
0
24,954
4,678
0
4,026
26,878
99,030
0
20,739
Annual
Production
MM BBL/YR
24.0
631.0
0.2
18.5
411.7
38.6
0
0
17.2
0
0
0
28.9
5.4
0
96.7
11.8
604.7
0
0
0
40.5
0
33.5
0.1
30.7
6.6
2.0
0
0
129.9
1.0
0
58.7
15.3
207.5
0
4.8
*
Gas Wells
659
81
5
2,492
1,220
4,665
0
0
0
0
0
0
157
1,194
0
12,680
9,013
16,815
0
9
0
510
0
715
0
2,152
18
0
0
0
17,523
3,800
0
58
27,846
23,647
6
24,050
Annual
Production
MMSCF Gas
130,080
300,046
225
162,678
470,124
271,544
0
0
15,404
0
0
0
1,530
394
0
466,590
61,518
5,867,511
0
20
0
144,695
0
210,393
0
56,895
2,347
0
0
0
965,717
27,000
0
80,596
186,480
1,996,713
2,790
166,342
*
Strippers
98
—
14
4,738
26,650
1,690
0
0
165
0
0
0
29,942
6,134
0
45,749
16,433
16,500
0
—
0
3,500
0
1,923
548
3,085
1,700
—
0
0
14,749
4,532
0
1,061
25,129
82,431
—
19,540
1-1-14
-------
TABLE 1-1 (Continued)
ONSHORE OIL AND GAS PRODUCTION - 1984
Annual Annual
Total I Production # Production #
Oil Wells MM BBL/YR Gas Wells MMSCF Gas Striroers
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Totals
0
0
141
775
203,178
1,862
0
35
0
15,475
0
12,463
636,942
0
0
0.7
0.9
1186.1
39.0
0
0.3
0
10.0
0
143.4
3799.4
0
0
41
726
43,174
728
0
499
0
30,700
0
2,280
0
0
2,468
5,023
6,753,889
99,800
0
8,928
0
143,731
0
600,137
0
0
30
744
162,855
400
0
32
0
15,200
0
5,020
227,463 19,201,608 493,844
(—) No Data
Sources: Interstate Oil Compact Commission, The Oil and Gas Compact Bulletin.
Vol. XLIV, No. 2. December 1985; Interstate Oil Compact Commission
and the National Stripper Well Association, National Stripper Well
Survey. January 1, 1985; Oklahoma City: Interstate Oil Compact
Commission, October 1985.
1-1-15
-------
Downhole Production Operations
Oil and Gas Recovery Techniques. Conventional primary and secondary
recovery processes produce about one-third of the original oil
discovered. These techniques are described below. Recovery efficiency is
a result of a variation in the properties of the specific rock, the
properties of the petroleum fluid involved from reservoir to reservoir,
and the recovery technique(s) employed.
In all petroleum recovery methods, aqueous solutions are produced and
must be treated, stored, recycled, or disposed of.
Primary oil and gas recovery. "Natural drive" production relies on
natural reservoir pressure to drive the oil through the complex
rock pore network to the producing wells. The driving pressure is
derived from the expansion of liquid and the release of dissolved
gas from the oil as the pressure of the well decreases during
production. Also affecting the flow is the expansion of free gas
or "gas cap," the influx of natural water, and gravity.
Eventually, the natural pressure lowers to a point at which added
pressure must be applied to the well to produce significant amounts
of oil and gas.
Many oil wells do not have a formation pressure high enough to push
the head of oil standing in the well to the surface. In these
cases, some artificial method for lifting the oil must be
installed. The most common installation involves a motor and
"walking beam" (like a seesaw) on the surface that operates the
pump on the bottom of the production string. A chain of solid
metal rods connects the beam and the pump. Another method, called
gas lift, uses the buoyancy of a bubble of gas in the tubing to
push the oil to the surface. A third type of artificial lift
forces some of the produced oil down the well at high pressure to
operate a pump at the bottom of the well. Even though initially an
oil field may have enough pressure to produce naturally, artificial
lift will usually be required in later stages of production. Gas
wells that produce little or no liquid do not need artificial lift
devices (see Figures 1-4 and 1-5).
1-1-16
-------
ARTIFICIAL LIFT
WALKING
EQUALIZER
•EARING
EQUALIZER
ION SOCKET
TOWARD LONG ',
f MO OF CRANK
WASINO HEAD
SAMSON I
POST
MIME
MOVER
COUNTER
WEIGHT
BOLT
Figure 1-4. The major parts of a
conventional crank counterbalanced
beam pumping unit are shown in this
drawing. All units are not exactly
like this one, but they operate
generally in the same way.
POLISHED ROD CLAMP-
POLISHED MOO •
STUFFING SOX '
TEE-
TUBING RING ^J
SUCKER MOO
FLUID LEVEL
(IN ANNULUS)
ROD PUMP r—T-*
. "• • •
MUD ANCHOR •*<«•:
CASING
PERFORATIONS
• CARRIER BAR
FLOWUNE
CASINO HEAD
CASINO STRINGS
TUS4NO STRING
P
SUMFACE CASINO
\\
PRODUCTION CASING
TIMING
MOO
PMOOUCINO ZONE
Source: API. 1983. Intro-
duction to Oil and Gas Production.
Book 1 of Vocational Training
Series, Pp. 8, 19.
Figure 1-5. This sketch shows the
principal items of wellhead and down-
hole equipment installed for a typical
sucker rod pumping system.
1-1-17
-------
• Secondary oil and gas recovery. Secondary oil recovery involves
the injection of gas or water into the petroleum-bearing formation
around producing wells. The injected fluids maintain reservoir
pressure and displace a portion of the remaining crude oil to the
production wells (see Figure 1-6).
Water flooding is the leading secondary recovery method and
accounts for a very large part of all U.S. oil production. Fresh
water or treated produced water is usually used as the flooding
liquid. The use of natural gas for secondary recovery is limited
because of its cost. Natural gas has a high market value and would
only be used when water is not available.
• Tertiary oil and gas recovery. Tertiary (or enhanced) oil recovery
is the recovery of the very last segment of oil that can be
economically produced from the petroleum reservoir over and above
what has already been economically recovered by conventional
primary and secondary methods. Tertiary recovery operations
generate wastes similar to other oil and gas field operations.
Tertiary recovery can be divided into the following techniques or
methods: chemical, miscible, and thermal. All of these methods
involve injection of a solution or gas into the rock formation to
direct the crude oil to the well from which it is recovered (DOE,
1984).
The chemical methods of enhanced recovery include polymer flooding,
surfactant flooding, and alkaline flooding. Each method is usually
tied to a specific set of formation and crude oil conditions.
Polymer flooding is simple and inexpensive; it is in fairly
extensive commercial use. Surfactant flooding is expensive and
still in the laboratory testing stages. Alkaline flooding fills a
need in formations containing higher acid crude oils.
Miscible oil recovery involves formation flooding with
gases—carbon dioxide, nitrogen, or a hydrocarbon gas such as
propane. The specific application of these techniques is the
recovery of low viscosity crudes. Hydrocarbon flooding has been
commercially available since the 1950s. Carbon dioxide and
nitrogen flooding are more recent developments.
Thermal recovery methods include steam injection and in situ
combustion ("fire flooding"). Steam processes are most often
applied to formations containing viscous crudes and tars. In situ
combustion remains a terminal recovery technique because it burns
out the hydrocarbons as the firefront advances through the
formation. However, in situ combustion can yield up to 4 barrels
of crude for each barrel burned.
1-1-18
-------
M
I
M
VO
PRODUCED FLUIDS fOIL. OAS. WATER!
SEPARATION AND
STORAGE FACILITIES
PRODUCTION WELL
INJECTION WELL
WATER
INJECTION
PUMP
I I I I I I I I I I
^^^^*W*^B—^^^^^^^^^^^^^^^^^^^^^^^^*"^^" ^^^^^« • ^^^^^^^|^^^«^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^^-^^B
OIL ZONE
DRIVE WATER
SOURCE: Admttd fcoM origM drawing* by Jo* B. Undtoy. U.S. O**rtm** el Eiwrgy.
Enwoy TKhnotogy C«rtw
Figure 1-6
-------
Workover Operations. As a well continues to produce crude oil and/or
natural gas, its production may begin to decrease and may even cease.
There are many geological and man-made reasons for this nonproductivity.
Workover operations are operations on a producing well to restore or
increase production. Producing wells need a workover operation when there
has been a mechanical failure or a blockage from corrosion products or
sand.
A typical workover cleans out a well that has sanded up. The tubing
is pulled, the casing and bottom of the hole are washed, out with mud, and,
in some cases, explosives are set off in the hole to dislodge the silt and
sand (Williams and Meyers, 1984).
Workover operations generate cleaning fluids, packing fluids, bailing
fluids, and deck drainage that must be disposed of.
Well Stimulation Techniques. The well stimulation techniques
discussed in the Industry Profile, Exploration and Development Operations,
and Well Stimulation sections, are equally applicable to production well
enhancement. Well stimulation wastes may include acids, additives, and
other wastes as discussed above.
Surface Production Operations
Surface production operations generally include transport of the well
fluids (oil, gas, gas liquids, water) from the wellhead or from a group of
wells to a facility that separates the fluids and treats them prior to
sale. The separation facility is called a lease operating unit, or tank
battery (see Figure 1-7). Products may be transported from the tank
battery by truck or pipeline.
1-1-20
-------
Stock tank*
• |nt«ctton iMCfc
OnMto •»»•«• l« w
Figure 1-7 Oil/Gas Production Operation
-------
Impoundments (or pits) are used in nearly all petroleum producing
operations to contain produced water and other waste material generated at
the production site.
For clarity, the following discussion of production processes will
focus separately on oil and gas and will briefly consider the case where
gas production is concomitant with oil production. The first example to be
discussed is production of oil.
Oil Production Operations. Water, oil, oil/water emulsion, and
limited amounts of gas flow into the well and are brought to the
wellhead. This mixture is usually piped from the wellhead, through an
oilfield gathering system serving many wells, to the lease operating unit
or tank battery, although some wells have dedicated surface facilities
(see Figure 1-7).
A "separator" may be used to divorce produced gas from produced fluids
(including oil and water at this point). A separator is a vertical or
horizontal baffled vessel; it is designed for sufficient retention time to
allow gas to break out of the wellhead fluids. If the guantity of gas is
low, a "free water knock out" vessel may be used to make the initial
separation of free water (taken off the bottom of the vessel) and gas
(taken off the top of the vessel) from free oil and oil emulsion (taken
from the midsection of the vessel) (see Figure 1-7). Gas from the
separator and/or the free water knock out may be routed into a low
pressure gas gathering system or flared (burned in a controlled manner
onsite). Produced water is sent to an impoundment, pit, or tank to
accumulate prior to disposal.
1-1-22
-------
•/•
+p
-------
The free oil and oil emulsion may be treated differently from site to
site, depending upon how difficult it is to break the emulsion and other
factors. If the emulsion is difficult to break, the free oil and oil
emulsion may be heated and chemically treated prior to mechanical or
gravity separation. A "heater-treater" is used to heat the free oil and
oil emulsion prior to a settling process (see Figure 1-7).
If the emulsion can be broken through longer settling time (with or
without emulsion-breaking chemical addition), the free oil and oil
emulsion are sent to a larger settling vessel, usually a "gun barrel" (see
Figure 1-7). The gun barrel may be used as the settling vessel after the
heater-treater, or it may be used alone.
Crude oil flows from the gun barrel to stock tank(s) (see
Figure 1-7). Ownership of the oil may change past the stock tank. Stock
tank oil is measured (corrected to 60°F) and moved off the lease or unit
for sale.
The most modern production sites have computerized oil transfer
gauging systems called Lease Automatic Custody Transfer (LACT) units.
These units take samples, record temperature, and determine the quality
and net volume of the oil. They also recirculate bad oil for
reprocessing, keep records for production and accounting purposes, and
shut down and sound an alarm when something goes wrong. LACT units are
used mainly with pipeline systems.
In all crude oil recovery methods, aqueous solutions are produced and
must be treated, stored, recycled, or disposed of. As a well ages, the
aqueous fraction of the crude oil-water production increases. In
California, there are areas where crude oil wells produce 98-99 percent
brine with 1 to 2 percent crude oil. For stripper well production, 25 to
80 percent is brine (EPA, 1986).
1-1-24
-------
Depending upon State regulations, produced water may be reinjected
into the petroleum formation, used for ice control or as a dust
suppressant on roads, land spread, stored in pits to evaporate,
percolated, or be discharged into surface waters.
Gas Production Operations. As in oil production, water, liquid
hydrocarbons, and impurities must be removed from natural gas before it
can be marketed. Gas production contains limited amounts of heavier
petroleum compounds. Gas is separated from wellhead fluids in a
separator.
In one technique, natural gas from the well enters a chamber where the
pressure on the gas is increased. This causes a concomitant decrease in
temperature, and petroleum liquids and water precipitate out of the gas
stream and flow through a drain at the chamber bottom. Natural gas exists
near the top of the chamber. Heat exchangers are also used with this
system to further cool the gas. This process is also called Low
Temperature Separation. In this system, the petroleum liquid that settles
out of the separator bottoms enters a low pressure separator chamber where
additional gas is removed. Natural gas and petroleum liquids are the
products that leave this separator (API, 1976). This gas may still
contain substantial amounts of water. It must be dehydrated and sold, or
sent to a gas plant for further processing.
One problem associated with the production of natural gas is the
presence of free water. Free water promotes corrosion and formation of
hydrates. Both corrosion and hydrates cause increased piping pressure
drops and piping restrictions. Hydrates are precipitates that form in the
presence of free water under certain conditions. The greater the pressure
in the equipment, the higher the temperature at which hydrates will form.
Hydrates will form of methane, ethane, propane, isobutane, normal butane,
hydrogen sulfide, and carbon dioxide from a natural gas stream (API, 1976).
1-1-25
-------
Problems associated with the presence of free water may be avoided by
dehydrating the gas stream or by preventing formation of hydrates in other
ways. Water may be removed by glycol dehydration, by desiccants, or by
expansion-refrigeration. Glycol is a liquid desiccant that absorbs water
from the gas. When using liquid absorbent, the gas passes through a
chamber into which a fine spray of the liquid is introduced. The liquid
flows out the bottom of the chamber and is heated to remove the water so
that the liquid can be reused. The dry gas exits the chamber at the top.
Solid absorbents (desiccants) are used in conjunction with a gas permeable
filter through which the gas flows. The solid absorbent may be renewed by
heating (API, 1976).
Hydrates usually are prevented or removed from the gas stream by one
of three methods. The first method is to remove the water, and various
ways of doing this have been described. Another method is to heat the gas
stream to keep the hydrate from becoming saturated in the gas. When using
the latter method, heating has to be repeated at every point where hydrate
formation is likely. The third method of hydrate control is to add a
chemical to the gas stream to lower the temperature at which the hydrate
will precipitate (i.e., "antifreeze agent"). Alcohol is usually used for
this. With the hydrogen sulfide hydrate, a solid filter can be used to
remove the hydrate. As the gas stream containing hydrogen sulfide passes
through this filter, the gaseous hydrogen sulfide is converted to solid
iron sulfide (API, 1976). These filters cannot be reused and must be
properly disposed of.
Once removed, free water may be accumulated in tanks, pits, or
impondments pending disposal.
1-1-26
-------
Other impurities, such as hydrogen sulfide and carbon dioxide, must
also be removed from the gas stream. The removal processes vary from
absorption to chemical reaction. All of these removal processes generate
waste material.
Produced water disposal is described in the previous section. Oil
Production Operations.
WASTE GENERATION
This section identifies the sources of wastes considered within the
scope of this study and presents a methodology, or the means by which EPA
will develop the methodology, for generating national estimates of volumes
for major wastes (i.e., drilling fluids, well stimulation and well
completion fluids, workover fluids, produced fluids). In addition, a
brief literature review is presented. Quantitative estimates of waste
volumes will be completed for inclusion in the final Report to Congress.
The methodologies presented herein have inherent limitations. Some of
these limitations include:
• Oversimplification;
• Incomplete accounting of wastes generated (i.e., accounts for
drilling media but not other associated wastes such as well
treatment/well completion fluids, deck drainage, sewage, etc.);
• Lack of accounting for drill cuttings and formation fluid; and
• Lack of accounting for drilling media makeup water.
1-1-27
-------
Nevertheless, these limitations do not preclude the Agency from
calculating estimates of waste volumes. The Agency plans to use the
method(s) presented herein (or combinations thereof) to estimate waste
volumes. Waste volume estimates will be used in the risk assessment and
economic analysis (see Part IV, Risk Assessment).
For this preliminary technical report, the potential wastes generated
from oil and gas exploration, development, and production activities are
listed in Table 1-2. Not all of these wastes are necessarily within the
scope of the project as discussed in the Introduction.
Literature Review
EPA has conducted an extensive literature review of both published and
unpublished reports addressing the sources and volumes of wastes generated
from the exploration, development, and production activities of oil and
natural gas. One aspect of this process was a review of EPA's literature
in this area. This includes the EPA 1976 Oil and Gas Extraction Industry
Development Document for the Office of Water's effluent limitations
guidelines (See Appendix A - EPA) and the 1985 Proposed Development
Document for the offshore segment of the oil and gas extraction industry
effluent limitations guideline.
The disposal of wastes associated with oil and gas drilling and
production has been an increasing concern over the last five years. As a
result, the main objective of most of the literature has been to evaluate
disposal practices of the given waste in a given area of reporting, or to
present case studies. Therefore, any reporting of volumes of waste has
been a minor objective, if performed at
all (Waite et al, 1983; Eck and Sack, 1984; Elmer E. Templeton and
Associates, 1980).
1-1-28
-------
l o tat ion/Development
Drilling media
6.
I
t^i
>0
a.
b.
c.
Water-base drilling fluid system
Oil-base drilling fluid system
Pneumatic drilling fluids system
Air
Foam
Hist
Aerated mud
d. (Some) produced fluids
2. Drill cuttings
3. Deck drainage
4. Well completion fluids/well treatment fluids
5. Well Stimulation fluids
6. Packing fluids
7. Waste lubricants, waste hydraulic fluids, waste
solvents, and waste paints
8. Sanitary Waste
Production
1. Produced waters (oil and gas)
Skimmed solids from air flotation units
2. Produced sand
3. Workovet fluids
Cleaning fluids
- Packing fluids
Bailing fluids
Deck drainage
4. Field tank bottoms
Gun barrel
Free water knockout (FWKO)
Stock tank(s)
Other production tanks
Skiniuing surface inpoundntents, pits, and
tanks
5. Waste crude oil
Waste specialty chemicals, waste lubricants, waste
hydraulic fluid, waste motor oil, waste paints; waste
solvents
7. Sanitary Waste
8. Waste associated gases (CHj &
9. Waste triethylene glycol (TEG)
10. Gathering pipelines to central oil and gas
separation facilities
Hydrostatic test fluids
Pig wax
Filters/slug catchers
11. Secondary and tertiary production operations
Produced water
Tank bottoms [all sorts - be more specific]
Filter media (solid waste)
Water treating residues
- Pipeline pigging waters (prior to separation
facilities)
Workover fluids
Waste fluids from compressors, turbines, and
boilers
Waste paints, waste solvents, waste specialty
chemicals
- Waste associated gases
Waste crude oil
Dehydration units (waste TEG)
Waste scrubber sludges
Sanitary Waste
Table i-?: List of Potential liases
-------
Many of the reports collected address a single waste such as drilling
fluids (Canter, at al., 1984; Freeman and Deuel, 1986; West and
Snyder-Conn, 1985), pit fluids (EPA, 1984), drill cuttings (Michigan Oil
and Gas Association, 1984), or produced waters (Elmer E. Templeton and
Associates, 1980; Morton, 1983; Herrold, 1984; Coleman and Crandall,
1981). Some documents attempt to discuss both drilling fluids and
produced waters (Waite et al., 1983; EPA, 1985a; EPA, 1985b; API, 1983).
Few studies attempt to address other oil and gas "associated wastes"
(Waite et al., 1983).
Almost all of the literature is either site-specific (Heitman, 1985;
Manuel, 1982; CH2M Hill, 1983), State-specific (Morton, 1984; Birge et
al., 1985), or regionally-specific (Murphy and Kehew, 1984; Alaska DEC,
1983; Freeman and Deuel, 1986; Powder River Conservation District, 1986).
None of the literature addresses the wastes generated from the oil and gas
extraction industry from a national perspective. Data reporting volumes
for the two main wastes, drilling fluids and produced water, are
periodically presented (Waite et al., 1983; Eck and Sack, 1984; Wilkerson,
1984; Rafferty, 1985). Of all the wastes generated, produced water
figures are reported with the most frequency, followed by drilling
fluids. There are many reports that address the waste and/or disposal
practice without waste volumes reported (API, 1983; Freeman and Deuel,
1986; Canter et al., 1984).
Two major problems exist with most of data presented. One problem is
verification of the source. For example, Rafferty (1985) stated that an
estimated 315 million barrels of waste drilling fluid are generated by
onshore oil and gas drilling activities. There is no supporting
documentation to verify that number, however. The second problem is
determining how to evaluate data when they are derived using different
approaches.
1-1-30
-------
For example, EPA has received two recent submittals addressing West
Virginia brine production. In 1984, Eck and Sack estimated West Virginia
brine production at 11.6 million barrels annually. In 1986, the West
Virginia Oil and Natural Gas Association and the Independent Oil and Gas
Association of West Virginia (hereafter "West Virginia Joint Survey")
submitted profiles of average brine production for over 5,000 wells in
West Virginia. The methodology and documentation of both estimates are
illustrative of the difficulties encountered when evaluating previous
waste volume estimates.
Eck and Sack based their estimate on information from a variety of
sources and on assumptions. The number of producing oil and gas wells for
1981 was obtained from the Interstate Oil Compact Commission (IOCC,
1982). Estimates of brine production per well were obtained from a report
on produced water volumes in two districts of Pennsylvania (Waite, et al.,
1983). As shown in Table 1-3, Waite, et al., presented only ranges of
produced fluids observed from a few specific Pennsylvania areas. Eck and
Sack apparently assumed that the average of the product water volumes
paralleled West Virginia brine production. This is a major assumption
that overlooks the effects of the different geologies of Pennsylvania and
West Virginia, the relative ages of wells (i.e., older wells produce more
water), and local production practices. In addition, the format of the
Waite, et al., production estimates was presented in terms of "deep gas
wells," "shallow gas wells," and so on. This situation appears to have
compelled Eck and Sack to assume ratios of "deep gas wells," "shallow gas
wells," and so forth in West Virginia for purposes of estimating volumes.
Table 1-4 presents some of the assumptions and calculations of produced
water in West Virginia.
The 1986 West Virginia Joint Survey used a different approach to
illustrate brine production ranges in that State. A survey was conducted
1-1-31
-------
TABLE 1-3
Development Areas
I. Shallow Oil
1A. Venango
District
IB. Bradford
District
ESTIMATED WASTE FLUID VOLUMES
IN PENNSYLVANIA .
Waste Fluid Type
Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
(After 6 months of pumping)
Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
(After 6 months of pumping)
Ranges In
Waste Fluid
Volumes Per Well
* 0-2,000 Gal.
26,000 Gal.
1-2 BBL/Day
(42-84 Gal/Day)
* 0-2,000 Gal.
30,000 Gal.
1-2 BBL/Day
(42-84 Gal/Day)
II. Shallow Gas
Upper Dev.
III. Deep Gas
Medina Fin.
Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
Fluids Produced During Drilling
Stimulation Fluids
Production Fluids
* 0-5,000 Gal.
40,000 Gal.
0-1 BBL/Day
(0-42 Gal/Day)
* 0-25,200 Gal.
58,800 Gal.
2-4 BBL/Day
(84-168 Gal/Day)
* Estimated volumes of fluids produced during drilling, does not
include top hole water or ground water encountered before surface
pipe is set.
These estimates apply only to air rotary drilled holes.
All ranges are considered typical for the type of well indicated.
Individual wells or groups of wells in selected locations may
differ significantly from the ranges indicated here.
Source: Waite, B.A., Eeauvelt, S.C., and Mood, J.L., 1982, Cil and
Gas Well Pollution Abatement Project ME No. 81495, Part C.
Moody and Associates, Inc. Meadeville, Pa. Pg. 52
-------
TABLE 1-4
ESTIMATE OF BRINE PRODUCTION IN WEST VIRGINIA
Assumptions:
o Daily volumes of brine produced per:
Deep gas well - 2 BBL/day
Shallow gas well - 0.35 BBL/day
Shallow gas well - 1.2 BBL/day
(Above values chosen from Table 1-3)
o 90% of Gas wells are "shallow"
10% of Gas wells are "deep"
100% of Oil wells are "shallow"
Given:
o No. of producing wells in West Virginia in 1981:
Gas wells - 26,925 Oil wells - 14,700
Calculate daily brine production per gas well based on above
information:
(0.90 x 0.35 BBL/day) + (0.10 x 2 BBL/day) =0.52 BBL/day
Calculate annual brine production:
o Gas wells:
0.52 BBL brine/day/well x 26,925 wells x 365 days/yr
= 5,110,365 BBL brine/year
o Oil wells:
1.2 BBL brine/day/well x 14,700 wells x 365 days/yr
= 6,438,600 BBL brine/year
o Total produced brine:
5,110,365 BBL brine from gas wells/yr
+ 6,438,600 BBL brine from oil wells/yr
= 11,548,965 BBL brine/yr
= 11.6 x 106 BBL brine/yr
Source: Eck, Ronald W. and William A. Sack. 1984. "Determining
Feasibility of West Virginia Oil and Gas Field Brines as
Highway Ceicing Agents, Phase I, Volume II -
Appendices." WVDOH Research Project 68. West Virginia
Department of Highways in cooperation with U.S.
Department of Transportation and Federal Highway
Administration.
1-1-33
-------
of 5,232 wells in West Virginia, and the results are presented in Table
1-5. The results are informative but not concrete. In fact, major
assumptions would still be required to project West Virginia production
from Table 1-5.
An interesting comparison of the Eck and Sack and West Virginia Joint
Survey results is possible by back-calculating total estimated brine
production (on a per-well basis) from Eck and Sack as follows:
Given: Total estimated brine production = 11.6 x 10 BBL/yr
Calculate: Unit brine production for:
5.1 x 106 BEL brine/yr
Gas wells: 1
161,251 MMCF gas/yr
=31.6 BBL brine/MMCF gas
... ... 6.4 x 106 BBL brine/yr
Oil wells: 2
2.433 x 106 BBL oil/yr
=2.63 BBL brine/BBL oil
These results are not inconsistent with the results of the West
Virginia Joint Survey presented in Table 1-5. These examples were not
selected to say whether one number calculated is potentially better than
the other, but to illustrate how carefully numbers presented in the
literature for any waste will have to be evaluated.
Exploration and Development Wastes
As shown in Table 1-2, wastes associated with exploration and
development are largely drilling media (the media used to drill, i.e..
1-1-34
-------
TABLE 1-5
WEST VIRGINIA PRODUCED WATER SURVEY
2,799 Gas Wells
Gas Vol .
0-10
10-30
30-60
>60
TOTAL
% of TC/TAL
i
i
in
Oil Vol.
BOPD
0-1
1-5
5-10
>10
TOTAL
% Of TOTAL
No Prod.
Water
676
423
275
91
1,465
52%
No Prod.
Water
447
283
19
5
754
3.1%
0-10 BPM1
Prod. Water
143
663
182
137
1,125
40%
0-10 BPM
Prod. Water
491
62
3
2
558
23%
10-20 BPM
Prod. Water
5
31
21
24
81
3%
2
10-20 BPM
Prod. Water
121
28
0
0
149
6%
20-30 BPM
Prod. Water
0
32
47
4
83
3%
,453 Oil Wells2
20-30 BPM
Prod. Water
64
20
2
0
86
3%
30-100 BPM
Prod. Water
0
3
22
5
30
1%
30-100 BPM
Prod. Water
130
63
2
0
195
8%
>100 BPM
Prod. Water
1
0
11
3
15
1%
>100 BPM
Prod. Water
404
305
1
1
711
29%
Total
825
1,152
558
264
2,799
Total
1,657
761
27
8
2,453
% of
Total
30%
41%
20%
9%
% of
Total
63%
31%
1%
1%
*BPM is defined as Barrels Per Month
Doeu not include any waterflood producing wells.
Source: Independent Oil and Gas Association of West Viiginia and West Virginia Oil and Natural Gas
Association. 1906. "Oil and Gas Produced Water Survey." Submitted to EPA April 30 .
-------
fluids, air, gas), cuttings, and deck drainage. In general, these wastes
are temporarily (up to 1 year) or permanently disposed of into an earthen
pit, the reserve pit. Some long-term disposal options are: dewatering
and burial, land farming, road spreading, and centralized pits (see
Industry Waste Management Practices). Well completion and/or treatment
fluids, along with well stimulation fluids, also may be disposed of into
the reserve pit. Smaller volume wastes such as waste lubricants, hydraulic
fluids, solvents, paints, and sewage may either be commingled in the
reserve pit or disposed of separately, which can be subject to control by
regulatory programs. At this time, volume estimates will not be developed
for small miscellaneous waste sources; any incremental estimate of these
waste volumes is not expected to significantly increase the overall volume
estimate per well site for exploration and development, sources. Also, EPA
is still defining the scope of this project, which could affect the
Agency's need to quantify volumes of wastes generated (see Introduction).
Virtually every aspect of drilling operations affects the quantity of
wastes generated. Table 1-6 presents a listing of factors that can
influence waste volumes. These factors may influence volumes
individually, but they usually are so strongly interrelated that the
effect of a single factor can be obscured.
For example, anticipated downhole geology dictates the drilling media
selected. When water-bearing formations are encountered, however, waste
volumes increase (via water displaced to the surface). Further, the
addition of this connate water causes changes in the drilling media for
which compensation is required. The addition of connate water also
contributes to the possibility of such problems as stuck drill pipe. Once
the drilling media and drill cuttings are brought to the surface, the type
and extent of solids control equipment used influence how well the
cuttings can be separated from the drilling fluid, and hence also
1-1-36
-------
TABLE 1-6
FACTORS INFLUENCING THE VOLUME OF WASTE
DRILLING FLUIDS, DRILL CUTTINGS, WELL TREATMENT/WELL COMPLETION,
o Geology, e.g. - Hard rock formations
Shale
Sandstone
o . Well Depth / Hole Size / Casing Program
o Drilling media; e.g.
- Mud type
Air
Gas
Foam
o Extent of solids control equipment used; e.g.
Influences the amount of water
added to the circulating mud system
Cuttings washing efficiency
o Problems encountered during the operation; e.g.
Stuck pipe
Lost circulation
High pressures and temperatures
(expected/unexpected)
o Service products used; e.g.
Types of products used
Numbers of products used
Solids vs. liquids
1-1-27
-------
influence the volume of waste displaced to the reserve pit. When poor
drill media/cuttings separation occurs, the drill media must be
continuously diluted with makeup water to counter the high solids content
of the media. Thus, poor surface separation causes drill media volume
swell. This example is illustrative of the interacting factors that
affect final waste volume. All of the factors in Table 1-6 are similarly
complex.
Table 1-7 describes factors affecting total solids content in weighted
drilling muds. The table further illustrates the number and type of
factors introducing variability into volume estimates. Even with these
factors in mind, EPA will fulfill the larger objective of collecting
pertinent information by examining the data collected through standard
industry recordkeeping practices.
For example, drilling contractors keep records that routinely itemize
the type and quantities of products used on a given well; this information
is extremely site-specific. The drill report does not describe the solids
control equipment in use at the site, however, nor does it include
freshwater consumption data. The information noted on the drilling report
is generally unavailable to the Agency because it is not required in State
or Federal regulatory programs. Some drill report data were collected
during the screening sampling program conducted in conjunction with this
study during June - September 1986, and will be presented in the
January 31, 1987, Technical Report.
Drilling Waste Methodology
EPA plans to work cooperatively with the Petroleum Equipment Suppliers
Association (PESA) to develop a methodology to estimate drilling waste
1-1-38
-------
2823
Table 1-7 Factors That Control Total Solids Content in Weighted Muds
(Numbered in Order of Decreasing Influence)
Item
Contributes to
low total sol ids
Contributes to
high total solids
First Order of Importance
la Type of formation
Ib Bit cutter type
2 Mud density
3 Bit jet horsepower
4 Annular lift
5 Rig shale shaker
Medium hard
UnconsoTidated sand
and gravel
Long teeth
Minimum
Adequate
Adequate
Constant efficient
operation
Second Order of Importance
6 Full-flow
7 Rig screen mesh
8 Fine screen used
to return to system
part of the liquid,
clays, and silts
from hydrocyclone
9 Removing directly
from system a
fraction of clay
and 1iquid with
centrifuge, while
maintaining weight
and volume
10 Centrifuge used to
return to system
the 1iquid and
clay from
hydrccyclone
unaerflow (see No.6)
Unconsolidated silt
Very hard
All Small diamond /
Slow drill ing
Above minimum
Inadequate
Inadequate (rare if hole
is near gauge size)
Bypassed
Effectiveness varies with
formation and bit type
Fine*
Secondary separation does
not further reduce solids
Varaible effect on total
solids content, but good
viscosity reduction
Not applicable
Coarse'
Variable increase in
total solids content,
but more than centrifuge
salvage (see Mo. 10);
no viscosity reduction
Primary separation cannot
increase total solids
content
Secondary seoaration
cannot raouce solias
content; not normally
recommended on water-
base weignted muas
Variable increase in
total solids content, but
less than screen salvage
(see No. 8); no viscosity
reduction
-------
2823
Table 1-7. (Continued)
Item
Contributes to
low total solids
Contributes to
high total solids
11 Chemical treatment
to prevent shale
cuttings dispersion
Variable (but may help
screen removal?)
Normally does not cause,
but decreases viscosity
to total-solids-content
ratio
12 Chemical treatment
to disperse shale
to clay-size
particles
Variable, but can help
centrifuge removal of
shale as clays
Normally does not cause.
but increases viscosity
to total-solids-content
ratio
Whether or not a finer screen will help noticeably in this primary separation
depends upon the comparative size relation between the cuttings reaching the
surface and the screen mesh, and whether or not the finer mesh can be
maintained in proper operation. If a "fine" screen cannot operate properly at
full flow, a coarser screen will maintain lower total solids content than a
finer screen that is bypassed.
Source: Chilingarian, G.V. and P. Vozabute. 1983. Prilling and Drilling Finds.
Elsevier Science Publishing Co., Amsterdam, Holland, pp. 450-451.
1-1-40
-------
volumes generated annually. PESA is an industry trade organization that
has a subset membership of drilling service and product supply companies.
Members of PESA have substantial technical expertise in estimating
drilling supply needs on a site-by-site basis. They also have
considerable information on types and quantities of materials consumed.
Individual sources of wastes that will be considered in designing the
methodology include drilling media, well completion treatment, and well
stimulation fluids.
Some of the methodologies considered for estimating exploration and
development wastes are:
Determine the average well depth nationwide. Develop an estimate of
the volume of drilling fluids used (either per foot or per the
determined average well depth) based on site-specific or standard
industrial calculations (Chilingarian, 1983). National volume
would be estimated by multiplying the volume of drilling fluid used
by the average number of wells drilled over the past three to five
years.
Interview and gather data from operators by State and/or by
region. Extrapolate these data to the national level.
Develop a model to consider all the possible variables or only the
most important shown in Table 1-6. This method has been rejected
as a viable alternative because of complexity, number of variables,
and the time and cost involved.
The methodology (or combination of methodologies) used will be
determined by the quantity and reliability of the data gathered.
Production Wastes
As shown on Table 1-2, the main wastes associated with production
activities are produced water, produced sand, workover fluids, tank
1-1-41
-------
bottom, waste crude oil, and waste triethylene glycol. Depending on the
waste, the primary methods of disposal are injection into subsurface
formations, deposition into earthen pits (production pits or
impoundments), discharge to surface waters, and road spreading (see
Industry Waste Management Practices). All of these methods are subject to
control by existing State and Federal regulatory programs (see Appendix
A). This technical report discusses the methodology used to estimate the
volumes of produced water. Although EPA does not present a methodology
for associated wastes generated from production activities, as discussed
herein, the Agency is contemplating various courses of action to evaluate
these wastes.
For example, while EPA recognizes that wastes are generated from
secondary and tertiary enhanced recovery operations, the Agency will not
include a methodology for estimating the volumes in this report. EPA is
coordinating with the Department of Energy in this area in order to use
the Department's expertise and existing data prior to generating any new
estimates.
EPA has considered generating estimates of volumes of tank bottoms,
waste crude oil, and waste triethylene glycol, but this technical report
does not present such a method for several reasons. First, EPA found that
the existing literature lacks any useful data. Second, the industry is
not routinely submitting pertinent waste volume data to regulatory
agencies because of the absence of such regulatory requirements. Third,
there are many significant factors that can influence the volume produced
(see Table 1-8). At this time, EPA is considering the alternative of
developing an industry profile and visiting commercial operations (that
dispose of or reclaim these wastes) in various parts of the country to get
an indication of the amount of waste tank bottoms or crude oil they
routinely dispose of or reclaim.
1-1-42
-------
TABLE 1-8
FACTORS INFLUENCING VOLUMES OF WASTE
TANK BOTTOMS AND WASTE CRUDE OIL
o Type of crude oil, type of gas
o Single well vs. central battery vs. field separation
facility
o Numbers, sizes, and types of vessels
o Method utilized for separation/dehydration -
gravitational heater treater
o Age and efficiency of equipment used
o Settling time/velocity
o Any capacity for recirculating settled material, at
what points, and how many times
1-1-43
-------
As stated, EPA will estimate annual quantities of produced water.
Table 1-9 lists the major factors influencing the volumes of produced
water. Even with all these variables, estimating produced water volumes
is possible, since many States require that volumes be reported (Herrold,
1984b). The following methodology outlines how EPA expects to calculate
volumes of produced water. EPA welcomes comments on this procedure.
Produced Water Methodology
The following method is proposed for use in determining a. national
estimate of volumes of produced water generated from primary, secondary,
and tertiary oil and gas production operations:
1. Establish the number of producing oil and gas wells by State and by
zone (EPA, 1986), as well as a total for the United States.
2. Establish a range of barrels of oil produced and the millions of
cubic feet of natural gas and gas liquids produced by State, and a
national total.
3. Complete and update a table similar to Table 1-10 (Herrold,
1984b). The table will list which oil and gas States have any
produced water reporting or manifest systems. Table 1-11 presents
an example from the State of Alaska (Alaska Oil and Gas Commission,
1986).
4. Review volumes reported in the literature (Elmer E. Templeton and
Associates, 1986; Herrold, 1984a). Use estimates and/or water:
oil/gas ratios presented in the EPA Eastern and Western Workshops
Proceedings presented by State personnel where they can be verified
(EPA, 1985a; EPA, 1985b). Review the data gathered during the
screening/sampling program. This source of information will be
valuable in those States where no formal reporting requirements
exist and/or the data are not computerized.
5. Make use of regional oil and/or gas to water ratio patterns to
estimate volumes for States where only hydrocarbon production
information is available.
6. Make use of data from trade organizations (WVIOGA/O&NGA, 1986),
research institutes, and/or other Federal agencies (such as the
Department of Energy) when possible.
1-1-44
-------
TABLE 1-9
FACTORS INFLUENCING VOLUMES OF WASTE
PRODUCED WATER
o Type of producing well; e.g.,
Oil
Gas
Oil and gas
o . Depth
o Type of reservoir; e.g.,
- Light crude
Heavy crude
- Wet gas
o Size of reservoir
o Age of the well; e.g.,
The older the well, the more
associated water
o Water to product (oil, gas, oil and gas) ratio
o Type of production operation; e.g.,
Primary
Secondary
Tertiary
1-1-45
-------
TABLE I-10
PRODUCED WATER RECORD-KEEPING IN
SELECTED STATES AND PROVINCES
Production Records
Disposal Well Records
1.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
19.
22.
23.
24.
27.
Annual Monthly
Texas x
California x
Louisiana
Oklahoma
Wyoming X
New Mexico x
Kansas
North Dakota x
Mississippi x
Michigan X
Montana X
Colorado X
Illinois X
Florida X
Ohio
Indiana
Pennsylvania
West Virginia
New York X
Ontario X
Annual Monthly No Recorc
X
X
X
X
X
X
X
X
X
X
X
X
X
Source: Eerrold, Jeffrey E. 1984. Saltwater Disposal and Reccrdkeepin:
in Selected States and Provinces. Geological Survey Division,
State Michigan. April 5. p. 6.
1-1-46
-------
TABLE J-ll
201,639
6,615.161
OIL FIELDS I ALL POOLS I CHUDE OIL
BEAVER CREEK
GRANITE POINT
KUPAHUK RIVER
HCARTMUR RIVER
MIDDLE GROUND SHOAL
PRUOMOE HAY
SWANSON RIVER
TRADING UAY
TOTAL ACTIVE FIELDS
DAILY AVERAGE
NCL PRODUCTION
279.221
M7.51 7.0*4 ii»
172.8*49
62^281
57.673.365
1.860,MlI
KUPARUK RIVER
MCARIIIUR RIVER
PHUDIIOE BAY
SWANSON RIVER
TRADING UAY
TOTAL ACTIVE FIELDS
DAILY AVERAGE
CAS FIELDS
BEAVER CREEK
BELUGA RIVfR
EAST UARHOW
KENAI
LEWIS RIVER
MCAIMHUn HIVCn
MIDDLE GROUND SHOAL
NOIUII COOK INLC1
SOU1H BAHHOW
TRADING UAY
T01AL ACIIVE FIELDS
DAILY AVERAGE
.INJECTION PROJECTS
GRANITE POINT
KUPARUK RIVER
MCARIHUn RIVER
MIDDLE GROUND SHOAL
PHUDMOE BAY
SWANSON RIVER
THAD INC BAY
TOTAL ACTIVE FIELDS
DAILY AVERAGE
135.093
(4.357
CONDEN.
Ullll. I
OIL
IUUL1
WA1EH
IHIII I
15
8*4, 121
1.976.567
1.651.671
*413,197
9.912.9'l5
158,006
_ 122^8.52
1*1,596.376
(470,650
WATER
I Dill. I
•4.971
2.2*16
10
1.010
B.239
265
WATER
_ L!»«U _
683,613
1*4,201.612
1. 191.9*18
619,160
36. 102,031
_
5*«.012. 167
1.76B. 13*4
CTION SUMMARY BY ACTIVE FIELDS
GAS PKOD. ADOL CUM
IMCFI WEILS COMPS
9,770 2
20*1,326 29
11,317.013 290
397.229 6*1 8
180,1472 Ml 2
89.11*4.326 5*15 M.
6,383.670 33
26^521 22 2
109.703.397 1,036 19 5,
3.536,819 T01AL INACTIVE
TOTAL ALL FIELDS 5.
TOTAL INACTIVE
FOII MAMCII.
CRUDE OIL
_LL«»U
3.210.1(15
101.67*1,562
222.93*4. 126
508. (418.938
1*4?, 8/9,226
1196.6*12,867*
203.712.656
_flLJ28»271
77*1,001.263
155.526
77*4, 156.859
CUM NGL
.JI'Wl 1
915. /6*4
8,l|*l2.60l
1.966.069
1,130.065
356.765
12.611.3*4*1
0
TOTAL ALL FIELDS T2. 811, 3*4*4
CAS PROD. ADDL CUM CONDEN.
IMCFJ WE, IIS, COMPS IIIHLI
1,566.090 *4
2,2*46.507 13
60,106 M
6,971,96*4 35 21
210,562 2
619.800 5
f4i4,230 1
3,933.501 12
6*i.'l53 6
1*1.790 1
15.732.103 83 21
507,1467 TOTAL INACTIVE
11.877
11.677
0
T01AL ALL FIELDS 11,677
GAS INJ. ADDL CUM OIL
IMCFI WELLS COMPS IUUL»
20
9,132,506 163
7 1
19 1
81,032.023 125
8.113.868 8
98.278.397 3M3 3
3,170,270 TOTAL INACTIVE
T01AL ALL FIELDS
13.012,875
13.012,875
0
13,012,875
1966
CUM WATER
11HILI
17,678
5.623,205
58. 6 39. Oi|(4
106. 211. (42*1
6*4. 8146.656
• 211. 21*4. (406
6*4, 123.609
_56^J6K(502
2*49.638, lO'l
2*19
6*19,636.353
CUM WATER
(HIM 1
73.591
010
1O9
M33.2I5
31
77.85*4
12
585,622
0
585,622
CUM WATER
1217399.398
112.178,663
83*4.736.901
2*46.366.122
7/5,93*4,095
8.1471.561
_ 12Q.229.JlJl
2.220.077,1457
n
2.220, 077. '157
CUM CAS
IMCFI
1.320,091
68.008.063
263. 269. *40I
187,275.l)ii5
7M,6l'j.y<0
5,712.4403.995
1,597,391.069
. 58^.16.0^6.0
77963. 72'4.7«Hl
*l'.>6
7.963,725.200
CUM CAS
( MCF J
3*4.320,925
210.BU6.2Vl
2.9*19.0147
1,661. 156.396
3,025. 1 J6
116.6I6.2U6
1.622, 1 18
7*4*4. "477, 620
16.798.6*16
2. (423.006
2,61*4. 199. *456
10. Ol>9. 167
2,032,268,623
CUM CAS
IMCFI
216.721,825
63.03*4
5,172,1?1.2449
1,613.955,90*4
7.202,6(i2.092
5«I7.*I57
7, 203, *409. 5*19
"INCIUDES 1,570.3*47 BIILS OF CONDEHSATE
••INCLUDES 7*4.209,'4/5 BOLS OF CUNDENSAIE
Source: Alaska Oil and Gas Conservation Commission. 1986.
The Alaska Report. May 28: Section IX, p. 1.
-------
7. Assimilate produced water volume estimates by State, by zone, and
nationwide.
8. Finally, cross-check these estimates by taking the oil and gas
production figures generated by State, by zone, and nationally,
then calculating a series of oil and/or gas to water ratios by
zone, which are then weighted according to production figures to
determine a national estimate.
1-1-48
-------
REFERENCES
Alaska Department of Environmental Conservation. Division of
Environmental Quality Operations. 1983. Environmental Quality Monitoring
and Laboratory Operations. Drilling Mud Impoundment Leachate and the
Kenai Wetlands. March 1983.
Alaska Oil and Gas Conservation Commission. The Alaska Report. May 1986.
American Petroleum Institute. 1976. Primer of Oil and Gas Production,
API, Dallas, TX.
American Petroleum Institute. 1983. Introduction to Oil and Gas
Production - Book 1 of the Vocational Training Series, American Petroleum
Institute.
American Petroleum Institute. 1983. Summary and Analyses of API Onshore
Drilling Mud and Produced Water Environmental Studies. API Bui D19. First
Edition (November).
Birge, W. J., et al. 1985. Recommendations on Numerical Values for
Regulating Iron and Chloride Concentrations for the Purpose of Protecting
Warmwater Species of Aquatic Life in the Commonwealth of Kentucky.
Memorandum of Agreement No. 5429 Kentucky Natural Resources and
Environmental Protection Cabinet. January 1985.
Canter, L. W., et al. 1984. Environmental Implications of Off-site
Drilling Mud Pits in Oklahoma. University of Oklahoma, Environmental and
Ground Water Institute, for Oklahoma Corporation Commission. May 1984.
Volumes I and II.
CH2M Hill. 1983. San Ardo Field - Produced Water Disposal/Reuse -
Appendix J - Feasibility Study Report. June 1983.
Coleman, Wendy Blake and Douglas A. Creendall. 1981. Illinois Oil Field
Brine Disposal Assessment - Phase II Report. Illinois Environmental
Protection Agency, Division of Water Pollution Control, Springfield,
Illinois. January 1981.
Eck, Ronald W. and William A. Sack. 1984. Determining Feasibility of
West Virginia Oil and Gas Field Brines as Highway Deicing Agents. Phase
I, Vol. I - Final Report. West Virginia University, Morgantown.
Department of Civil Engineering. Sponsored by West Virginia Department of
Highways and U.S. Department of Transportation, Federal Highway
Administration. WVDOH Research Project 68. January 1984.
1-1-49
-------
Federal Register, Vol 44, No. 73 (April 13, 1979), p. 22069.
Freeman, B. D. , Shell Oil Co., and L. E. Deuel, Deuel & Zahray
Laboratories. 1986. "Closure of Freshwater Base Drilling Mud Pits in
Wetland and Upland Areas."
Heitman, J. Fred. 1985. Chemical Stratification and Environmental
Concerns of Oklahoma Off-site Disposal Pits. Oklahoma Water Resources
Board, Water Quality Division. Publication No. 127. September 1985.
Herrold, J. E. 1984. State of Michigan. Department of Natural
Resources. The Use of Oil Field Brine on Michigan Roadways. January 27,
1984.
Herrold, Jeffrey E. 1984. Saltwater Disposal and Record Keeping in
Selected States and Provinces. Geological Survey Division. April 5, 1984.
Hydrocarbon Processing, April 1986, p. 78.
Interstate Oil Compact Commission. 1982. The Oil and Gas Compact
Bulletin Vol. XLI, Number 2 (December).
1985. The Oil and Gas Compact Bulletin Vol. XLI, Number 2
(December).
Interstate Oil Compact Commission and The National Stripper Well
Association. National Stripper Well Survey, January 1, 1985. October
1985.
Kirk-Othmer Concise Encyclopedia of Chemical Technology, 3rd Edition
(abridged) New York: John Wiley and Sons, 1985, p. 853. XLI, Number 2
(December).
Manuel, R. J. 1982. Hydrogeologic Assessments of One Proposed and Two
Existing Drilling Mud Disposal Sites, Hancock County, Mississippi for
Mississippi Pumping Service, Inc. June 28, 1982.
Michigan Oil and Gas Association. 1984. Industry Position Paper on Brine
Drilling Fluids and Salt Cuttings. Prepared by MOGA Task Force on Brine.
June 18, 1984.
Morton, Robert B. 1984. U.S. Geological Survey/Oklahoma Geological
Survey. Effects of Brine on the Chemical Quality of Water in Parts of
Creek, Lincoln, Okfuskee, Payne, Pottawatomie, and Seminole Counties,
Oklahoma. Open File Report 84-445.
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Murphy, Edward C. and Alan E. Kehew. 1984. "The Effect of Oil and Gas
Well Drilling Fluids on Shallow Groundwater in Western North Dakota."
Report of Investigation No. 82, North Dakota Geological Survey.
DE85 900622.
Office of Management and Budget, Statistical Policy Division, Executive
Office of the President. 1972. Standard Industrial Classification
Manual, pp. 37, 232, 237.
Oil and Gas Journal. September 23, 1985, p. 74.
. April 14, 1986.
. September 15, 1986, p. 64.
Kathleen Galagher, John P. Garvin, and William M. Schafer. January 7,
1986. Powder River Conservation District. Powder River Basin Water
Quality Study.
Rafferty, Joe H. 1985. Recommended Practices for the Reduction of Drill
Site Waste. Proceedings of a National Conference on Disposal of Drilling
Wastes. Sponsored by the University of Oklahoma Environmental and
Groundwater Institute and Continuing Education and Public Service. May
30-31.
Templeton, Elmer E. and Associates. 1980. Environmentally Acceptable
Disposal of Salt Brines Produced with Oil and Gas. Prepared for the Ohio
Water Development Authority. January.
U.S. Department of Energy, National Petroleum Council. Enhanced Oil
Recovery. June 1984.
U.S. EPA. Industrial Technology Division. 1985. Proceedings of the
Onshore Oil and Gas State/Federal Western Workshop. December.
U.S. EPA. 1986. Oil and Gas Exploration, Development, and Production -
Sampling Strategy. May 1986.
West, Robin L. and Elaine Snyder-Conn. 1985. The Effects of Prudhoe Bay
Reserve Pit Fluids on the Water Quality and Macroinvertebrates of Tundra
Ponds. U.S. Fish and Wildlife Service, Northern Alaska Ecological
Services, Fairbanks, Alaska. August 5.
West Virginia Independent Oil and Gas Association and West Virginia Oil
and Natural Gas Association. Meeting with EPA, April 30, 1986.
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Wilkerson, Daniel L. 1984. Survey of Drilling Mud Use and Disposal,
Staff Report. Alaska Department of Environmental Conservation.
September 1.
Williams, B. B., J. L. Gidley, and R. S. Schechter. 1979. Acidizing
Fundamentals. Society of Petroleum Engineers of AIME, pp. 1-17, 92-102.
William, H. R. and C. J. Meyers. 1984. Manual of Oil and Gas Terms. 6th
Edition. Matthew Bender Co., New York.
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CHAPTER 2
INDUSTRY WASTE MANAGEMENT PRACTICES
INTRODUCTION
This section is a preliminary review of control and disposal
techniques currently used by industry for wastes from onshore oil and gas
exploration, development, and production operations. Descriptions are
based on specific State or Federal regulatory requirements, published
information, professional observations during screening sampling, and
interviews. In addition, the practices described herein address the
management of major waste streams (e.g., drill cuttings, drilling muds,
produced fluids, etc.) identified in the previous section titled Waste
Generation. This section will be expanded for the full Report to Congress.
Normally, in a technical review such as this, a discussion of
"current" and "alternative" practices is presented. In the oil and gas
industries, however, waste management practices are so varied (because of
the influences of State and Federal regulations, operator preferences,
etc.), that the terms "current" and "alternative" are often
interchangeable depending on the context. Therefore, this section presents
waste management practices without distinguishing their relative
applicabilities. Technologies other than those presented in this review
may be identified based on the analytical results of the EPA screening
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sampling efforts conducted from June through September 1986. These
sampling efforts and associated results are briefly discussed in the
section titled Evaluation of Waste Management Methods.
Although the disposal practices generally used by this industry are
not highly complicated, they are fraught with variabilities that influence
their ability to protect the environment. State agencies can accommodate
these differences to a large extent by evaluating waste management
practices for each individual case within a general regulatory framework.
In some areas of a State, for instance, unlined reserve pits may be
permitted. In other, more hydrologically sensitive areas of the same
State, reserve pits may be required to have liners (meeting permeability,
puncture, and other durability specifications), monitoring wells, or a
leak detection system. Thus, waste management practices (and the
corresponding construction and monitoring requirements) are often tailored
to the specific situation even within a particular State.
These variabilities and the lack of concrete data to characterize the
extent of the practices prevent a definitive assessment of the relative
effectiveness of disposal options at this time. The control and disposal
techniques presented herein range from pilot operations to long-practiced
methods, none of which have been verified by EPA for treatability or
economic feasibility. Thus, it is the intent of this section to describe
the general management practices employed for pertinent wastes. It is not
the purpose of this section to quantify the number of sites using each
waste management method or to address the effectiveness of disposal
techniques.
In this report, the term "permitted" means that formal permits are
issued by a regulatory agency for the practice described.
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One difficulty encountered in. developing this section is the
widespread use of common descriptive terms for a variety of similar waste
management practices. Where descriptive terms for waste management
techniques varied, the most rational definition for purposes of this
discussion was selected. The definition of these terms is clarified
herein.
CURRENT INDUSTRY WASTE MANAGEMENT
Onsite Methods of Waste Disposal
The waste management methods discussed in the following sections are
divided into four topics:
• Onsite Disposal of Pit Fluids;
• Onsite Disposal of Pit Sludge;
• Closed Systems; and
• Treatment and Discharge Options.
The first two topics are self-explanatory. The section titled Closed
Systems discusses drilling mud recirculation systems and associated
technology. The Treatment and Discharge Options section discusses two
subcategories of the onshore segment of the oil and gas extraction
industry effluent limitations guideline: (1) Agricultural and Wildlife
Water Use and (2) Coastal Treatment and Disposal (see also Appendix A -
EPA).
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Onsite Disposal of Pit Fluids
Evaporation/Percolation Pits. Disposal of fluids by use of
evaporation and percolation pits is the simplest and least expensive
disposal method. It requires no special handling of the fluids and can
often be achieved at the drilling site itself.
The purpose of an evaporation or percolation pit is to use the
natural processes of liquid evaporation or diffusion through soil to
remove liquids from, waste drilling muds, cuttings, or brines. An
evaporation pit may be lined or unlined. Percolation pits must, by
definition, be unlined. Evaporation pits are widely used in areas of
overall net evaporation or net evaporation seasons. Percolation pits are
typically used in areas where there is no potential for ground-water
contamination or when percolating fluids are known not to adversely
degrade ground-water quality.
In many cases, the evaporation or percolation pit is the actual
reserve pit on a drilling site. As drilling muds and other fluids are
added to the pit, the evaporation and/or percolation of the liquids
reduces the volume of the contents of the pit. Evaporation pits on
drilling sites that use polymer muds are especially appropriate, since the
dried residue of these muds often is very low in volume. At the
conclusion of drilling activities, the reserve pit is allowed to be
completely dewatered by one or both of the evaporation or percolation
processes. This method of fluid disposal is preferred at sites in which
the reserve pit is to be backfilled with the dried solid wastes remaining
in the pit.
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Evaporation pits and percolation pits can also be used for brine
disposal. Percolation pits used for brine disposal are less common, since
many States have regulations prohibiting such disposal. Some States allow
such pits if the chloride content is such that no contamination would
result if the fluids contacted ground water. Several States, such as
North Dakota, and certain regions of New Mexico, do not allow the use of
evaporation pits for brine disposal, except in emergency conditions.
Reasons for prohibiting this form of brine disposal include the presence
of shallow ground water, highly permeable soils, and/or inherently high
chlorides concentrations in native brines. In general, the intent of
regulations addressing brine disposal via evaporation or percolation is to
protect ground-water quality.
Onsite Treatment and Disposal. Onsite treatment and disposal of
reserve pit wastes is accomplished by a variety of techniques. The choice
of treatment method depends on characteristics of the waste, economic
considerations, and applicable State or Federal regulations.
Generally, most of the onsite treatment methods are designed to treat
the wastes generated from drilling activities. The following sections
titled Treatment and Discharge Options and Centralized Treatment
Facilities discuss the disposal of other wastes such as produced water,
completion fluids, and stimulation fluids.
Onsite treatment technologies are commercially available for reserve
pit fluids as well as solids, typically in the form of mobile equipment
brought to a drill site. Examples of liquid treatment methods are pH
adjustment, aeration, coagulation and flocculation, centrifugation,
dissolved gas flotation, and reverse osmosis. Chemical fixation or
solidification is a method of pit solids treatment. Usually, a treatment
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company employs a combination of these methods in conjunction with
physical separation techniques in order to treat the entire contents of a
reserve pit. One possible treatment sequence is described as follows: A
coagulant such as aluminum sulfate, ferric chloride, or calcium chloride
is added to the pit followed by a flocculant (a natural or synthetic
polymer) to remove suspended solids from the liquid phase. Depending on
the results of this step, the liquid may be pumped from the pit and
discharged to the land surface, or may receive further treatment in the
form of centrifugation or filtration prior to final discharge. The pit
solids are then stabilized by mixing in cement kiln dust, which produces a
cement-like material that is buried onsite (see also Solidification).
Reverse osmosis has been used to treat reserve pit fluids. The
process can be described in four steps:
• Preclarification in the pit by flocculation of suspended solids;
• Filtration of flocculated fluid down to particles of one micron
in size (to extend the life of the membranes);
• Two-stage reverse osmosis through cellulose acetate membranes to
reduce total dissolved solids; and
• Disposal of clarified fluid and concentrated fluid products
(Moeco, 1984).
A unique alternative to flocculation and filtration of reserve pit
waste is boiler-evaporation. A company that uses this technique states
that it will treat "drilling fluids and drilling muds" from a reserve pit
by steam-heating the wastes. Part of the process includes taking gas or
oil from the wellhead onsite to burn in the boiler that provides steam to
the evaporator (E-Vap Systems).
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Many States allow onsite treatment and disposal of pit contents as an
alternative to other, possibly less cost-effective means of disposal.
Most States do not specifically require treatment of pit contents before
they are buried or land-applied onsite, but treatment is often a necessary
step in order to comply with limitations set on pollutant parameters for
ons i t e di sposa1.
Among the States that address onsite treatment of pit contents, the
most common limitations on pollutant parameters include pH, total
dissolved solids, oil and grease, and metals such as arsenic, cadmium,
chromium, lead, and mercury. For example, guidelines set by the West
Virginia Department of Natural Resources for the acidic pit fluids from
air drilling call for a pH between 8 and 10 for waste that is landspread
"from oil and gas well operations." Other criteria required by West
Virginia include a 24-hour waiting period between pH adjustment and
discharge (for land application only), and reporting requirements to
document the discharge. West Virginia also requires some laboratory
analyses of pit waste samples in order to monitor compliance with the
discharge limitations.
The type of method used for onsite treatment often depends on
particular characteristics of a well site in addition to the pollutant
parameters set by a State. For example, the only forms of pit treatment
presently used in Alaska are "settling and freeze-thaw concentration of
contaminants." That is, a pit must go through a one-year cycle of
freezing and thawing, presumably to cause heavy metals to absorb
permanently onto the drilling muds in the pit. The effectiveness of this
technique is under debate within the State (EPA - AK, 1985b).
Finally, the choice of treatment method is influenced by the
proximity of reserve pits (or production tanks) to centralized
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treatment/disposal facilities. Onsite waste treatment is often used in
locations where centralized treatment/disposal facilities are excessively
distant or not available. Centralized treatment and disposal practices
are discussed in the section titled Centralized Methods of Waste Disposal.
Onsite Disposal of Pit Sludge
Pit Burial. Onsite burial of a pit is defined as the disposal of pit
sludge and residuals within the approximate area of the pit. The solids
are covered by backfilling and by pushing in the walls of the pit. This
method of disposal is very often used for the closing of a dried
evaporation/percolation pit.
In many States, onsite burial of closed reserve pits is the most
common practice. Specific regulations for proper closure and burial vary
from State to State. For example, time limits for closure vary. In
Texas, the facility has 1 year after drilling ceases to close and bury the
reserve pits. Oklahoma allows 18 months, while Louisiana allows only 6
months. Kansas has no time limit for reserve pit closure (EPA - KS,
1985b).
Some States require testing of pit contents prior to burial. Under
Louisiana State Order 29-B, pit solids can be buried only if the following
limitations are met:
Arsenic 10 ppm
Barium 2,000 ppm
Cadmium 10 ppm
Chromium 500 ppm
Lead 500 ppm
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Mercury 10 ppm
Selenium 10 ppm
Silver 200 ppm
Zinc 500 ppm
pH between 6 and 9
Oil and grease 3% weight
Moisture 50% weight
Conductivity 12 mmhos/cm
In addition, the buried mixture must be 5 feet below ground level and
must be at least 5 feet above the water table.
Texas backfill requirements vary according to the type of pit and its
chloride content. Permits may have pit closure requirements; however, the
Texas Railroad Commission requires all pits to be backfilled and compacted
for closure after dewatering.
Kansas encourages burial onsite, but has no law requiring backfilling
of pits. In geologically sensitive or hydrogeologically sensitive areas,
onsite disposal of drilling pit contents can be prohibited (EPA - KS,
1985b).
Wyoming pit closure rules are included in the drilling permits and
may include special provisions such as testing and treatment prior to
burial (EPA - WY, 1985b).
A modified version to standard pit burial is the method of
encapsulation. This is a disposal method for burial of solids in a lined
pit. After the pit is dried, the top of the pit is lined with plastic
(presumably the same type of liner used on the pit bottom). The pit is
then backfilled and compacted. In theory, the pit solids are completely
separated from contact with other soil. This method is used to bury pits
in Alaska, Michigan, and Utah.
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Another modified method of pit burial is the technique of trenching.
A synonym for trenching is spidering (Crabtree, 1985). Trenching is
accomplished by pushing the pit solids into trenches extending out from
the main body of the pit. This increases the load-bearing capacity,
making it easier to cover the pit. It also tends to become structurally
stronger over time. This practice was common in Michigan, but now has
been phased out. It still is used in the Williston basin in North Dakota.
Solidification. Solidification of pit wastes is a method used to
"stabilize" reserve pit wastes prior to pit closure. Problems reported by
landowners, including reduced load-bearing capacity of the ground over the
pit and the formation of wet spots over the pit, have prompted
investigation into solidification. In addition, plastic pit liners that
are now required in many States do not allow for timely drying of pit
solids. Solidification provides a faster means of closing a pit,
particularly in areas of net precipitation where seasonal changes often
interfere with site restoration (Crabtree, 1985).
There are two categories in which solidification methods can be
placed: chemical and physical. In general, chemical methods of
solidification involve mixing cement-like products with the dewatered
contents of a pit, and physical methods of solidification involve
permanent freezing of pit solids. Only locations in Alaska have
environmental conditions appropriate for physical solidification.
Solidification of pit wastes is offered as an acceptable disposal
alternative in the regulations of several States. Title 18 of the Alaska
Administrative Code, Chapter 60, specifically addresses construction
requirements for "a containment structure which is designed to contain
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drilling wastes in a permanently frozen state," including a waste surface
level 2 feet below the active thaw zone (ISAAC 60.520, 1986). Louisiana's
Statewide Order 29-B states that, "Pits containing nonhazardous oilfield
wastes (as defined within Order 29-B) may be closed by solidifying waste
and burying it onsite" if the material to be buried meets specified
criteria, summarized in the table below:
- pH 6-12
- Leachate testing for:
Oil and grease . < 10.0 mg/1
Arsenic < 0.5 mg/1
Barium < 10.0 mg/1
Cadmium < 0.1 mg/1
Chromium < 0.5 mg/1
Lead < 0.5 mg/1
Mercury < 0.02 mg/1
Selenium < 0.1 mg/1
Silver < 0.5 mg/1
Zinc < 5.0 mg/1
- Top of buried mixture must be at least 5 feet below ground level
and covered with 5 feet of native soil.
- Bottom of burial "cell" must be at least 5 feet above the seasonal
high water table.
- Unconfined compressive strength > 200 psi
- Permeability < 1 x 10~6 cm/sec
- Wet/dry durability > 10 cycles to
failure
Michigan's Supervisor of Mineral Wells Instruction 1-84 specifies
lined pit closure requirements, and includes the following statement
regarding solidification:
Earthen materials shall be mixed with the pit contents to
stiffen it sufficiently to provide physical stability and
support for the pit cover. A pit stiffening process as
approved by the Supervisor may be used at the option of
the operator.
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Materials commonly used to "stiffen pits" in Michigan include native
soils, gravel, and sawdust. Processes have been developed within the
State that "stabilize" dewatered pit contents by addition of cement kiln
dust, cement, and other materials. Mixing is performed by a backhoe or jet
pump. The product of mixed waste and cement kiln dust resembles a
low-grade mortar. The Michigan Department of Natural Resources has run
tests on the raw material and the mixed product of one of three
"stabilizing" processes used in the State, and has found that "addition of
the raw material to a mud pit would not introduce toxic materials," among
other findings. The Michigan DNR expressed concerns over elevated SO.
levels found in leachate from the raw material, in addition to other
findings, and is pursuing further investigations of pit stiffening
materials (Crabtree, 1985).
A recent study conducted by scientists from Shell Development Company
and the Environmental and Ground Water Institute investigated the behavior
of drilling fluid wastes stabilized by the addition of fly ash. The study
concluded that "no significant uptake or release of [heavy] metals can be
expected during treatment," and that fly ash could be considered a valid
method of treatment (Deeley and Canter, 1985).
Closed Systems
A closed system used for oil or gas drilling is a system in which the
drilling fluids and liguids are recirculated and reused. A system in
which the drilling fluids are partially recirculated represents a
semi-closed system. The use of mud recirculation systems is a common
practice for onshore drilling. Such systems can be closed or
semi-closed. Their use represents a great benefit, as they can reduce the
water and mud input requirements. This can translate into cost savings on
raw materials and also a reduction of waste material generated requiring
disposal at the conclusion of drilling activities.
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Closed systems at drilling sites can be operated to have
recirculation of the liquid phase, the solid phase, or both. In reality,
there is no completely closed system for solids since cuttings are always
produced and removed. The closed system for solids, or the mud
recirculation system, can vary in design from site to site. However, the
system must have sufficient solids handling equipment to effectively
remove the cuttings from muds to be reused. A very common apparatus used
for this purpose is the shale shaker. The shale shaker is essentially a
screen that is used to separate cuttings from muds. Two types are
common. In one type, the screen is in the form of a tapered cylinder that
is rotated by the flow of the drilling fluid. The other is a
rubber-mounted sloping flat screen that is vibrated by a motor; drilling
fluids fall by gravity through the screen while the cuttings pass over the
screen (McCray, 1959). Other equipment utilized for mud recirculation
includes desanders, desilters, vacuum chambers (that can remove gas from
the muds), and centrifuges.
Water that is removed from the mud along with the cuttings can be
reused. A separate closed system for water reuse can be operated onsite
along with the mud recirculation system. As with mud recirculation
systems, the design of a water recirculation system can vary from site to
site, depending on the quality of the recycled water required for further
use. This may include chemical treatment of the water. Also, any solids
must be removed from the water. This can be accomplished by the use of a
centrifuge or similar apparatus.
A discovery well in France had, at the drilling site, a closed system
for solids and liquids. The system combined physical and chemical water
treatment with a conventional solids handling system to continuously
create clean water. As a result, the total pit volume, treatment, and
reserve was reduced to about one-third conventional volume (Neidhardt,
1985).
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In the United States, onshore oil or gas drilling sites that have
closed or semi-closed systems use variations of the systems described
above. In California, one site was known to use a mud recirculation
system using two shale shakers. The reduction of mud generated waste at
this site was necessary as the wastes were stored in aboveground storage
bins. At the conclusion of drilling, the contents of these bins were
emptied and transported to a centralized treatment facility (EPA - CA,
1986).
In Michigan, a particular site used a mud recirculation system
similar to the one observed in California. At this site, drilling wastes
at the end of drilling were placed in a lined pit and were later removed
by a vacuum truck (EPA - MI, 1986).
In Wyoming, mud recirculation systems were also used. At one
particular site, two reserve pits were constructed. The first pit
received all mud and cuttings from the well hole. The supernatant and mud
flowed into the second pit, while coarse cuttings remained in the first.
A large pipe was placed at the base of the second pit and thus
recirculated only the mud from the second pit. The mud then went through
an additional series of stages to further remove cuttings. At the
conclusion of drilling, the pits were dewatered. The supernatant was
removed for disposal at a disposal site; the solids remained in the pits
and were buried (EPA - WY, 1986).
In Kansas, a different type of mud recirculation system was used.
Mud and cuttings from the well hole were placed in a series of working
pits. Mud flowed from one end of the working pit to the other. At the
end of the pit, the mud was piped back to the well hole for reuse. As the
mud flowed along the length of the working pit, the cuttings were removed
by gravity settling. Pipes were placed at the base of the working pit.
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and at certain intervals the settled cuttings were removed and placed in
the reserve pit. At the conclusion of drilling, the working and reserve
pits were dewatered by evaporation and buried. Neither the working pits
nor the reserve pits were lined (EPA - KS, 1986).
Treatment and Discharge Options
Agricultural and Wildlife Water Use. Agricultural and Wildlife Water
Use is a subcategory under the onshore segment of the oil and gas
extraction industry effluent limitations guideline. This subcategory,
defined in 40 CFR Part 435, Subpart E, as authorized by the Clean Water
Act, addresses the use of produced water that is of good enough quality to
be used for livestock watering or other agricultural uses. This
subcategory was formerly called the Beneficial Use subcategory. The
terminology was changed because of the confusion resulting from the word
"beneficial." The term "beneficial use" has a long history of use in
Western U.S. water laws unrelated to its meaning in these regulations.
This subcategory was established because many western States had
asked EPA to allow produced water to be discharged and used for
agricultural and wildlife purposes. Investigation showed that in arid
portions of the Western U.S., low-salinity produced waters were often a
significant (if not the only) local source of water used for those
purposes. The regulation is intended as a restrictive subcategorization
based on the unique factors of prior usage in the region, arid conditions,
and the existence of low-salinity potable water.
To qualify for the use of produced water under Agricultural and
Wildlife use, the facility must be located west of the 98th meridian.
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Also, to qualify, the facility must show that the discharged water will be
used for agriculture or wildlife. The discharger must also meet the
required oil and grease discharge limitation of 35 mg/1.
There are inconsistencies from State to State for the issuance of
discharge permits under Agricultural and Wildlife Use. For example, 18
production facilities in Montana have been permitted, yielding a total
daily discharge of 0.6 million gallons for agricultural and wildlife use
(EPA - MT, 1985b). Wyoming currently allows discharge of produced water
for agricultural and wildlife use under 550 NPDES permits with effluent
limitations of:
TDS 5,000 mg/1
Sulfates 3,000 mg/1
Chlorides 2,000 mg/1
pH 6.5-8.5
Oil and grease 10 mg/1
(EPA - WY, 1985b).
These oil and grease limitations are met generally by the use of
oil-water separation systems. In Wyoming, a system of pits connected in
series has been used. Each pit is skimmed for removal of oil. The final
pit discharges directly into the Powder River.
Coastal Treatment and Disposal. The framework for regulating
treatment and disposal methods used in coastal areas is derived from the
Coastal subcategory of the onshore segment of the oil and gas extraction
industry effluent limitations guideline, defined in 40 CFR 435, Subpart D,
as authorized by the Clean Water Act. The Coastal subcategory defines
"coast" as "any body of water landward of the territorial seas, or any
wetlands adjacent to such waters" (see also Appendix A - EPA).
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Methods used for treatment and disposal of drilling or production
wastes in coastal areas are based on State and Federal regulatory
requirements. Where applicable, permits for discharge to coastal waters
are written in accordance with the National Pollutant Discharge
Elimination System (NPDES), and may be issued by State or Federal
authorities. At this time, 37 States have approved State NPDES programs.
In States that do not have approved NPDES programs, permitting of coastal
discharges is coordinated through Regional EPA offices and State agencies
concerned with these matters. States in EPA Region VI, for example, do
not have approved NPDES programs.
Actual treatment and disposal methods in coastal areas depend on the
nature of the effluent as well as applicable effluent limitations. Types
of waste effluents permitted by Louisiana include produced water and
water-based muds and cuttings (EPA - LA, 1985a). The Alaska Department of
Environmental Conservation permits surface discharge of reserve pit fluids
to the coastal tundra region, and specifically includes the following
limitations in the permits:
pH 6.5 to 8.5
Chemical oxygen demand 200 mg/1
Settleable solids 0.2 mg/1
Oil and grease 15 mg/1
Total aromatic hydrocarbons 10 ug/1
Arsenic 0.05 mg/1
Barium 1.0 mg/1
Cadmium 0.01 mg/1
Chromium 0.05 mg/1
Lead 0.05 mg/1
Mercury 0.002 mg/1
Frequently, the types of oil and gas field wastes that are permitted
to be disposed of in coastal areas are expected to be compatible with the
coastal environment, if kept segregated from unacceptable wastes. For
example, at a production site in Louisiana, the contents of the produced
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brine are close enough to the State's tidewater effluent limitations that
skim tanks to separate hydrocarbons from produced water are the only
treatment used prior to discharge (EPA - LA, 1986). In most cases,
monitoring, laboratory analyses, and reporting reguirements are specified
in permits for coastal discharges of any oil or gas field waste.
Simple separation technigues are not always sufficient to achieve
reguired discharge limitations. In general, brine treatment technology is
available in two categories: physical-chemical processes and biological
processes. Examples of physical-chemical treatment include flotation,
filtration, activated carbon adsorption, ion exchange, air stripping, and
break point chlorination. Examples of biological treatment include
dispersed growth systems such as aerated lagoons and activated sludge or
fixed film systems such as trickling filters and bio-disks. The primary
pollutants in produced water that these technologies affect include
biological oxygen demand, chemical oxygen demand, phenols, ammonia,
sulfide, and oil and grease. The most common method of treatment is oil
removal, which can be accomplished in skim tanks, tube separators, and,
more recently, sand filters. Biological treatment methods are only
recently being considered as alternatives to more conventional techniques
(Michalczyk, et al., 1984).
Centralized Methods of Waste Disposal
The waste management methods discussed in the following sections are
divided into four topics:
• Centralized Pits;
• Centralized Treatment Facilities;
• Reconditioning/Recycling/Reuse; and
• Incineration.
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The term "centralized," rather than "off site," is used in this
section to define a pit or facility designed, constructed, and operated
expressly for the purpose of receiving wastes from numerous oil and/or gas
field operations. The term "offsite pit" is used only in reference to
such pits located in Oklahoma, because this term is in common usage there
(Cantor, et al., 1984)
Centralized Pits
The use of centralized pits for disposal of oil and gas drilling
and/or production wastes is practiced in several States. Centralized pits
can be very large in size and can, as a result, accept the wastes for many
well and production sites over large geographical areas. They can be
designed to accept drilling muds, brines, or a combination of both. The
design capacity of a centralized pit is directly related to land
availability and topography, in addition to the anticipated volumes of
drilling and production wastes generated in the "service area" of the pit.
The purpose of a centralized pit is to accept wastes from outside
drilling and production activities and to provide long-term storage for
these wastes. No treatment of the pit contents is performed. A properly
sited, designed, constructed, and operated centralized pit allows the
natural evaporation process to concentrate drilling fluids and brines. A
pit is "closed" when it no longer receives any new material. The final
disposition of the pit and its contents is determined by local or State
regulations.
In Oklahoma, there are approximately 95 centralized pits (called
"offsite pits" in the State), with surface areas as large as 15 acres and
with depths up to 50 feet. They are created by excavating, damming
1-2-19
-------
gullies, and using abandoned strip pits. Rule 3-110.2 of the Oklahoma
Corporation Commission permits centralized pits and their use provided
that they are sealed with an impervious material, do not receive outside
runoff water, and are filled and leveled within 1 year after closure. The
chloride level of the pit contents cannot exceed 3,500 mg/1. The pits are
periodically sampled and checked for chloride. If the contents are above
the chloride limit, they must be treated and removed to a hazardous waste
disposal site. Operators of new centralized pits are required to install
and sample monitoring wells for chloride and pH. It is proposed to make
this requirement applicable to existing centralized pits (Appendix A - OK).
In California, drilling fluids and brines may be transported to
centralized pits. Drilling fluids are generally received by centralized
evaporation sumps, but many of these sumps are also used for percolation
where no freshwater source is near. No State manifest is required unless
the material is classified by the State as hazardous. On the western side
of the San Joaquin Valley, where ground water is of poor quality, there is
a commercial facility on Federal land. At this facility, there are 20 to
40 acres of permitted sumps for evaporation and percolation. BLM has sumps
on Federal leases that range up to 5 acres (Appendix A - CA).
In Ohio, the contents of reserve pits may be required to be removed
and transported to an Ohio EPA (State) regulated disposal site. This is
due to potential ground-water contamination from the pit. When pit
contents are to be moved, the State requires tests to determine whether
the waste can be disposed of in an approved landfill (Appendix A - OH).
In Texas, about 200 centralized saltwater disposal pits are in
operation. These pits are regulated by the Texas Railroad Commission.
State manifests are required to transport brines to these pits (Appendix A
- TX).
1-2-20
-------
In Wyoming, the Department of Environmental Quality regulates
centralized pits. Such pits require operating permits from the State. To
receive these permits, the pit operators must demonstrate that pit
construction will not allow a discharge to ground water by direct or
indirect discharge, percolation, or filtration. Also, it must be shown
that the wastewater quality will not cause violation of any ground-water
standards and that existing geology will not allow a discharge to ground
water (Appendix A - WY).
Centralized Treatment Facilities
A centralized treatment facility for oil and gas drilling and
production wastes is a process facility that accepts such wastes solely
for the purpose of reconditioning and treating wastes to allow for
discharge or final disposal. This removes the burden of required onsite
treatment of wastes from the drilling or production facility. Centralized
treatment can represent an economically viable alternative to onsite waste
disposal. A treatment facility can be run in batch or continuous
operation. The facility can have a design capacity large enough to accept
a great quantity of wastes from many drilling and/or production
facilities. In this way, the centralized treatment facility can treat a
large quantity of wastes more efficiently than a single drilling or
production facility can treat a small quantity of waste.
Many different treatment technologies can potentially be used in
central treatment of oil and gas drilling and production wastes. The
actual technology used at a particular facility would depend on a number
of factors. One of these factors is type of waste. Presently, some
facilities are designed to treat solids (muds and cutting), while others
1-2-21
-------
are designed to treat produced waters, completion and stimulation fluids,
or other liquids. Some facilities can treat a combination of both. Other
factors determining treatment technology include facility capacity,
discharge options and requirements, solid waste disposal options, and
other relevant State or local requirements.
Centralized treatment facilities can be divided into three different
categories: drilling waste treatment, produced water treatment, and
drilling waste and produced water treatment. Examples of each of these
types are given below.
An example of a drilling waste treatment system is found in
California. Drilling fluids at some drilling sites are accumulated in
disposal bins. The contents of these bins are vacuumed into trucks and
taken to a facility that uses a patented process to convert the sludge
into a substance having a gel-like consistency that hardens in 2 hours.
Metals within the drilling fluids are converted into stable, nonleachable
metal silicates. The final product can be disposed of by landfill or can
be used for backfilling or landfill covers (Ven Virotek, 1986).
California regulations do not require a State manifest for transporting
material unless it is determined to be hazardous under State regulations.
Another example of a central drilling waste treatment facility is in
Alabama. The facility accepts water-based drilling fluids and sewage from
offshore and coastal rigs in Alabama waters. Material is received by truck
or by barge. From the holding container, the mud is pumped through shaker
screens for cuttings removal. Treatment consists of pH adjustment,
flocculation, clarification, and dewatering. The water is pumped to the
local publicly owned treatment works (POTW) for final treatment. Solids
are trucked off to the municipal landfill for disposal (SAFE, Inc., 1986).
1-2-22
-------
Examples of brine treatment are exhibited in Pennsylvania and
Colorado. Pennsylvania estimates that 20 percent of all brines are hauled
to a treatment plant in that State (EPA - PA, 1985). It is the
responsibility of the brine generator to transport the material to the
treatment facility. Treatment at these facilities may include flow
equalization, pH adjustment, settling and surface skimming, retention and
settling, and aeration. These facilities must have NPDES and Pennsylvania
Water Quality Management Part II permits. The permit criteria and limits
will be governed by the receiving water quality standards. Generally,
total suspended solids will . be limited to an instantaneous maximum of
60 mg/1, with an average monthly of 30 mg/1. Oil and grease will have a
maximum of 30 mg/1 and an average of 15 mg/1. pH must be between 6 and 9
and dissolved iron will have a maximum of 7 mg/1 (Appendix A - PA).
In Colorado, the State Department of Health has permitted 10 to 15
commercial brine disposal facilities to discharge under the Wildlife and
Agricultural Use subcategory. Discharge limitations include pH between 6
and 9, a monthly average of 30 mg/1 for total suspended solids, with a
daily maximum of 45 mg/1, an oil and grease limit of 10 mg/1, a monthly
average of 5,000 mg/1 for total dissolved solids, with a daily maximum of
7,500 mg/1, and metal limits under the State water quality standards
(Appendix A - CO). One brine treatment facility was visited during the
field sampling portion of the Onshore Oil and Gas Study. This facility
treated brines with chemical addition (borax, calcium hypochlorite, and
potassium permanganate) and aeration. This facility did not discharge;
rather, brines were placed in large evaporation ponds (EPA - CO, in press).
Alaska also has centralized brine treatment facilities. Produced
waters from 14 platforms in Cook Inlet are sent to one of three treatment
facilities. Treatment consists of heating to enhance oil/gas separation,
solids settling, and surface skimming. The water is discharged off the
coast (EPA - AL, 1985b).
1-2-23
-------
Louisiana has approximately 33 commercial centralized facilities
currently in operation. Some accept only brines, while others accept mud
and brine. They must be permitted for operation by the State.
Treatment of reserve pit wastes can also be accomplished via mobile
treatment units. Such units employ scaled-down equipment designed to
perform the same treatment processes as those performed at centralized
treatment facilities, except that the equipment is truck-mounted and is
brought to the reserve pit onsite. Mobile treatment is discussed in
greater detail in the section .titled Onsite Treatment and Disposal.
Reconditioning/Recycling/Reuse
This section discusses the reconditioning and reuse of oil and gas
drilling and production wastes. Not included here are the recycling and
reuse of drilling fluids (i.e., drilling mud recirculation systems), since
these are cited in the section on Closed Systems.
The reconditioning, recycling, or reuse of oil and gas wastes
represents a positive environmental policy, when applicable. By means of
chemical or physical treatment, a material that otherwise would have to be
disposed of becomes a material with a beneficial use. In some cases, no
adjustment of the waste material is needed to put it to an advantageous
use. The recycling and reuse of these wastes not only can reduce the
volume of generated wastes that requires disposal, but also can reduce the
need for raw materials. This is especially important in geographical
areas where onsite waste disposal is extremely difficult because of
geological or other physical conditions, or not allowed because of
regulation.
1-2-24
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The State of Louisiana has regulations that specifically mention
reusable oilfield waste. "Reusable material" is defined as a "material
that would otherwise be classified as oilfield waste, but has been
processed in part or in whole for reuse." Commercial facilities may
produce reusable material as their treatment process or in conjunction
with their treatment process. In either case, the facility must be
permitted by the State. Onsite generation of reusable material requires
approval from the State Office of Conservation. The reusable material
must be tested and meet the following limitations:
Moisture content
pH
Conductivity
Sodium adsorption rate
Exchangeable sodium percentage
Leachate test:
Oil and grease
Chlorides
Leachate (EP Toxicity)
Arsenic
Barium
Cadmium
Chromium
Lead
Mercury
Selenium
Silver
Zinc
<50 % by weight
6.5 - 9.0
8 mmhos/cm
12
15%
10.0 mg/1
500.0 mg/1
0.5 mg/1
10.0 mg/1
0.1 mg/1
0.5 mg/1
0.5 mg/1
0.02 mg/1
0.1 mg/1
0.5 mg/1
5.0 mg/1
Louisiana has permitted reusable material that meets the above
criteria to be used as landfill cover or various construction fill
material (LA State Order 29-B).
A relatively new well-site treatment system offers beneficial
material reuse. The technology mentioned earlier was proven on a French
discovery well. This method is now being tested on several wells in the
western United States (Neidhardt, 1985).
1-2-25
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In Canada, a feasibility study was conducted on reusing produced
water as the feedwater supply for steam generation for onsite oil recovery
(Kus, 1984). Such steam-assisted methods operate with steam-to-oil ratios
of 3 to 1 and generate 2 to 5 barrels of produced water per barrel of
oil. To raise the large quantities of steam required for reservoir
stimulation, once-through type steam generators are most commonly used.
Preliminary investigations into the feasibility of using produced water as
the only source of water proved to be uneconomical. As an alternative, a
blend of produced water and municipal water was chosen (Kus, 1984).
EPA authorized a study on the feasibility of removing and recovering
phenol and acetic acid from sodium chloride brine (EPA, 1973). A pilot
plant was constructed to demonstrate the feasibility of using the method
of fixed bed adsorption of activated carbon. Separate electrolytic
test-cell evaluation of the purified brine showed it to be equivalent to
pure brine. The carbon beds were regenerated with dilute sodium
hydroxide. Desorbed phenol was recycled to a phenol manufacturer (EPA,
1973).
Incineration
This treatment method is applicable for organic and oil-laden
wastes. These include oil-based muds, oil emulsions, and other muds and
cuttings contaminated with oil, tank bottoms, and separator sludges. In
theory, any drilling or production waste with a low enough water content
can be economically combusted. The combustion residuals must also be
disposed of. The practice of incinerating drilling and production wastes
is not common. It is known to occur at a central treatment facility near
Kenai, Alaska. This facility receives oil and water from the coastal rigs
in Cook Inlet. All waste oil is collected in a storage tank where it is
periodically removed and incinerated. The residuals are placed in a
landfill on the facility property. Incineration is also known to be used
1-2-26
-------
on waste oil-laden cuttings and oil-based muds from offshore facilities in
Louisiana. EPA will investigate further the extent of the use of
incineration as a reliable waste treatment method.
Land Application
Landfarming
Landfarming, as defined by the Railroad Commission of Texas and used
in this report, is "a waste management practice in which oil and gas
wastes are mixed with or applied to the land surface in such a manner that
the waste will not migrate off the landfarmed area." The ultimate goal of
landfarming is to use dilution, chemical alteration, and biodegradation to
decrease the level of pollutants and alter the waste so that the
waste/soil mixture remains compatible with the intended or original land
use (Freeman and Deuel, 1986).
Landfarming is generally viewed as a long-term, management-intensive
process. Though widespread in Texas, Colorado, and Louisiana, and to a
lesser degree in Mississippi and Alabama, it is not common in other
States. Improperly managed landfarming sites have the potential for
environmental damage. The State of Texas has identified improper
landfarming and the resulting runoff to surface water as a critical
environmental problem.
Landfarming can provide an efficient disposal method for various oil
and gas wastes, including pit residue, sludges, muds, and liquids. Solid
wastes can be distributed over the land surface and mixed with the soils
by mechanical means. Liquids can be applied to the land surface by
various types of irrigation, including sprinkler, flood, and ridge and
1-2-27
-------
furrow. Injection plowing and disking of irrigated land surfaces allow
for subsurface application of wastes (Railroad Commission of Texas, 1985).
Certain criteria must be met, however, for successful landfarming.
Chloride content of the wastes must be relatively low. For example, Texas
allows non-permitted landfarming of wastes only if chloride content is
less than or equal to 3,000 mg/1. Alabama requires a. chloride content of
less than 500 mg/1. Oklahoma permits spray-application of reserve pit
fluids if chloride content is less than 1,000 mg/1.
Oily wastes and other organics is another concern. To alleviate this
problem, some States allow only water-based drilling fluids to be
landfarmed, and also limit oil and grease content of the wastes. Oklahoma
requires less than or equal to 30 mg/1 of oil and grease in wastes before
allowing spray application. Disking, and the resulting soil aeration,
also assists in the biodegradation of oil, grease, and other organics.
The presence of heavy metals (primarily barium, chromium, lead, and
zinc, and, to a lesser extent, arsenic, cadmium, mercury, selenium, and
silver) in drilling muds is also a concern (Kissock, 1986). The solution
to this problem is to limit the landfarming of wastes with high metal
content and to carefully maintain a soil pH range of 6.5 to 9.0, keeping
the heavy metals insoluble and immobile.
In addition to these considerations, the site and design of the
landfarming facility is a critical component in its success. Louisiana has
developed location and facility design standards that address these
concerns. These standards prohibit facilities in flood zones and
wetlands, limit their proximity to existing buildings, require spill
containment systems in loading and storage areas, and limit access to the
sites (Field and Smith, 1986). Additional standards detail requirements
1-2-28
-------
of the treatment zone, including thickness, permeability, and relationship
to the water table. This requires a detailed geological/geotechnical
investigation of prospective landfarming sites.
Roadspraying
In addition to landfarming, there are other types of land
applications for oil and gas wastes. In the past, pit and produced brines
have been used for ice and dust control on roads in Michigan. This
process, called roadspraying or roadspreading, is being discontinued by
order of the State. Alaska is also reconsidering the use of brines for
de-icing roads. Kansas still allows the spreading of brines on roads
under construction, and in New York, road spreading for ice control is the
predominant disposal method.
Subsurface Disposal
Subsurface disposal of oil or gas field waste is Federally regulated
through the Underground Injection Control (UIC) Program, as detailed in
Appendix A. States may be granted primacy over the UIC program as a
result of EPA's evaluation and approval of State programs. Otherwise, EPA
is the primary regulatory authority in matters of underground injection.
However, States that do not have primacy may have regulations in addition
to those imposed by the Federal UIC Program. Pennsylvania, for example,
regulates underground disposal of oil and gas field wastes through the
Clean Streams Law (Waite, et al., 1983).
One of the most common forms of liquid waste disposal used by the oil
and gas industries is injection into non-producing formations (Waite, et
al., 1983). Liquid waste is typically produced water (also known as
1-2-29
-------
brine) brought to the surface with the produced oil or gas. Historically,
surface disposal of produced brine has been believed to cause severe
environmental damage in States (EPA - OH, 1985a; EPA - IL, 1985a; EPA -
MM, 1985b), which has led to the widespread use of subsurface injection
methods.
Brine is injected to non-producing formations (or "safe horizons") by
two methods. The method often preferred by State regulatory agencies is
the use of disposal wells specifically drilled, cased, and completed to
accommodate brine. Figure 1-8 .displays a typical saltwater disposal well
pumping into a zone located far below the freshwater table (Elmer E.
Templeton and Associates, 1980). New wells may be constructed for this
purpose, or old wells may be retrofitted to meet construction
requirements. The second method is injection into the uncased annular
space of a producing well, or in the space within the production casing.
Figures 1-9 and 1-10 illustrate these, techniques (Templeton, 1980).
Annular disposal of brine to non-producing zones has been or is being
phased out of many States (Elmer E. Templeton and Associates, 1980).
Louisiana allows annular injection of reserve pit fluids whenever the
surface casing is deep enough to protect underground sources of drinking
water (Appendix A - LA).
Wells used for brine disposal must be carefully constructed in order
to protect freshwater aquifers. When old wells are retrofitted for brine
disposal, ground-water contamination may occur as a result of casing
failure. Consideration must also be given to abandoned wells in the
vicinity of a proposed disposal well site. Figure 1-11 illustrates the
potential for freshwater contamination created by abandoned wells
(Illinois EPA, 1978).
In addition to construction requirements, injection pressure must be
determined such that it successfully disposes of waste fluids without
1-2-30
-------
V/WCR
MONITOR ANfciULUS PRESSURE
MS
DISPOSAL ZONE 'r- -
— • -- D\iPO£AL Z
Figure I-S. Brine (saltwater) disposal well design.
Source: Templeton, Elmer E., and Associates, Environmentally
Acceptable Disposal of Salt Brines Produced with C;_l
and Gas, January, 1980.
1-2-31
-------
tf
JJ
^L
t^m^
1
1
— "1
I
1
f
f
T
I-
L
!
i
':(
I
V
^
— — - _ 1^ — _
vl- ^-
:Vv] '
" • 4 | -- — -- —
'. ' -J* '—
• ?!
^L^. CtMtNT
•' ' ~~
>
1
i
C&.MLKIT
PRODUC
)
: ' __ • _ .
PRODUCT-ON
V1G
PRCCUCING«
• «
Figure 1-9. Annular disposal outside production casing.
Source: Templetcn, .Elrr.er E. , anc Associates, Envircnr.ental
Acceptable Disposal of Salt Brines Produced with O
and Gas, January, 1980.
-------
PRODUCTION.
Figure I-10. Annular disposal within production casing.
Source: Templeton, Elmer E., and Associates, Environmentally
Acceptable Disposal of Salt Brines Produced with
Oil and Gas, January, 1980.
1-2-23
-------
BRINE-DISPOSAL
WELL
I
A Lond
AnANOONO) WCLLS
I I
WITH CASING NO CASING
B C
WATFR-SUPPLY
WELL
I
0 Surface
WATFR-Slim.Y
WtLL
I
ro
GJ
Cosing rusted;
failure or
absence of
cement
Well not
plugged or
improperly
plugged
V
INTERVENING ROCKS
--—^-CONFINING ROCKS(Low permeability) JII7
i—•B-^, " ' "••" % _ • . __ •"•""•'»•.. ,. <^i^^_
r-i^r • r^^*7>^v**^M^^^^BB_ *^* --. — • ~ ..^*',.._ " • i ii ™-
''Casing rusted; failure or
absence of cement
Figure 1-11. Pollution of a fresh water aquifer through abandoned wells.
Source: Illinois EPA, Illinois Oil Field Brine Disposal Assepsmoni-: nt.
Report, November 1978.
-------
propagating fractures (Waite et al., 1983). Estimated maximum and average
injection pressures must be included in applications for UIC permits (40
CFR 146.22).
Pretreatment of wastes prior to injection is used in locations of low
permeability in order to extend the life of disposal wells. In
Pennsylvania, pretreatment methods that have been used include settling,
filtration, and flocculation. These treatment steps are enhanced by the
addition of corrosion inhibitors, bactericides, and other additives used
to adjust pH or prevent undesired precipitation in the disposal reservoir
(Waite et al., 1983).
Another subsurface brine disposal alternative is injection of brine
into producing zones for the purpose of enhancing oil or gas production.
This secondary form of recovery is referred to as "water flooding," and
may utilize surface water in addition to produced water. This is a widely
accepted method of reusing produced water.
Drilling fluids and reserve pit wastes also can be disposed of by a
one-time annular injection, depending on the geological formations. This
type of subsurface disposal is preferred by some States because it
eliminates surface disposal problems. Oklahoma, for example, allows this
type of disposal, provided the well to be used has surface casing at least
200 feet below the depth of the base of the treatable water (McCaskill,
1985). Oklahoma sets no limit on the quantity of waste to be disposed of
in this manner, because this is a one-time act of disposal, unlike
continuous disposal of produced brine. Examples of other States that
allow the annular injection of drilling fluid are Mississippi (EPA - MS,
1985a) and Alaska (EPA - AK, in press).
1-2-35
-------
The intention of subsurface disposal of any waste is to avoid
treatment or hauling costs that would otherwise be required. Therefore, a
well and associated formation must be permeable enough to accept all the
waste generated onsite, or another disposal alternative must be employed.
In many areas, the alternatives are either costly or not allowed by State
regulations (Ohio EPA, 1983).
Ocean Discharge
The U.S. Environmental Protection Agency has established guidelines
for "Issuance of National Pollution Discharge Elimination System (NPDES)
permits for the discharge of pollutants from a point source into the
territorial seas, the contiguous zone, and the oceans" (40 CFR 125,
Subpart M), as required by Section 403 of the Federal Clean Water Act.
The guidelines are designed to "Prevent unreasonable degradation of the
marine environment and to authorize imposition of effluent limitations,
including a prohibition of discharge, if necessary, to ensure this goal"
(Federal Register, October 3, 1980).
In general, ocean discharge of wastes from onshore and coastal oil
and gas field operations is regulated on a case-by-case basis. States
that have NPDES programs oversee the permitting of any discharges or
dumping along the coast or in marine waters. States that do not have NPDES
programs, such as Louisiana and Texas, establish guidelines in
coordination with Regional EPA offices.
An example of State-established effluent limitations is California's
"Water Quality Control Plan for Ocean Waters of California," also called
"The Ocean Plan." The Ocean Plan defines Water Quality Objectives, based
on bacteriological, physical, chemical, biological, and radioactive
1-2-36
-------
characteristics, such that ocean disposal will not violate the
objectives. The Ocean Plan next defines General Requirements for
Management of Wastes and Effluent Quality Requirements.
The General Requirements specify constituents that must not be
present in waste discharges, such as floatable particulates, settleable
material that may be harmful to aquatic life, and materials that result in
discoloration of the ocean surface. Another General Requirement states
that waste discharges must be sufficiently diluted so as to minimize
concentrations of . substances not previously removed by treatment.
Finally, the General Requirements call for a "detailed assessment of the
oceanographic characteristics and current patterns" in order to determine
a discharge location that will protect shellfish harvesting areas, areas
of special biological significance, and the overall marine environment.
Effluent Quality Requirements are specified in Tables A and B of
Chapter IV of the Plan. Table A, presented here as Table 1-12, applies
only to discharges not covered by Sections 301, 302, 304, or 306 of the
Federal Clean Water Act. Table B, presented here as Table 1-13, applies
to all discharges within the jurisdiction of the Plan.
In California, wells located in the Santa Maria Basin were granted a
suspension to the onshore oil and gas effluent limitations guidelines
requiring "zero discharge" of any wastewater pollutants (Federal Register,
July 21, 1982). Exception was made for this area because of the geologic
and hydrogeologic problems associated with reinjection of produced water,
the normal disposal method.
Other companies, located outside the Santa Maria Basin and interested
in obtaining permits that would allow ocean discharge, have investigated
possible methods by which produced water can be disposed of.
1-2-37
-------
TABLE 1-12
CALIFORNIA OCEAN PLAN: MAJOR WASTEWATER
CONSTITUENTS AND PROPERTIES
Limiting
Concentrations
Monthly Weekly Max imum
Unit of (30 day (7 day at any
measurement Average) Average) time
Grease and Oil mg/125 40 7B~
Suspended Solids see below+
Settleable Solids mg/1 1.0 1.5 3.0
Turbidity JTU 75 100 225
pH units within limits
of 6.0 to 9.0
at all times
Toxicity Concentration tu 1.5 2.0 2.5
+Suspended Solids: Dischargers shall, as a 30-day average, remove 75% of
suspended sol ids from the influent stream before discharging wastewaters
to the ocean*, except that the effluent limitation to be met shall not be
lower than 60 mg/1. Regional Boards may, with the concurrence of the State
Board and the Environmental Protection Agency, adjust the lower effluent
concentration limit (the 60 mg/1 above) to suit the environmental and effluent
characteristics of the discharge. As a further consideration in making sucn
adjustment, Regional Boards should evaluate effects on existing and potential
water* reclamation projects.
If the lower effluent concentration limit is adjusted by the Regional Boars,
the discharger shall remove 75% of suspended solids from the influent stream
at any time the influent concentration exceeds four times such adjusted effluent
1 imit.
Source: Water Quality Control Plan for Ooean Water:
of California, November 17, 1985.
1-2-28
-------
TABLE 1-13
CALIFORNIA OCEAN PLAN: TOXIC MATERIALS
LIMITATIONS
Limiting Concentrations
Arsenic
Cadmium
Chromium (Cr+6)
Copper
Lead
Mercury
Nickel
Silver
Zinc
Cyanide
Total Chlorine Residual
(continuous sources)
Ammonia
(expressed as
nitrogen)
Toxicity Concentra-
tion
Phenolic Compounds
(non-chlorinated)
Chlorinated Phenolics
Aldrin and Dieldrin
Chlordane and
Related Compounds
DDT and
Derivatives
Endrin
HCH
PCS's
Toxaphene
Unit of
Measurement
ug/1
ug/1
ug/1
ug/1
ug/1
ug/1
ug/1
ug/1
ug/1
ug/1
ug/1
6-Month
Median
8
3
2
5
8
0.
20
0.
20
5
14
45
0.003
Daily
Maximum
32
12
8
20
32
0.56
80
1.8
80
20
11
2,400
0.006
Instantaneous
Maximum
80
30
20
50
80
1.4
200
4.5
200
50
124
6,000
0.009
Radioactivity
Not to exceed limits specified in Section 30269
of the California Administrative Code.
Source: Water Quality Control Plan for Ocean
Waters of California, November 17, 1983,
1-2-39
-------
One particular study investigated several methods including ocean
discharge via pipeline, river discharge, percolation/evaporation pond
disposal, effluent irrigation disposal, and other alternative methods
(CH2M Hill, 1983). The proposed ocean discharge alternative is
presented in two parts: a treatment system and outfall design, and
pipeline route considerations. The treatment system includes three process
steps:
• Induced gas flotation for oil and suspended solids removal;
• Filtration for final oil removal and effluent polishing; and
• A minimum dilution of 100:1 to be achieved by the ocean outfall.
Design criteria for two alternative pipeline routes are based on
pipeline orientation, pumping requirements, and piping requirements. Both
the treatment system and the p'ipeline routes are designed to meet the
anticipated ocean discharge effluent limitations defined by the California
Ocean Plan {CH2M Hill, 1983).
Alaska permits ocean discharge of oil and gas drilling waste
according to applicable Federal NPDES requirements. The permitting
authority is U.S. EPA Region X. Alaska does not have its own NPDES
program. Statutory bases on which permits are written in this State are
derived from the Federal Clean Water Act, Sections 301(b), 304, 308, 401,
402, and 403, and include technology-based effluent limitations, ocean
discharge criteria, and State of Alaska standards and limitations (U.S.
EPA Region X, 1985). Specific permit requirements allow discharge of
"generic [drilling] muds and authorized additives," listed in Table 1-14.
Under this provision, drill cuttings that meet specified content
requirements may be discharged "without special permission" (U.S. EPA
Region X, 1985).
1-2-40
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TARI.K I-.14
U.S. EPA REGION X: AUTHORIZED DRILLING MUD TYPES
i
ro
i
Components
I. Seawater/Freshwater/Potasslum/Polymer Hud
ice I
Starch
Cellulose Polymer
Xanthan Gum Polymer
Drilled Solids
Caustic
Barlte
Seawater or Freshwater
2- ifWlfl'USOJHuJloniii M*y!
AttapuTgite or Behtonite
Llgnosulfonite. Chrome or Ferrochrome
Lignite, Untreated or Chrome-treated
Caustic
Barlte
Drilled Solids
Soda Ash/Sodium Bicarbonate
Cellulose Polymer
Seawattr
3. lime Mud
Lime
Bentontte
Llgnosulfonjte. Chrome or Ferrochrome
Lignite. Untreated or Chrome-treated
Caustic
Barlte
Drilled Solids
Soda Ash/Sodium Bicarbonate
Seawater or Freshwater
4. Hondlspersed Hud
Bentonlte
Acrylic Polymer
Barlte
Drilled Solids
Seawater or Freshwater
HaKI mum Allowable
Concentration
(Ib/bbi)'
50
12
S
2
100
3
4SO
As needed
50
15
10
5
450
100
2
5
As needed
20
50
15
10
5
ISO
100
2
As needed
15
2
ISO
70
As needed
Components
Spud Hud
Lime
Attapulglte or Bentonlte
Caustic
Barlte
Soda Ash/Sodium Bicarbonate
Seawater
Seawater/Freshwater Gel Hud
Lime
Attapulglte or Bentonlte
Caustic
Barlte
Drilled Solids
Soda Ash/Sodium Bicarbonate
Cel lulose Polymer
Seawater or freshwater
_....
Li"- ! shwater/Seawater Hud
Lime
Bentonlte
Llgnosulfonate, Chrome or Ferrochrome
Lignite, Untreated or Chrome-treated
Caustic
Barlte
Drilled Solids
Soda Ash/Sodium Bicarbonate
Cellulose Polymer
Seawater & Freshwater In 1:1 ratio
Llgnosulfonate Freshwater Mud
Lime
Bentonlte
Llgnosulfonate. Chrome or Fprrochroroe
Lignite. Untreated or Chrome-ti eated
Caustic
Barlte
Drilled Solids
Soda Ash/Sodium Bicarbonate
Cellulose Polymer
freshwater
Majilmuffl Allowable
Concentration
(ib/bbi)
I
50
2
50
2
As needed
2
50
3
50
100
2
2
As needed
2
50
6
4
3
180
100
2
2
As needed
2
50
15
10
5
450
100
As
Source: NPDFfl Pornn't- No. AK-On4497-l (draff-). 1985
-------
In general, ocean discharge of oil and gas field wastes is viewed by
concerned State agencies as an acceptable discharge alternative, provided
that effluent limitations are observed by the industry (EPA - CA, 1985).
CONSTRUCTION AND MONITORING REQUIREMENTS
Introduction
There is wide, variation among governmental entities regarding
construction and monitoring requirements associated with pits, sumps, or
impoundments used to contain wastes generated from drilling and production
operations. This section of the report discusses design and construction
features, and provide examples of impoundments and centralized/offsite
pits as prescribed for Federal lands and by States.
The terms "sump," "impoundment," "pond," and "lagoon" often are used
synonymously to describe a pit (EPA, 1983). The pit consists of an
excavation of predetermined size and shape, and may be lined or unlined
depending upon the intended purpose.
In the 1983 EPA Surface Impoundment Assessment National Report, the
following statistics were determined from a sample population of oil and
gas sites:
• Thirty-one percent (64,951) of all sites (176,242) were oil and
gas sites. (Pits associated with drilling activities were
excluded.)
• Thirty-seven percent of all impoundments were associated with the
oil and gas category.
1-2-42
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• Through the randomization of site selection, only 13 percent of
the located oil and gas sites and 5 percent of the oil and gas
impoundments were assessed.
• Disposal is the primary purpose of 67 percent of the oil and gas
impoundments, with 29 percent being used for storage (i.e.,
emergency pits), and 4 percent being used for treatment prior to
discharge (usually oil skimming).
• Only 20 percent of the oil and gas impoundments were lined. For
this report, however, the definition of a liner did not consider
mixing bentonite with native soil or compacted soils as liners.
In the exploration and development phases, reserve pits are used to
store drilling fluids, cuttings, and associated wastes produced by
drilling. At the drill site, there may be one reserve pit to handle all
drilling wastes or several individual pits to serve different purposes,
such as containing fresh "make-up" water, holding circulating mud prior to
disposal in the reserve pit, holding well treatment fluids (fracture
fluids), acting as an emergency pit, and acting as a test pit. These pits
generally are constructed for temporary use and are backfilled at the end
of drilling operations.
During the production phase, pits are utilized for several different
purposes. A pit is constructed to hold produced waters. This pit is
designed for the long-term storage and evaporation of fluids associated
with the production of oil and gas. At wells that are reinjecting fluids,
long-term storage pits are constructed to act as settling/holding ponds
for the injection fluid.
In general, pit construction practices are left to the discretion of
the company and subsequently pit designs vary widely throughout the oil
and gas industry. Many parameters must be taken into consideration in the
proper design and construction of a pit, including facility layout.
1-2-43
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function, location of drilling rig, location of adjacent water bodies,
geology, climatology, topography, volume of waste, ground-water hydraulic
gradient, characteristics of waste, and soil characteristics.
The following is a brief synopsis of specific pit design and
construction criteria for the containment of wastes associated with
exploration, development, and production of oil and gas.
Pit Design and Construction Features
Pit Types
Reserve pits. Proper location and construction of pits facilitate
the reclamation process and help prevent problems such as leakage and pit
wall failure. Ideally, a pit should be excavated from undisturbed, stable
subsoil to prevent pit wall failure. For areas where excavating below
ground level cannot be done, the pit berm is usually constructed as an
earthen dam. Sidewalls should be constructed with a slope of less than
3:1 to give support and minimize seepage. Whenever possible, a reserve
pit should not be constructed on sloping ground or near the edge of a hill
top. This is often impossible to avoid, which means that the hillside must
be contoured in such a way that the runoff water is diverted around the
drilling location and reserve pit. Pits should be located a minimum of
300 feet laterally from the high water mark of the nearest water body
and/or intermittent water courses, according to one source (MoeCo, 1984).
The site chosen should be high enough to escape flooding in heavy rains.
A reserve pit is typically excavated directly adjacent to where the rig
and associated mud equipment will be sited; however, in recent years, a
growing practice for disposal of drilling fluids has involved the use of
centralized pits.
1-2-44
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Centralized pits are larger than onsite pits, and they may serve the
disposal needs for drilling or production wastes from multiple wells over
large geographical areas. Centralized pits should be close to drilling
and production sites to be cost-effective, yet they should be located in
environmentally safe areas. A site removed from well-defined drainage
basins will minimize the potential for surface water pollution from heavy
runoff (Univ. of Oklahoma, 1984).
The reserve pit should be of adequate size to properly contain the
drilling fluid. The reserve pit volume should allow for ample freeboard
when the pit is full. The purpose of freeboard is to create a margin of
safety to protect against unexpected drilling conditions and unpredictable
elements in planning the mud program. Increasing drilling depth increases
the drilling fluid volume and therefore more reserve pit capacity may be
required. Overfilling the pit has presented significant problems in the
past. In the case of an off site pit, the design volume is generally a
function of land availability and topography, along with business-related
estimates of drilling fluid volumes likely to be generated within the
potential geographical service area (Univ. of Oklahoma, 1984).
Percolation pits. There is a certain controversy over whether
percolation or seepage is an allowable alternative to evaporation in areas
with humid climates (Illinois EPA, 1978). Regulations concerning the
matter vary from State to State. Many State regulations prohibit the use
of percolation pits; some States require a ground-water discharge permit
for their use. A percolation pit is an unlined pit in which substantial
waste volume percolates to the ground, with some loss through
evaporation. The percolation pit is designed and located to maximize the
infiltration of waste through the soil profile. The critical limitations
for any specific site would be the depth to ground water, ground-water
quality, actual or potential use of ground water, and the existence of any
1-2-45
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impermeable layers within the soil profile. Percolation pits must be sited
in areas where the distance to ground water is great and where there are
no restrictions to infiltration. In addition, the location of the
percolation pit could depend on the location and quality of the underlying
ground-water aquifer. Percolation can adversely affect the ground-water
quality. Percolation pits often are designed with several cells, so that
one cell can be cleaned or raked if necessary to improve filtration while
others are in use (CH_M Hill, 1983). Percolation pits are not always
*£
suitable for all waste materials, and seepage can result in the formation
of pockets of salt in .the underlying soil. These salts can slowly migrate
to ground water via leaching (Univ. of Oklahoma, 1984).
Evaporation pits. When properly designed, constructed, and operated,
evaporation pits rely on the atmosphere to concentrate brines or drilling
fluids by removal of water as vapor. The relationship between the local
precipitation and evaporation rates should therefore be considered. The
successful operation of such a pit depends on the annual net evaporation
rate of the brine or drilling fluid. The presence of dissolved solids and
oil films lowers the evaporation rate. Other variables influencing the
rate include the air and brine temperature, relative humidity, and wind
speed (Reid, et al., 1974). If the space at the drilling location is
adequate, it is preferable to have a larger, more shallow evaporation pit,
because the increased surface-area-to-volume ratio enhances the
evaporation rate and final disposal can be achieved more quickly and
efficiently. When suitable foundation soils are not available,
alternatives must be sought such as lining with clay, concrete, or asphalt
or employing a synthetic material to line the pit (MoeCo,
1984).
1-2-46
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Pit Liners
Natural pit sealing has been found to occur when the settled solids
form a bottom layer that physically clogs the soil pores (Univ. of
Oklahoma, 1984). This can occur most effectively with certain types of
drilling fluids, and many drill operators count on this phenomenon to seal
mud pits (Freeman and Deuel, 1986). In permeable soils, however, natural
sealing may not afford enough protection and earthen pits should be lined
with an impermeable material. Many types of man-made pit liners exist,
and they can be classified into two major categories: (1) synthetic and
rubber liners and (2) earthen and cement liners. Also, there is a wide
variety of application characteristics within each of these categories.
Choosing the appropriate lining for a specific site is a critical issue in
the design for seepage control. The criteria for lining a pit are highly
dependent on the specific geographical location, climate, local
hydrogeology, and the characteristics of the waste material.
Synthetic and rubber liners. Synthetic and rubber liners include
PVC, butyl rubber, neoprene, and hypalon. Synthetic liners are popular in
applications requiring essentially zero permeability. These materials are
economical and resistant to most chemicals when selected and installed
properly. However, many are susceptible to degradation by ultraviolet
rays and, therefore, should not be used in long-term impoundments.
Further, there is disagreement regarding the level of tensile strength and
puncture resistance needed (Western Workshop, EPA, 1985). Standard
procedures for installing and maintaining synthetic membrane liners
suggest that side slopes should not exceed a ratio of 3:1 and subgrade
surface should be dragged for sharp rocks and rolled smooth. A layer of
clay is applied as a base for the membrane liner. Generally, membrane
liners are made from sheets of 0.008 inch or thinner and must be protected
from mechanical damage. As a protective measure, the liners are often
1-2-47
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buried (Univ. of Oklahoma, 1984). The effectiveness of the membrane liner
depends on not being punctured or torn during installation or use. It is,
therefore, imperative that liners meet proper strength and durability
specifications and are employed properly.
Earthen and cement liners. Bentonite, asphalt, and soil cement have
been used as linings for pits and reservoirs for several decades.
Bentonite is a sodium-type montmorillonite clay and exhibits a high degree
of swelling, imperviousness, and low stability in the presence of water.
Seepage losses for bentonite-lined pits represent about a 60 percent
improvement over unlined pits (Univ. of Oklahoma, 1984). The construction
approach for using bentonite to line pits involves overexcavating the area
to allow for the added layer of clay. Side slopes should not exceed 2:1.
The subgrade is smoothed and dusted and the bentonite layer applied over
the top. Permeability of bentonite linings is greatly affected by the
quality of the bentonite. If the bentonite is finer than a No. 30 sieve,
it should be used without specifying size gradation, but if the material
is coarser than the No. 30 sieve, it should be well-graded. Bentonite
tends to crack and deteriorate if allowed to dry; therefore, a protective
blanket of soil is usually placed over the bentonite layer.
Asphalt linings composed of prefabricated buried materials can be
used for both onsite and offsite disposal pits, since the amount of
special equipment and labor connected with installation is minimal.
Asphalt membrane linings can be constructed at any time of year. Its
convenient usage in canals and ponds may dictate that buried asphalt
membrane lining is the appropriate one to use in many cases. Asphalt has
been used extensively as a lining material for brine storage basins
(Ostroff, 1965).
1-2-48
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Examples of Drilling Pit/Impoundment Permit Requirements
Drilling Reserve Pits
Often States do not issue permits relating to drill pits or reserve
pits. Monitoring generally is not required; construction requirements
vary. Some States have construction guidelines covering above or below
ground construction, required freeboard, and compaction. Pits typically
are unlined. Such pits contain drilling cuttings, contaminated fresh and
salt water produced during construction and well stimulation, and various
additives used during drilling and well stimulation. Often pits are not
reclaimed, nor is there a permit required for a drill pit, nor a
contingency fund required for management of abandoned pits (Appendix A -
PA).
General language is used in other State regulations to require that
mud pits, sumps, reserve pits, or tanks be of sufficient size and managed
to prevent contamination of ground water and damage to the surface
environment. After a well is completed or abandoned, the fluids are to be
removed and disposed of properly, and all mud pits, sumps, reserve pits,
and dikes usually must be backfilled with earth or graded and compacted in
such a manner as to be returned to a nearly natural state.
There may or may not be a requirement for lining with plastic or an
impervious material and, generally, such pits must be closed within 12 to
18 months. Often, the pits are placed in wetlands (Summary of State
Regulations - Alaska, California, Ohio, Oregon, North Dakota, South
Dakota; Alabama Oil and Gas Administrative Code 400-1-5-.03; Alaska Oil
and Gas Commission 20 AAC 25.047; Georgia Department of Natural Resources
391-3-13(11); Oklahoma Oil and Gas Conservation Division Rule 3-110.1; and
Tennessee State Oil and Gas Board 1040-3-3-.02). Generally, State
agencies do not prescribe drilling pit construction conditions.
1-2-49
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More specific instructions are supplied to a driller by the Arkansas
Department of Pollution Control and Ecology through a Letter of
Authorization. Reserve pits must be constructed with either a synthetic
liner of at least 20 mils thickness or an 18- to 24-inch compacted clay
liner. Such reserve pits must maintain at least a 2-foot freeboard. Pits
must be closed within 60 days after the drilling rig is removed from the
site. In Utah, saltwater and oil field wastes associated with the
drilling process may be disposed of by evaporation if impounded in
excavated earthen reserve pits underlain by tight soil or lined (Rule 309
- Utah Oil and Gas Commission).
A Letter of Instruction was issued by the Michigan Supervisor of
Wells on April 6, 1981, which provided for a two-pit drilling mud
system—one for freshwater muds and one for saltwater muds—and required
that all reserve pits receiving other than freshwater fluids be lined with
20 ml PVC or an equivalent liner as approved. Instructions, in 1985
require that all mud pits be lined with an impervious material that will
meet or exceed specifications for 20 mil virgin PVC. Liners shall be one
piece, or with factory-installed seams, and shall be installed in a manner
sufficient to prevent both vertical and lateral leakage. A revised
Supervisor Instruction, effective February 1, 1985, requires that cellars
shall be sealed, and rat holes and mouse holes shall be equipped with a
closed-end steel liner or otherwise sealed or cased in such a manner that
all fluids entering the cellar, rat hole, and/or mouse hole shall not be
released to the ground but shall be discharged to steel tanks, the lined
reserve pit, or the mud circulation system. Aprons of 20 mil virgin PVC
or other equivalent material shall be installed under steel mud tanks and
overlapping the mud pit apron, and in ditches or under pipes used for
brine conveyance from cellars to pits or to steel mud tanks (Appendix A -
MI).
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Production Impoundments
Montana allows evaporation of production salt water when impounded in
excavated earthen pits underlain by tight soil such as heavy clay (Oil and
Gas Conservation Division 36.22.1227). California uses lined sumps for
evaporation of produced fluids (Appendix A - CA). The Colorado Oil and
Gas Conservation Commission in 1984, Rule 325, specifies that if domestic
water supplies are found to immediately underlie significant geographical
areas and are not separated from the surface by a confining layer, it is
to be proposed to the Commission that a rule be adopted to require all
produced fluid retaining pits in the area to be lined and properly
constructed so as to prevent pollution.
Wyoming exercises its regulatory authority over the construction
location, operation, and reclamation of produced water pits that are used
for the storage, treatment, and disposal of production and treated unit
wastes. After June 1, 1984, no earthen retaining pit can be constructed
without a permit. Produced water pits that receive less than 5 barrels of
water per day on a monthly basis may be exempt from the formal permit.
Owners of produced water retaining pits in operation prior to June 1,
1984, may continue with such operation as long as it causes no
endangerment to the State's waters and as long as the operation conforms
to the requirements of new pits. When any retaining pit is sited in an
area where the potential for communication between the pit contents and
surface water or shallow ground water is high, the Commission may require
lining or waterproofing of any retaining pit, installation of monitoring
systems and provisions for reporting, and any other reasonable requirement
that will assure the protection of fresh water. Unlined pits must not be
constructed on fills. Pits must not be constructed in a drainage, or in
the flood plain of a flowing or intermittent stream, or in an area where
there is standing water during any portion of the year (Wyoming Oil and
Gas Commission Rule 326).
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Rule 632-10-192 of the Oregon Department of Geology and Mineral
Industries provides for saltwater disposal in excavated earthen
evaporation pits that are lined with impervious material. All pits must
have a continuous embankment surrounding them sufficiently above the level
of the surface to prevent surface water from running into the pit.
Illinois also provides for saltwater evaporation in lined pits (Illinois
Division of Oil and Gas Rule lX(2)(a». Mississippi requires temporary
saltwater storage pits to be lined with an impervious material. Salt
water must never rise to within 1 foot of the top of the pit walls or
dikes (Rule 63.III.E.3). .
In proposed Rule 83-3-600, the State Corporation Commission of the
State of Kansas would require all surface permitted ponds to have
30 inches of freeboard; observation trenches, holes, or wells, if
required; and be sealed with artificial materials if it is determined that
an unsealed condition will present a pollution threat to soil or water
resources.
The Utah Water Pollution Control Committee, in Part VI, 6.4 of
wastewater disposal regulations, requires surface disposal ponds to be
fenced and properly netted to prevent access by waterfowl, to have a
minimum 2 feet of freeboard, and to be lined. Each pond used for disposal
of more than 100 barrels per day of produced water is required to have
monitoring wells and leak detection technology in both vertical and
horizontal directions. Detailed instructions are provided for onsite
containment soil and for liners.
The Railroad Commission of Texas has issued a Water Protection
Manual, published by the Texas Oil and Gas Division, which provides design
and construction techniques for pits proposed for long-term, continuous
use that must be authorized by permit. All earthen dikes surrounding pits
1-2-52
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should be constructed of soil material that is capable of achieving a
permeability of 1 x 10 cm/sec or less when compacted. During
construction, successive lifts should not exceed 9 inches in thickness,
and the surface between lifts should be scarified to achieve a good seal.
The dike height and width should be consistent with the volume of
wastewater to be retained. When wastewater is retained in aboveground
pits, it is recommended that the top width of the dike be at least 4 feet
and the side slopes not be steeper than 3 to 1 (3 feet horizontal to
1 foot vertical). Dikes for all pits are "keyed" into the underlying soil
to achieve a good seal between the ground and the bottom of the dike to
prevent lateral seepage of wastewater through the base of the dike. Two
of the most common construction methods for pits are "above ground" and
"below ground." The aboveground pit should be used in areas where the
water table is high. The aboveground method consists of constructing
dikes around the area without excavating below the surface. The
below-ground method of constructing a pit consists of excavating an area
and building dikes around the excavation. The below-ground pit should be
used in areas where the water table is well below the surface.
A proposed rule of the Alaska Oil and Gas Commission would require
monitoring of surface ponds to include at least three ground-water
monitoring wells and may include a leachate collecting and sampling system
designed to collect any waste or leachate escaping as a result of the
failure of the primary liner. Finally, the Letter of Authorization from
the Arkansas Department of Pollution Control and Ecology requires produced
salt water to be stored in a plastic or fiberglass tank above ground and
resting on a concrete pad.
Centralized/Offsite Pits
On the western side of the San Joaquin Valley, California, there is a
wastewater disposal facility permitted on Federal land where the oil
1-2-53
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industry has cooperated with a private consultant and formed a series of
sumps that cover approximately 20 to 40 acres. These sumps are used for
percolation and evaporation (Summary of State Regulations - California).
Rule 325 of the 1984 Rules of the Colorado Oil and Gas Commission
requires an impervious, weather-resistant lining, a leak detection system,
monitoring wells, and an opportunity for State inspection of the leak
detection system, the liner, and cover material for the liner.
Rule 3-110.2 of the .Oklahoma Corporation Commission permits the use
of centralized earthen pits provided they are sealed with an impervious
material, do not receive outside runoff water, and are filled and leveled
within 1 year after abandonment. The chloride content of the contained
fluids must not exceed 3,500 mg/1. Centralized pits are created by
excavating, damming gullies, and using abandoned strip pits. Every
centralized earthen pit must be completely enclosed by a permanent woven
wire fence of at least 4 feet in height. No centralized earthen pit is
allowed to contain a soil seal less than 12 inches thick with the
coefficient of permeability no greater than 10 cm/sec. Mew pits are
required to have monitoring wells, which are sampled principally for
chlorides and pH. There is currently a proposal to make such requirement
applicable to existing centralized pits. Three wells would be
required—one upgradient and two downgradient. Any indicated change over
background in the constituent levels tested would indicate potential
pollution.
Federal Lands
The Bureau of Land Management (BLM) approves the use, on Federal
lands, of unlined surface pits as a temporary means of storage of fluids
associated with drilling, redrilling, reworking, deepening, or plugging of
1-2-54
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a well. Such pits must be promptly and properly emptied and restored upon
completion of the operations; they may be used for well evaluation
purposes for 30 days (see Appendix A. Summary of Federal Regulations -
Bureau of Land Management).
Generally, BLM authorizes unlined pits when: (1) input fluid volume
averages 5 barrels or less per day, (2) the total dissolved solids is less
than 5,000 mg/1, (3) water will be used for livestock or wildlife watering
or irrigation, (4) well fluids are of better quality than area's surface
or subsurface waters, and .(5) a discharge is allowed by an NPDES permit.
The Bureau of Land Management permits disposal of produced water into
lined and unlined pits, but all such pits must: (1) have adequate
storage, (2) be maintained to prevent surface discharge, (3) be fenced to
preclude large animal entrance, (4) be maintained free from floating oils,
and (5) be constructed away from established drainage areas and to prevent
surface water entrance.
For longer-term, lined, produced water disposal pits, leak detection
underlying a gravel-filled sump and lateral system is required.
Monitoring is limited to total dissolved solids, pH, chlorides, and
sulfates.
EVALUATION OF WASTE MANAGEMENT METHODS
An evaluation of disposal methods will be conducted for waste
disposal techniques. Disposal methods will be examined to determine their
effectiveness in removing (or mitigating the environmental effects of) the
pollutants identified during the screening sampling program conducted June
- September 1986 on wastes from onshore oil and gas sources. Analytical
results from the screening sampling program will be presented in the EPA
Technical Report due January 31, 1987.
1-2-55
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Identification of waste management practices has been accomplished
through research into published and unpublished literature, through
extensive contact with State regulatory agencies, through observation
during the screening sampling program, and through interviews. The
control/disposal practices identified through this research were presented
earlier in this chapter.
Waste management practices other than those identified in this report
may be appropriate for particular pollutants, groups of similar
pollutants, or estimated pollutant loadings. Identification of alternative
waste management practices would be questionable, however, if it was based
only on the limited data available from the literature. The literature
contains little data regarding the full range of constituents in oil and
gas wastes (see Literature Review under Waste Generation). Thus,
identification of alternative treatment and disposal technologies will be
directed by the analytical results from the screening sampling program
previously mentioned. Detailed sample site documentation, in addition to
the analytical results, will be part of the January 1987 technical report.
Alternative technologies will be identified based on historical
evaluations of their effectiveness for handling particular pollutants,
groups of similar pollutants, or pollutant loadings as targeted by
analytical data from the screening sampling program. Technology transfer
and data for new treatment methods under development will also be
considered.
When the data are available, the effectiveness of waste management
practices will be evaluated based on:
• Fundamental chemical and/or engineering concepts;
• Treatability or other related information from the literature;
1-2-56
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• Best estimates based on professional engineering judgments; and
• Environmental conditions.
It is anticipated that the evaluation of control/disposal techniques
will be presented in detail in the final technical report. For ease of
understanding, however, the effectiveness of the technology may be ranked
in ranges appropriate to distinguish between levels of performance.
Mitigating circumstances affecting the performance of a particular
technology (e.g., the use of evaporation pits in areas of net
precipitation) will also be presented.
If the analytical data present a relatively limited list of
pollutants of concern, a matrix will be constructed identifying the major
pollutant loadings in each waste stream, current waste management
practices, and alternative control/disposal techniques, as illustrated by
the example in Figure 1-12. (If the pollutant list is extensive, an
effort will be made to construct the matrix presenting only the most
hazardous, difficult to treat, or highly concentrated pollutants.)
Entries in the matrix will be codified to indicate the estimated
effectiveness of waste management practices for each pollutant found in
concentrations of concern. The matrix will serve as a summary of a
detailed discussion of the evaluation for each waste management practice.
Some alternative waste management practices will be identified for
control or treatment of particular pollutants. It is expected that
literature regarding treatability or other aspects of the technique(s)
which mitigate environmental effects will provide a basis for the
evaluation.
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CURRENT PRACTICES ALTERNATIVE TECHNIQUES
Major pollutants
DRILLING
Muds
Pollutant 1
Pollutant 2
Pollutant 3
Reserve pits
Pollutant 1
Pollutant 2
Pollutant 3
PRODUCTION
Produced water
Pollutant 1
Pollutant 2
Pollutant 3
(and so forth for each major waste stream)
Figure 1-12 Example matrix of pollutants and control/disposal
methods to be constructed
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REFERENCES
California Water Resources Control Board. 1983. Water Quality Control
Plan for Ocean Waters of California, November 1983.
Canter, L. W. , et al. 1984. Environmental Implications of Off-site
Drilling Mud Pits in Oklahoma. University of Oklahoma, Environmental and
Ground Water Institute, for Oklahoma Corporation Commission. May 1984.
Volumes I and II.
CH2M Hill. 1983. Feasibility Study Report: San Ardo Field Produced
Water Disposal/Reuse, June 1983.
Corporate Literature supplied by VenVirotek, 1536 Eastman Ave., Suite 6-A,
Ventura, CA 93003.
Crabtree, Allen F. 1985. Drilling Mud and Brine Waste Disposal in
Michigan, Geological Survey Division of Michigan Department of Natural
Resources, April 1985.
Deeley, George M. and Larry W. Canter. 1985. "Chemical Speciation of
Metals in Nonstabilized and Stabilized Drilling Muds" In: Proceedings of
a National Conference on Disposal of Drilling Wastes, May 1985.
E-Vap Systems. "For Immediate Release: Water Disposal for Gas or Oil
Wells by Evaporation," (advertisement), E-Vap Systems, 400 North 8th, Fort
Smith AR 72901.
Federal Register Vol. 47 No. 139, July 21, 1982.
Field, Mary M. and W. G. Smith. 1986. Design Considerations for
Landfarming Non-Hazardous Oilfield Waste Drilling Fluids.
Freeman, B. D. and L. E. Deuel. 1986. Closure of Freshwater Base
Drilling Mud Pits in Wetland and Upland Areas.
Illinois EPA. 1978. Illinois Oil Field Brine Disposal Assessment: Staff
Report, November 1978.
Kissock, D. C. 1986. Landfarming: The Cost Effective State-of-the-Art
Solution to Oilfield Waste Disposal.
Kus and Card. 1984. "Produced Water Reuse Considerations for In-situ
Recovery: A Case Development," The Journal of Canadian Petroleum
Technology, January 1984, p. 66.
McCaskill, Clark. "Well Annulus Disposal of Drilling Wastes" In:
Proceedings of a National Conference on Disposal of Drilling Wastes, May
1985.
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McCray and Cole. 1959. Oil Well Drilling Technology, University of
Oklahoma Press.
Michalczyk, Betr L., I.E. Pollock, and Heather R. White. 1984. Treatment
of Oilfield Production Waters, October 1984.
Michigan Department of Natural Resources, Letter of Instruction,
Supervisor of Wells, April 6, 1981.
Moeco Sump Treatment, "Brief Summary of the Reverse Osmosis Process"
(advertisement), July 24, 1984.
NL Baroid, Advertisement for ENVIRO-FLOC™ and ENVIRO-FIX™
reserve pit treatment processes, 1986.
Neidhardt, Dietmar. "Rig-site System Allows Water Reuse, Cuts Cleanup
Costs," Oil and Gas Journal, March 4, 1985, p.88.
Ohio EPA. Brine Disposal from Oil and Gas Production in Ohio, 1983
(reprint).
Railroad Commission of Texas. 1985. Water Protection Manual.
Templeton, Elmer E. and Associates. 1980. Environmentally Acceptable
Disposal of Salt Brines Produced with Oil and Gas, for the Ohio Water
Development Authority, January 1980.
U.S. EPA Region X. 1985. "Authorization to Discharge Under the National
Pollution Discharge Elimination System," No. AK-004497-1 (draft).
U.S. EPA. Air Drilling Technology: Five States in West Virginia, November
1985.
U.S. EPA. Office of Drinking Water. Surface Impoundment Assessment -
National Report. December 1983.
U.S. EPA. Sampling Site Visit, Louisiana, June 16, 1986.
U.S. EPA. Sampling Site Visit, West Virginia, August 18, 1986.
U.S. EPA. Site Visit Reports - Screening Sampling Program for Oil and Gas
Industry. In Press. June-September 1986.
U.S. EPA. State/Federal Western Workshop, Alaska, December 1985.
U.S. EPA. State/Federal Western Workshop, California, December 1985.
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U.S. EPA. State/Federal Western Workshop, Louisiana, December 1985.
U.S. EPA. May 1973, Fox et al. Recondition and Reuse of Organically
Contaminated Waste Sodium Chloride Brines.
Waite, Burt A., Jeffrey L. Moody, and Scott C. Blauvelt. 1983. Oil and
Gas Well Pollution Abatement Project ME No. 81495, Part C, submitted to
the Pennsylvania Department of Environmental Resources, June 1983.
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CHAPTER 3
ESTIMATING THE COSTS OF ALTERNATIVE WASTE MANAGEMENT PRACTICES
INTRODUCTION AND OVERVIEW
As requested under Section 8002(m)(F) of RCRA, this chapter of the
report describes EPA's procedures for estimating the costs attributable to
oil and gas field alternative waste management practices. Essentially,
this involves estimating the incremental costs to oil and gas field
companies of implementing increased levels of environmental control beyond
the "baseline" practices currently employed in the various Regions and
States. For the Report to Congress, these costs will be estimated at the
individual project level for representative typical projects. Costs will
also be scaled up to Regional and National totals as a basis for
evaluating potential industry-wide impacts (see Chapter 4).
Procedures for estimating these costs involve a series of steps
described briefly in the following paragraphs.
Step 1. Identifying Relevant Waste Management Practices
For cost estimating purposes, relevant practices include both standard
waste management practices commonly employed in the various producing
regions, as well as more advanced or sophisticated waste treatment,
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storage, and disposal methods that are potentially applicable but may be
used less frequently or not at all in certain regions at present. A
relatively complete array of such practices was described earlier in
Chapter 2 of this report, and a selected representative group will be used
in the cost study.
Step 2. Estimating Project-level Costs for the Selected Waste Management
Practices
Engineering cost functions will be developed for the individual waste
practices based on previous EPA cost modeling work, current industry
literature, and selected industry interviews, as necessary. These cost
functions for unit processes at various sizes will constitute the building
blocks of the cost estimating methodology. Preliminary work and data
sources for these basic costs are described in some detail following this
introductory overview.
Step 3. Structuring Waste Management Scenarios
In order to have a consistent basis for evaluating costs, it is
necessary to define all cost elements associated with each waste
management alternative, both at the facility level and the aggregate
industry level. Basically, the concept of the "scenario" is to
hypothesize a given level of environmental control, typically a level
beyond the baseline that is currently being achieved at some, or perhaps
many, projects in a given region. This might be stated in terms of a set
of waste-management technology requirements (such as present RCRA Subtitle
C Standards) or in terms of specified conditions on environmental
contaminant releases, or otherwise. Two or three such alternative
scenario will be structured for purposes of the Report to Congress. Each
scenario will clearly state both the types of waste characteristics
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relevant to the particular case and the control measures involved so that
comparisons may be drawn between the costs of practices observed in the
baseline profile and the costs estimated for the practices assumed in a
given alternative scenario.
Step 4. Determining Affected Projects
Not all projects in a given Region or State will be affected by a
given scenario for increased environmental control, either because the
project does not generate "problem" wastes or because current practices
(either naturally or because of current State or other Federal
regulations) already meet the full requirements for the management
scenario. This may be the case for entire States or multi-State Regions
for a given scenario. The task here is to identify the proportions of
total projects in all major Regions that would be affected and the degree
to which they would be affected for particular waste-categories. This is
an essential step in generating reasonable cost estimates at the
individual project level, and especially so in scaling costs to Regional
and National aggregates.
Step 5. Calculating Project-level Cost Increases
Given the waste management cost functions for both baseline and
alternative practices, together with information on Regional practices and
affected facilities, "incremental costs" (increases incurred between
baseline and improved alternative practices) will be calculated for
representative Regional projects. (Regional differences are discussed in
some detail in Chapter 4 in conjunction with economic impacts and the
selection of typical representative projects.)
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Step 6. Scaling Up to Regional and National Aggregate Cost Totals
The final step in the cost estimating analysis is to use information
gathered from the industry-wide profiles of affected projects, together
with the incremental cost estimates for representative projects, to
calculate aggregate costs. Total investment costs, total annualized
costs, and cost per unit of product (per gallon of crude oil or per MCF of
natural gas) will be presented on both a Regional and National basis for
comparisons. These aggregate costs, together with costs for
representative projects, provide the basis for estimating the significance
of any potential economic impacts due to changes in current practices.
These economic effects are the subject of Chapter 4.
The remaining pages of this chapter provide further details on
estimating methods and expected sources of data on cost functions and
other work in progress.
ESTIMATION OF COSTS FOR INDIVIDUAL CURRENT AND ALTERNATIVE WASTE MANAGEMENT
PRACTICES
The purpose of this section is to discuss a limited number of
representative disposal practices, such as the use of earthern pits {lined
and unlined) and Class II (hazardous waste) injection wells, and to
briefly describe how EPA will estimate baseline alternative management
costs. The section also presents known or expected sources of information
to support the cost analysis.
Cost estimates for other important current control and disposal
methods not included here, such as waste solidification, landfarming, and
incineration, which are described at length in Chapter 2, will also be
analyzed as part of this effort.
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Earthen Pit Storage and Disposal
Drilling wastes are commonly held in a reserve pit prior to disposal.
Costs for disposal in lined or unlined evaporation or evaporation/
percolation pits will be adapted from the general surface impoundment
estimates from the EPA literature (U.S. EPA, 1985). These estimates may
be adjusted, however, in recognition of possible difference between the
assumptions of the EPA cost functions and actual oilfield practices. A
more detailed discussion of current waste disposal practices is provided
in Chapter 2.
Literature Review
The drilling cost estimates compiled annually by the American
Petroleum Institute and the Independent Petroleum Association of America
include a category covering road and site preparation. On average, road
and site preparation represents 6.3 percent of total drilling costs
(Independent Petroleum Association of America, 1986). Unfortunately, this
category is too broad to allow identification of costs specifically for
reserve pit construction. The costs for preparing the remainder of the
site (other than the reserve pit) and for any entry roads commonly exceed
costs for the reserve pit. Also, the specific technology represented in
the disposal practices is not identified by the industry-average figures.
Thus, unless more specific cost breakdowns can be developed from the
original industry survey data, the published figures can be used only to
describe an upper limit to disposal costs.
A few literature sources also give some indications of reserve pit
construction costs (e.g., Rafferty, 1985). These estimates will be
reviewed but will not be sufficient to provide the basis for estimating
disposal costs.
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Various cost estimates for constructing lined and unlined pits can be
derived from previous EPA studies. Estimates of these costs are given in
several sources (Charles River Associates, Inc., 1985, and U.S. EPA,
1985). Such costs will be reviewed for their applicability to the
oilfield case. The costs are of the form C = a V where C = cost, a = a
constant, V = volume of water or capacity of the facility, and b = the
elasticity of cost with respect to volume.
Data Collection and Analysis
Further cost analysis for construction of reserve pits will be
developed using Means Site Work Cost Data 1986, a standard cost estimation
source, and information to be provided by "dirt work" contractors. In the
Means source, costs are presented for cut and fill operations, which are
similar to the process of reserve pit construction. The unit costs for
site work are given per cubic yard. These unit costs may be converted to
total reserve pit construction costs using data on the capacity of reserve
pits. The estimates derived using the Means source will then be verified
and adjusted through discussions with firms engaged in site preparation
work.
For closure of the reserve pit, the pit wastes are dewatered (by
evaporation or vacuum truck removal) and backfilled. Costs for
evaporation are incurred only when lease agreements with landowners are
based on the amount of time the reserve pit remains in place. Costs for
waste removal by vacuum truck will be derived through contacts with
commercial oilfield waste removal firms. Costs for backfilling will be
estimated using the reference source mentioned above. Means Site Work Cost
Data 1986.
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Disposal in Lined Pits (with Installation of an Impermeable Cap at Site
Closure)
For this technology, clay or artificial liners from one to three
layers thick would be installed in disposal pits to limit or prevent the
release of leachate. In addition, an equivalent impermeable cap would be
placed over the facility at closure to reduce infiltration from
precipitation. This practice is primarily applicable to both drilling
solids and associated wastes and to dewatered production sludges.
Literature review
Costs for liners and caps have been estimated in the models prepared
by the Office of Solid Wastes (specifically, see U.S. EPA, 1985). Cost
functions have been defined for surface impoundments using the following
liner designs: single synthetic, double synthetic, single clay, single
synthetic/clay, double synthetic/clay. The equations are of the form C =
a V where C = cost, a = constant, V = volume or capacity of the
facility, and b = the elasticity of cost with respect to volume. The
values for b vary from 0.6 to 0.7 in the EPA studies. Costs for facility
caps are estimated in a similar fashion in these studies.
Data Collection and Analysis
The previous EPA studies will be used in estimating costs for facility
liners and caps. The cost functions for various liner designs can be
developed on a consistent basis from this source. Assumptions in the cost
models about facility design, location, and soil characteristics that
influence the costs for facility construction will be reviewed before the
cost functions are used.
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Monitoring and Site Management Practices
This includes components that are commonly required at permanent
disposal sites. The elements include leachate collection systems,
monitoring wells, runon/runoff systems, property fencing and site
security, and provisions for post-closure maintenance of the facility.
Literature Review
Costs for each element of the package will be adapted from the
previously estimated EPA cost models maintained by the Office of Solid
Waste. Depending on the element, costs will be expressed as a function of
the disposal volume or of the reserve pit dimensions.
Table 1-15 presents cost functions estimated for basic monitoring and
site management items in a previous EPA study. Economies of scale exist
for leachate collection and treatment (the exponent in the equation for
estimating capital costs is less than 1), but not for the other items.
Permitting costs may also be incorporated into this alternative.
Costs for permitting activities will be derived from previous EPA studies
covering the administrative and paperwork burdens of permit application.
The costs will be based on estimates of the hours and personnel skill
levels needed to prepare permit materials.
Data Collection and Analysis
Assumptions about the design and extent of the monitoring package will
be adapted (with the costs) from the previous EPA estimates. Some
adjustments must be made to account for the unique features of oilfield
waste disposal facilities. For example, in comparison to landfills or
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This page for 1-15
Sample format of costs for monitoring & site mgmt.
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surface impoundments that have been modeled in most EPA work, oilfield
reserve pits are small disposal facilities. The capacity of the smallest
surface impoundment in a recent EPA study is given as 638,307 gallons, or
14,300 barrels (U.S. EPA, 1985). This capacity would normally be adequate
to handle wastes from a well drilled to deeper-than-average depth.
Extrapolation of the cost estimates to allow analysis of smaller waste
volumes will be necessary.
Offsite Disposal in a Secure Facility (i.e., Those Employing Multiple
Liner Systems and Other Controls)
This disposal method is primarily applicable to most drilling and
production wastes.
Literature Review
Costs for offsite solid waste disposal in secure facilities have been
estimated by EPA and are included in the Liner Location Risk and Cost
Analysis Model, Draft Report, (U.S. EPA, 1985). The estimates include
costs for facility construction, operation and maintenance, and closure.
The disposal facilities were designed with double or triple liner systems,
leachate collection and monitoring provisions, and other control systems.
Alternatively, costs for offsite disposal might simply include charges
made by commercial facilities, costs for waste management prior to
shipping, and costs for transportation. The latter are described
separately below. The disposal charges at commercial facilities have been
presented in recent EPA studies (Industrial Economics, Inc., 1985, and
Sobotka and Company, 1985). Table 1-16 summarizes the estimates presented
in recent publications. Most of the estimates were defined for broad
categories of hazardous waste and are not specific to disposal of reserve
pit wastes. Only the estimate presented in the Office of
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TABLE 1-16. Cost Estimates in Literature for Centralized Disposal
Type of
Disposal
Bulk from Waste
1983 Prices
(per MT)
Source
Landfill Based on charges for bulk-
form waste; transportation
costs not included.
$28-$100
Booz, Allen
& Hamiliton,
1984
Landfill3 Based on costs for low-risk $125 Industrial
hazardous waste (including Economics Inc.
drilling muds) disposal at et al.. 1985
commercial facility; trans-
portation costs not included.
Landfill13 Based on charges predicted $13-$29 U.S. Office
for a captive facility plus of Technology
profit estimates; includes Assessment,
100-mile transportation 1983
charge.
Surface Based on charges for a $264.6 Industrial
Impoundment*5 captive facility plus pro- Economics Inc.
fit estimate; includes 100- et al., 1985
mile transportation charge.
a These estimates are based on estimated operating costs for a
captive facility (i.e.. a facility owned by the waste generator) combined
with an assumption regarding the profit level and transportation expenses.
b This estimate is based partly on figures compiled by Booz-Allen &
Hamilton which are also referenced in this table. Thus, the estimates
may not be fully independent from the other observation.
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Technology Assessment study (Office of Technology Assessment, 1983)
applies to low hazard wastes, such as most drilling muds.
Data Collection and Analysis
Price quotations for disposal at selected waste disposal facilities
will be assembled to supplement the literature estimates for offsite
disposal of reserve pit wastes. Some firms are currently receiving
drilling solids, so their charges can be used directly in this research.
For facilities that are not receiving such wastes at this time, estimates
of charges for low hazard, bulk wastes will be considered most likely to
represent the applicable costs.
Estimation of Waste Transportation Costs for Centralized Disposal
Oil and gas companies will incur incremental transportation costs
whenever disposal alternatives require shipment of wastes off site or
shipment of wastes to more distant sites than those currently used. The
most significant transportation costs will be incurred for shipping of
drilling wastes to centralized treatment facilities or pits and for
shipping of production fluids for treatment and/or disposal in Class II
wells.
Literature Review
Literature on hazardous waste disposal includes estimates of the cost
per ton for waste shipments (e.g., Sobotka and Company, Inc., 1985). Many
of the available estimates from EPA reports are derived from an earlier
study of waste transportation costs (Abkowitz et al., 1984). This study
provides a set of assumptions that may be used to derive estimates of the
fixed and variable components of transportation costs.
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Previous EPA studies have estimated mileage to specific hazardous
waste disposal facilities by direct measurement of highway miles or by
averaging distances from waste generators to disposal sites. EPA data
bases are available to identify the location of the specific disposal
facilities.
Data Collection and Analysis
Shipping costs for oilfield wastes are regulated in some States (e.g.,
Oklahoma) and such cost figures will be assembled. These regulated price
limits and the other literature values may be a sufficient basis for
estimating shipment costs per ton-mile.
To estimate the distances for transportation of drilling solids and
associated wastes, an average distance will be calculated from the
approximate middle of oil and gas basins to the nearest disposal
facilities. This calculation will be made using maps of National
oilfields and information on the exact highway location of disposal
facilities. Depending on the volumes involved, new facilities dedicated
to oil and gas waste disposal may be hypothesized for cost estimating
purposes.
To estimate incremental transportation distances for drilling fluids
and production fluids, a similar procedure will be used. Drilling fluids
and production fluids may be shipped longer distances if necessary to
reach Class I instead of Class II disposal wells. At present. Class II
disposal wells are common in oilfield areas and transportation distances
are relatively short. Class I disposal wells are much less common.
Estimates of current transportation distances (to Class II wells) will
be developed based on a sample of current operations. Next, distances
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from the approximate middle of oilfield basins to specific Class I
disposal wells will be estimated. Information on the location of Class I
wells will be requested from State agencies or EPA Regions with
responsibility for the UIC program. An average distance will be
calculated for a sample of oilfield basins.
The transportation costs incurred by oil companies will be restrained
to the extent that nearby disposal options eventually become cost
effective. As transportation distances increase, for example, oil
companies become more likely to drill new Class I wells in their producing
fields. Relative costs of such options will be considered in the
transportation analysis.
Class II Injection Wells
A common disposal method for most production liquids is injection in
Class II wells. Produced water, however, may be injected for disposal
only or it may be injected as a part of oilfield pressure maintenance
efforts. A detailed discussion is provided in Chapter 2.
Literature Review
Costs for drilling new Class II injection wells were estimated in a
1979 study of the Underground Injection Control Program (Arthur D. Little,
1979). A range of estimates was given for wells drilled to depths of
2,000 and 5,000 ft. Since 1979, however, drilling costs have fluctuated
widely. Therefore, current costs for drilling Class II injection wells
will be obtained from drilling contractors.
Costs for various components of injection well operations are also
addressed in the previous report (Arthur D. Little, 1979). The estimates.
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however, do not provide a complete profile of operating costs or disposal
costs per barrel of produced water.
Data Collection and Analysis
Costs for injection for the purposes of disposal only are approximated
by the prices charged at commercial disposal wells. Price information
from these facilities will be obtained from a limited survey. Costs for
injection in pressure maintenance (waterflood) operations are offset by
enhanced hydrocarbon production. Effective costs for disposal may,
therefore, be zero or negative depending on the effectiveness of the
waterflood.
PLANS FOR ADAPTING EPA COST MODELS AND FOR ORIGINAL COST ESTIMATION
Many if not all of the baseline and alternative waste management
practices described have been modeled, to some degree, in previous EPA
studies. These models and other cost estimates found in the literature
will be adapted where appropriate. Original cost estimates will be
developed where necessary to supplement the previous results.
In preparing original cost estimates, source materials will include
literature references, price quotations from vendors of waste treatment
and disposal systems, and original engineering estimates as appropriate
for each cost element. Cost estimation technologies to be used for this
project include exponential cost functions, constant cost functions, and
model case estimates, depending on the specific item under consideration.
In most cases, exponential functions are most desirable for their
flexibility in defining disposal costs for wells with differing waste
volumes. For centralized disposal of drilling media and associated
wastes, costs to the oil and gas industry are the prices charged by
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commercial waste disposal firms, plus transportation. Constant cost
functions (e.g., a constant dollar-per-barrel price estimate regardless of
waste quantity) have been used in much of the literature to characterize
these prices. For this study, information on prices for bulk waste
volumes (such as would apply to drilling solids) will also be sought. A
constant or variable cost function will then be fitted to the cost data.
Cost information for small volume wastes will also be obtained in order to
establish a cost function for associated wastes (such as tank bottoms and
separator sludges).
Identify Incremental Actions and Costs
Those operations required to alter their waste management practices
(i.e., affected operations) under a scenario will incur incremental
costs. The estimation of these incremental costs requires:
1. Identification of baseline waste management costs. The
estimates generated in the analysis described above will be
applied to establish baseline costs of the affected
operations.
2. Estimation of incremental compliance measures. Based on the
list of alternative waste management practices, the measures
available to conform to the scenario will be identified,
including incremental waste transportation actions.
3. Establish least-cost compliance method. In some cases, more
than one alternative will be available for affected firms.
By comparing the cost of available measures, a least-cost
method can be identified.
4. Compare costs to baseline costs. Once the cost of waste
management practices of affected firms have been estimated,
these costs can be compared to baseline costs to establish
incremental compliance costs.
The incremental cost estimates will be expressed initially as both
capital investment costs and operating costs. The capital cost estimates
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will be annualized based on the expected life of the capital item and the
industry discount rate. The cost estimates will be defined in terms of
constant 1986 dollars, so the discount rate employed will reflect the
industry's real cost of capital. For purposes of calculating annualized
costs, typical project lifetimes must be estimated from available industry
services.
Because there are so many oil and gas projects, the cost analysis
described above must generally be performed on the basis of representative
or "model" operations. In this case, model oil and gas operations will be
defined to represent all of the firms affected under a given scenario.
The identification of model facilities is described in more detail in
Chapter 4.
Develop Regional and Aggregate National-Level Cost Estimates
The cost estimates for affected operations will be aggregated
Regionally and Nationally to derive annual total costs for each waste
management scenario. If model projects are used. National costs will be
estimated by multiplying the model facility costs by the number of
facilities the model represents.
Regional or National cost estimates will be two types. First, a
National-level investment cost total will be generated. This is a sum of
the investment costs (before annualization) for the affected projects.
Second, a National-level annualized cost total will be generated by
summing the total annualized cost to affected projects.
In addition to these National cost totals, other cost measures will be
computed, including the environmental control cost per ton of disposed
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waste and the environmental control cost per barrel of oil or MCF of gas
produced. The former can be used for comparison to the costs of other EPA
hazardous waste management programs. The latter can be compared to the
current cost of producing a barrel of oil to gauge the magnitude of the
impact of a waste management scenario.
National-level costs will be developed for the period 1987-2000.
Estimates of the level of growth of industry activity for 1987-2000 will
be obtained from the Department of Energy/Energy Information
Administration (EIA). The EIA mid-term forecasting system generates
projections of oil and gas activity that are used in Federal energy
planning.
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REFERENCES TO CHAPTER 3
Abkowitz, et al., 1984. Assessing the Releases and Costs Associated
with Truck Transport of Hazardous Waste. U. S. Environmental Protection
Agency, Office of Solid Waste, January 1984, as referenced in Sobotka &
Company, Inc.
American Petroleum Institute, no date. Land Treatment.
Arthur D. Little, Inc., 1979. Cost of Compliance, Proposed
Underground Injection Control Program, Oil and Gas Wells. U. S.
Environmental Protection Agency, Office of Drinking Water, June 1979.
Booz-Allen & Hamilton, 1984. Review of Activities of Firms in the
Commercial Hazardous Waste Management Industry: 1983 Update. Office of
Policy Analysis, U. S. Environmental Protection Agency, November 30, 1984.
Galloway, Mike, 1986. Presentation at National Conference on Drilling
Muds, Environmental and Ground Water Institute, University of Oklahoma.
Charles River Associates, Inc., 1985. Estimated Costs to the
U. S. Mining Industry for Management of Hazardous Solid Wastes.
U. S. Environmental Protection Agency, August 1985.
Davis, Ken, and T. Lawrence Heniline, 1986. Two Decades of
Successful Hazardous Waste Disposal Well Operation - A Computation of Case
Histories. In Proceedings of the International Symposium Subsurface
Injection Practices Council, New Orleans, Louisiana, March 3-5, 1986.
Gulf Publishing Co., 1986. World Oil (Monthly magazine).
Guthrie, Mark A., George Patrick, and Thomas N. Sargent, 1986.
Economic Impacts of Alternative Technologies for Treatment and Disposal of
Liguid Hazardous Wastes. In Proceedings of the International Symposium
Subsurface Injection of Liguid Wastes, The Underground Injection Practices
Council, New Orleans, Louisiana, March 3-5, 1986.
Hanson, Paul M., Frederick V. Jones, C. Michael Moffitt, and Miles R.
Rhea, 1986. A Review of Mud and Cutting Disposal for Offshore and
Land-Based Operations. In Proceedings of National Conference on Drillling
Muds, University of Oklahoma, May 29-30, 1986.
Independent Petroleum Association of America, 1986, Report of the Cost
Study Committee. Midyear Meeting, Nashville, Tennessee, April 30-
May 2, 1986.
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Industrial Economics, Inc., and ICF Incorporated, 1985. Regulatory
Analysis of Proposed Restrictions on Land Disposal of Hazardous Wastes.
Studies and Methods Branch and Economic Analysis Branch, Office of Solid
Waste, U. S. Environmental Protection Agency, December 27, 1985.
Lloyd, David, 1985. Drilling Waste Disposal in Alberta. In
Proceedings of a National Conference on Disposal of Drilling Wastes,
University of Oklahoma, Environmental and Ground Water Institute, May
30-31, 1985.
Moody and Associates, Inc., 1983. Oil and Gas Well Pollution
Abatement Project. ME No. 81495. June, 1983.
Rafferty, Joe, 1985. Recommended Practices for the Reduction of Drill
Site Waste. In Proceedings of the National Conferences on Disposal of
Drilling Wastes, Environmental and Ground Water Institute, University of
Oklahoma, May 30-31, 1985.
R.S. Means Company, Inc. 1985. Means Site Work Cost Data, 1986.
Sobotka and Company, Inc., 1985. Cost Analysis of Variances to Land
Disposal Bans. Economic Analysis Branch, Office of Solid Waste,
U. S. Environmental Protection Agency, December 16, 1985.
Technical Resources, Inc., 1985. Assessment of Environmental Fate and
Effects of Discharges from Offshore Oil and Gas Operations.
U. S. Environmental Protection Agency, EPA 440/4-85/002.
U. S. Environmental Protection Agency. 1980. Treatability Manual,
Volume IV: Cost Estimating. Office of Research and Development.
EPA-600/8-80-042D. July, 1980.
U. S. Environmental Protection Agency, 1984. Handbook for Estimating
Sludge Management Costs at Municipal Wastewater Treatment Facilities.
Contract No. 68-01-662/to SCS Engineering, Long Beach, California. Draft,
September, 1984.
U. S. Environmental Protection Agency, 1985. Liner Location Risk and
Cost Analysis Model. Draft Report. Contract No. 68-01-6621. Office of
Solid Waste, January 1985.
U. S. Office of Technology Assessment, 1983. Technologies and
Management Strategies for Hazardous Waste Control. OTA-M-196. March 1983.
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CHAPTER 4
IMPACT OF WASTE MANAGEMENT SCENARIOS ON PETROLEUM EXPLORATION,
DEVELOPMENT, AND PRODUCTION
INTRODUCTION AND OVERVIEW
This chapter describes the scope and methods for EPA's analysis of the •
impact of alternative waste management practices on petroleum and gas
exploration, development, and production, as called for in Section
8002(m)(G) of RCRA. The methodology for estimating the economic cost of
alternatives is described in Chapter 3. The impact of these costs will be
addressed for individual projects, on corporations and on the aggregate
regional and national levels of industry exploration, development, and
production.
The impact of incremental waste management costs will be analyzed
first at the level of individual projects. Because of the large number of
oil and gas projects initiated each year, "model" or representative
projects will be defined. As described in detail below, model projects
will be specified to capture regional differences in oil and gas
development and to depict situations in which the impacts of the waste
management scenarios are greatest.
Each model oil and gas development project will be characterized by a
stream of expenditures and revenues. By estimating these expenditures and
revenues and factoring these estimates into a discounted cash flow model.
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EPA will simulate the financial performance of model projects. A second
series of model-project simulations will be run, incorporating the added
costs of the alternative waste management scenarios for representative
facilities. Comparison of financial performance under the different
simulations will show the relative impact of the incremental environmental
control cost on project financial performance.
The cost impact of the waste management scenarios will also be
assessed at the industry and corporate levels. The total cost of the
waste management alternatives will be compared to total annual industry
investment and production expenditures to provide a broad measure of
aggregate industrial-level impacts. To analyze impacts at the corporate
level, the industrial-level cost of the waste management scenarios will be
allocated to individual representative corporations. The decline in the
financial ratios of these corporations due to incremental waste management
expenditures will be calculated.
This chapter describes the methodology for the project-level economic
impact assessment, corporate-level analysis, and the use of those results
in formulating conclusions regarding the impact of environmental control
costs on industry exploration, development, and production.
MODEL PROJECT ANALYSIS
Identification of Model Projects
The impact of the control requirements and costs on industry
exploration, development, and production is essentially the sum of the
impact on individual projects. An increase in waste management costs
could potentially result in the early closure of existing projects or in
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the cancellation of new projects. If a large number of projects would be
cancelled or curtailed under a given waste management scenario, then the
level of industry exploration, development, and production would be
reduced. Because the number of exploration and development projects
initiated each year is so large (e.g., over 80,000 wells were drilled
onshore in 1985), it is impossible to assess the impact of a scenario on a
case-by-case basis; it is therefore necessary to depict "model" projects
to represent the entire population.
Model projects will be defined for this research based on several
criteria:
1. The model projects must represent the entire population;
therefore, each model case must represent a substantial,
identifiable part of the population.
2. The model projects must capture the impact of the waste
management scenarios; therefore, some of the model cases
must be selected to represent those situations where the
largest environmental control costs (required under a
scenario) will be incurred.
3. The model projects must depict situations in which
environmental costs could affect overall project
profitability; therefore, some of the model cases will
depict economically marginal activities.
Establishing Representative Cases
Concerning the first criterion (i.e., representativeness), it will be
necessary to depict model cases that capture the geographical diversity of
the oil and gas industry. The regions of the country differ geologically,
resulting in differences in mud formulations, drilling procedures, and
production practices. These regional differences, in turn, bring about
differences in the types of wastes generated, the waste disposal practices
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employed, and the overall cost and profitability of the projects. Model
projects must be defined to capture these regional differences.
As described in a previous report (U.S. Environmental Protection
Agency, 1986), the nation can be divided into 11 oil and gas Regions
(Figure 1-1). Regions 1 and 3 do not have a significant amount of oil and
gas production. Thus, the model cases will focus on the other nine
regions, with cases defined to capture regional c..aracteristics of
exploration, development, production, and waste generation and disposal.
Given the significant regional differences in the basic parameters of
oil and gas projects, the nine regions will be used as a primary variable
to distinguish model cases. Since the major industry data series present
drilling and production information disaggregated to the State level (API,
1986; Independent Petroleum Association of America, 1986; DOE, 1986),
these data can be used to specify the proportion of drilling and
production that occurs in each region. These proportions can, in turn, be
used to extrapolate the results of modeling within regions to the national
level.
There will be significant differences, however, within regions
concerning many of the parameters described above. Further, there are
differences in the current regulatory treatment of these wastes, which
lead to different baseline disposal practices and costs for the States
within a region. Model projects defined using average regional values for
the parameters will not capture these differences. It will, therefore, be
necessary to specify additional model cases that depict situations in
which the impact of the waste management scenarios will be greatest.
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Environmental Control Costs
Subregional models will be defined to represent cases where
environmental control costs will be highest. Projects depicting average
regional characteristics may not experience significant environmental
control costs under a given waste management scenario. However, some
projects within the regions will experience significant costs. For
example, if a scenario's environmental protection requirements lead to
strict controls on oil-based muds, then model projects within Regions 4
and 7 must be defined to depict the use of such muds, even though the use
of oil-based muds is not practiced by the majority of projects in the
region. Further, projects in States with lenient current regulations may
experience higher incremental costs, and such projects must also be
modeled. Essentially, the requirements of a given waste management
scenario are compared to baseline practices in each region. State and
regional project profiles will provide the data necessary to extrapolate
the results of the subregional models to the National level.
Marginal Economics Cases
#
Another critical factor determining the impact of a waste management
scenario is the baseline economic performance of the model case. Those
cases showing marginal economic performance in the baseline condition
could be most affected by environmental control costs. Thus, as discussed
further below, it will be necessary to specify marginal economic projects
within the regions.
In summary, regional values will be used as a primary variable to
identify model cases. However, "average" regional cases may have only
limited interest to the analysis of a waste management scenario. It will.
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therefore, be necessary to specify subregional models to depict cases of
high impact of environmental control requirements and marginal baseline
economic performance.
Economic Parameters of Model Projects
Regional information, such as that presented above, will allow a
project to be specified in technical terms. For example, a representative
case in Region 2 would incorporate such features as air drilling, shallow
depth, discharge of liquid waste, and a high gas-to-oil ratio. It will
also be necessary to define the model cases in economic terms. The
economic specification of model projects will allow a simulation of ,
project financial performance both with and without the cost of
environmental controls inherent in a waste management scenario. The
following variables will be used to define model cases in economic terms:
• Drilling cost. Drilling costs will be derived from the Joint
Association Survey on Drilling Costs (American Petroleum
Institute et al., 1985). This source presents average
drilling costs by depth category and by State. It can be
used to derive average drilling costs for all specific model
wells defined (by region or subregion) in the analysis.
A new Joint Association Survey covering 1985 will be
published in December 1986. Model inputs will be defined in
1986 dollars. To bring the survey cost estimates forward to
1986, extrapolations will be developed using more recent
published drilling cost indices. Such indices are published
by the Independent Petroleum Association of America and by
the U.S. Department of Energy (Independent Petroleum
Association of America, 1986, and U.S. Energy Information
Administration, 1985b). At present, the published indices
cover 1985, but the DOE index for 1986 will be published in
January 1987. This index will then be used to adjust the
region and depth-specific costs taken from the Joint
Association Survey.
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Probability of a successful wildcat well. The probability of
a successful wildcat well can be calculated from annual
statistics on exploratory drilling as published in World Oil
magazine. The data present the total number of exploratory
wells and the number of oil/ gas, dry and suspended (the
drilling project was interrupted before its outcome was
determined) wells by State each year. Thus the probability
of a successful exploratory well can be calculated for each
State, and subsequently for each region or subregion depicted
in the model cases.
Data are currently available (as of October 1986) on
exploratory wells drilled through 1985. The 1986 data will
be published in the February 1987 World Oil magazine. The
success of exploratory well drilling over the past three
years will be averaged for input to the model.
Number of development wells per successful wildcat well. Oil
companies who drill wildcat wells attempt to have surrounding
acreage under their control. Should the wildcat be
successful, the company can then derive the benefits of
additional (i.e., development) wells. Thus the economics of
a project are dependent upon the success of a wildcat well
and the amount of development that results.
The number of development wells completed per year is derived
by subtracting the number of successful exploratory wells
from the number of wells completed annually. The latter are
presented in industry sources (American Petroleum Institute,
1986). The ratio of development to successful wildcat wells
by region will be calculated and used as a parameter in the
model projects.
Operating costs. Operating cost data is compiled by the
Energy Information Administration of the Department of Energy
(Energy Information Administration, 1985a). Cost breakdowns
are provided for categories of lease equipment and direct
operating expenses by region and by depth categories. The
regions and depth categories are, however, different in this
source from the regions that have been defined herein. Thus,
interpolation of the statistics will be necessary to match
the operating cost data to the format needed for the economic
modeling.
Operating cost data through 1985 will be available for use in
the model. Costs for 1986 will be extrapolated based on cost
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trends from historical data and from trends in other oilfield
cost indices.
• Type of production. The type of production (i.e., oil, gas,
or both) in each model is a statistic calculated directly
from State oil and gas production figures. The type of
production combined with current wellhead prices for oil and
gas determine the project revenues. These statistics are
available in major industry sources such as World Oil and the
API Basic Petroleum Data Book (Gulf Publishing Co. and
American Petroleum Institute, 1986). The State data will be
combined as necessary to calculate the regional values for
the type of production.
• Peak production level. Data on peak production are necessary
for the effort to describe the amount of production and thus
the revenue stream from successful wells. It will be assumed
•that peak production in all successful wells occurs in the
first year. Thereafter, production is assumed to decline
over time until the well is shut in.
Data on initial production (IP) are available from State oil
and gas commissions and from the Petroleum Information
Corporation in Denver, Colorado. The initial production
statistics will be compiled and averaged for each region in
the study. It is anticipated that initial production
averages will be calculated covering the past three years of
production statistics.
• Production decline rate. The decline rate for production is
needed to complete the profile of production and therefore to
calculate the average revenue stream from successful wells.
Hydrocarbon production typically declines over the life of a
well, although decline rates are quite variable.
Two possible approaches to development of this statistic are
under consideration. First, a representative decline rate
will be developed based on expert judgment obtained from
industry sources and from Department of Interior, Mineral
Management Services, publications.
A second approach remains under consideration. In this
approach, actual decline rates would be calculated from
individual well records. A random sample of well records
would be required for this task. The size of the necessary
sample and other details of the calculation procedure have
not yet been estimated.
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• Wellhead selling price. The selling price for recovered
hydrocarbons (in combination with the production profile)
determines the revenue stream for oil and gas projects.
Wellhead prices as of December 31, 1986, will be utilized in
the modeling work. Wellhead prices are reported weekly in
API publications.
• Tax treatment. A set of tax assumptions must be included in
the model to allow calculation of the after-tax rate of
return. The assumptions will approximate the national (i.e.,
all regions) tax treatment of oil and gas. Changes in the
tax code included in the tax overhaul legislation passed by
Congress in September of 1986 will be incorporated.
Variations in State tax laws will be incorporated into the
subregional models.
• Cost of waste disposal. Each model case would be
characterized by a distinct waste disposal cost. Baseline
• waste disposal costs for the industry will be developed as
described in Chapter 3. This baseline cost information will
be adapted to the model cases.
Marginal Economic Cases
The preceding discussion has addressed methods for deriving economic
parameters that define average or representative oil and gas projects. As
mentioned previously, it will also be necessary to develop model cases of
the marginally profitable projects in the industry. Such projects are
most vulnerable to increases in waste management costs, and cancellation
of such projects will impact industry production levels.
Projects may be marginal for a variety of reasons, including
(1) location in areas that are characterized by small oil or gas
reservoirs so that production levels are below industry average,
(2) developments with high operating costs, such as where large quantities
of produced water are generated and require disposal (e.g., stripper
wells, waterflooding projects), and (3) developments by small companies
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that have higher hurdle rates (in other words, a higher cost of capital).
Such firms may pay higher rates for debt financing than larger companies
because of the greater risk to lenders.
Based on these and other factors, models of marginal economic cases
will be defined for the analysis. The models will reflect intraregional
variation in the economic variables described above. For example, some
marginal cases will be based on patterns for initial production; that is,
some cases will be defined for those areas characterized by low initial
production (and, therefore, modest revenue streams during the life of the
project).
Model Project Simulations
The economic parameters of the model projects will be input to a
discounted cash flow model designed by EPA to simulate the financial
performance of oil and gas projects. The economic model simulates the
performance and measures the profitability of model projects. For each
model project, exogenous economic data (e.g., drilling cost, number of
development wells, production rate, wellhead selling price) ^are input to
the economic simulation model. The model calculates the annual after-tax
cash flow for each year of project operation, as well as cumulative
measures of a project's performance such as net present value (NPV) and
internal rate of return (IRR).
The EPA economic model software provides integrative calculation
procedures and algorithms that duplicate (1) the oil industry's accounting
procedures, (2) standard rate of return calculation methods, and (3)
Federal taxation rules. The tax code revisions enacted by Congress in
September 1986 are now being incorporated into the model.
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Each model project will be simulated in a base case and under the
requirements of each waste management scenario. The base case simulation
will, simply, operate the model incorporating baseline economic values to
calculate a model project's economic performance. The alternative cases
will incorporate the same economic information and the additional cost of
the waste management scenario to estimate a new (lower) NPV and IRR for
each model. Costs for the waste management scenarios will be developed as
described in Section 6.4. The national-level cost analysis in Chapter 3
will employ the same model cases as the impact assessment described here,
so the cost information developed in that chapter can be adapted directly
for use in the model project simulations.
The baseline economic results will be compared to the economic results
under a waste management scenario as a first measure of regulatory
impacts. The issues addressed in this comparison include the following:
1. Absolute decline. The absolute decline in internal rate of
return under a given scenario for each model project will
give an immediate indication of economic impact. If the
decline is less than one tenth of a percentage point for all
models, for example, impacts will not be severe.
2. Hurdle rate. A second indication of impact is whether the
incremental waste management costs push any of the model
projects from a level above the industry hurdle rate of
return to a level below that rate. If the decline in IRR
makes some model projects unprofitable, impacts could be
substantial.
CORPORATE AND INDUSTRY-LEVEL IMPACTS
Another way to measure the impact of regulatory costs of exploration,
development, and production is to compare annual compliance expenditures
to annual corporate and industry investment expenditures. These
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comparisons can give a good initial indication of whether regulatory costs
are likely to have a substantial impact on industry capital formation.
Industry-wide Assessment
Total aggregate annual costs will be estimated for each waste
management scenario as described in in Chapter 3. Total industry
investment expenditures are compiled and published annually by the Energy
Economics Division of the Chase Manhattan Bank. This source tabulates all
industry exploration and development expenditures, both onshore -and
offshore. By dividing the total annual costs under a given regulatory
scenario by total annual industry expenditures for exploration and ,
development, one can obtain a first measure of the magnitude of effects on
industry investment spending.
EPA will compare the cost of each waste management scenario to
industry-wide exploration and development expenditures in four separate
ratios:
1. Annual Incremental Expenditures Under a Given Waste
Management Scenario (as described in Section 6.4)/Total
Annual Industry Exploration and Development Expenditures
(Chase Manhattan Bank).
2. Annual Incremental Expenditures Under a Given Waste Manage-
ment Scenario/Total Annual Industry Onshore Exploration and
Development Expenditures.
3. Annual After-Tax Expenditures Under a Given Waste Management
Scenario/Total Annual Industry Exploration and Development
Expenditures.
4. Annual After-Tax Expenditures Under a Given Waste Management
Scenario/Total Annual Industry Onshore Exploration and
Development Expenditures.
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Each of these ratios provides a slightly different comparison. The
use of onshore expenditures as opposed to total industry expenditures
allows waste management costs to be compared to the subset of industry
expenditures that the compliance expenditures would be part of. The use
of gross compliance expenditures in the numerator (Ratios #1 and #2}
compares the social cost of compliance to total industry exploration and
development expenditures. However, industry will deduct compliance costs
as business expenditures and will, therefore, not pay the entire social
compliance cost. The use of after-tax compliance costs in the numerator
(Ratios #3 and #4) compares the cash effect of compliance to total
industry expenditures. These latter ratios, then, provide a measure, from
the industry's point of view, of the percentage of funds diverted from
other uses to pay for regulatory controls.
Financial Assessment for Representative Companies
In addition to the above industry-wide ratios, a second set of ratios
can be calculated to show the impact of compliance costs of the financial
health of individual corporations. Using financial data available from
corporate annual reports, EPA will construct a representative balance
sheet for a typical major, a typical large independent, and a typical
small independent oil company. These balance sheets can be used to
calculate statistics and ratios which measure a company's financial health.
EPA will use four financial parameters in the analysis: level of
working capital, current ratio (i.e., current assets divided by current
liabilities), long-term debt-to-equity ratio, and debt-to-capital ratio.
These parameters will be calculated both before and after the incremental
cost of a waste management scenario. Parameter calculations under the
waste management scenarios will be calculated under two sets of
1-4-13
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assumptions. The first assumption is that incremental waste management
costs are funded out of working capital and, therefore, the level of
working capital and the current ratio will be impacted. The second
assumption is that incremental waste management costs are funded out of
long-term debt, and therefore, the long-term debt-to-equity ratio and the
debt-to-capital ratio will be affected. A comparison of pre- and
post-scenario ratios will provide an indication of the financial effect of
the scenarios on a corporation-specific basis.
In the above analysis, the fraction of total industry compliance costs
attributed to the model major and the model independent oil companies will
be estimated by comparing the exploration and development expenditures of
the model corporation to those of the industry as a whole. In a related
study, EPA estimated that a typical major accounts for 5.4 percent of
industry exploration and development expenditures while a typical
independent accounts for 0.3 percent of all such expenditures. Thus, for
the ratio analysis described above, it will be assumed that 5.4 percent of
total aggregate compliance costs (as calculated in Section 6.4) are borne
by a typical major and that 0.3 percent of aggregate compliance costs are
borne by a typical independent oil company. Small companies in areas
experiencing the greatest impact of the regulatory scenarios, may absorb
more than a proportional share of the national costs. For these firms,
modified assumptions regarding the actual (larger) share of national costs
to be borne will be developed for the ratio analysis.
IMPACT ON INDUSTRY EXPLORATION, DEVELOPMENT, AND PRODUCTION
The analysis will provide several indications of the economic impact
of the costs of the alternative waste management scenarios. In particular:
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1. The financial impact of the environmental control costs will
be simulated for representative projects, including average
projects, projects expected to show the largest total costs,
and for projects showing marginal baseline economic
performance.
2. Incremental costs under the waste management scenario will
be compared to total industry onshore exploration and
development costs.
3. Incremental costs under the waste management scenarios will
be compared to total industry exploration and development
costs.
4. The financial ratios of typical small independent, large
independent, and major oil companies will be estimated
separately, both before and after the costs of the waste
. management scenarios are estimated.
EPA will evaluate these results to determine whether any of the waste
management scenarios will have a substantial impact on industry
exploration, development, and production. Three key issues will be
addressed. First, a determination will be made as to whether any (and
what percentage of) projects would likely be cancelled under each waste
management scenario. Second, a determination will be made as to whether
any of the waste management scenarios will affect the industry's ability
to raise capital. Third, the results of the ratio analysis will be
•
reviewed to determine whether the ratios of any affected firms will
deteriorate to the point where the probability of financial failure
increase significantly.
Because oil is sold in a world market with abundant foreign supply at
the world price, any decrease in domestic exploration, development, and
production will lead to an increase in imports. These balance of trade
effects will be estimated. It is not expected that the waste management
scenarios will result in production declines substantial enough to change
price in the world market, so fuel substitution and the rate of
development for alternative energy technologies will not be affected.
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CHAPTER 4 REFERENCES
American Petroleum Institute, 1986. Basic Petroleum Data Book, October
1986.
American Petroleum Institute et al., 1985. Joint Association Survey on
Drilling Costs, 1984; December 1985.
Gulf Publishing Company, no date. World Oil. Houston, Texas. Monthly
magazine.
Independent Petroleum Association of America, 1986. Report of the Cost
Study Committee. Mid-year Meeting, Nashville, Tennessee, April 30 -
May 2, 1986.
Interstate Oil Compact Commission, 1985. History of Production Statistics,
Production and Reserves, 1969-1984, November 1985.
U.S. Energy Information Administration, 1985a. Costs and Indexes for •
Domestic Oil and Gas Field Equipment and Production Operating, 1984.
DOE/EIA-0185 (84), May 1985.
U.S. Energy Information Administration, 1985b. Indexes and Estimates of
Domestic Well Drilling Costs, 1984 and 1985. DOE/EIA-0347 (84-95),
November 1985.
U.S. Environmental Protection Agency, 1986. Oil and Gas Exploration,
Development and Production; Sampling Plan - Draft. Office of Water
Regulations and Standards, May 1986.
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PartH
Geothermal Energy
-------
CHAPTER 1
INDUSTRY DESCRIPTION
The purpose of this section is to provide background information on
geothermal energy and a profile of the geothermal energy industry. This
report presents a brief description of geothermal energy systems; where
geothermal energy systems are found, some common techniques used by
industry for bringing the resources into production, and a discussion of
how the resources are used.
BACKGROUND
The crust and the atmosphere of the earth account for less than
one-half of a percent of its total mass. The remaining 99.5 percent lies
concealed beneath the crust, and our knowledge of the nature of the
material beneath the crust is largely a result of the study of earthquake
waves, and lavas, and measurements of the flow of heat from the interior
towards the surface. Nevertheless, this indirect knowledge has allowed us
to construct a fairly clear and consistent model of the structure of the
earth. The currently accepted structure consists of four concentric
spheres; from the outermost to the innermost they are the crust, the
mantle, the liquid core, and the innermost core, which is believed to be
II-l-l
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solid. This structure is presented in Figure II-l. Temperatures and
densities rise rapidly as the center of the earth is approached. The term
"geothermal energy" is defined by some to include all of the heat
contained in these four concentric spheres (approximately 260 billion
cubic miles that constitute the entire volume of the earth) (Chilinger, et
al., 1982). The potentially useful part of this enormous energy supply,
however, is represented by that small fraction of the earth's volume in
which crustal rocks, sediments, volcanic deposits, water, steam, and other
gases at usefully high temperatures are accessible from the earth's
surface and from which it may somehow be possible to extract useful heat
economically. Even this small portion of the total is an enormous
reservoir of thermal energy. The classification, location, and recovery
of this portion of the available thermal energy are the subjects of this
section.
THE NATURE AND OCCURRENCE OF GEOTHERMAL ENERGY SYSTEMS
Geologists and engineers classify geothermal energy systems into three
major categories:
• Hot igneous systems;
• Conduction-dominated systems; and
• Hydrothermal systems.
The first two categories may contain the largest amount of useful heat
energy, but are not economically and technically feasible to exploit.
Advancements in current technology would be required in order to use these
potential heat sources commercially. The third category, hydrothermal
energy systems, is commercially viable and has received the most attention
because extraction technology exists for the economic recovery of heat
from these resources.
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Continental crust
Average thickness about 35 km
Average density 2.7 g/cm3
Densities
(g/cm3)
Oceanic crust
Average thickness:
about 5 km water
about 5 km rock
Average density 3.0 g/cm3
Total, with crust about 6370 km
Figure II-l. Concentric Layers of the Earth.
Source: Armstead, Christopher H., "Geothermal Energy: Its past, present and
future contributions to the energy needs of man," 2nd Ed., London,
1983, E and FN Span.
II-1-3
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Hot Igneous Systems
These systems consist of magma chambers near the earth's surface that
are created by the buoyant rise of molten rock generated deep in the
earth's crust. This type of geothermal energy system is made up of two
major groups: Hot, Dry Rock, where the magma is no longer molten (less
than 650°C), and Volcanic Systems, where the magma is still molten or
partly molten (greater than 650°C). Figure II-2 presents a schematic
diagram of a representative hot igneous system.
Because of the great depth (3 km) and high temperatures (650-1200°C)
associated with volcanic systems, the heat is not recoverable with current
technology. The hot, dry rock - hot igneous systems, however, are located
on the margins of molten magma chambers and might in the future be
favorable candidates for recovering heat energy. Some speculate that a
system of hydraulic fractures can be created between special,
directionally-drilled wells to provide circulation loops in rocks having
low to very low permeability. An experimental program at Los Alamos, Mew
Mexico, is underway to develop this technology. Success in these efforts
will make it possible to consider exploitation of hot dry rock geothermal
energy. In general, however, the economic extraction of energy from this
resource has yet to be demonstrated (Chilinger et al., 1982).
Conduction-Dominated Systems
The very high heat from the molten center of the earth is transferred
very slowly from deep within the earth to the surface by thermal
conduction. Because of the size and relatively low heat flux at or near
the surface, however, one would have to drill 5 to 10 km to reach
subsurface temperatures of only 100°C. Therefore, the development of this
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NATURAL FISSURE
WELL
HOT DRY ROCK
HEAT EXTRACTION SYSTEM
PERMEABLE'./ SEDIMENTS
RED VOUCANIC ROCK "
te* UNITS -i-:
HYDROTHERMAL SYSTEM
Figure II-2. Schematic Diagram of a Hot, Dry Rock Geothermal System.
Source: Chilinger, G.V., L.M. Edward, W.H. Fertl, H.H. Ricke III Editors,
"The Handbook of Geothermal Energy." Houston, Texas, 1982, Gulf
Publishing Company.
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type of system is not, at this time, economical. Geopressured reservoirs
are also within this category, however. Geopressured reservoirs are
usually found in deep sedimentary basins where a lower level of sediment
compaction has taken place over geologic time and where an effective
caprock exists. These conditions, supplemented by water released,
possibly by clay mineral alteration, foster trapped-water pore pressures
up to several thousand pounds per square inch above the hydrostatic
pressures that would normally exist. For example, temperatures up to
237°C with wellhead pressures in excess of 11,000 psi have been recorded
in some geopressured zones in the States of Texas and Louisiana
(Chilinger et al., 1986). Since there is no deep circulation of the
water, however, it only reaches moderately elevated temperatures. Because
these reservoirs are usually associated with petroleum, the water is
generally saturated with methane and other hydrocarbon gases. They
therefore could represent an important supplement to the supply of natural
gas. There is still no direct evidence that heat, natural gas, or both
can be extracted economically from geopressured hot water reservoirs, but
large-scale field experiments are now underway to investigate this
possibility.
Hydrothermal Systems
Hydrothermal systems are the systems of economic importance. These
systems consist of high temperature water and/or steam trapped in porous
and permeable reservoir rocks. Because of the convective circulation of
water and steam through faults and fractures, the heat is transported to
near the earth's surface. Gravity is the driving force of this movement,
owing to the density difference between cooler, downward moving water and
the hot, upward moving water. The heat that is available in the
II-1-6
-------
geothermal reservoir rock is produced by bringing hot water and/or steam
to the surface. Figure II-3 presents a schematic diagram of a simplified
hydrothermal system.
Two classes of hydrothermal reservoirs exist. Reservoirs that
liberate mostly steam are referred to as vapor-dominated.
Liquid-dominated reservoirs are reservoirs where the water is in the
liquid phase; they are much more abundant and are usually found in
permeable sedimentary rock. The latter reservoirs are also found in
competent rock systems, such as volcanic formations, if open channels
along faults or fractures exist. A brief discussion of both systems is
presented below.
Vapor-Dominated Reservoirs
If the caprock in a hydrothermal reservoir is not able to sustain the
pressure level to prevent boiling, then pockets of steam will form. When
the pressure is relieved (for example, by drilling a well into the
pocket), most of the dissolved minerals are left behind in the formation,
and relatively pure steam is recovered. Except for a variable content of
noncondensible gases (which could be methane, carbon dioxide, radon, and
hydrogen sulfide) the evolved steam can be an economical energy source.
Frequently, it is used to drive turbines and generate electricity.
The existence of a large, bounded volume of rock within which
temperatures are high enough and pressures are low enough to permit
boiling within the cavity is rare. Therefore, vapor-dominated systems or
natural steam reservoirs are far less common than hot water reservoirs.
Nevertheless, the technology for utilizing energy from vapor-dominated
systems is well developed, and one of the largest geothermal power plant
developments in the world (at The Geysers in California) uses steam from
such a system (Chilinger et al., 1982).
II-1-7
-------
PRECIPITATION
RECHARGE
*
CONVECTION
.CELLS
CRYSTALLINE \ ROCKJJH&':
LIQUIDS, GASES & VAPORS
CONDUCTIVE HEAT FLOW
'/////////
HOT INTRUSION
Figure II-3. Diagram of a Hydrothermal Geothermal Reservoir.
Source: Chilinger, G.V., L.M. Edward, W.H. Fertl, H.H. Ricke III, Editors,
The Handbook of Geothermal Energy." Houston, Texas, 1982, Gulf
Publishing Company.
II-1-8
-------
Power generation from these resources produces relatively small
quantities of solid wastes. This is primarily due to the nature of the
vapor transport mechanism that carries the volatile components to the
surface. Some secondary waste components, however, are generated from use
of the vapor or off-gas cleanup systems employed in the overall process.
These solid wastes could include significant levels of hydrogen sulfide,
boric acid, arsenic, and mercury (USEPA, 1978).
Liquid-Dominated Reservoirs
In these reservoirs water slowly circulates through permeable crustal
rocks, encounters rock at high temperatures, and, becoming less dense as
it is heated, rises buoyantly toward the surface. If some geologic
barrier prevents it from actually reaching the surface, an underground
reservoir may form, within which the water will circulate convectively.
This slow circulation of the water allows it to continuously extract
enough heat from the lower part of the reservoir to compensate for the
heat that escapes upward through the formation. Thus, an equilibrium may
eventually be reached in which the water temperature throughout the
reservoir is approximately uniform (this temperature may range anywhere
from slightly above ambient temperature to 350°C or higher).
Hydrostatic pressure on the water is usually high enough to keep it
from boiling even when the water is greatly superheated. Because of its
high temperature and its residence time in the reservoir, the water
becomes saline and can be saturated with the minerals with which it comes
in contact. Since the solubilities of a number of minerals increase with
temperature, the hotter geothermal waters generally contain greater
contents of dissolved solids than water at ambient temperature. This
condition is, however, strongly site-dependent, because the mineralogical
composition of the rock of a geothermal reservoir varies widely from site
II-1-9
-------
to site. As a rule, the concentration of metals and other constituents
also increases as the concentration of total dissolved solids increases
(USEPA, 1978).
Geothermal liquids range rather widely in hydrogen ion concentration,
with pH values generally between 2.0 and 8.5 (USEPA, 1978). It appears
that most liquids are above a pH of 7.0. Liquids of higher salinity
generally have the lowest pH and can be highly corrosive to man-made
materials.
Noncondensible gases, those that do not condense at normal ambient
operating temperatures, are environmentally important constituents of
geothermal liquids. They may be free gases, dissolved or entrained in the
liquid phase. Hydrogen sulfide traditionally has been the component of
greatest concern. Noncondensible gases usually comprise between about
0.3 percent and 5 percent of flashed steam from geothermal liquids (USEPA,
1978).
Radioactive elements are also generally found in geothermal liquids in
low concentrations. These include uranium and thorium isotopes, radium,
and radon. Radon, a radioactive gas and one of the products of radium
decay, is the most significant generally recognized radioactive component
in geothermal liquids. EPA data covering 136 geothermal sites showed a
range of 13 to 14,000 pCi/1 {picocuries per liter), with a median of about
510 pCi/1 (USEPA, 1978).
Chemicals, such as acids, bases, and various flocculants and
coagulants, may be added to geothermal liquids to minimize scaling and
corrosion or to remove certain constituents. Although these chemicals may
not in themselves be of great consequence as pollutants, consideration
must be given to interactions that might alter the geothermal liquid
II-1-10
-------
composition. This is particularly true of any metal compounds which may
be added during this process. Most such chemicals will be acids and/or
bases used for pH adjustment.
The Geographic Distribution of Geothermal Energy Systems
The locations of hydrothermal and geopressured resource areas are
shown in Figure II-4. Identified hydrothermal systems with temperatures
greater than or equal to 90°C are located primarily in the western United
States, while low temperature geothermal waters are found in the central
and eastern United States.
EXPLORATION OF GEOTHERMAL RESOURCES
Preliminary Exploration
The overall objective of any geothermal exploration program is to
locate a geothermal resource system from which energy can be profitably
extracted. Rapid low-cost reconnaissance techniques are employed in the
early stages of exploration, when gross areas are to be screened for
commercial potential. For example, leakages of liquids through the
impermeable capping often occur in natural geothermal systems. These
leaks and/or seeps may produce such features as fumaroles, hot springs,
warm springs, geysers, mud volcanoes, or boiling ground, and are the most
direct and obvious indicators of the presence of a geothermal reservoir or
system. These seeps can also provide quantitative information on the
nature of the reservoir and the liquids contained within it.
II-l-ll
-------
\
>--._
u. / \
Vl
X'^ ''•
LEGEND V j^i—r- ^J
Identified Hydrothermal \
Systems with reservoir
temperature greater than 90C \
Known or Inferred Low-Temperature
Hydrothermal Systems
Geopressured basins
Figure II-4 The Geographic Distribution of Geothermal Energy Systems
-------
Geothermal Well Drilling
Exploratory drilling is undertaken once an area is defined. This
allows the exploration area to be narrowed to confirm the existence of a
production field.
The drilling of geothermal wells is quite similar to the drilling of
oil and gas wells. The major differences between geothermal and oil and
gas wells have been described in the literature (Armstead, 1983). They
are the following:
• Nearly all geothermal well drilling is performed at
relatively low pressure (this excludes the geopressured
geothermal testing now underway in the Gulf Coast area).
• With the exception of the Gulf Coast area, the majority of
the geothermal wells are of relatively shallow depth
(1,500 m), having high formation temperatures.
• The rocks being drilled are mostly igneous and metamorphic.
• Geothermal wells are usually 50-100°C hotter than oil and gas
wells of comparable depths (Armstead, 1983).
• Cooling towers are sometimes required for the geothermal
drilling fluids.
• Gas/drilling fluid separation is sometimes required for
geopressurized field drilling.
In fields that produce water exceeding 100°C, the drilling depth
usually ranges from about 500-2,000 meters, and although a few bores may
lie outside of these limits, the majority lie in depths of 600-1,500
meters. In lower temperature fields and in low grade aquifers depths of
approximately 1,800 meters are common, but in some places (e.g., Klamath
Falls, Oregon), where the aquifer is located close to the surface, wells
range from 30 to 300 meters. In geopressured fields, depths of about
6,000 meters may be necessary (Armstead, 1983).
II-1-13
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Nearly all geothermal wells have been drilled using the rotary
drilling technique. A typical rotary drilling rig is shown in
Figure II-5. Before the drilling operations can be initiated, a concrete
cellar must be constructed. The cellar serves to support the weight of
the drilling rig and accommodate the wellhead valving and is generally
accessed by a concrete stairway. Consolidation grouting is usually
injected into the surrounding ground. This grouting provides additional
support and serves to deflect away from the wellhead any steam that may
accidentally ascend to the surface along the outside of the bore and its
casings (Armstead, 1983).
The methods and equipment used for geothermal drilling do not vary
greatly from those used in petroleum and natural gas drilling. Both
rotary and turbo drilling can be used. In geothermal well drilling,
however, because of the possibility of encountering harder rock
formations, higher temperatures, and highly corrosive fluids, certain
modifications in techniques, materials, and equipment are required.
(Armstead, 1983) Serrated tri-cone drill bits made of very hard steel are
used to effect penetration. The drill bits are attached to a hollow drill
stem, and both are rotated by a power source, which is usually a diesel
engine {Armstead, 1983).
The process of drilling for geothermal steam is a complex process. A
tall lattice steel tower, which contains a pulley system, is used to
position and withdraw the drill stem and the casing. Power units are also
needed for rotating the drill, operating the derrick, and driving the
auxiliary pumps and compressor. There are racks for carrying a stock of
such items as casing pipes and drill stems, and a circulatory system for
pumping, cooling, screening, settling, and storing the cooling mud
(Armstead, 1983). This circulating system, and its cooling fluid (mud)
are of primary concern since it is responsible for generating one of the
major waste streams.
II-1-14
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Derrick
Blow-out preventer
ri
Cooling
tower
Pump
-Swivel head
Pump
Mudtjank
i. Vibrating
.screen
Chips
Main mud tank
Pump
-Drill stem
Mud
Figure II-5. Typical Rotary Drilling Rig and Mud Circulation Arrangements.
Sourca: Armstaad, Christopher H., "Geothermal Energy: Its past, present and
future contributions to the energy needs of man/' 2nd Ed., London,
1983, S and FN Span.
II-1-15
-------
One of the most important factors in drilling is the provision of
adequate steel casings. Normally, up to four concentric casings may be
installed in a single well. They are constructed of high quality steel
and are rigidly fixed with cement to the surrounding rock. The purpose of
the casing is to prevent the collapse of a newly drilled, completed well.
Figure II-6 presents a diagram of a completed hydrothermal well with
installed casings.
Drilling Fluids (Muds)
The primary purpose of the drilling fluid is to cool and lubricate,
and to flush out rock chippings from the bore hole. It also serves to
prevent collapse of the bore walls and to cool the surrounding ground.
The fluid is pumped downward through the hollow drill stem and returns
upward through the annular space surrounding it. The mud circulates from
the bore, is screened to remove rock cuttings, and is then passed through
a cooling tower. A cooling tower may not always be needed and the need
for one depends upon the downhole temperatures (Armstead, 1983).
The type of drilling fluid used and its proper control are essential
in geothermal drilling operations. The drilling fluid used for both the
vapor-dominated and liquid-dominated systems may be similar. However,
drilling into vapor-dominated systems generally utilizes air so as not to
kill the production zone with a hydrostatic column of fluid. Liquid-
dominated systems are normally drilled with conventional drilling fluids
(muds). Various types of drilling muds may be used and the type and
composition of the mud depend upon the drill-site conditions. Some of the
more common drilling fluid systems are listed in Table II-l.
II-1-16
-------
Main valve
Pump
normal
water well depth
Competent lithologic unit
Concrete pad
Conductor pipe set at
20'-80' (6-24m)
Surface casing
Cement
Fluid level
Pump turbines
and bowls
Cement
Production casing
Liner hanger
Slotted liner
ft.
(m)
100*
(30)
500'
(152)
1000'
(305)
3000'
(915)
5000'
(1524)
Figure II—6 Cross Section of a Typical Hydrothermal Well (not to scale).
Source: Q'Banion, K. and D. Layton, "Direct Use of Hydrothermal Gsotherroal
Energy: Review of Environmental Aspects," U.S. Department of Enargv,
April 1981.
II-1-17
-------
Table II-1. Common Orming Fluid Systems Prevalent in Geothermal Drilling
Type
Compos i t i on
Bentonite water
Bentonite lignite - caustic
soda system
Chrome - lignite - chrome
lignosulfate system
Polymer system
Seplollte system
Bentonite provides viscosity and fluid loss
control with MaOH addition for pH adjustments.
Lignite is incorporated in the fluid to
provide greater thermal stability and better
viscosity and fluid loss control than a
simple bentonlte water system.
Chrome lignite and chrome lignosulfate are
added to the drilling fluid to Impart greater
overall stability.
Predominantly composed of polymers. This
results 1n bentonlte extension and
flocculatlon of drill solids, thus creating a
low sol Ids, mud system.
Seplollte clay Is substituted for bentonlte
because it does not flocculate at high
temperatures and provides better viscosity
control. Modified polymers are added for
fluid loss reduction and caustic soda for pH
adjustment.
11-1-18
-------
Distribution of Geothermal Drilling Activity
Table II-2 and Figure II-7 present data on the locations of current
major geothermal drilling activity in the United States from 1976 to 1978
(Chilinger et al., 1982). This activity is mainly found in the western
United States where hydrothermal resources tend to be located.
ELECTRICAL POWER GENERATION
There are basically two processes that can be used in the generation
of electrical power: the conventional steam cycle and the binary power
system.
In the conventional steam cycle, geothermal brine is partially
converted to steam by flashing or sudden pressure reduction in a vessel.
Steam from the flash process system is then piped to the manifold where it
is used to directly power a turbine generator. The exhaust steam from the
turbine is condensed on a surface or barometric condenser. The
noncondensible gases are vented to the atmosphere using a steam injector
system. The condensate is then pumped to a cooling tower where it can be
cooled and reused as water or, more typically, reinjected into the
aquifer. Figure II-8 presents a flow diagram for this type of process
(USEPA, 1978).
In order to maximize thermal efficiency, some cycles utilize multiple
flashes in the overall process scheme. Because the brine usually includes
high levels of dissolved solids, the concentration of solids in the brine
increases in each flash cycle and the brine becomes more corrosive.
Therefore, a flash injection system may not be economically used in
geothermal energy fields containing a high concentration of dissolved
solids (USEPA, 1978).
II-1-19
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Table II-2.
Sunmary of Major Geothermal Drilling Activity in
Western U.S.A. (1976-1978)
State Region Area
California Imperial Valley Westmorland
Brawl ey
East Mesa
Sal ton Sea
Heber
South Brawl ey
The Geysers Main Geysers
Southeast Geysers
Northwest Geysers
North Geysers
Howard Hot Springs
Borax Lake
Mlddletown
Thurston Lake
Castle Rock
Cloverdale
Mt. Konaockl
Callstoga
Mono Co. Long Valley
Inyo Co. Coso Hot Springs
N.W. California Lassen
Nevada Churchill Co. Desert Peak
Stlllwater
Lander Co. Beowawe
Carson sink soda Lake
Allen Springs
Pershlng Co. Rye Patch
Dixie Valley
Gerlach
San Emld1o Desert
Number of wells
1976
6
2
2
-
6
-
13
-
-
-
-
-
3
-
4
1
1
3
1
1
-
2
3
1
-
-
-
-
-
-
1977
1
2
S
-
-
-
14
13
2
1
1
-
-
1
.
-
-
-
.
1
-
.
_
_
1
1
1
-
-
_
1978
4
7
1
_
1
IS
6
1
2
1
1
1
_
.
_
_
-
.
1
_
_
_
_
1
1
1
1
Total
7
a
14
i
6
I
37
47
19
3
3
2
1
4
1
4
1
1
j
89
1
2
]_
4
2
3
1
1
1
2
1
1
1
13
II-1-20
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Table II-2. (continued)
State
Oregon
Hawaii
Idaho
Utah
New Mexico
Region
Klamath Co.
Hawaii Island
Cassia Co.
Ada Co.
Washington Co.
Owyhec Co.
Beaver Co.
Mlllard Co.
Iron Co.
Sandoval Co.
Area
Klamath Hills
Mt. Hood
Puna
Raft River
Boise
Crane Creek
Castle Creek
Preston
Roosevelt H.S.
Thermo H.S.
Cove Ft.
Beryl Junction
Lund
Fenton H111
valles Caldera
TOTAL
Number of wells
1976 1977 1978 Total
1 - - 1
1 1
2
2 _j
2
2147
2 - - 2
1 - 1
- 1 - 1
1 ]_
12
3115
1 2
1124
2 - - 2
1 - 1
14
1 - 1
1 L
2
65 51 58 175
II-1-21
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(* \HAWAII
(^ 2
HAWAIIAN ISLANDS
Figure II-7 Locations of Major Geothermai Drilling, Western USA, 1976-1973.
Source: Chilinger, G.V., L.M. Edward, W.H. Fertl, H.H. Ricke III, Editors,
"The Handbook of Geothermai Energy." Houston, Texas, 1582, Gulf
Publishing Company.
II-1-22
-------
z
o
a
O
STEAM FROM
OTHER WEILS
COOLING
TOWER
WASTE WATER
O
CJ
vu
z
Figure IJ-8. Simplified Schmatic diagram of Conventional Steam Cycle Electrical Power
Plant
Source: Hartley, R., "Pollution Control Guidance for Geotheraal Energy
Development," Industrial Environmental Research Laboratory, Cffics o:
Research and Development, "J.S. EPA, 1373.
II-1-23
-------
The binary cycle avoids the corrosion problem by employing a heat
exchanger to transfer heat from the brine to a secondary working fluid.
This fluid, usually isobutane or isopentane, is then used to drive a
turbine. Binary cycles are much lower in thermal efficiency than flash
injection systems. Figure II-9 presents a flow diagram for a binary
system.
Current and Planned Development
Table II-3 presents a summary of the status (through 1985) and
projected development of geothermal power plants in the U.S. These tables
also describe power generating capacity as either operational, planned, or
under construction; they also note process type.
The two best known power generating facilities, at The Geysers and at
Imperial Valley, (both in California) utilize vapor-dominated resources.
The Geysers (through 1985) had 1792 MW operational and plans to expand
this capacity to 2660.2 MW. At Imperial Valley, the operational capacity
is 32.5 MW and plans to increase capacity to 4140 MW. These two
facilities together account for most of the installed capacity. However,
other plants are being constructed, mostly in the western United States,
to take advantage of the high temperature hydrothermal reservoirs which
can be utilized economically (DiPippo, 1985).
DIRECT USE APPLICATIONS
In addition to the use of geothermal resources for the generation of
electric power, the power plants may be used directly for heating.
II-1-24
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STEAM
QKGAHIC UflPOR
I
M
I
Ul
CEOTHERHAL
WELL
Figure II-9 Simplified Schematic Diagram for Binary Type Electric
Power Generation System.
-------
Table II-3. Geothermal Power Plants In the United States
Plant
California
Cosco:
Mammoth:
Honey Lake
Geysers:
Year
1986
n.a.
1984
198S
1987
PG&E Geysers 1960-1985
Imperial Valley
East Mesa
Sal ton sea
Heber
Binary Oemo Plant
Flash Plant (HOC)
North Brawl ey
Westmoreland
So. Brawl ey (CU I)
1985
1988
n.a.
n.a.
1988
1979
1986
n.a.
1982
1986
1985
n.a.
1985
1985
1980
1988
n.a.
Tyoe
1-Flash
1-Flash
Binary
Binary
Hybrid: wood-
geothermal
Dry steam
Dry steam
Binary
Dry steam
Dry steam
Dry steam
Binary
Binary
Binary
1-Flash
2-Flash
2-Flash
2-Flash
Binary
2-Flash
1-Flash
Binary
Flash
MW
25.0
2 x 25.0
2 x 3.5
5 x 0.6
20.0
1454
338
141.2
55
617
55
12.5
20.02
50.0
1010
73.1
31.4
49.0
45.0
49.0
10.0
15.0
49.0
Status
Under construction
Advanced planning
Operational
Under construction
Under construction
Operational
Under construction
Advanced planning
Advanced planning
Preliminary planning
Under CEC review
Operational
Under construction
Planned
Operational
Under construction
Planned addition
Planned
Under construction
Under construction
Operational
Planned
Planned
Hawaii
Puna No. 1
1982 1-Flash
3.0 Operational
II-1-26
-------
Table II-3. (continued)
Plant
Year Type
Status
Idaho
Raft River
1982 Binary
5.0 Being moved to Brady U.S.
NV
Nevada
Wabuska Hot Springs
Beoware
Brady Hot Springs
Steamboat Springs
Fish Lake
Big Smokey Valley
Desert Peak
Spring Creek
Dixie central
Oregon
Hanmersly Canyon 1983-1984 Binary
1984
1985
1986
1986
1986
1986
1985
1987
1987
Binary
2-Flasn
Binary
Binary
Binary
F1ash(?)
Total flow/
2-Flash
2-Flash
Flash
Utah
Milford:
Blundell Unit 1 1984
Wellhead No. 1 1936
Cove Ft Sulpnurdale:
Phase 1 1985
Phase 2 1985
Phase 3 1986
l-Flash
Total now/
2-Flasn
Binary
Binary
Dry steam
Totals:
0.6
17.0
8.3
5.5
15.0
10.0
9.0
20.0
20.0
Operational
Under construction
Under construction
Planned
Planned
Planned
Under construction
Planned
Planned
2.01 Operational
20.0 Operational
14.5 Under construction
4 x 0.675 Operational
2 x 1.0 Under construction
2.3 Advanced Planning
1893.61 Operational'
353.71 Operational or U.C.
3331.11 Operational, u.c. or
planned
includes plants under ccnstruction and scheduled for comole'ion in 1985.
II-1-27
-------
cooling, and a variety of other applications. Figure 11-10 presents the
potential extent of direct uses, as well as the approximate temperature
range of use. In general, direct use of geothermal resources comprises
applications in agriculture, aquaculture, space conditioning, and
industrial processes. The end use distribution along with the use
temperature is shown in Figure 11-11. Space heating is by far the most
widely practiced direct use application of geothermal energy, other uses
include (Chilinger et al., 1982):
• Greenhousing;
• Mushroom culturing;
• Livestock raising;
• Soil warming;
• Aquaculturing (fish hatcheries, alligator breeding, etc.); and
• Biogas production.
Industrial uses may include applications such as:
• Preheating;
• Washing;
• Cooking and peeling (pulp and paper industry);
• Evaporating;
• Sterilizing;
• Distilling and separating;
• Drying; and
• Refrigeration.
There are two basic types of direct use systems: those that utilize
the hydrothermal water itself and those that transfer the heat from the
hydrothermal fluid to another fluid (a working fluid). The main reason
for using a working fluid is to isolate the system from the hydrothermal
II-1-28
-------
•c
'200'
190-
180-
.170"
SATURATED^
STEAM
THERMAL
WATERS
90-
80«
70-
20.
Evspontlan of highly eonc*ntrit«d •olutlani
lUfrigannton by •mmonU «b»orptlon-
OlgntlM In p*p*r pulp. kr«ft~
*r via
s&yfngTfton'maa?
H Drying ambar ~ -
ELECTRICAL:
PRODUCT/ON
Drying fwm products «t high ratm
^Evaporation In sugar r
130— «Si EnrMtfon of tato by
u. -' -
w v At » t— f Jt —to •—• • -• — * •
Mast murapHXttaat svaparatians. aanaantratlan aiiaMna satait
Oryin* witf curing NgM-*ggr«gn* contr«t« «!•••
*
. v*g«nbln. we.
-_5
- ^
--- . -- e -
Drying (W«k n*n
Inunt* <*4«in» «p*»tlon«
Spaca hMting of gr««nriout««
R«Mg«ntio« (know t»mp*rMiu* limit)
Animal hutbantf>y
CamWnW ipac* ««d hotbed h««tlng o( 9'*
Mu
Madlclnal b*m»
Swimming p«on>. Mod«gn>«tlan. f«rm»n»nom
Wwm w«*r far y«*r-round mining In ceM eUmaim
O»4clng
n«n hatching tnt »»H worming
Figure n-10 Typical Geothermal Fluid Temperatures for Representative
Direct-Use Applications.
Source: Chilinger, G.V., L.M. Edward, W.H. Fertl, H.H. Ricke III. Editors,
"The Handbook of Geothermal Energy." Houston, Texas, 1982, Gulf
Publishing Company.
II-1-29
-------
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O
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rr
C
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01
H
V
so
US. ENERGY CONSUMPTION (%)
5 8
-------
fluid and its impurities and thus to confine or reduce corrosion and
scaling problems. Such a system is shown in Figure 11-12.
II-1-31
-------
HEAT EXCHANGERS - E.G. RESIDENCES
WATER
DISCHARGE
Figure H-12
Simplified Schematic Diagram of Non-electric Use (space
heating) of Geothermal Energy. Spent Liquids Can Be
Injected or Discharged to Surface Waters.
Source: Hartley, R., "Pollution Control Guidance for Geothermal Energy
Development," Industrial Environmental Research Laboratory, Office of
Research and Development, U.S. EFA, 1973.
II-1-32
-------
CHAPTER 2
WASTE GENERATION
A review of available information indicates that there are two primary
processes that generate wastes associated with the exploration,
development, and production of geothermal energy. These wastes come from
(1) the process of drilling and (2) the direct utilization of the
resource. This section presents a brief description of how the wastes are
•
generated and a suggested methodology for estimating waste volumes and
characteristics. A substantial amount of information was derived from
three previous studies {USDOE, 1982; USEPA, 1978; USEPA, 1983).
WASTE SOURCES
Drilling Wastes
The process of drilling for steam from a geothermal resource has been
described in detail in the Industry Description. In a 1982 study (USDOE,
1982), it was estimated that (based on the experience of drilling 50 wells
in the Imperial Valley in California) about 600 metric tons of mud and
cuttings would be produced while drilling a typical 1,500-meter well.
II-2-1
-------
Typically, there are four types of wastes generated by the drilling
process. They are:
• Drilling fluid and drill cuttings;
• Deck drainings;
• Drilling fluid, cooling tower wastes; and
• Miscellaneous small waste streams.
Drilling Fluid Waste
A large quantity of drilling waste is derived from the drilling mud or
the processing steps taken to reuse and recycle this material. The
drilling fluids are "cleaned" by circulation through solids separation
equipment, (i.e., shale shakers, sand traps, hydrocyclones, and
centrifuges). After "cleaning," the drill cuttings and washwater are
discharged and the "cleaned" muds are reused. There is, however, a point
of diminishing return with the cleaning process. When the muds become too
viscous, the muds must be discharged into a reserve pit. Muds also are
discharged into the reserve pit when all drilling is completed or when
entire mud systems are changed because of abrupt changes in drilling
conditions.
Deck Drainings Wastes
Typically, drilling oprations generate deck drainings. These wastes
are composed of rig washdown, rinses, drilling fluids, and other
miscellaneous waste materials generated on or around the derrick.
Depending on the type of drilling operations, these volumes can be
substantial.
II-2-2
-------
Drilling Fluid Cooling Tower Wastes
Some operations may necessitate the drilling fluids being cooled
before it is recycled into the well bore. For those cases, the drilling
fluid is circulated through a cooling tower. The tower will require
occasional cleaning of scale and other deposits that build up in the tower.
Miscellaneous Small Waste Streams
Other wastes will also he produced in the drilling operations. These
wastes consist of empty containers, bags, broken tools, paint wastes,
minor spillages and leaks of diesel fuel, hydraulic fluid, wood pallets,
and miscellaneous trash.
WASTE STREAMS FROM POWER PLANTS AND DIRECT USERS
It is convenient to classify the wastes generated from the usage of
geothermal energy into two categories: (1) wastes derived from operations
that use geothermal energy for electric power generation and (2) wastes
derived from direct usage. These streams are discussed on the following
pages.
Electric Power Generation
Presented below is a preliminary list of solid wastes that may result
from the generation of power from geothermal energy. These wastes include:
• Reinjection well fluid wastes;
• Piping scale wastes, production well filter waste, and flash tank
solids;
• Brine effluent precipitated solids; and
• Settling pond solids.
II-2-3
-------
The sources of these wastes are shown schematically in Figures 11-13
and Figure 11-14 (USDOE, 1982).
Several other wastes are generated by electric power generation plants
that utilize geothennal energy, but, as described in the Introduction,
these wastes are not expected to be covered by the statutory exclusion or
included in the final report. The wastes include the following:
• Makeup water treatment solids;
• Hydrogen sulfide removal wastes; and
• Cooling tower drift and blowdown.
These wastes are included in Figures 11-13 and 11-14 for completeness.
As indicated in Figure 11-14, solid precipitates resulting from
temperature and chemical changes in the brine during energy extraction
constitute about one-half of the solid waste generated; well cuttings and
drilling mud constitute about one-guarter; scale, solids from cooling
water treatment, H_S abatement, and other miscellaneous sources make up
the balance. It is not known if these charts are typical of the industry
in 1986. More data must be collected to verify these preliminary
estimates.
Reinjection Well Fluid Wastes
The reject fluid from the geothennal power plant potentially can serve
as a vehicle for disposa.1 of most of the dissolved solid wastes when
reinjected into an aquifer. However, brine injection can be complicated
by precipitation of silica in high levels. The precipitation of silica
has the tendency to occlude or cause co-precipitation of other dissolved
ions present in the brine. Thus, the silica precipitate may contain heavy
metals at elevated concentrations.
II-2-4
-------
Nl
Ul
PIPE
•SCALE
WASTE
HjbHtMOVAl /
IHtAIMtNl
WASIE
FLASH
VANK
SPENT
UHINE
PHOOUCTION
WELLflLTEfl
WASTE
WELL
DRILLING
WASTE
FLASH TANK
SOLIDS WASTE
(BHINE PHECIPITATEI
WATLH
Slim Y
COOI INli IOWER
UtfcAIMtNl/
blOWIIOWN
WASIE i
MAKE UP
WATER
SOLID
WASTES
H Ull» IHEATMF.NI
(CI.AHIHEH/
S£ miNGPONO)
rnr
T
LIOIJIU WASTE
SOI 1C)
WASIE
7777
IN IEC MOM
WEI L FlUlO
WASTE
Figure 11-13. Sources of Geothermal Solid Wastes.
Source: Darnell, A.J., et al., "Survey of Geothermal Solid Toxic Waste,"
Rockwell International Energy Technology Engineering Center, for U.S.
pppartment of Energy, San Francisco, California.
-------
Flash Tank Solid
Uastes(Br1ne
Precipitate) 53 X
Well Drilling Wastes
(Well Cuttings &
Drilling Muds) 26 X
Solids From
H,S Abatement
* 1 I
Production Well
Filter Wastes 4
Pipe Scales Wastes
15 %
Slowdown Wastes
And Solids From
Cooling Water
Treatment 5 %
Figure 11-14. Distribution of Solid Wastes from Development of a Liquid-
Dominated Geothermal Resource.
Source: Darnell, A.J., et al., "Survey of Geothermal Solid Toxic Waste,"
Rockwell International Energy Technology Engineering Center, for
U.S. Department of Energy, San Francisco, California, 1982.
II-2-6
-------
Piping, Production Well Filter Waste, Scale Waste, and Flash Tank Solids
Scale can constitute approximately 15 percent of the solid wastes
requiring disposal.. Temperature, pH, chloride and sulfate ion
concentration, and dissolved gases (C0_, H.S, NH ) all influence the
level of scale formation. Scaling and plugging may result from one or
more of the following:
• Precipitation and polymerization of silica and silicates (silica in
solution will neither precipitate nor adhere until it starts to
polymerize);
• Precipitation of alkaline earths as insoluble carbonates, sulfates,
and hydroxides;
• Precipitation of heavy metals as sulfides; and
• Precipitation of redox reaction products (e.g., iron compounds).
Silica precipitation and scale formation are among the major problems in
geothermal energy conversion and injection systems.
Many of the factors causing the formation of scale from an aqueous
solution could be reversible. It is, therefore, highly likely that scale
would exhibit some solubility to surface waters under ambient conditions
and that any toxic substances present in the scale would potentially be
leachable.
Brine Effluent Precipitated Solids
Brine effluent precipitated solids generated from geothermal fluids
are saline and may contain elements such as arsenic, lead, boron, and
fluoride. If there is to be optimum utilization of heat, most brine
effluents are returned to the reservoir. In some areas, such as the
II-2-7
-------
Imperial Valley, these can be supersaturated with silica. Although
amorphous silica may not deposit readily from water flowing in a pipe,
separator, or heat exchanger, it is known to do so on concrete or brick
surfaces. Thus, with time, it will reduce injectability by blocking the
aquifer formation unless the chemical composition is carefully
controlled. Therefore, treatment of the brines will have a major impact
on the type and amount of solids that must be disposed of. In order to
maintain its injectability in the accepting formation, it is necessary to
adequately treat this brine effluent to rectify its supersaturated
dissolved solids condition. Three processing methods used for treatment
of geothermal brines are:
(1) Ponding of the brine effluent with reinjection of the clear
liquor underground and landfilling any precipitated solids.
(2) Use of conventional water treatment technology to precipitate and
remove solids and toxic materials. The wastewater would be
injected and the solids hauled to a landfill.
(3) Processing the geothermal brine in such a way that minerals and
useful byproducts are recovered from the brine. Solid wastes
would then be disposed of in a landfill, and the clear liquid
injected into the aquifer.
Settling Pond Solids
Settling pond solids are generated by spent brine holding ponds. A
holding pond has been used at the East Mesa site for treatment of spent
brine. This holding pond has sufficient residence time so that liquid
withdrawn from the end opposite the injection point is sufficiently clear to
be injected back into the aquifer. Solids that accumulate in the pond are
dredged and then dried by evaporation and transported to a suitable landfill
site. This method has been successful in those cases where the salinity of
the brine is low. At the East Mesa site, the salinity of the brine is low
compared to the Salton Sea sites. (USDOE, 1982)
II-2-8
-------
Cooling Tower Drift and Slowdown
Cooling tower drift will be present whenever an evaporative type cooling
tower is used. The drift is a fine mist of water droplets that escape from
the top and sides of the tower during normal operation. Any compounds
normally present in the cooling water will be carried out with the drift.
Direct Steam Usage
A brief discussion of direct resource utilization has been discussed in
the Industry Description. Drilling wastes generated from these applications
are expected to be similar to those produced for power generation.
Information on waste sources from direct steam usage is currently being
developed.
WASTE CHARACTERIZATION, COMPOSITION, AND VOLUMES
A preliminary review of information from selected data-bases indicates
that the literature is limited in the areas of quantifying the sources,
volumes, characteristics, and management techniques for specific wastes
derived from some, but not the majority, of geothermal activities.
Nevertheless, there is still enough data to provide the reader, in the
interim, with a general sense of the types and characteristics of wastes that
may be encountered as a result of the utilization of geothermal energy. We
are currently reviewing the following:
• Chemical Abstracts;
• Enviroline;
• Pollution Abstracts;
II-2-9
-------
• U.S. Geological Survey Library;
• U.S. Department of Energy, Geothermal Division Reports;
• Cambridge Scientific Abstracts;
• Sandia National Laboratories Technical Publications;
• Los Alamos Scientific Laboratory Publications; and
• Proceedings of the Geothermal Resources Council.
Because of data availability, this report will again draw heavily on the
results of three EPA studies: published in 1978, 1982, and 1983, which were
undertaken to characterize certain types of geothermal wastes at selected
sites.
WASTE STREAMS FROM ELECTRIC POWER GENERATION AND DIRECT USERS
In 1983, major geothermal resource exploration and development sites in
the western United States and the Gulf Coast were screened by Acurex under
contract to EPA (USEPA, 1983) to locate candidate sites for sampling and
analysis. A telephone survey of over 20 individuals representing 15
organizations was conducted to identify the types of solid wastes generated.
These data appear to be the most detailed and comprehensive found to date.
As a result of the telephone discussion, follow-up letters, and several
site visits, the sampling program was defined and permission obtained for
collecting samples in three geothermal resource areas: the Imperial Valley —
7 sites. The Geysers — 11 sites, and Northwestern Nevada — 3 sites.
The samples, collected on three field trips, encompassed the following:
II-2-10
-------
Total Geysers, CA Imperial Val., CA Nevada
Drilling sumps
Mud/fluid 82 3 3
Mud only 3 . 3
Fluid only 5 5
Reinjection treatment
Sediment ponds 3 3
(brines)
Flash tank 1 1
Filter press 1 1
Cooling tower basins 3 3
H2S removal
Centrifuge (iron 3 3
sulfide sludge
dewatering)
Stretford process 1 1
sulfur recovery
stream
Miscellaneous
Pipe scale 2 2
Geological surface 1 1
expression
Landfill 2 2
Of this sampling and analysis program was to evaluate the solid wastes
for some RCRA hazardous waste characteristics and listing criteria
proposed in 1978.
In addition to the eight constituents analyzed (Ag, Ba, Cd, Cr, Pb,
Hg, Se, As), tests were also conducted for eight other metals in that
study. These metals (Sb, Be, B, Cu, Li, Ni, Sr, Zn) were included because
of their suspected presence in geothermal solid wastes and their listing
in the water quality standards of several western States. Analytical
results for these metals are summarized in Table II-4. In general, these
levels were fairly low, except the levels for boron and zinc.
II-2-11
-------
Table II-4. Summary of Results for Additional Metals
Metal
Antimony
Beryl 1 ium
Boron
Cooper
Lithium
Nicfcel
Strontium
Zinc
Range of
Concentrations
— All Samples
(mg/1 )
0.05 - 0.18
0.020
0.2 - 660
O.OS - 60
o.os - s. a
0.2 - 0.90
0.5 - 1 ,400
0.020 - 6.000
Average Concentration
All values Above
Detection Limit
(mg/1 )
0.14
~
43
9
1.1
0.50
174
203
Number of
Values Above
Detection Limit13
3
0
26
12
19
n
16
30
alncludes results for both acid and ambient pH extracts.
''Total number of possible values (analyses) equals 42.
II-2-12
-------
Additional organic analyses were conducted on three samples,
presumably drilling wastes. Sample G12 was collected at the Class II-2
landfill in Brawley. This landfill contained a mixture of fresh solid
wastes, predominantly drilling muds, from the Imperial Valley. Sample
G24-1 was a geothermal drilling mud sample containing significant amounts
of oil. Additives known to be present in this mud were bentonite, sodium
hydroxide, calcium hydroxide, sodium tetraphosphate, and a polymeric
material. Sample G22-1 was selected for organics analysis because
cationic polyamines and anionic polyacrylamides are added to the iron
sludge removed from the H.S abatement centrifuge. These additives
facilitate settling of the solids.
Three samples (two drilling muds and an iron sulfide) were screened
for the 11 acid compounds and 46 base/neutral compounds listed as priority
pollutants by EPA. Each sample gave two fractions for analysis by GC/MS.
Phenol and phenol derivatives were found in all three samples. The
occurrence of phenols in the drilling mud samples (G12 and G24-1) is
probably due to the reaction of caustic soda (NaOH) with additives
containing phenol groups. The alkaline nature of the muds and the final
pH of the ambient extracts (both 9.4) suggest that the phenol is present
as a sodium salt. This is confirmed by the higher concentration of phenol
in the ambient extract (640 V*g/l) compared ' to the acid extract
(2 Mg/1) in G24-1. Polynuclear aromatic compounds (PNAs) were also
detected in G-12 and G22-1. For sample G-12, these could easily have come
from asphalt (known to contain PNAs), which may have been used in an
oil-based drilling mud system. The presence of a PNA in the iron sludge
(G22-1) cannot be readily explained, since the only known additives were
polyamines and polyacrylamides.
Tables II-5, II-6, and II-7 summarize the analytical results for these
three samples. In addition to the trace levels of organics, the Brawley
II-2-13
-------
Table II-5. Geothermal Analytical Data: Class 11-2 Landfill
Number: GI2 M437) Type: Mixed Solids
to
I
Location; Bradley
Bulk
Compofr j t j Qt)
Aluminum (Al)
Calcium (Ca)
Iron (Fe)
Magnesium (Hg)
Potassium (K)
Sodium (Na)
Chloride (Cl)
Fluoride (F)
Silica (Si02)
Sulfate (S04)
Sulfide (S)
ORGAN 1CS
( Imperial
Total
2.3
1.60
1.2
1.72
0.69
0.50
0.40
0.033
24.2
0.06
0.01
Valley!
Acid
Extract
(mq/1)
1
680
0.8
20
46
235
215
0.29
2
10
0.1
Priority Pollutants Detected
Acid. Extract
Neutral Extract
phenol
4.6-dini tro
Dhenol
-o-cresol
Anthracene/ohenathrene
Neutral
Extract
(mg/H
190
33
76
52
85
230
227
0.56
160
85
0.1
Mg/1
4
lfl
2
6
Site Owner/Operator:
Trace Elements
Arsenic (As)
Barium (Ba)
Cadmium (Cd)
Chromium (Cr)
Lead (Pb)
Mercury (Hg)
Selenium (Se)
Silver (Ag)
Antimony (Sb)
Beryllium (Be)
Boron (B)
Copper (Cu)
Lithium (Li)
Nickel (Ni)
Strontium (Sr)
Zinc (Zn)
OTHER
Corrosivi ty
Moisture
TSS
Radium 226
Imperial County Dept. of
Acid
Extract
tUflZlL-
100
1.000
5
23
20
1
20
20
50
20
200
70
130
200
2.400
250
PARAMETERS
10 pH
5r/.
NA
1.15 pCi/g
Public Works
Acid
Extract
(Ug/li
250
1,400
5
420
20
Int
50
20
100
20
340
230
340
200
100
1,400
-------
Number: G22-1 (15791
Table 11-6. Geothermal Analytical Data: Iron Sludge from Centrifuge
Type: Sludge
Location; Unit 5 & 6 (The Gevserb)
Bulk
Composition
Aluminum (Al )
Calcium (Ca)
Iron (Fe)
Magnesium (Mg)
Potassium (K)
Sodium (Na)
Chloride (Cl)
Fluoride (F)
Silica (Si02)
Sulfate (S04)
Sulfide (S)
ORGANICS
Total
a>
0.01
0.005
7.7
0.005
0.004
0.065
0.005
0.001
0.04
0.29
0.2
Acid
Extract
(mg/ll
1
2.4
0.2
0.20
O.IB
24
1
0.12
4
9.5
0.1
Priority Pollutants Detected
Acid Extract
Neutral Extract
phenol
Benzo (k)
f luoranth^ne
Neutral
Extract
(mq/n
1
2
0.2
0.16
0.15
24
1
0.14
4
85
0.1
"g/1
Q 4
_^
None detected
Site Owner/Operator: PG & E
Trace Elements
Arsenic (As)
Barium (Ba)
Cadmium (Cd)
Chromium (Cr)
Lead (Pb)
Mercury (Hg)
Selenium (Se)
Silver (Ag)
Antimony (Sb)
Beryllium (Be)
Boron (B)
Copper (Cu)
Lithium (Li)
Nickel (Ni)
Strontium (Sr)
Zinc (Zn)
Corrosivi ty
Moisture
TSS
Radium 226
Acid
Extract
jM.g/1)
20
300
5
20
20
1
20
20
50
20
28,000
70
50
200
500
60
OTHER PARAMETERS
6.6 pH
70%
NA
0 pCi/q
Acid
Extract
(Ug/1 1
20
300
5
20
50
1
20
20
100
20
27,000
70
100
200
500
30
-------
Table II-7. Geothermal Analytical Data: Abated Well Sump, Beigel #1 Well
Number: G24-K158IR1 Type: Mud
to
I
Location: Near Unit 18(The Gevsersl
Bulk
Composition
Aluminum (Al )
Calcium (Ca)
Iron (Fe)
Magnesium (Hg)
Potassium (K)
Sodium (Na)
Chloride (CD
Fluoride (F)
Silica (Si02)
Sulfate (S04)
Sulfide (S)
ORGANICS
Total
q>
1.58
0.59
3.03
1.6S
0.27
0.11
0.014
0.024
19.4
0.02
0.02
Acid
Extract
(mo/ll
,
280
32
9.6
6.3
24
2
0.34
4
32
0.1
Priority Pollutants Detected
Acid Extract
Neutral Extract
2-nitrophenol
phpnol
phenol
Neutral
Extract
(mg/1)
1
34
0.2
0.04
2.5
48
1
0.28
16
62
0.1
Mg/1
3
2
640
Site Owner/Operator:
Trace Elements
Arsenic (As)
Barium (Ba)
Cadmium (Cd)
Chromium (Cr)
Lead (Pb)
Mercury (Hg)
Selenium (Se)
Silver (Ag)
Antimony (Sb)
Beryllium (Be)
Boron (B)
Copper (Cu)
Lithium (Li)
Nickel (Ni)
Strontium (Sr)
Zinc (2n)
OTHER
Corrosivi ty
Moisture
TSS
Radium 226
Union Oil of California
Acid
Extract
(Ufl/l >
20
300
5
20
20
1
20
20
50
20
870
70
50
300
600
300
PARAMETERS
10 pH
53%
NA
0.5 pCi/g
Acid
Extract
(Ug/]\
32
300
5
20
20
1
20
20
50
20
15,000
70
50
500
500
20
-------
sites showed elevated levels of barium 1,400 l*g/l and the other two
sites showed elevated levels of boron 1,500-27,000 ^g/1 in the waste
streams.
DRILLING WASTES
The 1982 EPA study (USDOE, 1982) provides a qualitative composition of
a typical drilling fluid one might use in geothermal drilling operations.
The report presents the results of sampled and analyzed drilling muds and
cuttings at six power plant locations.
The report postulates that, while the well cuttings are not likely to
be hazardous in themselves, they may be sufficiently contaminated with
brine and drilling fluid to require special disposal. A summary of the
results from the analysis of these samples is given in Table II-8.
Production Waste
Analyses were made of several other waste streams including:
• Piping scale wastes and flash tank solids;
• Settling pond solids and effluent;
• Cooling tower drift and blowdown; and
• Brine effluent precipitated solids.
Data from these was streams are included in the 1983 EPA study and are
provided in order to establish the relative ranges of concentration pre-
sent at one location. In general, all four effluents show low levels of
arsenic. Barium results showed levels of barium (300 - 10,500 Vg/l) in
II-2-17
-------
0)982
Table 11-8. Summary of Analysis from Drilling Muds
l-t
M
Nl
1
|-_ |
00
Location
East Mesa. CA
Nil and. CA
Westmoreland, CA
The Geysers, CA
(near Unit 13)
Steamboat. NV
Hunboldt. NV
Desert Peak. NV
pH
12.0
8.4
8.8
9.6
9.3
9.8
9.1
Radioactivity
(pCi/g)
1.0
2.1
5.9
0.4
1.0
1.6
Kb
As
Ba
Cd Cr
(Neutral
Pb
Extract)
Hg Se
Ag
(Mg/L)
20
20
41
20
260
140
20
300
300
6,800
300
300
500
300
5
5
5
5
5
5
5
20
20
20
20
20
27
39
20
20
20
20
20
400
20
1 20
1 20
1 120
1 20
1 20
1 20
1 20
20
20
20
20
20
20
20
-------
the acid extract and somewhat lower levels (300 - 5,400 >*g/l) in the
neutral extract. RCRA limits for barium are 100 Wg/1. Arsenic levels
range from 36 to 230 Vg/1 in the acid extract and 33 to 230 Hg/1 in
the neutral extract. The analytical findings for lead ranged from less
than 20 ug/l to 200 Hg/1 in acid extract and less than 20 "g/1 to
130 ug/l in neutral extract.
DATA NEEDS
This waste information essentially represents "point" data, but is the
best available at this time and shows characteristics that are believed to
be highly site specific. Further data are required before definite
conclusions can be reached about the nature and characteristics of waste
generated from power production from geothermal resources.
Data are not available to allow the projection of total volume of mud
and cuttings for the industry, and this must be developed. However, the
1982 EPA study estimated that 600 metric tons of cuttings and that mud
would be generated by the drilling of one 1,500-meter well. These
estimates are based on data derived from drilling 50 wells in the Salton
Sea area of California.
In addition, information covering the volumes and composition of the
waste from drilling operations must be developed. This information
includes the volume and characteristics of mud pit solids, well cuttings,
and cooling tower blowdown. Because of the dispersed nature of the
industry, it is suspected that the results of these findings will show
that the characteristics of these streams will be very site and geologic
formation specific. If this is the case, then a comprehensive
characterization of the industry will be very complex. Data are also
II-2-19
-------
required in order to prepare reliable estimates of volumes of wastes
generated by the industry.
To fill these data gaps and to provide the data required to complete
the study, the literature survey now underway will be completed. This
manual literature search of waste characteristics and volumes will be
supplemented by accessing the following data bases: Aqualine, Enviroline,
Pollution Abstracts, and Chemical Abstracts. Appropriate articles will be
obtained and the information combined with existing data. The information
gathered from these data bases will be analyzed, tabulated, and
summarized. Data gaps will be identified and geothermal facility
owners/operators will be contacted to fill in these gaps. RCRA 3007
questionnaires and field sampling may also be required, if appropriate.
The Petroleum Equipment Supplier's Association has also agreed to provide
data to assist in the calculation of waste volumes.
The outputs from the review will be (1) an up-to-date listing of
active and planned geothermal power and direct stream users; (2) an
analysis of the amount and quality of waste characterization, treatment,
and disposal information available for each facility or geothermal region;
and (3) a firm estimate of additional data required.
Following EPA review and approval of area selection, drillers, owners,
and operators in each area will be contacted either by letter or telephone
to request their voluntary cooperation with this program. The goal is to
find a few operators in each area who would be willing to provide process
details, waste characterization and allow site sampling, if necessary.
Once industry contact has been established, data from each site will
be collected and an assessment will be made as to the necessity of site
II-2-20
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visits and waste sampling. If laboratory work is required, a sampling and
analysis plan will be prepared and arrangements will be made for the
actual sampling and analytical work to be conducted. Use will be made of
similar existing sampling and analysis plans, where appropriate, to
expedite the work.
Engineering studies will then be conducted, where necessary, to define
and evaluate alternative disposal methods, and to review and analyze the
results of the field studies. Concurrent with the field survey
activities, a preliminary list of alternative waste disposal options will
be prepared. The sources of these options will be the literature and
engineering judgment.
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CHAPTER 3
WASTE MANAGEMENT
Although the treatment and disposal methods for wastes from geothermal
operations are not well documented in the published literature, there is
some consistency in the reported methods. For example, the literature
reports that most geothermal wastewaters are reinjected into the
geothermal field (USDOE, 1982; USEPA, 1978). At the Geysers reinjection
into the same formation was started in 1969. Billions of gallons of
geothermal brine effluents have been reinjected since then. Cooled
geothermal effluent when reinjected back into the same formation,
scavenges heat from the reservoir rock matrix and may be withdrawn again.
Steam condensate that is reinjected may be withdrawn again as steam. This
reinjection process provides for a higher recovery rate of the stored
heat, helps prevent subsidence, and helps maintain the reservoir
pressure. Air emissions are not addressed in this report, but will be
discussed in the draft Report to Congress.
Old production wells may be converted to use as injection wells or new
wells may be drilled. Injection can be accomplished by gravity alone
because of the higher gravity head of the cooler and denser wastewater,
but pumps are usually provided. The efficiency of the injection operation
is highly dependent on the physical, chemical, and thermodynamic
characteristics and interrelationships of the wastewater, as well as the
reservoir fluids and rocks.
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Pretreatment may be required before injection to prevent silica
plugging, scaling, and pipe corrosion. Generally, the pretreatment
involves settling, coagulation, clarification and filtration. The
addition of corrosion or scale inhibitors may also be required.
Most of the available treatment and disposal data are old and will be
updated. A data search is being undertaken to identify waste
characteristics that will provide data on treatment/disposal processes.
This information will be combined with the existing data and data gaps
will be identified.
Where data gaps exist, current information will be solicited first by
telephone and then, if necessary RCRA 3007 questionnaires will be sent to
selected operations. If field sampling of wastes is required, then data
will also be requested on both current treatment/ disposal practices and
alternative treatment/disposal processes.
Some information is available on alternative treatment/disposal
processes. Many of these alternative processes have been field tested.
Existing data on the effectiveness of these processes will be evaluated
and compared to engineering studies to establish viable alternatives.
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CHAPTER 4
COST OF CURRENT AND ALTERNATIVE DISPOSAL PRACTICES
The literature contains some outdated cost estimates for treatment
processes that were in use during the late 1970s. Much of these data can
be inflated with appropriate indices in order to obtain current cost
estimates for those particular treatment/disposal processes represented.
The Agency is in the process of reviewing additional literature that has
been collected to locate more recent estimates for these current
processes. In addition to these published sources of data, a small sample
survey will be conducted to obtain up-to-date data on current treatment
and disposal practices. This survey will seek cost data (both investment
and operations/maintenance) on these processes. These collection cost
data will provide the basis for estimates of current waste practice cost.
In order to compare various alternatives, a cost estimate will be
derived for each individual process or practice. It is important to know
the cost of both current and alternative treatment processes so that the
incremental cost of any new treatment processes can be evaluated when
economic impacts are calculated.
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DEVELOPMENT OF ESTIMATES
There are several methods for preparing cost estimates. Selection of
a method to be used depends on the amount of detailed information
available and the accuracy desired. The following list briefly describes
the primary cost estimating techniques, any of which could be the most
appropriate, depending upon design constraints and guidelines of a
specific project.
Bottom-up Technique
The bottom-up approach to estimating, also called the detailed
take-off technique, requires a detailed definition of all the equipment
and material needs for a given project. This explicit itemization is
accomplished through the use of completed drawings, flow sheets, and
specifications. Equipment cost data are generally obtained from firm
equipment bids based on detailed purchase specifications. Costs for
engineering, supervision, installation, etc., are determined using
accurate labor rates, employee-hours standards, and productivity
assumptions. These costs are accumulated from the "bottom up" to obtain a
total cost estimate. Accuracy is usually ±10 percent.
Parametric Technique
Parametric estimating requires historical data bases on similar
systems or subsystems. For example, costs may be estimated for a proposed
facility by finding correlations among projects completed in the past that
use similar design or performance parameters (known as cost drivers) in
addition to using the same or similar equipment items. The analysis
produces cost equations or cost estimating relationships that can be used
individually or grouped into more complex models. Accuracy is usually
within an order of magnitude for estimates of this types.
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Specific Analogy Technique
Specific analogies use the known cost of a prior system as the basis
for estimating the cost of a similar new system. Adjustments are made to
known costs to account for differences in relative complexities of
performance, design, and operational characteristics. Accuracy is usually
+30 percent.
Cost Review and Update Technique
The cost review and update estimate is constructed by examining
previous estimates of the same or similar projects for internal logic,
completeness of scope, assumptions, and estimating technology. The
estimates are then updated to reflect the cost impact of new conditions or
estimating approaches. Sometimes a contractor efficiency index is derived
by comparing originally projected contract costs to actual costs on work
performed to date. The index is used to adjust the cost estimate of work
not yet completed. Accuracy is usually +5 percent.
Factored Cost Technique
Factored cost estimating incorporates elements of several estimating
techniques including portions of those previously discussed. The first
step in factored cost estimating is to develop an equipment list from
process flow diagrams or engineering drawings. Costs for major equipment
items are collected from various data sources such as vendor quotes,
equipment catalogues, and recent prices for the same or similar items.
The total equipment cost is then used in determining the add-on costs of
installation/erection, piping, instrumentation, insulation, electrical
system, and engineering. These add-on costs are calculated as a
percentage (based on extensive historic experience) of the total equipment
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costs and vary depending on the process involved, difficulty of
installation, design complexity, past experience, etc. This results in a
total direct plant cost to which indirect costs such as the contractor's
fee and contingency costs are added. Fee and contingency costs are
usually estimated as the percentage of the total direct plant cost.
It is anticipated that all but the bottom-up technique may be used to
derive estimates for alternative geothermal treatment processes. It is
not believed that detailed drawings will be available in order to permit
use of this more costly and time-consuming estimating approach. It is
likely that many of the estimates will be updates of previous estimates or
analogies. Some parametric estimating relationships exist in the
published data, and these are also likely to be used for certain processes.
Each estimate will be normalized to account for inflation, geographic
location, geothermal production rate, and similar factors that might tend
to skew a comparison between existing and alternative practices. Similar
cost estimate categories will be used so that the same adjustments can be
made to financial statements in order to determine total economic
impacts. At a minimum, costs will be broken into capitalized investment
costs and annual operations maintenance costs.
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CHAPTER 5
ECONOMIC IMPACTS OF ALTERNATIVE METHODS OF TREATMENT AND DISPOSAL
An economic impact assessment analysis will be conducted in future
work on a facility-by-facility basis. This assessment will encompass
evaluation of impacts on production costs, profitability, and liquidity.
In addition, an analysis of the impact on plant profitability and the
likelihood of plant closure will be made using computerized discounted
cash flow techniques. As a last step, small business and community
impacts will be calculated. In order to account for uncertainty,
sensitivity studies will be conducted wherein major variables and
assumptions will be varied to assess the impact.
The economic impact analysis will begin with a definition and
description of the industry. This industry description will include
geographic locations, production levels, income, prices/rates, product
volumes, employment levels, production costs, and profitability figures.
Product differentiation, substitution, demand elasticity, and barriers to
entry also will be evaluated. Much of the data necessary for the industry
description is currently available, but needs validation and updating.
Since several of the facilities will be experimental, the data reported
may vary from facility to facility. This descriptive material will
establish a baseline case for each facility.
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An economic impact assessment consists of a comparison of current
financial measures, in which the cost of current waste treatment processes
is reflected, with pro forma financial measures in which selected
alternative waste treatment options are substituted. The financial
measures will include production costs, profitability, and liquidity.
Ideally, these financial comparisons will be conducted at the facility
level so that the economic impact on the geothermal facility can be
isolated and quantified. Financial data will be obtained from State
Public Utility Commissions (PUCs). Regulated utilities are required to
file periodic statements with the PUCs, which contain information
regarding production costs, taxes, profits, assets, and other financial
data. These data will be gathered for each geothermal electric generation
production facility and for each regulated heating district. The PUC data
will form the baseline case that reflects current disposal practices.
The cost of disposal practices evolving from the cost analysis will
provide both capital investment and operations/maintenance costs for both
existing and alternative waste treatment/disposal systems. The impacts of
the existing treatment/disposal systems will be subtracted from the
baseline financial data, and the cost of removing the old system and
installing and operating the new system will be added. The impact of this
change will be reflected in a mills/kwh or similar measure that can be
compared to the estimated cost of alternative energy. The impact on
profitability as the final step of determining the economic impacts, a
closure analysis will be conducted wherein the current liquidation value
of the facility is compared to the present values of cash flow over the
remaining life of the facility. From this closure analysis, the impact on
employment, small business, and the community can be estimated.
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BIBLIOGRAPHY
Armstead, Christopher H. 1983. Geothermal Energy: Its past, present and
future contribution to the energy needs of man. 2nd ed. London: E and FN
Span.
Chilinger, G.V., L.M. Edward, W.H. Perth, and Rieke. III. eds. 1982. The
Handbook of Geothermal Energy. Houston, Texas, Gulf Publishing Company.
DiPippo, R. 1985. Worldwide Geothermal Power Development. EPRI Annual
Geothermal Meeting. San Diego, California.
Energy Development. EPA-600/7-78-101. Cincinnati, Ohio. U.S.
Environmental Protection Agency.
Environmental Aspects, Livermore, California: U.S. Department of Energy.
USDOE. 1982. U.S. Department of Energy. Survey of Geothermal Solid
Toxic Wastes. San Francisco, California.
USEPA. 1983. U.S. Environmental Protection Agency, Office of Research
and Development, Industrial Environmental Research Laboratory. Analysis
of Geothermal Wastes for Hazardous Components. NTIS P893-18860.
Cincinnati, Ohio. U.S. Environmental Protection Agency.
USGS. 1979. U.S. Geological Survey. Assessment of Geothermal Resources
of the United States. Circular No. 790. Washington, D.C.: Federal
Printing Office.
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Partm
Damage Case Assessment
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CHAPTER 1
INTRODUCTION
Section 8002(m) of the Solid Waste Disposal Act, as amended in 1980,
requires EPA to conduct a detailed and comprehensive study of the adverse
effects, if any, of drilling fluids, produced waters, and other wastes
associated with exploration, development, or production of crude oil,
natural gas, or geothermal energy. As specified in the Act, adverse
effects may include, but are not limited to, effects of wastes on humans,
water, air, health, welfare, and natural resources. The study must also
review the adequacy of means and measures currently employed by the oil,
gas, and geothermal drilling and production industries to prevent or
substantially mitigate such adverse effects.
The most direct method for meeting this requirement for estimating
possible damages is through the use of documented damage cases; Congress
has therefore directed EPA, under Section 8002(m)(D) of RCRA, to develop
such damage case data. A second method proposed by EPA for estimating
damage is through the use of risk assessment (described in Part IV of this
report). The two approaches are independent, but are intended to
complement and corroborate each other. Data developed under the damage
case review for this project will not be used as input to risk assessment
models or methods.
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This part of the report deals with EPA's proposed methodology for
gathering damage case data in a comprehensive, structured, and fully
documented manner. The methods described below to gather, document, and
interpret damage case data are simple and straightforward. EPA's overall
goal is to develop a compendium of available information on the incidence
of environmental contamination or damage, both actual or suspected, that
may be caused by the disposal of wastes from the subject industries.
Although it is impossible to determine precisely what types of adverse
impacts are caused by oil, gas, and geothermal operations before
completing the damage case review, the general categories of damage
expected are as follows:
• Human health effects (acute and chronic). While there may be
instances where contamination has resulted in documented cases of
acute adverse human health effects, such cases are expected to be
rare. Levels of pollution exposure caused by oil, gas, and
geothermal operations are more likely to be in ranges associated
with chronic carcinogenic and non-carcinogenic effects. The
damage case study will therefore seek to document instances where
operations result in levels of exposure associated with potential
long-term chronic effects, rather than attempt to document the
adverse effects themselves.
• Environmental effects. This type of damage would include
impairment of natural ecosystems and habitats, including
contamination of soils, impairment of terrestrial or aquatic
vegetation, or reduction of the quality of surface waters.
• Effects on wildlife. This would include impairment to
terrestrial or aquatic fauna; types of damage could include
reduction in species' presence or density, impairment of species
health or reproductive ability, or significant changes in
ecological relationships.
If necessary, the approaches described below may be modified or
expanded over the course of the project in order to support this goal
or in response to comments received on this initial report.
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• Effects on livestock. Damage in this category would include
morbidity or mortality of livestock, impairment in the
marketability of livestock, or any other adverse economic impacts
on livestock.
• Impairment of other natural resources. This category could
include contamination of any current or potential source of
drinking water, disruption or lasting impairment to agricultural
lands or commercial crops, impairment of potential or actual
industrial use of land, or reduction in current or potential use
of land.
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CHAPTER 2
APPROACH FOR COLLECTING DAMAGE CASES
The proposed approach for collecting damage case data involves four
separate activities: (1) specification of information types required,
(2) identification of case study information sources, (3) specification of
procedures for collecting data, and (4) specification of criteria for
classifying cases. Each activity is discussed separately below.
SPECIFICATION OF INFORMATION TYPES REQUIRED
The initial phase of the damage case study will identify the types of
information necessary for fulfilling the directive of Section 8002(m)(D).
The types of information EPA plans to gather will also support the
Agency's assessment of potential danger to human health and the
environment from surface runoff or leachate required in Section 8002(m)(C).
The information to be collected for each incident includes:
Characterization of specific damage types. This will involve
identification of the environmental medium or media involved, the
type of incident, and a characterization of actual or suspected
damage.
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The size and location of the site. Each site's location will be
noted, especially for its hydrogeological and other pertinent
environmental factors.
The operating status of the facility or site. A notation of
whether the site is active or inactive will be made.
Identification of the type and volume of wastes. For each
incident, EPA will characterize the types and volumes of oil,
gas, or geothermal wastes involved. This will include
identification of constituents and constituent concentrations in
the wastes associated with the contamination or damage.
Identification of waste management practices. For each incident,
information is required on the types of waste management
practices causing or contributing to the contamination or damage.
Identification of any pertinent regulations affecting the site.
These could include local. State, or Federal rules governing
environmental releases, health and safety requirements,
production restrictions, or any other relevant factors.
Type of documentation available. For each case, the nature of
the available documentation must be noted. This may include
environmental monitoring data, site inspection reports, records
of citizen complaints, litigation, enforcement-related
information for a local. State, or Federal rule violation, court
records, or records of administrative decisions.
IDENTIFICATION OF CASE STUDY INFORMATION SOURCES
The next phase of this effort will be to identify a full range of
potential sources of damage case information.
Although oil, gas, and geothermal operations exist in 33 States,
98 percent of the 1985 drilling activity and 97 percent of all producing
wells in the United States lie within 21 of those States. Because of time
and resource limitations, EPA will restrict its damage case study to these
21 States (see Table III-l). Furthermore, no attempt will be made to
conduct a complete census of all known damage cases, current or
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Table III-l. List of States from Which
Case Information Is Being
Assembled
1. Alabama
2. Alaska
3. Arkansas
4. California
5. Colorado
6. Illinois
7. Kansas
8. Kentucky
9. Louisiana
10. Michigan
11. Mississippi
12. Montana
13. New Mexico
14. North Dakota
15. Ohio
16. Oklahoma
17. Pennsylvania
18. Texas
19. Utah
20. West Virginia
21. Wyoming
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historical, within these States. Rather, EPA will seek to construct a
representative sample of cases based on criteria presented in the next
subsection (see below).
Sources of information relating to the selected States will include, but
are not necessarily limited to:
• Relevant State or local agencies. These will include State
environmental agencies, oil and gas regulatory agencies. State,
Regional, or local departments of health, and other agencies
potentially knowledgeable about damage cases.
• EPA Regional Offices.
• U.S. Bureau of Land Management.
* U.S. Forest Service.
* U.S. Geological Survey.
• Professional or trade organizations.
• Public interest or citizens' groups.
An attempt will be made to contact as many potential sources of
information as is possible in each of the 21 States to be surveyed. All
information collected, from whatever source (Federal, State, or local),
will be furnished to appropriate State agencies for review prior to
incorporation in this study.
SPECIFICATION OF PROCEDURES FOR COLLECTING DATA
The third phase of the study will be to select an appropriate sample
of cases from the range of those uncovered by contacts with the
organizations listed above. Documentation will then be gathered on this
sample.
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Criteria have been established for guiding detailed data collection
efforts. Cases selected for investigation will emphasize:
1. Recent cases. Cases that have occurred recently are the most
likely to reflect current waste management practices.
2. Cases that illustrate clear relationships among environmental
damage and specific waste management practices. Such links may
best be documented where scientific investigations have been
conducted at the involved sites.
3. Cases where the most significant levels of damage have occurred.
The Agency will seek to document as wide a range of damage types
as possible (see above).
Once sample cases have been selected for investigation, the Agency
will attempt to develop as much documentation as possible for each case.
This will include:
• Site investigation reports performed by State agencies in response
to citizen complaints;
• Inspection reports of unsatisfactory waste management;
• Follow-up site investigations, memoranda, and reports on individual
sites;
• Special studies performed on local or Regional issues that describe
specific sites' problems;
• Testimony of expert witnesses in administrative or court
proceedings; and
• Compliance orders or other administrative directives, with
supporting documentation, issued by State enforcement offices.
EPA believes that these materials will contain the information
required to satisfy Congress's directives, but will also review any other
available, appropriate information.
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SPECIFICATION OF CRITERIA FOR CLASSIFYING CASES
The final step of the damage case review project will be to classify
the collected damage cases and subject them to a test of proof. For the
purpose of this study, EPA will consider that a case has met the test of
proof if the damage, as defined above, is documented and is determined to
have been caused by oil, gas, or geothermal operations (1) through the
conclusion of a scientific investigation of the case, (2) by an
administrative ruling, or (3) by court decision.
Cases that fail to meet the test of proof will not be discarded, but
will be retained to furnish additional background information relevant to
other needs of this study.
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CHAPTER 3
APPLICATION OF DAMAGE CASE RESULTS
EPA intends to use the information contained in the damage cases to
support the assessment of the potential danger to human health and the
environment. EPA plans to present descriptive information from these cases
illustrating empirical relationships among damage types and particular types
of wastes, particular environmental contexts, and particular waste management
processes.
In addition, summary data will be cross-referenced by:
• Damage type. (As discussed above).
• Waste type. This will include consideration of the physical, chemical,
and toxicological characteristics of wastes.
• Environmental setting. Information will be referenced, as
appropriate, by hydrogeological characteristics, aquatic features,
meteorology and climatic regime (e.g., proximity of site to surface
water, net infiltration, surface and ground-water quality and flow
velocity), and any other relevant environmental factors.
• Exposure. Information will be referenced, as appropriate, to important
human or ecological exposure pathways (e.g., proximity to public or
private drinking water wells or surface water intakes, exposure to
agricultural crops or through food animals, etc.).
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The Agency wishes to emphasize that these data on damage estimation will
be compiled independently to the risk assessment. None of the data gathered by
this effort will be directly used in the modeling analysis (see Part IV,
following). The basic goal of this effort is to compile empirical descriptive
data on the existence of damages associated with exploration, development, and
production, to characterize as representatively as possible the nature and
extent of these damages, and to link causes and effects to the extent feasible.
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Part IV
Risk Assessment
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CHAPTER 1
INTRODUCTION
Section 8002(m) of the Solid Waste Disposal Act, as amended in 1980,
requires EPA to conduct a detailed and comprehensive study of drilling
fluids, produced waters, and other wastes associated with exploration,
development, or production of crude oil, natural gas, or geothermal
energy. Section 8002(m)(1)(C) directs EPA to analyze the potential danger
to human health and the environment from surface runoff or leachate
resulting from these activities. This part describes the proposed
approach for a risk analysis to fulfill the requirements of Section
8002(m)(l)(C). The approach is applicable to both oil and gas operations
and geothermal energy operations, although the input data for the analysis
will differ for the two industry categories.
The objectives of the risk analysis are to (1) characterize and
classify the major risk influencing factors (e.g., waste types, disposal
technologies, environmental settings) associated with current waste
management practices at oil and gas and geothermal energy facilities;
1 In this part all references to oil and gas and geothermal energy
facilities or sites refer to exploration, development, and production
operations.
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(2) estimate distributions of risk influencing factors across the
population of facilities; (3) rank these factors in terms of their
relative risks; and (4) develop initial quantitative estimates of the
range of baseline health and environmental risks for the variety of waste
types, management practices, and environmental settings that exist.
To meet these objectives, the risk analysis will estimate health and
environmental risks from fully specified model scenarios that represent
the range of wastes, release sources, and environmental settings typical
of onshore oi; and gas and geothermal energy operations. The Agency will
develop the model scenarios based on its review and analysis of available
data on actual oil, gas, and geothermal energy facilities, including the
information obtained from its sampling efforts (see Part I). This
analysis will not estimate site-specific risks nor will it produce a
rigorous quantitative estimate of national population risks. It will,
however, produce methods, modeling techniques, and a partial data base
that could be adapted for that purpose. The proposed risk analysis also
will produce initial estimates of health risks and potential environmental
damages, identification of low-risk and high-risk scenarios, and rankings
of major risk influencing factors consistent with the purpose of the
Section 8002(m) requirements. This risk assessment will address only
current conditions in the industry; it will not analyze regulatory
alternatives to reduce the baseline risk.
As with any National assessment of risk from waste generating
activities, whether based on specific real facilities or model facility
scenarios, many assumptions will be necessary for this analysis.
Assumptions are necessary for at least three reasons: (1) lack of
important data about waste generating and management practices and
environmental conditions, coupled with the expense of obtaining such data;
(2) significant limitations of available methods for modeling chemical
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release, transport, fate, and effects; and (3) modeling feasibility and
practicality, which are essential considerations to any National risk
analysis with a broad scope. Any assumptions in the analysis will be
explicit, and EPA will document them carefully in written reports.
The remaining chapters in this part describe the proposed risk
assessment methodology. The next chapter gives an overview of the
approach to provide the reader with an overall perspective. Following
that, the input data to be used in the analysis are discussed in Chapter
3, and Chapter 4 describes EPA's planned approach to characterizing oil
and gas and geothermal energy facilities. The development of combinations
of release source types, waste types, and environmental settings (i.e.,
model scenarios) is discussed in Chapter 5. The modeling techniques to be
used in the risk estimation calculations are described in Chapter 6, along
with the areas needing further model development and refinement. Finally,
Chapter 7 summarizes the actual risk calculation, which will follow
finalization of the model scenarios and modeling tools.
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CHAPTER 2
OVERVIEW OF THE RISK ASSESSMENT APPROACH
Potential health and environmental risks associated with waste
management activities depend on the types and quantities of wastes being
managed; the storage, treatment, and disposal technologies being used; and
the environmental settings in which the waste management activities are
carried out. These factors determine the degree to which receptors (human
or environmental) may be exposed to harmful constituents of the waste
through various exposure pathways. Risk is estimated by combining
exposure information with data on the toxicity of specific chemicals and
information on the characteristics of receptor populations.
The following section summarizes the specific risk assessment
methodology to be used in the oil and gas and geothermal energy study.
Following this overview, there is a brief description of alternative risk
assessment methodologies that were considered for the study and rejected.
OVERVIEW OF THE RISK ASSESSMENT METHODOLOGY
EPA proposes to conduct a generic, as opposed to site-specific, risk
assessment of onshore oil and gas and geothermal energy operations. A
schematic overview of the approach is given in Figure IV-1. A key part of
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Figure IV-1
IV-2-2
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Chnractenzo
Waste Slie.im
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Integrato into
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FIGURE IV-I. OVERVIEW OF THE RISK ASSESSMENT METHODOLOGY
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the generic approach is development and specification of model scenarios
(i.e., hypothetical facilities) to cover the range of important risk
influencing variables. Essentially, scenarios are unique combinations of
subcategories of important variables that are specified in sufficient
detail to allow risk estimation. The model scenarios for this analysis
will be derived from actual data on wastes, management practices, and
environmental settings.
Although the model scenarios will not represent individual real sites,
they will represent groups of similar real facilities in the analysis.
Generally, the more one disaggregates an analysis of this type (i.e., the
more variables one considers and the more subcategories they are divided
into), the more precise the results will be. A larger number of variable
subcategories means that each subcategory can better represent a smaller
number of real facilities. However, the data input requirements, modeling
complexity, and analytical requirements also increase substantially with
the level of disaggregation. Therefore, the design of a generic risk
analysis such as this must account for the tradeoffs between analytical
precision requirements and project scope. The proposed generic risk
assessment framework provides an appropriate level of detail and
disaggregation to address the objectives listed in Chapter 1.
As part of the model scenario development, the Agency will attempt to
estimate the frequency of occurrence of each scenario. For example,
suppose that 10 percent of the facilities of interest are in ground-water
category A, 20 percent in category B, and 70 percent in category C. This
would allow the Agency to evaluate the representativeness of the scenarios
and to weight the eventual risk estimation results by frequency.
In parallel with the development of model scenarios, EPA will be
developing, refining, and integrating the analytical tools necessary to
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quantitatively estimate chemical release, transport, exposure, health
risk, and environmental effects. Existing OSW models will be adapted to
the extent possible, especially the Liner Location Risk and Cost Analysis
Model (LLM) (U.S. EPA, 1985a). The LLM is a fully computerized model that
calculates health risks and contaminated ground-water volumes caused by
chemicals released from land disposal facilities. The LLM was developed
primarily for efficient analysis of large numbers of model scenarios (as
opposed to rigorous analysis of site-specific risk) and thus is
well-suited to the proposed approach. It will, however, need significant
supplementation in three areas:
• Estimating chemical releases from underground injection;
• Modeling chemical transport/fate in surface water; and
• Modeling potential environmental effects (other than
contaminated ground-water volumes).
As part of the oil and gas and geothermal energy risk analysis, EPA will
develop technical approaches to these three modeling areas, and then
integrate them into the LLM. Substantial alterations to the LLM surface
impoundment release submodel may also be necessary to make it more
applicable to treatment and disposal pits at oil and gas and geothermal
sites. The Agency plans to use the current ground-water transport, human
exposure/risk, and plume volume submodels of the LLM with limited
adaptation.
In summary, there are two major parts of EPA's methodology leading up
to the actual risk calculation step: scenario development and model
development. Model development will produce the analytical tools
necessary to estimate quantitative risks, while scenario development will
provide the model inputs necessary to do the risk estimation. Of course,
these two components are closely related. Modeling tools are needed only
for significant scenarios, so the waste/source/setting characteristics of
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the industry largely determine the emphasis in the model development
effort. Likewise, the specific equations selected as analytical tools
dictate the variables that must be specified within scenarios. For
instance, a complex ground-water model with substantial input data
requirements would necessitate a much greater level of scenario
specification than a simpler model. Thus, the two key parts of the
approach should be viewed as complementary.
The final step in the methodology is actually analyzing risks of the
scenarios using the modeling tools developed. In particular, the Agency
will estimate incremental chronic human health risks (cancer and
noncancer), that is, those effects due specifically to exposures to the
waste constituents being assessed, exclusive of background exposures, and
also the environmental damages for each realistic scenario. There will be
no attempt to factor background exposures into the risk estimates as part
of this analysis.
ALTERNATIVE METHODOLOGIES CONSIDERED
EPA believes that a generic risk assessment as described in this
section of the report will satisfy the requirements of Section 8002(m)
(1)(C), which directs EPA to analyze the "danger to human health and the
environment from surface runoff or leachate" from oil and gas and geother-
mal exploration, development, and production activities. Section 8002(m)
(1)(C) does not stipulate that quantitative risk estimates be developed,
nor does it require a site-specific assessment. The Agency believes that
the proposed generic methodology, which will incorporate available data on
the industry but will not require extensive new data gathering, can be
used to assess risk on an overall National basis and to identify patterns
of risk relative to a number of important risk influencing factors. In
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addition, this study should provide preliminary quantitative estimates of
individual risks and certain types of environmental damage, which can be
refined with additional data collection.
EPA considered and rejected several other methodologies for this
study. The principal alternatives and the reasons these methodologies are
not being proposed are:
* Detailed exposure and risk analysis of a statistically
representative sample of actual sites. This type of analysis
would probably provide the most reliable results, but it would
be impossible to carry out at this time because of extensive
gaps in the available data. A comprehensive, site-specific risk
analysis of a representative sample of sites would be a very
large project even if all necessary input data were available.
Therefore, this alternative was rejected because sufficient
site-specific input data are not available and would be
extremely time-consuming and expensive to collect.
* Worst-case exposure and risk analysis of a sample of actual
sites. This type of analysis would be similar to that described
above, but many site-specific parameters would be set based on
conservative assumptions. It would still require an extensive,
site-specific data collection effort, and the worst-case
assumptions would blur distinctions that may exist among sites.
Risk estimates tend to converge in these types of studies,
making it more difficult to assess the effects of important
factors such as waste type or hydrogeology on risk.
• Detailed case study of a few sites. This type of analysis would
provide reliable information on five to ten sites, but is too
narrowly focused to meet the needs of Section 8002(m) and
therefore was rejected. Case studies would not give any
information on the range or pattern of risks across the Nation
as a whole.
The Agency believes that the proposed generic approach best meets the
needs of the Section 8002(m) study. It will incorporate available
industry data on wastes, management practices, and environmental settings,
but will not require massive field data collection for specific sites.
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CHAPTER 3
INPUT DATA FOR THE ANALYSIS
This chapter identifies the major data inputs needed for the risk
analysis and the anticipated sources for these data. A comprehensive risk
assessment requires the availability of substantial amounts of data on
wastes, releases, and settings. To illustrate this point, Table IV-1 is a
partial list of data that would be useful for this assessment of oil and
gas and geothermal energy operations. Table IV-1 also identifies
potential sources for many of the key data elements. Acquisition of some
of these data elements is beyond the scope of this project, however, and
EPA plans to make assumptions where necessary to supplement the available
data.
Much of the information necessary for risk assessment is being
collected, at least in the form of raw data, in other parts of the Section
8002(m) study. In particular, EPA is gathering and analyzing relevant
data on the numbers and locations of facilities in the industry, types and
volumes of wastes generated, physical and chemical characteristics of
significant waste streams, and current waste management practices. The
Agency will rely largely on these data in developing model scenarios to
represent the industry. Thus, the risk assessment itself involves little
primary data collection in areas of wastes and release sources. A limited
research effort to characterize the environmental settings of oil and gas
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02032 Risk Assessment
Table IV-1. Oil and Gas and Geothermal Energy Development
and Production Risk Assessment: Potential
Data Needs and Sources
Potential
Data element data source
I. Production site/waste management system
A. General
* 1. Location of sites a
2. Size, shape of sites a
* 3. Description of waste management system components b
* 4. Downgradient distance to site boundary a
5. Surrounding land uses a,d,
6. Operating period a
B. Surface impoundments (pits)
* 1. Number/types of pits a,b
* 2. Size, shape, depth, residence time, annual flow b
3. Subgrade permeability, clogged layer permeability, b,f
and thickness
* 4. Basic design features (e.g., liners/liner b
permeability, leachate collection, leak
detection, cover)
* S. Effluent discharge rate/point b
6. Monitoring plan/data b
7. Closure and post-closure care practices b
C. Underground injection
* 1. Number/types of injection wells a,b
2. Size of well/injection volume b
* 3. Basic design features b
* 4. Discharge depth b
5. Monitoring plan/data b
6. Closure and post-closure care practices b
D. Other potentially significant waste management b
system components (e.g., land application, storage tanks)
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0203Z Risk Assessment
Table IV-1. (continued)
Potential
Data element data source
II. Wastes (drilling muds, brines)
* A. Total volume and volume per well a,b
B. Volume per unit of production a,b
* C. Chemical constituents and their concentrations c
inorganics, including metals
organics
* D. Physical characteristics of the waste stream c
solids (total and suspended)
density
* E. Treatment/disposal sequence and process description b
F. Physical/chemical and toxicity characteristics of e
chemical constituents
partition coefficients
degradation rates
solubility
toxicity parameters (e.g., threshold, potency)
bioaccumulation factors
III. Environmental Setting
A. Hydrogeology e,f
1. Ground-water flow direction
* 2. Ground-water velocity
* 3. Depth to ground water (water table)
4. Hydraulic conductivity
5. Porosity
6. Gradient
7. Fraction organic carbon (foe)
8. Bulk mass density
9. Subsurface stratigraphy (number of layers, depths)
10. Soil type (of each layer)
11. Ground-water quality data
12. Seismicity
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0203Z Risk Assessment
Table IV-l. (continued)
Potential
Data element data source
13. Fractures/faults
14. Hydraulic connections between injection zone
and surface aquifers
15. Ground-water class
16. Other (e.g.. unusual ground-water conditions)
B. Surface water f,g
* 1. Distance/direction to surface water bodies
(from site)
* 2. Type of surface water (perennial stream, river,
lake)
3. Streams
* — Flow rate
Size (width, depth)
Downstream system description (what it
flows into, where)
4. Lakes
* — Size (width, length, depth, volume)
Turnover rate
5. Surface water quality data
6. Use classification
C. Meteorology e,f
1. Precipitation, net infiltration
2. Severe storm frequency
3. Flooding frequency of site
D. Potentially exposed populations
Ground water — human f,h
* 1. Distance to nearest downgradient well(s)
2. Number of downgradient wells within 5 miles
* 3. Site vicinity (USGS) map with well locations
4. Public/private designation
5. Water supply fraction
6. Well depth
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0203Z Risk Assessment
Table IV-l. (continued)
Potential
Data element data source
Surface water — human f,g,h
* l. Distance to nearest intake/each surface water
2. Distance to all downstream public supply intakes
* 3. Use of each intake (e.g., public supply, irrigation)
4. Water supply fraction
5. Other significant point sources nearby
Surface water -- ecological f
1. Ecosystem description
2. Sensitive species/critical habitats
* Key data element for proposed methodology.
a. Current EPA research on sources and volumes of wastes that is being
conducted as part of the Section 8002 study.
b. Current EPA research on waste management practices that is being conducted
as part of the Section 8002(m) study.
c. Current EPA waste stream chemical analysis that is being conducted as part
of the Section 8002(m) study.
d. EPA damage case studies that are being compiled as part of the Section
8002(m) study.
e. LLM data bases (supplemented with additional chemicals, if necessary).
f. Mapping and literature surveys correlating site locations with
environmental variables.
g. USGS (e.g.. REACH files) and EPA (e.g., STORET) surface water data bases.
h. Population and drinking water data bases (e.g., GEMS, FRDS).
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and geothermal energy facilities will be conducted at a level of detail
consistent with the waste and release source data and the modeling
techniques. Some directly applicable environmental information, such as
maps of net infiltration categories and locations of sensitve
environmental settings, has been developed and used in recent projects by
EPA and is readily available.
One other significant source of information useful to the risk
assessment is the compilation and analysis of damages attributable to oil
and gas and geothermal energy facilities. The damage case summary
currently being conducted as part of the Section 8002(m) study will
provide information on the types and severity of damages attributed to
past releases of contaminants from these facilities. It should also
provide some information on the kinds of wastes, chemicals, and management
practices involved, as well as whether the release was intentional (e.g.,
permitted effluent) or a result of technology failure. EPA plans to use
information from the damage case reports to identify important exposure
pathways, especially in the area of environmental (non-health) effects,
and to confirm that its final methodology addresses these significant
pathways. The analysis will not eliminate consideration of potentially
important pathways simply because they are not frequently reported in the
damage cases; one would not expect pathways with hard-to-measure endpoints
(e.g., health effects of chronic exposures, ecosystem-level aquatic
effects) to be reported frequently.
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CHAPTER 4
INDUSTRY CHARACTERIZATION AND CLASSIFICATION
To initiate this risk assessment, EPA will analyze and organize
relevant data on the industry's waste generators, waste stream types,
release sources, and environmental settings. Characterizations will be
based largely on the primary research and analysis being conducted for
this Section 8002(m) study. The Agency will first develop appropriate
categories of waste generators, waste stream types, release sources, and
environmental settings based on these characterizations. The initial
industry characterization and classification is discussed in this
chapter. Then, for each waste generator subcategory, EPA will develop
model scenarios of the waste stream, release source, and environmental
setting to represent current practices in the industry and to serve as the
basis for quantitative risk modeling. The development of model scenarios
is described in Chapter 5 of this part.
WASTE GENERATORS
After organizing and reviewing the data on sources and volumes of
waste (see Part I), EPA will divide the industry into appropriate
categories for risk modeling. For example, waste generators may be
divided into two main categories, oil and gas operations and geothermal
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energy operations. Each main category can be subdivided into production
operations and developmental operations (drilling) and then further
subdivided into active operations and inactive operations. It may also
prove useful to classify generators as large-volume and small-volume
operations, and to estimate the number of generators and the locations of
facilities in each subcategory, based on the data collected in other
parts of the overall study. These steps will produce a list of waste
generator subcategories, with estimates of the numbers and locations of
each.
WASTE STREAM TYPES
EPA will review the chemical analysis data being generated in another
part of the Section 8002(m) study (see Part I) to identify significant
waste stream types for each waste generator subcategory. It will then be
possible to determine waste stream significance based on volume, number of
generators, toxicity, and release potential. The intent will be to
identify all wastes that are major contributors to health and
environmental risk on a national basis, as opposed to all wastes that
could potentially produce high risk in a few situations. The risk
analysis will be based primarily on the waste streams included in EPA's
current sampling and analysis program, in which samples are being
collected from nine oil and gas producing zones of the United States.
The Agency will also estimate, to the extent possible, the
distribution of waste streams across waste generator subcategories,
release sources, and location. EPA will compile a listing of potentially
toxic constituents for each significant waste stream type identified, and
may review published reports to identify "high-risk" constituents that may
be present in industry waste streams but not found in those sampled during
this study.
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For each significant waste stream type identified, it will be possible
to develop at least one representative waste stream for modeling
purposes. If waste characteristics differ subtantially across the nine
sampling zones, multiple representative streams will be developed. For
example, three different representative drilling muds corresponding to
various geographic zones might be modeled. The representative streams
will be defined by physical form and constituent identity and
concentrations based primarily on the EPA sampling data. The analysis
will also review the sampling data to identify waste streams whose
constituents and/or constituent concentrations vary substantially from the
representative streams.
After identification of significant waste streams in the industry, the
next step will be to identify constituents of concern for the
representative streams. Constituents of concern will be selected from the
list of all waste stream constituents based on concentration, toxicity,
persistence, and mobility in the environment. The LLM chemical data base
will be the primary source used to rank toxicity, persistence, and
mobility, and concentration data will be obtained from the EPA sampling
report. Quantitative scoring algorithms will not be used to select
constituents; instead, EPA plans to rank and evaluate the constituents in
a waste stream based on the factors listed above and to make the final
selection based on professional judgment. In general, the Agency expects
to select from two to six constituents per stream for risk modeling
purposes. The Agency may find it necessary to expand the list of
constituents to address potential environmental effects adequately. Based
on the Agency's prior experience modeling hazardous waste streams, most of
the quantifiable risk associated with streams is usually due to one or two
constituents. If those can be identified, it is unnecessary to include
all chemical constituents in the full risk modeling.
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The output of this step will be a limited number of representative
waste streams (no more than ten) and constituents of concern for risk
analysis. Each representative waste stream will be defined in terms of
its physical and chemical characteristics, and its disposal amount and
distribution across waste generator types and locations will be estimated.
WASTE TREATMENT, STORAGE, AND DISPOSAL PRACTICES/RELEASE SOURCES
The next step will be to review the waste treatment, storage, and
disposal technologies employed in the oil and gas and geothermal energy
industry. Significant practices are being identified and assessed in
another part of this study (see Parts I and II). EPA will estimate each
technology's distribution across waste generator subcategories, waste
stream types, and locations. From this information, the Agency will
identify the potentially significant sources and mechanisms of chemical
release to the environment for each waste stream type. These significant
release sources (e.g., surface pits) will eventually be the starting point
for risk modeling. The Agency will also identify low-frequency/low-volume
release sources that appear to have an unduly high potential for release
into the environment.
After reviewing the waste management information, the next step will
be to divide the identified release sources for modeling into appropriate
categories such as underground injection wells and surface pits. Some
release sources may be subdivided by size and/or design characteristics
(e.g., presence of a liner), because these variables can affect the timing
and magnitude of chemical releases and, therefore, the risk. It may also
be necessary to subdivide to represent the range of existing practices in
the industry adequately. For example, centralized treatment and storage
facilities, such as surface pits, are common in the industry and may be
much larger than typical units found at individual sites.
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For each release source category, the Agency will identify potential
mechanisms of release such as effluent discharge to surface water or
seepage into ground water. The result will be a list of subcategories of
release sources along with their potential mechanisms of release. It may
also be possible to estimate the distribution of release sources across
generators, waste stream types, and locations.
ENVIRONMENTAL SETTINGS FOR RELEASE SOURCES
The environmental setting of a release source location is an important
factor that influences risks associated with the release of waste
materials. In general, the analysis will develop values for significant
environmental variables based on this project's research and on a review
of readily available information generated as part of other relevant
projects (e.g., the Subtitle D risk analysis, the cross-program regulatory
analysis, other applications of the LLM, and applications of the RCRA
Risk-Cost Analysis Model).
The first step in characterizing environmental settings will be to
estimate the number and general distribution of facilities within each
major oil and gas and geothermal energy Region. Much of the information
needed to complete this step will come from EPA's research into waste
generators, waste stream types, waste management practices, and damage
cases. If necessary, however, these research results can be supplemented
with additional data available in the literature. For example, the
Independent Petroleum Association of America (1986), the American
Petroleum Institute (1986), the Department of Energy (1985), the Colorado
School of Mines (1983), and the Rand Corporation (1981) provide useful
data on the number and distribution of oil and gas sites. Next, the
analysis will characterize the principal environmental risk variables
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for each of the major Regions as a whole. Facilities within each Region
will then be assigned the distribution of environmental variables for the
respective Regions. Although this approach will not involve a site-
specific analysis of all sites, the Agency believes it is justified
because of the sheer number of sites involved (in 1985, there were
approximately 870,000 onshore oil and gas wells) and because it believes
that a Regional as opposed to a site-specific analysis will yield
reasonably accurate results (available information indicates that most
sites are clustered in certain Regions). EPA will develop a distribution
of values across release source locations such that, for each
environmental variable, it will have at least two values: a typical or
average value and a more conservative value that will yield higher, but
not necessarily worst-case, risk estimates.
Important risk influencing environmental variables are described below
under the categories of climate, hydrogeology, surface water, human
exposure points, and environmental exposure points. Each section
identifies the necessary individual data items required to characterize
environmental settings, and outlines the Agency's approach for obtaining
values for these data.
Climate
Net annual infiltration rate is an important variable that will be
used to characterize climate. Net infiltration affects the rate and
extent of ground-water contamination from some types of release sources,
including landfills and land treatment operations. EPA will develop a
distribution of values for this variable based on an analysis of the
Regions in which most of the oil and gas and geothermal energy facilities
are located.
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As part of OSW's LLM project, four net infiltration regimes (0.25
inch, 1 inch, 10 inches, and 20 inches, respectively) that are
representative of the different conditions found in the U.S. have been
developed from a previous literature review. These net infiltration
regimes have been assigned to different Regions across the U.S. For this
project, EPA plans to develop a distribution of net annual infiltration
rates for oil and gas and geothermal energy sites based on the locations
of the Regions that contain most of the relevant sites. This approach
will be consistent with the method the Agency has used to assign net
annual infiltration rates to hazardous waste facilities as part of other
projects (e.g., the 118 hazardous waste land disposal facilities in the
LLM's real facility data base and the 55 facilities examined as part of
the cross-program regulatory analysis).
Hydrogeology
The primary hydrogeologic variables of interest to this project
include ground-water velocity, depth to ground water, hydraulic
conductivity, and various soil properties used to assess contaminant
retardation (effective porosity, bulk mass density, and fraction of
organic carbon). In addition, information on the occurrence and nature of
any layering within the saturated zone (i.e., stratigraphic data) will be
required if the Agency decides to characterize more complex ground-water
flow systems. All of these variables influence risks by dictating the
potential for contaminants to migrate through ground water to points of
exposure. In past analyses using the LLM, EPA has focused on the upper
layers of ground-water systems; however, oil and gas wastes are often
released into deeper strata using injection wells. Information in the
damage case studies will be used to determine whether significant
exposures to wastes released in the injection zone are common and, if so,
additional hydrogeologic parameters needed to characterize deeper strata
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will be identified. At this time, however, the Agency does not plan to
model transmission of contaminants from deeper strata to upper layers of
ground-water systems because (1) there are no simple models to use, and
(2) acquiring the stratigraphic input data to assess this pathway is
beyond the scope of this project.
EPA will develop a range of values for several of the required
hydrogeologic variables using the National Water Well Association's
"DRASTIC" system (National Water Well Association, 1985). This system
divides the U.S. into hydrogeologic Regions and provides generally
recognized values within each Region for several variables related to
contamination potential. Superimposing these DRASTIC Regions onto the
Regions containing the majority of oil and gas and geothermal energy
activity will yield data on the depth to ground water, aquifer media type,
and unsaturated zone media. Once the media in the aquifers and
unsaturated zones are defined, the Agency will select a range of values
for hydraulic conductivity, effective porosity, and bulk mass density
based on typical values for these parameters reported for different soil
types. For example, Codell and Duguid (1983) provide tables of values for
hydraulic conductivity and effective porosity, and Hough (1957) reports
typical bulk mass density values for a wide range of earth materials.
Eleven ground-water flow field scenarios have been developed to
represent the majority of ground-water flow conditions in the U.S. These
scenarios, which define various combinations of ground-water velocities
(ranging from 1 meter/year to 10,000 meters/year) and aquifer-aquitard
layer sequences within the saturated zone, are used in the LLM to model
ground-water flow. Because the Agency will use the LLM to analyze
ground-water fate and transport (see the discussion in Chapter 6 on
modeling techniques), the values for ground-water velocity and the aquifer
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configurations developed for this project will be confined to those
specified in the 11 flow field scenarios of the LLM.
To determine the appropriate distribution of flow field scenarios for
this project, ground-water velocity data and aquifer configuration
information given in the DRASTIC system for the major oil and gas and
geothermal energy producing Regions will be examined. Combining the
facility location information with hydrogeologic data from DRASTIC (i.e.,
estimating densities of facilities per DRASTIC subregion), will yield a
frequency distribution for the variables of interest. It should be
emphasized that the Agency does not intend to use the DRASTIC scoring
procedures, but only the hydrogeologic data for various subregions. As a
check to this approach and to fill in any data gaps, two additional
methods for assigning flow field scenarios will be pursued. The first
will be to examine flow field scenarios previously assigned to other
facilities located in the various oil and gas and geothermal energy
Regions (e.g., the 55 facilities examined in the cross-program project,
the 118 facilities in the LLM's real facility data base, and the 67 sites
examined to develop the LLM's generic flow field scenarios). The second
will be to examine U.S. Geological Survey (USGS) topographic maps for a
sample of facilities to determine a range of hydraulic gradients which
will be ascertained by assuming the ground water underlying a site has the
same gradient as the land surface slope. These values for hydraulic
gradient will be used to calculate ground-water velocities using Darcy's
Law, an expression that relates ground-water velocity to the hydraulic
gradient, hydraulic conductivity, and effective porosity (a determination
based on predominant soil types as described above).
Surface Water
Surface water data are needed to determine direct impacts to surface
water resources as well as human and ecological exposures through surface
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water intakes. Although the methodology for modeling chemical transport
in and damage to surface waters has not yet been finalized (see Chapter
6), EPA expects that the data needs will include the type (e.g., lake,
river), location, size, flow rate, and patterns of use of nearby surface
waters.
Based on the Agency's current knowledge, the occurrence, nature, and
patterns of use of surface waters surrounding oil and gas and geothermal
energy production facilities are highly varied across the universe of
facilities. Therefore, rather than attempt to rigorously define the
distribution of key surface water variables across all sites, EPA will
simply define for each variable a set of values that are reasonable for
the major oil and gas and geothermal energy Regions. It will then be
possible to combine different values for each variable to form a variety
of surface water scenarios. As a means of illustration, the following is
a listing of surface water variables and a possible set of values for each:
• Distance from facility to nearest surface water body:
<^ 0.5 mile, between 0.5 and 2 miles, and > 2 miles;
• Stream flow rate: 10, 100, and 1,000 ft3/sec; and
• Patterns of use: human consumption only, recreational uses
(e.g., fishing and swimming) only, and combined consumption
and recreational uses.
To derive a reasonable set of values for important surface water
variables, the first step will be to examine State hydrologic unit maps
for those States where the majority of oil and gas and geothermal energy
facilities are located. These maps show the position and size of
principal streams, rivers, and lakes. Distances of facilities from these
surface water bodies can be estimated by superimposing the general
distribution of facilities onto these hydrologic unit maps. Other
information sources are available for determining values for other surface
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water variables. For example, the USGS's National Water Data Exchange,
Master Water Data Index, REACH Files, and Water Data Storage and Retrieval
System all contain values for water body-specific data. Similarly, EPA's
Stream Gage Inventory File and STORE! Flow File contain stream flow rates
for thousands of stream gauging stations throughout the country. Data in
these information systems will be examined only at a level of detail that
will enable EPA to develop a representative distribution of values for the
major oil and gas and geothermal energy Regions.
Human Exposure Points
Potentially exposed populations will be characterized by examining the
distance and direction to human exposure points in the vicinity of a
sample of facilities. The Agency does not plan to estimate rigorously the
number of people potentially exposed at any specific site nor to develop
projections of the total exposed population. EPA also intends to
emphasize exposures through the ingestion of contaminated ground and
surface waters; the Agency may expand the analysis to consider other
exposures including ingesting of contaminated fish and inhalation.
However, air exposures will be considered if waste release and damage case
information indicates that the airborne pathway should be addressed. Once
sufficient exposure point data have been developed for a sample of
facilities, EPA will extrapolate these results to estimate the
distribution of distances to human exposure points across all facilities.
The assumptions and uncertainties associated with this extrapolation will
be fully described in project reports.
To determine the distribution of human exposure points through ground
water, the first step will be to locate a sample of facilities on USGS
topographic maps and to estimate the direction of ground-water flow from
the site by assuming the ground water flows in the direction of the
predominant land surface slope. Next, the area of potential contamination
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will be defined as the area + 45 degrees of the center line of
ground-water flow and out to some specified distance, such as one or two
miles. Finally, EPA will attempt to determine whether drinking water
wells are located within this area of potential contamination. Telephone
interviews with local officials are the most reliable source of well
location information. EPA has used this mapping/telephone interview
approach for estimating exposed populations in several other recent
projects, including development of the LLM data base and the OSW
cross-program regulatory analysis.
Potentially contaminated surface water resources will be defined as
those bodies of water that (1) are located within the potentially
contaminated ground-water area; and/or (2) are known to receive liquid
effluents from an oil and gas or geothermal energy facility. The Agency
plans to identify the surface waters potentially contaminated by
ground-water seepage through the USGS map procedure outlined above, and
may, for a sample of facilities, identify surface waters receiving direct
discharge by conducting telephone interviews with State officials who
oversee National Pollutant Discharge Elimination System (NPDES) permits.
In addition, the Agency plans to estimate the distance to surface water
intakes (if any) for human consumption.
Environmental Exposure Points
The methodology and information requirements for modeling
environmental exposures will be finalized after some initial data
gathering is complete. This section, therefore, describes the general
information requirements for an assessment of environmental damage or
ecological risk.
An ecological risk assessment requires the development and examination
of two general types of data: toxicological hazard data and environmental
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exposure data. Environmental toxicity data reflect the potential for a
constituent to cause an adverse effect under a particular set of
conditions. Adverse effects can include mortality to single species of
organisms; reductions in populations of organisms caused by acute,
chronic, and reproductive effects; and disruption in community and
ecosystem level functions (EPA, 1986c). Common toxicological data used in
assessing environmental risks would include LC50 an^ LDCQ values and
no-effect levels for certain critical species. Environmental exposure
data include the estimated environmental concentration of a contaminant,
as well as the numbers, types, and distribution of organisms exposed to
the environmental concentrations.
In general, the Agency plans to collect toxicity data from a review of
the general literature (e.g., EPA's Ambient Water Quality Criteria
Documents; Curtis et al., 1979; and Stickel, 1974) and from discussions
with relevant scientific and government organizations (e.g., EPA, the
Department of the Interior's Fish and Wildlife Service, and academic
research institutions). In particular within EPA, the Office of Pesticide
Programs' Ecological Effects Branch, the Office of Water Regulations and
Standards, and the Corvallis Environmental Research Laboratory have been
active in examining ecological toxicity data and should prove useful for
this type of information. In addition, EPA has compiled environmental
toxicity data for a variety of contaminants in order to develop the
ecorisk submodel of the RCRA Risk-Cost Analysis Model (EPA, 1984b).
Although most ecological toxicity data have been developed on a
chemical-specific basis in the past, considerable testing has been done in
recent years on intact effluents and wastes. Some of this type of data
exists for wastes associated with oil and gas operations (Gaetz et al.,
1986; EPA, 1984a). The feasibility of using such a waste-based approach
for assessing ecological effects will be examined as a means of
supplementing the chemical-specific approach.
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Data on contaminant concentrations in environmental media will be
calculated based on the modeling approach (for surface and ground waters),
and/or estimated based on available environmental monitoring data from
actual facilities. Rather than attempting to precisely define the
numbers, types, and distribution of potentially exposed organisms, the
analysis will examine the risks to hypothetical exposed organisms of one
or more indicator species. The Agency will select appropriate indicator
species based on such factors as the availability of toxicity data for the
species, the sensitivity of the species to constituents of concern, the
likelihood of exposure of the species to oil and gas and geothermal energy
wastes, and the aesthetic and/or economic importance of the species. For
this type of information, EPA will consult experts and standard reference
materials (e.g.. Lee et al., 1980; EPA, 1972; and Carlander, 1977).
In addition to modeling ecological risks on a chemical-specific basis,
EPA will develop other measures of potential environmental damage such as
proximity of oil and gas and geothermal activities to wetlands, sensitive
areas, or endangered species habitats. The Agency also plans to estimate
damage measures such as volumes of ground water and surface water
contaminated and acres of land damaged.
To analyze potential damage to environmentally sensitive areas, the
analysis will rely on existing maps and delineations of endangered
species' habitats, wetlands, and other areas of interest. For example, in
analyzing ecologically vital ground water as part of the ground-water
classification guidelines, EPA mapped the environmentally sensitive areas
in California and Louisiana, two major oil and gas producing States (EPA,
1986a). Other useful sources of information include 50 CFR Part 17, which
identifies the historical range and critical habitats of threatened and
endangered species, and experts within the U.S. Fish and Wildlife Service
and State Natural Heritage Program Offices. Information on the locations
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of environmentally sensitive areas will be assembled only at a level of
detail that will allow a rough approximation of the type and extent of
potentially affected areas. The Agency will calculate approximate volumes
of ground water and surface water contaminated through the modeling
approach, but will rely primarily on the results of the damage case
studies to estimate acres of land damaged.
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CHAPTER 5
EXPOSURE PATHWAY ANALYSIS AND MODEL SCENARIO DEVELOPMENT
Once the characterization of wastes, release sources, and
environmental settings is complete, the Agency will identify potential
human and environmental exposure pathways (an exposure pathway is a unique
combination of release source, environmental transport medium, exposure
point, and exposure route). Actually, this step is a reassessment of the
preliminary identification of significant pathways that is made early in
the analysis. For example, the Agency has identified as a potentially
important human exposure pathway releases of contaminants to ground water
from surface pits, followed by ingestion via drinking water. EPA has also
made the preliminary determination that pathways involving release to air
will probably be relatively less important. The data collected in the
industry characterization step will, however, be systematically evaluated
to confirm the significance of exposure pathways identified earlier and to
identify ones that may have been overlooked. EPA will develop a complete
matrix of reasonable exposure pathways and will document the rationale
either for including or excluding each from the risk analysis.
Although dozens of potential exposure pathways may be identified, the
Agency emphasizes that it will only include a few in the quantitative
modeling and risk analysis. Each additional pathway included increases
the scope and complexity of the analysis. It is, therefore, important to
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identify and focus on the exposure pathways that are most significant in
terms of risk. EPA will use two different approaches to identify
important pathways. The first will be a review of the compiled
information on waste types, waste management practices, and environmental
settings for oil and gas and geothermal energy facilities in order to
develop hypotheses about possible sources and mechanisms of contaminant
release to environmental media. For each release source/release medium
combination, the Agency will evaluate the possibility of transport to
human or environmental exposure points, as well as the likelihood of
intermedia transfers (e.g., ground water to surface water). The second
approach will be to review the damage case summaries (see Part III). From
these reported cases of damages attributable to oil and gas production
operations, it will be possible to identify the chemicals and exposure
pathways that have resulted in either adverse health or environmental
effects.
After the exposure pathways for quantitative risk analysis are
determined, the next step is to combine the major waste types, release
sources, and environmental settings into realistic model scenarios for
risk modeling. Essentially, this is a reorganization and refinement of
the data collected in the industry characterization (see the discussion in
the preceding chapter). Model scenarios, intended to represent actual
current practices in the industry, will be arranged as a matrix with three
primary dimensions — waste type, source type, and environmental setting
type — with an as yet undetermined number of categories along each
dimension. It may be possible, for example, to reduce the industry data
to 10 composite waste types, 10 categories of release sources, and
20 environmental setting categories, for a theoretical total of 2,000
model scenarios for which risk would be estimated. It is also likely that
the theoretical total in this example could be reduced considerably,
because some combinations may be unrealistic (e.g., specific release
sources may not be applicable to all waste types).
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The final matrix of model scenarios defines what will be modeled in
the subsequent risk analysis. The Agency will estimate a health risk
and/or an environmental effects measure for each realistic cell in the
matrix.
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CHAPTER 6
DEVELOPMENT AND REFINEMENT OF MODELING TECHNIQUES
The LLM will be used as the predominant tool for estimating risks
associated with oil and gas and geothermal energy facilities. In its
current form, the LLM can assess human health risks associated with
ground-water releases from surface impoundments and landfills. Because
there are several other areas of interest in this project (e.g., releases
from injection wells, surface water fate and transport, and environmental
damage), it may be necessary to adapt the LLM and/or use other modeling
techniques to supplement the LLM analyses. This chapter discusses the
proposed general approach for modeling contaminant release mechanisms,
environmental fate and transport, human exposures and health risks, and
environmental damages. For more information about specific submodels of
the LLM, refer to the most recent draft report (EPA, 1985a).
CONTAMINANT RELEASE TO GROUND AND SURFACE WATERS
At this time, EPA plans to examine at least three sources for release
of oil and gas and geothermal energy wastes: underground injection wells,
surface pits, and effluent point sources. Based on a review of the
background information presently available to EPA, these disposal
practices appear to constitute the principal release sources of concern.
For this project, the Agency plans to model all releases deterministically;
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stochastic failure and release models will not be developed or used. EPA
anticipates developing several release profiles to represent the major
mechanisms of failure, including low-probability, high-quantity failures,
as determined by a literature review and engineering analysis.
Underground Injection Wells
In examining releases from injection wells, the scope of the analysis
will be limited to releases to upper aquifers through failure of the
injection well. At present, EPA does not intend to model risks from the
emplacement of wastes in an injection zone, primarily because the Agency
suspects that the health and environmental hazards are small if the wastes
are confined to deeper formations. For example, the RCRA Risk-Cost
Analysis Model only considers releases from injection wells that lead to
the contamination of upper aquifers. However, EPA will examine its damage
case studies to determine whether releases into the injection zone result
in significant exposures and whether such releases should also be taken
into account in this analysis.
In general, two main types of injection well failures that can result
in releases to upper ground-water systems will be examined: well-head/
piping failures and casing/grout seal failures. Well-head/piping failures
involve the failure of a pump seal or a rupture of a pipe such that wastes
are discharged directly to the ground surface. Although most of the
wastes released in this way will be cleaned up, some fraction may be
directed to surface water or seep into the ground. Casing/grout seal
failures involve a deterioration of the well casing or seals, creating a
hydraulic connection between the injectant and an aquifer. For this type
of failure, a significant portion of the injected wastes may escape into
an aquifer.
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The Agency will model release volumes and estimate the frequency of
occurrence associated with each of these release types. A probabilistic
approach involving simulation modeling will not be attempted; instead, the
Agency will develop "typical" injection well release scenarios based on
case histories involving injection well failures. For example, it will be
possible to estimate how many well-head/piping failures a typical
injection well experiences over its operating life, what volume is usually
released per failure, and what portion of the released volume is not
cleaned up. It will then be possible to estimate the fraction of
injection wells that result in releases as defined by this typical
scenario. Such an approach is used to estimate releases from hazardous
waste injection wells in OSW's RCRA Risk-Cost Analysis Model, based on
data gathered through consultation with experienced engineers and
injection well operators. EPA will explore the possibility of using the
injection well release scenarios developed for that model in this project.
Surface Pits
For modeling chemical release from a surface pit, the Agency plans to
adapt the unlined surface impoundment failure release submodel from the
LLM. The LLM models release (1) during the active operating period, when
the impoundment contains liquid and contaminant releases are driven by
that liquid; and (2) during the period following closure, when the
impoundment has been drained and covered and contaminant releases are
driven by net infiltration. The model may need to be modified for
drilling mud reserve pits because of the potential for clogging and
sealing. Available information collected for this project indicates that
the clay content of oil and gas wastes may in some cases reduce leachate
release rates by lowering the permeability of drilling fluid pits. EPA
plans to examine its waste stream and release source data (see Parts I and
II) and other literature sources as needed to quantify this phenomenon; if
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necessary, the permeability or other assumptions will be adjusted so that
the LLM submodel will be more similar to drilling mud surface pits at oil
and gas and geothermal energy sites. EPA also plans to investigate other
potentially applicable models, such as the Post Closure Liability Trust
Fund Model (EPA, 1985b); Hydrologic Simulation on Solid Waste Disposal
Sites (Perrier and Anthony, 1980); and a new release rate model being
developed by OSW's Land Disposal Branch.
Effluent Point Sources
As discussed in Chapter 4, the risk analysis will identify significant
waste streams for several waste generator subcategories. Based on the
available waste stream data, it will be possible to develop typical source
terms characterizing constituent concentrations and release rates for
effluent point sources. EPA will thus assign source terms for effluent
inputs to surface water based on the data review rather than through a
predictive modeling approach.
CONTAMINANT TRANSPORT AND FATE
For this risk analysis, the Agency anticipates modeling chemical
transport in two environmental media, ground water and surface water.
Ground Water
EPA will use the LLM's subsurface transport submodel to determine the
transport and fate of contaminants of concern in ground water. That
submodel predicts mass transport of contaminants through the unsaturated
zone—the soil layer above the water table in which the pore spaces are
only partially filled with water—and the saturated zone.
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The LLM calculates the travel time for a released contaminant to pass
through the unsaturated zone and reach an underlying aquifer using the
modified McWhorter-Nelson wetting front model. The travel time is related
to the difference in water content between the layer immediately above and
below the front, the distance traveled in the unsaturated zone, the
leakage rate, and the retardation of contaminant movement by soil
adsorption. Unsaturated zone thickness, leachate discharge rate, and a
chemical's retardation factor have the most effect on travel time. Key
assumptions in the unsaturated zone transport component of the submodel
are that no contaminant interactions occur and that one-dimensional
(vertical, downward) modeling of the transport in the unsaturated zone is
valid. EPA will address how these assumptions affect the final risk
estimates.
The Agency will assess the transport of contaminants in the saturated
zone and predict contaminant concentrations over time at distances
downgradient of the release sources using the saturated zone component of
the subsurface transport submodel. As discussed previously,
concentrations of contaminants in ground water can be estimated for
11 generic flow fields.
The LLM estimates concentrations in the 11 generic flow fields with a
modified version of the Random-Walk Solute Transport Model (Prickett,
Naymik, and Lonnquist, 1981). Dissolved chemicals are treated as
particles that move in two stages. First, each particle moves in the
direction of ground-water flow, and then each particle disperses randomly
based on values of exogenous dispersion coefficients. In the LLM, the
basic random-walk model output is adjusted for several factors not
rigorously modeled, including source strength, duration, and width;
degradation; retardation; transverse dispersion; and dilution caused by
pumping.
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The LLM calculates a separate time profile of contaminant
concentrations at the exposure point for each year of contaminant input to
the saturated zone, and then sums these profiles to produce the overall
time profile of concentration (i.e., breakthrough curve). As for the
unsaturated zone model, key assumptions in the saturated zone component
will be outlined and their effects on the final risk estimates will be
evaluated.
Surface Water
The LLM currently models releases of contaminants to surface water via
ground water, but it does not model the fate and transport of contaminants
once they enter the surface water body. The Agency will therefore modify
the LLM to incorporate a simple surface water model for this project. The
Agency also intends to modify the LLM to consider direct releases to
surface water.
The environmental fate of contaminants entering surface water bodies
is dependent on the type of water body involved. In general, there are
three predominant classifications of surface water bodies: rivers and
streams, lakes and other impoundments, and estuaries. Based on the known
distribution of oil and gas and geothermal energy sites, all three
classifications may be important in assessing waste releases for this
project.
For rivers and streams, the initial concentration of a constituent in
the water is simply the mass loading (from either ground-water seepage or
direct discharge) divided by the streamflow. To determine constituent
concentrations downstream, the analysis will use a one-dimensional,
steady-state model similar to the one proposed for use in the land
disposal restrictions program:
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Cx = C0
where
Cx = Concentration at downstream distance x (mg/1)
CQ = Concentration in stream after initial dilution
(mg/1)
K = Decay rate constant for surface water (sec"1)
U = Mean stream velocity (m/sec)
x = Distance downstream (m).
The input data for such a model will be developed through an examination
of existing data compilations and summaries available within EPA and from
the USGS. There are several other simple river and stream models being
evaluated for use in this project (e.g., equations available in Delos et
al., 1984; Fisher et al., 1979; Liu, 1977; and Neely, 1982). While such
models may have to be adapted for- this analysis to consider oily wastes
that do not mix completely with water, the Agency favors a simple surface
water model for this analysis because such models provide useful
predictions of contaminant concentrations without the substantial data
inputs and resources needed to run more complex models (e.g., EPA's
Exposure Analysis Modeling System).
There is great diversity in impoundment and estuary types, as well as
a wide range of complexity in methods for predicting contaminant fates in
these types of surface water bodies. Mills et al. (1982) identify and
describe several estimation methods useful in impoundment and estuary
assessment. EPA is currently in the process of evaluating these and other
models for impoundments and estuaries.
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EXPOSURE AND HEALTH RISKS
The LLM will be used to predict the human health risks from chronic
exposure to contaminated ground water via drinking water. The LLM is
capable of assessing both cancer and noncancer health risks.
Cancer Risks
Cancer risks will be estimated by using a linear (at low doses),
non-threshold dose-response equation. The LLM uses the one-hit equation,
which calculates the lifetime individual risk as an exponential (but
linear at low doses) function of potency and lifetime average dose. Dose
will have been determined from the release and transport submodels
described in previous chapters. Potency is chemical specific and will be
set equal to the the upper-bound unit risk parameter estimated by EPA's
Carcinogen Assessment Group.
Chronic Noncancer Health Risks
Chronic noncancer health risks will be estimated with a dose-response
model that calculates risk from noncarcinogens as a continuous function of
dose at dose levels above a threshold. For this purpose, the LLM uses the
Weibull equation with a threshold. The lifetime individual risk is an
exponential function of several parameters, including the Weibull
dose-response parameter, the lifetime average dose, and the threshold.
Individual risk is considered to be zero below the threshold.
ENVIRONMENTAL DAMAGE
To assess the environmental damages caused by oil and gas and
geothermal energy wastes, the Agency will examine potential adverse
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effects on ground water, surface water, land, and ecosystems. Because EPA
believes that potential environmental damages are an extremely significant
aspect of this study, and because some of these damages are not amenable
to the chemical-based predictive modeling procedures to be used for health
risk assessment, several assessment approaches will be employed for
estimating environmental effects. EPA definitely plans to conduct a
chemical-based analysis of model scenarios for some environmental damage
endpoints. Specific endpoints to be assessed in this way include
contaminated volumes of ground water and surface water, and exceeded
aquatic ecosystem thresholds for individual chemicals. This model
scenario approach will parallel the health risk analysis, and many of the
necessary modeling components (e.g., chemical release and transport) will
be identical. Thus, estimates will be available for both health risk and
environmental damage for some of the model scenarios developed.
A second approach will be to use current information from damage cases
to extrapolate observed environmental effects to the universe of oil and
gas and geothermal energy sites. EPA will attempt to derive point
estimates or distributions of relevant endpoints, such as contaminated
acreage or crop damage, per well or per some other index of production.
As a third approach, EPA intends to correlate locations of oil and gas and
geothermal energy operations with locations of significant environmental
variables, such as wetlands or critical habitats. EPA has used this
approach in the Section 8002 mining waste study. These three approaches
to analyze environmental damage are briefly described below.
Damage to ground and surface waters can be assessed by determining the
volumes of water contaminated above certain thresholds such that the water
is rendered unfit for human consumption, unfit to support aquatic life, or
otherwise significantly less useful than before becoming contaminated. To
assess the volumes of contaminated ground water from specific model
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scenarios, EPA will use the LLM, which is capable of estimating
contaminant plume widths and volumes. Using the modified LLM, along with
surface water damage thresholds for specific chemicals, the Agency will
also estimate the volumes of surface water contaminated.
Estimating adverse effects to land must be carried out through methods
other than chemical-specific modeling using the LLM. Documented cases
involving damages to significant areas of land primarily involve releases
of brines (i.e., chlorides). In several States, damage cases suggest that
thousands of acres have been damaged or rendered useless from brine
releases originating from oil and gas well sites. In one Region, for
example, the average acreage lost as a result of oil and gas production
activities has been reported as approximately 0.8 acre per brine pit. EPA
intends to develop a distribution of factors, such as the one just
presented, that relates the number of acres damaged per unit of waste
release or waste management activity. Because most land damage cases
involve and most information appears to be available for releases of
brines, hazards to land will be assessed mainly by focusing on brines. In
addition, EPA will have to define exactly what it means by "damaged"; it
plans to develop a range of adverse effects to land to reflect different
levels of damage.
Two complementary approaches to assessing ecosystem damages (a subset
of overall environmental damages) are under consideration. The first
would be a guantitative assessment of ecological risks for a set of model
scenarios. As in health risk assessment, an ecological risk assessment is
generally made up of four general components: hazard identification,
dose-response assessment, exposure assessment, and risk characterization.
The primary difference is that ecological risk assessments focus on
aguatic and terrestrial indicator species rather than on humans.
Barnthouse et al. (1982a and b) describe five methods for environmental
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risk analysis; the Ecological Effects Branch of EPA's Office of Pesticide
Programs also has documented its approach to ecological risk assessment
(EPA, 1986c). In addition, EPA's Office of Solid Waste has recently
applied an ecorisk scoring system for hazardous wastes (EPA, 1986b), and
EPA's Integrated Environmental Management Division (IEMD) has applied an
ecological effects assessment procedure for specific chemicals. These
methods are under consideration for use in this project.
As an alternative approach to examining ecosystem damages, EPA will
investigate the proximity of endangered species habitats, wetlands, and
possibly other sensitive environmental areas to oil and gas and geothermal
energy facilities. The Agency will determine the proximity of sensitive
areas by mapping the general distribution of wetlands and endangered
species habitats relative to the major oil and gas and geothermal energy
regions. This analysis, combined with results concerning the volumes of
water contaminated and acres of land damaged, will form the basis for
qualitative conclusions about the hazards to these sensitive environments.
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CHAPTER 7
ANALYSIS OF SCENARIOS
In this final major step of the risk analysis, EPA will apply the
modeling tools developed to estimate health risks and potential
environmental damages for the complete set of reasonable model scenarios.
This step will produce the quantitative risk modeling results of the
Agency's analysis, and will form the basis for its conclusions about
potential health risks and environmental effects. EPA will probably use
an integrated computer model, adapted from the LLM, to do the necessary
calculations for the large number of model scenarios.
The outputs of this step will be a quantitative measure of health risk
and/or environmental effects for each realistic scenario in the
waste/source/environmental setting matrix and, if possible on the basis of
available data, an estimate of the distribution of actual facilities
across scenarios. This type of result would provide information on both
the frequency and intensity of potential adverse effects from oil and gas
and geothermal energy facilities. The Agency will then be able to rank
scenarios on the basis of the risk and identify extremely high-risk and
low-risk combinations. It may be possible to construct relative risk
rankings of individual factors, such as waste type or source type.
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EPA does not plan on presenting precise point estimates of absolute
risk using the generic methodology described in this chapter. Instead, it
plans to present the results as both weighted (by frequency) and
unweighted frequency distributions of individual health risk (or
environmental damage) across various combinations of model scenarios. For
example, a risk distribution across all scenarios might be developed
first; the data might then be disaggregated into numerous distributions
across subsets of scenarios (i.e., if there were ten waste stream
categories, the analysis would develop and compare the risk distributions
for .each). Figure IV-2 illustrates the type of frequency distribution
that will result from the risk analysis.
Clearly, many assumptions will be necessary to carry out the
quantitative analysis of risks. EPA plans on testing the potential
effects of major assumptions through a sensitivity analysis, varying the
values assigned to key parameters over their reasonable range, and
determining the effects on the risk measures used.
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H
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12 -r
10 -
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4 -
2 -
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0.25 inch
1 inch
10 inches
20 inches
-10
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IIGUUE IV-2. CONTRIBUTION OF INFILTRATION TO WEIGHTED AVERAGE BASELINE RISK
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REFERENCES
American Petroleum Institute, 1986, Basic Petroleum Data Book, Petroleum
Industry Statistics, Volume VI, Number 3, Washington, DC.
Barnthouse, L.W., et al., 1982a, Methodology for Environmental Risk
Analysis, ORNL/TM 8167. Oak Ridge National Laboratory, Oak Ridge, TN.
Barnthouse, L.W., et al., 1982b, Preliminary Environmental Risk Analysis
for Indirect Coal Liquefaction. Draft Report. Oak Ridge National
Laboratory, Oak Ridge, TN.
Carlander, K.D., 1977, Handbook of Freshwater Fishery Biology, Volume 2, Iowa
State University, Ames, IA.
Codell, R.D. and J.D. Duguid, 1983, Transport of Radionuclides in Groundwater,
Chapter 4 in Radionuclide Assessment: A Textbook on Environmental Dose
Analysis, U.S. Nuclear Regulatory Commission, Washington, DC.
Colorado School of Mines, 1983, Potential Supply of Natural Gas in the United
States as of December 31, 1982, Potential Gas Committee, Potential Gas
Agency, Golden, CO.
Curtis, M.W. et al., 1979, Acute Toxicity of 12 Industrial Chemicals to Fresh-
water and Saltwater Organisms, Water Research 13: 137-141.
Delos, C.G., et al., 1984, Technical Guidance Manual for Performing Wasteload
Allocations, Book II: Streams and Rivers, EPA, Office of Water
Regulations and Standards, Washington, DC.
DOE, 1983, Oil and Gas Field Code Master List, 1985, DOE/EIA-0370(85),
Washington, DC.
EPA, 1986a, Analysis of the Definition of Ecologically-Vital Ground Water
Under the Proposed Ground-Water Classification Guidelines, Office of
Ground-Water Protection and Office of Policy Analysis.
IV-Ref-1
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EPA, 1986b, Assessment of Impacts of Land Disposal Restrictions on Ocean
Disposal of Solvents, Dioxins, and California-List Wastes, Office of Solid
Waste, Washington, DC.
EPA, 1986c, Hazard Evaluation Division Standard Evaluation Procedure:
Ecological Risk Assessment, EPA-540/9-85-001, Office of Pesticide
Programs, Washington, DC.
EPA, 1985a, Liner Location Risk and Cost Analysis Model, Draft Report, Office
of Solid Waste, Washington, DC.
EPA, 1985b, Post Closure Liability Trust Fund Model, Office of Solid Waste,
Washington, DC.
EPA, 1984a, A Survey of the Toxicity and Chemical Composition of Used Drilling
Muds, EPA-600/3-84-071, EPA Research Laboratory, Gulf Breeze, FL.
EPA, 1984b, The RCRA Risk-Cost Analysis Model, Phase III Report, Office of
Solid Waste, Washington, DC.
EPA, 1972, Biota of Freshwater Ecosystems, Water Pollution Control Research
Series, 18050 ELD 05/72, Manual No. 1-10.
Fisher, H.B., et al., 1979, Mixing in Inland and Coastal Waters, Academic
Press, Mew York, NY.
Gaetz, C.T., R. Montgomery, and T.W. Duke, 1986, Toxicity of Used Drilling
Fluids to Mysids (Mysidopsis bahia), Environmental Toxicology and
Chemistry, 5: 813-821.
Hough, B.K., 1957, Basic Soils Engineering, The Ronald Press Company.
Independent Petroleum Association of America, 1986, The Oil and Gas Producing
Industry in Your State, 1986-1987, Petroleum Independent, Washington, DC.
McWhorter, D.B. and J.D. Nelson, 1979. Unsaturated Flow Beneath Tailings
Impoundments. Jour. Geotech. Eng. Div. ASCE GT 11: 1317-1334.
Lee et al., 1980, Atlas of North American Freshwater Fishes.
Liu, H., 1977, Predicting Dispersion Coefficients of Streams, J. Environmental
Engineering Division, Proceedings of the American Society of Civil
Engineers, Vol. 103.
Mills et al., 1982, Water Quality Assessment: A Screening Procedure for Toxic
and Conventional Pollutants, Part 1, EPA Office of Research and
Development, Athens, GA.
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National Water Well Association, 1985, DRASTIC: A Standardized System for
Evaluating Ground-Water Pollution Potential Using Hydrogeologic Settings,
PB85-228146, Worthington, OH.
Neely, W.B., 1982, The Definition and Use of Mixing Zones, Environ. Sci.
Technol. 16(9): 520A-521A.
Perrier, E.R. and G. Anthony, 1980, Hydrologic Simulation on Solid Waste
Disposal Sites (HSSWDS), U.S. Army Engineer Watimag Experiment Station,
Contract No. EPA-IAG-D7-0101197.
Prickett, T.A., T.C. Naymik, and C.G. Lonnquist, 1981. A "Random-Walk" Solute
Transport Model for Selected Groundwater Quality Evaluations. Bulletin
#65, Illinois State Water Survey.
Rand, 1981, The Discovery of Significant Oil and Gas Fields in the United
States, R-2654/l-USGS/DOE, Santa Monica, CA.
Stickel, W.H., 1984, Some Effects Of Pollutants in Terrestrial Ecosystems,
Proceedings of the NATO Science Committee Conference of Ecotoxicology,
MontGabriel, Quebec, Canada, May 6-10.
IV-Ref-3
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Appendix A
SUMMARY OF STATE AND FEDERAL REGULATIONS
RELATED TO
ONSHORE OIL AND GAS EXPLORATION, DEVELOPMENT, AND PRODUCTION
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SUMMARY OF STATE AND FEDERAL REGULATIONS
RELATED TO
ONSHORE OIL AND GAS EXPLORATION, DEVELOPMENT, AND PRODUCTION
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NOTICE
THE INFORMATION CONTAINED IN THIS APPENDIX HAS NOT YET BEEN
VERIFIED BY STATE AGENCIES. WE INVITE THE COMMENTS OF STATE
AGENCIES ON THESE SUMMARIES. SUGGESTIONS AND COMMENTS WILL BE
INCLUDED IN THE REPORT TO CONGRESS. PLEASE SUBMIT COMMENTS TO:
Susan L. de Nagy
Industrial Technology Division
U.S. Environmental Protection Agency
401 M Street, S.W.
Washington, DC 20460
A-ii
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TABLE OF CONTENTS
SUMMARY OF STATE REGULATIONS A-l
ALABAMA A-2
ALASKA A-5
ARIZONA A-9
ARKANSAS A-12
CALIFORNIA A-16
COLORADO A-21
FLORIDA A-26
ILLINOIS A-29
INDIANA A-32
KANSAS A-35
KENTUCKY A-39
LOUISIANA ' A-42
MARYLAND A-46
MICHIGAN A-49
MISSISSIPPI A-54
MISSOURI A-58
MONTANA A-61
NEBRASKA A-64
NEVADA A-67
NEW MEXICO A-70
NEW YORK A-75
NORTH DAKOTA A-80
OHIO A-83
OKLAHOMA A-87
OREGON A-91
PENNSYLVANIA A-95
SOUTH DAKOTA A-99
TENNESSEE A-102
TEXAS A-105
UTAH A-110
VIRGINIA A-114
WEST VIRGINIA A-117
WYOMING A-120
SUMMARY OF FEDERAL REGULATIONS A-125
U.S. FOREST SERVICE A-126
BUREAU OF LAND MANAGEMENT A-l27
U.S. ENVIRONMENTAL PROTECTION AGENCY, EFFLUENT
LIMITATIONS GUIDELINES A-131
UNDERGROUND INJECTION CONTROL A-134
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SUMMARY OF STATE REGULATIONS
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ALABAMA
INTRODUCTION
Alabama produced 8,438,000
barrels of oil and gas from 760
oil wells and 130 x 109 cubic
feet of gas from 509 conven-
tional gas wells and 184
coalbed methane wells in 1984.
Thirteen percent of conven-
tional oil and gas wells are
strippers; 52 percent of
coalbed methane wells are
strippers.
Alabama began limited
regulation of oil and gas
activities in 1946.
Regulations for disposal of drilling wastes were adopted in 1973.
Regulations and/or administrative codes have continued to be
revised during the forty years of regulation.
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activity in Alabama:
- Alabama State Oil and Gas Board
- Alabama Department of Environmental Management
- U.S. Bureau of Land Management
- U.S. Corps of Engineers
The Alabama State Oil and Gas Board is "charged with preventing
the waste of Alabama's oil and gas resources and protecting the
correlative rights of owners." In carrying out its mandate, the
Board issues drilling permits for oil and gas operations through
the production phase. The Oil and Gas Board has authority to
issue permits for UIC Class II wells. The Oil and Gas Board
Administrative Code details statewide rules applicable to all
categories. The Administrative Code is supported by Oil and Gas
Laws of Alabama (1975).
The Alabama Department of Environmental Management has the
authority to issue permits for all UIC wells other than Class II.
The Department of Environmental Management also has NPDES
authority. The Oil and Gas Board and Department of Environmental
Management operate under a 1979 Memorandum of Agreement which
requires the Board to forward information regarding actual or
proposed discharges to the Department of Environmental
Management.
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The U.S. Bureau of Land Management, authority and regulations for
Federally-held mineral rights are discussed separately under
Federal Agencies. The U.S. Forest Service retains surface rights
(and usually coordinates stipulations with the Bureau of Land
Management) in Federal forests and grasslands.
STATE RULES AND REGULATIONS
DRILLING
Drilling pits are permitted by the Oil and Gas Board. The Board
has certain construction requirements to ensure the integrity of
the pit. Pits are closed by dewatering (see below), then
backfilling, leveling, and compacting.
Drilling muds and pit fluids may be disposed in one of three
ways. They may be injected into a formation below underground
sources of drinking water. They may be transported to a drilling
mud treatment (recycling) facility. In non-wetland areas, the
fluids may be applied to the land surface or into an approved
landfill if:
- The chloride concentration is less than 500 mg/L
- The Oil and Gas Board is properly notified
- The landowner provides written approval
- It is a one-time-only application
- There will be no discharge to surface body of water
These activities are permitted by the Oil and Gas Board prior to
allowing disposal of fluids.
PRODUCTION
No discharge of produced water (brine) is allowed. Class II UIC
wells are used for disposal of Alabama brines.
After conferring with EPA, EPA-Region IV has advised Alabama
authorities that coalbed methane production is not covered under
the Federal onshore oil and gas regulations. Produced waters
from coalbed methane wells may be allowed to accumulate in lined
pits, settle, and then may be discharged directly into live
streams.
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REFERENCES
State Oil and Gas Board of Alabama, Submittal to EPA
Regarding Onshore Oil and Gas Subcategory, March 1985.
State Oil and Gas Board of Alabama Administrative Code,
general order prescribing rules and regulations
governing the conservation of oil and gas in Alabama
and oil and gas laws of Alabama with Oil and Gas' Board
forms, Oil and Gas Report 1, 1983.
Alabama Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas Workshop, U.S. EPA,Washington,D.C.(March
26-27 in Atlanta, GA) .
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ALASKA
INTRODUCTION
Alaska produced 617,606,000
barrels of oil and 300 x 109
cubic feet of gas in 1984.
Production is from 864 oil
wells and 81 gas wells. Alaska
is second in U.S. oil
production but twenty-third in
the number of producing oil
wells. It ranks eighth in U.S.
gas production and twenty-
fourth in the number of
producing gas wells.
Alaska has two main oil and gas development areas: the South
Central area and the North Slope area. The South Central area
includes Cook Inlet and the Kenai Peninsula. There are 13 oil
platforms and one gas platform in Cook Inlet. These wells are
considered to be in the Coastal Subcategory.
The Kenai Peninsula produces mostly gas with little associated
brine. Brines are primarily reinjected. Drilling muds present a
larger problem in the Kenai Peninsula. Three to four hundred
wells, mostly onshore, have been drilled. Most of the reserve
pits have been unregulated.
The North Slope sends about 1.5 million barrels of oil down the
pipeline per day from three producing units (Kuparuk, Prudhoe,
and Milne Point). There is a lot of exploration occurring on the
North Slope and the exploration is moving east toward the
Canadian border.
STATE REGULATORY AGENCIES
Five agencies regulate oil and gas activities in Alaska:
Alaska Oil and Gas Conservation Commission
Alaska Department of Environmental Conservation
U.S. Bureau of Land Management
- U.S. Fish and Wildlife Service
Alaska Department of Natural Resources
The Oil and Conservation Commission permits wells regarding
conservation of resources. It checks well casings to prevent
contamination of water and the Commission has primacy for the UIC
Class II program. Section 31.05.009 of Title 31 of Alaska
Statutes established membership of the Oil and Gas Conservation
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Commission to three members appointed by the Governor. There is
a compliance bond of $100,000 for an individual well or $200,000
for a blanket bond.
The Alaska Department of Environmental Conservation regulates
waste disposal and issues permits regarding waste disposal.
The U.S. Bureau of Land Management is responsible for all oil and
gas activity on Federal lands. There are 370 million acres of
land in Alaska, of which 250 to 200 million are Federal acres.
There are 150 producing oil and gas wells on Federal leases. The
BLM works closely with the Alaska Department of Environmental
Conservation to regulate these wells. Regulatory processes for
oil and gas operations are covered in Onshore Oil and Gas Order
No. 1 and Regulation 43 CFR 3160.
The U.S. Fish and Wildlife Service has been conducting research
related to the permitted discharge of drilling and production
fluids to the tundra wetlands. The research project currently in
progress is designed to determine the deleterious nature of the
discharge to wildlife in wetlands, especially the waterfowl.
The Department of Natural Resources distributes leases for wells
on State land. Stipulations are made to environmental concerns,
such as requiring that reserve pits be rendered impermeable or
denying the discharge of produced waters to the tundra, at lease
award.
STATE RULES AND REGULATIONS
DRILLING
Existing drilling pits and reserve pits are not lined. Many are
located in wetlands. The Department of Environmental Conser-
vation is moving toward reducing pit sizes, subgrading pits to
enhance freezeback, injecting liquids, and capping pits to
prevent ponding. Currently, everything is put in reserve pits
including materials from mouse holes, rat holes, sewage, and
other wastes. Waste segregation and separate waste treatment
with fluid injection is a Department goal.
With pit closure, pits must be dewatered, stabilized to hold the
cover, and covered. Fluids often are reinjected down an annulus
in a nearby exploratory well.
PRODUCTION
Production fluids have been injected, used on roads, or
discharged to the tundra. The department is moving toward
reinjecting the fluids, and the use on roads is being considered
carefully because of potential pollution problems.
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There are two general wastewater disposal permits issued under
Alaska Statute 46.03 of the Alaska Administrative Code. These
discharges are considered minor discharges by the U.S. Environ-
mental Protection Agency and thus do not require an NPDES permit.
The permits are for discharges from onshore reserve pits used for
storage of produced water, drilling fluids and cuttings, boiler
blowdown, rig washing fluids, and completion fluids.
In 1985, 36 million gallons were discharged from 43 r'eserve pits.
Of the 43 pits, 35 violated permit limits; of the 35, 16 were in
violation of the manganese limit only. Manganese was deleted
from the 1986 permit because of high levels found naturally in
the North Slope. Discharge is to the tundra.
The permit discharge limits are:
pH 6.5 to 8.5
Chemical oxygen demand 200 mg/1
Settleable solids 0.2 mg/1
Oil and grease 15 mg/1
Total aromatic hydrocarbons 10 /ug/1
Arsenic 0.05 mg/1
Barium 1.0 mg/1
Cadmium 0.01 mg/1
Chromium 0.05 mg/1
Lead 0.05 mg/1
Mercury 0.002 mg/1
The environmental effects of large-scale reserve pit fluids
disposal to the tundra are unknown. Annually, 31 million gallons
of the fluids, which originate from drill muds, workover fluids,
snow melt, and other sources, must be disposed of from the pits.
Alternatives to tundra disposal include dedicated disposal wells
on the North Slope. Trucking is usually needed to get the muds
to one of the dedicated disposal wells. To avoid trucking
associated with injecting down one of the dedicated wells, it is
often possible to inject down the annulus of the well being
drilled or another well on the pad. The annulus of these wells
usually terminates at the bottom of the permafrost layer, about
2,000 feet below the ground surface. These are short-term
options, as the annulus must soon be cemented closed to preserve
the integrity of the permafrost and prevent collapse of the
well. Once cemented closed, it cannot be reopened.
OFFSITE AND COMMERCIAL PITS
Hauling from two or three well sites to another pad has been
allowed to concentrate wastes at one site.
Presently, there are no offsite and commercial pits. There was
one commercial pit, but it was closed because of pollution
problems; the case is in litigation.
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REFERENCES
Alaska Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas State/Federal Western Workshop. U.S.
Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Regulations, Alaska Administrative Code, Title 20, Alaska
Oil and Gas Conservation Commission, April 2, 1986.
Alaska Statutes, Title 31, Chapter 05, Alaska Oil and Gas
Conservation Act.
Fristoe, Bradley R. 1985. Letter Communication to EPA.
State of Alaska Department of Environmental
Conservation.
Personal Communications:
Dan Wilkerson, Alaska Department of Environmental
Conservation (907) 274-2533.
Doug Redburn, Chief of Water Quality Management Section,
Juneau (907) 465-2666.
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ARIZONA
INTRODUCTION
Arizona produced 214,000
barrels of oil and 225 MMCF of
gas in 1984. Production was
from 26 oil wells and 5 gas
wells. All brines are
reinjected and all drilling
fluids ^go to reserve pits.
Approximately 655 bbls/day of
brines are produced in the
State per day. Arizona does
not have NPDES or UIC program
primacy.
REGULATORY AGENCIES
There are five agencies that regulate the oil and gas industry in
Arizona:
U.S. Bureau of Land Management
- U.S. Bureau of Indian Affairs
Arizona Oil and Gas Commission
Arizona Department of Health and Safety
EPA, Region IX
The Bureau of Land Management has the authority to issue oil and
gas drilling permits for Federal minerals. Where Indian mineral
rights prevail, oil and gas activity may be governed by both the
BLM and the Bureau of Indian Affairs.
The Arizona Oil and Gas Commission reviews all oil and gas
drilling applications and is primarily responsible for approving
and enforcing oil and gas activities. The Oil and Gas
Commission's regulations pertain to the construction, location,
and operation of onsite drilling and production activities.
The Department of Health and Safety Coordinates with EPA's Region
IX for any surface water discharge or underground injection
permit. Region IX administers the UIC program; there are no
discharges from oil and gas facilities.
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STATE RULES AND REGULATIONS
Arizona's Official Compilation of Administrative Rules and
Regulations, Chapter 7, Oil and Gas Conservation Commission,
states in Section R12-7-140 that, "The owner or operator shall
take all reasonable precautions to avoid polluting streams,
polluting underground water, and damaging soil." These
regulations govern all construction, binding, well spacing,
reporting, and abandonment procedures for oil and gas activities.
Permit requirements for injection wells are specified, but the
substance to be injected is not mentioned. Section R12-7-108
states that, "In order to assure a supply of drilling mud to
confine oil, gas or water to its native stratum during the
drilling of any well, operators shall provide, before drilling is
commenced, an adequate pit, either earthen or portable, for the
drilling mud or the accumulation of drill cuttings."
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REFERENCES
Ray Brady, Deputy State Director, Division of Mineral
Resources. Letter to EPA. September 4, 1985.
Official Compilation of Administrative Rules and Regulations
for Arizona, Chapter 7, Oil and Gas Conservation
Commission, Article 1. Oil, Gas and Helium. 1975.
Personal Communications:
Lyndon Hammon, NPDES Permits Section Manager, Arizona
Department of Health and Safety. September 29, 1986
(602) 257-2262.
Nate Lau, Director of the UIC Division, EPA Region IX.
September 28, 1986 (415) 974-0893.
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ARKANSAS
INTRODUCTION
Arkansas produces 17,618,000
barrels of oil and 162,678 MM
cubic feet of gas each year.
Production is from 9,490 oil
wells and 2,492 gas wells. The
State is divided into two
geographical districts. The
Arcoma Basin, located in the
northwest corner of the State,
produces 99 percent natural gas
on a volume basis. The
Mississippi Embayment in
southeastern Arkansas produces
approximately 90 percent oil
and 10 percent gas.
STATE REGULATORY AGENCIES
Two agencies regulate oil and gas activity in Arkansas:
- Arkansas Oil and Gas Commission
- Arkansas Department of Pollution Control and Ecology
The Arkansas Oil and Gas Commission, a division of the Arkansas
Department of Commerce, regulates industry practices regarding
drilling and production of oil and gas wells by means of
Statewide General Rules and Regulations Order No. 2-39. The
General Rules and Regulations do not address all aspects of
industry practices, and refer the reader to "special rules
pertaining to individual oil, gas, or salt water fields and
pools." Special rules of any non-emergency nature require a
public hearing, and are provided for in Rules A-2 and B-38 of the
General Rules and Regulations. The reader of this document is
also advised that, "There is a considerable body of statutory law
in Arkansas that must be consulted in evaluating an oil and gas
matter," and is referred to the Arkansas Statutes, Annotated,
Title 53.
The Arkansas Department of Pollution Control and Ecology, a
division of the Water Pollution Control Commission, derives its
regulatory authority from Regulation No. 1, "Regulation for the
prevention of pollution by salt water and other oil field wastes
produced by wells in new fields or pools." The regulation was
promulgated on October 13, 1958, pursuant to the authority
provided by Act 472 of the Acts of Arkansas for 1949, and is
currently being revised. The updated regulation is being modeled
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after Louisiana State Order No. 29-B, and is expected to be
promulgated in 1987.
It is apparent from the regulations that there are areas in which
the responsibilities of these two agencies overlap. "Memorandums
of Understanding" are on file that define the role of each agency
as it applies to oil and gas regulations. For example, the
Arkansas Oil and Gas Commission regulates underground* disposal of
salt water, and the Arkansas Department of Pollution Control
regulates surface discharges of salt water. The state does not
have NPDES delegated authority.
STATE RULES AND REGULATIONS
DRILLING
Section 4 of Regulation No. 1 forbids discharging salt water from
an oil or gas well such that the salt water may come in contact
with "any of the waters of the State, whether by natural
drainage, seepage, overflow, or otherwise." Other sections of
Regulation No. 1 require the well operator to obtain a permit for
a waste disposal system that prevents the wastes from contacting
State waters. The regulation provides two alternatives for salt
water disposal: subsurface discharge in disposal wells con-
structed in accordance with the Rules and Regulations of the
Arkansas Oil and Gas Commission, and surface discharge into lined
earthen pits.
The Arkansas Department of Pollution Control and Ecology issues a
letter of authorization that serves as an informal permit for the
construction of reserve pits on drill sites. The Department uses
the letter to clarify and add strength to the outdated Regulation
No. 1 which is currently being revised. The letter lists
conditions which the Department of Pollution Control and Ecology
expects to be followed during drilling operations pertaining to
reserve pit construction, pit fluid and drilling mud disposal,
and drill site reclamation.
All earthen pits must be lined with a synthetic liner (20 mils
thick) or a clay liner (18 to 24 inches thick), and must maintain
at least 2 feet of freeboard. Pits must be reclaimed to grade
and seeded within 60 days after the drilling rig has been removed
from the site.
Reserve pit wastes may be treated and land applied at the drill
site if they contain less than 2,000 mg/1 total dissolved solids,
and if they are treated. Wastes having greater than 2,000 mg/1
TDS must be disposed of in State-permitted disposal wells.
The letter of authorization also states that completion fluids
high in total dissolved solids, such as KC1, should be kept
separate from the contents of the reserve pit, and recommends
that a lined pit be used for this purpose.
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Disposal of reserve pit fluids and drilling mud requires a. permit
from the Arkansas Department of Pollution Control and Ecology.
The permit requires that the disposal company provide an analysis
of the pit fluids and drilling mud, the amount hauled, and its
final destination. A disposal company that is permitted to land
apply pit fluid and drilling mud near the well must provide the
Department with a copy of the land owner's agreement "as well as
an analysis of the wastes. An analysis of pit fluid will include
tests for chlorides and pH, and a drilling mud analysis will
include tests for chromium, zinc, chlorides, and pH.
PRODUCTION
Rule C-7 of the General Rules and Regulations defines the means
by which salt water produced from oil and gas wells may be
discharged into subsurface formations. The Oil and Gas
Commission states that it will consult the State Geological
Survey and the State Board of Health, when reviewing an
application to inject salt water, in order to protect fresh water
supplies. Disposal wells are to be cased and cemented "in such
manner that damage will not be caused to oil, gas or fresh water
resources." The mechanical integrity of a disposal well is to be
tested prior to its first use, and at least once every 5 years
thereafter. A monthly salt water disposal report is required
that includes the amount of water injected, the injection
pressure, and the zone into which the salt water is injected.
The letter of authorization issued by the Arkansas Department of
Pollution Control and Ecology states that salt water produced any
time during the lifetime of a well will remain the responsibility
of the production company, and "shall be stored in a plastic or
fiberglass tank above ground and resting on a concrete pad."
OFFSITE AND COMMERCIAL PITS
State regulations do not address offsite and commercial pits.
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REFERENCES
Personal Communication with Mr. David A. Thomas, Arkansas
Department of Pollution Control and Ecology, August ??,
1986. Telephone (501) 562-7444.
Arkansas Department of Pollution Control and Ecology,
"Regulation No. 1," October, 1958.
Arkansas Oil and Gas Commission, "State of Arkansas Rules and
Regulations Order No. 2-39," revised 1983.
Interstate Oil Compact Commission, The Oil and Gas Compact
Bulletin, Volume XLIV, No. 2, December 1985.
Interstate Oil Compact Commission, Summary of State Statutes
and Regulations for Oil and Gas Production, June 1986.
U.S. Environmental Protection Agency, Proceedings; Onshore
Oil and Gas State/Federal Western Workshop, December 1985.
Letter of Authorization from Mr. David A. Thomas, Arkansas
Department of Pollution Control and Ecology, to
Mr. William S. Walker, Stevens Production Company,
August 20, 1986.
Letter to Mr. Naresh R. Shah, West Virginia Department of Natural
Resources Permits Branch, from Mr. Terry Muse, Arkansas
Department of Pollution Control and Ecology, regarding
Arkansas Water Permit No. 2839-W, March 2, 1984.
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CALIFORNIA
INTRODUCTION
California produced 411,665,000
barrels of oil and 470 x 10'
cubic feet of gas in 1984.
California ranked fourth in
U.S. oil production and sixth
in U.S. gas production.
Production is from 48,908
producing oil wells and 1,220
producing gas wells. Approxi-
mately 55 percent of the oil
production is attributed to
enhanced oil recovery.
At present, California has 10,652 Class II wells: 9,657 are
injecting fluids back into hydrocarbon producing zones; 971 are
water disposal wells. Some of the water produced in association
with oil and gas in the San Joaquin Valley is of a good quality.
In those cases, the water is cleaned up through filtration and
used for irrigation purposes. Some waters produced in urban oil
fields are disposed into municipal sewer systems.
California has been injecting fluids into non-hydrocarbon-
producing zones of the Santa Maria Valley and the Salinas Valley
for many years. Fluids from shallow, heavy oil steam flood
production is injected into other formations such as the Santa
Margarita.
STATE REGULATORY AGENCIES
Eight agencies regulate oil and gas activity in California:
- California Department of Conservation,
Division of Oil and Gas
California Water Resources Control Board with the
program administered through nine Regional Water
Quality Control Boards
- State Lands Commission
State Air Pollution Control Districts
California Department of Fish and Game
- Local governmental agencies
U.S. Bureau of Land Management
U.S. Department of Energy
The California Division of Oil and Gas was created in 1915 by the
State legislature. The Division was given the authority to
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supervise the drilling, operation, maintenance, and abandonment
of oil and gas wells to prevent, as far as possible, damage to
oil and gas deposits from infiltering water and other causes and
to prevent loss of oil and gas reservoir energy.
Since 1915, operators have been required to obtain a permit prior
to drilling, reworking, or abandoning a well. At the time of
permit application, engineers have prescribed well casing,
cementing, testing, and/or plugging requirements. In the early
1930s, additional legislation was passed that provided well
spacing and well bonding statutes. At that time, the State Oil
and Gas Supervisor was mandated to prevent damage to underground
and surface waters suitable for irrigation or domestic purposes
from degradation from oil and gas operations. The Division has
been delegated authority to issue UIC permits for Class II wells.
The Water Quality Control Boards have statutory responsibility to
protect waters of the State and to preserve all present and
anticipated beneficial uses of those waters. The Water Resources
Control Board has been delegated authority to issue NPDES
permits. The Division of Oil and Gas and the Water Quality
Control Boards have entered into a Memorandum of Understanding to
provide a coordinated approach resulting in a single permit that
satisfies the responsibilities of each agency. Basically, the
coordinated approach uses a method that provides the other agency
with the opportunity to comment on the proposed waste discharge
requirements. A permit to discharge will not be issued unless
the concerns of each agency are satisfied.
For wells on State-owned, onshore lands, the State Lands
Commission has joint responsibilities with the Division of Oil
and Gas. Their responsibilities are expressed in the provisions
of the lease terms.
State Air Pollution Control Districts issue permits to operate
equipment that emits pollutants into the atmosphere. The
equipment includes steam generators used for enhanced oil
recovery projects.
The California Department of Fish and Game provides comments and
recommendations on methods to mitigate any problems that oil and
gas operations may have on fish and wildlife. They coordinate
State operations involving any spills that affect fish and
wildlife.
Cities and counties also issue land use permits for oil and gas
operations. Generally, a condition of their permit requires that
an operator comply with the Division of Oil and Gas regulations.
The Bureau of Land Management approves approximately 400 oil and
gas drilling permits per year on Federal lands. BLM has
approximately 350 water disposal wells and approximately 500
earthen sumps for water disposal. Presently, there are 6,200
oil, gas, and injection wells on Federal lands. The oil and gas
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wells produce approximately 22-1/4 million barrels of water per
month. Most of this water is reused in steam flooding projects,
some goes into evaporation ponds, and some is reinjected for
water flooding projects. Presently, the BLM and Division of Oil
and Gas are negotiating a Memorandum of Understanding under the
UIC program on Federal wells.
The Department of Energy manages the Elk Hills Naval "Petroleum
Reserves. These fields produce approximately 80,000 barrels of
water per day, 133,000 barrels of oil per day, and 390 billion
cubic feet of gas per day, from 1,900 wells. There are 13
injection wells and, during fiscal year 1985, 23 new wells were
drilled. For fiscal year 1986, 36 new wells are planned. The
Department of Energy's goal will be to stop the disposal of
produced water in sumps by the end of fiscal year 1986. Pres-
ently, 1,400 barrels per day ar disposed into 34 earthen sumps.
STATE RULES AND REGULATIONS
Drilling muds are disposed at State-approved hazardous waste
disposal sites if the muds contain constituents considered to be
hazardous. Nonhazardous muds can be left in a drilling waste pit
if the free liquid is removed and the solids and semisolids are
nonhazardous. The drilling pit is reclaimed at the end of the
drilling operation.
Drilling pits may or may not need to be lined or sealed depending
upon their location. The State agency doesn't prescribe pit
construction conditions. The conditional use permit that a
driller obtains from each county generally details the pit
requirements. If the fluids contain hazardous materials, the
pits would have to have liners. At the completion of a well,
drilling fluids may be transported offsite generally to
evaporation sumps.
On Federal lands, drilling fluids are left in the sump until
completion of the well. After completion of the well, drilling
fluids are hauled to a Class II disposal site for oil field
wastes. Most of these sites are surface sumps.
Usually there is one pit for each drilled well but often portable
tanks are used in lieu of sumps. Mud pits usually are in
existence until the time of well completion or abandonment in the
case of dry holes. Brine pits are located only in areas where
percolation is allowed and they remain in existence as long as
needed. Emergency pits are allowed as long as they are evacuated
and cleaned after any spill.
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PRODUCTION
Production waters are disposed approximately as follows:
Evaporation in percolation sumps - 18 percent
Evaporation in lined sumps - 6 percent
To sewer systems - 2 percent
To surface water - 18 perce.nt
Underground injection - 56 percent
The small percentage that goes to sewer systems.predominantly is
within the Los Angeles County Sanitation District. Production
waters entering such sewers must meet applicable pretreatment
standards including a maximum oil and grease content of 75 mg/1,
heavy metals limits, cyanide, chlorinated hydrocarbons, and
sulfides. There is no pretreatment limit for chloride.
Some production waters are permitted for discharge to waters of
the United States including principally irrigation canals,
ephemeral streams, and dry ditches. There are at least 12 such
permits in the Fresno office of the Regional Water Quality Board.
There are a number of additional such discharges that currently
are pending a determination by the U.S. Environmental Protection
Agency. Discharge permit limits include the following maximum
values:
Electrical conductivity 1,000 p mhos
Boron 1 mg/1
Chlorides 200 mg/1
Oil and grease 35 mg/1
OFFSITE AND COMMERCIAL PITS
On the western side of the San Joaquin Valley, there is a
wastewater disposal facility permitted on Federal land where the
oil industry has gotten together with a private consultant and
permitted a series of sumps that cover approximately 20 to 40
acres. These sumps are used for percolation and evaporation.
BLM has some sumps on Federal leases that range up to roughly 5
acres. The quality of groundwater on the west side is very poor.
Drilling fluids and production brines may be transported to
offsite and commercial pits. Drilling fluids generally are
received by evaporation sumps, but many such sumps are used for
percolation and evaporation where fresh water sources are not
nearby. A manifest is not required unless the material
transported is a hazardous waste.
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REFERENCES
California Meeting Report. 1985. Proceedings of the
Onshore Oil and Gas State/Federal Western Workshop.
U.S. Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and Gas
Production.1986.Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Mefferd, Marty. 1985. Letter Communication to EPA.
Supervisor, Division of Oil and Gas.
Personal Communications:
Bob Reid, Division of Oil and Gas (916) 445-9686.
Scott Smith, Central Valley Water Quality Board
(209) 445-5116.
Chong Rhee, L.A. County Sanitation District (213) 699-7411
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COLORADO
INTRODUCTION
Colorado has a long history of
regulating oil and gas activ-
ities. As far back as 1889,
Colorado passed a bill pro-
hibiting the discharge of oil,
petroleum, or other substances
into any waters of the State.
In 1950, a second bill was
passed 'that included provis-
ions for well plugging. In
1951, the Oil and Gas Con-
servation Act was passed. The
Solid Wastes Disposal Sites
and Facilities Act (Title 30-
20-Part 1, C.R.S. 1973, as
amended) also has juris-
diction.
In 1985, Colorado produced 38,584,000 barrels of oil from 5,287
wells; 271,544 million cubic feet of gas were produced from 4,665
gas wells. Mud and air drilling are both encountered.
STATE REGULATORY AGENCIES
Three agencies share regulatory authority for oil and gas wastes
in Colorado:
- Department of Natural Resources-Oil and Gas
Conservation Commission
- Department of Health
- U.S. Bureau of Land Management
The Colorado Department of Natural Resources and Department of
Health share statutory and regulatory authority over oil and gas
activities in the State. Two divisions of the Department of
Health—the Water Quality Control Division/Commission and the
Waste Management Division—have statutory and regulatory
authority over solid waste disposal sites and facilities
(discharges and evaporation ponds, respectively). The Oil and
Gas Conservation Commission is dedicated to prevention of wastes
and conservation of oil and gas; the Department of Health is
concerned with endangerment of public health or the environment.
The shared regulatory responsibilities between the Oil and Gas
Conservation Commission and the Department of Health were worked
out in a 1971 Memorandum of Agreement between the groups. In
this agreement, primary responsibility for oil and gas activities
were delegated to the Oil and Gas Conservation Commission. The
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Department of Health retained the responsibility for offsite
disposal of oil and gas wastes. The Department of Health has
since sought to update the Memorandum, but the Oil and Gas
Conservation Commission has declined to change the agreement. In
fact, the Oil and Gas Conservation Commission has recommended
that their authority be expanded to cover offsite pits, ponds,
and lagoons (currently regulated by the Department of Health).
The Colorado Department of Natural Resources, Oil and Gas
Conservation Commission amended its rules and regulations
effective July 16, 1984.
The U.S. Bureau of Land Management has jurisdiction over
Federally-owned mineral rights. The U.S. Forest Service retains
surface rights on Federally-owned forests and grasslands. Both
agencies are discussed separately under Federal Agencies.
STATE RULES AND REGULATIONS
DRILLING
Oil and Gas Conservation Commission rules provide that, "Before
commencing to drill, proper and adequate slush pits shall be
constructed for the reception of mud and cutting and to
facilitate the drilling operation. Special precautions shall be
taken to prevent contamination or pollution of state waters."
Rule 324 charges owners with the responsibility to take "such
precautions as necessary to prevent polluting the waters of the
state ... by oilfield wastes." The rule does not contain
specific guidance regarding achievement of this goal.
Section 325 of the 1984 Rules and Regulations sets forth the
requirements for disposal of water produced with oil and gas
operations or other oil field waste into retaining pits. The Oil
and Gas Conservation Commission requires demonstration (via
geological information, percolation tests, or other means) that
the proposed retention pond will not pollute surface or
groundwater. The rule also requires chemical analysis of the
wastes to be stored and of the domestic water supply nearby. No
provisions for pit closure are noted in the Commission's Rules
and Regulations.
The Oil and Gas Conservation Commission rules and regulations for
drilling coincide with Department of Health Rules and
Regulations, which are applicable for all waste impoundments.
The Department of Health regulations set forth site standards
(including engineering design, geologic, operational, hydrologic,
and other data) for all facilities. For impoundments of oil and
gas wastes, the Department of Health considers facilities in
compliance if they are regulated by the Oil and Gas Conservation
Commission or if there is no endangerment of public health or the
environment.
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The Department of Health regulations also set standards for
closure of facilities. These standards include provisions for
testing of remaining sludge for hazardous characteristics and
final disposal of the sludge. The provisions are not reflected
in Oil and Gas Conservation Commission rules.
The Oil and Gas Conservation Commission rules have extensive
notification and construction requirements (including- spacing
requirements) for wells.
The Oil and Gas Conservation Commission requires lined pits for
5,000 mg/1 total dissolved solids waters. Reserve pit sludge is
dried out and disposed of on the surface by tilling it into the
ground." The sludge may be moved to a different location before
landfarming. The Oil and Gas Conservation Commission does not
consider this practice land application discharge of drilling
fluids. The Commission has permitted one facility for land
application discharge of wastes with limitations on total
suspended solids, total dissolved solids, oil and grease, and
chemical oxygen demand.
PRODUCTION
Oil and Gas Conservation Commission rules and regulations do not
distinguish between handling of produced waters and handling
other drilling or oil field wastes.
Produced water often is discharged under the provisions of the
BPT Wildlife and Agricultural Use Subcategory. In some cases,
the well operator has been asked by the landowner to put an
accumulation sump and head gate in to allow build up of produced
waters before being used for watering cattle.
COMMERCIAL BRINE DISPOSAL FACILITIES
The Department of Health permits 10 to 15 commercial brine
disposal facilities to discharge under the BPT Wildlife and
Agricultural Use Subcategory. These discharges must generally
meet the following limitations:
- 6.0 >_ pH <_ 9.0
- Total suspended solids of 30 mg/1 30-day
average (45 maximum one-day)
Oil and grease less than 10 mg/1
- Total dissolved solids of 5000 mg/1 30-day
average (7500 mg/1 maximum one-day)
- Some metals are limited by Water Quality
Standards
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Flows from these facilities are on the order of 10,000 gallons
per day.
Centralized pits are used for long term disposal in Colorado.
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REFERENCES
Interstate Oil Compact Commission, The Oil and Gas Compact
Bulletin, Volume XLIV, No. 2, December 1985.
U.S. EPA, Proceedings of the Onshore Oil and Gas
State/Federal Western Workshop, December 1985. -
Colorado Department of Health. Statement of the Colorado
Department of Health for the Informational Hearing
Regarding Oil and Gas Brine Waste Disposal to the
Colorado Water Quality Control Commission. May 10,
1983.
t,
State of Colorado. Department of Natural Resources. Oil
and Gas Conservation Commission. Rules and
Regulations, Rules of Practice and Procedure, and Oil
and Gas Conservation Act (As Amended).Effective July
^
id
16, 1984.
State of Colorado. Regulations Pertaining to Solid Waste
Disposal Sites and Facilities, Effective Date: October
1, 1984.
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FLORIDA
INTRODUCTION
Florida produced 14,090,000
barrels of oil and 15 x 109
cubic feet of gas in 1984.
Production was from 165 oil
wells; there are no producing
gas wells. Virtually all
drilling fluids as well as
produced fluids are reinjected.
STATE REGULATORY PROGRAMS
Three agencies are primarily responsible for regulating the oil
and gas industry in Florida:
Florida Department of Natural Resources, Division of
Resources Management, Bureau of Biology
- Florida Department of Environmental Regulation
Florida Regional Water Management Districts
U.S. Environmental Protection Agency, Region IV
The Department of Natural Resources (DNR) is the permitting
agency for oil and gas wells, including approval to dispose of
waste fluids by subsurface injection. The DNR regulates the
exploration, drilling, and production of the oil and gas industry
with respect to reporting, spacing, safety, and construction.
The Department of Environmental Regulation oversees the industry
with respect to water quality standards and dredge and fill
requirements (for pits) if oil and gas activities occur in waters
of the State.
Florida's Regional Water Management Districts, which are separate
regulatory groups on a local level, regulate oil and gas
activities with regard to water use. Consumptive use permits are
issued if applicable.
Other State agencies may be involved on a case-by-case basis.
These agencies are the Florida Game and Freshwater Fish
Commission, the Department of Community Affairs, and the
Department of Transportation.
The State of Florida does not have primacy for Class II UIC
program wells. The State operates a separate program for
injection wells with a State permit and State inspections. A
driller wishing to inject fluids underground must apply for
permit to do so from two separate governmental entities, the U.S.
Environmental Protection Agency Region IV and the State, and
undergo two sets of inspections.
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STATE RULES AND REGULATIONS
Drilling fluids are put into pits during operation but then
disposed of by reinjection. Pits are nearly dry when they are
backfilled. All produced waters are reinjected.
The DNR is governed by Chapter 377, Florida Statutes, and its
implementing rules, Chapters 16C-25 through 16C-30, Florida
Administrative Code. Part of Chapter 377's specific purpose is
to "require the drilling, casing, and plugging of wells to be
done in such a manner as to prevent the pollution of fresh, salt,
or brackish waters on the lands of the State." And Section
377.371, further states that, "No person drilling for or producing
oili gas, or other petroleum products shall pollute land or
water; damage aquatic or marine life, wildlife, birds, or public
or private property."
UIC permits are issued pursuant to Chapter 403, Florida Statutes
and Chapter 17-28, Florida Administrative Code. If applicable,
dredge and fill activities are regulated under Chapter 403,
Florida Statutes, Chapter 17-12 Florida Administrative Code, and
water standards are issued under Chapters 17-3 and 17-4, Florida
Administrative Code. "Water management licenses (consumptive use)
are issued under Chapter 373, Florida Statutes, by the regional
Water Management Districts.
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REFERENCES
Lloyd Wise, Region IV NPDES permit writer, Summary of EPA
Workshop presentation, Onshore Oil and Gas Workshop
Meeting Report. July 1985.
Lynn Griffin, Environmental Specialist, Department of
Environmental Regulation. Letter to W. A. Telliard,
EPA, March 22, 1985.
State of Florida Regulatory and Review Procedures for Land
Development. Chapter 14. November 1, 1984.
Personal Communication:
Lynn Griffin, Environmental Specialist, Department of
Environmental Regulation, October 2, 1986
(904) 488-8615.
David Curry, Florida Department of Natural Resources
(904) 487-2219.
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ILLINOIS
INTRODUCTION
Illinois produced 28,873,000
barrels of oil and 15 x 109
cubic feet of gas in 1984.
Production is from 28,920 oil
wells and 157 gas wells. Nine-
teen barrels of brine are pro-
duced for every barrel of oil.
Twelve thousand injection wells
are operating in the State.
STATE REGULATORY AGENCY
Principally one agency regulates the oil and gas industry in
Illinois:
- Department of Mines and Minerals, Division of Oil and
Gas
The Department of Mines and Minerals operates under an Act in
Relation to Oil, Gas, Coal and Other Surface and Underground
Resources. Section 8A of the Act provides the Department with
the power and authority to regulate the disposal of salt- or
sulphur-bearing water and any oil field waste produced in the
operation of any oil or gas well, and to adopt proper rules and
regulations relative thereto. Section 8B provides that no person
shall drill, convert or deepen a well for the purpose of
injecting gas, air, water, or other liquid into any underground
formation or strata without first securing a permit therefor.
Section 8C(A) states that no person shall operate an oil field
brine transportation system without an oil field brine
transportation permit. Section 8G(3) specifies that the
permittee shall not dispose of oil field brine onto or into the
ground except at locations specifically approved and permitted by
the Mining Board. No oil field brine shall be placed in a
location where it could enter any public or private drain, pond,
stream or other body of surface or ground water.
The Division of Oil and Gas has UIC program primary for Class II
wells. There are Federal lands in Illinois but there is no
drilling or production on Federal lands currently. The Illinois
Environmental Protection Agency has been delegated NPDES
authority but no surface water discharges from the oil and gas
industry are allowed.
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STATE RULES AND REGULATIONS
DRILLING
There are no State requirements that drilling pits be permitted
or lined. Fluids from the pits may be disposed in a dry drill
hole. When the pit mud dries, the pit is back-filled and
reclaimed. Pits must be reclaimed within 6 months after drilling
ceases.
PRODUCTION
Production fluids go to lined holding-evaporation ponds or they
are reinjected into certified injection wells. The lining may be
clay or plastic, but recently no requests for plastic-lined pits
have been received. Requests now are for fiber glass or concrete
lined pits. Earthen lined pits have been substantially
eliminated during the past 5 years. The Department of Mines and
Minerals has been reducing the number of old pits by removing and
injecting the brines, stabilizing the contents, applying topsoil,
and vegetating the pit area.
Neither road spreading nor land farming is allowed.
OFFSITE AND COMMERCIAL PITS
Use is not made of offsite or commercial pits in the State of
Illinois.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil Compact
Commission (December).
Illinois Meeting Report. 1985. Proceedings of the Onshore Oil
and Gas Workshop. U.S. Environmental Protection Agency,
Washington, D.C. (March 26-27 in Atlanta, GA).
v
State of Illinois. 1984. An Act in Relation to Oil, Gas, Coal
and Other Surface and Underground Resources.Revised
Edition.
State of Illinois. 1984. Rules and Regulations. Department of
Mines and Minerals, Division of Oil and Gas. Revised
Edition.
Personal Communication:
George R. Lane, Division of Oil and Gas (217) 782-7756.
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INDIANA
INTRODUCTION
Indiana produced 5,394,000
barrels of oil and 394,000,000
cubic feet of gas in 1984.
Production was from 6,792 oil
wells and 2,294 gas wells.
STATE REGULATORY AGENCIES
Two agencies principally regulate oil and gas activity in
Indiana:
- Indiana Division of Oil and Gas
- U.S. Environmental Protection Agency, Region V
The Indiana Division of Oil and Gas regulates the industry
through Rule 310 IAC 7-1. No discharge to surface waters is
allowed so that any involvement of the Indiana Department of
Environmental Management would occur as a result of improper
disposal of oil and gas wastes. Concerns that owners of Federal
lands may have regarding oil and gas surface treatment are
satisfied thorough conditions of the respective lease agreements
The Oil and Gas Division does not have primacy for UIC program
Class II wells. The State is in the process of attaining such
status. Currently, however, anyone interested in underground
injection must obtain two permits—one from the State, and one
from the U.S. Environmental Protection Agency.
STATE RULES AND REGULATIONS
DRILLING
Pits associated with drilling operations are allowed; they are
small with a 250 cubic foot capacity, approximately. Drill pits
must be reclaimed within 60 days after drilling has stopped.
Fluids associated with such drill pits generally can be
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classified as fresh-water and are mixed with bentonite clays.
When a pit is closed, the practice is to pump the small amount of
fluid in the pit to the surrounding land, bury the drill cuttings
and other pit muds, and reclaim the land.
PRODUCTION . -
Pits used for gathering production fluids and storing them until
reinjection must be lined with impervious clay or an artificial
liner. All production fluids must be reinjected underground.
Evaporation pits were disallowed by the State two years ago.
OFFSITE" AND COMMERCIAL PITS
There is one operating commercial injection well with associated
holding pits. Some use is made by a producer at one well of
another's holding pits and injection well for produced fluids
disposal.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Personal Communication:
Mike Nickolaus, Indiana Division of Oil and Gas
(ai7) 232-4055.
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KANSAS
INTRODUCTION
Kansas produced 75,723,000
barrels of oil and 466.6 x 109
cubic feet of gas in 1984.
Production is from 57,633
producing oil wells and 12,680
gas wells. Kansas ranks
seventh in both U.S. oil
production and U.S. gas
production. There are 11,000
injection wells in the State.
Oil was found in Kansas in the
1860s, but it was not commer-
cially developed until 1895.
Oil and gas regulation began in
1935.
STATE REGULATORY AGENCIES
One agency regulates oil and gas activities in Kansas:
- Kansas Corporation Commission
One July 1, 1986, by passage of House Bill 3078, the Kansas
Legislature transferred the Department of Health and Environment
responsibilities in oil and gas activities regulation to the
Kansas Corporation Commission. Prior to July 1, 1986, the
Department of Health and Environment maintained certain
responsibilities related to lease maintenance, emergency pits,
drill pits, burn pits, and storage ponds. Kansas Statute Chapter
55, Article 10, 55-1003 provided that for the disposal of oil and
gas brines and mineralized waters, the plans and specifications
for such were to be submitted to and approved by the State
Corporation Commission and the Secretary of Health and
Environment. By legislative action, the Secretary of Health and
Environment no longer is a party to such action.
There are few Federal lands and little involvement of Indian
Tribes in the Kansas oil and gas industry. The State informs
neither party directly when an application for a permit to drill
has been received. Such information is published as a routine
matter in local news outlets, and if there are specified
requirements by the Bureau of Land Management or Indian Tribes,
they are communicated directly to the driller through lease
agreement condition or by other legal means.
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STATE RULES AND REGULATIONS
DRILLING
Kansas Statute 55-156 states that prior to abandonment of any
well which has been drilled, is being drilled, or may hereafter
by drilled, the operator shall protect usable groundwater or
surface water from pollution and from loss through downward
drainage by plugging the well, in accordance with the rules and
regulations adopted by the Commission. Failure to comply with
these rules and regulations shall be a class E felony.
A compliance or surety bond is not required. Regulation of the
industry is through the issuance of drilling and well operation
permits. With the recent departmental transfer of responsi-
bilities, the Corporation Commission is in the process of
resolving issues, revising, and proposing regulations pertaining
to those activities formerly administered by the Secretary of
Health and Environment.
Drilling pits and burn pits have been regulated under a general
permit for a maximum period of 365 days unless the operator
requests and receives approval for an extension. No application
for permit is required. In the sandy soils of the State, such
pits would need to be lined. In the heavy clay region of the
North-Central portion, for example, such pits most likely would
not be lined.
Permits are required for emergency pits but not reserve pits. If
an emergency or reserve pit gets brine in it, it must be pumped
out upon termination of the emergency or completion of the well.
Kansas does not support transporting contents of reserve pits
upon closure to landfills in central locations. Burial on site
is the primary method used. There is no law requiring
backfilling of pits, but most of the lease agreements contain
that provision. In geologically sensitive or hydrogeologically
sensitive areas, seals in drilling pits can be required and in
situ disposal of drilling pit contents can be prohibited.
PRODUCTION
Kansas Statute 55-901 provides that the owner or operator of any
oil or gas well which may be producing and which produces salt
water or waters containing minerals in an appreciable degree
shall have the right to return said waters to any horizon from
which such salt waters may have been produced, or to any other
horizon which contains or had previously produced salt water or
waters containing minerals in an appreciable degree, if the owner
or operator of such well makes a written application to the State
Corporation Commission for authority to do so and written
approval has been granted him or her after investigation by the
State Corporation Commission. Salt water is defined as water
with greater than 5,000 mg/1 chlorides. Spreading of salt water
A-3 6
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on roads under construction is not prohibited if approval is
received from the Commission. The Commission has primacy for UIC
Class II wells.
Requests for a surface pond permit are granted unless denied by
the Commission within 10 days. According to proposed Rule 32-3-
600, the Commission, in approving applications for surface pond
permits, shall consider the protection of soil and water
resources from pollution. Each operator of a surface pond shall
install observation trenches, holes, or wells if required by the
Commission, and seal the pond with artificial material if the
Commission determines that an unsealed condition will present a
pollution threat to soil or water resources. Surface drainage is
to be prevented from entering the pond. During the past two
years, it has become a practice, on a case-by-case basis, to
require monitoring wells in association with surface ponds.
There are approximately 25 permanent pits, receiving a total of
30 barrels of brine a day, mostly in the Southeast corner of the
State where there are no groundwater or seepage problems and
where chloride is quite low. Surface discharges of produced
brine are not allowed nor is pit disposal allowed.
Upon the permanent cessation of the flow of fluids into any
surface pond, all fluids resulting from oil and gas activities
shall be removed to a disposal well approved by the Commission,
or used for road maintenance or construction if approved by the
Commission. Pond solids may be transported to a permitted solid
waste landfill or to an approved offsite disposal area; however,
this latter condition of former Rule 28-41-5 and currently
proposed Rule 82-3-603 has not been used.
OFFSITE AND COMMERCIAL PITS
Use is not made of offsite or commercial pits.
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REFERENCES
Kansas Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas State/Federal Western Workshop. U.S.
Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and Gas
Production.1986.Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
General Rules and Regulations, the State Corporation
Commission of the State of Kansas (Effective May 1,
1986).
Personal Communication:
Jim Schoff, Kansas Corporation Commission (316) 263-3238,
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KENTUCKY
INTRODUCTION
Kentucky produced 7,788,000
barrels of oil from 19,980 oil
wells and 61.5 x 109 cubic feet
of gas from 9,013 gas wells in
1984.
STATE REGULATORY AGENCIES
Five agencies regulate oil and gas activity in Kentucky:
Kentucky Division of Oil and Gas
Kentucky Department of Natural Resources and
Environmental Protection
U.S. Bureau of Land Management
U.S. Army Corps of Engineers
U.S. Environmental Protection Agency, Region IV
The Kentucky Division of Oil and Gas issues drill permits and
provides well casing and well plugging requirements. The State
is seeking primacy but does not yet have primacy for the UIC
Class II well program.
The Kentucky Department of Natural Resources and Environmental
Protection has NPDES-delegated authority. The Department issues
permits for holding pits containing production fluids and
instructions, pursuant to regulations, for pit construction.
The U.S. Army Corps of Engineers becomes involved in oil and gas
activities on lands maintained for water management projects.
The U.S. Environmental Protection Agency, Region IV, issues UIC
program Class II injection well permits.
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STATE RULES AND REGULATIONS
DRILLING
Pursuant to Kentucky regulation 401 KAR 5:090, there can be no
discharge from a pit without an NPDES permit. Pits used to
contain drilling muds or fluids associated with drill-ing
activities do not have to have a permit for construction or
operation provided that the pit life is not longer than 30 days.
Where the pit life is longer than 30 days, a pit is defined as a
holding pit and a permit is required. When a pit no longer is in
service, it must be backfilled and the land restored. There are
no liner requirements for a pit with less than a 30-day life.
PRODUCTION
A holding pit with a life longer than 30 days must have a permit
and must be lined with a synthetic material of 20 mil minimum
thickness. The State may grant an exemption to the lining clause
for pits that pre-existed the date of regulatory enactment.
Construction requirements include at least l foot of freeboard
and a 2-foot berm above ground around the pit. Surface waters
must be diverted from the pit.
No NPDES permits have been issued for discharges from holding
pits. However, the Department of Natural Resources and
Environmental Protection recently was sued and entered into a
consent decree which specified a water quality criterion of 600
mg/1 chlorides as appropriate for receiving water quality, it is
anticipated that there will be a number of requests for NPDES
permits to discharge produced fluids. Discharge constituent
limits will be a part of any permit issued.
Some holding pits are used as produced water storage pits until a
contract hauler transports the fluids for well injection or other
purposes. There is no manifest system per se, but there is
registration of drilling fluid haulers with the Department and
there is reporting of the producer of the fluid and its
destination following transportation. Most of the fluid goes
into injection wells.
There is no roadspreading or landspreading of produced fluids in
Kentucky. Some use is being made currently of mechanical
evaporation.
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REFERENCES
Summary of St.atie Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Personal Communications:
Brian C. Gelpin, Kentucky Division of Oil and Gas
(606) 257-3812.
Brad Lambert, Kentucky Department of Natural Resources
and Environmental Protection (502) 264-3410.
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LOUISIANA
INTRODUCTION
Louisiana produced 449,545,000
barrels of oil and 5,867 x 109
cubic feet of gas in 1984.
Louisiana ranks third in U.S.
oil production and second in
U.S. gas production. Over
half of Louisiana's 25,823 oil
wells are strippers. More
than two-thirds of Louisiana's
14,436 gas wells are marginal
(produce less than 60 thousand
cubic feet of gas per day.)
Eighty five percent of all
produced fluids is salt water.
State statutes have regulated
drilling operations since
1950. On January 20, 1986,
the Department of Conservation
promulgated amended rules and
regulations regarding "the
storage, treatment, and
disposal of non-hazardous
oilfield waste."
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activities in Louisiana:
- Louisiana Department of Natural Resources
- Louisiana Department of Environmental Quality
- U.S. Bureau of Land Management
- U. S. Corps of Engineers
The Louisiana Department of Natural Resources Office of
Conservation regulates all subsurface and surface disposal of
oil- and gas-associated wastes. These powers were delegated to
the Office of Conservation under Title 30 of the Revised
Louisiana Statutes of 1950. The Office of Conservation has been
granted primacy for all classes of UIC wells.
The Office of Conservation does not coordinate with EPA on NPDES
permits, but does coordinate with the Louisiana Department of
Environmental Quality, Water Quality Division, on any problem
discharges originating from oil and gas activities.
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The Bureau of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands where the
mineral rights are federally held. Surface rights in Federal
forests and grasslands are retained by the U.S. Forest Service.
These rules, regulations, and orders are discussed in a separate
section, Federal Agencies. The Bureau of Indian Affairs has some
jurisdiction in limited areas of Louisiana. ;
STATE RULES AND REGULATIONS
DRILLING
<*
All pits must be lined such that the hydraulic conductivity of
the liner does not exceed 1 X 10"^ cm/s. Liners may consist of
clays, soils, synthetics, or any combination meeting the 1 X 10~7
cm/s limitation. Pits located within inland tidal waters, lakes
bounded by the Gulf of Mexico, and saltwater marshes are
excempted from the liner requirement provided they are part of an
approved treatment train for removal of oil and grease. Natural
gas processing pits and compressor station pits are also
exempted.
Louisiana State Order No. 29-B contains pit construction and
closure requirements which are consistent with most States (i.e.,
2-foot freeboard, pit closure within 6 months of completion,
prohibition of trash and produced water into reserve pits). The
Order is unusual in the perspective it uses for these
requirements. The Order is written specifically so that "pits
will be protected from surface waters." Another aspect of the
Order is that it defines sixteen classes of oilfield waste
(including drilling fluids, produced fluids, workover fluids,
completion fluids, and others) as "non-hazardous oilfield
wastes."
Pit closure and land treatment facilities must meet certain
requirements for pH, electrical conductivity, and concentrations
of certain elements. These requirements are set in Statewide
Order 29-B. Reserve pits must be closed within 6 months of
reaching total depth during drilling. Closure may be through
annular injection, injection down another newly-drilled well
which will be plugged, land treatment, solidified and buried
onsite, or offsite disposal at permitted commercial facilities.
Annular injection of reserve pit fluids is allowed whenever
surface casing is deep enough to protect underground sources of
drinking water. Reserve pit solids may be transported offsite to
a permitted commercial treatment facility for treatment and
disposal. A manifest system is enforced.
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PRODUCTION
Produced waters must be disposed into subsurface formations
unless discharge is permitted under "applicable state or federal
discharge regulatory program." Produced water may also be
treated and disposed by an approved commercial facility.
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REFERENCES
Louisiana State Statutes 1950 30:204.
Interstate Oil Compact Commission, Oil and Gas Compact
Bulletin, Volume XLIV, No. 2, December 1985.
State of Louisiana Department of Natural Resources, Office
of Conservation, "Amendment to Statewide Order
No. 29-B," January 20, 1986.
Wascom, Carroll, D., "Oilfield Pit Regulations - A First for
the Louisiana Oil and Gas Industry," May 30, 1986.
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MARYLAND
INTRODUCTION
Maryland produced 20 million
cubic feet of gas from 9 gas
wells, and no oil, in 1984.
STATE REGULATORY AGENCIES
Two agencies regulate oil and gas activities in Maryland:
Department of Natural Resources, Bureau of Mines
Department of Health, Office of Environmental
Protection
The Department of Natural Resources regulates oil handling,
storage, and transportation. Drilling permits are issued, and
site erosion is regulated.
All wastewater regulation is managed by the Department of Health.
Section 6-104 of the public general laws of Maryland provides
that a person may not dispose of any product of a gas or oil well
without a permit issued by the Department. The Department has
both NPDES delegation and UIC program authority.
STATE RULES AND REGULATIONS
DRILLING AND PRODUCTION
Drilling and production wastes are managed by the Department of
Health, Office of Environmental Protection. There is no
differentiation between pits that are associated with drilling or
production activities.
A pit may be lined with an impervious material such as clay or a
plastic to prevent groundwater pollution. Fluids introduced to
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lined pits generally are transported to a brine disposal facility
or to a sewage treatment plant, or they may be transported out of
State for disposal purposes. There are no requirements on
thickness or type of pit liners. There is no manifest system
associated with transporting gas wastes unless such wastes are
defined as hazardous.
Pits that are not lined must have a groundwater discharge permit
issued under Code of Maryland regulations. The requirements
associated with pit contents that would meet permit conditions
for a groundwater discharge are determined on a site-by-site
basis. If there is a discharge from a pit, an NPDES permit would
be required.
The State currently has neither issued an NPDES permit for
surface discharges nor a UIC permit for underground injection.
There is a groundwater discharge gas storage extraction facility
in the western part of the State that is permitted to discharge
about 1 million gallons per year. The permit requires that the
first of a series of ten ponds be lined. There are periodic
monitoring requirements for the ponds and in a nearby stream, but
there are no monitoring limits and no monitoring wells.
OFFSITE AND COMMERCIAL PITS
The only offsite pit used in the State is the one in Western
Maryland described above. Some transported production fluids are
received by this facility.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Personal Communications:
Al Hooker, Department of Natural Resources, Bureau of Mines
(3P1) 689-4136.
Bob Creter and David Fluke, Department of Health, Office of
Environmental Protection (301) 791-4787.
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MICHIGAN
INTRODUCTION
Michigan produced 30,980,000
barrels of oil and 144.7 x 109
cubic feet of gas in 1984 from
3,848 stripper oil wells, 1,759
full-production oil wells, and
721 gas'wells. In 1984, the
state ranked twelfth in U.S.
oil production and thirteenth
in U.S. gas production. Oil
and gas production in Michigan
had been relatively constant
for the past 5 years, but more
recently oil production is down
because of declining crude oil
prices.
The first successful Michigan
oil well was drilled in 1886.
The first oil and gas drilling
permit was issued in 1927.
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activities in Michigan:
- Michigan Department of Natural Resources
U.S. Forest Service
- U.S. Bureau of Land Management
- U.S. Environmental Protection Agency
The Michigan Oil and Gas Act of 1939 (PA 61) established the
Supervisor of Wells within the Geological Survey Division of the
Michigan Department of Natural Resources. The prime regulator of
the oil and gas industry is the Supervisor of Wells. The
Supervisor has authority to subpoena, to establish well spacing
requirements, to develop orders without legislative interference,
and to control disposal of solid and liquid wastes from drilling.
The Oil and Gas Act provides the Supervisor of Wells broad
authority to regulate the industry from "cradle to grave"; it
stresses "prevention of waste" from exploration to well aban-
donment. The State requires a bond, an environmental assessment,
and spacing minimums.
The Water Resources Commission Act of 1929 (PA 245) regulates
discharges to and the pollution of any waters of the state; it is
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under Act 245 that National Pollution Discharge Elimination
System (NPDES) permits are issued. Michigan is an NPDES
delegated state with such permits issued by the Surface Water
Quality Division of the Department of Natural Resources. No
NPDES permits are issued for oil and gas wastes.
The Solid Waste Management Act of 1978 (PA 641) provides for the
licensing of solid waste disposal sites.
The State of Michigan does not require NPDES or landfill permits
for disposal of liquid or solid oil field drilling wastes; these
activities are regulated by the Supervisor of Wells. Other
divisions of the Department of Natural Resources provide
assistance to the Geological Survey Division in enforcing the Act
by providing liaison with the Attorney General and with county
prosecutors for action by the local courts through cooperative
efforts of Department of Natural Resources law enforcement
conservation officers. Where a groundwater problem has been
identified through investigation and monitoring by the Geological
Survey Division, and groundwater restoration is required, an
NPDES permit by the Water Quality Division is issued on the
restored water.
When drilling is requested to occur on Federal lands, Federal
surface ownership often is severed from ownership of mineral
rights. When only surface rights are owned by the Federal
government, a copy of the drilling application is sent to the
Federal agency involved, generally the U.S. Forest Service. Two
separate investigations then follow: one by the Geological
Survey, and one by the U.S. Forest Service, which involves fish
and wildlife, geological, and other Federal experts. A Federal
surface use permit then is issued. The drilling application is
not approved by the State until all reviews have been completed
and pertinent comments made a part of permit conditions. When
both surface and mineral rights are Federally owned, a copy of
the drilling application is sent to both the U.S. Forest Service
and Bureau of Land Management.
The U.S. Environmental Protection Agency administers the UIC
program for the State (40 CFR 147.1151).
STATE RULES AND REGULATIONS
DRILLING
A letter of instruction was issued by the Supervisor of Wells on
April 6, 1981, which provided for a two-pit drilling mud system—
one for fresh water muds and one for salt water muds—and
required that all reserve pits receiving other than fresh water
fluids be lined with 20 mil PVC or an equivalent liner as
approved. Instructions in 1985 require that all mud pits be
lined with an impervious material that will meet or exceed
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specifications for 20 mil virgin PVC. Liners shall be one piece,
or with factory-installed seams, and shall be installed in a
manner sufficient to prevent both vertical and lateral leakage.
A revised Supervisor Instruction, effective February 1, 1985,
requires that cellars shall be sealed, and rat holes and mouse
holes shall be equipped with a closed-end steel liner or
otherwise sealed or cased in such a manner that all fluids
entering the cellar, rat hole, and/or mouse hole shall not be
released to the ground but shall be discharged to steel tanks,
the lined reserve pit, or the mud circulation system. Aprons of
20 mil virgin PVC or other equivalent material shall be installed
under steel mud tanks and overlapping the mud pit apron, and in
ditches or under pipes used for brine conveyance from cellars to
pits or to steel mud tanks.
Current required practice in Michigan is for the fluids in the
drilling pits to be pumped off prior to encapsulation of the pit
solids. These pit fluids represent nearly 28 million gallons per
year, and they have been used for drilling of additional wells,
disposed in approved brine disposal wells, or spread on roads for
dust and ice control. The best estimate for 1983 shows that 22
million gallons of pit brines were used for road dust and ice
control. A Special Order of the Supervisor of Wells, issued
March 29, 1985, banned the use of pit brines for dust control
after September 1, 1985, and for ice control immediately.
For those pits that have been active since 1981, the fluid is
removed and the solids are encapsulated at the site with the
remaining PVC provided for such purpose, when a pit no longer is
used. For those pits that may have been abandoned, or that were
used prior to the Supervisor's Letter of Instruction, no action
is taken unless a contamination problem has surfaced. When a
potential contamination problem exists, the site is investigated
by the Survey's groundwater unit. If it can be shown that an
identifiable entity is responsible, damages are sought through
the courts.
PRODUCTION
Over 90 percent of Michigan's brines now are disposed of by
underground injection. Earthen production pits are not allowed.
The Supervisor's Special Order of March 29, 1985, requires that
produced brines not be used for ice control on roads and that
such brines meeting certain specifications for benzene, toluene,
and xylene content may be used for dust control under certain
testing and approval conditions until December 31, 1987. None is
to be used for such purpose after January 1, 1988.
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OFFSITE AND COMMERCIAL PITS
No use is made of offsite or commercial pits in Michigan. Rule
601 of Michigan's Oil and Gas Regulations provides that brine or
salt water resulting from oil and gas drilling and producing
operations shall be stored, transported, and disposed of in such
manner as may be approved by the Supervisor. Any brine disposal
procedure which results or may result in the pollution of surface
or underground fresh water resources is prohibited.
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REFERENCES
Crabtree, Allen F. 1985. "Drilling Mud and Brine Waste
Disposal in Michigan." Paper presented at the
Reclamation Review Technical Advisory Committee
Seminar/Workshop on Gel and Saline Based Drilling
Wastes, Edmonton, Alberta, Canada, April 24, 1985.
Supervisor of Mineral Wells Instruction 1-84. "Use of
Liners in Earthen Drilling Pits, Sealing of Cellars,
Rate Holes, Mouse Holes and other Procedures to Protect
Ground Waters," effective February 1, 1985.
Order of the Supervisor of Wells, Special Order 1-85, dated
March 29, 1985.
Summary of State Statutes and Regulations for Oil and Gas
Production.1986.Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Debrabander, S. 1985. Letter Communication to EPA.
Geological Survey Division, Michigan Department of
Natural Resources.
Michigan Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (March 26-27 in Atlanta, GA).
Personal Communications:
Bill Shaw, DNR Office of Water Quality (517) 373-8088.
Steve Debrabander, DNR Geological Survey Division
(517) 334-6976.
Rex Tefertiller, Permits, Geological Survey Division
(517) 334-6974.
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MISSISSIPPI
INTRODUCTION
Mississippi produced 31,879,000
barrels of oil in 1984 from
3,569 oil wells; 210 x 109
cubic feet of gas were produced
from 715 gas wells.
STATE REGULATORY AGENCIES
Four agencies regulate the oil and gas activity in Mississippi:
State Oil and Gas Board
- Mississippi Department of Natural Resources, Bureau of
Pollution Control
- Department of Wildlife Conservation
- U.S. Environmental Protection Agency, Region IV
The State Oil and Gas Board regulates the oil and gas industry
"to prevent the pollution of freshwater supplies by oil, gas or
saltwater" and to promote, encourage, and foster the oil and gas
industry (Section 53-1-17, State Statutes). The Oil and Gas
Board does not have UIC program authority.
The Department of Natural Resources, Bureau of Pollution Control,
is responsible for the investigation of water pollution and for
the issuance of NPDES permits. No NPDES permits are issued for
the onshore oil and gas industry.
The Department of Wildlife Conservation is responsible for the
maintenance of fish and wildlife within the State.
The U.S. Environmental Protection Agency, Region IV, issues UIC
program Class II injection well permits for Mississippi. In this
activity area, the State Oil and Gas Board maintains a separate
well injection permitting program; a well operator must obtain an
injection permit both from the State and Federal Governments.
A 1982 Memorandum of Agreement among the Department of Natural
Resources, Department of Wildlife Conservation, and the State Oil
and Gas Board coordinates the activities of the three State
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agencies related to the oil and gas industry. The Agreement
ensures that the Mississippi Commission on Wildlife Conservation
has an opportunity to review the drill plan, as drilling may
impact the sensitive environmental nature of the States's wetland
resources. The Agreement, further, allows for suspension of
operations by the Oil and Gas Board where any signatory agency
determines such operations to be in violation of applicable laws
or regulations.
STATE RULES AND REGULATIONS
DRILLING
Rule 63 of the State Oil and Gas Board provides requirements
related to pits. There are generally four types of pits (other
than reserve pits) permitted in Mississippi:
1. Temporary saltwater storage pits are allowed at remote
sites. These must be lined, diked, and drained. They
are not allowed to be filled more than 2 feet from the
top. Regular inspections are required. The permit is
good for 1 year. Only three such permits have been
issued in the last 4 years.
2. Emergency pits are not required to be lined. They are
permitted for 2 years. Three or four of these pits may
be permitted in a field. Level must not exceed 1 foot
in these pits. Whenever the pit is used, the Oil and
Gas Board must be notified within 48 hours, and they
will inspect the pit.
3. Burn pits are used to burn tank bottoms on site.
4. Well test pits are used only for test purposes. These
are used rarely.
The use of drilling reserve pits or mud pits does not require a
special permit; the permit to drill constitutes the permit for
the drilling reserve pit. This type of pit is subject to strict
stipulations regarding backfilling when drilling is completed.
Rule 63 was promulgated to prevent waste by pollution of air,
fresh waters, and soils. Extensive management conditions are
presented in the Rule with each of the above pit descriptions.
Mississippi allows annular reinjection of drilling fluids. Seven
annular reinjection wells are operating in Mississippi. These
are used only when no other economical disposal method is avail-
able. Mississippi requires radiological surveys of annular
reinjection wells every 6 months to determine where the rein-
jected fluids are going. Pit muds may be pumped into a dry well
hole, or they most often are buried on site. Land farming is
used in Mississippi. Muds act as a low-grade fertilizer.
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PRODUCTION
Production fluids are reinjected. Reinjection of brines is
operationally feasible state-wide. Since 1978, no method of
brine disposal other than reinjection has been considered
acceptable in Mississippi.
OFFSITE AND COMMERCIAL PITS
Except for two commercial pits in Southern Mississippi, both of
which are phasing down, use is not made of offsite and commercial
pits within the State.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production"! 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Mississippi Meeting Report. 1985. Proceedings of the
Onshore Oil and Gas Workshop. U.S. Environmental
Protection Agency, Washington, D.C. (March 26-27 in
Atlanta, GA).
Statutes and Statewide Rules and Regulations, State of
Mississippi, State Oil and Gas Board, Revised 7/1/86.
Personal Communication:
Richard Lewis, Mississippi Oil and Gas Board
(601) 359-3725.
Jerry Cain, Mississippi Department of Natural
Resources, Bureau of Pollution Control (601) 961-5073.
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MISSOURI
INTRODUCTION
Missouri produced 131,000
barrels of oil from 557 oil
wells and no gas in 1984. The
State has 9 evaporation pits
and 229 injection wells. In
1984, Missouri had a total of
1.9 million barrels of produced
waters and 2.6 million barrels
were injected. The reason for
injection exceeding production
is that two major steam oper-
ations import fresh water to
steam out the oil, which re-
sults in an increased quantity
of injectable fluids. Missouri
has not had gas production
since 1977.
STATE REGULATORY AGENCIES
Three agencies regulate oil and gas activities in Missouri:
- Department of Natural Resources, State Oil and Gas
Council
- U.S. Bureau of Land Management
- Department of Natural Resources, Division of
Environmental Quality
The State Oil and Gas Council was formed by Rule 10 CSR 50-1.010
and is composed of the executive heads of the Division of Geology
and Land Survey, Division of Commerce and Industrial Development,
Missouri Public Service Commission, Clean Water Commission, the
University of Missouri, and two persons knowledgeable of the oil
and gas industry appointed by the Governor with the advice and
consent of the Senate. The State geologist is charged with the
duty of enforcing the rules, regulations, and orders of the
Council. The State has primacy for UIC program Class II wells.
Federal lands in Missouri are confined to U.S. Air Force bases.
There is drilling on such lands. When a request for a permit to
drill is received, the Bureau of Land Management prepares the
draft permit, which is issued by the State Oil and Gas Council.
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The Department of Natural Resources, Division of Environmental
Quality becomes involved only when there is a breach of a pit
dike because of heavy rains, or because of another reason, and a
spill of fluids occurs. Appropriate action under the Division of
Environmental Quality regulations then occurs.
STATE RULES AND REGULATIONS
DRILLING
Rule 10 CSR 50-2.040 provides requirements during the drilling of
wells to prevent contamination of either surface or underground
fresh water resources. There is a bonding requirement before
commencing oil or gas drilling operations, and all wells must be
plugged when abandoned.
There are no regulations related to drill pits. Drill pits are
not lined. When pit muds dry, the muds are buried on site.
PRODUCTION
There are no regulations related to construction of evaporation-
percolation pits for produced waters. About a third of the
produced waters are allowed to evaporate-percolate in such pits,
much of the produced water is injected into a Class II well, and
some of it is trucked off property.
OFFSITE AND COMMERCIAL PITS
Some of the produced fluid is trucked off the property associated
with the producing field. Some may cross a State line. There is
no manifest required of the transported fluids.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Missouri Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas State/Federal Western Workshop. U.S.
Environmental Protection Agency, Washington, D.C.
(December 1985).
v
Rules and Regulations of Missouri Oil and Gas Council, June
1985.
Personal Communication:
Kenneth Deason, Missouri Oil and Gas Council (314) 364-1752
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MONTANA
INTRODUCTION
Montana produced 29,762,000
barrels of oil and 56.9 x 109
cubic feet of gas in 1984.
Production is from 4,665 oil
wells and 2,152 gas wells. A
total of 622 wells were drilled
for oil and gas in 1985. About
320,000 barrels of brine per
day are produced from the
approximately 1,600 full
producing oil wells. The
remaining stripper wells
produce about 40 barrels each
of brine per day.
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activities in Montana:
Montana Department of Natural Resources and
Conservation, Oil and Gas Conservation Division
Montana Department of Health and Environmental
Sciences, Water Quality Bureau
U.S. Environmental Protection Agency, Region VIII
- U.S. Bureau of Land Management
The Oil and Gas Conservation Division issues drilling permits and
regulates the oil and gas industry in Montana. There is a
compliance bond. Montana does not have primacy for the UIC
program.
The Montana Department of Health and Environmental Sciences,
Water Quality Bureau, controls water quality issues. The Bureau
has primacy for the issuance of NPDES permits.
Region VIII of the Environmental Protection Agency issues UIC
permits for the injection of brines in Montana.
The Bureau of Land Management uses their own form for drilling
permits; thus, a driller must obtain a State as well as a Federal
permit to drill for oil or gas on Federal lands. The Oil and Gas
Conservation Division has a cooperative agreement with the Bureau
of Land Management regarding treatment of Indian lands. Normally,
the State issues the permits to drill on Indian lands.
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STATE RULES AND REGULATIONS
DRILLING
Permits are not required for drilling pits. If a dry hole is
encountered, fluids from the drill pit normally are pumped to the
drill hole prior to well plugging. Or, the liquids may be moved
to an oil field reserve pit. The pit solids are allowed to dry,
the pit is closed, and the surface reclaimed.
PRODUCTION
Rule 36.22.1227 of the Board of Oil and Gas Conservation states
that salt or brackish water may be disposed of by evaporation
when impounded in excavated earthen pits which may only be used
for such purpose when the pit is underlaid by tight soil such as
heavy clay or hardpan. At no time shall salt or brackish water
impounded in earthen pits be allowed to escape over adjacent
lands or into streams. Rule 36.22.1228 allows salt water to be
injected into the stratum from which produced or into other
proven saltwater-bearing strata.
The lining requirement of production reserve pits is decided
case by case, based upon soil composition, slope, drilling
fluids, and proximity to water sources. Fluids may be removed
from reserve pits by several methods. One method is to remove
fluids by truck and haul them to another drill site or disposal
facility. No manifest is required for transporting fluids.
Another method is to allow fluids, other than oil, to remain in a
reserve pit for up to a year for evaporation. Most produced
water is reinjected underground. Another method is to chemically
treat the fluids so that they may be used for beneficial
purposes. After the fluids have been removed, the remaining
solids are left to dry before backfilling. If a plastic liner
has been used, it is folded into and buried in the reserve pit.
NPDES discharge permits are issued by the Water Quality Bureau of
the Montana Department of Health and Environmental Sciences for
10 to 12 production reserve pits under the beneficial use
provision of the wildlife and agricultural use subcategory. Of
those issued, only about two of the permitted facilities
discharge. Discharges are to a closed basin in the northern part
of the State. Discharge limits include total dissolved solids of
less than 1,000 mg/1 and an oil and grease of 15 mg/1 absolute
with an average of 10 mg/1. Other discharge limits including
phenols and metals are imposed.
OFFSITE AND COMMERCIAL PITS
Use is not made of offsite and commercial pits in Montana.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Personal Communications:
Charles Maio, Administrator, Board of Oil and Gas
(406) 656-0040.
Abe Horpestad, Water Quality Bureau (406) 444-2459.
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NEBRASKA
INTRODUCTION
Nebraska produces 6,470,000
barrels of oil and 2,347 MM
cubic feet of gas each year.
Production is from 2,072 oil
wells and 18 gas wells. Most
of the State production is in
two areas: the five county area
in the Denver Basin, and Red
Willow and Hitchcock Counties.
Strippers account for about 85
percent of the State
production.
STATE REGULATORY AGENCIES
Three agencies regulate oil and gas activity in Nebraska:
- Nebraska Oil and Gas Conservation Commission
Nebraska Department of Environmental Control
U.S. Bureau of Land Management
The Nebraska Oil and Gas Conservation Commission regulates
industry practices and procedures with regard to construction,
location, and operation of onsite drilling. The Commission
issues permits for oil and gas drilling and UIC Class II wells.
The Commission has three members who are appointed by the
Governor. At least one member must have experience in oil or gas
production.
Nebraska is an NPDES-delegated State. The Nebraska Department of
Environmental Control issues all NPDES permits and regulates all
other classes of UIC wells.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. The Bureau is addressed in a
separate section.
STATE RULES AND REGULATIONS
DRILLING
Under Commission Rule 3.022, retaining pits must be permitted.
Upon receipt of Form 15, Retaining Pit Permit, a Commission
representative will approve or disapprove a proposed retaining
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pit. These pits are required to be lined or constructed with
impermeable material and must have the capacity for at least 3
days of facility fluid influx. This rule does not apply to
reserve pits, emergency pits, or burn pits. Burn pits are
required to be a safe distance from any other structure and shall
be constructed so as to prevent any materials escaping the pit or
surface water entering the pit. The regulations do not address
any requirements for reserve pits. Open pit storage of oil is
not allowed unless during an emergency or by special permission
by the Director of the Commission.
PRODUCTION
V
Commission regulations on brine disposal do not distinguish
between well types. Under Rule 3.002, "No salt water, brackish
water, or other water unfit for domestic, livestock, irrigation
or general use shall be allowed to flow over the surface or into
any stream or underground fresh water zone." Brine may be
disposed by evaporation pits, road spraying, or injection. Brine
pits fall under the regulations in Rule 3.022. Road spraying of
brine is considered on a case-by-case basis. When allowed,
spraying must be done with a spreader bar and in such a way as
the prevent runoff.
Brine can be disposed by injection into either a disposal well or
an enhanced recovery well. Both types of injection wells are
regulated by the Commission. Under Rule 4.005.01, "Each enhanced
recovery well or disposal well shall be completed, equipped,
operated, and maintained in a manner that will prevent pollution
of fresh water or damage to sources of oil and/or gas and will
confine injected fluids to the formations or zones approved."
Annular injection is prohibited. Authorization of injection into
disposal or enhanced recovery wells remains valid for the life of
the well unless revoked by the Commission.
OFFSITE AND COMMERCIAL PITS
This subject is not addressed in the Commission regulations.
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REFERENCES
Nebraska Oil and Gas Conservation Commission, Rules and
Regulations, December 1985.
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Coubrough, Rob, State Regulatory Information Submitted in 1985,
Nebraska Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas State/Federal Western Workshop. U.S. EPA,
Washington,D.C.(December 1985).
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NEVADA
INTRODUCTION
During 1984, Nevada produced
1,953,000 barrels of oil from a
total of 34 oil wells. There
are no producing gas wells in
this State. All of these wells
are on Federal land and most
use reserve pits to evaporate
drilling fluids. Reinjection
is applied to produced waters.
Between 200,000 and 500,000
barrels per year of brine are
produced in Nevada's major
production area (the Carbonate
Belt). Reinjection of these
waters is accomplished-*
collectively into some 5-9
injection wells. No produced
waters are discharged under the
beneficial use subcategory.
Nevada does not have NPDES
primacy.
STATE REGULATORY AGENCIES
For agencies regulate the oil activity in Nevada:
- Nevada Department of Minerals
- Nevada Department of Conservation and Natural
Resources, Division of Environmental Protection
- Bureau of Land Management
EPA, Region IX, Underground Injection Section
The Nevada Department of Minerals, created as a single State
department by the State legislature in 1983, regulates the
industry on the State level with respect to construction,
location, and operation of onsite drilling and production. All
operation permits are issued from this department.
The Division of Environmental Protection in the Department of
Conservation and Natural Resources currently is developing a
program to obtain UIC primacy. The Division has regulations
pertaining to major spills.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. For such drilling, the Bureau of
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Land Management handles all Applications to Drill. The Bureau
requires extensive environmental documentation, including
environmental assessments, and develops environmental impact
statements for drilling on Federal land.
EPA's Region IX regulates the reinjection of produced fluids
under the UIC program.
STATE RULES AND REGULATIONS
The Regulations and Rules of Practice and Procedures under
Chapter 522 of the Nevada Revised Statutes of the Oil and Gas
Conservation Law were adopted by the Department of Minerals on
December 20, 1979. Section 200.1 of these rules states that,
"Fresh water must be protected from pollution whether in
drilling, plugging or producing oil or gas or in disposing of
salt water already produced." The -regulations govern the
"drilling, safety, casing, production, abandoning and plugging of
wells." The regulations do not include a provision for allowing
or disallowing discharges nor is their mention of a discharge
allowance. Section 308, however, states that all excavations
must be drained and filled and the surface leveled so as to leave
the site as near to the condition encountered when operations
were commenced as practicable. Section 407 further states that
"Oil or oil field wastes may not be stored or retained in unlined
pits in the ground or open receptacles except with the approval
of the Division." Section 600.1 states that, "The underground
disposal of salt water, brackish water, or other unfit for
domestic, livestock, irrigation or other use, is permitted only
upon approval of the Administrator."
Region IX regulates the underground injection of wastes from oil
wells under the UIC program. The applicable regulations are
found in 40CFR 144 and 146.
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REFERENCES
Proceedings of the Onshore Oil and Gas State/Federal Western
Workshop. Summary of presentation given by Scott
McDaniel, Nevada Department of Minerals. December
1985.
Nevada Department of Conservation and Natural Resources,
Division of Mineral Resources. Regulations and Rules
of Practice and Procedures. Chapter 522. December 20,
1979.
Personal Communications:
Cathy Loomis, Engineering Technician, Nevada Department
of Minerals, September 26, 1986 (702) 885-5050.
Dan Gross, Division of Environmental Protection, Department
of Conservation and Natural Resources, September 26, 1986
(702) 885-4670.
Ellis Hammett, Permit Processor, Nevada Bureau of Land
Management, September 26, 1986 (702) 784-51236.
Nate Lau, Director, UIC Division, EPA Region IX,
September 26, 1986 (415) 974-0893.
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NEW MEXICO
INTRODUCTION
New Mexico produced 75,532,000
barrels of oil and 965.7 x 109
cubic feet of gas in 1984,
ranking fourth in U.S. gas pro-
duction and eighth in U.S. oil
production. Production is from
24,954 oil wells and 17,523 gas
wells. Twenty percent of oil
production is from the stripper
well category.
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activities in New Mexico:
New Mexico Energy and Minerals Department
New Mexico Water Quality Control Commission
- U.S. Bureau of Land Management
- Indian Tribes
The New Mexico Energy and Minerals Department, Oil Conservation
Division, is responsible for regulating the oil and gas industry.
It regulates exploration and drilling, production, and refining
with respect to protection of water quality.
New Mexico has very few statewide specific rules relating to oil
and gas activities because of the diversity of the climate,
diversity of the geology, and diversity of the quantity and type
of waste that is produced. There is a plugging bond requirement
that endures until well abandonment has been approved by the
Division.
The U.S. EPA has the responsibility for NPDES permitting in New
Mexico; however, the State Environmental Improvement Division
certifies those permits. No NPDES permits have been issued for
the New Mexico oil and gas industry drilling and production
facilities.
The New Mexico Water Quality Control Commission, Environmental
Improvement Division, is prohibited from taking any action which
would interfere with the exclusive authority of the Oil
Conservation Commission over all persons and things necessary to
prevent water pollution as a result of oil or gas operations.
The Environmental Improvement Division administers and enforces
Commission regulations at brine manufacturing operations and
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concerning discharges to ground or surface waters at brine
manufacturing operations, including all brine production wells,
holding ponds, and tanks. The Oil Conservation Division
regulates brine injection through its Class II UIC program if the
brine is used in the drilling for or production of oil and gas.
The Environmental Improvement Division regulates brine injection
through its UIC program if the brine is used for other purposes.
The U.S. Bureau of Land Management takes the lead on'oil and gas
drilling activities on Federal lands. Where drilling on Federal
land occurs, two drilling permits would be issued—one from the
Bureau of Land Management and one from the State. The State
would maintain primacy in waste disposal activities associated
with any such drilling or production activities.
Issues with drilling on Indian lands currently remain unresolved.
Some Tribes have issued regulations concerning oil and gas
drilling and production activities., Some Tribes have applied for
UIC program delegation. The State has not waived jurisdiction in
regard to regulating the oil and gas industry on Indian lands,
however. Where Tribe regulations go beyond those of the State,
the Tribe regulations prevail.
STATE RULES AND REGULATIONS
DRILLING
No drilling fluids are authorized to be discharged to surface
waters. Drilling fluids must be disposed of at the well site in
a manner to prevent water contamination; they cannot be removed
to another site without approval of the District Supervisor.
There is a fine of $1,000 per day for violating this rule. All
drilling and reserve pits must be built large enough to hold all
drilling mud and waste fluids at each well location.
The Rules and Regulations are general and allow for a great deal
of flexibility in managing day-to-day situations. Different
district managers manage conditions with some variation from
district to district, which leads to a case-by-case approach in
management.
Commission Rule 310 requires that all oil or distillate tanks,
the location of which constitutes an objectionable hazard, be
surrounded by a dike or fire wall having a capacity one-third
larger than the capacity of the enclosed tanks. Any tank used in
the oil and gas industry and located within 1,000 feet of a river
or irrigation canal is deemed to be a hazard under this rule and
is required to have a fire wall or dike constructed.
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PRODUCTION
In 1985, a modified statewide produced water rule was promulgated
by the Oil Conservation Division that prohibits disposal on the
surface of the ground or in any pit, pond, lake, depression,
draw, stream bed, arroyo, in any water course, or in any other
place or in any other manner which constitutes a hazard to fresh
water supplied. Fresh water is defined as water having 10,000
mg/1 or less of total dissolved solids, unless it is "found that
there is no reasonably foreseeable beneficial use which would be
impaired by contamination of such water. Produced water may be
used in road construction with approval of the District
Supervisor.
6
There are 1985 requirements that evaporation pit linings must be
approved. The New Mexico Oil Conservation Division has issued
guidelines for pit liners and below-grade storage tanks, and
applications are now being accepted under the order that was
adopted in June 1985.
There are two specific orders requiring disposal of produced
water in New Mexico. One order instituted in 1969 bans all
disposal in unlined pits in the southeastern part of the State.
The second order requires that no unlined pits receive more than
five barrels per day in shallow groundwater areas in northwest
New Mexico.
In 1984, 337 million barrels of brine were produced from oil
wells, and another 5.5 million barrels were produced from natural
gas, for a total of 342 million barrels. One hundred fifty-three
million barrels were disposed of in injection wells for secondary
recovery and pressure maintenance. Approximately 43 percent of
the state's oil yield is produced through secondary recovery and
pressure maintenance wells. One hundred fifty-nine million
barrels were injected into saltwater disposal wells. There are
roughly 4,500 injection wells for secondary recovery and another
300 injection wells for salt water disposal. Thirty-one million
barrels of produced water were disposed of in permitted ponds or
in unlined pits, or were used as secondary recovery makeup water.
Most of the produced water is disposed by injection and a very
small percent is disposed of using surface methods. None of
these surface methods includes disposal into any streams or water
courses.
Contamination now is being detected related to oil and gas
activities which occurred three or four decades ago. These cases
may be related to improper casing, pit construction, or any
number of practices. Little groundwater monitoring has been
done, so the extent of damage is unknown.
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OFFSITE AND COMMERCIAL PITS
Operators trucking pit contents away from a sensitive area of the
State must dispose of the fluids in a pond approved for ground-
water protection. Some of these sites are located high atop
mesas where there are unsaturated geological strata. Little, if
any, groundwater contamination is expected from these sites.
Three different off site disposal methods have been ap'proved. The
first involves moving the drilling mud to another drilling pit.
The second is land application. The third is to seal stock
watering ponds and catch ponds in the San Juan basin. In the
latter case, the operator and the land owner coordinate with the
Soil Conservation Service, which has standards for the appli-
cation of these materials to pond soils.
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REFERENCES
New Mexico Meeting Report. 1985. Proceedings of the
Onshore Oil and Gas State/Federal Western Workshop.
U.S. Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
K
State of New Mexico, Energy and Minerals Department, Oil
Conservation Division. Rules and Regulations. April
1, 1986.
State of New Mexico. Water Quality Control Commission
Regulations. March 3, 1986.
Chavez, Frank. 1985. "Management and Regulation of
Drilling Waste Disposal: The New Mexico Approach."
Proceedings of a National Conference on Disposal of
Drilling Wastes. University of Oklahoma Environmental
and Ground Water Institute, Norman, OK, pp. 151-164.
Order of the Oil Conservation Commission of the State of New
Mexico, Order No. R-3221.
Order of the Oil Conservation Commission of the State of New
Mexico, Order No. R-7940-A.
Memorandum, R. L. Stamets, Director, Oil Conservation
Commission, regarding Hearings for Exceptions to Order
No. R-3221, dated October 22, 1985.
Personal Communication:
David Boyer, Hydrogeologist, New Mexico Oil Conservation
Division, (505) 827-5802.
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NEW YORK
INTRODUCTION
New York is one of the pioneer
States for oil and gas produc-
tion and use. Proven oil
reserves were documented in
1627, and drilling began in the
late 1800s. Since then it is
estimated that 30,000 to 50,000
wells have been drilled in New
York.
New York produced 952,000
barrels of oil from 4,678 wells
in 1984. Twenty-seven billion
cubic feet of natural gas was
produced from 3,800 gas wells
in 1984.
REGULATORY AGENCIES
BACKGROUND
In 1963 the New York legislature passed laws regarding oil and
gas operations. A working permitting system was instituted in
1966 under the purview of the Department of Environmental
Conservation. The regulations have been revised fairly often
over the last twenty years. In fact, further revisions are
expected in the next year or two as a result of a Generic
Environmental Impact Statement scheduled for completion in mid-
1987.
AGENCIES
Oil and gas activities in New York are regulated by:
- NY Department of Environmental Conservation
Bureau of Land Management (Federally-held mineral
rights only)
- U.S. Forest Service (surface activities in U.S.
forests)
Most oil and gas activities in New York are regulated by the
Department of Environmental Conservation. The Department of
Environmental Conservation is authorized to regulate the
"development, production, and utilization of natural resources of
oil and gas ... in such a manner that a greater ultimate
recovery of oil and gas may be had." The Department also has
authority for "prevention of pollution and migration." New York
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is NPDES-delegated, with the Department of Environmental
Conservation responsible for the program. New York does not have
UIC primacy.
The Department of Environmental Conservation is not entirely
independent. Within the Department of Environmental Conser-
vation, the Oil, Gas, and Solution Mining Advisory Board (with a
majority of industry representatives) has input in the
development of rules and regulations.
The U.S. Bureau of Land Management has regulatory authority for
oil and gas activities when mineral rights are Federally held.
Their regulations are discussed in a separate section, Federal
Agencies.
The U.S. Forest Service has jurisdiction over surface activities
on federal forest lands even when mineral rights are held
privately.
The Water Quality Division, Fish and Wildlife Division,
Regulatory Affairs, Law Enforcement, and Lands and Forests
provide instrumental manpower and enforcement actions, when
applicable.
RULES AND REGULATIONS
DRILLING
The Division of Mineral Resources (within the Department of
Environmental Conservation) issues all oil and gas drilling
permits. Each permit requires that the fluids generated by
drilling be "hauled away and properly disposed of." The
regulations are unclear regarding what practices constitute
proper disposal.
"Pollution of the land and/or of surface or ground fresh water
resulting from exploration or drilling is prohibited." Part 554
Section 554.1 of the Mineral Resources Regulations requires the
operator "to submit and receive approval for a plan for the
environmentally safe and proper ultimate disposal of such
fluids." Drilling muds are specifically excluded from this
requirement; "Drilling muds are not considered to be polluting
fluids." Drilling pits are dewatered and the fluid disposed of
properly prior to reclamation. During reclamation, pit liners
are shredded or removed and the rock cuttings disposed in situ.
After drying, the cuttings are buried.
Other drilling wastes must be disposed or discharged in a manner
acceptable to the Department considering the environmental
sensitivity and geology of the area. Historical experience with
drilling operations in the same area may also be used in
considering an application. Permits may be required for disposal
or discharge of drilling wastes (excluding drilling muds) in
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addition to the drilling permit. Drilling muds are not defined
in the regulation; it is unclear whether this term is intended
specifically for rotary drilling muds, or if the term is
inclusive of all fluids used in drilling. Ninety-five percent of
New York drilling utilizes rotary air drilling technology.
Brine and salt water generated during drilling are considered
"polluting fluids" in the Mineral Resources Regulations. These
fluids, and other polluting fluids, may be stored in watertight
tanks or earthen pits for up to 45 days after drilling ends prior
to disposal. An extension may be granted if the operator plans
to use^the fluids for later activities. The regulations do not
specify what disposal alternatives may be ultimately acceptable
for disposal of brines and salt water generated during drilling.
The Department is also responsible for well construction,
spacing, and plugging requirements.
PRODUCTION
Part 556 of the Mineral Resources Regulations addresses operating
practices applicable to oil and gas wells. Section 556.5
prohibits pollution of the land and/or surface or ground fresh
water resulting form producing, refining, transportation, or
processing of oil, gas, and products. Brine (i.e., produced
water) may be stored in water-tight tanks or in earthen pits
prior to disposition. Although specific construction
requirements are not described in the regulation, earthen pits
must be constructed to prevent percolation into the soil, over or
into adjacent lands, streams, or bodies of water.
The only disposal alternative described in the regulation is
injection. The Department of Environmental Conservation has
procedures for application and approval of permits to inject
brines.
Although the regulations do not address road spreading, it is the
predominant brine disposal method in New York. Road spreading is
conducted on a manifest system under a separate permit.
Although it is not discussed in the regulations, the Department
of Environmental Conservation allows "processing [of brines] at
sewage disposal plants, permitted onsite discharges, and hauling
to other states with approved disposal facilities." Brine
discharges from stripper wells is permitted under the following
limitations:
oil and grease 15 mg/1
pH 6 to 9
benzene 10 micrograms/1
toluene 10 micrograms/1
xylene 10 micrograms/1
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Sampling is done infrequently on any given well. Annular
disposal is not allowed.
OFFSITE PITS
New York regulations do not address the use of offsit'e pits for
long term storage or disposal.
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REFERENCES
Interstate Oil Compact Commission, The Oil and Gas Compact
Bulletin, Volume XLIV, Number 2, December 1985.
Cornell University, "Oil, Gas and Solution Mining
Legislation in New York As Amended through September
1985."
New York State Statute 550.2, Subchapter B - "Mineral
Resources," Parts 550 through 558, as amended.
New York State Environmental Conservation Law, Article 23,
Title 1-5 (circa 1985).
New York Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas Workskop, U.S. EPA, Washington, D.C., March
26-27 in Atlanta, GA) . July 1985.
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NORTH DAKOTA
INTRODUCTION
North Dakota produced
52,654,000 barrels of oil and
80 x 109 cubic feet of gas in
1984. Production is from 4,026
oil wells and 58 gas wells.
This 1984 figure for oil
production established a record
high production figure for the
State.
STATE REGULATORY AGENCIES
Three agencies regulate oil and gas activity in North Dakota:
North Dakota Industrial Commission
U.S. Department of Agriculture, Forest Service
- U.S. Bureau of Land Management
The North Dakota Industrial Commission, Oil and Gas Division, has
the regulatory responsibility to oversee the drilling and
production of oil, protect the correlative rights of the mineral
owners, prevent waste, and protect all sources of drinking water.
Other responsibilities of the Division are to collect monthly
reports on oil, gas, and water; oversee proper disposal of brine;
and issue drilling permits. The Division also has primacy for
UIC Class II wells and issues such permits.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. When drilling is to occur on U.S.
forestland, no additional permit is needed but additional
stipulations are placed by the U.S. Forest Service.
STATE RULES AND REGULATIONS
DRILLING
Before a drilling permit is issued by the Commission, the
operator of the well must be bonded. Single well bonds are
$15,000, a ten-well bond is $50,000, and a blanket bond is
$100,000. The Commission will release the bond after site
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restoration is approved. Before drilling activities, Commission
inspectors will survey the site for pit location. The inspectors
also decide whether or not to require a pit liner at the site.
Under Commission Rule 43-02-03-19, "Pits shall not be located in,
or hazardously near, stream courses, nor shall they block natural
drainages. Pits shall be constructed in such manner so as to
prevent contamination of surface or subsurface waters by seepage
or flowage therefrom. Under no circumstances shall pits be used
for disposal, dumping or storage of fluids, wastes and other
debris not used in drilling operation." Within 1 year after the
completion of a well, the pit site must be restored. Pit
restoration does require approval from the Commission. Recla-
mation includes redistributing topsoil that was removed from the
site at the beginning of drilling activities.
When drilling is on U.S. forest lands, the U.S. Forest Service
has additional stipulations on top of those of the Commission.
The Forest Service requires a complete survey and design of the
drilling site. This survey must be approved before drilling.
All reserve pits must be lined with a material that has a minimum
burst strength of 150 psi. Tanks must be diked. The site
reclamation plan must also be approved by the Forest Service
before implementation.
PRODUCTION
Under Commission Rule 43-02-03-53, "All saltwater liquids or
brines produced with oil and natural gas shall be disposed of
without pollution of freshwater supplies. At no time shall
saltwater liquids or brines be allowed to flow over the surface
of the land or into streams." Surface pits are not allowed for
brine storage. Surface tanks are allowed provided they are diked
and are leak-proof. Brine may be disposed by use of injection
wells or disposal wells; both methods require permits issued by
the Commission.
When a central tank battery or central production facility is
planned to be used, approval must be received from the Commission
or by the forest Service if on U.S. forest lands.
OFFSITE AND COMMERCIAL FACILITIES
Offsite pits are not addressed in the Commission regulations.
Offsite treatment facilities require a permit from the
Commission. Before treatment operations commence, the facility
is required to put up a bond of $25,000 to the Commission.
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REFERENCES
North Dakota Industrial Commission, Statutes and Rules for
the Conservation of Oil and Gas. January 1985.
Williams, Tex. State regulatory information submitted in
1985.
U.S. EPA. North Dakota Meeting Report. Proceedings of
Onshore Oil and Gas State/Federal Western Workshop.
U.S.EPA,Washington D.C. (December 1985).
U.S. Department of Agriculture, Special Forest Service
stipulations, September 1986.
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OHIO
INTRODUCTION
Ohio produced 15,271,000
barrels of oil and 186.5 x 109
cubic feet of gas in 1984 from
1,830 full producing oil wells
and approximately 24,263
stripper wells producing less
than 10 barrels per day, and
14,762 full producing gas wells
and approximately 60,000
stripper wells producing less
than 60,000 cubic feet per day.
STATE REGULATORY AGENCIES
Two agencies regulate oil and gas activities in Ohio:
Ohio Department of Natural Resources
- Ohio Environmental Protection Agency
The Ohio Department of Natural Resources, Division of Oil and
Gas, issues permits for oil and gas drilling and for underground
brine injection. The statutes and rules of the Division of Oil
and Gas do not contain provisions for effluent discharges. The
Division operates on revenues from permit and other similar fees.
Enforcement activities are dependent primarily upon approximately
50 field staff employees who inspect well sites and conduct
investigations. The Division of Oil and Gas has authority to
review, investigate, and require corrective action related to all
oil and gas drilling and production activities. Compliance bond
and well spacing are requirements of the Division.
Ohio has been delegated NPDES authority. NPDES permits are
issued through the Ohio Environmental Protection Agency, Water
Quality Division; none is issued for the oil and gas drilling and
production industry. The jurisdiction of the Ohio EPA extends to
any pollution of the waters of the State. Where brine spills may
impair waters of the State, for example, there is coordination
between the Ohio DNR and Ohio EPA in damage assessment and
corrective measures. When there is potential for groundwater
contamination, the Ohio Environmental Protection Agency may
assist in the investigation and joint charges may be filed with
the Ohio Department of Natural Resources.
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A five-member oil and gas Board of Review was created by statute
within the Ohio Department of Natural Resources with 5-year terms
consisting of representatives of a major petroleum company, the
public, independent petroleum operators, one learned and
experienced in oil and gas law, and one learned and experienced
in geology, as appointed by the Governor. Any person claiming to
be aggrieved or adversely affected by an order of the Chief of
the Division of Oil and Gas may appeal to the Board for an order
vacating or modifying such an order.
Rarely, there is oil and gas drilling on Federal lands. When
application for such drilling is filed, the permittee obtains a
lease from the appropriate Federal authority prior to requesting
a permit from the Division of Oil and Gas. The permitting
process then is managed as a standard procedure with no special
coordinating efforts.
STATE RULES AND REGULATIONS
DRILLING
Pursuant to Section 1509.22 of the Ohio Revised Code, substances
resulting, obtained, or produced in connection with the
exploration, drilling or production of oil and gas must be
injected into an underground formation approved by the Chief,
Division of Oil and Gas, or disposed by an approved alternative
method. Alternative methods include annular disposal, disposal
in association with an enhanced recovery project, or road
spreading for dust and ice control.
Earthen brine pits may have caused most of Ohio's contamination
problems. Pursuant to recently enacted legislation, pits are
required to be water tight either by clay or plastic liner. A
pit life beyond 180 days is prohibited. Pits will be allowed
only for drilling, reconditioning, plugging, or other limited
use.
In most cases, pit solids are buried on the well site when no
environmental harm is expected. When there is a history of
groundwater problems associated with an area, a plastic liner
requirement is made a part of the drilling permit.
PRODUCTION
Recently enacted laws, which became effective on April 12, 1985,
established new standards for well operators and waste brine
transporters. Brine disposal is one of the major problems in
Ohio. Well drillers now are required to submit a brine disposal
plan identifying the transporter of the brine including the
transporter's address. Anyone who transports brines must pay a
$500 one-time fee, provide a $300,000 certificate of insurance
for bodily injury and liability, post a $15,000 bond to be used
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in paying for damages, and provide detailed information. The
detailed information includes a daily log that identifies
ultimate brine disposal such as time and date of brine loading
and amount, road spreading location, disposal well permit number,
time and date of brine disposal, etc. The driver is required to
maintain a daily log showing driver name, registration
certificate number, sites visited, and destination. Brine
production is estimated at 160,000 barrels per day.
For road or land spreading, a township must pass a resolution to
allow brine disposal that meets five minimum requirements: it
must regulate the rate and amount of application, prohibit
spreading when ground is water saturated, regulate the spreader
speed, 'require use of a dispersion bar, and prohibit direct spray
on vegetation. The resolution then is considered for approval by
the Department of Natural Resources.
When a well is abandoned, following permission for such by the
Division Chief, a detailed report containing information and
names and addresses of witnesses to the plugging of the well must
be signed and filed by the owner and operator of the well. When
a well is plugged, the drill site must be restored, the area
including pit site is.to be returned to its natural contour, all
trash is to be removed, and the site is to be seeded.
OFFSITE AND COMMERCIAL PITS
When such a groundwater problem history exists, pit solids may be
required to be removed and transferred to an Ohio EPA regulated
disposal site. Or, if there is a request to move pit solids to
an offsite area, an EP-toxicity test for hazardous waste
characteristics is required prior to a transfer to a State-
approved hazardous or nonhazardous landfill, as appropriate.
Abandoned pits are investigated when alleged to be the cause of a
groundwater problem. When found to contribute to such a problem,
the owner of the pit is required to remove solids and transport
them to a State-approved solids disposal facility.
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REFERENCES
Chapter 1509 of the Ohio Revised Code.
Chapter 1501, Rules of the Division of Oil and Gas of the
Ohio Department of Natural Resources.
Summary of State Statutes and Regulations for Oil and" Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Hodges, David H. 1985. Letter Communication to EPA.
Division of Oil and Gas, Ohio Department of Natural
Resources.
Ohio Meeting Report. 1985. Proceedings of the Onshore Oil
and Gas Workshop. U.S. Environmental Protection
Agency, Washington, D.C. (March 26-27 in Atlanta, GA)
Personal Communications:
David A. Hodges, DNR, Division of Oil and Gas
(614) 265-6917.
Ted De Brosse, DNR, Division of Oil and Gas
(614) 265-6894.
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OKLAHOMA
INTRODUCTION
Oklahoma produced 153,250,000
barrels of oil and 1,996 x 109
cubic feet of gas in 1984. It
ranked fifth in U.S. oil
production and third in U.S.
gas production. Oklahoma had
99,030 producing oil wells and
23,647 producing gas wells.
There are approximately 200
million barrels of salt water
produced by the oil industry
per year. There are about
5,200 saltwater disposal wells
and 9,900 enhanced recovery
injection wells. Approximately
100 of the disposal wells are
commercial facilities.
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activities in Oklahoma:
- Oklahoma Corporation Commission, Oil and Gas
Conservation Division
Oklahoma Department of Health Water Resources Board
- Osage Indian Tribe
U.S. Bureau of Land Management
The Oklahoma Corporation Commission has the exclusive
jurisdiction for regulating the disposal of waste from oil and
gas activities. Pollution of surface or subsurface water during
any well activity is prohibited. Currently, there are 55
inspectors who have the authority to shut down operations if
regulations are not followed. Well activity is defined in Rule
3-101 as exploration, drilling, producing, refining,
transporting, or processing of oil and gas. Oklahoma has
received primacy for the UIC program.
The Water Resources Board of the Oklahoma Department of Health
protects all surface and ground waters to ensure that pollution
does not occur and that discharges meet specified beneficial uses
outlined in water quality standards. Oklahoma has not been
delegated NPDES authority. However, discharges to water from oil
and gas activities are not permitted. The Water Resources Board
issues land application permits for reserve pit fluids.
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The Osage Indian Tribe has sole primacy regarding oil and gas
operations in Osage County and has been delegated UIC program
responsibility for Class II wells.
The U.S. Bureau of Land Management has primacy where both surface
and mineral rights are owned by the Bureau or by an Indian Tribe
other than the Osage Tribe. In those cases where mineral rights
are owned by the Bureau or an Indian Tribe, but not the surface
rights, both the Bureau and the Oklahoma Corporation Commission
would become involved and would coordinate the permitting
procedures.
STATE RULES AND REGULATIONS
DRILLING
Corporation Commission Rule 3-104 specifies that pits and tanks
for drilling mud or deleterious substances used in the drilling,
completion, and recompletion of wells shall be constructed and
maintained to prevent pollution of surface and subsurface fresh
water. A written permit is issued for the use of an onsite
earthen pit (Rule 3-110.1 ). Any reserve mud pit used in
drilling, deepening, testing, reworking, or plugging a well must
be emptied and leveled within a maximum of 18 months after the
drilling operations cease (Rule 3-110.1(d)(2)).
Reserve drilling pit fluids are permitted on a one-time basis by
the Water Resources Board to be spray-applied to land as a part
of pit closure providing certain limits are met. These limits
include a pH range of 6.5 to 9.0 and not to exceed:
Chlorides 1,000 mg/1
Total chromium 0.2 mg/1
Chemical oxygen demand 250 mg/1
Total dissolved solids 3,000 mg/1
Oil and grease 30 mg/1
Total sodium 750 mg/1
Specific conductance 4,600 u mhos
Special field rules have been adopted that prohibit the use of
pits in certain areas. This has caused the use of offsite
reserve pits for a particular well.
Drilling fluid must be disposed of by one of three ways: Annular
injection, evaporation then closure of a reserve pit, or vacuum
truck removal to offsite earthen pits. A manifest is required
for offsite transportation. High chloride content drilling
fluids are injected into a Class II well.
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PRODUCTION
Underground disposal of high chloride produced water is required
either in disposal wells or enhanced recovery injection wells.
There are about 5,200 of the former and 9,900 of the latter. The
Oil and Gas Commission has been delegated UIC program activities
for Class II wells.
OFFSITE AND COMMERCIAL PITS
Rule 3-110.2 of the Oklahoma Corporation Commission permits the
use of "offsite earthen pits provided they are sealed with an
impervious material, do not receive outside runoff water, and are
filled and leveled within 1 year after abandonment. The chloride
content of the contained fluids shall not exceed 3,500 mg/1.
Drilling muds containing both solids and fluids may be
transported to such commercial pits.
Offsite pits are created by excavating, damming gullies, and
using abandoned strip pits. There are approximately 95 offsite
pits throughout Oklahoma, ranging as large as 15 acres. They are
sampled periodically to enforce a maximum 3,500 parts per million
chloride concentration requirement, if the pit bottom mud cannot
meet chloride limits, it must be effectively treated and hauled
to a hazardous waste disposal site. Some offsite pits are large
and may contain over 3,000,000 barrels of waste, which calculates
to 387 acre feet of fluids.
Owners of new pits are required to install and sample monitoring
wells, principally for chlorides and pH. There is a proposal,
currently, to made such requirement applicable to existing
offsite pits. Three wells would be required—one upgradient and
two downgradient. Any indicated change over background in the
constituent levels tested would indicate potential pollution.
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REFERENCES
Oklahoma Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas State/Federal Western Workshop. U.S.
Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
General Rules and Regulations of the Oil and Gas
Conservation Division, The Corporation Commission of
the State of Oklahoma (1986).
Oklahoma Drilling Waste Conference.
Personal Communications:
Mike Battles, Manager of Pollution Abatement, Oklahoma
Corporation Commission (405) 521-4456
Karen Dihrberg, Geologist, Water Resources Board
(405) 271-2549.
Margaret Graham, Permits, Water Resources Board
(405) 271-2561.
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OREGON
INTRODUCTION
Oregon does not produce oil.
Oregon's only producing gas
field was discovered in 1979.
Eleven active gas wells
produced 2.8 x 109 cubic feet
of gas in 1984. There are four
additional wells that are
capable of production but
currently these are not
producing wells. There is one
saltwater injection well for
the field. In 1984, approxi-
mately 100,000 barrels of brine
were injected underground;
about 19,000 barrels went to
surface land disposal.'
STATE REGULATORY AGENCIES
Two agencies regulate oil and gas activity in Oregon:
Oregon Department of Geology and Mineral Industries
- Oregon Department of Environmental Quality
Oil and gas drilling permits are issued by the Oregon Department
of Geology and Mineral Industries. The State Geologist serves as
the implementor of rules, orders, and enforcement actions taken
by the Department's governing board.
The Oregon Department of Environmental Quality has delegated
authority for the NPDES program and issues UIC permits. The
State has maintained a permitting program since 1968. No NPDES
permits have been issued because there have been no requests to
discharge waste to public waters.
None of the gas wells is on Federal lands. All are located where
Columbia County owns the mineral rights. If, in the future,
drilling were to take place on Federal lands, there would be two
separate permitting actions—one by the U.S. Bureau of Land
Management and one by the Oregon Department of Geology and
Mineral Industries.
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STATE RULES AND REGULATIONS
DRILLING
Oregon Administrative Rule 632-10-205 requires a surety bond of
up to §25,000 for one well, or a blanket bond of $150,000 for
more than one well, conditioned upon the faithful compliance by
the principal with the rules, regulations, and orders, of the
Department of Geology and Mineral Industries.
Rule 632-10-140 requires that any fluid necessary to the
drilling, production, or other operations by the permittee shall
be discharged or placed in pits and sumps approved by the State
Geologist and the State Department of Environmental Quality, The
operator shall provide pits, sumps, or tanks of adequate capacity
and design to retain all materials. In no event shall the
contents of a pit or sump be allowed to:
1. Contaminate streams, artificial canals or
waterways, groundwaters, lakes, or rivers.
2. Adversely affect the environment, persons,
plants, fish, and wildlife and their
population.
When no longer needed, fluid in pits and sumps is to be disposed
of in a manner approved by the Department of Environmental
Quality and the sumps filled and covered and the premises
restored to a near natural state. The restoration need not be
done if arrangements are made with the surface owner to leave the
site suitable for beneficial subsequent use.
Drilling mud pits are not allowed to hold over winter because of
lack of sufficient storage for winter rainfall. If drilling muds
dry in the reserve pits before winter occurs, the pit is then
closed.
There has not been a problem with abandoned pits; the surety bond
provides a mechanism to ensure adequate pit closure.
PRODUCTION
Rule 632-10-192 of the Department of Geology and Mineral
Industries provides that brines or saltwater liquids may be:
1. Disposed in pits only when the pit is lined
with impervious material and a Water
Pollution Control Facility permit has been
issued by the Department of Environmental
Quality. Earthen pits used for impounding
brine or salt water shall be so constructed
and maintained as to prevent the escape of
fluid.
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2. Disposed by injection into the strata from
which produced or into other proved salt-
water bearing strata.
3. Disposed by ocean discharge, which may be
permitted if water quality is acceptable and
if such discharge is approved by the State
Department of Environmental Quality through.
issuance of a National Pollutant Discharge
Elimination System waste discharge permit.
Produced brines are permitted to be spread on dirt roads—
predominantly logging roads—when such is done in dry weather.
OFFSITE AND COMMERCIAL PITS
There are no operational offsite pits. One dump-site has been
used as an emergency pit. Operators must dispose of drilling
muds in a Department of Environmental Quality approved solid
waste disposal site. Such solids may be tested prior to disposal
to determine if they contain hazardous materials.
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REFERENCES
Oregon Meeting Report. 1985. Proceedings of the Onshore
Oil and Gas State/Federal Western Workshop. U.S.
Environmental Protection Agency, Washington, D.C.
(December 1985).
Summary of State Statutes and Regulations for Oil and- Gas
Production.1986.Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Olmstead, Dennis L. 1985. Letter Communication to EPA.
Oregon Department of Geology and Mineral Industries.
Personal Communications:
Dan Wermiol, Department of Geology and Mineral Industries
(503) 229-5580.
Kent Ashbaker, Department of Environmental Quality
(503) 229-5325.
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PENNSYLVANIA
INTRODUCTION
Pennsylvania produced 4,825,000
barrels of oil and 166 x 109
cubic feet of gas in 1984.
Production was from 20,739 oil
wells and 24,050 gas wells.
Until 1955, environmental
requirements for the oil and
gas industry were minimal if
not nonexistent. State laws
did not require permitting or
registration of oil and gas
wells. In 1961, the statutes
were strengthened to prohibit
wasting in production wells,
establish spacing, and provide other requirements. It was not
until 1984 that the Coal and Resource Coordination Act and the
Oil and Gas act made sweeping changes in permit review and
requirements. There had been little uniformity in Pennsylvania
oil and gas laws until then. Combined, these statutes enable
Pennsylvania permitting authority to put terms and conditions on
permits, and to deny permits. Passage of House Bill 1375 in mid-
September, 1986, further strengthens the regulatory management of
the oil and gas industry in Pennsylvania, and requires the
development of new regulations relating to solid waste management
and the disposal of wastes onsite.
The first commercial oil well was drilled near Titusville, PA,
1859.
STATE REGULATORY AGENCIES
Five agencies regulate oil and gas activities in Pennsylvania:
- Department of Environmental Resources, Bureau of Oil
and Gas Management
U.S. Environmental Protection Agency, Region III
- Pennsylvania Fish Commission
U.S. Forest Service
- U.S. Bureau of Land Management
The Bureau of Oil and Gas Management was created in 1984 to
coordinate and combine all related regulatory activities of the
oil and gas industry. The Oil and Gas Conservation Law, enacted
in 1961, established powers and duties of the Oil and Gas
Conservation Commission. Those powers and duties were
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transferred to the Department of Environmental Resources in 1970.
The Oil and Gas Act of 1984 created an Oil and Gas Technical
Advisory Board to advise the Department in regulatory activities
(Section 216 of 1984 Act). The five-member board consists of
three representatives of the oil industry, one from the Citizen's
Advisory Council, and one from the coal industry.
Section 207(a) of the Act requires that the disposal of drilling
and production brines be consistent with the requirements of the
Clean Streams Law. Section 208(a) requires that any well owner
who affects the public or private water supply by pollution or
diminution shall restore or replace the affected supply with an
alternative source. Section 205 prohibits drilling of wells
within ,200 feet of buildings or water wells without the consent
of the owner, within 100 feet of any body of water, or within 100
feet of a wetland 1 acre or more in size.
There is a compliance bond conditioned on the operator's faithful
performance of the drilling, restoration, water supply replace-
ment, and well plugging requirements of the Oil and Gas Act. The
passage of House Bill 1375 transferred NPDES permitting authority
in the oil and gas industry—already delegated to the State—to
the Bureau.
The U.S. Environmental Protection Agency, Region III, issues UIC
program permits for underground injection and secondary recovery.
The Bureau of Oil and Gas Management has not sought primacy in
the UIC program.
The Pennsylvania Fish Commission seeks out pollution of surface
waters and takes appropriate action under the Pennsylvania Fish
and Boat Code.
The U.S. Forest Service and the U.S. Bureau of Land Management
provide requirements they may have in lease agreements. The well
driller must demonstrate his notification of landowners and water
supply owners of the intent to drill. Mineral rights in the
Allegheny National Forest are privately owned. The Bureau of Oil
and Gas Management issues drilling permits on Federal lands.
STATE RULES AND REGULATIONS
DRILLING
Drilling pits to the present time have been virtually
unregulated. Pits typically are unlined. Such pits contain
drilling cuttings, contaminated fresh and salt water produced
during construction and well stimulation, and various additives
used during drilling and well stimulation. Pits are not
reclaimed and no permit is required for a drill pit. There is no
contingency fund for management of abandoned pits.
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The Bureau is in the process of developing regulations to further
control oil and gas operations. The thrust on drilling pits is
to remove liquids to an offsite and commercial treatment and
disposal facility and to dispose of solids waste on site with pit
reclamation.
PRODUCTION
It has been estimated that Pennsylvania has 17,000 impoundments
associated with oil and gas brines. If an impoundment is
associated with an individual well, a permit has not been
required. Permits are required for offsite and commercial
treatment systems. The trend since 1985 has been to move in the
direction of centralized treatment facilities for oil and gas
waste fluids. It is estimated that currently 20 percent of all
brines are transported to a treatment plant for treatment and
discharge. No manifest is required for transporting oil and gas
waste materials.
There are other production fluid disposal alternatives, which
include:
- Disposal wells
- Annular disposal
Treatment and discharge to surface waters
- Onsite treatment and land disposal of top hole water
- Discharge to existing treatment facility
Road spreading
- Evaporation (through waste heat)
OFFSITE AND COMMERCIAL PITS
Water Quality Management Part II permits and NPDES permits are
required for treatment facilities that discharge to waters of the
Commonwealth. Treatment afforded production fluids may include
flow equalization, pH adjustment, gravity separation and surface
skimming, retention and settling and, if necessary, aeration.
The discharges from several offside produced-fluids treatment
facilities may be covered under a single NPDES permit, if the
management of those facilities is under the control of one
owner/operator and the geographic area is such as to allow for
effective monitoring and surveillance.
The NPDES permit criteria and limits will be governed by
receiving water quality standards. Generally, however, total
suspended solids will be limited to an instantaneous maximum of
60 mg/1 and an average monthly of 30 mg/1. oil and grease will
be limited to an instantaneous maximum of 30 mg/1 and an average
monthly of 15 mg/1. Dissolved iron has an instantaneous maximum
of 7 mg/1, and the acidity shall be less than the alkalinity.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production.1986.Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission (December).
Slack, Peter. 1985. Letter Communication with EPA.
Division of Permits and Compliance, Bureau of Water
Quality Management, Department of Environmental
Resources.
Pennsylvania Meeting Report. 1985. Proceedings of the
Onshore Oil and Gas Workshop. U.S. Environmental
Protection Agency, Washington, D.C. (March 26-27 in
Atlanta, GA).
The Oil and Gas Act, Act of 12-19-84, P.L. 1140, No. 223.
The Oil and Gas Conservation Law, 1961, P.O. 825, No. 359.
Rules and Regulations, Department of Environmental
Resources, Chapter 97, Industrial Wastes.
Personal Communication:
Carlyle Westlund, Bureau of Oil and Gas Management
(717) 783-9645.
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SOUTH DAKOTA
INTRODUCTION
South Dakota produced 710,000
barrels of oil and 2.5 x 109
cubic feet of gas in 1984. The
State has 312 full production
and 33 stripper oil wells, and
41 full.production and 1
marginal production gas wells.
STATE REGULATORY AGENCIES
Four agencies regulate oil and gas activities in South Dakota:
South Dakota Department of Water and Natural Resources
South Dakota Department of School and Public Lands
U.S. Bureau of Land Management
U.S. Environmental Protection Agency, Region VIII
The South Dakota Department of Water and Natural Resources is the
primary regulatory agency for oil and gas operations through its
Oil and Gas Program in the Division of Environmental Quality.
The primary enforcement agency for the UIC program, and non-
delegated responsibility for NPDES compliance, is the Depart-
ment's Office of Water Quality. The Department of Water and
Natural Resources also houses the Board of Minerals and
Environment, which has power to conduct hearings and take action
on other oil and gas program related enforcement measures.
South Dakota has not been delegated NPDES authority. Two of the
active wells have NPDES permits because of beneficial use
associated with wastewaters. Draft NPDES permits are prepared by
the State and issued by the Water Management Division, U.S.
Environmental Protection Agency, Region VIII.
In the event of a desire to drill on Federal lands, two
applications for drilling would be filed—one with the State
Department of Water and Natural Resources, and one with the U.S.
Bureau of Land Management. The State would defer to the Bureau
regarding any pre-drilling permit investigation. Two permits,
one from each entity, would be issued to the driller. In the
event of a request to inject drilling fluids underground, the
Bureau would defer to the State, and the State would issue the
injection permit. The Bureau has no means of holding hearings,
and the State Board of Minerals and Environment would hold such
hearings prior to permit issuance.
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The South Dakota Department of School and Public Lands has
enforcement powers for lease compliance on State-owned lands and
for State-owned minerals.
STATE RULES AND REGULATIONS
DRILLING
Total retention evaporation ponds for brines, underground
injection wells for brines and drilling muds, and burial of
drilling muds are allowed. There are no specific requirements
related to pit construction.
Drilling pits may become a source of groundwater pollution,
depending upon local hydrologic conditions. There has been a
documented complaint of contamination from salt brines in an
unlined pit where groundwater was used for stock watering. This
complaint currently is in the negotiation phase. Currently,
also, the State is undertaking regulation revision, and con-
sideration is being given to a proposal to require that pits have
liners or be of impermeable construction.
When drilling operations cease, water in the pit is allowed to
evaporate and the mud is allowed to dry. The time interval for
this to occur is a various and unknown factor. When the mud has
sufficiently dried, the pit is buried and the surface is
reclaimed to natural conditions.
The Department of Water and Natural Resources requires a Plugging
and Performance Bond for wells, and a Surface Restoration Bond.
There is a well spacing requirement.
PRODUCTION
Discharge of brine from oil well production is allowed when a
beneficial use of the wastewater can be documented. An NPDES
permit is required for such discharge. The two NPDES permitted
discharges from wells in South Dakota are used for stock
watering. NPDES permits contain not-to-exceed limits for oil and
grease of 10 mg/1, total dissolved solids of 5,000 mg/1, and a pH
of 6.0 to 9.0. The flow is not to exceed 4,500 gallons per day.
OFFSITE AND COMMERCIAL PITS
There are no offsite pits in use, but if there were a request for
such usage, the request would be managed through the solid waste
permitting process.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production.1986.Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(December).
Pirner, S. M. 1986. Letter Communication to EPA. South
Dakota Department of Water and Natural Resources,
Office of Water Quality.
•
Personal Communications:
Steven M. Pirner, DWNR, Office of Water Quality (605) 773-
3351.
Fred V. Steece, DWNR, Supervisor of Oil and Gas Program
(605) 394-2385.
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TENNESSEE
INTRODUCTION
Tennessee produced about.
937,000 barrels of oil from 798
wells in 1984. Only 54 oil
wells produced more than 10
barrels of oil per day. Of 507
gas wells, 474 produce less
than 60 thousand cubic feet per
day.
Regulation of oil and gas
drilling operations began in
1968. Wells drilled prior to
1968 do not have to be
permitted unless they are
deepened, reopened, or
reentered.
STATE REGULATORY AGENCIES
Three agencies regulate oil and gas activities in Tennessee:
- State Oil and Gas Board
- Tennessee Department of Health and Environment
- U.S. Department of the Interior, Bureau of Land
Management
The state Oil and Gas Board is authorized by the Tennessee Code
Annotated (Revised 1982) for prevention of waste of petroleum
resources in Tennessee. The State Oil and Gas Board regulates
the industry according to the General Rules and Regulations
(Tennessee State Oil and Gas Board Statewide Order No. 2). The
State Oil and Gas Board issues drilling permits and regulates
surface disposal.
The Department of Health and Environment is the NPDES authority
in Tennessee. They do not currently have UIC primacy, but are
working towards being granted primacy by EPA. Discharges of oil
and gas wastes are not permitted by the Tennessee Department of
Health and Environment.
The U.S. Department of the Interior Bureau of Land Management has
jurisdiction over lease arrangements and post-lease activity on
Federal lands where the mineral rights are Federally held.
Surface rights in Federal forests and grasslands are retained by
the U.S. Forest Service.
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RULES AND REGULATIONS
DRILLING
The State Oil and Gas General Rules and Regulations are directed
towards prevention of waste. The rules do not address drill pit
construction, use, or closure requirements. The Oil jand Gas
Board has been working to develop rules with regard to waste
pits, and plans to incorporate them into its rules and
regulations. The Oil and Gas Board has instituted a policy
requiring that proposed well sites "be inspected with regard to
its waste pits, and that those pits be approved by the gas and
oil field inspector assigned to that particular well prior to the
issuance of a drilling permit for that well."
The State Oil and Gas Board regulates spacing, casing, plugging,
and abandonment of wells.
PRODUCTION
"Produced water and plant wastes may be disposed of into
subsurface formations not productive of hydrocarbons, ground-
water, or other mineral resources." It is also considered
acceptable for produced water to be disposed in evaporation pits
approved by the State Oil and Gas Board Supervisor. Criteria for
approval are not part of the rules.
The State Oil and Gas Board Assistant Supervisor maintains that
Tennessee gas wells and oil wells producing over 10 barrels of
oil per day do not produce salt water. The Assistant Supervisor
estimates "Statewide average daily production of slightly more
than 0.1 barrels of water per day [per full producing oil well]."
OFFSITE PITS
The regulations do not specifically address offsite pits.
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REFERENCES
Zurawski, Ronald P. "1985 EPA Onshore Oil and Gas Workshop
Request for Information on Tennessee Activity and
Technology," circa mid-1985.
State of Tennessee - State Oil and Gas Board. "General
Rules and Regulations, Statewide Order No. 2,"
Effective November 1972.
Zurawski, Ronald P. Drilling Waste Conference submittal,
circa mid-1985.
State of Tennessee State Oil and Gas Board. "Oil and Gas
Laws in Tennessee and Mineral Test Hole Regulatory
Act," Amendments added 1982.
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TEXAS
INTRODUCTION
Texas produces 856 million
barrels of oil annually from
over 200,000 wells. Gas
production is 6,753,889 MMCF
from 43,174 gas wells. It is
estimated that 75 percent of
all active Texas wells are
marginally-producing wells.
Regulation of the oil and gas
industry began in Texas when
the Railroad Commission was
assigned jurisdiction over oil
and gas activities in 1919.
STATE REGULATORY AGENCIES
Five agencies have jurisdiction over disposal of oil and gas
wastes in Texas:
- Railroad Commission of Texas
- Texas Water Commission
- Texas Parks and Wildlife Department
- U.S. Bureau of Land Management (and the Bureau of Indian
Affairs)
- U.S. Corps of Engineers
Oil and gas activities in Texas are regulated almost entirely by
the Railroad Commission of Texas. Unlike many State oil and gas
commissions, the Railroad Commission is responsible for both
prevention of waste and for prevention of pollution. Thus one
agency is responsible for well spacing, construction requirements
(casing, etc.), and environmental protection (air, water, etc.).
According to the Texas Administrative Code, Title 31 as amended
July 3, 1986, the Texas Water Commission jurisdiction over
disposal activities is superceded by Railroad Commission and
Department of Health authority.
The Texas Parks and Wildlife Department, Pollution Surveillance
Branch, investigates fish kills and water pollution complaints
and evaluates the effects of discharged wastes on fish and
wildlife. The Texas Parks and Wildlife Department has statutory
authority to recover the monetary value of damaged fish and
wildlife. The Parks and Wildlife Department may also enforce the
Texas Water Code when permit violations, discharges in excess of
permit limitations, or discharges without a permit occur.
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The U.S. Department of the Interior, Bureau of Land Management,
has jurisdiction over lease arrangements and post-lease activity
on Federal lands. Their rules are discussed in a separate
section, Federal Agencies. The Bureau of Indian Affairs has some
jurisdiction in limited areas of Texas.
STATE RULES AND REGULATIONS
GENERAL
Texas State Rule 8 prohibits any "person conducting activities
subject to regulation by the state" from causing or allowing
pollution of surface or subsurface waters in Texas. Except for
underground injection (either for disposal or for enhanced
recovery), "no person may dispose of any oil and gas wastes by
any method without obtaining a permit to dispose of such wastes."
DRILLING
The Railroad Commission of Texas has the authority to permit
reserve pits, mud circulation pits, completion/workover pits,
basic sediment pits, flare pits, fresh makeup water pits, and
water condensate pits. The use of mud pits and mud recirculation
pits for oil and gas wastes is limited to drilling fluids, drill
cuttings, wash water, drill stem test fluids, and blowout
preventer test fluids. Pit locations are evaluated on a case-by-
case basis to determine what construction requirements are
necessary to prevent waste of oil and gas resources or pollution
of surface water, groundwater, or agricultural land. The
requirements may or may not include liners.
Permits must carry requirements for pit operation (maintenance)
and pit closure as well. The Railroad Commission requires that
pits be dewatered, backfilled, and compacted for closure.
Backfill requirements (for all type of pits) vary according to
the type of pit and the chloride concentration of the pit
contents. Reserve pits (and mud recirculation pits) containing
over 6,100 mg/1 chloride must be dewatered within 30 days and
backfilled within one year of cessation of drilling operations.
The operator has up to one year to dewater and to backfill
reserve pits (and mud circulation pits) containing less than
6,100 mg/1 chlorides.
Completion and workover pits must be dewatered within 30 days and
compacted within 120 days of completion of workover operations.
Basic sediment pits must be closed "within 120 days of cessation
of use of the pits."
Pit fluids and other oil and gas wastes are tracked via a
manifest system in Texas. Railroad Commission permits are
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necessary to "transport, store, handle, treat, reclaim, or
dispose of oil and gas wastes."
The Railroad Commission permits treatment and discharge of
reserve pit fluids to land or to surface waters provided that the
discharge does not cause a violation of Texas water quality
standards. The rule is unclear as to what processes constitute
acceptable treatment technologies. The permit "does -not
authorize the use of surfactants or spray adjuvants." The
criteria for discharges to surface waters are:
24-hour bioassay by Texas Parks and Wildlife
Chemical oxygen demand <_ 200 mg/1
-y Total suspended solids <_ 50 mg/1
- Total dissolved solids <_ 3000 m/1
- Oil and grease <_ 15 mg/1
- Chlorides (coastal) <_ 1000 mg/1
- Chlorides (inland) <^ 500 mg/1
- pH 6.0 to 9.0
- Water color must be adjusted to match the receiving
stream
- Volume of the discharge must be "controlled so that a
minimum 5:1. dilution of the wastewater by the principal
receiving stream is maintained."
Discharge cannot exceed concentrations of
hazardous metals as defined by Texas Water Development
Board Rules 156.19.15.001-.009.
No permit is required for landfarming of water-based drilling
fluids and associated wastes with a concentration of chlorides at
or below 3000 mg/1; however, the written consent of the landowner
must be obtained. Landfarming encompasses sprinkler irrigation,
trenching, injecting under the surface using a disc, and surface
spreading by vehicles as defined by the Railroad Commission of
Texas. Applications for discharge permits do not require
submittal of analytical data on wastes.
Annular injection of drilling fluids is also regulated via "minor
permits" issued by the Railroad Commission of Texas. Certain
conditions and limitations apply to the use annular injection for
disposal.
Drilling is allowed in wildlife management areas and in State
parks. Drilling muds are often disposed on State property.
On Federal lands, the Railroad Commission of Texas has
jurisdiction whenever mineral rights are privately owned,
although the U.S Forest Service retains surface rights. For
Federally-owned mineral rights, the Bureau of Land Management has
jurisdiction.
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PRODUCTION
Injection of produced water is the major approved disposal method
for brine. "Texas has primacy for Class II wells and has
permitted approximately 47,000 such wells."
The Railroad Commission allows discharge of produced water into
coastal areas on an individual basis. The application for a
discharge permit does not require submittal of analytical data
for produced water.
West of the 98th meridian, the Railroad Commission permits
"beneficial use" of produced waters where there will be no
discharge.
OFFSITE PITS
Although there are currently about 200 saltwater disposal pits
operating in Texas, these pits are not specifically addressed in
Texas Railroad Commission rules and regulations.
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REFERENCES
Railroad Commission of Texas, Oil and Gas Division. Rules
Having Statewide Application to Oil Gas and Geothermal
Resource Operations Wit.hin the State of Texas,
September 1985.
Interstate Oil Compact Commission, The Oil and Gas Compact.
Bulletin, Volume XLIV, Number 2, December 1985.
Railroad Commission of Texas, Oil and Gas Division. Water
Protection Manual, April 1985.
U.S. Environmental Protection Agency, Proceedings - Onshore
Oil and Gas State/Federal Western Workshop, December
1985.
"Texas Surface Water Quality Standards," TDWR Publication
LP-71.
Railroad Commission of Texas, "Application Information -
Casing/Annulus Disposal of Drilling Fluid." Not dated.
Railroad Commission of Texas, Letter communication to EPA,
October 1985.
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UTAH
INTRODUCTION
Utah produced 35,750 barrels
of oil annually from 1,862
wells in 1984. Approximately
20 percent of these oil wells
are strippers. Utah's gas
fields produced 99.8 x 109
cubic feet of gas from 728 gas
wells in 1984. It is not
known what proportion of these
wells are marginal producers
of gas.
STATE REGULATORY AGENCIES
Four agencies share regulatory responsibility for oil and gas
activities in Utah:
- Utah Department of Natural Resources, Division of Oil,
Gas, and Mining
- Department of Health, Bureau of Water Pollution Control
- U.S. Bureau of Land Management (and possibly the Bureau of
Indian Affairs)
- U.S. Forest Service (surface rights only)
The Division of Oil, Gas, and Mining adopted new Oil and Gas
Conservation General Rules effective December 2, 1985. These
rules cover drilling and operating practices, UIC Class II
responsibility, and rules governing purchasing, transportation,
refining, and rerefining. The Department of Health currently has
regulatory authority over disposal ponds. The Department of Oil,
Gas, and Mining is hoping to bring most aspects of oil and gas
regulations under one agency by assuming authority for disposal
ponds in the near future.
The U.S. Department of the Interior, Bureau of Land Management,
has jurisdiction over lease arrangements and post-lease activity
on Federal lands where the mineral rights are Federally held.
Surface rights in Federal forests and grasslands are retained by
the U.S. Forest Service.
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STATE RULES AND REGULATIONS
DRILLING
Rule 308 of the Division of Oil, Gas, and Mining rules requires
oil and gas operators to "take all reasonable precautions to
avoid polluting streams, reservoirs, natural drainage, ways, and
underground water." This requirement is supported by a specific
rule for reserve pits (Rule 309). "Salt water and oil field
wastes associated with the drilling process may be impounded in
excavated earthen reserve pits underlain by tight soil such as
heavy clay or hardpan or lined in a manner acceptable to the
Division." Pit liquids are not allowed to escape onto the land
surface or into surface waters.
Since most of Utah has very rapid evaporation rates, the reserve
pit supernatant is generally allowed to evaporate before pit
closure. Final pit closure requirements were not found in the
rules.
In areas of net precipitation, or in areas where pit construction
is especially difficult (i.e., steep mountain sides), the
Division may allow the reserve pit supernatant to be disposed
down the annulus of the new well into a properly confined zone of
poor water quality. This determination is made by the Division
of Oil, Gas, and Mining on a case-by-case basis.
The Division of Oil, Gas, and Mining has extensive technical
rules regarding well siting, casing requirements, and well
drilling.
PRODUCTION
Most produced water is injected for water flooding or for
disposal. Utah has approximately 560 Class II injection wells,
including about 45 disposal wells. The Division of Oil, Gas, and
Mining controls injection wells and onsite disposal facilities.
The Utah Department of Health regulates surface disposal of
produced water from gas and oil wells. No pond is allowed to
discharge to the surface (land or water). Construction
requirements seek to protect the pit from intrusion of surface
water, be constructed of impervious material, and be located at
"Onsite disposal facilities" are presumed to include
onsite evaporation pits. The Division of Oil, Gas, and
Mining rules do not include specific guidance regarding
onsite disposal facilities, however, their reserve pit
guidance is probably applied to produced water pits as
well. There appears to be some overlap in authority
for onsite pits between the Utah Department of Health
and the Division of Oil, Gas, and Mining.
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least 5 feet above groundwater. Pits must be properly located
above ordinary high water marks for surface waters. Pits may not
be located within 200 feet of a fault or at the bottom of creeks,
rivers, or natural drainages.
Surface disposal into unlined ponds is allowed if the wastewater
contains less than 5,000 mg/1 total dissolved solids,- and if the
wastewater does not contain "objectionable or toxic levels of any
constituent as shown by chemical analyses." This requirement is
waived for sites discharging less than 5 barrels of water per
day. Small dischargers into unlined pits are required only to
notify the Department of Health with minimal site information.
Application for approval to discharge into unlined pits must
include an estimate of waste volume, estimate of percolation and
net evaporation rates, and information about freshwater aquifers
within a one square mile radius of the proposed site.
For disposal ponds without artificial liners which receive more
than 100 barrels per day, the Department of Health requires a
monitoring program including monitoring wells.
For artificially-lined ponds, the Department of Health requires
"an underlying gravel-filled sump and lateral system, or other
suitable devices for detection of leaks." The Department of
Health, Bureau of Water Pollution Control, is considering a
requirement that all ponds (lined or unlined) be equipped with a
leak detection system. In general, the Bureau feels that pit
siting is more important than construction requirements.
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REFERENCES
Interstate Oil Compact Commission, The Oil and Gas Compact
Bulletin, Volume XLIV, Number 2, December 1985.
U. S. Environmental Protection Agency, Proceedings - Onshore
Oil and Gas State/Federal Western Workshop, December
1985.
Hunt, Gil. Letter to Ms. Susan de Nagy with attachments
dated September 20, 1985.
Swindel, D. B. Letter to Kerri Kennedy with attachments
dated June 6, 1986.
"The Oil and Gas Commission General Rules," effective
December 2, 1985.
Utah Water Pollution Control Committee, State of Utah,
Department of Health, Division of Environmental Health,
Wastewater Disposal Regulations — Part VI Surface
Disposal of Produced Water from Gas and Oil Wells,
January 20, 1982.
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VIRGINIA
INTRODUCTION
Virginia produced 33,000
barrels of oil from 35
producing oil wells and 9 x 109
cubic feet of gas from 499 gas
wells in 1984.
STATE REGULATORY AGENCY
One agency principally regulates oil and gas activities in
Virginia:
- Virginia Department of Mines, Minerals, and Energy,
Oil and Gas Section
The Oil and Gas Section is governed by the Virginia Oil and Gas
Act and by the Rules and Regulations for Conservation of Oil and
Gas Resources and Well Spacing as issued by the Virginia
Department of Labor and Industry. The Oil and Gas Section issues
drilling permits and regulates the details of the industry
through this process. The State does not have primacy for the
UIC program Class II wells, but there is no underground injection
of fluids currently associated with the Virginia industry. There
has been drilling on Federal lands, but such lands are owned by
the National Forest Service and the Service serves as another
surface landowner in such drilling activity. The Service would
manage their concerns principally through the surface lease
process. The Virginia Water Control Board would become involved
only in the event of an incident that potentially could affect
surface water quality.
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STATE RULES AND REGULATIONS
DRILLING
Virginia Regulations 3.02 (f) and (g) require pits to be
associated with the drilling of a well that will preclude water
pollution. Pits must be lined with a plastic liner,;and the
drill site and any associated pits must be reclaimed .within 1
year after drilling ceases.
In general, there is little fluid associated with the drilling
process in Virginia. Such fluids as may be present are not high
in chloride concentration. Generally, the fluid is tested by the
driller, the pH is adjusted if necessary, and the water is
sprayed on the surrounding land. Pit muds are buried on site and
the pit area reclaimed.
PRODUCTION
Almost no fluid is associated with gas production in Virginia.
Very small amounts of fluids are produced with the 100 gallons of
oil produced per day statewide. As a result, produced waters
generally are held in"steel tanks. Dikes are required around the
tanks, and fluids generally are allowed to flow into the diked
area, where they disappear through evaporation and infiltration.
OFFSITE AND COMMERCIAL PITS
No use is made of offsite and commercial pits in Virginia.
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REFERENCES
Summary of State Statutes and Regulations for Oil and Gas
Production. 1986. Interstate Oil and Gas Commission
(June).
The Oil and Gas Compact Bulletin. 1985. Interstate Oil
Compact Commission(June).
Personal Communication:
James Henderson, State Oil and Gas Inspector (703) 628-8115
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WEST VIRGINIA
INTRODUCTION
West Virginia produces about
four million barrels of oil per
year from 15,475 wells. Gas
production of 136 billion cubic
feet annually is realized from
30,700 wells. Between 1,800
and 2,5X)0 drilling permits are
issued annually, although the
number of wells drilled has
dropped in 1986.
STATE REGULATORY AGENCIES
Two agencies regulate oil and gas acstivities in West Virginia:
West Virginia Department of Energy
U.S. Bureau of Land Management
The recently-created West Virginia Department of Energy has
statutory authority over oil and gas activities in the State.
The Department of Energy is in the process of assuming
responsibilities from the Department of Mines, Office of Oil and
Gas (historically the drilling permitting authority), and from
the Department of Natural Resources, Water Resources Division and
Reclamation Division. West Virginia has proposed regulations and
hearings have been conducted regarding the oil and gas industry.
However, new regulations cannot go into effect until the State
legislature approves them and the Governor signs a proclamation.
Thus, old regulations remain in place. In the interim, the
Department of Natural Resources and Department of Mines are
working cooperatively with the Department of Energy towards a
transition of responsibilities.
The current reorganization seriously complicates a presentation
of existing regulations. For instance, the Department of Natural
Resources, Water Resources Division, retains NPDES delegation,
although the Department of Energy has applied for delegation
specifically limited to oil and gas wastes and certain other
industries. This parallel permitting responsibility is
duplicated for other regulatory areas as well.
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The U.S. of Land Management has jurisdiction over lease
arrangements and post-lease activity on Federal lands. Their
rules are discussed in a separate section, Federal Agencies. The
U.S. Forest Service retains surface rights on Federal forests and
grasslands. They coordinate surface stipulations with the Bureau
of Land Management where applicable.
STATE RULES AND REGULATIONS
The following discussion of State rules and regulations is based
on proposed rules and regulations that are expected to become
effective in early 1987. Current copies of the proposed rules
stress an outline of the authority and definitions of
responsibilities rather than specific waste handling regulations.
DRILLING
The Department of Energy issues drilling permits for all oil and
gas wells in the State. Suitable applications must provide
detailed information regarding locale, site, and construction
plans. The Department of Energy has well construction
requirements which include casing, cement type, or cement
strength. Permitted drillers are required to keep work records
during the period of work. Similar information is required for
applications for plugging and abandonment.
PRODUCTION
The West Virginia Department of Energy is applying for NPDES
delegation for discharges from oil and gas operations. The
regulations are closely modeled after 40 CFR 124.
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REFERENCES
Interstate Oil and Gas Compact Commission, The Oil and Gas
Compact Bulletin, Volume XLIV, Number 2, December 1985,
Personal communication with Mr. Ted Streit, former head of
Office of Oil and Gas. September 25, 1986.
West Virginia Department of Energy, "Notice of Public
Hearing and Comment Period on Proposed Rules," not
dated. Received October 1986.
Streit/ T. M. Letter submitted to William A. Telliard, U.
S. EPA, May 28, 1985.
West Virginia Legislative Rule Department of Energy -
Division of Oil and Gas Chapters 22-1 and 22B-1
Series 2.
West Virginia Meeting Report. 1985. Proceedings of the
Onshore Oil and Gas Workshop. U.S. EPA, Washington,
D.C. (March 26-27 in Atlanta, GA).
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WYOMING
INTRODUCTION
Wyoming produced 127,763,000
barrels of oil and 600,137
million cubic feet of gas in
1984. Production is from
12,463 oil wells and 2,280 gas
wells. Although many of these
wells had been producing for
30 to 40 years, discharges of
produced water were not
permitted until the Clean
Water Act was passed in 1972.
STATE REGULATORY AGENCIES
Three agencies regulate oil and gas activity in Wyoming:
- Wyoming Department of Environmental Quality
- Wyoming Oil and Gas Conservation Commission
- U.S. Department of Interior, Bureau of Land Management
The Wyoming Oil and Gas Conservation Commission has the authority
to "monitor and regulate, by the promulgation of rules and the
issuance of orders, the location, operation, and reclamation of
produced water and emergency overflow pits associated with oil
and gas production." The Commission regulates industry practices
and procedures with regard to construction, location, and
operation of onsite drilling and onsite production pits which
serve a single well. The Oil and Gas Conservation Commission is
chaired by the Governor of Wyoming, and four other commis-
sioners. The Office of the State Oil and Gas Supervisor is
primarily responsible for regulation of industry practices as
described above.
Wyoming is an NPDES-delegated State. The Wyoming Department of
Environmental Quality has NPDES authority for all discharges.
Department of Environmental Quality has "jurisdiction and
authority to regulate through monitoring and the promulgation of
rules, regulations and orders governing treatment works and
disposal systems and other facilities capable of causing or
contributing to pollution, pursuant to W.S. 35-11-301." These
responsibilities generally cover offsite commercial ponds and
disposal pits serving two or more wells. The Department of
Environmental Quality also has permitting authority for land
application or discharge of drilling wastes.
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The cooperative roles between the Wyoming Oil and Gas Commission
and the Department of Environmental Quality is described in
"Memorandum of Agreement between the Wyoming Oil and Gas
Conservation Commission and the Department of Environmental
Quality," dated September 13, 1983, and in the memorandum from
the Wyoming Attorney General's office to the Office o.f the State
Oil and Gas Supervisor dated January 18, 1982.
The Bureau of Land Management has jurisdiction over drilling and
production on Federal lands. For drilling on Federal land, the
U.S. Bureau of Land Management handles all Applications to Drill.
The Bureau requires extensive environmental documentation,
including environmental assessments and develops environmental
impact statements for drilling on Federal land. For produced
water, the Bureau routinely approves discharges of produced water
up to 5 barrels per day under Notice to Lessees 2B.
STATE RULES AND REGULATIONS
DRILLING
Section 326 of the Rules and Regulations of the Wyoming Oil and
Gas Conservation Commission states, "At no time will drilling
fluids be discharged into live waters or into any drainages that
lead to live waters of the state." Application forms for
temporary earthen pits (including reserve pits) allow only one of
three designations for final disposition of pit contents:
evaporation, hauling, or injection in a disposal well. No
manifest system is in effect for hauled wastes.
Earthen pits are required to be constructed to "prevent pollution
of streams, underground water, or to unreasonably damage the
surface of leased premises or other lands." The rules do not
require pit or pond liners, leak detection, or other modifi-
cations to a simple earthen pit except where "potential for
communication between the pit contents and surface water or
shallow ground water is high." The State Supervisor makes this
determination based on the information presented in the permit
application (Form 14A or 14B).
The Department of Environmental Quality allows discharge of
drilling fluids from pits associated with the drilling of oil
and/or gas wells under exceptional conditions, including a
"complete analysis of the drilling liquid, the volume of liquid
to be discharged, the location of the proposed discharge, and the
name of the receiving water, " have been submitted to Department.
of Environmental Quality. These requirements must meet the
approval of the Department of Environmental Quality and the
landowner prior to discharge. (Wyoming Department of
Environmental Quality Water Quality Rules and Regulations Chapter
VII, p.5)
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Workover and completion pits are exempted from permit
requirements if their use is limited to containment of
oil/water. No definition of oil/water is found in the rules;
however, the Commission staff explains that these pits are not
allowed to contain acids or other chemical fluids. Fresh and
potable water are defined as (1) having TDS less than 10,000
milligrams per liter, (2) reasonably suited for domestic,
agricultural, or livestock use, and (3) suitable for fish or
aquatic life. State law adopts these limitations at the guidance
of the Federal UIC program.
Chemical use which destroys, removes, or reduces the fluid seal
of a reserve pit is prohibited. Chemical or mechanical treatment
of reserve pits must be specially allowed after a public hearing
before the Oil and Gas Commission.
Earthen pits must be reclaimed within 1 year of the date of last
use unless the Supervisor grants a specific variance. Bonds
guaranteeing pit reclamation are not released until the Commis-
sion has inspected and approved the reclaimed pit.
PRODUCTION
The Oil and Gas Commission requires permits for brine pits
receiving more that 5 barrels of water per day. Pits receiving
less than 5 barrels of water per day (i.e., less than 76,650
gallons per year) are unregulated. Even for larger pits, liners
are required only in special cases where "potential for
communication between the pit contents and surface water or
shallow ground water is high."
The Wyoming Department of Environmental Quality's Water Quality
Rules and Regulations, Chapter VII, describes the rules for
surface discharge of water associated with the production of oil
and gas. Discharge of produced water may be permitted by the
Department of Environmental Quality if certain effluent
limitations are met (including 2000 mg/1 chlorides, 3000 mg/1
sulfates, 5000 mg/1 TDS, pH between 6.5 and 8.5, 10 mg/1 oil and
grease, toxic substances, and other reserved additional
limitations). This discharge is permitted through the NPDES
system. Exceptions to the foregoing limitations may be granted
if "beneficial use" can be properly demonstrated to the Depart-
ment of Environmental Quality, and unless the landowner or the
Department of Environmental Quality determines that environmental
damage would result.
OFFSITE AND COMMERCIAL PITS
The Department of Environmental Quality regulates offsite and
commercial pits. Chapter III of the Wyoming Water Quality Rules
and Regulations outlines three basic requirements for permitting
commercial pits. First, the facility must demonstrate that its
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construction will not allow a discharge to groundwater by direct
or indirect discharge, percolation, or filtration. Second, the
quality of wastewater will not cause violation of any groundwater
standards. Finally, that existing geology will not allow a
discharge to groundwater.
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REFERENCES
Personal communication with Ms. Janie Nelson, Wyoming Oil
and Gas Commission, August 14, 1986. Telephone (307)
234-7147.
Personal communication with Mr. E. J. Fanning, Department of
Environmental Quality, Water Quality Division, August
11 and August 14, 1986. Telephone (307) 777-7781.
Wyoming Department of Environmental Quality Water Quality
Rules and Regulations, Chapter III, VII, IX, September
5, 1978.
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SUMMARY OF FEDERAL REGULATIONS
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U.S. FOREST SERVICE
National Forest Systems, which include National forests and
National grasslands, are administered by the U.S. Forest Service
within the U.S. Department of Agriculture. Every application to
drill for oil and gas that impacts the above lands is reviewed by
the Service.
Where a road use permit is required, or where permit conditions
related to oil and gas drilling are appropriate, such are
conveyed by interagency communication to the Bureau of Land
Management. The Bureau issues the lease conditions at the
request of the U.S. Forest Service.
The nature of any lease condition depends upon case-by-case site
specific requirements.
Communication:
Craig Losche, U.S. Forest Service (703) 235-9873
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BUREAU OF LAND MANAGEMENT
INTRODUCTION
Exploration, development, drilling, and production of onshore oil
and gas on Federal and Indian lands are regulated separately from
non-Federal lands. This separation of authority is significant
for western States where oil and gas activity on Federal and
Indian lands is a large proportion of statewide activity.
REGULATORY AGENCIES
The U.S. Department of the Interior is authorized by 30 CFR 221.4
and 221.32 for regulation of onshore oil and gas practices on
Federal and Indian lands. The Department of Interior administers
their regulatory program through state Bureau of Land Management
or U.S. Geological Survey District offices. These agencies
generally have procedures in place for coordination with state
agencies on regulatory requirements. Where written agreements
are not in place, the Bureau of Land Management usually works
cooperatively with the respective state agencies.
The Bureau works closely with the U.S. Forest Service for surface
stipulations in Federal forests or Federal grasslands. This
arrangement is also provided for in the Federal regulations.
RULES AND REGULATIONS
The Bureau of Land Management has authority over all aspects of
oil and gas activities on Federal lands. The authority includes
leasing, bonding, and royalty arrangements, construction and well
spacing requirements, waste handling, waste disposal, site
reclamation, and site maintenance as well as others areas. These
responsibilities are extensive and the documentation regarding
them is voluminous; only those portions of the regulations
relating to waste handling, treatment, and disposal will be
summarized herein.
Historically the Bureau of Land Management has regulated oil and
gas activities through "Notice to Lessees." The requirements of
current notices are described below. The Bureau is working to
revise all notices into Oil and Gas Orders, which will be Fed-
erally promulgated. To date, Oil and Gas Order No. 1 has been
issued. Other oil and gas orders are expected to be promulgated
in the next year.
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DRILLING
The Bureau of Land Management considers reserve pits, and some
other types of pits, as temporary. Notice to Lessees 2B contains
the following provisions for "Temporary Use of Surface Pits:"
Unlined surface pits may be used for handling or storage
of fluids used in drilling, redrilling, reworking,
deepening, or plugging of a well provided that such
facilities are promptly and properly emptied and
restored upon completion of the operations. Mud or
other fluids contained in such pits shall not be
disposed of by cutting the pits walls without the prior
authorization of the District Engineer. Until finally
restored, unattended pits must be fenced to prevent
access by livestock and wildlife. Unless otherwise
specified by the District Engineer, unlined pits may be
used for well evaluation purposes for a period of 30
days.
Land spreading of drilling and reworking wastes by breaching pit
walls is allowed when approved by the District Engineer.
PRODUCTION
Produced waters may be disposed into the subsurface, either for
enhanced recovery of hydrocarbon resources or for disposal. The
operator must present detailed information regarding the proposed
disposal site, including subsurface configuration of the proposed
injection well, to the Bureau of Land Management prior to
approval to inject. This documentation is required to ensure
that the injected wastes will be confined to a receiving
formation of poor quality. Further, the operator must identify
the sources of the produced water, must submit estimated daily
quantities of produced water, and must submit an analysis of the
water. The analysis is limited to total dissolved solids, pH,
chlorides, and sulfates.
The Bureau of Land Management also permits disposal of produced
water into lined and unlined pits. "Lined and unlined pits
approved for water disposal shall:
1. Have adequate storage capacity to safely
contain all produced water even in those
months when evaporation rates are at a
minimum.
2. Be constructed, maintained, and operated to
prevent unauthorized surface discharges of
water. Unless surface discharge is
authorized, no siphon, except between pits,
will be permitted.
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3. Be fenced to prevent livestock or wildlife
entry to the pit, when required by the
District Engineer.
4. Be kept reasonable free from surface
accumulations of liquid hydrocarbons by use
of approved skimmer pits, settling tanks, or
other suitable equipment.
5. Be located away from the established drainage
patterns in the area and be constructed so as
to prevent the entrance of surface water."
9
For disposal into lined pits, the operator must submit:
- Site identification
- Planned waste quantities
- Net evaporation data
- Method of disposal for accumulated solids
- Information documenting the liner material
and the impervious nature of the proposed liner
- Method used for leak detection
The operator must submit a water analysis "which include the
concentrations of chlorides, sulfates, and other constituents
which are toxic to animal, plant, or aquatic life." No list of
required analytes is included in the Notice.
Leak detection is required for all lined produced water disposal
pits. The recommended detection system is an "underlying gravel-
filled sump and lateral system." Other systems may be considered
acceptable upon application and evaluation.
Oil and gas operators may be permitted to use unlined pits on any
one of the following bases: If the pit will receive 5 barrels or
less of water per day (monthly basis), no permit is required. If
the water contains less than 5,000 ppm total dissolved solids,
and does not contain "objectionable levels of any constituent
toxic to animal plant, or aquatic life," use of unlined pits is
allowed. If the water will be used for wildlife watering,
irrigation, or livestock watering, unlined pits may be used.
Unlined pits may be used when the produced water is of better
quality than surface or subsurface waters of the area. Unlined
pits permitted for surface discharges under the National
Pollutant Discharge Elimination System are also allowed.
Operators are required to provide information regarding the
sources and quantities of produced water, topographic map,
evaporation rates, estimated soil percolation rates, and "depth
and extent of all usable water aquifers in the area."
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REFERENCES
Personal communication with Mr. Steve Spector September 23,
1986.
U.S. Land Management, "Federal Onshore Oil and Gas Leasing
and Operating Regulations. Not dated.
43 CFR 3100 (entire group)
U.S. Bureau of Land Management, NTL-2B.
U.S. Department of the Interior - Geological Survey
Division. " Notice to Lessees and Operators of Federal
and Indian Oil and Gas Leases (NTL-2B)," not dated.
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U.S. ENVIRONMENTAL PROTECTION AGENCY
EFFLUENT LIMITATIONS GUIDELINES
On October 30, 1976, the Interim Final BPT Effluent Limitations
Guidelines for the Onshore Segment of the Oil and Gas Extraction
Point Source Category were promulgated. [41 FR 44942] The
rulemaking also proposed Best Available Technology Economically
Achievable (BAT), and New Source Performance Standards (Table
1).
On April 13, 1979, BPT Effluent Limitations Guidelines were
promulgated for the Onshore Subcategory, Coastal Subcategory, and
the Agricultural and Wildlife Water Use Subcategory of the Oil
and Gas Extraction Industry. [44 FR 22069] Effluent limita-
tions were reserved for the Stripper Subcategory due to lack of
technical data.
The 1979 BPT regulation established a zero discharge limitation
for all wastes under the Onshore Subcateogy. Zero discharge
Agricultural and Wild-life Subcategory limitations were
established, except for produced water which has a 35 mg/1 oil
and grease limitation.
The American Petroleum Institute (API) challenged the 1979
regulation (including the BPT regulations for the Offshore
Subcategory). [661 F.2D.340(1981)] The court remanded EPA's
decision transferring 1,700 wells from the Coastal to the Onshore
Subcategory. [47 FR 31554] The court also directed EPA to
consider special discharge limits for gas wells. Table 2
provides regulatory details related to onshore oil and gas
activities.
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TABLE 1. SUMMARY OF MAJOR REGULATORY ACTIVITY
RELATED TO ONSHORE OIL AND GAS
October 13, 1976 - Interim Final BPT Effluent Limitations
Guidelines and Proposed (and Reserved) BAT
Effluent Limitations Guidelines and New
Source Performance Standards for the Onshore
Segment of the Oil and Gas Extraction Point
Source Category
April 13, 1979 - Final Rules
- BPT Final Rules for the Onshore,
Coastal, and Wildlife and Agricultural
Water Use Subcategories
- Stripper Oil Subcategory Reserved
- BAT and NSPS never promulgated
July 21, 1982 - Response to American Petroleum Institute vs
EPA Court Decision
- Recategorization of 1700 "onshore"
wells to Coastal Subcategory
- Suspension of regulations for Santa
Maria Basin, California
- Planned reexamination of marginal gas
wells for separate regulations
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TABLE 2. ONSHORE SEGMENT SUBCATEGORIES
o ONSHORE:
O BPT LIMITATION
—- ZERO DISCHARGE
o DEFINED: JJQ discharge of wastewater pollutants into
navigable waters from ANY source associated with
production, field exploration, drilling, well completion,
or well treatment (i.e., produced water, drilling muds,
drill cuttings, and produced sand).
O STRIPPER (OIL WELLS):*
O CATEGORY RESERVED
o DEFINED: TEN barrels per well per calendar day or less
of crude oil.
o COASTAL
O BPT LIMITATIONS
— No Discharge of Free Oil (No Sheen)
— Oil and Grease: 72 mg/1 (Daily)
48 mg/1 (Average Monthly)
(Produced Waters)
o DEFINED: Any body of water landward of the territorial
seas, or any wetlands adjacent to such waters.
O WILDLIFE AND AGRICULTURE USE
O BPT LIMITATIONS
— Oil and Grease: 35 MG/L (Produced Waters)
— Zero Discharge: ANY Waste Pollutants
o DEFINED: That produced water is of good enough quality
to be used for wildlife or livestock watering or other
agricultural uses ... west of the 98th meridian.
*This subcategory does not include marginal gas wells.
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UNDERGROUND INJECTION CONTROL
The Underground Injection Control (UIC) Program was established
under Part C of the Safe Drinking Water Act (SDWA) to provide
minimum standards for procedural and technical requirements for
individual State and Federal UIC Programs. Part C of the SDWA
requires the EPA to: (1) identify a list of States for which UIC
programs may be necessary; (2) approve or disapprove, in whole or
in part, UIC programs submitted by the listed States; and (3)
develop programs and regulate those States that do not have
approved UIC programs. The Federal UIC Program is defined in 40
CFR Parts 144, 145, and 146.
Table 3 is a list of States having full or partial primacy over
their particular UIC Programs. The second column from the left
in Table 3 lists the section of the SDWA under which the States
applied for approval of their UIC Programs. The third column
from the left lists the classes of wells, defined in Table 4, for
which primacy has been given. The classes of wells that a State
can regulate depend upon the SDWA section under which a State's
authority is granted. Section 1422 was originally designed to
cover all classes of wells. Brine disposal injection wells were
later addressed specifically in Section 1425, which was created
by Congress (Dec. 5, 1980) to further define the conditions by
which these wells would be regulated. In essence, a State may
show that it has a program already in place that has been
effective in protecting underground sources of drinking water and
that includes record keeping, reporting, permitting, and
inspections authority over Federal agencies, and assurance that
authorized wells do not endanger underground sources of drinking
water.
Minimum standards for UIC programs as defined in 40 CFR 144, 145,
and 146 include, respectively, permitting requirements, guidance
to obtain approval for State primacy, and technical criteria and
standards to be met in permits and authorizations. Part 144 also
serves as part of the UIC program for States to be administered
by EPA. Part 147 lists and sets specific criteria for those
States whose UIC programs are administered by EPA.
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TABLE 3. UIC PRIMACY STATES (PROGRAMS APPROVED)
Date June 9, 1986
STATE
TYPE
CLASSES
DATE APPROVED
*Full primacyr as of date indicated
**Partial primacy
FR CITE
Oklahoma
Texas
New Mexico
Louisiana*
Texas*
Oklahoma*
Arkansas
Alabama
New Hampshire*
Utah
Wyoming
Massachusets*
Utah*
Nebraska
Florida**
California**
Guam*
New Mexico*
Wyoming*
New Jersey*
North Dakota
Ohio
Alabama*
Maine*
Mississippi**
Wisconsin*
Kansas
Missouri
West Virginia*
Illinois
Illinois*
Kansas*
Arkansas*
Connecticut*
Colorado**
Delaware*
Maryland*
North Carolina*
Georgia*
Nebraska*
Vermont*
South Carolina*
Rhode Island*
Washington*
North Dakota*
Oregon*
South Dakota**
Ohio*
Idaho*
Missouri*
CNMI*
Alaska**
1425
1422
1425
1422/25
1425
1422
1422
1425
1422
1425
1425
1422
1422
1425
1422
1425
1422
1422
1422
1422
1425
1425
1422
1422
1422
1422
1422
1425
1422/25
1425
1422
1425
1425
1422
1425
1422
1422
1422
1422
1422
1422
1422
1422
1422
1422
1422/25
1425
1422
1422
1422
1422
1425
II
I, HI,
II
I - V
II
Ir Ulr
I, IHr
II
I - V
II
II
I - V
It Hit
II
I, HI,
II
I - V
I, IH»
Ir III,
I - V
II
II
If III,
I - V
If IHf
I - V
If III,
II
I - V
II
I, III,
II
II
I - V
II
I - V
I - V
I - V
I - V
If III,
I - V
I - V
I - V
I - V
If III,
I - V
II
If III,
I - V
If III,
I - V
II
TV, V
IV, V
rv, v
IV, V
IV, V
IV, V
rv, v
rv, v
IV, V
rv, v
IV, V
IV, V
IV, V
TV, V
TV, V
December 2, 1981
January 6, 1982
February 5, 1982
April 23, 1982
April 23, 1982
June 24, 1982
July 6, 1982
August 2, 1982
September 21, 1982
October 8, 1982
November 22, 1982
November 23, 1982
January 19, 1983
February 3, 1983
February 7, 1983
February 11, 1983
May 2, 1983
July 11, 1983
July 15, 1983
July 15, 1983
August 23, 1983
August 23, 1983
August 25, 1983
August 25, 1983
August 25, 1983
September 30, 1983
December 2, 1983
December 2, 1983
December 9, 1983
February 1, 1984
Feburary 1, 1984
February 9, 1984
March 26, 1984
March 26, 1984
April 2, 1984
April 5, 1984
April 19, 1984
April 19, 1984
April 19, 1984
June 12, 1984
June 22, 1984
July 10, 1984
August 1, 1984
August 9, 1984
September 21, 1984
September 25, 1984
October 24, 1984
November 29, 1984
June 7, 1985
July 17, 1985
July 17, 1985
May 6, 1986
46 FR 58488
47 FR 618
47 FR 5412
47 FR 17487
47 FR 17488
47 FR 27273
47 FR 29236
47 FR 33268
47 FR 41561
47 FR 44561
47 FR 52434
47 FR 52705
48 FR 2321
48 FR 4777
48 FR 5556
48 FR 6336
48 FR 19717
48 FR 31640
48 FR 32343
48 FR 32343
48 FR 38237
48 FR 38238
48 FR 38640
48 FR 38641
48 FR 38641
48 FR 44783
48 FR 54350
48 FR 54349
48 FR 55127
49 FR 3990
49 FR 3991
49 FR 4735
49 FR 11179
49 FR 11179
49 FR 13040
49 FR 13525
49 FR 15553
49 FR 15553
49 FR 15553
49 FR 24134
49 FR 25633
49 FR 28057
49 FR 30698
49 FR 31875
49 FR 37065
49 FR 37593
49 FR 42728
49 FR 46896
50 FR 23956
50 FR 28941
50 FR 28942
51 FR 16683
A-135
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TABLE 4. CLASSIFICATION OF INJECTION WELLS
Class I o Wells used by generators of hazardous waste or
owners or operators of hazardous waste management
facilities to inject hazardous waste beneath the
lowermost formation containing, within one quarter
(1/4) mile of the well bore, an underground source
of drinking water.
o Other industrial and municipal disposal wells
which inject fluids beneath the lowermost
formation containing, within one quarter mile of
the well bore, an underground source of drinking
water.
Class II Wells used to inject fluids:
o Which are brought to the surface in connection
with conventional oil or natural gas production
and may be commingled with waste waters from gas
plants which are an integral part of production
operations, unless those waters are classified as
a hazardous waste at the time of injection;
o For enhanced recovery of oil or natural gas; and
o For storage of hydrocarbons which are liquid at
standard temperature and pressure.
Class III Wells used to inject for extraction of minerals
including:
o Mining of sulfur by the Frasch process.
o In situ production of uranium or other metals.
This category includes only in situ production
from ore bodies which have not been
conventionally mined. Solution mining of
conventional mines such as stopes leaching is
included in Class V.
o Solution mining of salts or potash.
Class IV o Wells used by generators of hazardous waste or of
radioactive waste, by owners or operators of
hazardous waste management facilities, or by
owners or operators of radioactive waste disposal
sites to dispose of hazardous waste or radioactive
waste into a formation which within one quarter
(1/4) mile of the well contains an underground
source of drinking water.
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TABLE 4. CLASSIFICATION OF INJECTION WELLS
(Continued)
Class IV o Wells used by generators of hazardous waste or of
(Cont'd) radioactive waste, by owners or operators of
hazardous waste management facilities or by owners
or operators of radioactive waste disposal sites
to dispose of hazardous waste or radioactive waste
above a formation which within one quarter (1/4)
mile of the well contains an underground source of
drinking water.
o Wells used by generators of hazardous waste or
owners or operators of hazardous waste management
facilities to dispose of hazardous waste, which
cannot be classified under Sect. 146.05(a)(l) or
146.05(d) (1) and (2) (e.g., wells used to dispose
of hazardous wastes into or above a formation
which contains an aquifer which has been exempted
pursuant to Sect. 146.04).
Class V o Injection wells not included in Class I, II, III,
or IV.
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REFERENCES
Federal Register, 40 CFR Parts 144, 145, 146, and 147.
Safe Drinking Water Act, Part C, December 16, 1974, as amended by
PL 96-502, December 5, 1980.
Personal Communication with Mr. Mario Salazar, U.S. EPA UIC
Program, October 7, 1986. Telephone 202- 382-5561.
A-138
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Appendix B
Glossary of Terms and Abbreviations
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APPENDIX B
GLOSSARY AND ABBREVIATIONS
Annular Injection. Long-term disposal of wastes between the outer wall of
the drill stem or tubing and the inner wall of the casing or open hole.
Annulus or Annular Space. The space between the drill stem and the wall
of the hole or casing.
Barite. Barium sulfate. An additive used to weight drilling mud.
Barrel. Forty-two United States gallons at 60°F.
Bentonite. A clay additive used to increase the viscosity of drilling mud.
Blowout. A wild and uncontrolled flow of subsurface formation fluids at
the earth's surface.
Blowout Preventer (BOP). A device to control formation pressures in a
well by closing the annulus when pipe is suspended in the well or by
closing the top of the casing at other times.
Brackish Water. Water containing low concentrations of any soluble salts.
Brine. Water saturated with or containing a high concentration of common
salt (sodium chloride); also any strong saline solution containing other
salts such as calcium chloride, zinc chloride, calcium nitrate, etc.
BS&W. Bottom sediment and water carried with the oil. Generally,
pipeline regulation limits BS&W to 1 percent of the volume of oil.
B-l
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Casing. Large steel pipe used to "seal off" or "shut out" water and
prevent caving of loose gravel formations when drilling a well. When the
casings are set, drilling continues through and below the casing with a
smaller bit. The overall length of this casing is called the string of
casing. More than one string inside the other may be used in drilling the
same well.
Centralized Brine Disposal Pit. An excavated or above grade earthen
impoundment remotely located from the oil or gas operations from which it
receives produced fluids (brine). Centralized pits usually receive fluids
from many wells, leases, or fields.
Centralized Combined Mud/Brine Disposal Pit. An excavated or above grade
earthen impoundment remotely located from the oil or gas operations from
which it receives produced fluids (brine) and drilling fluids.
Centralized pits usually receive fluids from many wells, leases, or fields.
Centralized Mud Disposal Pit. An excavated or above grade earthen
impoundment remotely located from the drilling operations from which it
receives drilling muds. Centralized pits usually receive fluids from many
drilling sites.
Centralized Treatment Facilities (Mud or Brine). Any facility accepting
drilling fluids or produced fluids for processing. This definition
encompasses municipal treatment plants, private treatment facilities, or
publicly owned treatment works for treatment of drilling fluids or
produced fluids. These facilities usually accept a spectrum of wastes
from a number of oil, gas, or geothermal sites, or in combination with
wastes from other sources.
Centrifuge. A device for the mechanical separation of solids from a
liquid. Usually used on weighted muds to recover the mud and discard
solids. The centrifuge uses high-speed mechanical rotation to achieve
this separation as distinguished from the cyclone-type separator in which
the fluid energy alone provides the separating force.
Chemical-Electrical Treater. A vessel that utilizes surfactants, other
chemicals, and an electrical field to break oil-water emulsions.
Christmas Tree. Assembly of fittings and valves at the tip of the casing
of an oil well that controls the flow of oil from the well.
Circulate. The movement of fluid from the suction pit through pump, drill
pipe, bit annular space in the hole, and back again to the suction pit.
Clean Water Act. The Federal Water Pollution Control Act Amendments of
1972 (33 U.S.C. 1251 et sea.), as amended by the Clean Water Act of 1977
(P. L. 95-217).
B-2
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Closed-In. A well capable of producing oil or gas, but temporarily not
producing.
Completion Operations. Work performed in an oil or gas well after the
well has been drilled to the point where the production string of casing
is to be set, including setting the casing, perforating, artificial
stimulation, production testing, and equipping the well for production,
all prior to the commencement of the actual production of oil or gas in
paying quantities, or in the case of an injection or service well, prior
to when the well is plugged and abandoned.
Condensate. Hydrocarbons that are in the gaseous state under reservoir
conditions but which become liquid either in passage up the hole or at the
surface.
Conduction Dominated System. A geothermal energy system created by
thermal conduction of heat from deep within the earth to the surface.
Connate Water. Water that probably was laid down and entrapped with
sedimentary deposits, as distinguished from migratory waters that have
flowed into deposits after they were laid down.
Cuttings. Small pieces of formation .that are the result of the chipping
and/or crushing action of the bit.
Cyclone. Equipment, usually cyclone type, for removing drilled sand from
the drilling mud stream and from produced fluids.
Derrick and Substructure. Combined foundation and overhead structure to
provide for the hoisting and lowering necessary for drilling.
Desilter. Equipment, normally cyclone type, for removing extremely fine
drilled solids from the drilling mud stream.
Development Facility. Any fixed or mobile structure addressed by this
document that is engaged in the drilling and completion of productive
wells.
Disposal Well. A well through which water (usually salt water) is
returned to subsurface formations.
Drill Cuttings. Particles generated by drilling into subsurface geologic
formations and carried to the surface with the drilling fluid.
B-3
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Drilling Fluid. The circulating fluid (mud) used in the rotary drilling
of wells to clean and condition the hole and to counterbalance formation
pressure. A water-base drilling fluid is the conventional drilling mud in
which water is the continuous phase and the suspended medium for solids,
whether or not oil is present. An oil-base drilling fluid has diesel,
crude, or some other oil as its continuous phase with water as the
dispersed phase.
Drilling Fluids. Drilling fluids are circulated down the drill pipe and
back up the hole between the drill pipe and the walls of the hole, usually
to a surface pit. Drilling fluids are used to lubricate the drill bit, to
lift cuttings, to seal off porous zones, and to prevent blowouts. There
are two basic drilling media: muds (liquid) and gases. Each medium is
comprised of a number of general types. The type of drilling fluid may be
further broken down into numerous specific formulations.
Drill Pipe. Special pipe designed to withstand the torsion and tension
loads encountered in drilling.
Emulsion. A substantially permanent heterogeneous mixture of two or more
liquids (which are not normally dissolved in each other), but which are
held in suspension or dispersion, one in the other, by mechanical
agitation or, more frequently, by adding small amounts of substances known
as emulsifiers. Emulsion may be oil-in-water or water-in-oil.
Enhanced Oil Recovery. The increased recovery from a pool achieved by
artificial means or by the application of energy extrinsic to the pool.
These artificial means or applications include pressuring, cycling,
pressure maintenance, or injection to the pool of a substance or form of
energy, but do not include the injection in a well of a substance or form
of energy for the sole purpose of (1) aiding in the lifting of fluids in
the well, or (2) stimulating the reservoir at or near the well by
mechanical, chemical, thermal, or explosive means.
EPA. United States Environmental Protection Agency.
Exploration Facility. Any fixed or mobile structure addressed by this
document that is engaged in the drilling of wells to determine the nature
of potential hydrocarbon reservoirs.
Field. The area around a group of producing wells.
Flocculation. The combination or aggregation of suspended solid particles
in such a way that they form small clumps or tufts resembling wool.
B-4
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Flowing Well. A well that produces oil or gas without any means of
artificial lift.
Fluid Injection. Injection of gases or liquids into a reservoir to force
oil toward and into producing wells.
Formation. Various subsurface geological strata penetrated by well bore.
Fractionation. A process of separating various hydrocarbons from natural
gas or oil as they are produced from the ground.
Fracturing. Application of excessive hydrostatic pressure that fractures
the well bore (causing lost circulation of drilling fluids).
Free Water Knockout. An oil/water separation tank at atmospheric pressure.
Gas-Oil Ratio. Number of cubic feet of gas produced with a barrel of oil.
Gathering Line. A pipeline, usually of small diameter, used in gathering
crude oil from the oil field to a point on a main pipeline.
GC. Gas chromatography.
Geothermal Energy. Defined broadly, includes all of the heat within the
interior of the earth. For the purposes of this report, it includes the
potentially useful part of this energy supply that is represented by
crustal rocks, sediments, volcanic deposits, water, steam, and other gases
that are at usefully high temperatures, are accessible from the earth's
surface, and from which it may be possible to extract useful heat energy.
Gun Barrel. An oil-water separation vessel.
Header. A section of pipe into which several sources of oil, such as well
streams, are combined.
Heater-Treater. A vessel used to break oil water emulsion with heat.
Hot Igneous System. A geothermal energy system created by magma chambers
near the earth's surface.
Hydrocarbon Ion Concentration. A measure of the acidity or alkalinity of
a solution, normally expressed as pH.
Hydrostatic Head. Pressure that exists in the well bore due to the weight
of the column of drilling fluid; expressed in pounds per square inch (psi).
B-5
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Hydrothermal System. A geothermal energy system consisting of high
temperature water and/or steam which is transported near to the surface by
the convective circulation through faults and fractures.
Hyperthermal Fields. (1) Wet Fields - producing pressurized water at
temperatures exceeding 100°C, so that when the fluid is brought to the
surface and its pressure is reduced, a fraction is flashed into steam
while the majority of it remains as boiling water. (2) Dry Fields -
producing dry saturated, or slightly superheated, steam at pressures above
atmospheric.
Inhibitor. An additive that prevents or retards undesirable changes in
the product. Particularly, oxidation and corrosion, and sometimes
paraffin formation.
Injection. Introduction of drilling fluids or produced fluids into an
underground geologic formation, usually for disposal purposes.
Invert Oil Emulsion Drilling Fluid. A water-in-oil emulsion where fresh
or salt water is the dispersed phase and diesel, crude, or some other oil
is the continuous phase. Water increases the viscosity and oil reduces
the viscosity.
Killing a Well. Bringing a well under control that is blowing out. Also,
the procedure of circulating water and drilling fluids into a completed
well before starting well servicing operations.
Location (Drill Site). Place at which a well is to be or has been drilled.
Low Grade Aquifers. Capable of producing useful hot water of low grade
(ranging up to 70°C) because of a temperature gradient.
Marginal Well. An oil or gas well that produces such a small volume of
hydrocarbons that the gross income therefrom provides only a small margin
of profit or, in many cases, does not even cover the cost of production.
("Marginal well" should be distinguished from the definition for "stripper
well" in 44 FR 22073.)
Mud Pit. A steel or earthen tank that is part of the surface drilling mud
system.
Mud Pump. A reciprocating, high pressure pump used for circulating
drilling mud.
Multiple Completion. A well completion that provides for simultaneous
production from separate zones.
B-6
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NPDES Permit. A National Pollutant Discharge Elimination System permit
issued under Section 402 of the Clean Water Act.
96-hr LC-50. The concentration of a test material that is lethal to 50
percent of the test organisms in a bioassay after 96 hours of constant
exposure.
Onsite Air Drilling Pit. An excavated or above grade earthen impoundment
on a well site that holds fluids produced by or associated with the air
drilling process. These fluids include but are not limited to: connate
water, fresh water (for dust suppression), stimulation fluids, completion
fluids, and drilling additives.
Onsite Drilling Mud (Reserve) Pit. An excavated or above grade earthen
impoundment on a well site that holds drilling mud, connate water,
stimulation fluids, completion fluids, or other waste produced by or
associated with drilling.
Onsite Pit Treatment. Treatment of pit contents in situ, or on the
drilling site by the operator. Neutralization, aeration, and settling (or
some combination thereof) are routine onsite pit treatment technologies.
Reverse osmosis is a rare but available onsite pH treatment.
Priority Pollutants. The 65 pollutants and classes of pollutants declared
toxic under Section 307(a) of the Act. Appendix C contains a listing of
specific elements and compounds.
Production Facility. Any platform or fixed structure addressed by this
document that is used for active recovery of hydrocarbons from producing
formations.
Produced Fluids. All of the liquid and gaseous materials yielded by a
well, excluding fluids introduced into the well for enhancement of
productivity. In this document, the term "produced fluids" is normally
construed as the non-product portion of the fluids yielded by a well. In
this context, produced fluids are principally brines.
Produced Water. The water (brine) brought up from the hydrocarbon-bearing
strata during the extraction of oil and gas. It can include formation
water, injection water, and any chemicals added downhole or during the
oil/water separation process.
Produced Sand. Slurried particles used in hydraulic fracturing, and the
accumulated formation sands and scale particles generated during
production.
B-7
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Publicly Owned Treatment Works (POTWs). A treatment facility as defined
by Section 212 of the Clean Water Act, which is owned by a State or
municipality. An "approved POTW treatment program" or "Program" or
"Pretreatment Program" means a program administered by a POTW that meets
the requirements established in 40 CFR 403, and which has been approved by
a Regional Administrator or State Director in accordance with 40 CFR 403.
RCRA. The Resource Conservation and Recovery Act of 1976, as amended.
Semithermal Fields. Capable of producing hot water at temperatures up to
approximately 100°C from depth of 1 to 2 km.
Separation. A process whereby liquid hydrocarbons are separated from
gas. The term is sometimes used to describe a relatively simple process
distinguished from fractionation.
Stimulation. Any action taken by well operator to increase the inherent
productivity of an oil or gas well including, but not limited to,
fracturing, shooting, or acidizing, but excluding cleaning out, bailing,
or workover operations.
Stripper Wells. Wells in a field producing an average of less than 10
barrels of oil per calendar day per well. Water injection wells and gas
wells are excluded from the calculation of average daily oil production
for a field.
Supernatant. A liquid or fluid forming a layer above settled solids.
Tank Bottom Sludge. Sediment, oil, water, and other substances that tend
to concentrate in the bottom of production field vessels, especially stock
tanks, are called field tank bottom sludges. This layer of sludge may be
periodically removed to prevent oil contamination.
Treatment Works. Any devices and systems used in the storage, treatment,
recycling, and reclamation of municipal sewage or industrial wastes of a
liquid nature to implement Section 201 of the Act, or necessary to recycle
or reuse water at the most economical cost of the estimated life of the
works, including intercepting sewers, outfall sewers, sewage collection
systems, pumping, power, and other equipment and their appurtenances
thereof; extensions, improvements, remodeling, additions, and alterations
thereof; elements essential to providing a reliable recycled supply such
as standby treatment units and clear well facilities; and any works,
including site acquisition of the land that will be an integral part of
the treatment process (including land use for the storage of treated
wastewater in land treatment facilities prior to land application) or is
used for ultimate disposal of residues resulting from such treatment.
B-8
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"Treatment works" means any other method or system for preventing,
abating, reducing, storing, treating, separating, or disposing of
municipal waste, including waste combined with storm water and sanitary
sewer systems.
Well Completion. In a potentially productive formation, the completion of
a well in a manner to permit production of oil; the walls of the hole
above the producing layer (and within it if necessary) must be supported
against collapse and the entry into the well of fluids from formations
other than the producing layer must be prevented. A string of casing is
always run and cemented at least to the top of the producing layer, for
this purpose. Some geological formations require the use of additional
techniques to "complete" a well such as casing the producing formation and
using a "gun perforator" to make entry holes, using slotted pipes,
consolidating sand layers with ; chemical treatment, and using
surface-actuated underwater robots for offshore wells.
Workover. To clean out or otherwise work on a well in order to increase
or restore production. A typical workover is cleaning out a well that has
sanded up. Tubing is pulled, the casing and bottom of the hole washed out
with mud, and (in some cases) explosives set off in the hole to dislodge
the silt and sand.
Workover Fluids. Any type of fluid used in the workover operation of a
well.
B-9
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