United States
Imrifonmentai Protection
Agency
Offce of Solid Waste
and Emergency Response
Washington, DC 20460
EPA1530-SW-8&403
December 1S87
Solid Waste
v-xEPA
Report to Congress
Management of Wastes from the
Exploration, Development, and
Production of Crude Oil, Natural Gas,
and Geothermal Energy
Volume 1 of 3
Oil and Gas
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REPORT TO CONGRESS
MANAGEMENT OF WASTES FROM THE
EXPLORATION, DEVELOPMENT, AND PRODUCTION
OF CRUDE OIL, NATURAL GAS, AND GEOTHERMAL ENERGY
VOLUHE 1 OF 3
OIL AND GAS
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Office of Solid Haste and Emergency Response
Washington, D.C. 20460
December 1987
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TABLE OF CONTENTS
Chapter Page
Chapter I - INTRODUCTION
Statutory Requirements and General Purpose 1-1
Study Approach I -3
Study Factors , 1-3
Chapter II - OVERVIEW OF THE INDUSTRY
Description of the Oil and Gas Industry... II-l
Exploration and Development II-2
Production , 11-8
Downhole Operations 11-9
Surface Operations. 11-10
Definition of Exempt Wastes ....11-16
Scope of the Exemption ..11-16
Waste Volume Estimation Methodology.. 11-19
Estimating Volumes of Drilling Fluids and
Cuttings 11-19
EPA's Estimates 11-21
American Petroleum Institute's Estimates 11-23
Estimating Volumes of Produced Water..... 11-24
EPA's Estimates, 11-24
API's Estimates , 11-25
Waste Volume Estimates 11-26
Characterization of Wastes 11-26
Samp! irig Methods. 11-31
EPA Sampling Procedures 11-31
Pit Sampling. .11-31
Produced Water , 11 -32
Central Treatment Facilities 11-32
API Sampling Methods 11-32
Analytical Methods , 11-32
EPA Analytical Methods ...11-33
API Analytical Methods. 11-33
Result s 11-34
Chemical Constituents Found by EPA in Oil and Gas ...11-34
Comparison to Constituents of Potential Concern
Identified in the Risk Analysis 11-36
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TABLE OF CONTENTS (continued)
Chapter II - Continued Page
Facility Analysis. 11-39
Central Treatment Facility 11-40
Central Pit Facility 11-40
Drilling Facilities.. II-40
Production Facility .11-40
Waste Characterization Issues.......'. 11-41
Toxicity Characteristic Leaching Procedure (TCLP) 11-43
Solubility and Mobility of Constituents .11-43
Phototoxic Effect of Polycyclic Aromatic
Hydrocarbons (PAH) 11-44
pH and Other RCRA Characteristics.. 11-45
Use of Constituents of Concern 11-47
References 11-49
Chapter III - CURRENT AND ALTERNATIVE WASTE MANAGEMENT PRACTICES
Introduction. Ill -1
Sources of Information III-3
Limitations. .,111-3
Drilling-Related Wastes ...III-5
Description of Waste 111-5
Drilling Fluids (Muds) III-5
Cuttings III-6
Waste Chemicals 111-6
Fracturing and Acidizing Fluids III-ll
Completion and Workover Fluids .111-12
Rigwash and Other Miscellaneous Wastes..... 111-13
Onsite Drilling Waste Management Methods..... .....111-13
Reserve Pi ts 111 -14
Annular Disposal of Pumpable Drilling Wastes 111-18
Drilling Waste Solidification III-20
Treatment and Discharge of Liquid Wastes to Land
or Surface Water 111-21
Cl osed Cycl e Systems .111-22
Disposal of Drilling Wastes on the North Slope of
Alaska 111-24
Offsite Waste Management Methods .111-27
Centralized Disposal Pits III-27
Centralized Treatment Facilities......... ... ........111-29
11
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TABLE OF CONTENTS (continued)
Chapter III - Continued Page
Commercial Landfarming 111-30
Reconditioning and Reuse of Drilling Media 111-32
Production-Related Wastes. 111-33
Waste Characterization 111-33
Produced Water , 111 -33
Low-Volume Production Wastes. II1-34
Onsite Management Methods II1-34
Subsurface Injection Ill-35
Evaporation and Percolation Pits 111-44
Discharge of Produced Waters to Surface Water
Bodies ..111-44
Other Product ion-Related Pits. .111-45
Offsite Management Methods III-46
Road or Land Applications .111-46
Well Plugging and Abandonment 111-47
References 111 -49
Chapter IV - DAMAGE CASES
Introduction IV-1
Purpose of Damage Case Review .IV-1
Methodology for Gathering Damage Case Information IV-2
Information Categories IV-2
Sources and Contacts ". IV-4
Case Study Development IV-7
Test of Proof IV-7
Review by State Groups and Other Sources IV-9
Limitations of the Methodology and Its Results. IV-9
Schedule for Collection of Damage Case Information ....IV-9
Limited Number of Oil- and Gas-Producing States
in Analysis IV-9
Difficulty in Obtaining a Representative Sample IV-10
Organization of this Presentation IV-11
New England ..IV-12
Appalachia. IV-12
Operations IV-I2
Types of Operators IV-13
Major Issues IV-13
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TABLE OF CONTENTS (continued)
Chapter IV - (Continued) Page
Contamination of Ground Water from Reserve Pits... 1V-I3
Illegal Disposal of Oil field Wastes in Ohio.. IV-14
Contamination of Ground Water from Annular Disposal
of Produced Water IV-16
Illegal Disposal of Oil and Gas Waste in
West Virginia. ' IV-17
Illegal Disposal of Oil Field Waste in
Pennsylvania. ...IV-19
Damage to Water Wells From Oil or Gas Well Drilling
and Fracturing IV-21
Problems with Landspreading in West Virginia ..IV-23
Problems with Enhanced Oil Recovery (EOR) and
Abandoned Wells in Kentucky ...IV-24
Southeast IV-26
Gul f IV-26
Operations IV-26
Types of Operators ; IV-28
Major Issues IV-29
Ground Water Contamination from Unlined Produced
Water Disposal Pits and Reserve Pits : IV-29
Allowable Discharge of Drilling Mud Into.Gulf Coast
Estuaries., IV-30
Illegal Disposal of Oil Field Waste in the Louisiana
Gul f Coast Area IV-32
Illegal Disposal of Oil Field Waste in Arkansas...... IV-35
Improperly Operated Injection Wells IV-38
Midwest IV-38
Operations IV-38
Types of Operators IV-39
Major Issues IV-39
Groundwater Contamination in Michigan.. IV-39
Plains , ... IV-41
Operations IV-42
Types of Operators IV-42
Major Issues. IV-43
Poor Lease Maintenance. IV-43
Unlined Reserve Pits IV-45
IV
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TABLE OF CONTENTS (continued)
Chapter IV - Continued
Problems with Injection Wells. IV-46
Texas/Oklahoma IV-47
Operations IV-47
Types of Operators IV-48
Major Issues IV-48
Discharge of Produced Water and Drilling Mud into Bays
and Estuaries of the Texas Gulf Coast IV-48
Leaching of Reserve Pit Constituents into Ground Water....IV-52
Chloride Contamination of Ground Water from Operation
of Injection Wells IV-53
Illegal Disposal of Oil and Gas Wastes IV-54
Northern Mountain IV-56
Operations. IV-56
Types of Operators IV-56
Major Issues. IV-57
Illegal Disposal of Oil and Gas Wastes IV-57
Reclamation Problems IV-58
Discharge of Produced Water into Surface Streams IV-59
Southern Mountain. IV-60
Operations IV-60
Types of Operators IV-61
Major Issues. '. IV-61
Produced Water Pit and Oil Field Waste Pit Contents
Leaching into Ground Water IV-61
Damage to Ground Water from Inadequately Maintained
Injection Wells IV-65
West Coast IV-66
Operations IV-66
Types of Operators IV-67
Major Issues. IV-67
Discharge of Produced Water and Oily Wastes to
Ephemeral Streams IV-67
Alaska. IV-69
Operations ....IV-69
Types of Operators IV-70
Major Issues IV-70
Reserve Pits, North Slope IV-70
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TABLE OF CONTENTS (continued)
Chapter IV - Continued Page
Waste Disposal on the North Slope IV-73
Disposal of Drilling yastes, Kenai Peninsula IV-74
Miscellaneous Issues . IV-76
Improper Abandoned and Improperly Plugged Wells...... IV-76
Contamination of Ground Water with Hydrocarbons.... IV-79
Oil Spills in the Arctic IV-80
Chapter V - RISK MODELING
Introduction. .V-l
Objectives ..V-l
Scope and Limitations V-2
Quantitative Risk Assessment Methodology V-5
Input Data ...V-7
Environmental Settings V-li
Model ing Procedures V-16
Quantitative Risk Modeling Results: Human Health V-23
Onsite Reserve Pits -- Drilling Wastes V-23
Nationally Weighted Risk Distributions V-24
Zone-Weighted Risk Distributions ..V-28
Evaluation of Major Factors Affecting Health Risk V-29
Underground Injection -- Produced Fluids , .....V-34
Nationally Weighted Risk Distribution V-34
Grout Seal Failure V-35
Well Casing Failure V-37
Zone-Weighted Risk Distributions V-40
Evaluation of Major Factors Affecting Health Risk V-41
Direct Discharge of Produced Water to Surface Streams V-44
Potentially Exposed Population V-45
Quantitative Risk Modeling Results: Resource Damage V-50
Potential Ground-Water Damage -- Drilling Wastes V-5!
Potential Ground-Water Damage -- Produced Water V-53
Potential Surface Water Damage. V-54
Assessment of Waste Disposal on Alaska's North Slope V-55
Locations of Oil and Gas Activities in Relation to
Environments of Special Interest V-61
Conclusions V-64
General Conclusions . V-64
Drilling Wastes Disposed of in Onsite Reserve Pits.. V-65
Produced Fluid Wastes Disposed of in Injection Wells V-67
vi
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TABLE OF CONTENTS (continued)
Chapter V - Continued Page
Stripper Well-Produced fluid Wastes Discharged
Directly into Surface Water V-69
Drilling and Production Wastes Disposed of on Alaska's
North Slope V-69
Locations of Oil and Gas Activities in Relation to
Environments of Special Interest V-70
References V-71
Chapter VI - COSTS AND ECONOMIC IMPACTS OF ALTERNATIVE
WASTE MANAGEMENT PRACTICES
Overview of the Cost and Economic Impact Analysis VI-1
Cost of Baseline and Alternative Waste Management
Practices VI-3
Identification of Waste Management Practices VI-3
Cost of Waste Management Practices VI-6
Waste Management Scenarios and Applicable Waste
Management Practices '.. .VI-14
Baseline Scenario. VI-15
Intermediate Scenario VI-15
The Subtitle C Scenario VI-1.6
The Subtitle C-l Scenario ,...VI-17
Summary of Waste Management Scenarios VI-18
Cost and Impact of the Waste Management Scenarios for
Typical New Oil and Gas Projects VI-18
Economic Models. VI-18
Quantities of Wastes Generated by the Model Projects.......VI-21
Model Project Waste Management Costs VI-21
Impact of Waste Management Costs on Representative
Projects VI-25
Regional and National-Level Compliance Costs of the
Waste Management Scenarios..-., VI-30
Closure Analysis for Existing Wells. VI-32
Intermediate and Long-Term Effects of the Waste
Management Scenarios. .VI-35
Production Effects of Compl iance Costs VI-35
Additional Impacts of Compliance Costs VI-37
References. VI-42
Chapter VII - CURRENT REGULATORY PROGRAMS
Introduction. VII-1
State Programs ...VII-1
Federal Programs - EPA VII-2
Underground Injection Control VII-2
Effluent Limitations Guidelines VII-4
Vll
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TABLE OF CONTENTS (continued)
Chapter VII - Continued Page
Summary of Major Regulatory Activity Related
to Onshore Oil and Gas. VII-5
Onshore Segment Subcategories.. VI1-6
Onshore VII-6
Stripper (Oil Wells) VII-6
Coastal VII-7
Wildlife and Agriculture Use ...VII-7
Federal Programs - Bureau of Land Management................VII-8
Introduction. VII-8
Regulatory Agencies. VII-8
Rules and Regulations .VII-9
Drilling VII-10
Production , VII-11
Disposal in Pits .VII-11
Injection... VII-13
PI ugg i ng/Abandonment VII-13
Implementation of State and Federal Programs VII-14
References , VII-35
Chapter VIII - CONCLUSIONS "., .VIII-1
Chapter IX - RECOMMENDATIONS..... . IX-1
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LIST OF TABLES
Table Page
II-l Partial List of Exempt and Nonexempt Wastes 11-20
11-2 Estimated U.S. Drilling Waste Volumes, 1985 11-27
11-3 Estimated U.S. Produced Water Volumes, 1985....... 11-29
II-4 Constituents of Concern Found in Waste Streams
Sampled by EPA and API 11-37
II-5 EPA Samples Containing Constituents of Concern 11-38
II-6 pH Values for Exploration, Development, and Production
Wastes (EPA Samples). ..11-46
II-7 Comparison of Potential Constituents of Concern that
Were Modeled in Chapter V 11-48
III-l States with Major Oil Production Used as Primary
References in This Study ..III-4
III-2 Characterization of Oil and Gas Drilling Fluids .111-7
IV-1 Types of Damage of Concern to This Study. IV-3
IV-2 List of States from Which Case Information Was
Assembled IV-5
IV-3 Sources of Information Used in Developing Damage Cases...IV-6
V-l Model Constituents and Concentrations V-li
V-2 Toxicity Parameters and Effects Thresholds V-12
V-3 Drilling Pit Waste (Waste-Based) Management Practices V-14
V-4 Produced Water Waste Management Practices V-15
V-5 Values and Sources for Environmental Setting Variables V-17
V-6 Definition of Best-Estimate and Conservative Release
Assumptions . V-18
V-7 Definition of Flow Fields Used in Groundwater
Transport Model ing V-22
V-8 Surface Water Flow Rates at Which Concentrations of
Waste Stream Constituents in the Mixing Zone Will
Exceed Reference Level s V-46
V-9 Population Potentially Exposed Through Private Drinking
Water Wells at Sample Drilling and Production Areas V-48
V-10 Population Potentially Exposed Through Public Water
Supplies at Sample Drilling and Production Areas.... V-49
V-ll Surface Water Flow Rates at Which Concentrations of
Waste Stream Constituents in the Mixing Zone Will
Exceed Aquatic Effects and Resource Damage Thresholds...V-56
IX
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LIST OF TABLES (continued)
Table
VI-1 Summary of Baseline Disposal Practices Vl-5
VI-2 Summary of Engineering Design Elements for Baseline
and Alternative Waste Management Practices VI-7
VI-3 Unit Costs of Drilling Waste Disposal Options, by Zone VI-12
VI-4 Unit Costs of Underground Injection of Produced Water,
by Zone VI -13
VI-5 Assumed Waste Management Practices for Alternative
Waste Management Scenarios. .VI-19
VI-6 Economic Parameters of Model Projects for U.S.
Producing Zones. VI-22
VI-7 Average Quantities of Waste Generated, by Zone VI-23
Vl-8 Weighted Average Regional Costs of Drilling Waste
Management for Model Projects Under Alternative
Waste Management Scenarios VI-26
VI-9 Weighted Average Unit Costs of Produced Water
Management for Model Projects Under Alternative
Waste Management Scenarios VI-27
VI-10 Impact of Waste Management Costs on Model Projects:
Comparisons of After-Tax Internal Rate of Return VI-28
VI-11 Impact of Waste Management Costs on Model Proj'ects;
Increase in Total Cost of Production...... VI-29
VI-12 Annual Regional and National RCRA Compliance
Costs of Alternative Waste Management Scenarios VI-31
VI-13 Distribution of Oil Production Across Existing
Projects, 1985. VI-33
VI-14 Impact of Waste Management Cost on Existing Production VI-34
VI-15 Long-Term Impacts on Production of Cost Increases
Under Waste Management Scenarios VI-38
VI-I6 Effect of Domestic Production Decline on Selected
Economic Parameters in the Year 2000.. VI-39
VII-1 Reserve Pit Design, Construction, and Operation..........VII-15
VI1-2 Reserve Pit Closure/Waste Removal VII-20
VII-3 Produced Water Pit Design and Construction VII-24
VII-4 Produced Water Surface Discharge Limits VII-26
VI1-5 Produced Water Injection Well Construction VII-28
VII-6 Well Abandonment/Plugging. VII-31
VII-7 State Enforcement Matrix VII-33
VII-8 BLM Enforcement Matrix VII-34
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LIST OF FIGURES
Figure Page
1-1 Oil and Gas Production Zones..... 1-6
II-l Typical Rotary Drilling Rig II-4
II-2 Typical Production Operation, Showing Separation of
Oil, Gas, and Water 11-11
II-3 Average Water Production with Dissolved/Associated Gas...11-12
II-4 Oil Production with High Oil/Water Ratio Without
Significant Dissolved Associated Gas 11-13
III-l Annular Disposal of Waste Drilling Fluid ,...111-19
III-2 Typical Produced Water Disposal Design 111-37
III-3 Annular Disposal Outside Production Casing 111-38
III-4 Pollution of a Freshwater Aquifer Through
Improperly Abandoned Well s 111 -48
V-l Overview of Quantitative Risk Assessment Methodology......V-6
V-2 Overview of Modeling Scenarios Considered in the
Quantitative Risk Assessment V-9
V-3 Nationally Weighted Distribution of Health Risk
Estimates. V-25
V-4 Weighted vs. Unweighted Distribution of Cancer
Risk Estimates V-27
V-5 Health Risk Estimates (Unweighted) as a Function
of Size and Distance, V-32
V-6 Health Risk Estimates (Unweighted) as a Function
of Ground-Water Type V-33
V-7 Nationally Weighted Distribution of Health Risk
Estimates V-36
V-8 Nationally Weighted Distribution of Health Risk
Estimates , V-38
V-9 Nationally Weighted Distribution of Health
Risk Estimates . . V-39
V-10 Health Risk Estimates (Unweighted) as a Function of
Ground-Water Type V-43
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LIST OF EXHIBITS
Exhibit Pege
*
Exhibit 1 Section 8002(m) Resource Conservation and
Recovery Act as amended by PL 96-482 , ......1-13
xn
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CHAPTER I
INTRODUCTION
STATUTORY REQUIREMENTS AND GENERAL PURPOSE
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).1 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 requires the
Administrator to*study these wastes and submit a final report to
Congress. This report responds to those requirements. Because of the
many inherent differences between the oil and gas industry and the
geothermal energy industry, the report is submitted in three volumes.
Volume 1 (this volume) covers the oil and gas industry; Volume 2 covers
the geothermal energy industry; Volume 3 covers State regulatory
summaries for the oil and gas industry and includes a glossary of terms.
This report discusses wastes generated only by the onshore segment of the
oil and gas industry.
The original deadline for this .study was October 1982. EPA failed to
meet that deadline, and in August 1985 the Alaska Center for the
Environment sued the Agency for its failure to conduct the study.
EPA 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 Mater Act, Determining emissions
standards under the Clean Air Act, and imp lenient ing the requirements of the underground injection
control program under the Safe Drinking Water Act.
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EPA entered into a consent order, obligating it to submit the final
Report to Congress on or before August 31, 1987. In April 1987, this
schedule was modified and the deadline for submittal of the final Report
to Congress was extended to December 31, 1987,
Following submission of the current study, and after public hearings
and opportunity for comment, the Administrator of EPA must determine
either to promulgate regulations under the hazardous waste management
provisions of RCRA (Subtitle C) or to declare that such regulations are
unwarranted. Any regulations would not take effect unless authorized by
an act of Congress.
This does not mean that the recommendations of this report are
limited to a narrow choice between application of full Subtitle C
regulation and continuation of the current exemption. Section 8002(m)
specifically requires the Administrator to propose recommendations for
"[both] Federal and non-Federal actions" to prevent or substantially
mitigate any adverse effects associated with management of wastes from
these industries. EPA interprets this statement as a directive to
consider the practical and prudent means available to avert health or
environmental damage associated with the improper management of oil, gas,
or geothermal wastes. The Agency has identified a wide range of possible
actions, including voluntary programs, cooperative work with States to
modify their programs, and Federal action outside of RCRA Subtitle C,
such as RCRA Subtitle D, the existing Underground Injection Control
Program under the Safe Drinking Water Act, or the National Pollution
Discharge Elimination System under the Clean Water Act.
In this light, EPA emphasizes that the recommendations presented here
do not constitute a regulatory determination. Such a determination
cannot be made until the public has had an opportunity to review and
comment on this report (i.e., the determination cannot be made until June
1988). Furthermore, the Agency is, in several important areas,
presenting optional approaches involving further research and
consultation with the States and other affected parties.
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STUDY APPROACH
The study factors are listed in the various paragraphs of Section
8002(m), which is quoted in its entirety as Exhibit 1 (page 1-13). For
clarity, the Agency has designed this report to respond specifically to
each study factor within separate chapters or sections of chapters. It
is important to note that although every study factor has been weighed in
arriving at the conclusions and recommendations of this report, no single
study factor has a determining influence on the conclusions and
recommendations.
The study factors are defined in the paragraphs below, which also
introduce the methodologies used to analyze each study area with respect
to the oil and gas industry. Hore detailed methodological discussions
can be found later in this report and in the supporting documentation and
appendices.
STUDY FACTORS
The principal study factors of concern to Congress are listed in
subparagraphs (A) through (G) of Section 8002(m)(l) {see Exhibit 1). The
introductory and concluding paragraphs of the Section, however, also
contain directives to the Agency on the content of this study. This
work has therefore been organized to respond to the following
comprehensive interpretation of the 80Q2(m) study factors.
Study Factor 1 - Defi ni ng Exempt Wastes
RCRA describes the exempt wastes in broad terms, referring to
"drilling fluids, produced waters, and other wastes associated with the
exploration, development, or production of crude oil or natural gas or
geothennal energy." The Agency, therefore, relied to the extent possible
on the legislative history of the amendments, which provides guidance on
the definition of other wastes. The tentative scope of the exemption is
discussed in Chapter II of this volume.
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Study Factor 2 - Specifying the Sources and Volumes of Exempt Wastes
In response to Section 8002{m)(1)(A), EPA has developed estimates of
the sources and volumes of all exempt wastes. The estimates are
presented in •Chapter II, "Overview of the Industry."
Comprehensive information on the volumes of exempt wastes from oil
and gas operations is not routinely collected nat-ionwide; however,
estimates of total volumes produced can be made through a variety of
approaches.
With respect to drilling muds and related wastes, two methods for
estimating volumes are presented. The first, developed early in the
study by EPA, estimates drilling wastes as a function of the size of
reserve pits. The second method is based on a survey conducted by the
American Petroleum Institute (API) on production of drilling muds and
completion fluids, cuttings, and other associated wastes discharged to
reserve pits. Both methods and their results are included in Chapter II.
Similarly, EPA and API developed independent estimates of produced
water volumes. EPA's first estimates were based on a survey of the
injection, production, and hauling reports of State agencies; API's were
based on its own survey of production operations. Again, this report
presents the results of both methodologies,
Study Factor 3 - Characterizing Wastes
Section 8002(m) does not directly call for a laboratory analysis of
the exempted wastes, but the Agency considers such a review to be a
necessary and appropriate element of this study. Analysis of the
principal high-volume wastes (i.e., drilling fluids and produced waters)
can help to indicate whether any of the wastes may be hazardous under the
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definitions of RCRA Subtitle C. Wastes were examined with regard to
whether they exhibited any of the hazardous characteristics defined under
40 CFR 261 of RCRA, including extraction procedure toxicity,
ignitability, corrosivity, and reactivity. Also, a compositional
analysis was performed for the purpose of determining if hazardous
constituents were present in the wastes at concentrations exceeding
accepted health-based limits.
EPA therefore conducted a national screening type program that
sampled facilities to compile relevant data on waste characteristics.
Sites were selected at random in cooperation with State regulatory
agencies, based on a division of the United States into zones (see
Figure 1-1). Samples were subjected to extensive analysis, and the
results were subjected to rigorous quality control procedures prior to
their publication in January 1987. Simultaneously, using a different
sampling methodology, API sampled the same sites and wastes covered by
the EPA-sponsored survey. Chapter II of this report, "Overview of the
Industry," presents a summary of results of both programs.
Study Factor 4 - Describing Current Disposal Practices
Section 8002(m}(l)(B) calls for an analysis of current disposal
practices for exempted wastes. Chapter III, "Current and Alternative
Waste Management Practices," summarizes EPA's review, which was based on
a number of sources. Besides reviewing the technical literature, EPA
sent representatives to regulatory agencies of the major oil- and
gas-producing States to discuss current waste management technologies
with State representatives. In addition, early drafts of this study's
characterizations of such technologies were reviewed by State and
industry representatives.
1-5
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Zone 8
Northern
Mountain
Zone 9
Southern
Mountain
Zone 7
Texas-
Oklahoma '
Figure 1-1
Oil and Gas Production Zones
Divisions of the United States
Used for the
RCRA Section 8002(m) Study of
OH and Gas Wastes
1-6
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The Agency intentionally has not compiled an exhaustive review of
waste management technologies used by the oil and gas industry. As
stressed throughout this volume, conditions and methods vary widely from
State to State and operation to operation. Rather, the Agency has
described the principal and common methods of managing field-generated
wastes and has discussed these practices in general and qualitative terms
in relation to their effectiveness in protecting human health and the
envi ronment.
Study Factor 5-Documenting Evidence of Damage to Human Health and the
Environment Caused by Management of Oil and Gas Wastes
Section 8002(m)(1)(0) requires EPA to analyze "documented cases" of
health and environmental damage related to surface runoff or leachate.
Although EPA has followed this instruction, paragraph (1) of the section*
also refers to "adverse effects of such wastes [i.e., exempted wastes,
not necessarily only runoff and leachate] on humans, water, air, health,
welfare, and natural resources,..."
Chapter IV, "Damage Cases," summarizes EPA's effort to collect
documented evidence of harm to human health, the environment, or valuable
resources. Cases were accepted for presentation in this report only if,
prior to commencement of field work, they met the standards of the test
of proof, defined as (1) a scientific study, (2) an administrative
finding of damage under State or other applicable authority, or
(3) determination of damage by a court. Many cases met more than one
such test of proof.
A number of issues of interpretation have been raised that must be
clarified at the outset. First, in the Agency's opinion, the case study
approach, such as that called for by Section 8002(m)» is intended only to
define the nature and range of known damages, not to estimate the
frequency or extent of damages associated with typical operations. The
1-7
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results presented here should not be interpreted as having statistical
significance. The number of cases reported in each category bears no
statistically significant relationship to the actual types and
distribution of damages that may or may not exist across the United
States.
Second, the total number of cases bears no implied or intended
relationship to the total extent of damage from oil or gas operations
caused at present or in the past.
Third, Section 8002(m)(])(D) makes no mention of defining
relationships between documented damages and violations of State or other
Federal regulations. As a practical necessity, EPA has in fact relied
heavily on State enforcement and complaint files in gathering
documentation for this section of the report," Consequently, a
large proportion of cases reported here involve violations of State
regulations. However, the fact that the majority of cases presented here
involve State enforcement actions implies nothing, positive or negative,
about the success of State programs in enforcing their requirements on
industry.
Study Factor 6 - Assessing Potential Danger to Human Health or the
Enyironment from the Wastes
Section 8002{m)(1)(C) requires analysis of the potential dangers of
surface runoff and leachate. These potential effects can involve all
types of damages over a long period of time and are not necessarily
limited to the categories of damages for which documentation is currently
available.
* Other source* "Jve included evidence Submitted by private citizens or supplied by attorneys
in response to inquiries from fPA researchers
1-8
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Several methods of estimating potential damages are available, and
EPA has combined two approaches in responding to this study factor in
Chapter V, "Risk Modeling." The first has been to use quantitative risk
assessment modeling techniques developed for use elsewhere in the RCRA
program. The second has been to apply more qualitative methods, based on
traditional environmental assessment techniques.
The goal of both the quantitative and the qualitative risk
assessments has been to define the most important factors in causing or
averting human health risk and environmental risk from field operations.
For the quantitative evaluation, EPA has adapted the EPA Liner Location
Model, which was built to evaluate the impacts of land disposal of
hazardous wastes, for use in analyzing drilling and production
conditions. Since oil and gas operations are in many ways significantly
different from land disposal of hazardous wastes, all revisions to the
Liner Location Model and assumptions made in its present application have
been extensively documented and are summarized in Chapter V. The
procedures of traditional environmental assessment needed no modification
to be applied.
As is true in the damage case work, the results of the modeling
analysis have no statistical significance in terms of either the pattern
or the extent of damages projected. The Agency modeled a subset of
prototype situations, designed to roughly represent significant
variations in conditions across the country. The results are very useful
for characterizing the interactions of technological, geological, and
climatic differences as they influence the potential for damages.
Study Factor 7...- Reviewing the Adequacy of Government and Private
Measures to Prevent and/or Mitigate any Adverse Effects
Section 8002 (m)(l) requires that the report's conclusions of any
adverse effects associated with current management of exempted wastes
1-9
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include consideration of the "adequacy of means and measures currently
employed by the oil and gas industry, Government agencies, and others" to
dispose of or recycle wastes or to prevent or mitigate those adverse
effects.
Neither the damage case assessment nor the risk assessment provided
statistically representative data on the extent of damages, making it
impossible to compare damages in any quantitative way to the presence and
effectiveness of control efforts. The Agency's response to this
requirement is therefore based on a qualitative assessment of all the
materials gathered during the course of assembling the report and on a
review of State regulatory programs presented in Chapter VII, "Current
Regulatory Programs." Chapter VII reviews the elements of programs and
highlights possible inconsistencies, lack of specificity, potential
problems in implementation, or gaps in coverage. Interpretation of the
adequacy of these control efforts is presented in Chapter VIII,
"Conclusions."
Stud_y__Factor 8 - Defining Alternatives to Current. Waste Management
Practices
Section 8002 (m)(l) requires EPA to analyze alternatives to current
disposal methods. EPA's discussion in response to this study factor is
incorporated in Chapter III, "Current and Alternative Waste Management
Practices."
Chapter III merges the concepts of current and alternative waste
management practices. It does not single out particular technologies as
potential substitutes for current practices because of the wide variation
in practices among States and among different types of operations.
Furthermore, waste management technology in this field is fairly simple.
At least for the major high-volume waste streams, no significant,
field-proven, newly invented technologies that can be considered
"innovative" or "emerging" are in the research or development stage.
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Practices that are routine in one location may be considered innovative
or alternative elsewhere. On the other hand, virtually every waste
management practice that exists can be considered "current" in one
specific situation or another.
This does not mean that improvements are not possible: in some cases,
currently available technologies may not be properly selected,
implemented, or maintained. Near-term improvements in waste management
in these industries will likely be based largely on more effective use of
what is already available.
Study Factor 9 - Estimating theCostsof.AlternativePractices
Subparagraph (F) calls for analysis of costs of alternative
practices. The first several sections of Chapter VI, "Costs and Economic
Impacts of Alternative Waste Management Practices," present the Agency's
analysis of this study factor.
For the purposes of this report, EPA based its cost estimates on 21
prototypical regional projects, defined so as to capture significant
differences between major and independent companies and between stripper
operations and other projects. The study evaluates costs of waste
disposal only for the two principal high-volume waste streams of concern,
drilling fluids and produced waters, employing as its baseline the use of
unlined reserve pits located at the drill site and the disposal of
produced waters in injection wells permitted under the Federal
Underground Injection Control Program and located off site.
The study then developed two alternative scenarios that varied the
incremental costs of waste management control technology, applied them to
each prototype project, and modeled the cost impacts of each. The
Ml
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first scenario imposes a set of requirements typical of full Subtitle C
management rules; the second represents a less stringent and extensive
range of requirements based, in essence, on uniform nationwide use of the
most up-to-date and effective controls now being applied by any of the
States. Model results indicate cumulative annual costs, at the project
level, of each of the more stringent control scenarios.
Study Factor 10 -Estimating theEconomic Impacts on Industry of
Alternative Practices
In response to the requirements of subparagraph (G), the final two
sections of Chapter VI present the Agency's analysis of the potential
economic impacts of nationwide imposition of the two control scenarios
analyzed at the project level.
Both the cost and the economic impact predicted in this report are
admittedly large. Many significant variations influence the economics of
this industry and make it difficult to generalize about impacts on either
the project or the national level. In particular, the price of oil
itself greatly affects both levels. Fluctuations in the price of oil
over the period during which this study was prepared have had a profound
influence on project economics, making it difficult to draw conclusions
about the current or future impacts of modified waste management
practices.
Nevertheless, the Agency believes that the analysis presented here is
a reasonable response to Congress's directives, and that the results,
while they cannot be exact, accurately reflect the general impacts that
might be expected if environmental control requirements were made more
stringent.
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1
Section 8CO?|fE} Sesoyrce Conservation and Recovery Act as amended by PL 96-482
"(m) Drilling Fluids, Produced Haters, and Other Wastes Associated with the Extraction,
Development, or Production of Crude Oil or Natural Gas or Geothermal Energy,- (i) The
Administrator shall conduct a detailed and comprehensive study and submit a report on
the adverse effects, if any, of drilling fluids, produced waters, and other wastes
associated with the exploration, deve lopwent . or production of crude oil or natural gas
or geotherrrtdl energy on human health and the env tronwent , including, but not limited to
the effects of sucn wastes on humans, water, air. health, welfare, and natural resources
and on the adequacy of means and measures currently employed by the oil and gas and
geo thermal drilling and production industry. Government agencies, and others to dispose
of ana utilize sucn wastes and to prevent or substantially mitigate such adverse
effects, SycN study shall include art analysis of-
"(A) the sources and volume of discarded material generated per year from such
wastes;
"(B) present disposal practices:
"(C) potential danger to human health and the environment from the surface runoff or
leachate;
"(0) documented cases which prove or have caused danger to human health and the
environment from surface runoff or leacftate;
"(E) alternatives to current disposal methods:
"(F) the cost of such alternatives; and
"(G) the impact of those alternatives on the exploration for. and development and
production of, crude oil and natural gas or geothermal energy.
In furtherance of this study, the Administrator shall, as he deems appropriate, review
studies and other actions of other. Federal agencies concerning such wastes with a view
toward avoiding duplication of effort and the need to expedite Such study The
Administrator shall publish a report of such and shall include appropriate findings and
recommendations for Federal and non-Federal actions concerning such effects.
"(2) The Administrator shall complete the research and study and submit the report
required under paragraph (1) not later than twenty-four months from the dale of
enacticent of the Solid Waste Disposal Act Amendments of 1980, Upon couplet ion of the
study, the Administrator shall prepare a summary of the findings of the study, a plan
for research, development, and demonstration respecting the findings of the study, and
shall submit the findings and the study, along with any recommendations resulting from
such study, to the Conmittee on Environment and Public Works of the United States Senate
and the Cowmttee on Interstate and Foreign Comierce of the United states House of
Representat ives .
"(3) There are authorized to be appropriations not to exceed $1,000,000 to carry out the
provisions of this subsection.
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CHAPTER II
OVERVIEW OF THE INDUSTRY
DESCRIPTION OF THE OIL AND GAS INDUSTRY
The oil and gas industry explores for, develops, and produces
petroleum resources. In 1985 there were approximately 842,000 producing
oil and gas wells in this country, distributed throughout 38 States.
They produced 8.4 million barrels1 of oil, 1.6 million barrels of
natural gas liquids, and 44 billion cubic feet of natural gas daily, The
American Petroleum Institute estimates domestic resexvfiS—at. 28.4 billion
barrels of oil, 7.9 billion barrels of natural gas liquids, and 193
trillion cubic feet of gas. Petroleum exploration, development, and
production industries employed approximately 421,000 people in
1985.2
The industry is as varied as it is large. Some aspects of
exploration, development, and production can change markedly from region
to region and State to State. Well depths range from as little as 30 to
50 feet in some areas to over 30,000 feet in areas such as the Anadarko
Basin of Oklahoma. Pennsylvania has been producing oil for 120 years;
Alaska for only 15. Maryland has approximately 14 producing wells; Texas
has 269,000 and completed another 25,721 in 1985 alone. Production from
a single well can vary from a high of about 11,500 barrels per day (the
1985 average for wells on the Alaska North Slope) to less than 10 barrels
per day for many thousands of "stripper" wells located in Appalachia and
Crude oil production has traditionally been expressed in barrels. A barrel is equivalent
.61 ft3, 0.158 s3, or 42 U.S. gallons.
These numbers, provided to EPA by the Bureau of Land Management (6LH), are generally
•ant uri
to 5
2
accep
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the more developed portions of the rest of the country.3 Overall,
70 percent of all U.S. oil wells are strippers, operating on the margins
of profitability. Together, however, these strippers contribute 14
percent of total U.S. production — a number that appears small, yet is
roughly the equivalent of the immense Prudhoe Bay field in Alaska.
Such statistics make it clear that a short discussion such as this
cannot provide a comprehensive or fully accurate -description of this
industry. The purpose of this chapter is simply to present the
terminology used in the rest of this report4 and to provide an
overview of typical exploration, development, and production methods.
With this as introduction, the chapter then defines which oil and gas
wastes EPA considers to be exempt within the scope of RCRA Section 8002;
estimates the volumes of exempt wastes generated by onshore oil and gas
operations; and presents the results of sample surveys conducted by EPA
and the American Petroleum Institute to characterize the content of
exempt oil and gas wastes.
Exploration and Development
Although geological and geophysical studies provide information
concerning potential accumulations of petroleum, the only method that can
confirm the presence of petroleum is exploratory drilling. The majority
of exploratory wells are "dry" and must be plugged and abandoned. When
an exploratory well does discover a commercial deposit, however, many
development wells are typically needed to extract oil or gas from that
reservoir.
The definition of "stripper" well way vary from State to State. For example. North Dakota
defines a stripper as a well that produces 10 barrels per day or less at 6,000 feet or less; 11 to
15 barrels per day from & depth of 6,001 feet to 10,000 feet; and 16 to 20 barrels per day for wells
that are 10.000 feet deep.
4
A glossary of terms is also provided in Volume 3.
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Exploratory and development wells are mechanically similar and
generate similar wastes up to the point of production. In order to bring
a field into production, however, development wells generate wastes
associated with well completion and stimulation; these processes are
discussed below. From 1981 to 1985, exploration and development drilling
combined averaged 73,000 wells per year (API 1986). Drilling activity
declined in 1986 and by mid-1987 rebounded over 1986 levels.
In the early part of the century, cable-tool drilling was the
predominant method of well drilling. The up-and-down motion of a
chisel-like bit, suspended by a cable, causes it to chip away the rock,
which must be periodically removed with a bailer. Although an efficient
technique, cable-tool drilling is limited to use in shallow, low-pressure
reservoirs. Today, cable-tool drilling is used on a very limited basis
in the United States, having been replaced almost entirely by rotary
drill ing.
Rotary drilling provides a safe method for controlling high-pressure
oil/gas/water flows and allows for the simultaneous drilling of the well
and removal of cuttings, making it possible to drill wells over 30,000
feet deep. Figure II-l illustrates the process. The rotary motion
provided by mechanisms on the drill rig floor turns a drill pipe or stem,
thereby causing a bit on the end of the pipe to gouge and chip away the
rock at the bottom of the hole. The bit itself generally has three
cone-shaped wheels tipped with hardened teeth and is weighted into place
by thick-walled collars. Well casing is periodically cemented into the
hole, providing a uniform and stable conduit for the drill stem as it
drills deeper into the hole. The casing also seals off freshwater
aquifers, high-pressure zones, and other troublesome formations.
Most rotary drilling operations employ a circulation system using a
water- or oil-based fluid, called "mud" because of its appearance. The
11-3
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vf.
SPENT MUD
»fAND CUTTtNGS
MUD TANK
II.
-------
mud is pumped down the hollow drill pipe and across the face of the bit
to provide lubrication and remove cuttings. The mud and cuttings are
then pumped back up through the annular space between the drill pipe and
the walls of the hole or casing. Mud is generally mixed with a weighting
agent such as barite, and other mud additives, thus helping it serve
several other important functions: (1) stabilizing the wellbore and
preventing cave-ins, (2) counterbalancing any high-pressure oil, gas, or
water zones in the formations being drilled, and (3) providing a medium
to alleviate problems "downhole" (such as stuck pipe or lost circulation).
Cuttings are removed at the surface by shale shakers, desanders, and
desilters; they are then deposited in the reserve pit excavated or
constructed next to the rig. The reclaimed drilling mud is then
recirculated back to the well. The type and extent of solids control
equipment used influences how well the cuttings can be separated from the
drilling fluid, and hence influences the volume of mud discharged versus
how much is recirculated. Drilling mud must be disposed of when excess
mud is collected, when changing downhole conditions require a whole new
mud formulation, or when the well is abandoned. The reserve pit is
generally used for this purpose. (Reserve pits serve multiple waste
management functions. See discussion in Chapter III.) If the well is a
dry hole, the drilling mud may be disposed of downhole upon abandonment.
The formation of a drilling mud for a particular job depends on types
of geologic formations encountered, economics, availability, problems
encountered downhole, and well data collection practices. Water-based
drilling muds predominate in the United States, Colloidal materials,
primarily bentonitic clay, and weighting materials, such as barite, are
common constituents. Numerous chemical additives are available to give
the mud precise properties to facilitate the drilling of the well; they
include acids and bases, salts, corrosion inhibitors, viscosifiers,
II-5
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dispersants, fluid loss reducers, lost circulation materials,
flocculants, surfactants, biocides, and lubricants. (See also Table
III-2.)
Oil-based drilling fluids account for approximately 3 to 10 percent
of the total volume of drilling fluids used nationwide. The oil base may
consist of crude oil, refined oil (usually fuel oil or diesel), or
mineral oil. Oil-based drilling fluid provides lubrication in
directionally drilled holes, high-temperature stability in very deep
holes, and protection during drilling through water-sensitive formations.
In areas where high-pressure or water-bearing formations are not
anticipated, air drilling is considerably faster and less expensive than
drilling with water- or oil-based fluids. (Air drilling cannot be used
in deep wells.) In this process, compressed air takes the place of mud,
cooling the bit and lifting the cuttings back to the surface. Water is
injected into the return line for dust suppression, creating a slurry
that must be disposed of. In the United States, air drilling is post
commonly used in the Appalachian Basin, in southeastern
Kansas/northeastern Oklahoma, and in the Four Corners area of the
Southwest. Other low-density drilling fluids are used in special
situations. Gases other than air, usually nitrogen, are sometimes
useful. These may be dispersed with liquids or solids, creating wastes
in the form of mist, foam, emulsion, suspension, or gel.
Potential producing zones are commonly measured and analyzed (logged)
during drilling, a process that typically generates no waste. If
hydrocarbons appear to be present, a drill stem test can tell much about
their characteristics. When the test is completed, formation fluids
collected in the drill pipe must be disposed of.
If tests show that commercial quantities of oil and gas are present,
the well must be prepared for production or "completed." "Cased hole"
11-6
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completions are the most common type. First, production casing is run
into the hole and cemented permanently in place. Then one or more
strings of production tubing are set in the hole, productive intervals
are isolated with packers, and surface equipment is installed. Actual
completion involves the use of a gun or explosive charge that perforates
the production casing and begins the flow of petroleum into the well.
During these completion operations, drilling fluid in the well may be
modified or replaced by specialized fluids to control flow from the
formation. A typical completion fluid consists of a brine solution
modified with petroleum products, resins, polymers, and other chemical
additives. When the well is produced initially, the completion fluid may
be reclaimed or treated as a waste product that must be disposed of. For
long-term corrosion protection, a packer fluid is placed into the
casing/tubing annulus. Solids-free diesel oil, crude oil, produced
water, or specially treated drilling fluid are preferred packer fluids.
Following well completion, oil or gas in the surrounding formations
frequently is not under sufficient pressure to flow freely into the well
and be removed. The formation may be impacted with indigenous material,
the area directly surrounding the borehole may have become packed with
cuttings, or the formation may have inherent low permeability.
Operators use a variety of stimulation techniques to correct these
conditions and increase oil flow. Acidizing introduces acid into the
production formation, dissolving formation matrix and thereby enlarging
existing channels in carbonate-bearing rock. Hydraulic fracturing
involves pumping specialized fluids carrying sand, glass beads, or
similar materials into the production formation under high pressure; this
creates fractures in the rock that remain propped open by the sand,
beads, or similar materials when pressure is released.
II-7
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Other specialized fluids may be pumped down a production well to
enhance its yield; these can include corrosion inhibitors, surfactants,
friction reducers, complexing agents, and cleanup additives. Although
the formation may retain some of these fluids, most are returned to the
surface when the well is initially produced or are slowly released over
time. These fluids may require disposal, independent of disposal
associated with produced water.
Drilling operations have the potential to create air pollution from
several sources. The actual drilling equipment itself is typically run
by large diesel engines that tend to emit significant quantities of
particulates, sulfur oxides, and oxides of nitrogen, which are subject to
regulation under the Clean Air Act. The particulates emitted may contain
heavy metals as well as polycyclic organic matter (ROMs). Particularly
for deep wells, which require the most power to drill, and in large
fields where several drilling operations may be in progress at the same
time, cumulative diesel emissions can be important. Oil-fired turbines
are also used as a source of power on newer drilling rigs. Other sources
of air pollution include volatilization of light organic compounds from
reserve pits and other holding pits that may be in use during drilling;
these are exempt wastes. These light organics can be volatilized from
recovered hydrocarbons or from solvents or other chemicals used in the
production process for cleaning, fracturing, or well completion. The
volume of volatile organic compounds is insignificant in comparison to
diesel engine emissions.
Production
Production operations generally include all activities associated
with the recovery of petroleum from geologic formations. They can be
divided into activities associated with downhole operations and
activities associated with surface operations. Downhole operations
include primary, secondary, and tertiary recovery methods; well
workovers; and well stimulation activities. Activities associated with
II-8
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surface operations include oil/gas/water separation, fluid treatment, and
disposal of produced water. Each of these terms is discussed briefly
below.
Downhole Operations
Primary recovery refers to the initial production of oil or gas from
a reservoir using natural pressure or artificial lift methods, such as
surface or subsurface pumps and gas lift, to bring it out of the
formation and to the surface. Most reservoirs are capable of producing
oil and gas by primary recovery methods alone, but this ability declines
over the life of the well. Eventually, virtually all wells must employ
some form of secondary recovery,, typically involving injection of gas or
liquid into the reservoir to maintain pressure within the producing
formation. Waterflooding is the most frequently employed secondary
recovery method. It involves injecting treated fresh water, seawater, or
produced water into the formation through a separate well or wells.
Tertiary recovery refers to the recovery of the last portion of the
oil that can be economically produced. Chemical, physical, and thermal
methods are available and may be used in combination. Chemical methods
involve injection of fluids containing substances such as surfactants and
polymers. Miscible oil recovery involves injection of gases, such as
carbon dioxide and natural gas, which combine with the oil. Thermal
recovery methods include steam injection and in situ combustion (or "fire
flooding"). When oil eventually reaches a production well, injected
gases or fluids from secondary and tertiary recovery operations may be
dissolved or carried in formation oil or water, or simply mixed with
them; their removal is discussed below in conjunction with surface
production operations.
Workovers, another aspect of downhole production operations, are
designed to restore or increase production from wells whose flows are
11-9
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inhibited by downhole mechanical failures or blockages, such as sand or
paraffin deposits. Fluids circulated into the well for this purpose must
be compatible with the formation and must not adversely affect
permeability. They are similar to completion fluids, described earlier.
When the well is put back into production, the workover fluid may be
reclaimed or disposed of.
Other chemicals may be periodically or continuously pumped down a
production well to inhibit corrosion, reduce friction, or simply keep the
well flowing. For example, methanol may be pumped down a gas well to
keep it from becoming plugged with ice.
Surface Operations
Surface production operations generally include gathering of the
produced fluids (oil, gas, gas liquids, and water) from a well or group
of wells and separation and treatment of the fluids. See
Figures II-2, II-3, and II-4. As producing reservoirs are depleted, their
water/oil ratios may increase steeply. New wells may produce little if
any water; stripper wells may vary greatly in the volume of water they
produce. Some may produce more than 100 barrels of water for every barrel
of oil, particularly if the wells are subject to waterflooding operations.
Virtually all of this water must be removed before the product can be
transferred to a pipeline, (The maximum water content allowed is
generally less than I percent.) The oil may also contain completion or
workover fluids, stimulation fluids, or other chemicals (biocides,
fungicides) used as an adjunct to production. Some oil/water mixtures
may be easy to separate, but others may exist as fine emulsions that do
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OIL AND GAS
PRODUCTION
WELL
OIL AND GAS
SEPARATOR
. OIL .
STORAGE/
TANK %
TO OIL
PIPELINE,
BARGE,
OR
TRUCK
SEDIMENT
RESERVOIR
ENHANCED
RECOVERY
OR
DISPOSAL
INJECTION
WELL
Figure 11-2 Typical Production Operation, Showing Separation of OH, Gas, and Water
Produced waters are not always Injected as Indicated In this figure. Produced water may be trucked to central treatment and disposal
facilities, discharged Into disposal pits, discharged to surface or coastal waters, or used for beneficial or agricultural use.
-------
DRY GAS
CASING HEAD ,—
GAS IF
OIL AND GAS
PRODUCTION
WELL
IS)
OIL AND GAS
SEPARATOR
TO OIL
PIPELINE,
BARGE,
OR
TRUCK
SEDIMENT
ENHANCED
RECOVERY
OR
DISPOSAL
INJECTION
WELL
RESERVOIR
Figure 11-3 Oil Production With Average H20 Production With Dissolved/Associated Gas
Produced waters are not always injected as indicated in this figure. Produced water may be trucked to central treatment and disposal
facilities, discharged Into disposal pits, discharged to surface or coastal waters, or used for beneficial or agricultural use.
-------
OIL AND GAS
PRODUCTION
WELL
HEATER
TREATER
OIL
WATER
SEDIMENT
EMERGENCY
PIT
METER
TO OIL
PIPELINE,
BARGE,
OR
TRUCK
SEDIMENT
ENHANCED
RECOVERY
OR
DISPOSAL
INJECTION
WELL
RESERVOIR
Figure 11-4 High Oil/HaO Ratio Without Significant Dissolved/Associated Gas
Produced waters are not always injected as indicated in this figure. Produced water may be trucked to central treatment and disposal
dischnroed into disposal pits, discharged to surface or coastal waters, or used lor beneficial or agricultural use.
-------
not separate of their own accord by gravity. Where settling is possible,
it is done in large or small tanks, the larger tanks affording longer
residence time to increase separation efficiency. Where emulsions are
difficult to break, heat is usually applied in "heater treaters,"
yhichever method is used, crude oil flows from the final separator to
stock tanks. The sludges and liquids that settle out of the oil as tank
bottoms throughout the separation process must be collected and discarded
along with the separated water.
The largest volume production waste, produced water, flows from-the
separators into storage tanks and in the majority of oil fields is highly
saline. Most produced water is injected down disposal wells or enhanced
recovery wells. Produced water is also discharged to tidal areas and
surface streams, discharged to storage pits, or used for beneficial or
*
agricultural use, (Seawater is 35,000 ppm chlorides. Produced water can
range from 5,000 to 180,000 ppm chlorides.) If the produced water is
injected down a disposal well or an enhanced recovery well, it may be
treated to remove solids, which are also disposed of.
Tank bottoms are periodically removed from production vessels. Tank
bottoms are usually hauled away from the production site for disposal.
Occasionally, if the bottoms are fluid enough, they may be disposed of
along with produced water.
Waste crude oil may also be generated at a production site. If crude
oil becomes contaminated with chemicals or is skimmed from surface
impoundments, it is usually reclaimed. Soil and gravel contaminated by
crude oil as a result of normal field operations and occasional leaks and
spills require disposal.
Natural gas requires different techniques to separate out crude oil,
gas liquids, entrained solids, and other impurities. These separation
processes can occur in the field, in a gas processing plant, or both, but
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more frequently occur at an offsite processing plant. Crude oil, gas
liquids, some free water, and entrained solids can be removed in
conventional separation vessels. More water may be removed by any of
several dehydration processes, frequently through the use of glycol, a
liquid dessicant, or various solid dessicants. Although these separation
media can generally be regenerated and used again, they eventually lose
their effectiveness and must be disposed of.
Both crude oil and natural gas may contain the highly toxic gas
hydrogen sulfide, which is an exempt waste. (Eight hundred ppm in air is
lethal to humans and represents an occupational hazard, but not an
ambient air toxics threat to human health offsite.) At plants where
hydrogen sulfide is removed from natural gas, sulfur dioxide (SO^)
release results. (EPA requires compliance with the National Ambient Air
Quality Standards (NAAQS) for sulfur dioxide; D01 also has authority to
regulate these emissions.) Sulfur is often recovered from the hydrogen
sulfide (^S) as a commercial byproduct. HLS dissolved in crude oil
does not pose any danger, but when it is produced at the wellhead in
gaseous form, it poses serious occupational risks through possible leaks
or blowouts. These risks are also present later in the production
process when the H^S is separated out in various "sweetening"
processes. The amine, iron sponge, and selexol processes are three
examples of commercial processes for removing acid gases from natural
gas. Each FLS removal process results in spent or waste separation
media, which must be disposed of. EPA did not sample hydrogen sulfide
and sulphur dioxide emissions because of their relatively low volume and
infrequency of occurrence.
Gaseous wastes are generated from a variety of other
production-related operations. Volatile organic compounds may also be
released from minute leaks in production equipment or from pressure vents
on separators and storage tanks. When a gas well needs to be cleaned
out, it may be produced wide open and vented directly to the atmosphere.
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Emissions from volatile organic compounds are exempt under Section
3001(b)(2)(A) of RCRA and represent a very low portion of national air
emissions. Enhanced oil recovery steam generators may burn crude oil as
fuel, thereby creating air emissions. These wastes are nonexempt.
DEFINITION OF EXEMPT WASTES
The following discussion presents EPA's tentative definition of the
scope of the exemption.
Scope of the Exemption
The current statutory exemption originated in EPA's proposed
hazardous waste regulations of December 18, 1978 (43 FR 58946), Proposed
%
40 CFR 250.46 contained standards for "special wastes"--reduced
requirements for several types of wastes that are produced in large
volume and that EPA believed may be lower in toxicity than other wastes
regulated as hazardous wastes under RCRA. One of these categories of
special wastes was "gas and oil drilling muds and oil production brines."
In the RCRA amendments of 1980, Congress exempted most of these
special wastes from the hazardous waste requirements of RCRA Subtitle C»
pending further study by EPA. The oil and gas exemption, Section
3001(b)(2)(A), is directed at "drilling fluids, produced waters, and
other wastes associated with the exploration, development, or production
of crude oil or natural gas." The legislative history does not elaborate
on the definition of drilling fluids or produced waters, but it does
discuss "other wastes" as follows:
The term "other wastes associated" is specifically included to
designate waste materials intrinsically derived from the primary
field operations associated with the exploration, development, or
production of crude oil and natural gas. It would cover such
substances as: hydrocarbon bearing soil in and around related
facilities; drill cuttings; and materials (such as hydrocarbons,
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water, sand and emulsion) produced from a well in conjunction with
.crude oil and natural gas and the accumulated material (such as
hydrocarbons, water, sand, and emulsion) from production separators,
fluid treating vessels, storage vessels, and production
impoundments. (H.R. Rep No. 1444, 96th Cong., 2d Sess. at 32 (1980)),
The phrase "intrinsically derived from the primary field
operations..." is intended to differentiate exploration, development,
and production operations from transportation (from the point of
custody transfer or of production separation and dehydration) and
manufacturing operations.
In order to arrive at a clear working definition of the scope of the
exemption under Section 8002(m), EPA has used these statements in
conjunction with the statutory language of RCRA as a basis for making the
following assumptions about which oil and gas wastes should be included
in the present study.
« Although the legislative history underlying,the oil and gas
exemption is limited to "other wastes associated with the
exploration development or production of crude oil or natural
gas," the Agency believes that the rationale set forth in that
history is equally applicable to produced waters and drilling
fluids. Therefore, in developing criteria to define the scope of
the Section 3001(b)(2) exemption, the Agency has applied this
legislative history to produced waters and drilling fluids.
* The potential exists for small volume nonexempt wastes to be
mixed with exempt wastes, such as reserve pit contents. EPA
believes it is desirable to avoid improper disposal of hazardous
(nonexempt) wastes through dilution with nonhazardous exempt
wastes. For example, unused pipe dope should not be disposed of
in reserve pits. Some residual pipe dope, however, will enter the
reserve pit as part of normal field operations; this residual pipe
dope does not concern EPA. EPA is undecided as to the proper
disposal method for some other waste streams, such as rigwash that
often are disposed of in reserve pits.
Using these assumptions, the test of whether a particular waste
qualifies under the exemption can be made in relation to the following
three separate criteria. No one criterion can be used as a standard when
defining specific waste streams that are exempt. These criteria are as
follows.
11-17
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1. Exempt wastes must be associated with measures (1) to locate oil
or gas deposits, (2) to remove oil or natural gas from the ground,
or (3) to remove impurities from such substances, provided that
the purification process is an integral part of primary field
operations.5
2. Only waste streams intrinsic to the exploration for, or the
development and production of, crude oil and natural gas are
subject to exemption. Waste streams generated at oil and gas
facilities that are not uniquely associated with the exploration,
development, or production activities are not exempt. (Examples
would include spent solvents from equipment cleanup or air
emissions from diesel engines used to operate drilling rigs.)
Clearly those substances that are extracted from the ground or
injected into the ground to facilitate the drilling, operation, or
maintenance of a well or to enhance the recovery of oil and gas
are considered to be uniquely associated with primary field
operations. Additionally, the injection of materials into the
pipeline at the wellhead which keep the lines from freezing or
which serve as solvents to prevent paraffin accumulation is
intrinsically associated with primary field operations. With
regard to injection for enhanced recovery, the injected materials
must function primarily to enhance recovery of oil and gas and
must be recognized by the Agency as being appropriate for enhanced
recovery. An example would be produced'water. In this context,
"primarily functions" means that the main reason for injecting the
materials is to enhance recovery of oil and gas rather than to
serve as a means for disposing of those materials.
3. Drilling fluids, produced waters, and other wastes intrinsically
derived from primary field operations associated with the
exploration, development, or production of crude oil, natural gas,
or geothermal energy are subject to exemption. Primary field
operations encompass production-related activities but not
transportation or manufacturing activities. With respect to oil
production, primary field operations encompass those activities
occurring at or near the wellhead, but prior to the transport of
oil from an individual field facility or a centrally located
facility to a carrier (i.e., pipeline or trucking concern) for
transport to a refinery or to a refiner. With respect to natural
gas production, primary field operations are those activities
occurring at or near the wellhead or at the gas plant but prior to
that point at which the gas is transferred from an individual
field facility, a centrally located facility, or a gas plant to a
carrier for transport to market.
Thus, wastes associated with such processes as oil refining, petrochemical-related
ruanufacturing, or electricity generation are not exempt because those processes do not occur at the
primary field operations.
11-18
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Primary field operations may encompass the primary, secondary, and
tertiary production of oil or gas. Wastes generated by the
transportation process itself are not exempt because they are not
intrinsically associated with primary field operations. An
example would be pigging waste from pipeline pumping stations.
Transportation for the oil and gas industry may be for short or
long distances. Wastes associated with manufacturing are not
exempt because they are not associated with exploration,
development, or production and hence are not intrinsically
associated with primary field operations. Manufacturing (for the
oil and gas industry) is defined as any activity occurring within
a refinery or other manufacturing facility the purpose of which is
to render the product commercially saleable.
Using these definitions, Table II-l presents definitions of exempted
wastes as defined by EPA for the purposes of this study. Note that this
is a partial list only. Although it includes all the major streams that
EPA has considered in the preparation of this report, others may exist.
In that case, the definitions listed above would be applied to determine
their status under RCRA.
Waste Volume Estimation Methodology
Information concerning volumes of wastes from oil and gas
exploration, development, and production operations is not routinely
collected nationwide, making it necessary to develop methods for
estimating these volumes by indirect methods in order to comply with the
Section 8002(m) requirement to present such estimates to Congress. For
this study, estimates were compiled independently by EPA and by the
American Petroleum Institute (API) using different methods. Both are
discussed below.
Estimating..Volumes of Drilling Fluids and Cuttings
EPA considered several different methodologies for determining volume
estimates for produced water and drilling fluid.
11-19
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Table 11-1 Partial List of Exempt and Nonexempt Wastes
EXEMPT WASTES
Dr i II cyll ings
Dri 1 1 \r,g flu ids
Well completion, treatment,
arid st imulat ion fluids
PrfCMng fluids
Sand, hydrocarbon solids,
and other deposits removed
from production wells
Pipe scale, hydrccardon
solids, hydrates, and other
deposits refKJved from
piping and eq
Hydrocarbon-bearing soil
Pigging wastes from
gathering 1 mes
yjstes from Subsurface
gas storage and retrieval
Waste lubricants, hydraulic
fluids, motor oil. and
paint
Waste scl.ents frous clean-
up operations
Off-specification and
unused materials intended
for disposal
Incinerator ash
Pigging wastes from
transportation pipelines
Tattle II-l
Basic sediment ana *.jter
ana other tan* oottCT.s
frojn storage facilities
and separators
Produced water
Constituents removed from
proaycefl water Before it
ts injected or otherwise
disposed of
Accumulated materials (such
as hydrocarbons, solids.
sand, ana emulsion) from
production separators.
flu id-treat ing vessels,
and product ton impoundments
tnat are not mixed with
separation or treatment
media
Drilling muds from offshore
operat »0ns
Appropriate fljias injected
dowrthole for secondary ana
terttary recovery operations
Liquid hydrocarbons removed
from the product ion stream
but not frow oil refining
Gases removed from trie
production streara, sucrs as
hydrogen sulfide, carbon
dioxide, and volatilized
hydrocarbons
Mater u Is ejected from a
production well during ttie process
as blow in j down a well
Waste crude oil from
primary field operations
Light organics volatilized
from recovered rvydrocaroons
or from solvents or other
chennca Is used for cleaning,
fracturing, or well completion
NIMXEHPT WASTES
Sanitary wastes, trash, and Waste iron sponge, glycol, and
gray water other separation med»a
Gases, such as SO*. NQx,
and part icy )*t£s from gas
turbines or other machinery
Drums (filled, partially
filled, or cleaned) whose
contents are not intended
for use
Filters
Spent catalysts
Wastes from trunk- and drum-
cleaning operations
Waste solvents from equipment
maintenance
Spills from pipelines or
other transport methods
11-20
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EPA's estimates: For several regions of the country, estimates of
volumes of drilling fluids and cuttings generated from well drilling
operations are available on the basis of waste volume per foot of well
drilled. Estimates range from 0.2 barrel/foot (provided by the West
Virginia Dept. of Natural Resources) to 2.0 barrels/foot (provided by
NL Baroid Co. for Cotton Valley formation wells in Panola County,
Texas), EPA therefore considered the possibility of using this approach
nationwide. If it were possible to generate such estimates for all areas
of the country, including allowances for associated wastes such as
completion fluids and waste cement, nationwide figures would then be
comparatively easy to generate. They could be based on the total footage
of all wells drilled in the U.S., a statistic that is readily available
from API.
This method proved infeasible, however, because of a number of
complex factors contributing to the calculation of waste-per-foot
estimates that would be both comprehensive and valid for all areas of the
country. For instance, the use of solids control equipment at drilling
sites, which directly affects waste generation, is not standardized. In
addition, EPA would have to differentiate among operations using various
drilling fluids (oil-based, water-based, and gas-based fluids). These
and other considerations caused the Agency to reject this method of
estimating volumes of drilling-related wastes.
Another methodology would be to develop a formal model for estimating
waste volumes based on all the factors influencing the volume of drilling
waste produced. These factors would include total depth drilled,
geologic formations encountered, drilling fluid used, solids control
equipment used, drilling problems encountered, and so forth. Such a
model could then be applied to a representative sample of wells drilled
nationwide, yielding estimates that could then be extrapolated to produce
nationwide volumes estimates.
11-21
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This method, too, was rejected as infeasible. It would have required
access to data derived from the driller's logs and mud logs maintained at
individual well sites, which would have been very difficult to acquire.
Beyond this, other data and analytical needs for building such a model
proved to be beyond the resources available for the project.
With these methodologies unavailable, EPA developed its estimates by
equating the wastes generated from a drilling operation with the volume
of the reserve pit constructed to service the well. Typically, each well
is served by a single reserve pit, which is used primarily for either
temporary or permanent disposal of drilling wastes. Based on field
observations, EPA made the explicit assumption that reserve pits are
sized to accept the wastes anticipated from the drilling operation. The
Agency then collected information on pit sizes during the field sampling
program in 1986 (discussed later in this chapter), from literature
searches, and by extensive contact with State and Federal regulatory
personnel.
EPA developed three generic pit sizes (1,984-, 22,700-, and
87,240-barrel capacity) to represent the range of existing pits and
assigned each State a percent distribution for each pit size based on
field observation and discussion with selected State and industry
personnel. For example, from the data collected, Utah's drilling sites
were characterized as having 35 percent small pits, 50 percent medium
pits, and 15 percent large pits. Using these State-specific percent
distributions, EPA was then able to readily calculate an estimate of
annual drilling waste volumes per year for each State. Because Alaska's
operations are generally larger than operations in the other oil- and
gas-producing States, Alaska's generic pit sizes were different (55,093-
and 400,244-barrel capacity.)
11-22
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Although the EPA method is relatively simple, relying on a well site
feature that is easily observable (namely, the reserve pit),-the method
does have several disadvantages. It does not explicitly account for
waste volume increases and decreases due to evaporation, percolation, and
rainwater collection. The three generic pit sizes may not adequately
represent the wide range of pit sizes used for drilling, and they all
assume that the total volume of each reserve pit, minus a nominal 2 feet
of freeboard, will be used for wastes. Finally, the information
collected to determine the percent distributions of pit sizes within
States may not adequately characterize the industry, and adjusting the
distribution would require gathering new information or taking a new
survey. All of these uncertainties detract from the accuracy of a risk
assessment or an economic impact analysis used to evaluate alternative
waste management techniques.
The American Petroleum Institute's estimates: As the largest
national oil trade organization, the API routinely gathers and analyzes
many types of information on the oil and gas industry. In addition, in
conducting its independent estimates of drilling waste volumes, API was
able to conduct a direct survey of operators in 1985 to request waste
volume data--a method that was unavailable to EPA because of time and
funding limitations. API sent a questionnaire to a sample of operators
nationwide, asking for estimated volume data for drilling muds and
completion fluids, drill cuttings, and other associated wastes discharged
to the reserve pit. Completed questionnaires were received for 693
individual wells describing drilling muds, completion fluids, and drill
cuttings; 275 questionnaires also contained useful information concerning
associated wastes. API segregated the sampled wells so that it could
characterize drilling wastes within each of 11 sampling zones used in
this study and within each of 4 depth classes. Since API maintains a
data base on basic information on all wells drilled in the U.S.,
including location and depth, it was able to estimate a volume of wastes
for the more than 65,000 wells drilled in 1985. The API survey does have
11-23
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several significant limitations. Statistical representativeness of the
survey is being analyzed by EPA. Respondents to the survey were
primarily large oil companies. The survey was accompanied by a letter
that may have influenced the responses. Also, EPA experience with
operators indicates that they may underestimate reserve pit volumes.
Even though volumetric measurement and statistical analysis represent
the preferred method for estimating dril-ling waste volumes, the way in
which API's survey was conducted and the data were analyzed may have some
drawbacks. Operators were asked to estimate large volumes of wastes,
which are added slowly, to the reserve pit and are not measured. Because
the sample size is small in comparison to the population, it is
questionable whether the sample is an unbiased representation of the
drilling industry.
Estimating Volumes of Produced Water
By far the largest volume production waste from oil and gas
operations is produced water. Of all the wastes generated from oil and
gas operations, produced water figures are reported with the most
frequency because of the reporting requirements under the Underground
Injection Control (UIC) and National Pollution Discharge Elimination
System (NPOES) programs.
EPA's estimates: Because produced water figures are more readily
available than drilling waste data, EPA conducted a survey of the State
agencies of 33 oil- and gas-producing States, requesting produced water
data from injection reports, production reports, and hauling reports.
For those States for which this information was not available, EPA
derived estimates calculated from the oil/water ratio from surrounding
States (this method used for four States) or derived estimates based on
information provided by State representatives (this method used for six
States).
11-24
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API's estimates: In addition to its survey of drilling wastes, API
conducted a supplemental survey to determine total volumes of produced
water on a State-by-State basis. API sent a produced water survey form
to individual companies requesting 1985 crude oil and condensate volumes
and produced water volumes and distribution, fourteen operators in 23
States responded. Because most of the operators were active in more than
one State, API was able to include a total of 170 different survey
points, API then used these data to generate water-to-oil ratios (number
of barrels of water produced with each barrel of oil) for each operator
in each State. By extrapolation, the results of the survey yield an
estimate of the total volume of produced water on a statewide basis; the
statewide estimated produced water volume total is simply the product of
the estimated State ratio (taken from this survey) and the known total
oil production for the State. API rtports this survey method to have a
95 percent confidence level for produced water volumes. No standard
deviation was reported with this confidence level.
For most States, the figure generated by this method agrees closely
with the figure arrived at by EPA in its survey of State agencies in 33
oil-producing States. For a few States, however, the EPA and API numbers
are significantly different; Wyoming is an example. Since most of the
respondents to the API survey were major companies, their production
operations may not be truly representative of the industry as a whole.
Also, the API method did not cover all of the States covered by EPA.
Neither method can be considered completely accurate, so judgment is
needed to determine the best method to apply for each State. Because the
Wyoming State agency responsible for oil and gas operations believes that
the API number is greatly in error, the State number is used in this
report. Also, since the API survey did not cover many of the States in
the Appalachian Basin, the EPA numbers for all of the Appalachian Basin
States are used here. In all other cases, however, the API-produced
water volume numbers, which were derived in part from a field survey, are
believed to be more accurate than EPA numbers and are therefore used in
this report.
11-25
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Waste Volume Estimates
Drilling waste volumes for 1985, calculated by both the EPA and API
methods, appear in Table 11-2. Although the number of wells drilled for
each State differs between the two methods, both methods fundamentally
relied upon API data. The EPA method estimates that 2.44 billion barrels
of waste were generated from the drilling of 64,508 wells, for an average
of 37,902 barrels of waste per well. The API method estimates that 361
million barrels of waste were generated from the drilling of 69,734
wells, for an average of 5,183 barrels of waste per well. EPA has
reviewed API's survey methodology and believes the API method is more
reliable in predicting actual volumes generated. For the purposes of
this report, EPA will use the API estimates for drilling waste volumes.
Produced water volumes for 1985, calculated by both the EPA and API
methods, appear in Table II-3. The EPA method estimates 11.7 billion
barrels of produced water. The API method estimates 20.9 billion barrels
of produced water.
CHARACTERIZATION OF WASTES
In support of this study, EPA collected samples from oil and gas
exploration, development, and production sites throughout the country and
analyzed them to determine their chemical composition. The Agency
designed the sampling plan to ensure that it would cover the country's
wide range of geographic and geologic conditions and that it would
randomly select individual sites for study within each area
(USEPA 1987). One hundred one samples were collected from 49 sites in 26
different locations. Operations sampled included centralized treatment
facilities, central disposal facilities, drilling operations, and
production facilities. For a more detailed discussion of all aspects of
EPA's sampling program, see USEPA 1987.
11-26
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Table 11-2 Estimated U.S. Drilling Waste Volumes, 1985
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Georgia
Idaho
111 inois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
EPA method
Number of.
wells drilled
343
206
3
975
3,038
1,459
21
NCC
NC
2,107
910
NC
5,151
2,141
4,645
85
823
568
22
591
261
34
1,694
395
485
3,413
6,978
5
2,466
Volume3
1,000 bbl
15,179
4,118
56
43,147
82,276
27,249
929
NC
NC
57,063
24,645
NC
96,818
8,683
205,954
345
22,289
25,136
596
36,302
4,906
1,070
31,638
1,602
9,116
13,842
383,581
135
10,001
API
Number of
wells drilled
367
242
3
1,034
3,208
1,578
21
1
3
2,291
961
1
5,560
2,482
4,908
91
870
594
23
623
282
36
1,780
436
514
3,818
7,690
5
2,836
method
Voluroeb
1,000 bbl
5,994
1,816
23
8,470
4,529
8,226
1,068
2
94
2,690
1,105
1
17,425
4,874
46,726
201"
3,866
14,653
18
4,569
761
335
13,908
1,277
4,804
8,139
42,547
5
8,130
11-27
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3648Z
Table II-2 (continued)
State
South Dakota
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wyoming
U.S. Total
EPA method
Number of Volume3
wells drilled 1,000 bbl
44
169
22,538
332
85
NCC
1,188.
1,409°
64,499
827
685
1,238,914
6,201
345
NCC
4,sm
86t546d
2,444,667
API method
Number of Volume"
wells drilled 1,000 bbl
49
228
23,915
364
91
4
1,419
1,497
69,734
289
795
133,014
4,412
201
15
3,097
13,528
361,406
H Based on total available reserve pit volume, assuming 2 ft of freeboard (ref.)
b Based on total volume of drilling muds, drill cuttings, completion fluids,
circulated cement, formation testing fluids, and other water and solids.
Jj Not calculated.
° EPA notes that for Wyoming, the State's numbers are 1,332 and 11,988,000,
respectively.
11-28
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Table II-3 Estimated U.S. Produced Water Volumes, 1985
EPA volumes
State
Alabama
Alaska
Arizona
Arkansas
Cal ifornia
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Maryland
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
South Dakota
Tennessee
Texas
Utah
V i rg i n i a
West Virginia
Wyoming
U.S. Total
Sources; a.
b.
c.
d.
e.
f.
9-
h.
1,000 bbl
34,039
112,780
288
226,784
2,553,326
154,255
85,052
8,560
5,846
1,916,250
16,055
794,030
0
64,046
361,038
2,177
159,343
73,411
3,693
368,249
4,918
88,529
13,688
1,627,390
33
31,131
3,127
800
2,576,000
126,000
0
7,327
253,476*
11,671,641
Injection Reports
Production Reports
Hauling Reports
Estimate calculated
Estimate calculated
data were available
Estimate calculated
representative. See
a-f
API industry survey
Not surveyed
API volumes
Source 1,000 bbl Source
a
b
b
b
b
d
b
e
d
f
d
f
b
b
e
a
b
b
a
e
e
b
e
f
b
f
b
f
e
e
b
d
f
from
from
from
Tabl
87,619
97,740
149
184,536
2,846,978
388,661
64,738
1,282,933
..
999,143
90,754
1,346,675
—
76,440
318,666
..
223,558
164,688
--
445, -265
..
59,503
.
3,103,433
..
_.
5,155
__
7,838,783
260,661
..
2,844
985,221
20,873,243**
water/oil ratio from surrounding
water/oil ratio from other years
information provided by State
e I-8» (Westec, 1987) to explain
9
9
9
9
9
9
9
9
h
9
9
9
h
9
9
h
9
9
h
9
h
g
h
g
h
h
g
h
g
g
h
g
g
States
for which
footnotes
**
Wyoming states that 1,722,599,614 barrels of produced water were
generated in the State in 1985. For the work done in Chapter VI, the
State's numbers were used.
Includes only States surveyed.
11-29
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Central pits and treatment facilities receive wastes from numerous
oil and gas field operations. Since large geographic areas are serviced
by these facilities, the facilities tend to be very large; one pit in
Oklahoma measured 15 acres and was as deep as 50 feet in places. Central
pits are used for long-term waste storage and incorporate no treatment of
pit contents. Typical operations accept drilling waste only, produced
waters only, or both. Long-term, natural evaporation can concentrate the
chemical constituents in the pit. Central treatment and disposal
facilities are designed for reconditioning and treating wastes to allow
for discharge or final disposal. Like central pits, central treatment
facilities can accept drilling wastes only, produced water only, or
both.
Reserve pits are used for onsite disposal of waste drilling fluids.
These reserve pits are usually dewatered and backfilled. Waste
byproducts present at production sites include saltwater brines (called
produced waters), tank bottom sludge, and "pigging wax," which can
accumulate in the gathering lines.
Extracts from these samples were prepared both directly and following
the proposed EPA Toxicity Characteristic Leaching Procedure (TCLP). They
were analyzed for organic compounds, metals, classical wet chemistry
parameters, and certain other analytes.
API conducted a sampling program concurrent with EPA's. API's
universe of sites was slightly smaller than EPA's, but where they
overlapped, the results have been compared. API's methodology was
designed to be comparable to that used by EPA, but API's sampling and
analytical methods, including quality assurance and quality control
procedures, varied somewhat from EPA's. These dissimilarities can lead
to different analytical results. For a more detailed discussion of all
aspects of API's sampling program, see API 1987.
II-30
-------
Sampling Methods
Methods used by EPA and by API are discussed briefly below, with
emphasis placed on EPA's program.
EPA SamoJing Procedures
Pit sampling: All pit samples were composited grab samples. The EPA
field team took two composited samples for each pit--one sludge sample
and one supernatant sample. Where the pit did not contain a discrete
liquid phase, only a sludge sample was taken. Sludge samples are defined
by EPA for this report as tank bottoms, drilling muds, or other samples
that contains a significant quantity of solids (normally greater than
1 percent), EPA also collected samples of drilling mud before it entered
the reserve pit.
Each^pit was divided into four quadrants, with a sample taken from
the center of each quadrant, using either a coring device or a dredge.
The coring device was lined with Teflon or glass to avoid sample
contamination. This device was preferred because of its ease of use and
deeper penetration. The quadrant samples were then combined to make a
single composite sample representative of that pit.
EPA took supernatant samples at each of the four quadrant centers
before collecting the sludge samples, using a stainless steel liquid
thief sampler that allows liquid to be retrieved from any depth. Samples
were taken at four evenly spaced depths between the liquid surface and
the sludge-supernatant interface. EPA followed the same procedure at
each of the sampling points and combined the results into a single
composite for each site.
To capture volatile organics, volatile organic analysis (VGA) vials
were filled from the first liquid grab sample collected. All other
11-31
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sludge and liquid samples were composited and thoroughly mixed and had
any foreign material such as stones and other visible trash removed prior
to sending them to the laboratory for analysis (USEPA 1987).
Produced water: To sample produced water, EPA took either grab
samples from process lines or composited samples from tanks. Composite
samples were taken at four evenly spaced depths between the liquid
surface and the bottom of the tank, using only one sampling point per
tank. Storage tanks that were inaccessible from the top had to be
sampled from a tap at the tank bottom or at a flow line exiting the
tank. For each site location, EPA combined individual samples into a
single container to create the total liquid sample for that location.
EPA mixed all composited produced water samples thoroughly and removed
visible trash prior to transport to the laboratory (USEPA 1987).
Central treatment faci1ities: Both liquid and sludge samples were
taken at central treatment facilities. All were composited grab samples
using the same techniques described above for pits, tanks, or process
lines (USEPA 1987),
API Sampling Methods
The API team divided pits into six sections and sampled in an "S"
curve pattern in each section. There were 30 to 60 sample locations
depending upon the size of the pit. API's sampling device was a metal or
PVC pipe, which was driven into the pit solids. When the pipe could not
be used, a stoppered jar attached to a ridged pole was used. Reserve pit
supernatant was sampled using weighted bottles or bottom filling
devices. Produced waters were usually sampled from process pipes or
valves. API did not sample central treatment facilities (API 1987).
Analytical Methods
As for sampling methods, analytical methods used by EPA and by API
were somewhat different. Each is briefly discussed below.
11-32
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EPA Analytical Methods
EPA analyzed wastes for the RCRA characteristics in accordance with
the Office of Solid Waste test methods manual (SW-846). In addition,
since the Toxicity Characteristic Leaching Procedure (TCLP) has been
proposed to be a RCRA test, EPA used that analytical procedure for
certain wastes, as appropriate. EPA also used EPA methods 1624 and 1625,
isotope dilution methods for organics, which have been determined to be
scientifically valid for this application.
EPA's survey analyzed 444 organic compounds, 68 inorganics, 19
conventional contaminants, and 3 RCRA characteristics for a total of 534
analytes. Analyses performed included gas and liquid chromatography,
atomic absorption spectrometry and mass spectrometry, ultraviolet
detection method, inductively coupled plasma spectrometry, and dioxin and
furan analysis. All analyses followed standard EPA methodologies and
protocols and included full quality assurance/quality control (QA/QC) on
certain tests (USEPA 198J).
Of these 534 analytes, 134 were detected in one or more samples. For
about half of the sludge samples, extracts were taken using EPA's proposed
Toxicity Characteristic Leaching Procedure (TCLP) and were analyzed for a
subset of organics and metals. Samples from central pits and central
treatment facilities were analyzed for 136 chlorinated dioxins and furans
and 79 pesticides and herbicides (USEPA 1987).
API Analytical Methods
API analyzed for 125 organics, 29 metals, 15 conventional
contaminants, and 2 RCRA characteristics for each sample. The same
methods were used by API and EPA for analysis of metals and conventional
11-33
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pollutants with some minor variations. For organics analysis EPA used
methods 1624C and 1625C, while API used EPA methods 624 and 625, While
the two method types are comparable, method 1624 (and 1625C) may give a
more accurate result because of less interference from the matrix and a
lower detection limit than methods 624 and 625, In addition, QA/QC on
API's program has not been verified by EPA. See USEPA 1987 for a
discussion of EPA analytical methods.
Results
Chemical Constituents Found by EPA in Oil and Gas Extraction Waste Streams
As previously stated, EPA collected a total of 101 samples from
drilling sites, production sites, waste treatment facilities, and
commercial waste storage and disposal facilities. Of these 101 samples,
42 were sludge samples and 59 were liquid samples (USEPA 1987).
Health-based numbers in milligrams per liter (ftig/L) were tabulated
for all constituents for which there are Agency-verified limits. These
are either reference doses for noncarcinogens (Rfds) or risk-specific
doses (RSDs) for carcinogens. RSDs were calculated, using the following
risk levels: 10-6 for class A (human carcinogen) and 10-5 for class B
(probable human carcinogen). Maximum contaminant limits (MCLs) were
used, when available, then Rfds or RSDs. An MCL is an enforceable
drinking water standard that is used by the Office of Solid Waste when
ground water is a main exposure pathway.
Two multiples of the health-based limits (or MCLs) were calculated
for comparison with the sample levels found in the wastes. Multiples of
100 were used to approximate the regulatory level set by the EP toxicity
test (i.e., 100 x the drinking water standards for some metals and
11-34
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pesticides). Multiples of 1,000 were used to approximate the
concentration of a leachate which, as a first screen, is a threshold
level of potential regulatory concern. Comparison of constituent levels
found by direct analysis of waste with multiples of health-based numbers
(or MCLs) can be used to approximate dispersion of this waste to surface
waters. Comparison of constituent levels found by TCLP analysis of waste
with multiples of health-based numbers (or MCLs) can be used to
approximate dispersion of this waste to ground water,
For those polyaromatic hydrocarbons (PAHs) for which verified
health-based numbers do not exist, limits were estimated by analogy with
known toxicities of other PAHs. If structure activity analysis (SAR)
indicated that the PAH had the potential to be carcinogenic, then it was
assigned the same health-based number as benzo(a)pyrene, a potent
carcinogen. If the SAR analysis yielded equivocal results, the PAH was
assigned the limit given to indeno-(1,2,3-cd) pyrene, a PAH with possible
carcinogenic potential. If the SAR indicated that the PAH was not likely
to be carcinogenic, then it was assigned the same number as naphthalene,
a noncarcinogen.
The analysis in this chapter does not account for the frequency of
detection of constituents, or nonhuman health effects. Therefore, it
provides a useful indication of the constituents deserving further study,
but may not provide an accurate description of the constituents that have
the potential to pose actual human-health and environmental risks.
Readers should refer to Chapter V, "Risk Modeling," for information on
human health and environmental risks and should not draw any conclusions
from the analysis presented in Chapter II about the level of risk posed
by wastes from oil and gas wells.
EPA may further evaluate constituents that exceeded the health-based
limit or MCL multiples to determine fate, transport, persistence, and
toxicity in the environment. This evaluation may show that constituents
11-35
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designated as secondary in the following discussion may not, in fact, be
of concern to EPA.
Although the Toxicity Characteristics Leaching Procedure (TCLP) was
performed on the sludge samples, the only constituent in the leach
exhibiting concentrations that exceeded the multiples previously
described was benzene in production tank bottom sludge. All of the other
chemical constituents that exceeded the-multiples were from direct
analysis of the waste.
Constituents Present at Levels of Potential Concern
Because of the limited number of samples in relation to the large
universe of facilities from which the samples were drawn, results of the
waste sampling program conducted for this study must be analyzed
carefully. EPA is conducting a statistical analysis of these samples.
Table II-4 shows EPA and API chemical constituents that were present
in oil and gas extraction waste streams in amounts greater than,
health-based limits multiplied by 1,000 (primary concern) and those
constituents that occurred within the range of multiples of 100 and 1,000
(secondary concern). Benzene and arsenic, constituents of primary and
secondary concern respectively, by this definition, were modeled in the
risk assessment chapter (Chapter V). The table compares waste stream
location and sample phase with the constituents found at that location
and phase. Table 11-5 shows the number of samples compared with the
number of detects in EPA samples for each constituent of potential
concern.
The list of constituents of potential concern is not final, EPA is
currently evaluating the data collected at the central treatment
facilities and central pits, and more chemical constituents of potential
concern may result from this evaluation. Also, statistical analysis of
the sampling data is continuing.
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Table II-4 Constituents of Concern Found In Waste Streams Sampled by EPA and API
Chemical
Constituents
Primary concern
Benzene
Phcnan throne
Lead
Barium
Secondary concern
Arsenic
Fluoride
Antimony
Production
Midpoint
L#
ianK bottom
Sff S+
S H
S
Kndpoint
L U-
L U-
L
L
L-
Central treatment
Influent
S*
si
S
Tank
S#
S# •
s#
Effluent
L S
S#
s»
S
5
Central pit
Centra] pfi
S#
s#
s«
s#
S
S
Drilling
Drilling mud
S
Si
Tank bottoms
S#
S«
u
L
Pit
S S«
U L- S« SH*
U L«- S« i««
S S-
L S
Legend:
L; Liquid sample > 100 x health-based number
S: Sludge sample > 100 x health-based number
#: Denotes > 1,000 x health-based number
L.S: EPA samples
L-,S«: API samples
•K TCLP exfraction
— All values determined from direct samples except as denoted by "4-"
-------
Table 115 EPA Samples Containing Constituents of Concern
Primary concern
Benzene
Phenanihrene
Lead
Barium
Secondary concern
Arsenic
Fluoride
Production
Midpoint
L5(3)
Tank bottom
siu) +
Sl (I)
SI (1)
Endpolnt
L21 (16)
L21 (5)
L24 (2l)~
L24 (9}
Central treatment
Influent
SI (I)
si 0)
Si(l)
1 link
S2(l)
S2 (2)
S2(l)
Kffluent
L3(2)S3(1)
S3 (3)
S3 (3)
S3 (3)
S3 (3)
Central pit
Central pit
S3 (I)
S3 n
S3 fc)
S3 (3)
S3(l)
S3 (3)
Drilling
Drilling mud
S2(l)
SI (I)
Tank bottoms
SI (1)
si m
Ll (I)
Ll(l)
Pit
SIS (7)
LI7(I7) S2I(2I)
L17(17)S2I (21)
S2I (11)
L17(17) 520(20)
UJ
oo
Legend:
L: Liquid sample
S: Sludge sample
i (#) Number of samples (number of detects)
+ TCLP extract and direct exffacts
-------
Comparison to Constituents of Potential Concern Identified in the Risk
Analysis
This report's risk assessment selected the chemical constituents that
are most likely to dominate the human health and environmental risks
associated with drilling wastes and produced water endpoints. Through
this screening process, EPA selected arsenic, benzene, sodium, cadmium,
chromium VI, boron, chloride, and total mobile ions as the constituents
to model for risk assessment.5
The chemicals selected for the risk assessment modeling differ from
the constituents of potential concern identified in this chapter's
analysis for at least three reasons. First, the risk assessment
screening accounted for constituent mobility by examining several factors
in addition to solubility that affect mobility (e.g., soil/water
partition coefficients) whereas, in Chapter II, constituents of potential
concern were not selected on the basis of mobility in the environment.
Second,, certain constituents were selected for the risk assessment
modeling based on their potential to cause adverse environmental effects
as opposed to human health effects; the Chapter II analysis considers
mostly human health effects. Third, frequency of detection was
considered in selecting constituents for the risk analysis but was not
considered in the Chapter II analysis.
Facility Analysis
Constituents of potential concern were chosen on the basis of
exceedances in liquid samples or TCLP extract. Certain sludge samples
are listed in Tables II-4 and 11-5, since these samples, through direct
Mobile ions modeled in the risk assessment include chloride, sodium, potassiuffl,
calcium, ma§nes»yw, and sulfate.
11-39
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chemical analysis, indicated the presence of constituents at levels
exceeding the multiples previously described. One sludge sample analyzed
by the TCLP method contained benzene in an amount above the level of
potential concern. This sample is included in Tables II-4 and II-5. The
sludge samples are shown for comparison with the liquid samples and TCLP
extract and were not the basis for choice as a constituent of potential
concern. Constituents found in the liquid samples or the TCLP extract in
amounts greater than 100 times the health-based number are considered
constituents of potential concern by EPA.
Central Treatment Facility
Benzene, the only constituent found in liquid samples at the central
treatment facilities, was found in the effluent in amounts exceeding the
level of potential concern.
Central Pit FacjJit.y
No constituent was found in the liquid phase in amounts exceeding the
level of potential concern at central pit facilities.
Drill ing Facilities
Lead and barium were found in amounts exceeding the level of
potential concern in the liquid phase of the tank bottoms and the reserve
pits that were sampled. Fluoride was found in amounts that exceeded 100
times the health-based number in reserve pit supernatant.
Production Facility
Benzene was present in amounts that exceeded the level of potential
concern at the midpoint and the endpoint locations. Exceedances of the
11-40
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level of potential concern that occurred only at the endpoint location
were for phenanthrene, barium, arsenic, and antimony. Benzene was
present in amounts exceeding the multiple of 1,000 in the TCLP leachate
of one sample.
WASTE CHARACTERIZATION ISSUES
Toxicity Characteristic Leaching Procedure (TCLP)
The TCLP was designed to model a reasonable worst-case mismanagement
scenario, that of co-disposal of industrial waste with municipal refuse
or other types of biodegradable organic waste in a sanitary landfill. As
a generic model of mismanagement, this scenario is appropriate for
nonregulated wastes because those wastes may be sent to a municipal
landfill. However, most waste from oil and gas exploration and
production is not disposed of i.n a sanitary landfill, for which the test
was designed. Therefore, the test may not reflect the true hazard of the
waste when it is managed by other methods. However, if these wastes were
to go to a sanitary landfill, EPA believes the TCLP would be an
appropriate leach test to use.
For example, the TCLP as a tool for predicting the Teachability of
oily wastes placed in surface impoundments may actually overestimate that
Teachability. One reason for this overestimation involves the fact that
the measurement of volatile compounds is conducted in a sealed system
during extraction. Therefore, all volatile toxicants present in the
waste are assumed to be available for leaching to ground water. None of
the volatiles are assumed to be lost from the waste to the air. Since
volatilization is a potentially significant, although as yet
unquantified, route of loss from surface impoundments, the TCLP may
overestimate the leaching potential of the waste. Another reason for
overestimation is that the TCLP assumes that no degradation—either
chemical, physical, or biological--will occur in the waste before the
11-41
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leachate actually leaves the impoundment. Given that leaching is not
likely to begin until a finite time after disposal and will continue to
occur over many years, the assumption of no change may tend to
overestimate Teachability.
Conversely, the TCLP may underestimate the leaching potential of
petroleum wastes. One reason for this assumption is a procedural problem
in the filtration step of the TCLP. The amount of mobile liquid phase
that is present in these wastes and that may migrate and result in
ground-water contamination is actually underestimated by the TCLP. The
TCLP requires the waste to be separated into its mobile and residue solid
phases by filtration. Some production wastes contain materials that may
clog the filter, indicating that the waste contains little or no mobile
fraction. In an actual disposal environment, however, the liquid may
migrate. Thus, the TCLP may underestimate the leaching potential of
these materials. Another reason for underestimation may be that the
acetate extraction fluid used is not as aggressive as real world leaching
fluid since other solybili^ing species (e.g., detergents, solvents, humic
species, chelating agents) may be present in -leaching fluids in actual
disposal units. The use of a citric acid extraction media for more
aggressive leaching has been suggested.
Because the TCLP is a generic test that does not take site-specific
factors into account, it may overestimate waste Teachability in some
cases and underestimate waste Teachability in other cases. This is
believed to be the case for wastes from oil and gas exploration and
production.
The EPA has several projects underway to investigate and quantify the
leaching potential of oily matrices. These include using filter aids to
prevent clogging of the filter, thus increasing filtration efficiency,
and using column studies to quantitatively assess the degree to which
oiTy materiaTs move through the soil. These projects may result in a
leach test more appropriate for oily waste.
11-42
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Solubility and Mobility of Constituents
Barium is usually found in drilling waste as barium sulfate (barite),
which is practically insoluble in water (Considine 1974), Barium sulfate
may be reduced to barium sulfide, which is water soluble. It is the
relative insolubility of barium sulfate that greatly decreases its
toxicity to humans; the more soluble and mobile barium sulfide is also
much more toxic (Sax 1984). Barium sulfide formation from barium sulfate
requires a moist anoxic environment.
The organic constituents present in the liquid samples in
concentrations of potential concern were benzene and phenanthrene.
Benzene was found in produced waters and effluent from central treatment
facilities, and phenanthrene was found in produced waters.
An important commingling effect that can increase the mobility of
nonpolar organic solvents is the addition of small amounts of a more
soluble organic solvent. This effect can significantly increase the
extent to which normally insoluble materials are dissolved. This
solubility enhancement is a log-linear effect. A linear increase in
cosolvent concentration can lead to a logarithmic increase in
solubility. This effect is also additive in terms of concentration. For
instance, if a number of cosolvents exist in small concentrations, their
total concentration may be enough to have a significant effect on
nonpolar solvents with which the cosolvents come in contact (Nkedi-Kizza
1985, Woodburn et al. 1986). Common organic cosolvents are acetone,
toluene, ethanol, and xylenes (Brown and Donnelly 1986).
Other factors that must be considered when evaluating the mobility of
these inorganic and organic constituents in the environment are the use
of surfactants at oil and gas drilling and production sites and the
11-43
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general corrosivity of produced waters. Surfactants can enhance the
solubility of many constituents in these waters. Produced waters have
been shown to corrode casing (see damage cases in Chapter IV).
Changes in pH in the environment of disposal can cause precipitation
of compounds or elements in waste and this can decrease mobility in the
environment. Also adsorption of waste components to soil particles will
attenuate mobility. This is especially true of soils containing clay
because of the greater surface area of clay-sized particles.
Phototoxic Effect of Polycyclic Aromatic Hydrocarbons (PAH)
New studies by Kagan et al. (1984), Allred and Giesy (1985), and
Bowling et al. (1983) have shown that very low concentrations (ppb in
some cases) of polycyclic aromatic hydrocarbon (PAH) are lethal to some
forms of aquatic wildlife when they are introduced to sunlight after
exposure to the PAHs. This is called the phototoxic effect.
In the study conducted by Allred and Giesy (1985), it was shown that
anthracene toxicity to Daphnia pulex resulted from activation by solar
radiation of material present on or within the animals and not in the
water. It appeared that activation resulted from anthracene molecules
and not anthracene degeneration products. Additionally, it was shown
that wavelengths in the UV-A region (315 to 380 nm) are primarily
responsible for photo-induced anthracene toxicity.
It has been shown that PAHs are a typical component of some produced
waters (Davani et al., 1986a). The practice of disposal of produced
waters in unlined percolation pits is allowing PAHs and other
constituents to migrate into and accumulate in soils (Eiceman et al.»
1986a, 19865).
11-44
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pH and Other RCRA Characteristics
Of the RCRA parameters reactivity, ignitabi!ity, and corrosivity, no
waste sample failed the first two. Reactivity was low and igrntability
averaged 200 F for all waste tested. On the average, corrosivity
parameters were not exceeded, but one extreme did fail this RCRA test
(See Table II-6). A solid waste is considered hazardous under RCRA if
its aqueous phase has a pH less than or equal to 2 or greater than or
equal to 12.5. As previously stated, a sludge sample is defined by EPA
in this document as a sample containing a significant quantity of solids
(normally greater than 1 percent).
Of the major waste types at oil and gas facilities, waste drilling
muds and produced waters have an average neutral pH. Waste drilling
fluid samples ranged from neutral values to very basic values, and
produced waters ranged from neutral to acidic values. In most cases the
sludge phase tends to be more basic than the liquid phases. An exception
is the tank bottom waste at central treatment facilities, which has an
average acidic value. Drilling waste tends to be basic in the liquid and
sludge phases and failed the RCRA test for alkalinity in one extreme
case. At production facilities the pH becomes more acidic from the
midpoint location to the endpoint. This is probably due to the removal
of hydrocarbons. This neutralizing effect of hydrocarbons is also shown
by the neutral pH values of the production tank bottom waste. An
interesting anomaly of Table 11-6 is the alkaline values of the influent
and effluent of central treatment facilities compared to the acidic
values of the tank bottoms at these facilities. Because central
treatment facilities accept waste drilling fluids and produced waters,
acidic constituents of produced waters may be accumulating in tank bottom
sludges. The relative acidity of the produced waters is also indicated
by casing failures, as shown by some of the damage cases in Chapter IV.
11-45
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Table II-6 pH Values Tor Exploration, Development and Production Wastes (EPA Samples)
cr>
Production
Sludge
Liquid
Central treatment
Sludge
Liquid
Central pit
Sludge
Liquid
Drilling
Sludge
Liquid
Midpoint
6,4; 6.6; 8.0
Tank bottom
7.0; 7.0; 7.0
Eno* point
2.7; 7.6; 8.1
Influent
8.8; 8.8; 8.8
5.7; 6.5; 7.3
Tank
2.0; 3.9; 5.8
Effluent
).7; 8.2; 10.0
7.0; 8,2; 10.1
Central pit
7.2; 8.0; 9.2
5.7; 7.5; 8.5
Tank bottom*
7.1; 7.1; 7.1
Pit
6.8; 9.0; 12J
6.5; 7.7; 12.7
Legend:
#;#;#- minimum; average; maximum
-------
Use of Constituents of Concern
The screening analysis conducted for the risk assessment identified
arsenic, benzene, sodium, cadmium, chromium VI, boron, and chloride as
the constituents that likely pose the greatest human health and
environmental risks. The risk assessment's findings differ from this
chapter's findings since this chapter's analysis did not consider the
frequency of detection of constituents, mobility factors, or nonhuman
health effects (see Table 11-7). Some constituents found in Table II-4
were in waste streams causing damages as documented in Chapter IV.
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Table IJ-7 Comparison of Potential Constituents of Concern
That Were Modeled in Chapter V
Chemical
Benzene
Phenanthrene
Lead
Barium
Arsenic
Fluoride
Antimony
Chapter
If V"
P Yes
P No
P No
P No
S Yes
S No
S No
Reasons for not Including In Chapter V
risk analysis •*•
N/A
Low frequency in drilling pit and produced water samples;
low ground-water mobility; relatively low concentration-
to-toxicity ratio; unverified reference dose used for
Chapter 2 analysis.
Low ground-wafer mobility.
Low ground-water mobility.
N/A
Relatively low concentration-to-toxicity ratio.
Low frequency in drilling pit and produced water samples.
P = primary concern in Chapter II; S = secondary concern in Chapter II.
" Yes = modeled in Chapter V analysis; no « not modeled in Chapter V analysis.
*** Table summarizes primary reasons only; additional secondary reasons may also exist.
11-48
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REFERENCES
Allred. P. M,, and Giesy, J. P. 1985. Solar radiation induced toxicity of
anthracene to daphnia pulex. Environmental Toxicology Chem.
4: 219-226,
API. 1986. American Petroleum Institute. Comments to the docket on the
proposed toxicity characteristic leaching procedure (Doc.
fF-86-TC-FFFFF). August 12, 1986.
. 1987. American Petroleum Institute. Oil and gas industry
exploration and production wastes (Doc. 1471-01-09).
Baker, F.G., and Brendecke, C.M. 1983. Groundwater. 21: 317.
Bowling, J, W., Laversee, G. J., Landram, P. F., and Giesy, J. P. 1983,
Acute mortality of anthracene contaminated fish exposed to sunlight.
Aquatic Toxicology. 3: 79-90.
Brown, K.W., and Donnelly, K.C. 1986. The occurrence and concentration
of organic chemicals in hazardous and municipal waste landfill
leachate. In Press.
Considine, Douglas M., ed. 1974. Chemical and process technology
encyclopedia. New York: McGraw Hill Inc.
Davani, B., Ingram, J., Gardea, J.L., Dodson, J.A., and Eiceman, G.A.
1986a. Hazardous organic compounds in liquid waste from disposal
pits for production of natural gas. Int. J. Environ. Anal. Chem.
20 (1986): 205.
Davani, B., Gardea, J.S., Dodson, J.A., and Eiceman, G.A. 1986b. Organic
compounds in soils and sediments from unlined waste disposal pits for
natural gas production and processing. Water. Air and Soil
Pollution. 27: 267-276.
Eiceman, G.A., Davani, B., and Ingram, J. 1986a, Depth profiles for
hydrocarbons and PAH in soil beneath waste disposal pits from
production of natural gas. Int.J.Environ. Anal. Chem. 20 (1986):
508.
Eiceman, G.A., McConnon, J.T., Zaman, M., Shuey, C., and Earp, D.
1986b. Hydrocarbons and aromatic hydrocarbons in groundwater
surrounding an earthen waste disposal pit for produced water in the
Duncan Oil Field of New Mexico. Int. J. Environ. Anal. Chem.
24 (1986): 143-162.
11-49
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Environmental Defense Fund. 1986. Comments of the Environmental Defense
Fund on the June 13, 1986 proposed Toxicity Characteristic Leaching
Procedure (Doc »F-86-TC-FFFFF). August 12, 1986.
Kagan, J., Kagan, P. A., and Buhse, H. E., Jr. 1984. Toxicity of alpha
terthienyl and anthracene toward late embryonic stages of
ranapieines. J. Chetn. Ecol. 10: 1015-1122.
Nkedi-Kizza, P., et al. 1985. Influence of organic cosolvents on
sorption of hydrophobic organic chemicals by soils. Fnviron. Sci.
Techno!. 19: 975-979.
Sax, N. Irving. 1984. Dangerous properties of industrial materials.
New York: Nostrand Reinhold Company.
USEPA. 1987. U.S. Environmental Protection Agency. Technical report:
exploration development and production of crude oil and natural gas;
field sampling and analytical results (appendices A-G), EPA
#530-SW-87-005, (Doc. * OGRN FFFF).
Woodburn, K. B., et al. 1986. Solvophobic approach for predicting
sorption of hydrophobic organic chemicals on synthetic sorbents and
soils. J. Contaminant Hydrology 1: 227-241.
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CHAPTER III
CURRENT AND ALTERNATIVE WASTE MANAGEMENT PRACTICES
INTRODUCTION
Hanaging wastes produced by the oil and gas industry is a large
task. By the estimates gathered for this report, in 1985 over 361
million barrels of drilling muds and 20.9 billion barrels of produced
water were disposed of in the 33 States that have significant
exploration, development, and production activity. In that same year,
there were 834,831 active oil and gas wells, of which about 70 percent
(580,000 wells) were stripper operations.
The focus of this section is to review current waste management
technologies employed for wastes at all phases of the exploration-
development-production cycle of the onshore oil and gas industry. It is
convenient to divide wastes into two broad categories. The first
category includes drilling muds, wellbore cuttings, and chemical
additives related to the drilling and well completion process. These
wastes tend to be managed together and may be in the form of liquids,
sludges, or solids. The second broad category includes all wastes
associated with oil and gas production. Produced water is the major
waste stream and is by far the highest volume waste associated with oil
and gas production. Other production-related wastes include relatively
small volumes of residual bactericides, fungicides, corrosion inhibitors,
and other additives used to ensure efficient production; wastes from
oil/gas/water separators and other onsite processing facilities;
production tank bottoms; and scrubber bottoms.1
For the purpose of this chapter, all waste streams, whether exempt or nonexempt, are
discussed-
-------
In addition to looking at these two general waste categories, it is
also important to view waste management in relation to the sequence of
operations that occurs in the life cycle of a typical well. The
chronology involves both drilling and production — the two phases
mentioned above — but it also can include "post-closure" events, such as
seepage of native brines into fresh ground water from improperly plugged
or unplugged abandoned wells or leaching of wastes from closed reserve
pits.
Section 8002(m) of RCRA requires EPA to consider both current and
alternative technologies in carrying out the present study. Sharp
distinctions between current and alternative technologies are difficult
to make because of the wide variation in practices among States and among
different types of operations. Furthermore, waste management technology
in this field is fairly simple. At least for the major high-volume
streams, there are no significant newly invented, field-proven
technologies in the research or development stage that can be considered
"innovative" or "emerging." Although practices that are routine in one
location may be considered innovative or alternative" elsewhere, virtually
every waste management practice that exists can be considered "current"
in one specific situation or another. This is because different
climatological or geological settings may demand different management
procedures, either for technical convenience in designing and running a
facility or because environmental settings in a particular region may be
unique. Depth to ground water, soil permeability, net
evapotranspiration, and other site-specific factors can strongly
influence the selection and design of waste management practices. Even
where geographic and production variables are similar, States may impose
quite different requirements on waste management, including different
permitting conditions.
111-2
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Long-term improvements in waste management need not rely, however,
purely on increasing the use of better existing technology. The Agency
does foresee the possibility of significant technical improvements in
future technologies and practices. Examples include incineration and
other thermal treatment processes for drilling fluids; conservation,
recycling, reuse, and other waste minimization techniques; and wet air
oxidation and other proven technologies that have not yet been applied to
oil and gas operations.
Sources of Information
The descriptions and interpretations presented here are based on
State or Federal regulatory requirements, published technical
information, observations gathered onsite during the waste sampling
program, and interviews with State officials and private industry.
Emphasis is placed on practices in 13 States that represent a
cross-section of the petroleum extraction industry based on their current
drilling activity, rank .in production, and geographic distribution. (See
Table III-l.)
Limitations
Data on the prevalence, environmental effectiveness, and enforcement
of waste management requirements currently in effect in the
petroleum-producing States are difficult to obtain. Published data are
scarce and often outdated. Some of the State regulatory agencies that
were interviewed for this study have only very limited statistical
information on the volumes of wastes generated and on the relative use of
the various methods of waste disposal within their jurisdiction. Time
was not available to gather statistics from other States that have
significant oil and gas activity. This lack of concrete data makes it
difficult for EPA to complete a definitive assessment of available
disposal options. EPA is collecting additional data on these topics.
111-3
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Table II1-1 States with Major Oil Production Used as Primary
References ;n This Study
Alaska
Arkansas
Cal iforrna
Colorado
Kansas
Louisiana
Michigan
New Mexico
Ohio
Oklahoma
Texas
Uest Virginia
Wyoming
III-4
-------
DRILLING-RELATED WASTES
Description of Waste
Drilling wastes include a wide variety of materials, ranging in
volume from the thousands of barrels of fluids ("muds") used to drill a
well, to the hundreds of barrels of drill cuttings extracted from the
borehole, to much smaller quantities of wastes associated with various
additives and chemicals sometimes used to condition drilling fluids, A
general description of each of these materials is presented in broad
terms below.
Drilling Fluids (Muds)
The largest volume drilling-related wastes generated are the spent
drilling fluids or muds. The composition of modern drilling fluids or
muds can be quite complex and can vary widely, not only from one
geographical area to another but also from one depth to another in a
particular well as it is drilled.
Muds fall into two general categories: water-based muds, which can be
made with fresh or saline water and are used for most types of drilling,
and oil-based muds, which can be used when water-sensitive formations are
drilled, when high temperatures are encountered, or when it is necessary
to protect against severe drill string corrosion in hostile downhole
environments. Drilling muds contain four essential parts: (1) liquids,
either water or oil; (2) reactive solids, the viscosity- and
density-building part of the system, often bentonite clays; (3) inert
solids such as barite; and (4) additives to control the chemical,
physical, and biological properties of the mud. These basic components
perform various functions. For example, clays increase viscosity and
III-5
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density, barium sulfate (barite) acts as a weighting agent to maintain
pressure in the well, and lime and caustic soda increase pH and control
viscosity. Additional conditioning materials include polymers, starches,
lignitic material, and various other chemicals (Canter et al. 1984).
Table III-2 presents a partial list, by use category, of additives to
drilling muds (Note: this table is based on data that may, in some cases,
be outdated.}
Cuttings.
Well cuttings include all solid materials produced from the geologic
formations encountered during the drilling process that must be managed
as part of the content of the waste drilling mud. Drill cuttings consist
of rock fragments and other heavy materials that settle out by gravity in
the reserve pit. Other materials, such as sodium chloride, are soluble
in fresh water and can pose problems in waste disposal. Naturally
occurring arsenic may also be encountered in significant concentrations
in certain wells and in certain parts of the country and must be disposed
of appropriately. (Written communication with Mr. Don Basko, Wyoming Oil
and Gas Conservation Commission.)
Waste Chemicals
In the course of drilling operations, chemicals may be disposed of by
placing them in the well's reserve pit. These can include any substances
deliberately added to the drilling mud for the various purposes mentioned
above (see Table IIJ-2).
III-6
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Table 111-2 Character cat ion of Oil
anj Gas Drilling
Source, Information in this table was taken from American
Petroleum Institute (API) Bulletin 13F (1978), Drilling
practices nave evolved significantly in some respects since
tts pybl ication; the information presented celo« may
therefor* not be fully accaraie or current.
Bases
Bases used in formulating drilling fluid are predominantly fresh
water, with minor use of saltwater or oils, including dtesel and
mineral oils. It ts estimated that the industry used 30,000 tons of
diesel o»l per year in drilling fluid in 1978-*
Weighting Agents
Conifion weighting agents found in drilling fluids are barite, calcium
carbonate, and galena IPbS). Approximately 1.900,000 tons of
bante, 2,500 tons of calcium carbonate, and 50 tons of galena (the
mineral form of lead) are used in drilling each year.
Viscosifiers
Viscosifttrs found in drilling fluid include:
» Bentonue clays 650.000 tons/year
•• Attapulgue/sepiolrte 15,000 tons/year
• Asphalt/giIsonite 10,000 tons/year
• Asbestos 30,000 tons/year
« Bio-polymers 500 tons/year
a This figure included contributions from offshore operations.
According to API, use of diesel oil in drilling fluid has been
sybstantially reduced IP the past 10 years principally as a resylt of
ils restricted use in offshore operations.
API states that galena is no longer used in drilling mud.
III-7
-------
laoie Hl-2 (continued)
Dispersants
Oispersants ysed >n drilling fluid include:
• Cadmium, cnrootum. iron.
and other metal lignosyIfonates
• Natural, causticized chromium
and z\nc lignite
• Inorganic phosphates
• Modified tannins
65,000 tons/year
50,000 tons/year
1,500 tons/year
I,200 tons/year
Fluid loss Reducers
Fluid loss reducers used in drilling fluid include;
Starch/organic polymers
Cellulosic polymers (GMC. HEC)
Guar gyis
Acrylic polymers
15,000 tons/year
12.500 tons/year
SOO tons/year
2,500 tons/>eor
Lost Circulation Materials
Lost circylation Materials used comprise a variety of nontOiic
substances including cellophane, cotton seed, rice hulls, ground
Formica, ground leather, ground paper, ground pecan and walnut
shells, mica, and wood and cane fibers, A total of ?0.000 tons of
tnese materials is used per year.
III-8
-------
35611
laole II1-2 (continued)
Surface Active Agents
Surface active agents (used as em^lsificrs, detergents, defoamants)
me luoe:
» Fatty acids, naphtnenic acids, and soaps 5,000
tons/year
* Organic sulfates/sylfcmates 1,000 tons/year
» Aluminum siearate (quantity not available!
Lubricants
Lubricants used include;
Vegetable oils 500 tons/year
Qraphne <5 tons/year
flocculating Agents
The primary f loccy lat ing agents ysea in drilling are:
• Acrylic polymers 2,500 tons/year
Btoe ides
Biocides used \rt drilling include: '
• Organic amines, amides, amine salts 1,000 tons/year
• Aldehydes jparaformaldehyde) 500 tons/year
• Chlorinated phenols <1 ton/year
» Organosulfur compounds and (quantity not available)
organometallics
Hi seel laneous
Miscellaneous drilling flytd additives include.
• Ethoxylated alk.yl phenols 1,800 tons/year
• Aaliphatic alcohols <10 tons/year
• Alymmu* anhydride derivatives (quantities not
and chrom alum available)
III-9
-------
Table II1-2 (continued)
tasmercial Chemicals
Cofltnercial chemicals used in drilling fluid include:
Sodium hydroxide
Sodium Chloride
Sodium carbonate
Calcium chlorine
Calcium hydroxide/calcium ox-.de
Potassium chloride
Sodium chromate/dichromate
Calcium sulfate
Potassium hydro*.ide
Sodium bicarbonate
Sodiyra sulf He
Hagnesium oxide
Barium carbonate
50,000 tons/year
50,000 tons/year
20,000 tons/year
12.SOS tons/year
10.000' tons/year
5000 tons/year
4,000 tons/year
500 tons/year
500 tons/year
500 tons/year
50 tons/year
<10 tons/year
(quantity not available)
These commercial chemicals are used for a variety of purposes
including pH control, corrosion inhibition, increasing fluid phase
density, treating out calcium sulfdte in low pH muds, treating out
calctuss sulfate in high pM muds.
Corrosion Inhibitors
Corrosion inhibitors used include;
Iron oxide
Ammonium bisulfite
Basic zinc carbonate
Zinc chromate
100 tons/year
100 tons/year
100 tons/year
<10 tons/year
AP] states that sodium chromate is no longer used in drilling
mud.
111-10
-------
Fracturing and Acidizing Fluids
Fracturing and acidizing are processes commonly used to enlarge
existing channels and open new ones to a wellbore for several purposes:
« To increase permeability of the production formation of a well;
• To increase the zone of influence of injected fluids used in
enhanced recovery operations; and
» To increase the rate of injection of produced water and
industrial waste material into disposal wells.
The process of "fracturing" involves breaking down the formation,
often through the application of hydraulic pressure, followed by pumping
mixtures of gelled carrying fluid and sand into the induced fractures to
hold open the fissures in the rocks after the hydraulic pressure is
released, fracturing fluids can be oil-based or water-based. Additives
are used to reduce the leak-off rate, to increase the amount of propping
agent carried by the fluid, and to reduce pumping friction. Such
additives may include corrosion inhibitors, surfactants, sequestering
agents, and suspending agents. The volume of fracturing fluids used to
?
stimulate a well can be significant. Closed systems, which do
not involve reserve pits, are used very occasionally (see discussion
below). However, closed systems are widely used in California. Many oil
and gas fields currently being developed contain low-permeability
reservoirs that may require hydraulic fracturing for commercial
production of oil or gas.
Mobile Oil Co. recently set a well stimulation record (single stage) in a Wilcox
formation well in Zapata County, Texas, by placing 6,3 million pounds of sand, using i fracturing
fluid volume of 1,54 million gallons (Morld Oil, January 198?).
III-ll
-------
The process of "acidizing" is done by injecting acid into the target
formation. The acid dissolves the rock, creating new channels to the
wellbore and enhancing existing ones. The two basic types of acidizing
treatments used are:
« Low-pressure acidizing: acidizing that avoids fracturing the
formation and allows acid to work through the natural pores
(matrix) of the formation.
• Acid fracturing: acidizing that utilizes high pressure and high
volumes of fluids (acids) to fracture rock and to dissolve the
matrix in the target formation.
The types of acids normally used include hydrochloric acid (in
concentrations ranging from 15 to 28 percent in water), hydrochloric-
hydrofluoric acid mixtures (12 percent and 3 percent, respectively), and
acetic acid. Factors influencing the selection of acid type include
formation solubility, reaction time, reaction products effects, and the
sludging and emulsion-forming properties of the crude oil. The products
of spent acid are primarily carbon dioxide and water.
Spent fracturing and acidizing fluid may be discharged to a tank, to
the reserve pit, or to a workover pit.
Completion and Workoyer F1u i ds
Completion and workover fluids are the fluids placed in the wellbore
during completion or workover to control the flow of native formation
fluids, such as water, oil, or gas. The base for these fluids is usually
water. Various additives are used to control density, viscosity, and
filtration rates; prevent gelling of the fluid; and reduce corrosion.
They include a variety of salts, organic polymers, and corrosion
inhibitors.
111-12
-------
When the completion or workover operation is completed, the fluids in
the wellbore are discharged into a tank, the reserve pit, or a workover
pit.
Riqwash and Other Miscellaneous Wastes
Rigwash materials are compounds used to clean decks and other rig
equipment. They are mostly detergents but can include some organic
solvents, such as degreasers.
Other miscellaneous wastes include pipe dope used to lubricate
connections in pipes, sanitary sewage, trash, spilled diesel oil, and
lubricating oil.
All of these materials may, in many operations, be disposed of in the
reserve pit.
ONSITE DRILLING yASTE MANAGEMENT METHODS
Several waste management methods can be used to manage oil and gas
drilling wastes onsite. The material presented below provides a separate
discussion for reserve pits, landspreading, annular disposal,
solidification of reserve pit wastes, treatment and disposal of liquid
wastes to surface water, and closed treatment systems.
Several waste management methods may be employed at a particular site
simultaneously. Issues associated with reserve pits are particularly
complex because reserve pits are both an essential element of the
drilling process and a method for accumulating, storing, and disposing of
wastes. This section therefore begins with a general discussion of
111-13
-------
several aspects of reserve pits-~design, construction, operation, and
closure — and then continues with more specific discussions of the other
technologies used to manage drilling wastes.
Reserve Pits
Description
Reserve pits, an essential design component in the great majority of
well drilling operations,3 are used to accumulate, store, and, to
a large extent, dispose of spent drilling fluids, cuttings, and
associated drill site wastes generated during drilling, completion, and
testing operations.
There is generally one reserve pit per well. In 1985, an estimated
70,000 reserve pits were constructed. In the past, reserve pits were
used both to remove and dispose of drilled solids and cuttings and to
store the active mud system prior to its being recycled to the, well being
drilled. As more advanced solids control and drilling fluid technology
has become available, mud tanks have begun to replace the reserve pit as
the storage and processing area for the active mud system, with the
reserve pit being used to dispose of waste mud and cuttings. Reserve
pits will, however, continue to be the principal method of drilling fluid
storage and management.
A reserve pit is typically excavated directly adjacent to the site of
the rig and associated drilling equipment. Pits should be excavated from
undisturbed, stable subsoil so as to avoid pit wall failure. Where it is
impossible to excavate below ground level, the pit berm (wall) is usually
constructed as an earthen dam that prevents runoff of liquid into
adjacent areas.
Closed systems, which do not involve reserve pits, are used very occasionally (see
discussion below). However, closed systems are widely used in California,
111-14
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In addition to the components found in drilling mud, common
constituents found in reserve pits include salts, oil and grease, and
dissolved and/or suspended heavy metals. Sources of soluble salt
contamination include formation waters, downhole salt layers, and
drilling fluid additives. Sources of organic contamination include
lubricating oil from equipment leaks, well pressure control equipment
testing, heavy oil-based lubricants used to free stuck drill pipe, and,
in some cases, oil-based muds used to drill and complete the target
formation.4 Sources of potential heavy metal contamination
include drilling fluid additives, drilled solids, weighting materials,
pipe dope, and spilled chemicals (Rafferty 1985).
The reserve pit itself can be used for final disposal of all or part
of the drilling wastes, with or without prior onsite treatment of wastes,
or for temporary storage prior to offsite disposal. Reserve pits are
most often used in combination with some other disposal techniques, the
selection of which depends on waste type, geographical location of the
site, climate, regulatory requirements, and (if appropriate) lease
agreements with the landowner.
The major onsite waste disposal methods include:
• Evaporation of supernatant;
» Backfilling of the pit itself, burying the pit solids and
drilled cuttings by using the pit walls as a source of material
(the most common technique);
• Landspreading all or part of the pit contents onto the area
immediately adjacent to the pit;
Charles A. Koch of the North Dakota Industrial CotmiissJon, Oil and Gas Division, states
that "A company would not nomallj change the entire drilling fluid for just the target zone. This
change woyld add drastically to the cost of drilling,"
111-15
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• Onsite treatment and discharge;
» Injecting or pumping all or part of the wastes into the well
annulus; and
*
» Discharge to surface waters.
Another less common onsite management method is chemical
solidification of the wastes.
Dewatering and burial of reserve pit contents (or, alternatively,
landspreading the pit contents) are discussed here because they are
usually an integral aspect of the design and operation of a reserve pit.
The other techniques are discussed separately.
Dewatering of reserve pit wastes is usually accomplished through
natural evaporation or skimming of pit liquids. Evaporation is used
where climate permits. The benefits of evaporation may be overstated.
In the arid climate of Utah, 93 percent of produced waters in an unlined
pit percolated into the surrounding soil. Only 7 percent of the produced
water evaporated (Davani et al. 1985). Alternatively, dewatering can be
accomplished in areas of net precipitation by siphoning or pumping off
free liquids. This is followed by disposal of the liquids by subsurface
injection or by trucking them offsite to a disposal facility.
Backfilling consists of burying the residual pit contents by pushing in
the berms or pit walls, followed by compaction and leveling.
Landspreading can involve spreading the excess muds that are squeezed out
during the burial operation on surrounding soils; where waste quantities
are large, landowners' permission is generally sought to disperse this
material on land adjacent to the site. (This operation is different from
commercial landfarming, which is discussed later.)
111-16
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Environmental Performance
Construction of reserve pits is technically simple and
straightforward. They do not require intensive maintenance to ensure
proper function, but they may, in certain circumstances, pose
environmental hazards during their operational phase.
Pits are generally built or excavated into the surface soil zones or
into unconsolidated sediments, both of which are commonly highly
permeable. The pits are generally unlined,5 and, as a result,
seepage of liquid and dissolved solids may occur through the pit sides
and bottom into any shallow, unconfined freshwater aquifers that may be
present. When pits are lined, materials used include plastic liners,
compacted soil, or clay. Because reserve pits are used for temporary
storage of drilling mud, any seepage of pit contents to ground water may
be temporary, but it can in some cases be significant, continuing for
decades {USEPA 1986).
Other routes of environmental exposure associated with reserve pits
include rupture of pit berms and overflow of pit contents, with
consequent discharge to land or surface water. This can happen in areas
of high rainfall or where soil used for berm construction is particularly
unconsolidated. In such situations, berms can become saturated and
weakened, increasing the potential for failure. Leaching of pollutants
after pit closure can also occur and may be a long-term problem
especially in areas with highly permeable soils.
An API study suggests that 37 percent of reserve pits are lined with a clay or synthetic
1 mer.
111-17
-------
Annular Disposal of Pumpable Drilling Hastes
Description
Annular disposal involves the pumping of waste drilling fluids down
the annulus created between the surface and intermediate casing of a well
(see Figure III-l). (Disposal of solids is accomplished by using burial,
solidification, landfarming, or landspreading techniques.) Disposal down
the surface casing in the absence of an intermediate casing is also
considered annular disposal. Annular disposal of pumpable drilling
wastes is significantly more costly than evaporation, dewatering, or land
application and is generally used when the waste drilling fluid contains
an objectionable level of a contaminant or contaminants (such as
chlorides, metals, oil and grease, or acid) which, in turn, limits
availability of conventional dewatering or land application of drilling
wastes. However, for disposal in a "dry" hole, costs may be relatively
low. No statistics are available on how frequently annular injection of
drilling wastes is used.
Environmental Performance
The well's surface casing is intended to protect fresh ground-water
zones during drilling and after annular injection. To avoid adverse
impacts on ground water in the vicinity of the well after annular
injection, it is important that surface casing be sound and properly
cemented in place. There is no feasible way to test the surface casing
for integrity without incurring significant expense.
Assuming the annulus is open and the surface casing has integrity,
the critical implementation factor is the pressure at which the reserve
111-18
-------
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Figure 111-1 Annular Disposal of Waste Drilling Fluids
-------
pit contents are injected. The receiving strata are usually relatively
shallow, permeable formations having low fracture pressures. If these
pressures are exceeded during annular injection, the strata may develop
vertical fractures, potentially allowing migration of drilling waste into
freshwater zones.
Another important aspect of annular injection is identification and
characterization of the confining shale layer above the receiving
formation. Shallow confining layers are, very often, discontinuous. Any
unidentified discontinuity close to the borehole increases the potential
for migration of drilling wastes into ground water.
Drilling Haste Solidification
Description
Surface problems with onsite burial of reserve pit contents reported
by landowners (such as reduced load-bearing capacity of the ground over
the pit site and the formation of wet spots), as well as environmental
problems caused by leaching of salts and toxic constituents into ground
water, have prompted increased interest in reserve pit waste
solidification.
In the solidification process, the total reserve pit waste (fluids
and cuttings) is combined with solidification agents such as commercial
cement, flash, or lime kiln dust. This process forms a relatively
insoluble concrete-like matrix, reducing the overall moisture content of
the mixture. The end product is more stable and easier to handle than
reserve pit wastes buried in the conventional manner.. The solidification
process can involve injecting the solidifying agents into the reserve pit
111-20
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or pumping the wastes into a mixing chamber near the pit. The waste does
not have to be dewatered prior to treatment. Solidification can increase
the weight and bulk of the treated waste, which may in some cases be a
disadvantage of this method.
Environmental Performance
Solidification of reserve pit wastes offers a variety of
environmental improvements over simple burial of wastes, with or without
dewatering. By reducing the mobility of potentially hazardous materials,
such as heavy metals, the process decreases the potential for
contamination of ground water from leachate of unsolidified, buried
reserve pit wastes. Bottom sludges, in which heavy metals largely
accumulate, may continue to leach into ground water. (There are no data
to establish whether the use of kiln dust would add harmful constituents
to reserve pit waste. Addition of kiln dust would increase the volume of
waste to be managed.)
Treatment and Discharge of Liquid Wastes to Land or Surface Water
Description
Discharge of waste drilling fluid to surface water is prohibited by
EPA's zero discharge effluent guideline. However, in the Gulf Coast
area, the liquid phase of waste drilling muds having low chloride
concentrations is chemically treated for discharge to surface water. The
treated aqueous phase (at an appropriate alkaline pH) can then be
111-21
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discharged to land or surface water bodies,6 The addition of
selected reagents to reserve pit liquids must achieve the necessary
reactions to allow effective separation of the suspended solids prior to
dewatering of the sludge in the reserve pit.
Onsite treatment methods used prior to discharge are commercially
available for reserve pit fluids as well as for solids. They are
typically provided by mobile equipment .brought to the drill site. These
methods include pH adjustment, aeration, coagulation and flocculation,
centrifugation, filtration, dissolved gas flotation, and reverse
osmosis. All these methods, however, are more expensive than the more
common approach of dewatering through evaporation and percolation.
Usually, a treatment company employs a combination of these methods to
treat the sludge and aqueous phases of reserve pit wastes.
Environmental Performance
Treatment and discharge of liquid wastes are used primarily, to
shorten the time necessary to close a pit.
Closed Cycle Systems
Description
A closed cycle waste treatment system can be an alternative to the
use of a reserve pit for onsite management and disposal of drilling
David Flannery states that his interpretation of E?A's effluent guidelines would
preclude such a discharge. "On July 4, 1987, a petition was filed with EPA to revise the effluent
guideline. If that petition is granted, stream discharges of drilling fluid and produced fluids
would be allowed at least from operations in the Appalachian States."
111-22
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wastes. Essentially an adaptation of offshore systems for onshore use,
closed systems have come into use relatively recently. Because of their
high cost, they are used very rarely, usually only when operations are
located at extremely delicate sites (such as a highly sensitive wildlife
area), in special development areas (such as in the center of an
urbanized area), or where the cost of land reclamation is considered
excessive. They can also be used where limited availability of makeup
water for drilling fluid makes control of drill cuttings by dilution
infeasible.
Closed cycle systems are defined as systems in which mechanical
solids control equipment (shakers, impact type sediment separation, mud
cleaners, centrifuges, etc.) and collection equipment (roll-off boxes,
vacuum trucks, barges, etc.) are used to minimize waste mud and cutting
%
volumes to be disposed of onsite or offsite. This in turn maximizes the
volume of drilling fluid returned to the active mud system. Benefits
derived from the use of this equipment include the- following (Hanson et
al. , 1986):
» A reduction in the amount of water or oil needed for mud
maintenance;
« An increased rate of drill bit penetration because of better
solids control;
• Lower mud maintenance costs;
• Reduced waste volumes to be disposed of; and
• Reduction in reserve pit size or total elimination of the
reserve pit.
Closed cycle systems range from very complex to fairly simple. The
degree of solids control used is based on the mud type and/or drilling
program and the economics of waste transportation to offsite disposal
111-23
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facilities (particularly the dollars per barrel charges at these
facilities versus the cost per day for additional solids control
equipment rental). Closed systems at drill 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 because drill cuttings
are always produced and removed. The closed system for solids, or the
mud recirculation system, can vary in design from site to site, but the
system roust have sufficient solids handling equipment to effectively
remove the cuttings from muds to be reused.
Water removed from the mud and cuttings can be reused. It is
possible to operate a separate closed system for water reuse 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 water required for further use. This may
include chemical treatment of the water.
Environmental Performance
Although closed systems offer many environmental advantages, their
high cost seriously reduces their potential use, and the mud and cuttings
must still ultimately be disposed of.
Disposal of Drilling Hastes on the North Slope of Alaska—A Special
Case
The North Slope is an arctic desert consisting of a wet coastal plain
underlain by up to 2,500 feet of permafrost, the upper foot or two of
which thaws for about 2 months a year. The North Slope is considered to
be a sensitive area because of the extremely short growing season of the
tundra, the short food chain, and the lack of species diversity found in
111-24
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this area. Because of the area's severe climate, field practices for
management of drilling media and resulting waste are different on the
North Slope of Alaska from those found elsewhere in the country. In the
Arctic, production pads are constructed above ground using gravel. This
type of construction prevents melting of the permafrost. Reserve pits
are constructed on the production pads using gravel and native soils for
the pit walls; they become a permanent part of the production facility.
Pits are constructed above and below grade.
Because production-related reserve pits on the North Slope are
permanent, the contents of these pits must be disposed of periodically.
This is done by pumping the aqueous phase of a pit onto the tundra. This
pumping can take place after a pit has remained inactive for 1 year to
allow for settling of solids and freeze-concentration of constituents;
the aqueous phase is tested for effluent limits for various constituents
established by the State of Alaska. The National Pollutant Discharge
Elimination System (NPDES) permit system does not cover these
discharges. An alternative to pumping of the reserve pit liquids onto
the tundra is to "road-spread" the liquid, using it as a dust control
agent on the gravel roads connecting the production facilities. Prior
to promulgation of new State regulations, no standards other than "no oil
sheen" were established for water used for dust control. ADEC now
requires that at the edge of the roads, any leachate, runoff, or dust
must not cause a violation of the State water quality standards. Alaska
is evaluating the need for setting.standards for the quality of fluids
used to avoid undesirable impacts. Other North Slope disposal options
for reserve pit liquids include disposal of the reserve pit liquids
through annular injection or disposal in Class II wells. The majority of
reserve pit liquids are disposed of through discharge to the tundra.
Reserve pits on the North Slope are closed by dewatering the pit and
filling it with gravel. The solids are frozen in place above grade and
111-25
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below grade. Freezing in place of solid waste is successful as long as
hydrocarbon contamination of the pit contents is minimized. Hydrocarbon
residue in the pit contents can prevent the solids from freezing
completely. In above-grade structores thawing will occur in the brief
summer. If the final waste surface is below the active thaw zone, the
wastes will remain frozen year-round.
Disposal of produced waters on the North Slope is through subsurface
injection. This practice does not vary significantly from subsurface
injection of production wastes in the Lower 48 States, and a description
of this practice can be found under "Production-Related Wastes" below.
Environmental Performance
Management of drilling media and associated waste can be problematic
in the Arctic. Because of the severe climate, the reserve pits
experience intense freeze-thaw cycles that can break down the stability
of the pit walls, making .them vulnerable to erosion. From time to time,
reserve pits on the North Slope have breached, spilling untreated liquid
and solid waste onto the surrounding tundra. Seepage of untreated
reserve pit fluids through pit walls is also known to occur.
Controlled discharge of excess pit liquids is a State-approved
practice on the North Slope; however, the long-term effects of
discharging large quantities of liquid reserve pit waste on this
sensitive environment are of concern to EPA, Alaska Department of
Environmental Conservation (ADEC), and officials from other Federal
agencies. The existing body of scientific evidence is insufficient to
conclusively demonstrate whether or not there are impacts resulting from
this practice.
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OFFS1TE WASTE HANAGEHENT METHODS
Offsite waste management methods include the use of centralized
disposal pits (centralized injection facilities, either privately or
commercially operated, will be discussed under "subsurface injection" of
production wastes), centralized treatment facilities, commercial
landfarming, and reconditioning and reuse of drilling media.
Centralized Disposal Pits
Description
Centralized disposal pits are used in many States to store and
dispose of reserve pit wastes. In some cases, large companies developing
%
an extensive oil or gas field may operate centralized pits within the
field for better environmental control and cost considerations. Most
centralized pits are operated commercially, primarily for the use of
smaller operators who cannot afford to construct properly designed and
sited disposal pits for their own use. They serve the disposal needs for
drilling or production wastes from multiple wells over a large
geographical area. Centralized pits are typically used when storage and
disposal of pit wastes onsite are undesirable because of the high
chloride content of the wastes or because of some other factor that
raises potential problems for the operators.7 Wastes are
generally transported to centralized disposal pits in vacuum trucks.
These centralized pits are usually located within 25 miles of the field
sites they serve.
Operators, for instance, say be reauired ynder their lease agreements with landowners not
to dispose of their pit wastes onsite because of the potential for groynd-water contamination.
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The number of commercial centralized pits in major oil-producing
States may vary from a few dozen to a few hundred. The number of
privately developed centralized pits is not known.
*
Technically, a centralized pit is identical in basic construction to
a conventional reserve pit. It is an earthen impoundment, which can be
lined or unlined and used to accumulate, store, and dispose of drilling
fluids from drilling operations within a certain geographical area.
Centralized pits tend to be considerably larger than single-well pits;
surface areas can be as large as 15 acres, with depths as great as 50
feet. Usually no treatment of the pit contents is performed. Some
centralized pits are used as separation pits, allowing for solids
settling. The liquid recovered from this settling process may then be
injected into disposal wells. Many centralized pits also have State
requirements for oil skimming and reclamation.
Environmental Performance
Centralized pits are a storage and disposal operation; they usually
perform no treatment of wastes.
Closure of centralized pits may pose adverse environmental impacts.
In the past some pits have been abandoned without proper closure,
sometimes because of the bankruptcy of the original operator. So far as
EPA has been able to determine, only one State, Louisiana, has taken
steps to avoid this eventuality; Louisiana requires operators to post a
bond or irrevocable letter of credit (based on closing costs estimated in
the facility plan) and have at least $1 million of liability insurance to
cover operations of open pits.
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Centralized Treatment Facilities
Description
A centralized treatment facility for oil and gas drilling wastes is a
process facility that accepts such wastes solely for the purpose of
conditioning and treating wastes to allow for discharge or final
disposal. Such facilities are distinct from centralized disposal pits,
which do not treat drilling wastes as part of their storage and disposal
functions. The use of such facilities may remove the burden of disposal
of wastes from the operators in situations where State regulations have
imposed stringent disposal requirements for burying reserve pit wastes
onsite.
Centralized treatment may be an economically viable alternative to
onsite waste disposal for special drilling fluids, such as oil-based
muds, which cannot be disposed of in a more conventional manner. The
removal, hauling, and treatment costs incurred by treatment at commercial
sites will generally outweigh landspreading or onsite burial costs. A
treatment facility can have a design capacity large enough to accept a
great quantity of wastes from many drilling and/or production facilities.
Many different treatment technologies can potentially be applied to
centralized treatment of oil and gas drilling wastes. The actual method
used at the particular facility would depend on a number of factors. One
of these factors is type of waste. Currently, some facilities are
designed to treat solids for pH adjustment, dewatering, and
solidification (muds and cuttings), while others are designed to treat
produced waters, completion fluids, and stimulation fluids. Some
facilities can treat a combination of wastes. Other factors determining
treatment method include facility capacity, discharge options and
requirements, solid waste disposal options, and other relevant State or
local requirements.
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Envi ronmental Performance
Experience with centralized treatment is limited. Until recently, it
was used only for treatment of offshore wastes. Its use in recent years
for onshore wastes is commercially speculative, being principally a
commercial response to the anticipated impacts of stricter State rules
pertaining to oil and gas drilling and production waste. The operations
have not been particularly successful as business ventures so far.
Commercial Landfarming
Description
Landfarming is a method for converting reserve pit waste material
into soil-like material by bacteriological breakdown and through soil
incorporation. The method can also be used to process production wastes,
such as production tank bottoms, emergency pit cleanouts, and .scrubber
bottoms. Incorporation into soil uses dilution, biodegradation, chemical
alteration, and metals adsorption mechanisms of soil and soil bacteria to
reduce waste constituents to acceptable soil levels consistent with
intended land use.
Solid wastes are distributed over the land surface and mixed with
soils by mechanical means. Frequent turning or disking of the soil is
necessary to ensure uniform biodegradation. yaste-to-soil ratios are
normally about 1:4 in order to restrict concentrations of certain
pollutants in the mixture, particularly chlorides and oil (Tucker 1985).
Liquids can be applied to the land surface by various types of irrigation
including sprinkler, flood, and ridge and furrow. Detailed landfarming
design procedures are discussed in the literature (Freeman and Deuel
1984).
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Landfarming methods have been applied to reserve pit wastes in
commercial offsite operations. The technique provides both treatment and
final disposition of salts, oil and grease, and solids. Landfarming may
eventually produce large volumes of soil-like material that must be
removed from the area to allow operations to continue.
Requirements for later reuse or disposal of this material must be
determined separately.
EnvironmentalPerformance
Landfarming is generally done in areas large enough to incorporate
the volume of waste to be treated. In commercial landfarming operations
where the volume of materials treated within a given area is large, steps
must be taken to ensure protection of surface and ground water. It is
important, for instance, to minimize application of free liquids so as to
reduce rapid transport of fluids through the soils.
The process is most suitable for the treatment of organics,
especially the lighter fluid fractions that tend to distribute themselves
quickly into the soil through the action of biodegradation. Heavy metals
are also "treated" in the sense that they are adsorbed onto clay
particles in the soil, presumably within a few feet of where they are
applied; but the capacity of soils to accept metals is limited depending
upon clay content. Similarly, the ability of the soil to accept
chlorides and still sustain beneficial use is also limited.
Some States, such as Oklahoma and Kansas, prohibit the use of
commercial landfarming of reserve pit wastes. Other States, such as
Louisiana, allow reuse of certain materials treated at commercial
landfarrning facilities. Materials determined to meet certain criteria
after treatment can be reused for applications such as daily sanitary
111-31
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landfill covering or roadbed construction. When reusing landfarmed
material, it is important that such material not adversely affect any
part of the food chain,
Reconditioning and Reuse of Drilling Media
Description
Reconditioning and reuse of drilling media are currently practiced in
a few well-defined situations. The first such situation involves the
reconditioning of oil-based muds. This is a universal practice because
of the high cost of oil used in making up this type of drilling media.
A second situation involves the reuse of reserve pit fluids as "spud"
muds, the muds used in drilling the initial shallow portions of a well in
which lightweight muds can be used. A third situation involves the
increased reuse of drilling fluid at one well, using more efficient
solids removal. Less mud is required for drilling a single well if
efficient solids control is maintained. Another application for reuse of
drilling media is in the plugging procedure for well abandonment.
Pumpable portions of the reserve pit are transported by vacuum truck to
the well being closed. The muds are placed in the wellbore to prevent
contamination of possibly productive strata and freshwater aquifers from
saltwater strata. The ability to reuse drilling media economically
varies widely with the distance between drilling operations, frequency
and continuity of the drilling schedule, and compatibility between muds
and formations among drill sites,
Environmental Performance
The above discussion raises the possibility of minimization of
drilling fluids as an approach to limiting any potential environmental
impacts of drilling-related wastes. Experience in reconditioning and
reusing spud muds and oil-based muds does not provide any estimate of
111-32
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specific benefits that might be associated with recycling or reuse of
most conventional drilling muds. Benefits from mud recycling at the
project level can be considerable. From a national perspective, benefits
are unknown. The potential for at least some increased recycling and
reuse appears to exist primarily through more efficient management of mud
handling systems. Specific attempts to minimize the volume of muds used
are discouraged, at present, by two factors: (1) drilling mud systems are
operated by independent contractors, for whom sales of muds are a primary
source of income, and (2) the central concern of all parties is
successful drilling of the well, resulting in a general bias in favor of
using virgin materials.
In spite of these economic disincentives, recent industry studies
suggest that the benefits derived from decreasing the volume of drilling
mud used to drill a single well are significant, resulting in mud cost
reductions of as much as 30 percent (Amoco 1985).
PRODUCTION-RELATED WASTES
Waste Characterization
Produced Water
When oil and gas are extracted from hydrocarbon reservoirs, varying
amounts of water often accompany the oil or gas being produced. This is
known as produced water. Produced water may originate from the reservoir
being produced or from waterflood treatment of the field (secondary
recovery). The quantity of water produced is dependent upon the method
of recovery, the nature of the formation being produced, and the length
of time the field has been producing. Generally, the ratio of produced
water to oil or gas increases over time as the well is produced.
Host produced water is strongly saline. Occasionally, chloride
levels, and levels of other constituents, may be low enough (i.e., less
111-33
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than 500 ppm chlorides) to allow the water to be used for beneficial
purposes such as crop irrigation or livestock watering. More often,
salinity levels are considerably higher, ranging from a few thousand
parts per million to over 150,000 ppm. Seawater, by contrast, is
typically about 35,000 ppm chlorides. Produced water also tends to
contain quantities of petroleum hydrocarbons (especially lower molecular
weight compounds), higher molecular weight alkanes, polynuclear aromatic
hydrocarbons, and metals. It may also contain residues of biocides and
other additives used as production chemicals. These can include
coagulants, corrosion inhibitors, cleaners, dispersants, emulsion
breakers, paraffin control agents, reverse emulsion breakers, and scale
inhibitors.
Radioactive materials, such as radium, have been found in some oil
field produced waters. Ra-226 activity in filtered and unfiltered
produced waters has been found to range between 16 and 395
picocuries/1iter; Ra-228 activity may range from 170 to 570
picocuries/1 Her (USEPA 1985). The ground-water standard for the Maximum
Contaminant Level (MCL) for combined Ra-226 and Ra-228 is
5 picocuries/1iter (40 CFR, Part 257, Appendix 1). No study has been
done to determine the percentage of produced water that contains
radioactive materials.
Low-Volyme Product ion Wastes
Low-volume production-related wastes include many of the chemical
additives discussed above in relation to drilling (see Table III-2), as
well as production tank bottoms and scrubber bottoms.
Onsite Management Methods
Onsite management methods for production wastes include subsurface
injection, the use of evaporation and percolation pits, discharge of
produced waters to surface water, and storage.
111-34
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Subsurface Injection
DescriptIon: Today, subsurface injection is the primary method for
disposing of produced water from onshore operations, whether for enhanced
oil recovery (EOR) or for final disposal. Nationally, an estimated 80
percent of all produced water is disposed of in injection wells permitted
under EPA's Underground Injection Control (UIC) program under the
authority of the Safe Drinking Water Act.8 In the major
oil-producing States, it is estimated that over 90 percent of production
wastes are disposed of by this method. Subsurface injection may be done
at injection wells onsite, offsite, or at centralized facilities. The
mechanical design and procedures are generally the same in all cases.
%
In enhanced recovery projects, produced water is generally
reinjected into the same reservoir from which the water was initially
produced. Where injection is used solely for disposal, produced water is
injected into saltwater formations, the original formation, or older
depleted producing formations. Certain physical criteria make a
formation suitable for disposal, and other criteria make a formation
acceptable to regulatory authorities for disposal.
The sequence of steps by which waste is placed in subsurface
formations may include:
• Separation of free oil and grease from the produced water;
• Tank storage of the produced water;
» Filtration;
» Chemical treatment (coagulation, flocculation, and possibly pH
adjustment); and, ultimately,
« Injection of the fluid either by pumps or by gravity flow.
API states that 80 to 90 percent of all produced water is injected in Class I! wells.
111-35
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By regulation, injection for the purpose of disposal must take place
below all formations containing underground sources of drinking water
(USDWs). Figure III-2 displays a typical disposal well pumping into a
zone located below the freshwater table (Templeton and Associates 1980),
The type of well often preferred by State regulatory agencies is the well
specifically drilled, cased, and completed to accept produced water and
other oil and gas production wastes. Another type of disposal well is a
converted production well, the more prevalent type of disposal and
enhanced recovery well. An injection well's location and age and the
composition of injected fluids are the important factors in determining
the level of mechanical integrity and environmental protection the well
can provide.
Although it is not a very widespread practice, some produced water is
disposed of through the annulus of producing wells. In this method,
produced water is injected through the annular space between the
production casing and the production tubing (see Figure III-3).9
Injection occurs using little or no pressure. The disposal zone is
shallower than the producing zone in this case. Testing of annular
disposal wells is involved and expensive.
One method of testing the mechanical integrity of the casing used for
annular injection, without removing the tubing and packer, is through the
use of radioactive tracers and sensing devices. This method involves the
pumping of water spiked with a low-level radioactive tracer into the
injection zone, followed by running a radioactivity-sensing logging tool
through the tubing string. This procedure should detect any shallow
casing leaks or any fluid migration between the casing and the borehole.
Most State regulatory agencies discourage annular injection and allow the
practice only in small-volume, low-pressure applications.
9 In
the State of Ohio, produced water is gravity-fed into the annulus rather than being
pumped.
111-36
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PRODUCED WATER
MONITOR ANNULUS PRESSURE
£S^£±£gg:g£ USDW*
SURFACE CASING
CEMENTED TO SURFACE
ANNULUS CONTAINING
CORROSION INHIBITING
PACKER FLUID
PRODUCTION CASING
TUBING STRING
WITH PACKER
_ _ - _ DISPOSAL ZONE
SOURCE: TEMPLETON, ELMER E., AND ASSOCIATES, ENVIRONMENTALLY
ACCEPTABLE DISPOSAL OF SALT BRINES PRODUCED WITH OIL
AND GAS, JANUARY, 1980.
" UNDERGROUND SOURCE OF DRINKING WATER
NOTE: NOT TO SCALE
Figure IU-2 Typical Produced Water Disposal Well Design
111-37
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: ~« ~" PRODUCING
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SOURCE: TEMPLETON, ELMER E., AND ASSOCIATES, ENVIRONMENTALLY
ACCEPTABLE DISPOSAL OF SALT BRINES PRODUCED WITH OIL
AND GAS, JANUARY, 1980.
" UNDERGROUND SOURCE OF DRINKING WATER
NOTE; NOT TO SCALE
Figure UI-3 Annular Disposal Outside Production Casing
111-38
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Environmental performance: From the environmental standpoint, the
primary issue with disposal of produced waters is the potential for
chloride contamination of arable lands and fresh water. Other
constituents in produced water may also affect the quality of ground
water. Because of their high solubility in water, there is no practical
way to immobilize chlorides chemically, as can be done with heavy metals
and many other pollutants associated with oil and gas production.
Injection of produced water below all underground sources of drinking
water is environmentally beneficial if proper safeguards exist to ensure
that the salt water will reach a properly chosen disposal horizon, which
is sufficiently isolated from usable aquifers. This can be accomplished
by injecting water into played-out formations or as part of a
waterflooding program to enhance recovery from a field. Problems to be
%
avoided include overpressurization of the receiving formation, which
could lead to the migration of the injected fluids or native formation
fluids into fresh water via improperly completed or abandoned wells in
the pressurized area. Another problem is leaking of injected fluids into
freshwater zones through holes in the tubing and casing.
The UIC program attempts to prevent these potential problems. The
EPA UIC program requires periodic mechanical integrity tests (MITs) to
detect leaks in casing and ensure mechanical integrity of the injection
well. Such testing can detect performance problems if it is
conscientiously conducted on schedule. The Federal regulations require
that mechanical integrity be tested for at least every 5 years. If leaks
are detected or mechanical integrity cannot be established during the
testing of the well, the response is generally to suspend disposal
operations until the well is repaired or to plug and abandon the well if
repair proves too costly or inefficient. The Federal regulations also
require that whenever a new well or existing disposal well is permitted,
a one-quarter mile radius around the well must be reviewed for the
presence of manmade or natural conduits that could lead to injected
fluids or native brines leaving the injection zone. In cases where
111-39
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improperly plugged or completed wells are found, the permit applicant
must correct the problems or agree to limit the injection pressure.
Major factors influencing well failure include the design, construction,
and age of the well itself (converted producing wells, being older, are
more likely to fail a test for integrity than newly constructed Class II
injection wells); the corrosivity of the injected fluid (which varies
chiefly in chloride content); and the injection pressure (especially if
wastes are injected at pressures above specified permit limits).
Design, ...construction, operation, and testing: There is considerable
variation in the actual construction of Class II wells in operation
nationwide because many wells in operation today were constructed prior
to enactment of current programs and because current programs themselves
raay vary quite significantly. The legislation authorizing the UIC
program directed EPA to provide broad flexibility in its regulations so
as not to impede oil and gas production, and to impose only requirements
that are essential to the protection of USDWs, Similarly, the Agency was
required to approve State programs, for oil and gas wells whether or not
they met EPA's regulations as long as they contained the minimum required
by the Statute and were effective in protecting USDWs. For these reasons
there is great variability in UIC requirements in both State-run and
EPA-run programs. In general, requirements for new injection wells are
quite extensive. Not every State, however, has required the full use of
the "best available" technology. Furthermore, State requirements have
evolved over time, and most injection wells operate with a lifetime
permit. In practice, construction ranges from wells in which all USDWs
are fully protected by two strings of casing and cementing, injection is
through a tubing, and the injection zone is isolated by the packer and
cement in the wellbore to shallow wells with one casing string, no
packer, and little or no cement.
With respect to requirements for mechanical integrity testing of
injection wells, Federal UIC requirements state that "an injection well
111-40
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has mechanical integrity if: (1) there is no significant leak in the
casing, tubing or packer; and (2) there is no significant fluid movement
into an underground source of drinking water through vertical channels
adjacent to the injection well bore." Translation of these general
requirements into specific tests varies across States.
In addition to initial pressure testing prior to operation of
injection wells, States (including those that do not have primacy under
the UIC program) also require monitoring or mechanical integrity tests of
Class II injection wells at least once every 5 years. In lieu of such a
casing pressure test, the operator may, each month, monitor or record the
pressure in the casing/tubing annulus during actual injection and report
the pressure on a yearly basis.
%
To date, about 70 percent of all Class II injection wells have been
tested nationwide, though statistics vary across EPA Regions. Data on
these tests available at the Federal level are not highly detailed.
Although Federal legislation lists a number of specific monitoring
requirements (such as monitoring of injection pressures, volumes, and
nature of fluid being injected and 5-year tests for mechanical
integrity), technical information such as injection pressure and waste
characterization is not reported at the Federal level. (These data are
often kept at the State level.) Until recently, Federal data on
mechanical integrity tests listed only the number of wells passing and
failing within each State, without any explanation of the type of failure
or its environmental consequences.
For injection wells used to access underground hydrocarbon storage
and enhanced recovery, a well may be monitored on a field or project
basis rather than on an individual well basis by manifold monitoring,
provided the owner or operator demonstrates that manifold monitoring is
111-41
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comparable to individual well monitoring. Manifold monitoring may be
used in cases where facilities consist of more than one injection well
and operate with a common manifold. Separate monitoring systems for each
well are not required provided the owner or operator demonstrates that
manifold monitoring is comparable to individual well monitoring.
Under the Federal UIC program, all ground water with less than 10,000
mg/L total dissolved solids (IDS) is protected. Casing cemented to the
surface is one barrier against contamination of USDWs. State programs
vary in their requirements for casing and cementing. For example, Texas
requires surface casing in strata with less than 3,000 ppm IDS;
Louisiana, less than 1,500 ppm IDS; New Mexico, less than 5,000 ppm IDS.
However, all wells must be designed to protect USDWs through a
combination of surface casing, long string or intermediate casing,
cementing, and geologic conditions.
Proximlty to other welIs and_ to protected agoifers: When a new
injection well is drilled or an existing well is converted for injection,
the area surrounding the site must be inspected to determine whether
there are any wells of record that may be unplugged or inadequately
plugged or any active wells that were improperly completed. The radius
of concern includes that area within which underground pressures will be
increased. All States have adopted at least the minimum Federal
requirement of a one-quarter mile radius of review; however, the Agency
is concerned that problems may still arise in instances where
undocumented wells (such as dry holes) exist or where wells of record
cannot be located.
States typically request information on the permit application about
the proximity of the injection well to potable aquifers or to producing
wells, other injection wells, or abandoned oil- or gas-producing wells
111-42
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within a one-quarter mile radius. In Oklahoma, for instance, additional
restrictions are placed on U1C Class II wells within one-half mile of an
active or reserve municipal water supply well unless the applicant can
"prove by substantial evidence" that the injection well will not pollute
a municipal water supply.
Although these requirements exist, it is important to recognize the
following:
« Policy on review of nearby wells varies widely from State to
State, and the injection well operator has had only a limited
responsibility to identify possible channels of communication
between the injection zone and freshwater zones.
• Many injection operations predate current regulations on the
review of nearby wells and, because of "grandfather" clauses, are
exempt.
Operation and maintenance: Incentives for compliance with applicable
State or Federal UIC requirements will tend to vary according to whether.
a well is used for enhanced recovery or purely for waste disposal. Wells
used for both purposes may be converted production wells or wells
constructed specifically as Class II wells.
In order for enhanced recovery to be successful, it is essential for
operators to ensure that fluids are injected into a specific reservoir
and that pressures within the producing zone are maintained by avoiding
any communication between that zone and others. Operators therefore have
a strong economic incentive to be scrupulous in operating and maintaining
Class II wells used for enhanced recovery.
On the other hand, economic incentives for careful operation of
disposal wells may not be as strong. The purpose here is to dispose of
fluids. The nature of the receiving zone itself, although regulated by
State or Federal rules, is not of fundamental importance to the well
111-43
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operator as long as the receiving formation is able to accept injected
fluids. Wells used for disposal are often older, converted production
wells and may be subject to more frequent failures.
Evaporation and Percolation Pits
Description: Evaporation and percolation pits (see discussion above
under "Reserve Pits") are also used for produced water disposal. An
evaporation pit is defined as a surface impoundment that is lined by a
clay or synthetic liner. An evaporation/percolation pit is one that is
unlined.
Environmental performance: Evaporation of produced water can occur
only under suitable climatic conditions, which limits the potential use
of this practice to the more arid producing areas within the States.
Percolation of produced water into soil has been allowed more often in
areas where the ground water underlying the pit area is saline and is not
suitable for use as irrigation water, livestock water, or drinking
water. The use of evaporation and percolation pits has the potential to
degrade usable ground water through seepage of produced water
constituents into unconfined, freshwater aquifers underlying such
pits.10
Discharge of Produced Waters to Surface Water Bodies
Description: Discharge of produced water to surface water bodies is
generally done under the NPDES permit program. Under NPDES, discharges
are permitted for (I) coastal or tidally influenced water,
(2) agricultural and wildlife beneficial use, and (3) discharge of
produced water from stripper oil wells to surface streams. Discharge
under NPDES often occurs after the produced water is treated to control
This phenonienon >s docuieent&d in Chapter IV.
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pH and minimize a variety of common pollutants, such as oil and grease,
total dissolved solids, and sulfates. Typical treatment methods include
simple oil and grease separation followed by a series of settling and
skimming operations.
Environmental performance: Direct discharge of produced waters must
meet State or Federal permit standards. Although pollutants such as
total organic carbon are limited in these discharges, large volumes of
discharges containing low levels of such pollutants may be damaging to
aquatic communities.11
Other Production-Related Pits
Description: A wide variety of pits are used for ancillary storage
and management of produced waters and other production-related wastes.
These can include:12
1. Basic sediment pit: Pit used in conjunction with a tank battery
for storage of basic sediment removed from a production vessel or
from the bottom of an oil storage tank. (Also referred to as a
burn pit.)
2- Brine pit: Pit used for storage of brine used to displace
hydrocarbons from an underground hydrocarbon storage facility.
3. Collecting pit: Pit used for storage of produced water prior to
disposal at a tidal disposal facility, or pit used for storage of
produced water or other oil. and gas wastes prior to disposal at a
disposal well or fluid injection well. In some cases, one pit is
both a collecting pit and a skimming pit.
4, Completion/workover pit: Pit used for storage or disposal of
spent completion fluids, workover fluids, and drilling fluid;
silt; debris; water; brine; oil; scum; paraffin; or other
materials that have been cleaned out of the well bore of a well
being completed or worked over.
This phenomenon is documented in Chapter IV.
List adapted front Texas Railroad Connission Rule 8, amended March 5, 1984,
111-45
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5. Emergency produced water storage pit: Pit used for storage of
produced water for a limited period of time. Use of the pit is
necessitated by a temporary shutdown of a disposal well or fluid
injection well and/or associated equipment, by temporary overflow
of produced water storage tanks on a producing lease, or by a
producing well loading up with formation fluids such that the well
may die. Emergency produced water storage pits may sometimes be
referred to as emergency pits or blowdown pits.
6- Flare pit: Pit that contains a flare and that is used for
temporary storage of liquid hydrocarbons that are sent to the
flare during equipment malfunction but are not burned. A flare
pit is used in conjunction with a gasoline plant, natural gas
processing plant, pressure maintenance or repressurizing plant,
tank battery, or well.
1• Skimming pit: Pit used for skimming oil off produced water prior
to disposal of produced water at a tidal disposal facility,
disposal well, or fluid injection well.
8- Washout pit: Pit located at truck yard, tank yard, or disposal
facility for storage or disposal of oil and gas waste residue
washed out of trucks, mobile tanks, or skid-mounted tanks.13
The Wyoming Oil and Gas Conservation Commission would add pits
that retain fluids for disposal by evaporation such as pits used
for gas wells or pits used for dehydration facilities.
Environmental performance: All of these pits may cause adverse
environmental impact if their contents leach, if they are improperly
closed or abandoned, or if they are used for improper purposes. Although
they are necessary and useful parts of the production process, they are
subject to potential abuse. An example would be the use of an emergency
pit for disposal (through percolation or evaporation) of produced water.
Offsite Management Methods
Road or Land Applications
Description: Untreated produced water is sometimes disposed of by
application to roads as a deicing agent or for dust control.
The Alaska Department of Environmental Conservation questions whether pits described in
Items 1, 6, and 8 should be exempt under RCRA,
111-46
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E.ny.1.ronmental performance:_ Road or land application of produced
waters may cause contamination of ground water through leaching of
produced water constituents to unconfined freshwater aquifers. Many
States do not allow road or land application of produced waters.
Hell Plugging and Abandonment
There are an estimated 1,200,000 abandoned oil or gas wells in the
United States.
To avoid degradation of ground water and surface water, it is vital
that abandoned wells be properly plugged. Plugging involves the
placement of cement over portions of a wellbore to permanently block or
seal formations containing hydrocarbons or high-chloride waters (native
brines). Lack of plugging or improper plugging of a well may allow
native brines or injected wastes to migrate to freshwater aquifers or to
come to the surface through the wellbore. The potential for this is
highest where brines originate from a naturally pressurized formation
such as the Coleman Junction formation found in West Texas. Figure III-4
illustrates the potential for freshwater contamination created by
abandoned wells (Illinois EPA 1978).
Environmental Performance
Proper well plugging is essential for protection of ground water and
surface water in all oil and gas production areas.
111-47
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00
PRODUCED WATER-DISPOSAL
WELL
1
A
ABANDONED WELLS WATER
WITH NO WELL
CASING CASING 1
1 1 D
B C
WATER SUPPLY
WELL
1
E
°0 AQUIFER
- O O „ O C
0 WATER
CASING RUSTED,
FAILURE OR
ABSENCE OF
CEMENT
WELL NOT
PLUGGED OR
IMPROPERLY
PLUGGED
INTERVENING ROCKS
•—CONFINING ROCKS (LOW PERMEABILITY)
i§~?^
FUGITIVE BRINE
£aflife&*
PERMEABLE
INJECTION ZONE
CASING OUSTED; FAILURE OR
ABSENCE OF CEMENT
SOURCE: ILLINOIS EPA, ILLINOIS OIL FIELD BRINE DISPOSAL ASSESSMENT:
STAFF REPORT, NOVEMBER 1978.
NOTE: NOT TO SCALE
Figure MI-4 Pollution of a Fresh Water Aquifer Through Improperly
-------
REFERENCES
Canter, L. W. 1985. Drilling waste disposal: environmental problems
and issues. In Proceedings of a National Conference on Disposal of
Drill ing Wastes.
Canter, L.W., et al., 1984. Environmental implications of offsite
drilling mud pits in Oklahoma. Report submitted to Oklahoma
Corporation Commission, Oklahoma City, Oklahoma.
Cooper, R. V. 1985. Institutional management perspective of drilling
waste disposal. In Proceedings of a National Conference on Disposal
of Drilling Wastes.
Crabtree, A. F. 1985. Drilling mud and brine waste disposal in
Hichigan. Geological Survey Division of Michigan Department of
Natural Resources.
Davani et al. 1986. Organic compounds in soils and sediments from
unlined waste disposal pits for natural gas production and
processing. Water, Air and Soil Pollution. No. 27. 1986.
Deeley, G. M. 1986. Attenuation of chemicals within waste fresh
water drilling fluids. In Proceedings ofa National Conference on
Drill ing Huds.
Deeley, G. M., and Canter, L. W, 1985. Chemical speciation of metals
in nonstabilized and stabilized drilling muds. In Proceedings of a
National Conference on Disposal of Drilling Wastes.
Freeman, B. D., and Deuel, L. E. 1984. Guidelines for closing drilling
waste fluid pits in wetland and upland areas. 7th Annual Energy
Sources Technology Conference and Exhibition. New Orleans,
Louisiana.
Hanson et al. 1986. A Review of mud and cuttings disposal for
offshore and land based operations. In Proceedings of a National
Conference on Dri11inq Muds.
Illinois Environmental Protection Agency. 1978. Illinois oil field
brine disposal assessment: staff report.
Lloyd, D. A. 1985. Drilling waste disposal in Alberta. In
Proceedings of a National Conference on Drilling Muds.
McCaskill, C. 1985. Well annulus disposal of drilling waste. In
Proceedings p_f__a National Conference on Disposal of Drilling Wastes.
MoeCo Sump Treatment. 1984. Recommendations concerning the design and
rehabilitation of drilling fluid containment reserve pits.
111-49
-------
Musser, D. T. 1985. In-ptace solidification of oil field drilling
fluids. In Proceedings of a National Conference on Disposal of
Drill ing Wastes.
Rafferty, J. H. 1985. Recommended practices for the reduction of
drill site waste. In Proceedings ofa National Conference on
Disposal of Drilling Wastes. University of Oklahoma Environmental and
Ground Hater Institute.
Templeton, E. E., and Associates. 1980. Environmentally acceptable
disposalof salt brines produced with oil and gas. For the Ohio
Water Development Authority.
Tucker, B. B. 1985. Soil application of drilling wastes. In Proceedings
of a National Conference on Disposal of Drilling Wastes.
USEPA. 1979. U.S. Environmental Protection Agency. Cost of compliance,
proposed Underground Injection Control Program. A. D. Little, Inc.
. 1985. U.S. Environmental Protection Agency. Proceedings of the
Onshore Oil and Gas Workshop, Michigan Meeting Report, Ventura,
Calif.: VenVirotek Corporate Literature.
. 1986. U.S. Environmental Protection Agency. State/Federal Oil
and Gas WesternWorkshop. California.
Wascom, C. D. 1986. Oilfield pit regulations: a first for the
Louisiana oil and gas industry. In Proceedings of a Na t i o n a 1
Conference on Drilling Muds.
111-50
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CHAPTER IV
DAMAGE CASES
INTRODUCTION
Purpose of the Damage Case Review
The damage case study effort conducted for this report had two
principal objectives:
To Respond totheReguirements of Section 8002(mj[C]
The primary objective was to respond to the requirements of Section
8002{m) of RCRA, which require EPA to identify documented cases that
prove or have caused danger to human health and the environment from
surface runoff or leachate. In interpreting this passage, EPA has
emphasized the importance of strict documentation of cases by
establishing a test of proof (discussed below) that all cases were
required to pass before they could be included in this report. In
addition, EPA has emphasized development of recent cases that illustrate
damages created by current practices under current State regulations.
This has been complicated in some instances by recent revisions to
regulatory requirements in some States. The majority of cases presented
in this chapter (58 out of 61) occurred during the last 5 years.
Historical damages that occurred under prior engineering practices or
under previous regulatory regimes have been excluded unless such
historical damages illustrate health or environmental problems that the
Agency believes should be brought to the attention of Congress
now.1 The overall objective is to present documented cases that
show reasonably clear links of cause and effect between waste management
practices and resulting damages, and to identify cases where damages have
been most significant in terms of human health or environmental impacts.
The primary example of this is the problem of abandoned wells, discussed at length under
Miscellaneous Issues below. The abandoned well problem results for the most part from inadequate
past plugging practices. Although plugging practices have since been improved under State
regulations, associated damages to health and the environment are continuing.
-------
To Provide an Overview of the Nature of Damages Associated with Oil and
Gas Exploration, Development, or Production Activities
In the course of accumulating damage cases, EPA has acquired a
significant amount of information that has provided helpful insights into
the nature of damages.
Methodology for Gathering Damage Case Information
The methodology for identifying, collecting, and processing damage
cases was originally presented in draft form in the Technical Report
published on October 31, 1986. The methodology, which differs minimally
from the draft, is outlined below.
Information CategorJes
The damage case effort attempted to collect and record several
categories of information on each case. Initially, this information was
organized into a data base from which portions of cases were drawn for
use in the final report. Categories of information were as follows:
1. Characterization of specific damage types: For each case, the
environmental medium involved was determined (ground water,
surface water, or land), along with the type of incident and
characterization of damage. Only cases with documented damage
were included. Types of potential health or environmental damages
of interest are shown on Table IV-1.
2. The size and location of the site:_ Sites were located by nearest
town and by county. Where significant hydrogeological or other
pertinent factors are known, they were included; however, this
type of information has been difficult to gather for all cases.
3. The operating status ofthe facility or site: All pertinent
factors relating to the site's status (active, inactive, in
process of shutdown, etc.) have been noted.
IV-2
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Table IV-1 Types of Damage of Concern to This Study
1. Human Health Effects (acute and chronic): While there are some instances
where contamination has resulted in cases of acute adverse human health
effects, such cases are difficult to document. Levels of pollution exposure
caused by oil and gas operations are more likely to be in ranges associated
with chronic carcinogenic and noncarcinogenic effects.
2. Environmental Effects: Impairment of natural ecosystems and habitats,
including contaminating of soils, impairment of terrestrial or aquatic
vegetation, or reduction of the quality of surface waters.
3. Effects on Wildlife: Impairment to terrestrial or aquatic fauna; types of
damage may include reduction in species' presence or density, impairment
of species* health or reproductive ability, or significant changes in
ecological relationships among species.
4. Effects on Livestock: Morbidity or mortality of livestock, impairment in the
marketability of livestock, or any other adverse economic or health-based
impact on livestock.
5. Impairment of Other Natural Resources: 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.
IV-3
-------
4. Identification of the type and volume of waste Involved: While
the type of waste involved has been easy to define, volumes often
have not.
5, Jdentif.ication of_waste management practices: For each incident,
the waste management practices associated with the incident have
been presented.
6. Identification ofany pertinent regulations affecting the site:
State regulations in force across the oil- and gas-producing
States are discussed at length in Appendix A. Since it would be
unwieldy to attempt to discuss all pertinent regulations in
relation to each site, each documented case includes a section on
Compllance Issues that discusses significant regulatory issues
associated with each incident as reported by sources or
contacts.2 In some cases, interpretations were necessary,
7. Type of documentation available: All documentation available for
each case was included to the extent possible. For a few cases,
documentation is extensive.
For the purpose of this report, the data base was condensed and is
presented in Appendix C.
Sources and Contacts
No attempt was made to compile a complete census of current damage
cases. States from which cases were drawn are listed on Table IV-2. As
evident from the table, resources did not permit gathering of cases from
all States.
Within each of the States, every effort was made to contact all
available source categories listed in the Technical Report (see Table
IV-3). Because time was extremely limited, the effort relied principally
on information available through relevant State and local agencies and
All discussions have been reviewed by State officials and by any other sources or
contacts who provided information on a case.
IV-4
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Table IV-2 States From Which Case Information Was
Assembled
1. Alaska
2, Arkansas
3, CaHfomia
4. Colorado
5. Kansas
6, Louisiana
7, Michigan
8. New Mexico
9. Ohio
10. Oklahoma
11, Pennsylvania
12. Texas
13. West Virginia
14. Wyoming
IV-5
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Table IV-3 Sources of Information
Used in Developing Damage Cases
1. Relevant Statg,or Local Agencies:
including State environmental agencies;
oil and gas regulatory agencies; State,
regional, or local departments of health;
and other agencies potentially
knowledgeable about damages related to
oil and gas operations.
2. EPA Regional Offices
3. Bureau of Land Management
4. Forest Service
5. Geological Survey
6. Professional or trade associations
7. Public interest or citizens' groups
8. Attorneys engaged in litigation
IV-6
-------
on contacts provided through public interest or citizens' groups. In
some instances, cases were developed through contacts with private
attorneys directly engaged in litigation. Because these nongovernmental
sources often provided information on incidents of which State agencies
were unaware, such cases were sometimes undocumented at the State level.
State agencies were, however, provided with review drafts of case
write-ups. They, in turn, provided extensive additional information and
comments.
Case Study Development
Virtually all of the data used here were gathered through direct
contacts with agencies and individuals, or through followup to those
contacts, rather than through secondary references. For each State,
researchers first contacted all State agencies that play a significant
role in the regulation of oil or gas operations and set up appointments
for field visits. At the same time, contacts and appointments were made
where possible with local citizens' groups and private attorneys in each
State. Visits were made in the period between December 1986 and February
1987. During that time, researchers gathered actual documentation and
made as many additional contacts as possible.
Test of Proof
All cases were classified according to whether they met one or more
formal tests of proof, a classification that was to soie extent
judgmental. Three tests were used, and cases were considered to meet the
documentation standards of 8002(rn)(C) if they met one or more of them.
IV-7
-------
The tests were as follows:
1. Sc i ent1 fie i nyest1 gat ion: A case could meet documentation
standards if damages were found to exist as part of the findings
of a scientific study. Such studies could be extensive formal
investigations supporting litigation or a State enforcement
action, or they could, in some instances, be the results of
technical tests (such as monitoring of wells) if such tests
(a) were conducted with State-approved quality control procedures,
and (b) revealed contamination levels in excess of an applicable
State or Federal standard or guideline (such as a drinking water
standard or water quality criterion).
2. Administrative ruling: A case could meet documentation standards
if damages were found to exist through a formal administrative
finding, such as the conclusions of a site report by a field
investigator, or through existence of an enforcement action that
cited specific health or environmental damages.
3. Courtdecision: The third way in which a case could be accepted
was if damages were found to exist through the ruling of a court
or through an out-of-court settlement.
EPA considered the possibility of basing its damage case review
solely on cases that have been tried in court and for which damage
determinations have been made by jury or judicial decision. This
approach was rejected for a variety of reasons. First and most
important, EPA wanted wherever possible to base its damage case work on
scientific evidence and on evidence developed by States as part of their
own regulatory control programs. Since States are the most important
entity in controlling the environmental impacts of this industry, the
administrative damage determinations they make are of the utmost concern
to EPA. Second, comparatively few cases are litigated, and many
litigated cases, perhaps a majority, are settled out of court and their
records sealed through agreements between plaintiffs and defendants.
Third, as data collected for this report indicate, many litigated cases
are major cases in which the plaintiff may be a corporation or a
comparatively wealthy landowner with the resources necessary to develop
IV-8
-------
the detailed evidence necessary to successfully litigate a private suit
(see damage case LA 65 on pages IV-78 and IV-79). Private citizens
rarely bring cases to court because court cases are expensive to conduct,
and most of these cases are settled out of court.
Review by State Groups and Other Sources
All agencies, groups, and individuals who provided documentation or
who have jurisdiction over the sites in any specific State were sent
draft copies of the damage cases. Because of the tight schedule for
development of the report, there was limited time available for damage
case review. Their comments were incorporated to the extent possible;
EPA determined which comments should be included.
Limitations of the Hethodology and Its Results
Schedule for Collectionof Damage Case Informat ion
The time period over which the damage case study work occurred was
short, covering portions of three consecutive months. In addition, much
of the field research was arranged or conducted over the December
1986-January 1987 holiday period, when it was often difficult to make
contacts with State agency representatives or private groups. To the
extent that resources permitted, followup visits were made to fill gaps.
Nevertheless, coverage of some States had to be omitted entirely, and
coverage in others (particularly Oklahoma) was limited.
LimitedNumber of Oil- and Gas-Producing States in Analysis
Of the States originally intended to be covered as discussed in the
TechnicalReport, several were omitted from coverage; however, States
IV-9
-------
visited account for a significant percentage of U.S. oil and gas
production (see Table IV-2).
Pi ffi cyltyin Obtaininq a Representative Sampje
In general, case studies are used to gain familiarity with ranges of
issues involved in a particular study topic, not to provide a statistical
representation of damages. Therefore, although every attempt was made to
produce representative cases of damages associated with oil and gas
operations, this study does not assert that its cases are a statistically
representative record of damages in each State. Even if an attempt had
been made to create a statistically valid study set, such as by randomly
selecting drilling operations for review, it would have been difficult
for a number of practical reasons.
First, record keeping varies significantly among States. A few
States, such as Ohio, have unusually complete and up-to-date central
records of enforcement actions and complaints. More often, however,
enforcement records are incomplete and/or distributed throughout regional
offices within the State. Schedules were such that only a few offices,
usually only the State's central offices, were visited by researchers.
Furthermore, their ability to collect files at each office was limited by
the time available on site (usually 1 day, but never more than 3 days)
and by the ability of each State to spare staff time to assist in the
research. The number of cases found at each office and the amount of
material gathered were influenced strongly by these constraints.
Second, very often damage claims against oil and gas operators are
settled out of court, and information on known damage cases has often
been sealed through agreements between landowners and oil companies.
IV-10
-------
This is typical practice, for instance, in Texas. In some cases, even
the records of well-publicized damage incidents are almost entirely
unavailable for review. In addition to concealing the nature and size of
any settlement entered into between the parties, impoundment curtails
access to scientific and administrative documentation of the incident.
A third general limitation in locating damage cases is that oil and
gas activities in some parts of the country are in remote, sparsely
populated, and unstudied areas. In these areas, no significant
population is present to observe or suffer damages, and access to sites
is physically difficult. To systematically document previously
unreported damages associated with operations in more remote areas would
have required an extensive original research project far beyond the
resources available to this study.
Organization of This Presentation
As noted throughout this report, conditions affecting exploration,
development, and production of oil and gas vary extensively from State to.
State, and by regions within States. While it would be logical to
discuss damage cases on a State-by-State basis, the following discussion
is organized according to the zones defined for other purposes in this
project. Within each zone the report presents one or more categories of
damages that EPA has selected as fairly illustrative of practices and
conditions within that zone, focusing principally on cases of damage
associated with management of high-volume wastes (drilling fluids and
produced waters). Wherever possible, State-specific issues are discussed
as well.
IV-11
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At the end of this chapter are a number of miscellaneous categories
of damage cases that, although significant and well-documented, are
associated either with management of lower volume exempt wastes or with
types of damage not immediately related to management of wastes from
current field operations. Such categories include damages caused by
unplugged or improperly plugged abandoned wells.
NEW ENGLAND
The New England zone includes Maine, New Hampshire, Vermont,
Massachusetts, Rhode Island, and Connecticut. No significant oil and gas
are found in this zone, and no damage cases were collected.
APPALACHIA
%
The Appalachian zone includes Delaware, Kentucky, Maryland, New
Jersey, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West
Virginia. Many of these States have minimal oil and gas production.
Damage cases were collected from Ohio, West Virginia, and Pennsylvania.
Operations
Oil and gas production in the Appalachian Basin tends to be marginal,
and operations are often low-budget efforts. Funds for proper
maintenance of production sites may be limited. Although the absolute
amount of oil produced in the Appalachian zone is small in comparison
with the rest of the country, the produced water-to-product ratios are
typically very high and produced waters contain high concentrations of
chlorides.3
Da*sd Flannery, on behalf of various oil and gas trade organizations, states that "...in
absolute terns, the discharge of produced water from wells in the Appalachian states is snail."
IV-12
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In West Virginia in 1985, 1,839 new wells were completed at an
average depth of 4,270 feet. Only 18 exploratory wells were drilled in
that year. In Pennsylvania 4,627 new wells were completed in 1985 to an
average depth 2,287 feet; 59 exploratory wells were drilled in that
year. Activity in Ohio is developmental rather than exploratory, with
only 78 exploratory wells drilled in 1985 out of a total of 6,297 wells
completed. The average depth of a new well in 1985 was 3,760 feet.
Types of Operators
Oil and gas production in the Appalachian Basin is dominated by small
operators, some well-established, some new to the industry. Hajor
companies still hold leases in some areas. Since most extraction in this
zone is economically marginal, many operators are susceptible to market
fluctuations.
Major Issues
Contamination of Ground Water from Reserve Pits
Damage case incidents resulting from unlined reserve pits, with
subsequent migration of contaminants into ground water, are found in the
State of Ohio.
In 1982, drilling activities of an unnamed oil and gas company contaminated the well that
served a house and barn owned by a Mr Bean, who used the water for his dairy operations.
Analysis done on the water well by the Ohto Department of Agriculture found high levels of
barium, iron, sodium, and chlorides. (Bartyni is a cownon constituent of drilling mud.) Because
the barium content of the water «ell exceeded State standards, Mr. Bean was forced to shut down
his dairy operations. Milk, produced at the Bean farm following contawmation of the water well
contained 0.63 mg/L of barium. Concentrations of chlorides, barium, iron, sodium, and other
residues in the water well were above the U.S. EPA's Secondary Drinking Water Standards. Mr.
Sean drilled a new well, which also became contaminated. As of September 1984, Mr. Bean's water
IV-13
-------
well was still showing signs of contamination from the drilling-related wastes. It is not
known *heir,er Mr. Bear, was aole to recover financially from the disruption pf his dairy business.
(OH 49J"
This case is a violation of current Ohio regulations regarding
drilling mud and produced waters.
Illegal Disposal of Oil Field Wastes in Ohio
Illegal disposal of oil field wastes is a problem in Ohio, as
elsewhere, but the State is making an aggressive effort to increase
compliance with State waste disposal requirements and is trying to
maintain complete and up-to-date records. The State has recently banned
all saltwater disposal pits. A legislative initiative during the spring
of 1987 attempted to overturn the ban. The attempt was unsuccessful.
%
The Miller Sand and Gravel Co . thougn an active producer of sand and gravel, has also served
as an illegal disposal site for oil field wastes. An investigation by the Ohio Department of
Natural Resources (DNS) found that the sand and gravel pits and the surroundir.g swamp were
contaminated with oil and high-cnloride produced waters. Ohio inspectors noted
-------
Equity Oil & Gas Funds, Inc., operates Well fl on the Engle Lease, knox County. An Ohio DNR
official inspected the sue on April 5, 19c5 There were no saltwater storage tanks on site to
collect tne nign-chlonde produced water that was Being discharged from a plastic hose leading
from the tank battery into a culvert that, sn turn, emptied into a creek. The inspector took.
photos and Simples. Eotn produced water and ail and grease levels were of sufficient magnitude
to cause damage to flora and fauna, according to the notice of violation filed by the State.
The inspector noted that a large area of land along the culvert had been contaminated with oil
and produced water. The suspension order indicated that the "...violations present an inirunent
danger to puDl»c health and safety and are likely to result in tmnediate and sybstantial damage
to natural resources." The operator was required by the State to "...restore the disturbed land
surface and remove the oil from the stream in accordance with Section 1509.07Z of Ohio Revised
Statutes " (OH 07}6
This was an illegal discharge that violated Ohio regulations.
In another case:
Zenith Oil & Gas Co. operated Well *1 in Hopewell Township. The Ohio DNR issued a suspension
oroer to Zenith in March of 1984 after State inspectors discovered produced water discharges
onto tne surrounoing sue from a breech in a produced water pit and pipe leading from the pit.
A Notice of Violation had been issued in February 1984, but the violations were still »n effect
in March 1984. A State inspection of an adjacent site, also operated by Zenith Oil & Gas Co ,
discovered a plastic hose extending from one of the tank batteries discharging high-chloride
produced water into a breached pit and onto the site surface. Another tank, was discharging
produced water from an open valve directly onto the site surface. State inspectors also
expressed concern about lead and mercury contamination from the discharge. Lead levels in the
discharge were Z.S time's the accepted level for drinking water, and mercury levels were 925
limes the acceptable levels for drinking water, according to results filed for the State by a
private laboratory. The State issued a suspension order stating that the discharge was
"...causing contamination and pollution..." to the surface and subsurface soil, and in order to
remedy the problem the operator would have to restore the disturbed land. (Ohio no longer
allows the use of produced water disposal pits.) {OH 12)
This was an illegal discharge that violated Ohio regulations.
References for case cited: The Columbus Water and Chemical Testing Lab. lab reports.
Ohio Department of Natural Resources, Division of Oil and fias, Notice of Violation, 5/5/85.
References for case cited: Ohio Department of Natural Resources, Division of Oil and
Gas, Suspension Order »84-Q7, 3/22/84. Huskinguiti County Complaint form. Columbus Water and
Chemical lest ing Lab sampling report.
IV-15
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Contamination of Ground Water from Annular Disposal of Produced Water
Ohio allows annular disposal of produced waters. This practice is
not widely used elsewhere because of its potential for creating
ground-water contamination. Produced water containing high levels of
chlorides tends to corrode the single string of casing protecting ground
water from contamination during annular disposal. Such corrosion creates
holes in a well's casing that can allow migration of produced water into
ground water. Under the Federal UIC program, Ohio requires operators of
annular disposal wells to conduct radioactive tracer surveys to determine
whether produced water is being deposited in the correct formations.
Tracer surveys are more expensive than conventional mechanical integrity
tests for underground injection wells, and only 2 percent of all tracer
surveys were witnessed by DNR inspectors in 1985.
The Oonofrio well was a production oil well with an annular disposal hookup fed by a 100-bbl
produced water storage tank. In December 1975, shortly after completion of the well, tests
conducted by the Columbus Water and Chemical Tebting Lab on the Donofrio residential water well
showed chloride concentrations of 4,550 ppm. One month after the well contamination was
reported, several springs on the Oonofrio property showed contawmat ion from fugh-cnlor\Qe-
produced water ana oil, according to Ohio EPA inspections. On January 8. 1976, Ohio EPA
investigated the site and reported evidence of oil overflow from the Donofrro well production
facility, lack, of diking around storage tanks, and the presence of several produced water
Storage pits. In 19S6. 11 years after the first report of contatiination. a court ordtr was
issyed to disconnect the annular disposal lines and to plug the well. The casing recovered from
the well showed that its condition ranged from fair to very poor. The casing was covered with
w Q
rust and scale, and six holes were found, (OH 3bS
D
Comments in the Docket by David Flannery and American Petroleum Institute (API) pertain
to OH 38. Mr. flannery states that "...the water well involved in that case showed contamination
levels which predated the conraencement of annular disposal,..,*" EPA believes this statement refers
to bacteria) contatiinat ton of the me 11 discovered in 1974. (EPA notes that the damage case
discusses chloride contamination of the water well, not bacterial contamination )
9
References for case cited: Ohio Department of Natural Resources. Division of Oil and
Gas. interoffice conmumcat ion from M. Sharrock to S. Kell on the condition of the casing removed
from the Oonofrio well. Conwynication from Attorney General's Office, E.S. Post, discussing court
order to plug the Donofrio well. Perry County Common Pleas Court Case »19262. Letter from R.M.
Kimball, Assistant Attorney General, to Scott Hell, Ohio Department of Natural Resources, presenting
Case sumnary from 1974 to 1964. Ohio Department of Health lab sampling reports from 1976 to 1985,
Columbus Mater and Chemical Testing Lab, sampling reports from 12/1/75, 7/27/84, and 8/3/64.
IV-16
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This well could not pass the current criteria for mechanical
integrity under the UIC program.
An alternative to annular disposal of oil field waste is underground
injection in Class II wells, using tubing and packer, but these Class II
disposal wells are significantly more expensive than annular disposal
operations.
Illegal Disposal of Oil and Gas Waste in West Virginia
Environmental damage from illegal disposal of wastes associated with
drilling and production is by far the most common type of problem in West
Virginia, Results of illegal disposal include fish kills, vegetation
kills, and death of livestock from drinking polluted water. Fluids
illegally disposed of include oil, produced waters of up to 180,000 ppm
chlorides, drilling fluids, and fracturing fluids that can have a pH of
as low as 3.0 (highly acidic).
Illegal disposal in this State takes many forms, including draining
of saltwater holding tanks into streams, breaching of reserve pits into
streams, siphoning of pits into streams, or discharging of vacuum truck
contents into fields or streams.
Enforcement is difficult both because of limited availability of
State inspection and enforcement personnel and because of the remote
location of many drill sites (see Table VII-7), Many illegal disposal
incidents come to light through complaints from landowners or anonymous
informers.
IV-17
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Beginning in 157?. Allegheny Land and Hineral Company of West Virginia operated a gas
well, fA-226, on the property of Ray and Charlotte Willey. The well was located in a
corn field where cattle were fed in winter, and within 1.000 feet of the Uilley's
residence Tne well was also adjacent to a strear, known as the Eeverltn Fork. Allegheny
Land ano Mineral operated a-ciher gas well above the residence known as the fA-306. also
located on property owned b> the Willeys. Allegheny Land and Hineral maintained open
reserve pus and an open waste ditch, which ran into Beverlin Fork. The ditch servea to
dispose of produced water, oil, drip gas. detergents, fracturing fluuiSj and waste
production chemicals. Employees of the company told the Willeys that fluids in the pits
were safe for their livestock to drink.
The Willeys alleged that their cattle drank the fluid »n tne reserve pit and oecame
poisoned, causing abortions, birth defects, weight loss, contaminated milk, and death.
Hogs were also allegedly poisoned, resulting in infertility and pig still-births,
according to the complaint filed in the circuit court of Doddridge County, by the
Willeys. against Allegheny Land and Hineral. The Willeys claimed that the soil on the
fans was contaminated, causing a decrease in crop production and quality; that the ground
water of the farre was contaminated, polluting the water well from which the) dre» their
domestic water supply; and that the value of their real estate had been diminished as a
result of these damages. Laboratory tests of soil and water from the property confirmed
this contamination. The Willeys incurred laboratory expenses in having testing done on
livestock, soil, and water. A judgment filed in the circuit court of Doddridge County
was entered in I9&3 wherein the Wslleys were awarded a cash settlement in court for a
total of I3S.OCO plus interest and costs 10 (WV IB)11
This practice would violate current West Virginia regulations.
On February 23, 1983. Tom Ancona, a fur trapper, filed a complaint concerning a fish
kill on Stillwell Creek. A second complaint was also filed anonymously by an employee of
Marietta Royalty Co. Ancona, accompanied by a State fisheries biologist, followed a
trail consisting of dead fish, frogs, and salamanders yp to a dr-.11 sue operatec by
Marietta Royalty Co., according to the complaint filed with the West Virginia ONR. There
they founa a syphon hose draining the drilling waste pit into a tributary of Stillwell
Creek. Acid levels at the pit measured a pH of 4.0. enough to shock and kill aquatic
life, according to West Virginia District Fisheries Biologist Scott Morrison. Samples
and photographs were taken by the DNR. No. dead aquatic life was found afcove the satnple
West Virginia Department of Energy states that "...now the Division does not allow that
type of practice, and would not let a landowner subvert the reclamation law."
References for case cited: Complaint form filed in circuit court of Ooddridge County,
West Virginia, »81-c-I8, Judgment form filed in circuit court of Ooddndge County. West Virginia.
Water quality summary of Ray Willey farm. Letter from D, J. Horvath to Ray Uilley. Water analysis
done by Mountain State Environmental Service. Veterinary report on cattle and hogs of Willey farm.
Lab reports from National Veterinary Services Laboratories documenting abnormalities in Willey
livestock.
IV-18
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site. Marietta Royalty Co, was fined a total of $1,000 plus $30 m court
costs.12 fwv 20!13
This discharge was in direct violation of West Virginia regulations.
Illegal Disposal of Oil Field Waste in Pennsylvania
In Pennsylvania, disposing of oil and gas wastes into streams prior
to 1985 violated the State's general water quality criteria, but the
regulations were rarely enforced. In a study conducted by the U. S. Fish
and Wildlife Service, stream degradation was found in relation to chronic
discharges to streams from oil and gas operations:
The U.S. F isn and ysldlife Service conducted a survey of several streams in Pennsylvania from
1982-85 to determine the impact on aqyatic life over a period of years resulting from discharge
of oil field wastes to streams. The area studied has a history of chronic discharges of wastes
from oil and gas operations. The discharges were primarily of produced water from production
and enhanced recovery operations. The Streams studied were Miami Run, South Branch of Cole
Creek, Pantner Run, Foster Brook, lew»s Run, and Pi thole Creek. The study noted a decline
downstream front discharges in all fish populations and populations of frogs, salamanders, and
crayfish. fPA 02)14
These discharges of produced waters are presently allowed only under
the National Pollutant Discharge Elimination System (NPDES) permit system.
The West Virginia Department of Energy states that "This activity has now been regulated
under Hest Virginia's general permit for drilling fluids. Under that permit there would have been
no environmental damage."
References for case cited: Complaint Form 16/170/83, West Virginia Department of
Natural Resources, 2/25/63. Vest Virginia Department of Natural Resources Incident Reporting Sheet,
2/26/83. Sketches of Marietta drill site. Complaint for Suimons or yarrant, 3/28/83. Suutnons to
Appear, 3/18/83. Marietta Royalty Prosecution Report, West Virginia Department of Natural
Resources. Interoffice memorandum containing spill investigation details on Marietta Royalty
incident.
'4 References for case cued: U.S. Fish and Wildlife. Sunraary of Data from Five Streams in
Northwest Pennsylvania, 3/85. Background information on the streams selected for fish tissue
analysis, undated but after 10/23/85, Tables 1 through 3 on point source discharge samples
collected in the creeks included in this study, undated but after 10/30/84.
IV-19
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The long-term environmental impacts of chronic, widespread illegal
disposal include loss of aquatic life in surface streams and soil salt
levels above those tolerated by native vegetation. In 1985, Pennsylvania
established State standards concerning this type of discharge.
Discharges are now permitted under the NPDES system.
The northwestern area of Pennsylvania was officially designated as a
hazardous spill area (Clean Water Act, Section 311(k)> by the U.S.EPA in
1985 because of the large number of oily waste discharges that have
occurred there. Even though spills are accidental releases, and thus do
not constitute wastes routinely associated with the extraction of oil and
gas under the sense of the 3001 exemption, spills in this area of
Pennsylvania appear to represent deliberate, routine, and continuing
illegal disposal of waste oil.
Breaching of pits, opening of tank, battery valves, and improper oil
separation have resulted in an unusually high number of sites discharging
oil directly to streams. The issue was originally brought to the
attention of the State through a Federal investigation of the 500,000
acre Allegheny National Forest. That investigation discovered 500
separate spills. These discharges have affected stream quality, fish
population, and other related aquatic life.
The U.S. £PA declared a four-county area (including Mcktan, Warren, Venango, and Elk
counties) a major spill area in the summer of 1985. The area is the oldest commercial
oil-producing region in the world. Chronic low-level releases have occurred in the
region since earliest production and continue to this day. EPA and other agencies {e.g.,
U.S. Fish and Wildlife, Pennsylvania fish and Game. Coast Syardl were concerned that
continued discharge into the area's streams has alread> and will in the future have major
environmental impact. The area is dotted with thousands of marginal stripper wells
(producing a high ratio of produced water to oil), as well as thousands of abandoned
wells and pits. In the Allegheny Reservoir itself, divers spotted 20 of 81 known
improperly plugged or unplugged wells, 7 of which were leaking oily high-chloride
produced water into the reservoir and have since beers plugged. EPA is concerned that
iwny others are also leaking native oily produced water.
IV-20
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The Coast Guard (USC3) surveyed the forest for oil spills and produced water
discharges, identifying those of particular danger to be cleaned immediately, by
government if necessary. In the Allegheny Forest alone, USC6 identified over 500 sites
wnere oil was lea* ing frcm (.ells, pits, pipelines, or storage tanks In 59 cases, oil
was being oiscnarged airectly into streams, 21? sues showed evidence cf past discharges
and were on the verge of discharging again into the Allegheny Reservoir, Illegal
disposal of oil field wastes has had a detrimental effect on the environment: "...there
has been a lethal effect on trout Streams and damage to timber and habitat for deer, bear
and grouse." On Lewis Run, 5? discharge sues have been identified and the stream
supports little aquatic life. Almost all streams tn the Allegheny Forest nave suppressed
fisn population as a ". .direct result of pollution from oil and gas activity." (API
notes that oil and produced water leaks into streams are prohibited by State and Federal
regulations )15 (PA D9)io
These leaks are prohibited by State and Federal regulations.
However, discharges are allowed, by permit, under the NPDES program.
Damage to Water Wells from Oil or Gas Well Drilling and Fracturing
In West Virginia, the minimum distance established for separating oil
or gas wells from drinking water wells is 200 feet. Siting of oil or gas
drill sites near domestic water wells is not uncommon.17 West
Virginia has no automatic provision requiring drillers to replace water
wells lost in this way; owners must replace them at their own expense
toflwents in the docket by API pertain to PA 09. API states that "...litigation is
currently pending with respect to this case in which questions have been raised about the factual
basis for government action in this case,"
References for case cited- U.S. Geological Survey letter from Buckwalter to R>ce
concerning sampling of water in northern Pennsylvania, 10/27/86. Pennsylvania Department of
Environmental Resources press release on analysis of water samples, undated Dut after 8/63. Oil and
Water: When One of the By products of High-grade Oil Production is a low-grade Allegheny National
Forest, It's Time to Take a Hard Look at Our Priorities, by Jim Morrison, Pennsylvania Wildlife,
Vol. 8. No. 1. Pittsburgh Press, "Spoiling a Wilderness," 1/22/84; "Oil Leaking into Streams at 300
Sites in Northwestern Area of the State," 1985. Warren Times, "Slick Issues Underscore Oil Cleanup
in National Forest." 1986.
According to members of the Legal Aid Society of Charleston, West Virginia, landowners
have little control over where oil and gas wells are sited. Although a provision exists for
hearings to be held to question the siting of an oil or gas well, this process is rarely used by
private landowners for economic and other reasons.
IV-21
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or sue the driller. Where there is contamination of a freshwater source,
State regulations presume an oil or gas drilling site is responsible if
one is located within 1,000 feet of the water source.
During the fracturing process, fractures can be produced, allowing
migration of native brine, fracturing fluid, and hydrocarbons from the
oil or gas well to a nearby water well. When this happens, the water
well can be permanently damaged and a new well must be drilled or an
alternative source of drinking water found.
In 196Z, Miser Gas Co. drilled a gas well on the property of Mr. James Parsons, The well was
fractured using a typical fracturing fluid or gel. The residual fracturing fluid migrated into
Mr. Parson's water well (which was drilled to a depth of 416 feet), according to an analysts by
the West Virginia Environmental Health Services Lab of well wjter samples taken from the
property Darn, and 1ignt gelatinous material ^'t^-j' "•: Fluid) was found, along with white
fibers. {The gas well is located less than l.OOC feet f'om trie water well ) The chief of the
laooratory advised that the water well was contaminated and unfit for domestic use, and that an
alternative source of domestic water had to be found. Analysis showed the water to contain high
levels of fluoride, sodium, iron, and manganese. The water, according to DNR officials, had a
hydrocaroort odor, indicating tne presence of gas. To date Mr. Parsons has not resumed use of
the well as a domestic water source. (API states that this damage resulted from a malfunction
of the fracturing process If the fractures are not limited to the producing formation, the oil
and gas are lost from the reservoir and are unrecoverable.) {WV 17) "
tomnents in the Docket pertain to WV 17, by David Flannery and yest Virginia Department
of Energy, Mr. flannery states that "...this is an area where water problems have been known to
occur independent of oil and gas operations." EPA believes that the "problems" Mr. Flannery is
referring to are the natural high level of fluoride, alkalinity, sodium, and total dissolved solids
in the water. However, the constituents of concern found in this water well were the gelatinous
material associated with the fracturing process, and hydrocarbons, yest Virginia Department of
Energy states that the WVDOE "...had no knowledge that the Pittsburg sand was a fresh water
source." Also. WVDOE pointed out that WV Code 228-1-20 "...requires an operator to cement a string
of casing 30 feet below all fresh water zones." According to case study records, Kaiser Gas Co.
did install a cement string of casing 30 feet below the Ptttsburg sand, from which Hr. Parson drew
his water.
19
References for case cited: Three lab reports containing analysis of water well. Letter
from J. E. Rosencrance. Environmental Health Services Lab, to P. R. Merritt, Sanitarian, Jackson
County, West Virginia. Letter from P. R. Merritt to J, E. Rosencrance requesting analysis. Letter
from M. tf. Lewis. Office of Oil and Gas, to Janes Parsons stating State cannot help in recovering
expenses, and Mr. Parsons must file civil suit to recover damages. Hater well inspection report -
complaint. Sample report forms.
IV-22
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There were no violations of West Virginia regulations in this case,
Damage cases involving drilling activity in proximity to residential
areas are known to have occurred in Pennsylvania:
Civil su't was Drought by 14 families living in the village of Belmar against a
Headv 111e-based oil drilling company. Norwesco Development Corporation, in June 1966.
Norwesco had drilled more than 200 wells near Selmar, and residents of the village
claimed that the activity had contaminated the ground water from which they crew their
domestic water sypply Tne Pennsylvania Department sf Environmental Resources and tne
Pennsylvania Fish Commission cited Norwesco at least 19 times far violations of State
regulations. Norwesco claimed it was not responsible for contamination of the ground
water used by the village of Belmar. Norwesco suggested instead that the contamination
was frora old. Icng-afeartdoned wells. The Pennsylvania Department of Environmental
Resources IDES) agreed witn Eelraar residents that the contamination was from tne current
drilling operations Ground water in Belraar h.acs oeei pristine prior to the drilling
operation of" Norwesco. All families relying on the ground water lost tneir domestic
water supply The water from the contaminated wells would "...burn your eyes in the
shower, and your skin is so dry and itchy when you get out." Families had to buy bottled
water for armning and had to drive, in some cases, as far as 30 miles to Bathe. Hot
only were residents not atle to ariok or tathe using tne ground water; they could not use
the water for washing clothes or household items without causing permanent stains.
Plumbing fixtures were pitted by the high level of total dissolved solids and high
chloride levels.
In early 1565. DER ordered Norwesco to provide Belmar with an alternative water sypply
that was equal in quality and quantity to what the Belmar residents lost when their wells
were contaminated. In November 1986 Norwesco offered a cash settlement of $275,000 to
construct a fte» water system for the village and provided a temporary water supply. (PA
08)20
This case represents a violation of Pennsylvania regulations.
Problems with Landspreadinq in WestVirginia
Landspreading of drilling muds containing up to 25,000 ppm chlorides
was allowed in West Virginia until November 1, 1987. The new limit is
12,500 ppm chlorides. These concentrations of chlorides are considerably
References for case cited: Pittsburgh Press, "Franklin County Village Sees Hope after
Bad Water Ordeal," 12/7/86. Morning News. "Oil Drilling Firm Must Supply Water to Homes," 1/7/86,
"Village Residents Sue Drilling Company," 6/7/86.
IV-23
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higher than concentrations permitted for landspreading in other States
and are several times higher than native vegetation can tolerate.
Landspreading of these high-chloride muds may result in damage to arable
land. This waste drilling mud may kill surface vegetation where the mud
is directly applied; salts in the wastes can leach into surrounding soil,
affecting larger plants and trees. Leaching of chlorides into shallow
ground water is also a potential problem associated with this practice.
In early 1986 To*er Drilling land-applied the contents of a reserve pit 10 an area 100 feet by
150 feet. All vegetation died in the area where pit contents were directly applied, and three
trees adjacent to the land application area were dying allegedly because of the leacntng of h»gn
levels of chlorides into the soil. A complaint was made by a private citizen to the West
Virginia ONR. Samples taken by West Virginia DNR of the contaminated soil measured 18,000 ppm
chlorides Zl(yv 13}2?
Land applying reserve pit contents with more than 12,500 ppm
chlorides is now in violation of West Virginia regulations.
Problems with Enhanced Oil Recovery (EOR) and Abandoned Wells in Kentucky
The Martha Oil field, located in northeastern Kentucky, is situated
on the border of Lawrence and Johnson counties and occupies an area in
excess of 50 square miles. Oil production began in the early 1920s and
secondary recovery operations or waterflooding commenced in 1955.
Ashland Exploration, Inc., operated UlC-permitted injection wells in the
area. Approximately 8,500 barrels of fresh water were being injected per
day at an average pressure of 700 pounds per square inch.
Conwents in the Docket by David Mannery and API pertain to UV 13. The statements by
API and Mr. Flannery are identical. They state that u wight not be "...possible to determine
whether it was the chloride concentration alone wrnch caused the vegetation stress." Also, they
claim that the damage was short tern and "...full recovery of vegetation was nssde." Neither
commenter submitted supporting documentation.
22
References for case cited: West Virginia Department of Natural Resources complaint form
'6/131/86. Analytical report on soil analysis of kill area.
IV-24
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Several field investigations were conducted by the U.S. Environmental
Protection Agency, Region IV, to appraise the potential for and extent of
contamination of ground-water resources. Field inspections revealed
widespread contamination of underground sources of drinking water (USDWs).
From April 29 through May 8, 1986, representatives of the U.S. EPA, Region IV, conducted a
surface water investigation in the Blame Creek watershed near Martha, Kentucky. The study was
requested by the U S. EPA Water Management Division to provide additional baseline information
on streaa water Quality conditions in the Blame Creek area. Blame tree*, ana its tributaries
have been severely impacted by oil pred-tci ton activities conducted in me Martha field since the
early 1900s. The Water Management Division issued an aoroinistrative order requiring that
waterflooamg of the osl-bearing strata cease by February 4, 1985, and also requiring that
direct or indirect brine discharges to area streams cease by May 7, 1986.
For the stuay in 1966. 27 water chemistry sampling stations, 13 of which mere also biological
sampling stations, were estaol'srsec in the Blame Creek watershed Five streams m trie study-
area were considered control stations Biological sampling indicated that fwcroinvertebrates in
the limed late Martha oil field area were severely impacted. Many species were reduced or absent
at all stations within the oil field. Blame Creek stations downstream of the oil field,
although impacted, showed gradual improvement in the benthic macroinvertebrates. Control
stations exhibited the greatest diversity of benthic nacroinvertebrate species. Water chemistry
results for chlorides generally indicated elevated levels in the Martha o'l field drainage
area. Chloride values in the affected area of the oil field ranged from 440 to 5,900 nsg/l,
Control station cnloride values ranged from 3 to 42 mg/L.
In May of 1987, EPA, Region IV, conducted another surface water investigation of the Blame
Creek watershed The study was designed to document changes in water quality in the watershed
1 year following the cessation of 01! production activities in the Kartha oil field. By May of
1987, the major operator in the area. Ashland Exploration, Inc., had ceased operations. Some
independently owned production wells were still in service at this time. Chloride levels,
conductivity, and total dissolved solids levels had significantly decreased at study stations
within the Martha oil field. Marked improvements were observed in the benthic invertebrate
community structures at stations within the Martha field. New species that are considered
sensitive to water quality conditions were present in 1987 at most of the biological sampling
stations, indicating that significant water quality improvements had occurred following
cessation of oil production activities in the Martha field. Chloride levels in one stream in
the Blame Creek watershed decreased from 5,900 mg/L to 150
References for case cited; Martha Oil Field Water Quality Study, Martha. K-entucky, U.S.
EPA, Athens, Georgia, May 1986. Martha Oil Field Water Quality Study, Martha, Kentucky, U.S. EPA,
Athens, Georgia. May 1987.
IV-25
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In response to EPA's notice of violations and other requirements,
Ashland proposed to EPA that it would properly plug and abandon all
existing injection wells, oil production wells, and water-supply wells
and most gas production wells in the Martha field. EPA, Region IV,
issued to Ashland an Order on Consent With Administrative Civil Penalty
under the authority of Section 1423(9)(2) of the SDWA. Ashland has paid
an administrative penalty of $125,000 and will plug and abandon
approximately 1,433 wells in compliance with EPA standards. If
warranted, Ashland will provide alternative water supplies to private
water well users whose supplies have been adversely affected by oil
production activities.
SOUTHEAST
The Southeast zone includes North Carolina, South Carolina, and
Georgia. There is little oil and gas activity in this zone. No field
research was conducted to collect damage cases in this zone.
GULF
The Gulf zone includes Arkansas, Louisiana, Hississippi, Alabama, and
Florida. Attention in the damage case effort was focused on Arkansas and
Louisiana, the two major producers of the zone.
Operations
Operations in Arkansas are predominantly small to mid-sized
operations in mature production areas. A significant percentage of
IV-26
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production in this area comes from stripper wells, which produce large
volumes of associated produced water containing high levels of
chlorides. For Arkansas, most production occurs in the southern portion
of the State.
The average depth of a new well drilled in Arkansas in 1985 was 4,148
feet. That year 121 exploratory wells were drilled and 1,055 new wells
were completed.
Louisiana has two distinct production areas. The northern half of
the State is dominated by marginal stripper production from shallow wells
in mature fields. The southern half of Louisiana has experienced most
of the State's development activity in the last decade. There has been
heavy, capital-intensive development of the Gulf Coast area, where gas is
the principal product, yells tend to be of medium depth; operations are
typically located in or near coastal wetland areas on barge platforms or
small coastal islands. Operators dredge canals and estuaries to gain
access to sites.
In this area, reserve pits are constructed out of the materials found
on coastal islands, mainly from peat, which is highly permeable and
susceptible to damage after exposure to reserve pit fluids. Reserve pits
on barges are self-contained, but are allowed to be discharged in
particular areas if levels of certain constituents in wastes are below
specified limits. If certain constituents are found in concentrations
above these limits in the waste, they must be injected or stored in pits
(unlined) on coastal islands.
IV-27
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For many operators in the Gulf Coast area, produced water is
discharged directly to adjacent water bodies. Fields in this region have
an average water/oil ratio of from 4:1 to 6:1. The Louisiana Department
of Environmental Quality (DEQ) is now requiring that operators apply for
permits for these discharges. At this writing, the Louisiana DEQ had
received permit applications for approximately 750 to 800 discharge
points. Results of field work done by the Louisiana DEQ, the Louisiana
Geological Survey, and the Louisiana University Harine Consortium show
that roughly 1.8 to 2.0 million barrels of produced water are discharged
daily in this area. According to the Louisiana Geological Survey, many
receiving water bodies contain fresh water, with some receiving water
bodies 70 times fresher than the oil field discharges. The U.S. Fish and
Wildlife Service has stated that it will aggressively oppose any permits
for produced water discharges in the Louisiana wetlands of the Gulf Coast.
The average depth of a new well drilled in northern Louisiana in 1985
was 2,713 feet; along the Gulf Coast it was 10,150 feet. In the northern
part of the State, 244 exploratory wells were drilled and 4,033
production wells were completed. In the southern part of the State, 215
exploratory wells were drilled and 1,414 production wells were
completed.
Types of Operators
In Arkansas, operators are generally small to mid-sized independents,
including some established operators and others new to the industry.
Because production comes mostly from stripper wells, operators tend to be
vulnerable to market fluctuations.
Northern Louisiana's operators, like those in Arkansas, tend to be
small to mid-sized independents. They share the same economic
vulnerabilities with their neighbors in Arkansas. In addition, however,
IV-28
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Louisiana's more marginal operations may be particularly stressed by the
new Rule 29B, which requires the closing out and elimination of all
current and future onsite produced water disposal pits by 1989.
Estimated closing costs per pit are 520,000.
Operators in southern Louisiana tend to be major companies and large
independents. They are less susceptible to fluctuating market conditions
in the short term. Projects in the south tend to be larger than those in
the north and are located in more environmentally sensitive areas.
Major Issues
Ground-Water Contamination from Unlined Produced Water Disposal Pits and
Reserve Pits
Unlined produced water disposal pits have been used in Louisiana for
many years and are only now being phased out under Rule 29B. Past
practice has, however, resulted in damages to ground water and danger to
human health.
In 198Z, suit was brought on behalf of Dudley Romero et al. against operators of an oil
waste coaniercial disposal facility. PAB Oil Co, The plaintiffs stalea that their
domestic water wells were contaminated by wastes dumped into open pits >n the PAS Oil Co.
facility which were alleged to have migrated into the ground water, render»ng the water
wells unusable. Oil field wastes are dumped into the waste pits for skimming and
separation of oil. Trie pits are unlined. The PAB facility was operating prior to
Louisiana's first commercial oil field waste facility regylations. After promulgation of
new regulations, the facility continued to operate for 2 years in violation of the new
regulations, after which time the State shyt down the facility.
The plaintiff's water wells are downgradient of the facility, drilled to depths of 300
to 500 feet. Problems with water wells date from 1979. Extensive analysis was performed
by Soil Testing Engineers, Inc., and U.S. EPA, on the plaintiff's water wells adjacent to
the site to determine the probability of the well contamination coming from the PAB Oil
Co. site. There was also analysis on surface soil contamination. Soil Testing
IV-29
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Engineers, Inc., determined that it was possible for the wastes in the PAB Oil Co. pits
to reach and contaminate the Romeros' water wells. Surface sampling around the perimeter
of the PAB Oil Co. sue found high concentrations of metals. Resistivity testing showed
tfidt plumes cf chtorioe contamination in The water table lead front the pits to the water
wells. §0nngs tnjt Determined tne substrata fru«,eup sagaesteo that it wOulc be possible
for wastes to contaminate the Romero ground water witnin the time that the facility had
been in operation if the integrity of the clay cap in the pit had been lost (as by deep
excavation somewhere within it). The pit was 12 feet aeep and within range to percolate
into the water-bearing sandy soil.
The plaintiffs complained of sickness, nausea, and dizziness, and a less of cattle. The
case was settled out of cOiirt Tne plaintiffs received $140,000 from PAB Oil Co
(LA 67)?4
Unlined commercial disposal pits are now illegal in Louisiana.
The ground in this area is highly permeable, allowing pit contents to
leach into soil and ground water. Waste constituents potentially
leaching into ground water from unlined pits include arsenic, cadmium,
chromium, copper, lead, nickel, zinc, and chlorides. There have been
incidents illustrating the permeability of subsurface formations in this
area.25
Allowable Discharge of DrillingHud into Gulf Coast Estuaries
Under existing Louisiana regulations, drilling muds from onshore
operations may be discharged into estuaries of the Gulf of Mexico. The
State issues permits for this practice on a case-by-case basis. These
References for case cited- Soil Testing Engineers, Inc.. Brtne Study, Romero, et al..
Abbeville. Louisiana, 10/19/82, U.S. EPA lab analysis of pits and wells. 10/22/81. Dateline,
Louisiana: Fighting Chemical Dumping, by Jason Berry, May-Jyne, 1983,
?§
A gas well operated by Conoco, which had been plugged and abandoned, blew out below the
surface from December 11, 1985, to January 9, 1986. The blowout sent gas through fault zones and
permeable formations to the land surface owned by Claude H. Gooch. The gas could be ignited by a
match held to the ground. The gas was also determined to be a potential hazard to drinking water
wells in the intnediate area.
IV-30
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estuaries are often valuable commercial fishing grounds. Since the muds
can contain high levels of toxic metals, the possibility of
bioaccumulation of these metals in shellfish or finfish is of concern to
EPA-
In 19&4, the Glendale Drilling Co., under contract to Woods Petroleum, was drilling frow a
barge at the intersection of Taylor's 6a>ou and Cross Bayou. The operation was discharging drill
cuttings and mud into the aayou within 1,300 feet of an active oyster harvesting area and State
oyster seeding area. At the time of discharge, oyster harvests were in progress. {It is State
policy in Louisiana not to grant permits for the discharge of drill cuttings within 1,300 feet
of an active oyster harvesting area. The Louisiana Department of Environmental Quality does not
allow discharge of whole mud into estuaries.)
A State Hater Pollution Control Division inspector noted that there were two separate discharges
occurring from the barge and a 1o»> mound of mud was protruding from the surface of the water
beneath one of the discharges. Woods Petroleum had a letter from the Louisiana Department of
Environmental Quality authorizing them to discharge the drill cuttings and associated mud, but
this permit would presumably not have been issued tf it had been known that the drilling would
occur near an oyster harvesting area, while no damage was noted at time of inspection, there
was great concern expressed by the Louisiana Oyster Growers Association, the Louisiana
Department of Wildlife and Fisheries, Seafood Division, and some parts of the Department of
Water Pollution Control Division of the Department of Environmental Quality. The concern of
these groups stemmed from the possibility that the discharge of muds and cuttings with high
content of metals may have long-tern impact-on the adjacent cosjnwrcial oyster fields and the
State oyster seed fields in nearDy Jynop Bay. In such a situation, metals can precipitate frow
the discharge, settling in progressively higher concentrations m the bayou sediments where the
oysters mature. The bioaccumulation of these metals by the oysters can have an adverse impact
on trie oyster population and could also lead to human health problems if contaminated oysters
are consulted
The Department of Environmental Quality decided in this case to direct the oil company to stop
the discharge of drill cuttings and muds into the bayou. In this instance, the Department of
Environmental Quality ordered that a drill cutting barge be used to contain the remainder of the
on 11 cuttings. The company was not ordered to clean up the mound of drill cuttings that it
had already deposited in the bayou. (LA 20)
Activities in this case, though allowed by the State, are illegal
according to State law.
References for case cited: Louisiana Department of Environmental Quality, Water
Pollution Control Division, Office of Water Resources, internal memorandum, 6/3/85.
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Illegal Disposal of Oil Field Waste in the Louisiana Gulf Coast Area
The majority of damage cases collected in Louisiana involve illegal
disposal or inadequate facilities for containment of wastes generated by
operations on the Gulf Coast. For example:
Two Louisiana Water Pollution Control inspectors surveyed a swamp adjacent to a kEOCO
Oil Co, facility to assess flora damage recorded on a Notice of Violation issued to KEOCO
on 3/13/81. The Notice of Violation discussed produced water discharges into an adjacent
canal that emptied into a cypress swamp from a pipe protruding from the pit levee,
Analysis of a sample collected by a Mr. Martin, the complainant, who expressed concern
over the higr.-cnlonoe produced water discharge into the canal he ysed to obtain water
for his crawfish pond, showed salinity levels of 32,000 pom (seawater is 35.000 ppm).
On April 15. 1981, the Water Pollution Control inspectors made an effort to measure the
extent of damage to the trees in the cypress s*a.mp. After surveying the size of the
swamp, they randomly selected a cocipass bearing and surveyed a transect measuring 200
feet by 20 feet through the swamp. They counted and then classified all trees in the
area according to the degree of damage they had sustained. Inspectors found that "...an
approximate total area of 4,088 acres of swamp was severely damaged." Within the
randomly selected transect, they classified all trees according to the degree of damage.
Out of a total of 105 trees. 73 percent were dead, 18 percent were stressed, and 9
percent were normal The inspectors* report noted that although the transect ran through
a heavily damaged area, there were other areas much more severely impacted. Iney
therefore concluded, based upon data collected and firsthand observation, that the
percentages of damaged trees recorded "...are a representative, if not conservative,
estimate of damage over the entire affected area." In the opinion of the inspectors,
the discharge of produced water had been occurring for some tine, judging by the amount
of da«age sustained by the trees. f^lKQ was fined 19.500 by the State of Louisiana and
paid $4,500 in damages to the owner of the affected crawfish farm. (LA 45)
This discharge was in violation of Louisiana regulations.
References for case cited: Louisiana Department of Natural Resources, Water Pollution
Control Division, internal memo, Cormier and St. Pe to Givens, concerning damage evaluation of swamp
near the KEDCO Oil Co. facility 6/24/81. Notice of Violation, Water Pollution Control Log
#2-8-81-21.
1V-32
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Most of the damage cases collected involved small operations run by
independent companies. Some incidents, however, involved major oil
companies:
Sun 0)1 Co. operates a sue located in the Chaeahoula Field. A Department of
Resources inspector noted a site conf jgurat ion dying an inspection (6/25/6Z) of a tank battery
Surrounded by a pit levee and a ptt (30 yards by 50 yards). The pit was discharging produced
water into the adjacent swamp in two places, over a low part tn the levee and from a pipe that
had Seen put through the ring levee draining directly into the swamp. Produced water, oil, and
grease were being discharged into the snasrsp. Chloride concent rat sens front samples taken by the
inspectors ranged trow 2,948 to 4,848 ppm. and oil and grease concentrations measured 12,6 to
26.7 ppm. Tne inspector noted that the discharge into the swamp was the means by which the
company drains the tank battery ring levee area, A notice of violation was issued to Sun Oil by
?8
the Department of Natural Resources. (LA 15)
This discharge was in violation of Louisiana regulations.
Some documented cases noted damage to agricultural crops:
Dr. WiIma Subra documented damage to D.T, Caffery's sugar cane fields adjacent to a proauction
site, which included a saltwater disposal well, in St. Mary Parish., The operator was Sun Oil,
The documentation was collected between Jyly of 1985 and November of 1986 and included reports
of salt concentrations in soil at various locations in,the sugar cane fields, along with
descriptions of accompanying damage. Or, Subra noted that the sugar cane fields had various
areas that were barren and contained wnat appeared to be sludge. The production facility is
upgradient from the sugar cane fields, and Dr. Subra surmised that produced water was discharged
onto the soil surface from the facility and that a plume of salt contamination spread
downgradient. thereby affecting 1 3 acres of sugar cane fields, over a period of a year and a
half.
In July 198S, Dr. Subra noted that the cane field, though in bad condition, was predominantly
covered with sugar cane. There were, however, weeds or barren soil covering a portion of the
site. The patch of weeds and barren soil matched the area of highest salt concentration In the
area where the topography suggested that brine concentrations would be lowest, the sygar cane
appeared healthy. Subsequent field investigation and soil sampling conducted by Dr. Subra in
November of 1986 found the field to be nearly barren, with practically no sugar cane growing.
«JjQ
References for case cited; Louisiana Department of Natural Resources, Water Pollution
Control Division, internal tnero from Cormier to Givens, 8/16/82, concerning Sun Oil Co, brine
discharge, Chacahoula Field. Log IZ-8-81-122. tab analysis, 7/2/82,
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Or. Subra measured concentrations of salts in trie soil ranging from a low of 1,403 ppm to
35,?6S ppm at the edge of the field adjacent to the oil operation Sun has undertaken a
reclamation project TO restore the land. It is estimated that the project will take 2 to 3
years to complete. In tne interim. Sun Oil Co. will pay the sugar cane farmer for loss of
crops. (LA 63j
The State of Louisiana has not taken any enforcement action in this
case; it is unclear whether any State regulations were violated.
Host damage associated with illegal disposal involves disposal of
produced water containing high levels of chloride (brine). Illegal
disposal of other types of oil field waste also result in environmental
damage:
Cfievco-kengo Se~vtces, Inc. operates a centralized disposal facility near Abbeville,
Louisiana. Produced water and other wastes are transported from surrounding production fields
By vacuum truck to the facility. Complaints were filed by private citizens alleging that
discharges from the facility were damaging crops of rice and crawfish, and that the facility
represented a threat to the health of nearby residents. An inspection of the site by the Water
Pollution Control Division of the Department of Natural Resoyrces found that a truck washout pit
was emptying oil field wastes into a roadside ditch flowing into nearby coulees.
Civil suit was brought by private citizens against Chevco-^eogo Services, Inc., asking for a
total of $4 million in property damages, past and future crop loss, and exemplary damages. Lab
analysts performed by the Department of Natural Resources of waste samples indicated high metals
content of the wastes, especially in samples taken from the area near the facility and in the
adjacent rice fields, indicating that the discharge of wastes from the facility was the source
3] 3^
of damage to the surroynding land. The case is in litigation. JLA90)
The State did not issue a notice of violation in this case. However,
this type of discharge is illegal.
29
API states that an accidental release occurred in this case. EPA records show this
release lasted 2 years.
References for case cited: Documentation from Dr. yjlma Subra, including a series of
maps documenting changes in the sugar cane over a period of tine. 12/81. Maps showing location of
sampling and salt concentrations.
API states that these discharges were accidental.
"* 7
J References for case cited: Louisiana Department of Natural Resources, Water Pollution
Control Division, internal memo, lab analysis, and photographs, 8/25/83. Letter from West land Oil
Development Corp to Louisiana Department of Natural Resources, 4/15/83.
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Illegal Disposal of Oil Field Waste in Arkansas
The majority of damage cases found in Arkansas relate to illegal
dumping of produced water and oily waste from production units. Damages
typically include pollution of surface streams and contamination of soil
with high levels of chlorides and oil, documented or potential
contamination of ground water with elevated levels of chlorides, and
damage to vegetation (especially forest and timberland), from exposure to
high levels of chlorides.
An oil production unit operated Dy Mr. J. C. Langley was discharging oil and produced water in
"large quantities onto the property of Mr. Melvin Dunn and Mr. w. C Shaw The oil and produced
water discharge allegedly caused severe damage to the property, interfered with livestock on the
property, and delayed construction of a planned lake. Mr, Dunn had spoken repeatedly with a
company representative operating the facility concerning the oil and produced water discharge.
but no changes occurred in the operation of the facility. A complaint was made to Arkansas
Department of Pollution Control and Ecology {ADPCEJ. tne operator was informed of the situation.
and the facility was brought into compliance. Mr. Dunn then hired a private attorney in order
that remedial action be taken. It is not known whether the operator cleaned up the damaged
property ^ (AS O?)34
This discharge was in violation of Arkansas regulations.
On September 20, 1984, an anonymous complaint was filed with AOPCE concerning the discharge of
Oil and produced water in and near Swackover Creek, from production units operated by J S. Beebe
Oil Account. Upon investigation by ADPCE, U was found that saltwater was leaking from a salt
water disposal well located on the sue, Mr. Seebe wrote a letter stating his willingness to
correct the situation. On November 16, 1984, the site was again investigated by ADPCE, and it
was found that pits on location were being used as the primary disposal facility and were
API states that this incident constituted a spill and is therefore a non-RCRA issue.
References for case cited: Arkansas Department of Pollution Control and Ecology (ADPCE3
Complaint form, til 1721, 5/14/84. Letter from Michael Landers, attorney to Mr, Ounn, requesting
investigation from Mayne Thomas concerning Lang ley violations. Letter from J. C. Langley to Mayne
Thomas, AOPCE, denying responsibility for damages of Dynn and Shaw property. 6/5/84. Certified
letter from Wayne Thomas to J. C. Langley discussing violations of facility and required remedial
actions, 5/30/87, Map of violation area, 5/29/84. AOPCE oil field waste survey documenting
unreported oil spill on Langley unit, 5/25/84, Letter from Michael Landers, attorney to AOPCE,
discussing damage to property of Oynn and Shaw, 5/11/84.
IV-35
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overflowing and leaking into Smackover Creetc. The AOPCE issued a hotice of Violation (US
S4-06S) and noted tnat if
-------
Oil and saltwater damage to the area was documented in a study conducted by Hugh A. Johnson,
Ph.D., a professor of biology at Southern Arkansas University. His study mapped chlorine levels
around each well sue and calculated the affected area. The highest chloride level recorded in
the wetland was 9,000 ppm (native vegetation begins to be stressed from exposure to 250 ppm
chlorides). He found that significant areas around each well site had dead or stressed
vegetation related to excessive chloride exposure. The Game and Fish Commission fears that
continued discharges of produced water and oil in this area will threaten the last remaining
forest land in the Red River bottoms. (AR 04)
These discharges were in violation of State and Federal regulations.
Jurisdiction in the above case is unclear. Under a 1981 amendment to
the State Oil and Gas Act, OGC was granted formal permit authority over
oil and gas operations, but this authority is to be shared in certain
situations with the ADPCE. Jurisdiction is to be shared where Underground
Injection Control (U1C) wells are concerned, but is not clearly defined
with respect to construction or management of reserve pits or disposal of
drilling wastes. ADPCE has made attempts to clarify the situation by
issuing informal letters of authorization to operators,' but these are not
universally recognized throughout the State. (A full discussion of this
issue can be found in Chapter VII and in Appendix A.)
API states that the Arkansas Water and Air Pollution Act gives authority at several
levels to require cleanup of these illegal activities and to prevent further occurrences. EPA
believes that even though State and Feaeral Laws exist which prohibit this type of activity, no
mechanism for enforcement is in place.
References for case cited: Letter from Steve Forsythe, Department of the Interior
(D01), to Pat Stevens, Army Corps of Engineers (ACE), stating that activities of Mr. Roberson have
resulted in significant adverse environmental impacts and disruptions and that D01 recownends
remedial action be taken. Chloride Analysis of Soil and Water Samples of Selected Sites in Miller
County, Arkansas, by Hugh A. Johnson, Ph.D., 10/22/85. Letter to Pat Stevens, ACE, from Dick
Whittington, EPA, discussing damages caused by Jimmy Roberson in Sulphur River Wildlife Management
Area (SRWMA) and recommending remedial action and denial of new permit application. Oil and Gas
well drilling permits dated 1983 and 1985 for Roberson activities. A number of letters and
complaints addressing problems in SRWMA resulting from activities of James Roberson. Photographs.
Maps,
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Improperly Operated Injection Wells
Improper operation of injection wells raises the potential for
long-term damage to ground-water supplies, as the following case from
Arkansas illustrates.
3n Septewtae'" 19, 1964, *fr. Jawes Tnbble waoe a complaint to the Arkansas Department of
Pollution Control and Ecology concern ing salt water that was cottnng up out of tne ground in his
yard, killing his grass and threatening his water well. There are nsany oil wells in the area,
and water flooding is a cotrmon enhanced recovery method at these sues. Upon inspection of the
wells nearest to his residence, it was discovered that the operator, J. C. McLain. was injecting
salt water into an unperwntted well, The salt water was being injected into the casing, or,
annulus. not into tubing. Injection into the unsoynd casing allegedly allowed migration into
the freshwater zone. A produced water pit at the same site was near overflowing. State
inspectors later noted sn a followup inspection that the violations had been corrected. No fine
was levied. (AR 12) 3B
Operation of this well would now be in violation of UIC requirements.
MIDWEST
The Midwest zone includes the States of Hichigan, Iowa, Indiana,
Wisconsin, Illinois, and Missouri. Damage cases were collected in
Michigan.
Operations
Michigan produces both oil and gas from limestone reef formations at
sites scattered throughout the State at a depth of 4,000 to 6,000 feet.
**o
References for case cited"; ADPCE Complaint form, til 1790, 9/19/84. ADPCE inspection
report, 9/20/84. Letter from AOPCE to Mr, J. C. Mclain describing violations and required
corrective action, 9/21/84. ADPCE reinspection report. 10/11/84,
IV-38
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Oil and gas development is relatively new in this area, and most
production is primary (that is, as yet it involves no enhanced or
secondary recovery methods, such as water flooding). Exploration in
Michigan is possibly the most intense currently under way anywhere in the
country. The average depth of new wells drilled in 1985 was 4,799 feet.
In that year 863 wells were completed, of which 441 were exploration
wells.
Types of Operators
Operators in Michigan include everything from small independent
companies to the major oil companies.
Major Issues
Ground-Water Contaminationin Michigan
All the damage cases gathered in Michigan are based on case studies
written by the Michigan Geological Survey, which regulates oil and gas
operations in the State, All of these cases deal with ground water
contamination with chlorides. While the State has documented that
damages have occurred in all cases, sources of damages are not always
evident. Usually, several potential sources of contamination are listed
for each case, and the plume of contamination is defined by using
monitoring wells. Most of the cases involve disposal of produced waters.
In Jyne 1983. a water well owned by Mrs. Geneva 8ro«*« was tested after she had filed a
complaint to the Michigan Geological Syrvey. After responding, the Hichtgan Seological Survey
found a chloride concentration of 490 pom in the water. Subsequent sampling from the water well
of a neighbor, Mrs Dodder, showed that her well measured 760 ppm cnlortde in Aogyst. There are
a total of IS oil and gas wells in the area surrounding the contaminated water wells. Only five
of the wells are still producing, recovering a comb mat ion of oil and produced water. The
source of the pollution was evidently the H. E. Trope. Inc., crude oil separating facilities and
brine storage tanks located upgradient from the contaminated water wells. Monitoring wells were
installed to confirm the source of the contamination. Stiff diagrams were used to confirm the
similarity of the constituents of the formation brine and the chloride contamination of the
IV-39
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affected water wells. Sample results located two plumes of chloride contamination ranging in
concentration from 550 to 1,800 ppm that are traveling in a southeasterly direction downgradienl
from the proouceo water storage tanks and crude o»l separator facilities owned by M.E. Trope
{HI 05}39
Produced water spills from production facilities are covered by
Michigan regulations.
Ground-water contamination in the State has also been caused by
injection wells, as illustrated by the following case:
In April 198C, residents of Green R»oge Sutxhvision, located in Section 15, laketon Township.
Muskegon County, complained of bad-tasting water from their domestic water wells. Some wells
sampled by the local health department revealed elevated chloride concentrations. Because of the
proximity of the tjiketon Oil Field, an investigation was started by the Michigan Geological
Survey. Tne taketon Oil Field consists of dry holes, producing oil wells, and a produced water
disposal well, tne Hams Oil Corp. lappo *!. 0»1 wells prodyce a mixture of oil and produced
water. The produced water is separated and disposed of by gravity in the produced water disposal
well and is then placed back in the producing formation. After reviewing monitoring well and
electrical resistivity survey data, the Michigan Geological Survey concluded that the source of the
contamination was the Harris Oil Corp. Lappo •*] produced water disposal well, which was being
operated in violation of UlC regulations- (Ml 06)
This disposal well was being operated in violation of State
regulations.
Damage to ground water under a drill site can occur even where
operators take special precautions for drilling near residential areas.
An example follows:
39
References for case cued; Open file report, Michigan Department of Natural Resources,
Investigation of Salt-Contaminated Groundwater in Cat Creek Oil Field, Hersey Township, conducted by
D. W. Forstat, 1984. Appendix includes correspondence relating to investigation, area water well
drilling logs. Stiff diagrams and water analysis, site monitor well drilling logs, ano water sample
analysis for samples ysed in the invest\gat ion.
40
References for case cited: Open file report, Michigan Department of Natural Resources,
Investigation of Salt-Contaminated Groundwater in Sreen Ridge Subdivision, Laketon Township,
conducted by B. P. Shirey. 1930. Appendix includes correspondence relating to investigation, area
water well drilling lo§s. Stiff diagrams and water analysis, site monitor well drilling logs, and
water saaple analysis for samples used »n the investigation.
IV-40
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Drilling operations at the Burke Unit »! c=used the temporary ch1o<"»ae contamination of two
comes t ic water wells ana longer last »r»g enlonde contamination of « third well closer to the drill
site. Tne operation »as carried out in accorcance with State regulations and special site
restrictions required for uroan areas, using rig engines ecjuippea with mufflers, steel mud tanks
for containment of drilling wastes, lining for earthen pus that may contain salt water, and the
placement of a conductor casing to a depth of 120 feet to isolate the well from the freshwater zone
Beneath the rig.
The drilling location is underlain by permeable Surface sand, with bedrock at a depth of less
than 50 feet. Contamination of the ground water may rave occyrrec wf*e« material flushed fnw the
siyd tanns remained in the linea pit for 13 days before removal {T*1* material contained high
levels of cnlorides. and liners can leak.) According to the State report, this would have allowed
for sufficient time for contaminants to migrate into the freshwater aquifer. A leak from the
produced water storage tank was also reported by the operator to have occurred before the
contamination was detected in the water wells. One shallow well was less than 100 feet directly
east of the drill pit area and 100 to 150 feet southeast of the produced water leak site. Chloride
concentrations in this well measured by the Michigan Geological Survey were found to range from 750
(9/5/75! to 1.325 (5/33/753 ppm. By late August, two of the wells had returned to normal, while
the thiro well still measured 28 Times Us original background concentration of chloride. (MI
04 }41
In this case, damages resulted from practices that are not in violation
of State regulations.
PLAINS
The Plains zone includes North Dakota, South Dakota, Nebraska, and
Kansas. All of these States have oil and gas production, but for this
study, Kansas was the only State visited for damage case collection.
Discussion is limited to that State.
References for case cited: Open file report. Htchtgan Department of Natural Resources,
Report on Ground-Water Contamination. Sullivan and Company. J.D. Burke No. 1, Pennfield Township,
conducted by J, R. Byerlay, 1976. Appendix includes correspondence relating to investigation, area
water well drilling logs. Stiff diagrams and water analysis, site monitor well drilling logs, and
water sample analysis for samples used in the investigation.
IV-41
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Operations
Oil and gas production in Kansas encompasses a wide geographical area
and ranges from marginal oil production in the central and eastern portions
of the State to significant gas production in the western portion of the
State. Kansas is the home of one of the largest gas fields in the world,
the Giant Hugoton field. Other major areas of oil production in Kansas
include the Central Kansas Uplift area, better known as the "Kansas Oil
Patch," the El Dorado field in the east and south, and the Eastern Kansas
Shoestring sandstone area. The Eastern Kansas Shoestring sandstone
production area is composed mainly of marginal stripper operations. The
overall ratio of produced water to oil in Kansas is about 40:1, but the
ratio varies depending on economic conditions, which may force the higher
water-to-oil ratio wells (i.e., those in the Mississippian and Arbuckle
producing formations) to shut down.
The average depth of a new well drilled in Kansas in 1985 was 3,770
feet. In that year 6,025 new wells were completed. Of those, 1,694 were
exploratory.
Types of Operators
Operators in Kansas include the full range from majors to small
independents. The Hugoton area is dominated by majors and mid-sized to
large independents. Spotty oil production in the northern half of eastern
Kansas is dominated by small independent producers, and oil production is
densely developed in the southern half.
IV-42
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Hajor Issues
Poor Lease Maintenance
There are documented cases in Kansas of damage associated with
inadequate lease maintenance and illegal operation of pits. These cases
commonly result in contamination of soil and surface water with high levels
of chlorides as well as long-term chloride contamination of ground water.
Temple 0)1 Company and Wayside Production Company operated a number of oil production leases
in Montgomery County. The leases were operated with illegally maintained saltwater containment
ponds, improperly abandoned reserve pits, unapproved emergency saltwater pits, and improperly
abandonee) saltwater pus. Numerous oil and saltwater spalls were recorded during operation of
the sues Documental '.on of these incidents started in 197? when adjacent landowners began to
complain aboyt soil pollution, vegetation kills, fish kills, and pollution of freshwater streams
due to Oil and saltwater runoff from these sites. The leases also contain a large number of
4^
abandoned, unplugged wells, which may pose a threat to ground water, "" Complaints were
received by the Conservation Division, kansas Department of Health and the Environment (K.DHE),
Hontgosnery County Sheriff, and Kansas fish and Game Commission. A total of 39 violations on
these leases were documented beiweer, 1983 and 1984.
A sample tak.cn by ikDHE from a 4 1/2-foot test hole between a freshwater pond and a creek on'one
lease showed chloride concentrations of 65.500 ppm. Water samples taken from pus on other
leases showed chloride concentrations ranging from 5,000 to 82,000 ppm.
The Kansas Corporation Commission (kCC) issued an administrative order in 1984, fining letiple
and Uayside a total of $80.000. Initially. $25,000 was collected, and the operators could
reapply for licenses to operate in Kansas in 36 months if they initiated adequate corrective
measures. The case is currently in private litigation. The KCC found that no progress had
been made towards bringing the leases into compliance and, therefore, reassessed the outstanding
$55.000 penalty. The WX has since sought judical enforcement of that penalty in the District
Court, and a journal entry nas been signed and was reviewed by the K.CC and is now ready to be
filed sn District Court. Additionally, in'a separate lawsuit between the landowners, the
lessors, and the Temples regarding operation of the leases, the landowners were saccessful and
the leases have reverted back to the landowners. The new operators are prevented from operating
without KCC authority. (KS Ol)43
Ccsments in the Docket by the Kansas Corporation Cornnissian (Beatrice Stong) pertain to
KS 01. With regard to the abandoned wells, Kansas Corporation Ctsnaiss'on states that these wells
are "...cemented from top to bottom. ..**, they have "...limited resource energy..." and the static
fluid level these reservoirs could sustain are "...well below the location of any drinking or usable
water."
References for case cited: Trie Kansas Corporation Connnssion Court Order describing the
evidence ana charges against the Temple Oil Co.. 5/17/84.
IV-43
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This case represents habitual violation of Kansas regulations.
On January 31. !9d6, the Kansas Department of Health and the Environment (KOK£) inspected the
ReHz lease in Montgomery County, operated Dy Marvin Hirr of £1 Doraao, Arkansas. The lease
included an unpenmtted emergency pond containing water that had 56.500 ppn chlorides. A large
seeping area was observed by KDH£ inspectors on the soutn si* of tne pond, allowing the flow of
salt water down the slope for asoyt 30 feet. The company was notified and was asked to apply
for a permit and install a liner because the pond was constructed of sandy clay and sandstone.
The operator was directed to immediately empty the pond and backfill it if a liner was not
installed On February 24. the lease was reinspected oy KOHE and the emergency pond was still
foil and actively seeping. It appeared that the lease had been snyt down by the operator A
"pond oroer" was issued by >-Ph£ requiring the cowpany to drain and backfill tne pond. On April
29, the pond was still full and seeping.
Hater samples taken from the pit by K.OHE showed chloride concentrations of frosn 30,500 pp«
(4/29/fa&3 to 56.500 ppra J1/31/&6]. Seepage from the pit shotted chloride concentrations of I?.500
ppw (2/24/86) The Kansas Department of Health and the Environment stated that ". ..tne use of
the pond ..has caused or is likely to cause pollution to the soil and the waters of the State."
An adroinistrative penalty of J500 was assessed against the operator, and it was ordered that the
44
pond be drained and backfilled. (US 085
This activity is in violation of current Kansas regulations.
Such incidents are a recognized problem in Kansas. On May 13r 1987,
the Kansas Corporation (KCC) added new lease maintenance rules to their
oil and gas regulations. These new rules require permits for all pits,
drilling and producing, and require emptying of emergency pits within 48
hours. Spills must now be reported in 24 hours. The question of concern
is how stringently these rules can be enforced, in the light of the
evident reluctance of some operators to comply. (See Table VII-7.)
References for case cited: Kansas Department of Health and Environment Order assessing
civil penalty, in the matter of Marvin Harr, Case No. 86-E-77, 6/10/86. Pond Order issued by
Kansas Department of Health and Environment, in the matter of Marvin Harr, Case Mo. 86-PO-OOfl,
3/21/86.
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Unlined Reserve Pits
Problems with unlined reserve pits are illustrated in the following
cases.
Between February 9 and Z7, 1936, the Elliott il was drilled on the property of Mr. Laurence
keen ling. The hulchinson Salt meffiDer, an unoerground formation, was penetrated ounng the
drilling of Elliott il. The drilling process dissolved between 100 and 200 cubic feet of salt,
which was disposed of in the unlmed reserve pit. The reserve pit lies 200 feet away from a
•ell used by Mr. Koenltng for his ranching operations. Within a few weeks of the an limp of
the Elliott fl, Mr. koenling's nejrby well began to pump water containing a saltwater drilling
fluid.
Ground water on the koehling ranc^ has been contaminated with high levels of chlorides allegedly
because of leaching of the reserve pit fluids into the ground water. Water samples taken from
the koehling livestock water well by the KCC Conservation Division showed a chloricte
concentration of 1650 mg/L Background concentrations of chlorides were in the range of 100 to
150 ppm. It is stated in a kCC report, dated November 1986, that further movement of the
saltwater plume can be anticipated, thus polluting the koehling domestic water well and the
water well used by a farmstead over 1 mile downstream from trie koeh'iog ranch. It is also
stated in this kCC report that other wells drilled in the area ystng unlined reserve pits would
have similarly affected the grounowater,
The KCC now believes the source" of ground-water contamination is not the reserve pit from the
Elliott »1 The kCC has drilled two monitoring wells, one 10 feet frora the edge of the reserve
pit location ana the other within 400 feet of the affected water well. Between the affected well
and the reserve pit. The monitoring well drilled 10 feet from the reserve pit site tested 60
ppm chlorides, (EPA notes that it is not known if this monitoring well was located upgradient
frosi the reserve pit } The monitoring well drilled between the affected well and the reserve
pit testec ?50 ppm chlorides. (CPA notes that the level of chlor-des in this iwnitoring well is
more than twice the level of chlorines allowed under the EPA drinking water standards). The
case is still open, pending further investigation. EPA believes that the evidence presented to
date does not refute the earlier KCC report, which cited the reserve pit as the source of
ground-water contamination, since the recent K.CC report does not suggest an alternative source
of contain mat ton. (K.S OS!
Unpermitted reserve pits are in violation of current Kansas
regulations.
References for case cited: Sunuary Report, koehlmg Mater Well Pollution, ?Z-10-15W.
kCC, Conservation Division, Jim Schoof, Chief Engineer, 11/86.
IV-45
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Mr Leslie, a private lanoowner in Kansas, suspected that chloride contamination of a natural
spring occurred as a result of the presence of an abandoned reserve pit used when Western
Drilling Snc an lied a well (Leslie *1) at the Leslie Farm. Driving in this area required
penetration of the Hutch-rison Salt member, during which 200 to 400 cubic feet of rock salt was
dissolveo and disena»"§ed mtc the reserve pit. The ground in the area consists of faignly
unconsoltdated soils, which would allow for migration of pollutants into the ground water,
Water at the top of" the Leslie >l had a conductivity of 5,050 umnos Conductivity of trie spring
water equaled 7,250 unities. As noted ty the MIC, "very saline water" was coming out of the
springs Conductivity o* 2,000 mines will djmjge soil, precluding §rowtn of vegetation. No
fines were levied in this case as there were no violations of State ryles and regulations. Tne
Leslies filed suit in civil court and won their case for a total of $11,000 from the oil and gas
operator.46 (KS 03)47
Current Kansas regulations call for a site-by-site evaluation to
determine if liners for reserve pits are appropriate.
Problems with Injection Wells
Problems with injection wells can occur as a result of inadequate
maintenance, as illustrated by the following case.
On July 12, J981, the kansas Department of Health and the Environment (KDHEJ received a
complaint from Albert Richmeter. a landowner operating an irrigation well in the South Solomon
River valley, h'ts irrigation well had encountered salty water. An irrigation well belonging to
an adjacent landowner, I, M. Paxson, had become salty in the fall of 1980. Oil has been
produced in tne area since 1952. and since 1962 secondary recovery by water flooding has been
ysed. Upon investigation by tne HDH£, u was Discovered tftat the cause of the pollution was a
saltwater injection well nearby, operated by Petro-lewis. A casing profile caliper log was ryn
by an operator-contractor under the direction of kOh£ staff, which revealed numerous holes in
the casing of the injection well. The producing formation, the Kansas City-Lansing, requires as
much as 800 psi at the wellhead while injecting fluid to create a profitable enhanced oil
recovery project. To remediate tne contamination, tne alluvial aquifer was pumped, and the
initial chloride concentration of 1,000 mg/L was lowered to 600 to 700 mg/l tn a year's time.
Chloride contaminal ion in some areas was lowered from 10.0CO mg/L to near background levels.
However, a contamination problem continues in the Paxson well, which shows chlorides in the
range of 1,100 mg/L even though KDME, through pumping, has tried to reduce the
API states that KDMC had authority over pits at this time. The KCC now requires permits
for such pits.
Reference for case cited: Final Report, Gary Leslie Saltwater Pollution Problem,
kingman County, KCC Conservation Division, Jtm Schoof, Chief Engineer, 9/86. Contains letters,
memos, and analysis pertaining to the case.
IV-46
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concentration. After attempts at repair, Petro-Le«»)S deciaed to plua the injection
-ell 48 IKS 06}49
Operation of such a well would violate current Kansas and UIC
regulations,
TEXAS/OKLAHOMA
The Texas/Oklahoma zone includes these two States, both of which are
large producers of oil and gas. As of December 1986, Texas ranked as the
number one producer in the U.S. among all oil-producing States. Because
of scheduling constraints, research on this zone concentrated on Texas,
and most of the damage cases collected come from that State.
Operations
Oil and gas operations in Texas and Oklahoma began in the 1860s and
are among the most mature and extensively developed in the U.S. These
two States include virtually all types of operations, from large-scale
exploratory projects and enhanced recovery projects to marginal
small-scale stripper operations. In fact, the Texas/Oklahoma zone
includes most of the country's stripper well production. Because of
their maturity, many operations in the area generate significant
quantities of associated produced water.
48 torments in the Docket by the KCC [Bill Bryson) pertain to KS 06. KCC states that of
the affected irrigation nells. one is "...back »n service and the second is approaching near normal
levels as it continues to be pumped." API states that Kansas received primacy for the UIC program
in 1984.
References for case cited: Riefuneier Pollution Study, Kansas Department of Health and
Environment, 5. Blackburn and W. R. Bryson, 1983.
IV-47
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Development of oil and gas reserves remains active. In 1985, some
9,176 new wells were completed in Oklahoma, 385 of which were exploration
wells. In Texas in the same year, 25,721 wells were completed on shore,
3,973 of which were exploration wells. The average depth of wells in the
two areas is comparable: Oklahoma, 4,752 feet; Texas, 4,877 feet.
Because the scale and character of operations varies so widely, cases of
environmental damage from this zone are also varied and are not limited
to any particular type of operation.
Types of Operators
Hajor operators are the principal players in exploration and
development of deep frontiers and capital-intensive secondary and
tertiary recovery projects. As elsewhere, the major companies have the
best record of compliance with environmental requirements of all types;
they are least likely to cut corners on operations, tend to use
high-quality materials and methods when drilling, and are generally
responsible in handling well abandonment obligations.
Smaller independent operators in the zone are more susceptible to
fluctuating market conditions. They may lack sufficient capital to
purchase first-quality materials and employ best available operating
methods.
Major Issues
Discharge of ProducedWater and Drilling Muds into Bays andEstuaries of
the Texas Gulf Coast
Texas allows the discharge of produced water into tidally affected
IV-48
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estuaries and bays of the Gulf Coast from nearby onshore development.
Cases in which permitted discharges have created damage include:
In Texas, oil and gas producers operating near the Gulf Coast are permitted to discharge
produced water into surface streams if they are found to be tidal ly affected Along with the
produced water, residual product tan cnewicals and organic constituents may be discharged,
including lead, zinc, chromium, oarium, and water-soluble polyCycltc aromatic hydrocarbons
(PAHs). PAHs are known to accumulate in sediment, producing liver and lip tumors in catfish and
affecting mixed function oxidase systems of mairmals, rendering a reduced immune response. In
198-4, a study conducted by the U.S. Fisn and Wildlife Service of sed»went in Ta&b's Bay, which
receives discharged practiced water as well as discharges from upstream 'industry (i.e..
discharges from ships in the Houston Ship Channel}, indicates severe degradation of the
environment liy PAH contamination. Sediment was collected from within 100 yards of several tidal
discharge points of oil field produced water. Analytical results of these sediments indicated
severe degradation of the environment by PAH contamination. The study noted that sediments
contained no benihic fauna, and because of nave action, the contaminants were continuously
resu^pendto, allowing chronic exposure of contaminants to the water column. It is concluded fcy
the U.S. Fish and Wildlife Service that shrimp, crabs, oysters, fish, and fish-eating birds in
this location have the potential tc be neavily contaminated with PAHs. While these discharges
have to be within Texas Water Quality Standards, these standards are for conventional pollutants
and do not consider the water soluble components of oil that are in produced water such as
PAHs.50 (IX 55)51
NPDES permits have been applied for. but EPA has not issued permits for these discharges
on the Gulf Coast. The Texas Railroad Commission [TRC) issues permits for1these discharges The
TEC disagrees with the source of damage in this case.
References for case cited; Letter from U.S. Department of the Interior, Fish and
Wildlife Service, signed by H Dale Hall, to Railroad Commission of Texas, discussing degradation of
labb's Bay because of discharge of produced water in upstream estuaries, includes lab analysis for
polyCyclic aromatic hydrocarbons in Tabis's Bay sediment samples. Texas Railroad Commission Proposal
for Decision on Peiromllu Creek case documenting that something other than produced water is
killing aquatic organisms in the creek. (Roy Spears, Texas Parks and Wildlife, did LCSO study on
sunfish and sheepshead minnows using produced water and Aranssas Bay water. Produced water diluted
to proper salinity caused mortality of 50 percent. (Seawater contains 19.000 ppra chlorides.)
IV-49
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These discharges are not in violation of existing regulations.
Produced water d!scnarges contain a high ratio of calcium sons to magnesium ions. This high-
ratio of calcium to magnesium has been found b> Texas Parks and Wildlife officials to be lethal
to common Atlantic croaker, even when total salinity levels are within tolerable limits. In a
bioassay study conducted by Texas Parks and Wildlife, this fish was exposed to various ratios of
calcium to magnesium, ana it was foyfld that in 98-hour LCSQ studies, mortality was 50 percent
wberi exposed to calciura-magnesiyw ratios of 6:i. the natural ratio being 1:3. Nearly all of oil
field produced water aischarges on file with the Array Corps of Engineers in Galveston contain
ratios exceeding the 6:1 ratio, known to cause mortality in Atlantic croaker as established by
the LC50 test-52 (TX 31)53
These discharges are not in violation of current regulations.
Until very recently, the Texas Railroad Commission (TRC) allowed
discharge of produced water into Petronilla Creek, parts of which are 20
miles inland and not tidally affected.
For over 50 years, oil operators (including Texaco and Amoco) have been allowed to discharge
produced water into Petronilla Creek, a supposedly tidally influenced creek. Discharge areas
were as much as 20 miles inland and contained fresh water. In I&8I, the pollution of Petronilla
Creek frcra discliarge of produced water became an issue when studies done by the Texas Parks and
Wildlife and Texas Department of Water Resources documented the severe degradation of the water
and damage to native fish and vegetation. All freshwater species of fish and vegetation were
dead because of exposure to toxic constituents in discharge liquid. Portions of
the creek were black or bright orange in color. Heavy oil slicks and oily slime were
observatsle along discharge areas.
Impacts were ooserved ir- Baffin Bay, into which the creek empties. Petronslla Creek is the
only freshwater source for Baffin Bay, which is a nursery for many fish and shellfish in the
Gulf of Mexico. Sediments in Baffin Bay show elevated levels of toxic constituents found in
Petronilla Creek. For 5 years, the Texas Department of Water Resources and Texas Parks and
Wildlife, along with environmental groups,_worked to have the discharges stopped. In 1981. a
hearing was" held by the Texas Railroad Comaission (TRC). The conclusion of the hearing was that
discharge of the produced water plus disposal of other trash by the public was degrading
Petronilla Creek. The TRC initiated a joint comtnttee (Texas Department of Water Resources,
Texas Parks and Wildlife Department, and TRC) to establish the source of the trash, clean up
API comments in the Docket pertain to TX 31. API states that models show that "...rapid
mixing in Bay waters results in no pollution to Bay waters as a whole from calcium ions or from the
calcium-magnesium ratio."
References for case cited; Toxic Effects of Calcium on the Atlantic Croaker: An
Investigation of One Component of Oil field Brine, by Kenneth M. Knuason and Charles E. Belaire.
undated
IV-50
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trasn from the creek, and concoct additional studies After this work was completed, a second
hearing was held m 198-1. The creek *as shown to contain high levels of chromium, barium, oil,
grease, and EPA priority pollttants naphthalene and benzene. Oil operators stated that a no
dumping oraer would pui thern out of business because oil production in this area is marginal.
in 1966. tne TRC ordered a halt to discharge of produced water into norstidal portions of
Perron i I la Cree* (TX 2§)54
Although discharges are now prohibited in this creek, they are
allowed in other tidally affected areas.
Long-term environmental impacts associated with this type of
discharge are unknown, because of limited documentation and analysis.
Bioaccumulation of heavy metals in the food chain of estuaries could
potentially affect human health through consumption of crabs, clams, and
other foods harvested off the Texas Gulf Coast,
Alternatives to coastal discharge do exist. They include underground
injection of produced water and use of produced water tanks. While the
Texas Railroad Commission has not stopped the practice of coastal
discharge, it is currently evaluating the need to preclude this type of
discharge by collecting data from new applications, and it is seeking
delegation of the NPDES program under the Federal Clean Water Act. The
TRC currently asks applicants for tidal discharge permits to analyze the
produced water to be discharged for approximately 20 to 25 constituents.
References for case cited: The Effects of Brine Water Discharges on Petronilla Creek,
Texas Parks and Wildlife Department, 1981. Texas Department of Water Resources interoffice
memorandum documenting spills in Petronilla Creek from 1980 to 1983. The Influence of Oilfield
Brine Water Discharges on Chemical anc Biological Conditions in PetronUla Creek, by Frank Shipley,
Texas Department of Water Resources, 1984. Letter from Dick Whittingtcn. EPA, to Richard Lowerre.
documenting acsence of HPDES permits for discharge to Pet ton ilia Creek. Final Order of TRC, banning
discharge of produced water to Petronilla Creek, 6/23/86. Numerous letters, articles, legal
documents, on Petrontlla Creek case.
IV-51
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Leaching of Reserve Pit Constituents into Ground Water
Leaching of reserve pit constituents into ground water and soil is a
problem in the Texas/Oklahoma zone. Reserve pit liners are generally not
required in Texas and Oklahoma. When pits are constructed in permeable
soil without liners, a higher potential exists for migration of reserve
pit constituents into ground water and soil. Although pollutant
migration may not always occur during the active life of the reserve pit,
problems can occur after closure when dewatered drilling mud begins to
leach into the surrounding soil. Pollutants may include chlorides,
sodium, barium, chromium, and arsenic.
On November 20, 1981, the Michigan-Wisconsin Pipe Line Company began drilling an oil and gas
well on the property of Ralph and Judy Walker. Drilling was completed on March 27, 1982,
Unlined reserve pits were used at the drill site. After 2 months of drilling, the water well
used by the Walters became polluted with elevated levels of chloride and banym (683 ppsi and
1.750 ppb, respect>ve1y). The Walkers were forced to hay! fresh water from Elk City for
household use. The Walkers filed a complaint with the Oklahoma Corporation Comnission (OCC), and
an investigation »as conducted. The Michigan-Wisconsin Pipe Line Co. was ordered to remove all
drilling mud from the reserve pit.
In the end. the Walkers retained a private attorney and sued Michigan-Wisconsin for damages
sustained because of migration of reserve pit fluids into the freshwater aquifer from which they
drew their domestic water supply. The Walkers won their case and received an award of
ISO.000.55 (Ok OS}56
Constructing a reserve pit over a fractured shale, as in this case,
is a violation of OCC rules.
In 1973. Horizon Oil and Gas drilled an oil well on the property of Dorothy Moore. As was the
comnon practice, the reserve pit was dewatered. and the remaining mud was buried on site. In
1985-86, problems from the buried reserve pit waste began to appear. The reserve pit contents
API states that the Oklahoma Corporation Comnission is in the process of developing
regulations to prevent leaching of salt muds into ground water,
References for case cued: Pretnal Order, Ralph Gail Walker and Judy Walker vs.
Michigan-Wisconsin Pipe Line Company and Big Chief Drilling Company, U.S. District Court, Western
District of Oklahoma, »ClV-82-1726-R. Direct Examination of Stephen G. HcLin, Ph. D. Direct
Examination of Robert Hall Direct Examination of Laurence Alatshyler, M. D. Lab results from
Walker water well.
IV-52
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were seeping into a nearby creek and pond.. Tne Surrounding soil had very high chloride
content as established by Or. Billy Tucker, an agronomist and soil scientist. Extensive erosion
around trie reserve pit became evident, a conwon problem with high-sa' mity soil. Oil slicks
were visible in the adjacent creek and pond. An irrigation well on the property was tested by
Dr. Tucker and was found to have 3000 ppw chlorides; however, no monitoring wells had been
drilled to test the ground water prior to the drilling of the oil well, and background levels of
chlorides were not estaolished. Dorothy Moore has filed civil suit against tne operator for
damages sustained during the oil and gas drilling activity. The case is pending,
(Ok 02)58
Oklahoma performance standards prohibit leakage of reserve pits into
ground water.
Chloride Contamination of Ground Water from Operation of Injection Wells
The Texas/Oklahoma zone contains a large number of injection wells
used both for disposal of produced water and for enhanced or tertiary
recovery projects. This large number of injection wells increases the
potential for injection well casing leaks and the possibility of ground
water contamination.
Tne Oevore *J. a saltwater injection well located on the property of Verl and Virginia
Hentges, was drilled »n 1947 as an exploratory well. Shortly afterwards, it was permuted by
the Oklahoma Corporation Cotnnission (OCC) as a saltwater injection well. The injection
formation, the Layton, was known to be capable of accepting 80 barrels per hour at 150 psi. In
1984, George Sahn acquired the well and the OCC granted an exception to Rule 3-305, Operating
Requirements for Enhanced Recovery Injection and Disposal yells, and permitted the well to
inject 2,000 barrels per day at 400 psi. Later in 1984, it appeared that there was saltwater
tQ
migration from the intended injection zone of the Oevore #1 to the surface. The
Hentges alleged that the migrating salt water had polluted the ground water used or, their
ranch.
API contnents in the Docket pertain to OK. 02, API states that "...there is no evidence
that there has been any seepage whatsoever into syrface water." API states that there are no
irrigation wells on Mrs. Moore's farm. Further, it states that erosion has been occurring for years
and is the "...result of natural conditions coupled with the failure of Nrs. Moore to repair
terraces to prevent or limit such erosion." API has not provided supporting documentation.
rfl
References for case cited: Extensive soil and water analysis results collected and
interpreted by Dr. Billy Tucker, agronomist and soil scientist. Stillwater, Ok, la. Correspondence
and conversation with Randall Wood, private attorney, Stack and Barnes, Oklahoma City, Okla.
59 Contents by API in the Docket pertain to OK. 06. API states that "...tests on the well
pressure test and tracer logs indicate the injection well is not a source of salt water." API has
not provided documentation with this statement.
IV-53
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In addition, they alleged mat the migrating salt water was finding its way to the surface and
polluting Warren Creek, a freshwater stream used by downstream residents for domestic water.
Salt water discnarged to the surface had contaminated trie soil and had caused vegetation kills,
A report by the OCC concluded thai "...the Devore *i salt water disposal well operations are
responsible for the contaminant pluae in the adjacent alluvium and streams," The OCC required
that a »ornover be done en the well. The workover was completed, and the operator continues to
dispose of salt water in the well. The Hentges then sought private legal assistance and filed a
lawsuit against George Kahn, the operator, for $300,000 in actual damages and $3,000.000 in
punitive damages. The lawsuit is pending, scheduled for trial in October 1987,
{«. 06) 6!
Although at the time, the OCC permitted injection into the well at
pressures that may have polluted the ground water, Oklahoma prohibits any
contamination of drinking-water aquifers.
Illegal Disposal of Oil and Gas Wastes
Illegal disposal of oil and gas exploration and production wastes is
a common problem in the Texas/Oklahoma zone. Illegal disposal can take
many forms, including breaching of reserve pits, emptying of vacuum
trucks into fields and ditches, and draining of produced water onto the
land surface. Damage to surface soil, vegetation, and surface water may
result as illustrated by the examples below.
On May 16. 1364. Esenjay Petroleum Co. had completed the L.W. Bing *! well at a depth of 9,900
feet and had hired T&i Lease Service to dean up the drill site. During cleanup, the reserve
pit, containing high-chromium drilling ntud, was breached by T&L Lease Service, allowing drilling
mud to flow into a tributary of Hardy Sandy Creek. The drilling mud was up to 24 inches deep
along the north bank of Hardy Sandy. Drilling mud had been pushed into the trees and brush
adjacent to the drill site. The spill was reported to the operator and the Texas Railroad
Conmissson (IRC). The TRC ordered cleanup, which began on Hay 20.
API states that the operator now believes old abandoned saltwater pits to be the source
of contamination as the well now passes U!C tests.
References for ease cited; Remedial Action Plan for Aquifer Restoration within Section
92. Township 21 North, iange 2 West, Noble Coynty, Oklahoma, by Stephen 6. HcLin, Ph. D. Surface
Pollution at the De Vore #1 Saltwater Disposal Site, Oklahoma Corporation Connnssion, 1386.
District Court of Noble County, Amended Petition, Verl E. Hentges and Virginia L Hentges vs. George
kahn, »C-84-110. 7/25/85. Lab analysis records of De Vore well from Oklahoma Corporation Commission
and Southwell Labs. Communication with Alan DeVore. plaintiffs' attorney.
IV-54
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Because of h»gn levels of chromium contained in the drilling mud, warnings were issued by the
lavaca-Navioad River Authority 10 residents and lanooxners downstream of tfi^ spill as it
represented a possible Health hazara to cattle watering from the affected streams. The River
Authority also advised against eating the fish from trie affected waters Because of the high
chromium levels in the drilling mud. (TX 21)
This discharge was a violation of State and Federal regulations.
On September 15, 1983. TXO Production Company began drilling its Dunn Lease Well No. BZ in
Live Oak County. On October 5. 1983, employees of TxQ broKe the reserve pit levee and began
spreading drilling mud downhill from the sue, to«aros the fence line of property owned Dy the
Dunns. By October 9, the mud had entered the draw that flows into two stock, tanks on the Dunn
property. On November 24 and 25, dead fish were observed in the stock tank. On December 17,
Texas Parks and Wildlife documented over 700 fish killed in the stock tanks on the Dunn
property. Despite repeated requests Dy the Dunns. TXO did not clean up the drilling ntud and
polluted water from the Dunn property.
LaD results from TRC and Texas Department of Health indicated that the spilled drilling mud was
high in levels of arsenic, barium, chromium, lead, sulfates, other metals, and chlorides. In
February 1984, the TRC stated that the stock tanks contained unacceptable levels of nitrogen,
bariuss, chromium, and iron, and that the chewtcals present were detrimental to both fish and
livestock. {The Dunns water their cows at this same stock tank..) After further analysis, the
TRC issuea a memorandum stating that the fish had died because of a cold front moving through
the area, in spite of the fact that the soil, sediment, and water in and around the stock pond
contained harmful substances. Ultimately, TXO was fined $1,000 by the TfiC. and TXO paid the
Dunns a cash settlement for damages sustained [IX 22]
This activity was in violation of Texas regulations.
References for case cited: Memorandum from Lavaca-Navidad River Authority documenting
events of Esenjay reserve pit discharge, 6/27/84, signed by J. Henry Neason. Letter to TRC from
Lavaca-Xavidad River Authority thanking the TRC for taking action on the Esenjay case, "Thanks to
your enforcement actions, we are slowly educating the operators in this area on how to work within
the law.™ Agreed Order, Texas Railroad Commission. fZ-83,043. 11/12/84, fining Esenjay $10,000 for
deliberate discharge of drilling muds. Letter from U.S. EPA to TRC muting TRC to attend meeting
with Esenjay Petroleum to discuss discharge of reserve pit into Hardy Sandy Creek, 6/1/84, signed by
Thomas G. Giesberg. Texas Railroad Conwnssson spill report on Esenjay operations. 5/18/84,
API states that the fish died from oxygen depletion of the water. The Texas Railroad
Commission believes that the fish died from exposure to cold weather.
References for case cued: Texas Railroad Commission Motion to Expand Scope of Hearing,
»2-82.919, 6/29/84. Texas Railroad Ccareission Agreed Order, 12-82,919. 12/17/84. Analysis by Texas
Veterinary Medical Diagnostic Laboratory System on dead f»sh in Dunn stock tank. Water and soil
sample analysis from the Texas Railroad Corrmission. Water and soil samples from the Texas
Department of Health. Letter from Wendell Taylor, TRC, to Jerry Hullican, TRC, stating that the
fish kill was the result of cold weather, 7/13/84. Miscellaneous letters and memos.
IV-55
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NORTHERN MOUNTAIN
The Northern zone includes Idaho, Montana, and Wyoming. Idaho has no
commercial production of oil or gas. Montana has moderate oil and gas
production. Wyoming has substantial oil and gas production and accounts
for all the damage cases discussed in this section.
Operations
Significant volumes of both oil and gas are produced in Wyoming.
Activities range from small, marginal operations to major capital- and
energy-intensive projects. Oil production comes both from mature fields
producing high volumes of produced water and from newly discovered
fields, where oil/water ratios are still relatively low. Gas production
comes from mature fields as well as from very large new discoveries.
Although the average new well drilled in Wyoming in 1985 was about
7,150 feet, exploration in the State can be into strata as deep as 25,000
feet. In 1985, 1,332 new wells were completed in Wyoming, of which 541
were exploratory.
Types of Operators
Because of the capital-intensive nature of secondary and tertiary
recovery projects and large-scale drilling projects, many operations in
the State are conducted by the major oil companies. These companies are
likely to implement environmental controls properly during drilling and
completion and are generally responsible in carrying out their well
abandonment obligations. Independents also operate in Wyoming, producing
IV-56
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a significant amount of oil and gas in the State. Independent operators
may be more vulnerable to fluctuating market conditions and may be more
likely to maintain profitability at the expense of environmental
protection.
Hajor Issues
Illegal Disposal of Oil and Gas Wastes
Wyoming Department of Environmental Quality officials believe that
illegal disposal of wastes is the most pervasive environmental problem
associated with oil and gas operations in Wyoming. Enforcement of State
regulations is made difficult as resources are scarce and areas to be
patrolled are large and remote. (See Table VII-7.)
Altex Oil Company and its predecessors nave operated an oil production field for several
decades south of Rozet. Wyoming, {Altex purchased the property in 1984.) An access road runs
through the area, which, according to Wyoming Department of-£nvironmenta! Quality (WDEQ), for
years was used as a Drainage for produced water from the oil field operations,
In August of 1985, an official with WOEQ collected soil samples from the road ditch to ascertain
chloride levels because it had been observed that trees and vegetation along the road were dead
or dying. UDEO analysis of the samples showed chloride levels as high as 130,000 ppm. The road
was chained off m October of 1985 to preclude any further illegal disposal of produced
water.65 (UY 03)66
In early October 1985, Cities Service Oil Company had completed drilling at a site northeast
of Cheyenne on Highway 85. The drilling contractor, Z&S Oil Construction Company, was suspected
of illegally disposing of drilling fluids at a site over a mile away on the Pole Creek Ranch,
An employee of 2&S had given an anonymous lip to a County detective. A stake-oat of the
Comnents in the Docket from the Wyoming Oil and Sas Conservation Conrnission (WOGCC) (Mr.
Don Basko} pertain to WY 03. WOECC states that "...not all water frow Altex Oil producing wells...
caused the contamination problem," Further. tlOGCC states that "Illegal dumping, as well as a flow
line break the previous winter, had caused a high level of chloride in the soil which probably
contributed to the sagebrush and cottonwood trees dying."
References for case cited: Analysis of site by the Wyoming Department of Environmental
Quality (UDEQ). Quality Division laboratory, file »ej52I?9, 12/6/85, Photographs of dead and dying
cottonwood trees and sagebrush in and around site. Conversation with UOEQ officials.
IV-57
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illegal operation was mace with law enforcement and WDEQ personnel. Stake-out personnel took
samples and photos of the reserve pit and the dump site. During tne stake-out, vacyufn trucks
were witnessed draining reserve pit contents down a slope and into a small pond on the Pole
Creek Ranch, After sufficient evidence had been gathered, arrests were made by Wyoming law
enforcement personnel, ard the trucks were impounded- Tne State sued Z&S and won a tota! of
$10.000, SWY oi}°7
This activity was in violation of Wyoming regulations.
During the week of April 6, 1985, field personnel at the Byron/Garland field operated by
Harathon Oil Company were cleaning up a storage yard used to store drums of oil field
chemicals. Drums containing discarded production chemicals were punctured by the field
employees and allowed to dram into a ditch adjacent to the yard. Approximately 200 drums
containing 420 gallons of fluid were drained into the trencn, Tne chemicals were demulsiflers,
reverse demulsifiers, scale and corrosion inhibitors, and surfactants Broken transformers
containing PCBs were leaking into soil in a nearby area. Upon discovery of the condition of the
yard, Wyoming Department of Environmental Quality JWDEQ) ordered Marathon to begin cleanup
procedures. At tne request of the UD£Q. ground-water monitors were installed, and monitoring of
nearby Arnoldus Lake was begun. Ine State filed a civil suH against Marathon and won a 15000
fine and $3006 in expenses for 1ao work.6e (WY OS)"9
This activity was in direct violation of Wyoming regulations.
Reclamation Problems
Although Wyoming's mining industry has rules governing reclamation of
sites, no such rules exist covering oil and gas operations. As a result,
reclamation on privately owned land is often inadequate or entirely
lacking, according to WDEQ officials. By contrast, reclamation on
Federal lands is believed to be consistently more thorough, since Federal
References for case cited; WDEQ memorandum documenting chronology of events leading to
arrest of Z&S employees and owners. Lab analysis of reserve pit mud and effluent, and mud and
effluent found at dump site. Consent decree from District Court of first Judicial District, laranne
County, Wyoming, docket 1108-493, The People of the State of Vyomtng vs. Z&S Construction Company.
Photographs of vacyutn trucks dumping at Pole Creek Ranch.
CD
API states that the operator, thinking the drums had to be empty before transport
offslte, turned the drums upside down and drained 420 gallons of chemicals into the trench.
CQ
References for case cued: Stannary of Byron-Garland case by Marathon employee J. C.
Fowler. List of arums, contents, and field uses. Cross-section of disposal trench area. Several
sets of lab analyses. Map of Garland field disposal yard. Newspaper articles on incident.
District court consent decree, The People of the State of Wyoming vs. Harathon Oil Company,
1108-87.
IV-58
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leases specify reclamation procedures to be used on specific sites. WDEQ
officials state that this will be of growing concern as the State
continues to be opened up to oil and gas development.70
WDEQ officials have photographs and letters from concerned
landowners, regarding reclamation problems, but no developed cases. The
Wyoming Oil and Gas Conservation Commission submitted photographs
documenting comparable reclamation on both Federal and private lands.
The issue is at least partially related to drilling waste management,
since improper reclamation of sites often involves inadequate dewatering
of reserve pits before closure. As a result of this inadequate
dewatering, reserve pit constituents, usually chlorides, are alleged to
migrate up and out of the pit, making revegetation difficult. The
potential also exists for migration of reserve pit constituents into
ground water.
Discharge of Produced Water into Surface Streams
Because much of the produced water in Wyoming is relatively low in
chlorides, several operations under the beneficial use provision of the
Federal NPDES permit program are allowed to discharge produced water
directly into dry stream beds or live streams. The practice of chronic
discharge of low-level pollutants may be harmful to aquatic communities
in these streams, since residual hydrocarbons contained in produced water
appear to suppress species diversity in live streams.
A study was undertaken by the Colombia National Fisheries Research Laboratory of the U. S.
Fish and Wildlife Service to oeterwine the effect of continuous Discharge of low-level oil
effluent into a stream and tne resulting effect on the aquatic community in the stream. The
discharges to the stream contained 5.6 mg/L total hydrocarbons. Total hydrocarbons in the
receiving sediment were 979 mg/L to 2.515 mg/L. During the study, samples were taken upstream
70 WOGCC disagrees with WDEQ on this statement
IV-59
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and downstream from trie discharge. Species diversity and community structure were studied.
Water analysis was done on upstream and downstream samples Ine study found a decrease in
species diversity of the macrcbenthos cosmunity (fish) oowfistrear. from the discharge, further
cnaracter:zea By total elimination of sosne specses and drastic alteration cf cc*inyn»ty
structure- The study fat.no that the downstrearn cocitsafiity was cnaracterized S> only one dominant
species, wnile the upstream community was dominated by three species. Total hydrocarbon
concentrations in water and sediment increased 40 to 55 fold downstream from the discharge of
produced water. The authors of the study stated tnat "...based on our findings, the fisheries
and aqyatic resources wojld &e protected if discharge of oil into fresh water were regulated to
present concentrations in receiving streams wjter and sediment that would alter structure of
macro&entr.os conniunit IBS." (WY 07]
These discharges are permitted under NPDES.
SOUTHERN MOUNTAIN
The Southern Mountain zone includes the States of Nevada, Utah,
Arizona, Colorado, and New Mexico. All five States have some oil and gas
production, but New Mexico's is the most significant. The discussion
below is limited to New Mexico.
Operations
Although hydrocarbon production is scattered throughout New Mexico,
most comes from two distinct areas within the State: the Permian Basin in
the southeast corner and the San Juan Basin in the northwest corner.
Permian Basin production is primarily oil, and it is derived from
several major fields. Numerous large capital- and energy-intensive
enhanced recovery projects within the basin make extensive use of CO^
flooding. The area also contains some small fields in which production
References for case cited: Petroleum Hydrocarbon Concentrations in a Salrnonid Stream
Contaminated by Oil Field Discharge Water and Effects on the Macrobenthos Community, by D,F.
Woodward and R.G. Riley, U.S. Department of the Interior, Fish and Wildlife Service, Columbia
National Fisheries Research Laboratory, Jackson, Wyoming, 19SO; submitted to Transactions of the
Fisheries Society.
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is derived from marginal stripper operations. This is a mature
production area that is unlikely to see extensive exploration in the
future. The Tucumcari Basin to the north of the Permian may, however,
experience extensive future exploration if economic conditions are
favorable.
The San Juan Basin is, for the most part, a large, mature field that
produces primarily gas. Significant gas finds are still made, including
many on Indian Reservation lands. As Indian lands are gradually opened
to oil and gas development, exploration and development of the basin as a
whole will continue and possibly increase.
Much of the State has yet to be explored for oil and gas. The
average depth of new wells drilled in 1985 was 6,026 feet. The number
of new wells drilled in 1985 was 1,734, of which 281 were exploratory.
Types of Operators
The capital"- and energy-intensive enhanced recovery projects in the
Permian Basin, as well as the exploratory activities under way around the
State, are conducted by the major oil companies. Overall, however, the
most numerous operators are small and medium-sized independents. Small
independents dominate marginal stripper production in the Permian Basin.
Production in the San Juan Basin is dominated by midsize independent
operators.
Hajor Issues
Produced Water Pit and Oil FieldWastePit Contents leaching into Ground
Water
New Mexico, unlike most other States, still permits the use of
unlined pits for disposal of produced water. This practice has the
potential for contamination of ground water.
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In July 1985. a study was undertaken in the Duncan Oil Field in the San Juan Basin by faculty
meai&ers in the Department of Chemistry at New Hexicc State University, to analyze the potential
for ynlined produced water pn contents, including hydrocarbons and aromatic hydrocarbons, to
migrate into the ground water The oil field is situated in a flood plain of the San Juan
River. Tne site chosen for investigation by the study group was similar to at least 1,500 other
nearoy production sues in the flood plain. The study group Dug test pits around the disposal
pit on the cnosen site. These test pits »ere placed atovegradtem and do«»n§radtent of the
disposal pit, at ZS- and 50-meter intervals A total of 9 test pits were dug to a depth of Z
meters, and soil and ground-water samples were obtained from each test pit. Upon analysis, the
study group found volatile aromatic hydrocarbons were present in both the soil and water samples
of test pits downgraoient, demonstrating migration of unlined produced water pit contents into
the ground water.
Environmental impact was summarized Dy the study group as contamination of shallow ground water
with produced water pit contents due to leaching from an unlmed produced water disposal pit.
Benzene was found in concentrations of 0.10 ppb. New Mexico Water Quality Control Commission
standard is 10 ppb Concentrations of ethyIbenzene, xylenes, and larger hydrocarbon molecules
were found. NO contamination was found in test pits placed a&ovegraoient fro™ the disposal
pit. Physical signs of contamination were also present, downgradient from the disposal pit,
including black, oily staining of sands above the water table and black, oily film on the water
itself. Hydrocarbon odor was also present (NM 02}
It is now illegal to dispose of more than five barrels per day of
produced water into unlined pits in this part of New Mexico.
As a result of this study, the use of unlined produced water pits was
limited by the State to wells producing no more than five barrels per day
of produced water. While this is a more stringent requirement than the
previous rule, the potential for contamination of ground water with
hydrocarbons and chlorides still exists. It is estimated by individuals
familiar with the industry in the State that 20,000 unlined emergency
72
References for case cited: Hydrocarbons and Aromatic Hydrocarbons in Groundwater
Surrounding an Earthen Waste Disposal Pit for Produced Water in the Duncan Oil Field of New Hexico,
by G.A. Eicenan, J.T. McConnon, Masud Zarnan, Chris Shuey, and Douglas Earp, 9/16/85. Polycyclic
Aromatic Hydrocarbons in Soil at Groundwater Level Near an Earthen Pit for Produced Water in the
Duncan Oil Field, by B. Davani, K. Lindley, and G.A. Eiceman, 1986. New Mexico Oil Conservation
Coiramssion hearing to define vulnerable aquifers, comments on the hearing record by Intervenor Chris
Shuey, Case Ho. 8224.
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produced water disposal pits are still in existence in the San Juan Basin
area of New Mexico.7j
New Mexico has experienced problems that may be due to centralized
oil field waste disposal facilities:
Lee Acres "isodified" landfill {mean-ing refuse »s covered weekly instead of daily as is done in
a "sanitary" lanafilT) is located 4.5 miles E-SE of fanrtington. New Mexico, It is owned by the
U.S. Bureau of Lana Management (BLM). The landfill is approximately 60 acres sn size and
includes four unlined liquid-waste lagoons or pits, three of which were actively used. Since
1981, a variety of liquid wastes associated with the oil and gas industry have been disposed of
in the lagoans. The predominant portion of liquid wastes disposed of in the lagoons was
produced water, which is known to contain aromatic volatile organic compounds (VDCsJ. According
to the New Mexico Department of health and Environment, Environmental Improvement Division, 75
to 90 percent of the produced water disposed of in the lagoons originated from Federal and
Indian oil and gas "leases managed b> BLM Water produced on these leases was hauled from as far
away as Nageezi. which is 40 miles from the Lee Acres site. Disposal of produced water in these
unltned pus was, according to New Mexico State officials, in direct violation of BlM's ryle
NlL-ZB, which promtnts, without prior approval, disposal cf produced waters into unlined pits,
originating on Federally owned leases. The Department of the Interior states that disposal m
the lagoons was "...specifically authorized by the State of New Mexico for disposal of produced
water " the State of New Mexico states that "There is no truth whatsoever to the assertion that
the landfill lagoons were specifically authorized by the State of New Mexico for disposal of
proouced water " Use of the pus ceased on 4/19/85;- 8,800 cubic yards of waste were disposed of
prior to closure,
New Mexico's Environmental Improvement Division (NMEJD) asserts that leachate from the unlined
waste lagoons that contain oil and gas wastes has contributed to the contamination of several
water wells in the iee Acres housing sybdivisien located downgradtent from the lagoons and down-
gradient from a refinery operated by Giant, located nearby. NM£!D has on file a soil gas survey
that documents extensive contamination with chlorinated VQCs at the landfill site. High levels
of sodium, chlorides, lead, chromium, benzene, toluene, xylenes. chloroethane, and
trichloroethylene were found in the waste lagoons. An electromagnetic terrain survey of the Lee
Acres landfill site and surrounding area, conducted by NME1D, located a plume of contaminated
ground water extending from the landfill This ply*e runs into a plane of contannnation known to
exist, emanating fros the refinery. The plumes have become mixed and are the soyrce of
Governor Carruthers refutes this and states that "Unltned pits tn fresh water areas in
Southeast New Mexico were banned beginning in 1955. with a general prohibition adopted in 1967."
EPA notes that New Mexico still permits unlined pits to be used for disposal of produced water if
the pit does not receive more than five barrels of produced water per day.
IV-63
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contamination of the ground water serving the Lee Acres housing subdivision. One
domestic well was sampled extensively by NM£!D and was found to contain extremely high levels of
chlorides and elevated levels of chlorinated VOCs, including trichloroethane. {Department of
the Interior (001) states that it is unaware of any violations of New Mexico ground-water
standards involved in this case. New Mexico states that State ground-water standards for
chloride, total dissolved solids. ben;ene. xylenes, 1,l-dichloroetnane. and ethylene dicnloride
have been violated as a result of the plume of contamination. In addition, the EPA Safe
Drinking Water Standard for trichloroethylene has been violated.) Hew Mexico State officials
state that "The landfill appears to be the principal source of chloride, total dissolved solids
and most chlorinated VOCs, while the refinery appears to be the principal source of aromatic
VOCs and ethylene dichloride."
During the period after disposal operations ceased and before the site was closed, access to
the lagoons was essentially unrestricted. While NHE1D believes that it is possible that non-oil
and gas wastes illegally disposed of dyring this period say have contributed to the documented
contamination, the primary source of ground-water contamination appears to be from oil and gas
wastes.
The State has ordered BLM to provide public water to residents affected by the contamination,
develop a ground-water monitoring system, and investigate trie types of drilling, drilling
procedures, and well constryetion methods that generated the waste accepted by the landfill.
BiM submitted a'mot ton-to-stay the order so as to include Giant Refining Company and El Paso
Natural Gas in cleanup operations. The motion was denied. The case went into litigation.
According to State officials. "The State of New Mexico agreed to dismiss its lawsuit only after
the Bureau of Land Management agreed to conduct a somewhat detailed hydrogeologic investigation
in a reasonably expeditious period of time. Tne lawsuit was not dismissed because of lack of
evidence of contamination emanating from the landfill." The refinery conpany has completed an
74
In a letter dated 8/20/87, Giant Refining Company states that "Benzene, toluene and
xyienes are naturally occurring compounds »n crude oil, and are consequently in high concentrations
in the produced water associated with that crude oil. The only gasoline additive used by Giant that
has been found in the water of a residential well is OCA (ethylene dicnloride) which has also been
found in the landfill plume." Giant also notes that the refinery leaks in the last 2 years resulted
in less than 30,000 gallons of diesel being released rather than the 100,000 gallons stated by the
Department of Interior in a letter to EPA of 8/11/87.
IV-64
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extensive rtyarogeologic investigation ano has implemented containment ana cleanup
measures.75 (TO 05)7o
Current New Mexico regulations prohibit use of unlined commercial
disposal pits.
Damage to Ground Water from Inadequately Maintained Injection Wells
As in other States, New Mexico has experienced problems with
injection wells.
A saltwater injection well, tne 80-3. operated by Texaco, is ysed for produced water disposal
for tne Hoore-Devornan 01! field in southeastern New Mexico. Injection occurs at about 10.000
ft. Trie Ogallala aquifer, overlying the oil production formation, is the sole source of potable
ground water in much of southeastern New Mexico. Dr. Daniel B. Stephens, Associate Professor of
Hydrology at tne New Mexico Institute of Mining and Technology, concluded that injection well
80-3 has contributed to a saltwater plume of contamination in the Qgallala aquifer. The piume
is nearly J mile long and contains chloride concentrations of up to 26.000 ppw. %
A local rancher sustained damage 10 crops after irrigating with water contaminated by this
saltwater plume. In 1973. an irrigation well was completed satisfactorily on the ranch of Mr,
Paul Hamilton, and, in 1977, tho well began producing water with chlorides of 1,200 pptn. Mr.
Hamilton's crops were severely damaged, resulting in heavy economic losses, and his farm
property was foreclosed on. There is no evidence of crop damage from irrigation prior to 1977.
Mr Hamilton initiated a private law suit against Texaco for damages sustained to his ranch.
Texaco argued that Ihe saltwater plume was the result of leachate of brines front unlined brine
disposal pus. now banned in the area. Or, Stephens proved that if old pits in the vicinity,
Comments in the Docket from BLM and the State of New Mexico pertain to NM 05. BLM states
that the refinery upgradient from the subdivision is responsible for the contamination because of
their "., .extremely sloppy housekeeping practices,.."* which resulted in the loss of "...hundreds of
thousands of gallons of refined product through leaks in their underground piping systew." The
Department of tne Interior states that "There is, in fact, noynting evidence that the landfill and
lagoons may have contributed little to the residential well contamination in the subdivisions," 001
states "...we strongly recommend that this case be deleted from the Damage Cases [Report to
Congress]," "New Mexico states that "E!D [Environmental Improvement Division] strongly believes
that the Lee Acres Landfill has caused serious ground water contamination and is well worth
inclusion in the Oil and Gas Damage Cases chapter of your [EPA] Report to Congress on Oil, Gas and
Geothermal Mastes."
References for case cited. State of New Mexico Administrati we Order No. 1005; contains
water analysis for open pits, monitor wells, and impacted domestic wells. Motion-to-stay Order No.
1005, Denial of motion to stay. Newspaper articles. Southwest Research and Information Center,
Response to Hearing before Water Quality Control Commission, 12/2/86. Letter to Dan Derkics. EPA,
from Department of the Interior, refuting Lee Acres damage case. 8/11/87. Letter to Dan Derkics.
EPA, from NHE1D, refuting Department of the Interior letter of 8/11/87. dated 8/18/87. Letter to
Dan Derkics, EPA. from Giant Refining Company, 8/20/87.
IV-65
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previously used for saltwater disposal, had caused the contamination, high chloride levels
would have ceen detected in tne irrigation well prior to 1977. Or. Stephens also demonstrated
that the BO-3 injection well had leaked some 20 million gallons of brine into the fresh ground
vdter. causing chloride contamination of tne Qgaliala aquifer from which Mr. Hamilton drew his
irrigation »ater Saseo or, this evicence a jurj awarded Mr. Hamilton a cash settlement from
texaco for oar-ages sustained botn Dy the 'teaming injection well and by ins abandoned disposal
pits. The well has haa wortiovers and additional pressure tests since 1S78. The well ts still
in operation, in compliance with UIC regulations. (NM OlJ
Current UIC regulations require mechanical integrity testing every 5
years for all Class II wells.
The well in the above case was tested for mechanical integrity
several times during the course of the trial, during which the
plaintiff's hydrologist, after contacting the Texas Railroad Commission,
discovered that this injection well would have been classed as a failed
well using criteria established by the State of Texas for such tests.
However, at the time, the well did not fail the test using criteria
established by the State of New Mexico. Both States have primacy under
the UIC program.
WEST COAST
The West Coast zone includes Washington, Oregon, and California. Of
the three states, California has the most significant hydrocarbon
production; Washington and Oregon have only minor oil and gas activity.
Damage cases were collected only in California.
Operations
California has a diverse oil and gas industry, ranging from stripper
production in very mature fields to deep exploration and large enhanced
recovery operations. Southern California and the San Joaquin Valley are
dominated by large capital- and energy-intensive enhanced recovery
References for case cued: Oil-Field Brine Contamination - ft Case Study, Lea Co, New
Mexico, from Selected Papers on Water Quality and Pollution in New Hexico - 1984; proceedings of a
symposium, New Hexico Bureau of Mines and Resources.
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projects, while the coastal fields are experiencing active exploration.
California's most mature production areas are in the lower San Joaquin
Valley and the Sacramento Basin. The San Joaquin produces both oil and
gas. The Sacramento Valley produces mostly gas.
The average depth of new wells drilled in California in 1985 was
4,176 feet. Some 3,413 new wells were completed in 1985, 166 of which
were exploratory.
Types of Operators
Operators in California range from small independents to major
producers. The majors dominate capital- and energy-intensive projects,
such as coastal development and large enhanced recovery projects.
Independents tend to operate in the mature production areas dominated by
stripper production.
Major Issues
Discharge ...of Produced Water and Oily Wastes to Ephemeral Streams
In the San Joaquin Valley, the State has long allowed discharge of
oily high-chloride produced water to ephemeral streams. After discharge
to ephemeral streams, the produced water is diverted into central sumps
for disposal through evaporation and percolation. Infiltration of
produced water into aquifers is assumed to occur, but official opinion on
its potential for damage is divided. Some officials take the position
that the aquifers are naturally brackish and thus have no beneficial use
for agriculture or human consumption. A report by the Water Resources
Control Board, however, suggests that produced water may percolate into
useable ground-water structures.
IV-67
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for the purposes of this stadj condjcted by Bean/Logan Consulting Geologists, ground water in
the study area was categorizes accorotng to geetype ana compared to produced water in soups that
came from production zones Research was conducted on sumps in tymrtc Valley. Metvittnel,
Valley, Midway Valley, Elk Hills, Buena Vista Hills, and Buena Vista Valley production fields.
Wnile this recent research was not investigating ground-water damages per se, the study suggests
obvious potential for damages relating to the ground water. The hydrogeologic analysis prepared
for the California State Water Resources Control Board concludes that about 570,000 tons of salt
from produced water were deposited in 1981 and that a total of 14,8 million tons have been
deposited since 19CC, The California Water Resources Scard suspects that a portion of the salt
has percolated into the ground water ana has Degraded it In addition to suspected degradation
of ground water, officers of the California Department of Fish and Gatie often find birds and
animals entrapped in the oily deposits tp the affected ephemeral streams Exposure to the oily
?B ?^
deposits often proves to be fatal to these birds and animals. (CA 21)
This is a permitted practice under current California regulations.
Aside from concerns over chronic degradation of ground water, this
practice of discharge to ephemeral streams can cause damage to wildlife.
The volume of wastes mixed with natural runoff sometimes exceeds the
holding capacity of the ephemeral streams. The combined volume may then
overflow the diversions to the sump areas and continue downstream,
contaminating soil and endangering sensitive wildlife habitat. The oil
and gas industry contends that it is rare for any wastes to pass the
diversions set up to channel flow to the sumps, but the California
Department of Fish and Game believes that it is a common occurrence.
Produced water from the Crocker Canyon area flows downstream to where it is diverted into
Valley Waste Disposal's large unlined evaporation/percolation samps for oil recovery
(cooperatively operated by local oil producers). In one instance, discovery by California Fish
and Game officials of a significant spill was made over a month after it occurred. According to
the California State Water Quality Board, the incident was probably caused by heavy rainfall, as
a consequence of which the volume of rain and waste exceeded the containment capacity of the
disposal facility. The sumps became eroded, allowing oily waste to flow down the valley and
into a wildlife habitat occupied by several endangered species including blunt-nosed leopard
lizards. San Joaquin kit foxes, and giant kangaroo rats.
7H
API states that the California Regional Water Quality Board and EPA are presently deciding
whether to promulgate additional permit requirements under the Clean Water Act and NPDES.
73
References for case cited: Lower Vestside Water Quality Investigation Hern County, and
Lower Westside Water Quality Investigation l,ern County: Supplementary Report, Bean/Logan Consulting
Geologists, 11/83, prepared for California State Water Resources Control Board- Westside
Groundwater Study. Michael ft. Rector, Inc., 11/83; prepared for Western Oil and Gas Association,
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According to tne State's report, there were 116 known wildlife losses including 11 giant
kangaroo rats. The count of aead animals was estimated at only 20 percent of the actual number
of animals Destroyed because of the delay in finding the spill, allowing poisoned animals to
leave the area before dying. Vegetation was covered with waste throughout the spill area. The
California Department of Fisn and Game ooes not believe this to be an isolated incident Tne
California water Resources Control Board, airing its investigation of the incident, noted
"... deposits of oloer accumulated oil. thereby indicating thai the saw channel had been used
for wastewater Disposal conveyance tn tne past prior to the recent discharge Cleanup
activities conducted later revealed that buildup of older oil was significant," The companies
implicated in this incident were fined $100,000 and were required to clean up the area. The
a A
companies denied responsibility for the discharge. (CA 08}
This release was in violation of California regulations.
ALASKA
The Alaska zone includes Alaska and Hawaii. Hawaii has no oil or gas
production. Alaska is second only to Texas in oil production.
Operations
Alaska's oil operations are divided into two entirely separate areas,
the Kenai Peninsula (including the western shore of Cook Inlet) and the
North Slope. Because of the areas' remoteness and harsh climate,
operations in both areas are highly capital- and energy-intensive. For
the purposes of damage case development, and indeed for most other types
of analysis, operations in these two areas are distinct. Types of damages
identified in the two areas have little in common.
on
References for case cited: Report of Oil Spill in Buena Vista Valley, by Mike Glinzak,
California Division of Oil and Gas (DOG), 3/6/86; map of site and photos accompany the report,
Letters to Sun Exploration and Production Co. from DOG. 3/12 and 3/31/86. Newspaper articles in
Banersfield Californian. 3/8/86. 3/11/86, and undated. California Uater Quality Control Board,
Administrative Civil Liability Complaint rACl-016. 8/8/86, California Water Quality Control Board,
internal memoranda. Smith to Pfister concerning cleanup of site. 5/27/86; Smith to Nevins
concerning description of damage and investigation, including map, 8/12/86. California Department of
Fish and Game. Dead Endangered Species in a California Oil Spill, by Capt. E.A Simons and Lt. M,
Akin, undated. Fact Sheets; Buena Vista Creek Oil Spill, ICern County. 3/7/86. and Mammals
Occurring on Elk Hills and Buena Vista Hills, undated. Letter from Lt, Akin to EPA contractor,
2/24/87
IV-69
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Activities on the Kenai Peninsula have been in progress since the
late 1950s, and gas is the primary product. Production levels are modest
as compared to those on the North Slope.
North Slope operations occur primarily in the Prudhoe Bay area, with
some smaller fields located nearby. Oil is the primary product.
Production has been under way since the trans-Alaska pipeline was
completed in the mid 1970s, Much of the oil recovery in this area is now
in the secondary phase, and enhanced recovery through water flooding is
on the increase.
There were 100 wells drilled in the State in 1985, all of them on the
North Slope. In 1985, one exploratory well was drilled in the National
Petroleum Reserve - Alaska (NPRA) and two development wells were drilled
on the Kenai Peninsula.
Types of Operators
There are no small, independent oil or gas operators in Alaska
because of the high capital requirements for all activities in the
region. Operators in the Kenai Peninsula include Union Oil of California
and other major companies. Major producers on the North Slope are ARCO
and Standard Alaska Production Company.
Major Issues
Reserve Pits.North Slope
Reserve pits on the North Slope are usually unlined and made of
permeable native sands and gravels. Very large amounts of water flow in
this area during breakup each spring in the phenomenon known as "sheet
flow." Some of this water may unavoidably flow into and out of the
reserve pits; however, the pits are designed to keep wastes in and keep
IV-70
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surface waters out. Discharge of excess liquids from the pits directly
onto the tundra is permitted under regulations of the Alaska Department
of Environmental Conservation (ADEC) if discharge standards are met. (See
summary on State rules and regulations.)
Through the processes of breakup and discharge, ADEC estimates that
100 million gallons of supernatant are pumped onto the tundra and
roadways each year,81 potentially carrying with it reserve pit
constituents such as chromium, barium, chlorides, and oil. Scientists
who have studied the area believe this has the potential to lead to
bioaccumulation of heavy metals and other contaminants in local wildlife,
thus affecting the food chain. However, no published studies that
demonstrate this possibility exist. Results from preliminary studies
suggest that the possibility exists for adverse impact to Arctic wildlife
because of discharge of reserve pit supernatant to the tundra:
In 1963, a stydy of the effects of reserve pit discharges an water quality and the
nacroiiivcrtcDrate community of tyndra ponds was undertaken by the U. S Fish and Wildlife
Service in the Prudhoe Bay oil production area of the North Slope. Discharge to tnc
tyndra ponds is a coimwn disposal method for reserve pit fluid in th
-------
In the sunwer of 1935. a field raethoo was developed by the It, S. Fish and Wildlife Service to
evaluate toxicity of reserve pit fluids discharged into tundra wetlands at Prudhoe Bay, Alaska.
Results of the study document acute lOKicity effects of reserve pit fluids on Daphnia. Acute
toxicity in Dapnma was observed after 96 hours of exoosure to liquid in five reserve pits.
Daphrua exposed 13 iiouid in receiving ponds also haa significantly higher death/ umobi 1 izat ion
than dtd Daphnia e»ocsea to lia^'d in control ponds after 96 hours. At Drill Stte I, after 96
hours, IOC percent of the Ddphnia introduced to the reserve pit nad been iwnoDi 1 i;ed or were
dead, as comparea to a control pond which showed less than 5 percent innobilized or dead after
96 hours. At Drill Site 12, 80 percent of the Daphnia exposed to the reserve pit liquid were
dead or jmnobi1ized after 96 hours and less than 1 percent of Daphnia exposed to the control
A 7 »S 1
pond were dead or inroobi 1ized. [AK 0?)
In June 1965, fwe drill sues and three control sues were chosen for studying the effects of
drilling fluids and their discharge on f»sh and waterfowl habitat on the North Slope of Alaska.
Btoaccufflulation analysis was done on fish tissue using water samples collected from the reserve
pits. Fecundity and growth were reduced in daphnids exposed for 42 days to liquid composed of
2.5 percent and 25 percent drilling fluid from the selected drill sites. Bioaccumulation of
barium, titanium, iron, ccpper. and molybdenum was documented in fish exposed to drilling fluids
for as little as 96 hoyrs. JSk 08}
Erosion of reserve pits and subsequent discharge of reserve pit
contents to the tundra constitute another potential environmental problem
on the North Slope. If exploration drilling pits are not closed out at
the end of a drilling season, they may breach during "breakup." Reserve
pit contaminants are then released directly to the tundra. (As described
in Chapter III, production reserve pits are different from .expioration
reserve pits. Production reserve pits are designed to last for as long
as 20 years.) A reserve pit wall may be poorly constructed or suffer
structural damage during use; the wall may be breached by the hydrostatic
head on the walls due to accumulation of precipitation and produced
fluids. New exploration reserve pits are generally constructed
below-grade. Flow of gravel during a pit breach can choke or cut off
tundra streams, severely damaging or eliminating aquatic habitat.
83
API coHiBents in the Docket pertain to Ak 07. API discusses the relevance of the Daphnia
study to the damage cases.
R4
References for case cited: An In Situ Acute Toxicity Test with Daphnia: A Promising
Screening Tool for Field Biologists? by Elaine Snyder-Conn, U.S. Fish and Wildlife Service, Fish
and Wildlife Enhancement, Fairbanks, Alaska, 1985.
fiS
References for case cited: Effects of Oil Drilling Fluids and Thetr Discharge on Fish
and Waterfowl Habitat in Alaska, U.S. fish and Wildlife Service, Columbia National Fishery Research
Laooratory, Jackson Field Station, Jackson, Wyoming, February 1986.
IV-72
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Tne Atouna Test yell No. 1, which is 11,200 feet deep, is in the National Petroleum Reserve in
Alaska (NPRA) ana was a sue selected for cleanup of the NPRA by the U.S. Geological Survey
{USGS) in 1984. The site is in the northern foothills of the Brooks Range, The well was spud
on February 29, 1960, and operations were completed on April 20.1981. A side of the reserve pit
bent wasrteo out into the tundra during spring breakup, allowing reserve pit fluid to flow onto
the tundra As documented by the USGS cleanup team, high levels o* chromium, oil. and grease
have leached into the soil dewngraoient from the pit. Chromium was found at 2.2 to 3.0 ing/kg
dry weight. The high levels of oil and grease may be from the use of Arctic Pack. (85 percent
diesel fuel) at the well over the winter of I960. The cleanup team noted that the downslope
soils were discolored and putrefied, particularly in the upper layers. The pad is located in a
runoff area allowing for erosion of pad and pit into surrounding tundra. A vegetation kill area
caused by reserve pit fluid exposure is approximately equal to half an acre. Areas of the drill
pad may remain barren for many years because of contassinat ion of soil with salt and
hydrocarbons, Tne well sue is in a caribou calving area. {Ak 12}
This type of reserve pit construction is no longer permitted under
current Alaska regulations.
Waste Disposal on the North Slope
Inspection of oil and gas activities and enforcement of State
regulations on the North Slope is difficult, as illustrated by the
following case:
North Slope Salvage, Inc. (NSS1) operated a salvage business in Prudhoe Bay during 1982 and
1983. During this time. NSS1 accepted delivery of various discarded materials from oil
production companies on the North Slope, including more than 14.000 fifty-five gallon drums, 900
of which were full or he la more than residyal amounts of oils and chemicals used »n the
development and recovery of oil The drums were stockpiled and managed by HS5! in a manner that
allowed the discharge of hazardous substances, While the NSS1 site may have stored chemicals
and wastes from other operations that supported oil and gas exploration and production (e.g.,
vehicle maintenance materials), such storage would have constituted a very small percentage of
NSSl's total inventory.
oe
API states that exploratory reserve pits must now be closed 1 year after cessation of
drilling operations. EPA notes that it is important to distinguish between exploratory and
production reserve pits. Production reserve pits are permanent structures that remain open as long
as the well or group of wells ss producing. This may be as long as 20 years.
8?
References for case cited: Final Wellsite Cleanup on national Petroleum Reserve -
Alaska, USGS, July 1986.
IV-73
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The situation was discovered by the Alaska Department of Environmental Conservation (ADEC) in
June 1983. At this time, the State of Alaska requested Federal enforcement, but Federal action
was never ta«.en. An inadequate cleanup effort was mounted by NSS3 after confrontation by AOEC.
lo preclude further discharges of hazardous substances, AICO and Softio paid for the cleanup
because they were tne primary contributors to the site. Cleanup »as completed en August 5,
1983, after 58.00C gallons of chemicals and water were recovered. It is unknown how much of the
hazardous substances was carried into the tundra. The discharge consisted of oil and a variety
of organic substances known to be toxic, carcinogenic, mutagenic, or suspected of being
BB 89
carcinogenic or mutagemc. (AK, 10)
Disposal of Drilling Wastes, Kenal Peninsula
Disposal of drilling wastes is the principal practice leading to
potential environmental degradation on the Kenai Peninsula. The
following cases involve centralized facilities, both commercial and
privately run, for disposal of drilling wastes:
Operators of the Sterling Special Waste Site have nact a long history of substandard
monitoring, having failed during 197? and 1978 to carry out any well sampling and otherwise
having performed only irregular sampling. This was in violation of AOEC permit requirements to
perform quarterly reports of water quality samples from the monitoring wells. An internal ADEC
memo (L.G. Elphic toR.T. Williams, 2/25/76) noted "...we must not forget.,.that this is the
State's first sanctioned hazardous waste site and as such wast receive close observation during
< 90
its initial operating period."
A permit for .the site was reissued by ADEC in 1979 despite knowledge by ADEC of lack of
effective ground-water monitoring. In July of 1980, ADEC Engineer R. Williams visited the site
and filed a report noting that the "...operation appears completely out of control." Honitonna
well samples were analyzed by ADEC at this t irne and were found to be in excess of drinking water
standards for iron, lead, caetntum, copper, zinc, arsenic, phenol, and oil and grease. One
private water well m the vacinity showed 0.4 ppb 1,1.1-trichloroethane. The Sterling School
well showed 2.1 g/l mercury. (Subsequent tests show mercury concentration below detection
1imits--0.001 mg/kg.) Both contamination incidents are alleged to be caused by the Sterling
CO
Alaska Department of Environmental Conservation (ADEC) states that this case "...js^an
example of how the oil industry inappropriately considered the limits of the exemption [under RCRA
Section 3001]."
8S
References for case cited: Report on the Occurrence, Discovery, and Cleanup of an Oil
and Hazardous Substances Discharge at Lease Tract 57, Prudhoe Bay. Alaska, by Jeff Haeh - ADEC,
1984. Letter to Dan Derkics, EPA, from Stan Hungerford, ADEC, 8/4/87.
90
The term "hazardous waste site" as used >n this nemo does not refer to a "1CRA Subtitle C
hazardous waste site."
IV-74
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Q |
Special Waste Sue- Allegations are unconfirmed b> the ADEC. (An. 03}"
Practices at the Sterling site were in violation of the permit.
This case involves a 45-acre gravel pit on Poppy Lane on the Kenai Peninsula used since the
1970s for disposal of wastes associated witn gas development The gravel pit contains barrels
of ynioent if led wastes, drilling inyds, gas conoensate. gas conoensate-contaninated peat,
abandoned equipment, and soil contain mated with diesel and cheraicals. The property belongs to
Union Oil Co., which bought it around 1968. Dumping of wastes in this area is illegal; reports
of last observed dumping were in October 1985, as witnessed by residents in the area.
In thts case, there has been demonstrated contamination of adjacent water wells with organic
compounds related to gas tondensate (AOEC laboratory reports from October 1986 and earlier).
Alleged health effects on residents of neighboring properties include nausea, diarrhea, rashes,
and elevated levels of metals (chromium, copper) in blood in two residents. Property values
have beer, effectively reduced to zero for residential resale. A fire on the site on July 8,
1981, was attributed tc comtoystion of petroleyis-related products, ar.c the fire oepartsient was
unable to extinguish it. The fire was allegedly set by people illegally disposing of wastes in
the pit. Fumes from organic liquids are noticeable in the breathing tone onsite. UNOCAL has
been directed on several occasions to remove gas concensate in wastes from the site. Since June
19, 1972, disposal of wastes regulated as solid wastes has been illegal at this site. The case
9?
has been actively under review by the State since 1981 (Ak 01)
References for case cued: Dames and Moore well monitoring report, showing elevated
metals referenced above, October 1975. Bowling Rice & Associates monitoring results. 1/15/80, and
Har Enterprises monitoring results, September 1930, provided by Wa U Pederson. showing elevated
levels of 'metals, oil, and grease in ground water. Detailed letter from Eric Meyers to Glen Aikens,
Deputy" Commissioner, ADEC. recounting permit history of site and failure to conduct proper
monitoring, 1/22/62. Testimony and transcripts from Walt Pederson on public forums complaining
about damage to drinking water and mismanagement of site. Transcripts of waste logs of site from
9/1/79 to 8/20/84, indicating only 264,436 bbl of muds received, during a period that should have
generated much more waste. Letter from Howard Reiser to Dm on Oil, 12/7/81. indicating that
"...drilling «nud is being disposed of by methods other than at the Sterling Special Uaste Site and
by methods that coy Id possibly cause contamination of the ground water "
Op
References for case cited: Photos showing Illegal dumping in progress. Field
investigations. State of Alaska Individual Fire Report on "petroleum dump," 7/12/81. File memo on
site visit by Howard Keiser, AOEC Environmental Field Officer, in response to a complaint by State
Forestry Officer. 7/21/81. Memo from Howard Keiser to Bob Martin on his objections to granting a
permit to Union Oil for use of site as disposal site on basis of impairment of wildlife resources,
7/28/83. Letter. AOEC to Union Oil. objecting to lack of cleanup of site despite notification by
A0EC on 10/3/84, Analytical reports by ADEC indicating gas condensate contamination on site,
8/14/84. EPA Potential Hazardous Uaste Site Identification, indicating continued dumping as of
8/10/85. Citizens' complaint records. Blood test indicating elevated chromium for neighboring
resident Jessica Black, 1/16/85. Letter to Mike Lucky of ADEC from Union Oil confirming cleanup
steps, 2/12/85. Memo by Carl Keller, ADEC ecologist, indicating presence of significant toxics on
site, 8/14/85. Minutes of Uaste Disposal Commission meeting. 2/10/85. AOEC analytic reports
indicating gas condensate at site, 10/10/85, Letters from four different 'real estate firms in area
confirming inability to sell residential property in Poppy Lane area. Letter from Bill tanoreaux.
AOEC, to J. Black and R. Sizemore referencing high selenium/chromium in the ground water in the
area. Miscellaneous technical documents. EPA Potential Hazardous Waste Site Preliminary
Assessment, 2/12/87.
IV-75
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These activities are illegal under current Alaska regulations.
MISCELLANEOUS ISSUES
Improperly Abandoned and Improperly Plugged Hells
Degradation of ground water from improperly plugged and unplugged
wells is known to occur in Kansas, Texas, and Louisiana. Improperly
plugged and unplugged wells enable native brine to migrate up the
wellbore and into freshwater aquifers. The damage sustained can be
extensive.
Problems also occur when unidentified improperly plugged wells are
present in areas being developed as secondary recovery projects. After
the formation has been pressurized for secondary recovery, native brine
can migrate up. unplugged or improperly plugged wells, potentially causing
extensive ground-water contamination with chlorides.
In 1961, Gulf and its predecessors began secondary recovery operations in the East Gladys Unit
jn SedgwJck, County, Kansas. Dyrtng secondary recovery, water is Dumped into a target formation
at high pressure, enhancing oil product ion. This pumping of water pressurizes the formation.
which can at times result in brines being forced up to the surface through unplugged or
improperly plugged abandoned wells. When Gylf began their secondary recovery in this area, it
•as with the knowledge that a number of abandoned wells existed and could lead to escape of salt
water into fresh ground water,
Gerald Blood alleged that three improperly plugged wells in proximity to the Gladys unit were
the source of fresh ground-water contamination on his property, Mr. Blood runs a peach orchard
in the area Apparently native brine had migrated from the nearby abandoned wells into the
fresh ground water from which Mr, Blood draws water for domestic and irrigation purposes.
Contamination of irrigation wells was first noted by Mr. Blood when, in 1970, one of his truck
gardens was killed by irrigation with salty water. Brine migration contaminated two more
irrigation wells in the mid*1970s. By 1980, brine had contaminated the irrigation wells ysed to
irrigate a whole section of Mr, Blood's land. 8y this time, adjacent landowners also had
contaminated wells. Mr. Blood lost a number of peach trees as a result of the contamination of
his irrigation well; he also lost the use of his domestic well.
IV-76
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The Bloods sued Gulf Oil in civil court for damages sustained by their farm from chloride
contamination of their irrigation and residential wells. The Bloods won their case and were
awarded an undisclosed amount of money. (US 14)
Current UIC regulations prohibit contamination of groundwater.
The potential for environmental damage through ground-water
degradation is high, given the thousands of wells abandoned throughout
the country prior to any State regulatory plugging requirements.
In West Texas, thousands of oil and gas wells have been drilled over the last several
decades, many of which were never properly plugged. There exists in the subsurface of
this area a geologic formation known as the Coleman Junction, which contains extremely
salty native brine and possesses natural artesian properties. Since this formation is
relatively shallow, most oil and gas wells penetrate this formation. If an abandoned
well is not properly plugged, the brine contained in the Coleman Junction is under enough
natural pressure to rise through the improperly plugged well and to the surface.
According to scientific data developed Over several years, and presented by Mr. Ralph
Hoelscher, the ground water in and around San Angela, Texas, has been severely degraded
by this seepage of native brine, and much of the agricultural land has absorbed enough
salt as to be nonproductive, This situation has created a hardship for farmers in the
area. The Texas Railroad Conmission states that soil and ground water are contaminated
with chlorides because of terracing and fertilizing of the land. According to Mr.
Hoelscher, a long-time farther in the area, little or no fertilizer is used in local
agriculture. (TX II)95
Improper abandonment of oil and gas wells is prohibited in the State
of Texas.
93
API states that damage in this case was brought about by "old injection practices."
^ References for case cited: U.S. District Court for the district of Kansas, Memorandum
and Order, Blood vs. Gulf; Response to Defendants' Statement of Uncontroverted Facts; and Memorandum
in Opposition to Motion for Suimtary Judgment. Means Laboratories, Inc., water sample results.
Department of Health, District Office #14, water samples results. Extensive miscellaneous
memoranda, letters, analysis.
References for case cited: Water analysis of Ralph Hoelscher's domestic well. Soil
Salinity Analysis, Texas Agricultural Extension Service - The Texas A&M University System, Soil
Testing Laboratory, Lubbock. Texas 79401, Photographs. Conversation with Wayne Farrell. San Angelo
Health Department. Conversation with Ralph Hoelscher, resident and farmer.
IV-77
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CHAPTER V
RISK MODELING
INTRODUCTION
This chapter summarizes the methods and results of a risk analysis of
certain wastes associated with the onshore exploration, development, and
production of crude oil and natural gas. The risk analysis relies
heavily on the information developed by EPA on the types, amounts, and
characteristics of wastes generated (summarized in Chapter II) and on
waste management practices (summarized in Chapter III). In addition,
this quantitative modeling analysis was intended to complement EPA's
damage case assessment (Chapter IV). Because the scope of the model
effort was limited, some of the types of damage cases reported in
Chapter IV are not addressed here. On the other hand, the risk modeling
of ground-water pathways covers the potential for certain more subtle or
long-term risks that might not be evidenced in the contemporary damage
case files. The methods and results of the risk analysis are documented
in detail in a supporting EPA technical report (USEPA 1987a).
EPA's risk modeling study estimated releases of contaminants from
selected oil and gas wastes into ground and surface waters, modeled fate
and transport of these contaminants, and estimated potential exposures,
health risks, and environmental impacts over a 200-year modeling period.
The study was not designed to estimate absolute levels of national or
regional risks, but rather to investigate and compare potential risks
under a wide variety of conditions.
Objectives
The main objectives of the risk analysis were to (1) characterize and
classify the major risk-influencing factors (e.g., waste types, waste
-------
management practices, environmental settings) associated with current
operations at oil and gas facilities; (2) estimate distributions
of major risk-influencing factors across the population of oil and. gas
facilities within various geographic zones; (3) evaluate these factors in
terms of their relative effect on risks; and (4) develop, for different
geographic zones of the U.S., initial quantitative estimates of the
possible range of baseline health and environmental risks for the variety
of existing conditions.
Scope and Limitations
The major portion of this risk study involved a predictive
quantitative modeling analysis focusing on large-volume exempt wastes
managed according to generally prevailing industry practices. EPA also
examined (but did not attempt quantitative assessment of) the potential
effects of oil and gas wastes on the North Slope of Alaska, and reviewed
the locations of oil and gas activities relative to certain environments
of special interest, including endangered species habitats, wetlands, and
public lands.
Specifically, the quantitative risk modeling analysis estimated
long-term human health and environmental risks associated with the
disposal of drilling wastes in onsite reserve pits, the deep well
injection of produced water, and the direct discharge of produced water
from stripper wells to surface waters. These wastes and waste management
practices encompass the major waste streams and the most common management
practices within the scope of this report, but they are not necessarily
those giving rise to the most severe or largest number of damage cases of
the types presented in Chapter IV. For risk modeling purposes, EPA
generally assumed full compliance with applicable current State and
References in this chapter to oil and gas facilities, sites, or activities refer to
exploration, development, and production operations.
V-2
-------
Federal regulations for the practices studied. Risks were not modeled
for a wide variety of conditions or situations, either permitted or
illegal, that could give rise to damage incidents, such as waste spills,
land application of pit or water wastes, discharge of produced salt water
to evaporation/percolation pits, or migration of injected wastes through
unplugged boreholes.
In this study, EPA analyzed the possible effects of selected waste
streams and management practices by estimating risks for model
scenarios. Model scenarios are defined as hypothetical (but realistic)
combinations of variables representing waste streams, management
practices, and environmental settings at oil and gas facilities. The
scenarios used in this study were, to the extent possible, based on the
range of conditions that exist at actual sites across the U.S. EPA
developed and analyzed more than 3,000 model scenarios as part of this
analysis.
EPA also estimated the geographic and waste practice frequencies of
occurrence of the model scenarios to account for how well they represent
actual industry conditions and to account for important variations in oil
and gas operations across different geographic zones of the U.S.2 These
frequencies were used to weight the model results, that is, to account
for the fact that some scenarios represent more sites than others.
However, even the weighted risk estimates should not be interpreted as
absolute risks for real facilities because certain major risk-influencing
factors were not modeled as variables and because the frequency of
occurrence of failure/release modes and concentrations of toxic
constituents were not available.
*• The 12 zones used in the risk assessment are identical to the zones used as part of EPA's
waste sampling and analysis study (see Chapter II), with one exception: zone 11 (Alaska) was divide
into zone 11A representing the North Slope and »one 11B representing the Cook Inlet-Kenai Peninsula
area.
V-3
-------
A principal limitation of the risk analysis is that EPA had only a
relatively small sample set of waste constituent concentration data for
the waste streams under study. As a result, the Agency was unable to
construct regional estimates of toxic constituent concentrations or a
national frequency distribution of concentrations that could be directly
related to other key geophysical or waste management variables in the
study. Partly because of this data limitation, all model scenarios
defined for this study were analyzed under two different sets of
assumptions: a "best-estimate""* set of assumptions and a "conservative"
set of assumptions. The best-estimate and conservative sets of assumptions
are distinguished by different waste constituent concentrations, different
timing for releases of drilling waste and produced water, and, in some
cases, different release rates (see the later sections on model scenarios
and model procedures for more detail). The best-estimate assumptions
represent a set of conditions which, in EPA's judgment, best characterize
the industry as a whole, while the conservative assumptions define
higher-risk (but not worst-case) conditions. It is important to clarify
that the best-estimate and conservative assumptions are not necessarily
based on a comprehensive statistical analysis of the frequency of
occurrence or absolute range of conditions that exist across the industry;
instead, they reflect EPA's best judgment of a reasonable range of
conditions based on available data analyzed for this study.
Another major limitation of the study is the general absence of
empirical information on the frequency, extent, and duration of waste
releases from the oil and gas field management practices under
consideration. As described below, this study used available engineering
judgments regarding the nature of a variety of failure/release mechanisms
for waste pits and injection wells, but no assumptions were made
As used here, the term best estimate is different from the statistical concept cf maximum
likelihood (i.e., best) estimate.
V-4
-------
regarding the relative frequency or probability of occurrence of such
failures.
Although EPA believes that the scenarios analyzed are realistic and
representative, the risk modeling for both sets of scenarios incorporated
certain assumptions that tend to overestimate risk values. For example,
for the health risk estimates it was assumed that individuals ingest
untreated contaminated water over a lifetime, even if contaminant
concentrations were to exceed concentrations at which an odor or taste is
detectable. In addition, ingested concentrations were assumed to equal
the estimated center line (i.e., highest) concentration in the
contaminant plume.
Other features of the study tend to result in underestimation of
risk. For example, the analysis focuses on risks associated with
drilling or production at single oil or gas wells, rather than on the
risks associated with multiple wells clustered in a field, which could
result in greater risks and impacts because of overlapping effects.
Also, the analysis does not account for natural or other source
background levels of chemical constituents which, when combined with the
contamination levels from oil and gas activities, could result in
increased risk levels.
QUANTITATIVE RISK ASSESSMENT-METHODOLOGY
EPA conducted the quantitative risk assessment through a four-step
process (see Figure V-l). The first three steps—collection of input
data, specification of model scenarios, and development of modeling
procedures — are described in the following subsections. The last step,
estimation of effects, is described in subsequent sections of this
chapter that address the quantitative modeling results.
V-5
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Collect Input
Data
Waste Characterization
Data
Data on Waste
Management Practices
Environmental
Setting Data
Specify Model
Scenarios
* Waste Streams
* Waste Management
Practices
* Environmental
Settings
Develop Modeling
Procedures
• Release Modeling
* Environmental Transport
and Fate Modeling
• Risk/Effects Modeling
Estimation
of Effects
• Human Health Risk
• Water Resource Damage
* Toxicity to Aquatic
Biota
Figure V-1 Overview of Quantitative Risk Assessment Methodology
-------
Input Data
EPA collected three main categories of input data for the
quantitative modeling: data on waste volumes and constituents, waste
management practices, and environmental settings. Data on waste volumes
were obtained from EPA's own research on sources and volumes of wastes,
supplemented by the results of a survey of oil and gas facilities
conducted by the American Petroleum Institute (API) (see Chapter II}.
Data on waste constituents were obtained from EPA's waste stream chemical
analysis study. The results of EPA's research on current waste
management practices, supplemented by API's studies (see Chapter III),
were the basis for defining necessary input parameters concerning waste
management practices. Data needed to characterize environmental settings
were obtained from an analysis of conditions at 266 actual drilling and
production locations sampled from areas with high levels of oil and gas
activity (see USEPA 1987a, Chapter 3, for more detail on the sample
selection and analytical methods).
Model Scenarios
The model scenarios in this analysis are unique combinations of the
variables used to define waste streams, waste management practices, and
environmental settings at oil and gas facilities. Although the model
scenarios are hypothetical, they were designed to be:
• Representative of actual industry conditions (they were
developed using actual industry data, to the extent available);
» Broad in scope, covering prevalent industry characteristics but
not necessarily all sets of conditions that occur in the industry;
and
• Sensitive to major differences in environmental conditions (such
as rainfall, depth to ground water, and ground-water flow rate)
across various geographic zones of the U.S.
V-7
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As illustrated in Figure V-2, EPA decided to focus the quantitative
analysis on the human health and environmental risks associated with
three types of environmental releases: leaching of drilling waste
chemical constituents from onsite reserve pits to ground water below the
pits (drilling sites); release of produced water chemical constituents
from underground injection wells to surface aquifers (production
sites); and direct discharge of produced water chemical constituents to
streams and rivers (stripper well production sites).
Chemical Constituents
EPA used its waste sampling and analysis data (described in
Chapter II) to characterize drilling wastes and produced water for
quantitative risk modeling. Based on the available data, EPA could not
develop separate waste stream characterizations for various geographic
zones; one set of waste characteristics was used to represent the
nation. The model drilling waste represents only water-based drilling
muds (not oil-based muds or wastes from air drilling), which are by far
the most prevalent drilling mud type. Also, the model drilling waste
does not represent one specific process waste, but rather the combined
wastes associated with well drilling that generally are disposed of in
reserve pits.
For both drilling wastes and produced water, EPA used a systematic
methodology to select the chemical constituents of waste streams likely
to dominate risk estimates (see USEPA I98?a, Chapter 3, for a detailed
description of this methodology). The major factors considered in the
chemical selection process were (1) median and maximum concentrations in
4
far the purpose of this report, a suffice aquifer is defined as the geologic unit nearest
the land surface that transmits sufficient quantities of ground water to be used as a source of
drinking water It is distinguished from aquifers at greater depths, which may be the injection zone
for an underground injection well or are too deep to be generally yied as a drinking water source.
V-8
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Waste Streams:
Drilling Wastes
Produced Fluids
Waste
Management
Practices:
Discharge
to On-Site
Reserve Pits
Discharge
In Underground
Injection Wells
Direct Discharge
to Surface
Water
(Stripper Wells Only)
Seepage
Release
to Surface
Aquifer
Environmental
Settings:
Hydrogeologic and
Exposure Point
Characteristics
Hydrogeologic and
Exposure Point
Characteristics
Surface Water
and Exposure Point
Characteristics
Figure V-2 Overview of Modeling Scenarios Considered in the Quantitative Risk Assessment
-------
the waste samples; (2) frequency of detection in the waste samples;
(3) mobility in ground water; and (4) concentrations at which human
health effects, aquatic toxicity, or resource damage start to occur.
Through this screening process, EPA selected six chemicals for each waste
type that were likely to dominate risk estimates in the scenarios
modeled. For each selected chemical, two concentrations were determined
from the waste characterization data. The 50th percentile (median) was
used to set constituent concentrations for a "best-estimate" waste
characterization, while the 90th percentile was used for a "conservative"
waste characterization. The selected chemicals and concentrations, shown
in Table V-l, served as model waste streams for the quantitative risk
analysis.
Of the chemicals selected, arsenic and benzene were modeled as
potential carcinogens. Both substances are rated as Group A in EPA's
weight-of-evidence rating systei (i.e., sufficient evidence of
carcinogenicity in humans). Some scientists, however, believe that
arsenic may not be carcinogenic and may be a necessary element at low
levels. Sodium, cadmium, and chromium VI were modeled for
noncarcinogenic effects. The critical (i.e., roost sensitive) health
effects for these constituents are hypertension for sodium and liver and
kidney damage for cadmium and chromium VI. It is emphasized that the
effect threshold for sodium used in this analysis was based on potential
effects in the high-risk (not general) population. (The level used is
slightly higher than EPA's 20 mg/L suggested guidance level for drinking
water.) The high-risk population is defined to include individuals with
a genetic predisposition for hypertension, pregnant women, and
hypertensive patients. Finally, boron, chloride, sodium, cadmium,
chromium VI, and total mobile ions were modeled for their potential
aquatic toxicity and resource damage effects. Table V-2 lists the cancer
potency factors and effects thresholds used in the study.
V-10
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Table V-l Model Constituents ana Concentrations*
Produced water
constituents
Arsenic
Benzene
Boron
Sodium
Chloride
Mobile ionsb
Cor-e-'
Median
(mg/L)
0.02
0.47
9 9
9.400
7,300
23,000
trat ions
Upper 9!
(ny/L)
1
2
120
67 . 000
35.000
110.000
7
9
Concentr.it ions
Or 1 1 1 ing waste
i*ater-t>ased)
const ituents
Arsenic
Cadmium
Sodium
Chloride
Chromium VI
Mobi le ions
Pit llQU
Median
(mg/l
0.0
0.056
6.700
3.500
0.43
17,000
<
Upper 90"4
0.16
1.4
44.000
39.000
290
95.000
p
Median
0.0
0.011
1.200e
2.000f
0
4.000
sol ids/TCI PC
Upper 90S
{mg/L}
o.oozd
0.29
4,400e
11.000f
0.78
16.000
Pit
Median
0
2
e.soo
1 7 . OOC
22
100.000
so lids, 'direct
Upper
(mg/fcg)
0 0
.0 5
S9.000
8d,000
190
250.000
90%
.010
.4
?he medlar, constituent concentrations from the relevant samples in the EPA waste sampling/
analysis siydy mere ysed for a "best-estimate"' »aste characterization, and the 90th percent tie
concentrations were used for a "conservative" waste characterization (data source. t'SEPA 19876}.
Mobile tons include chloride, sodium, potassium, calcium, magnesium, and so Ifate.
CTCLP - toxicity characteristic leaching procedure.
Upper 90th percent»le arsenic values estimated twsed on detection limit.
Preliminary examinations indicate that the sodium TCLP values nay overestimate the actual
leachable sodium concentrations in reserve pit samples. The accuracy of these concentrations is the
subject of an ongoing evaluation.
Chloride TCLP values are estimated based on sodiun data.
V-ll
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Table V-2 Toxicity Parameters and Effects Thresholds*
Mood
const i tuent
Benzene
Arsenic
Sod } ym
C a dan urn
Chromiuiit VI
Chloride
Boron
Total IBODI le
ions
Cancer
potency factor
(mg/kd-d)"'
0 052
15
NA
NAC
^
NA
NA
NA
Human ncncancer
threshold
(mg/ng-d)
NA
WA
0,66
0 . 00029
0.005
NA
HA
NA
Aquatic toxstity Resource damage
threshold (mg/L) threshold (mg/L)
NAb NA
NA NA
83.4 NA
0 . NA
O.Oil NA
HA 250
NA 1
NA • 33 5e
500f
See USEPA 198"/a for detailed description and ootuirientation.
NA = not applicable; indicates that an effect type was not nodeled for a specific chemical.
cNot considered carcinogenic by the oral exposure route,
Represents total mass of ions mobile in ground water.
For surface water only {assumes a backg'round 1e»el of 65 mg/L and a threshold limit of 400
mg/L).
For ground water only.
V-12
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The chemicals selected for risk modeling differ from the constituents
of potential concern identified in Chapter II for at least three
important reasons, first, the analysis in Chapter II considers the
hazards of the waste stream itself but, unlike the selection process used
for this risk analysis, does not consider the potential for waste
constituents to migrate through ground water and result in exposures at
distant locations. Second, certain constituents were selected based on
their potential to cause adverse environmental (as opposed to human
health) effects, while the analysis in Chapter II considers only human
health effects. Third, frequency of detection was considered in
selecting constituents for the risk modeling but was not considered in
the Chapter II analysis.
Waste Management Practices
Three general waste management practices were considered in this
study: onsite reserve pits for drilling waste; underground injection
wells for produced water; and direct discharge of produced water to
rivers and streams (for stripper wells only).5 EPA considered the
underground injection of produced water in disposal wells and
waterflooding wells.6 The design characteristics and parameter values
modeled for the different waste management practices are presented in
Tables V-3 and V-4. These values were developed from an evaluation of
EPA's and API's waste volume data .(see Chapter II) and waste management
practice survey results (see Chapter III) for the nation as a whole.
At present, there are no Federal effluent guidelines for stripper wet Is (i.e.. oil wells
producing less than ten barrels of crude oil per day), and, under Federal law, these wells are allowed
to discharge directly to surface waters subject to certain restrictions. Most other onshore oil and
gas facilities are subject to trie federal zero-discharge requirement.
Waterflooding is a seconaary recovery method in wruch treated fresh water, seawater, or
produced water is injected into a petroleum-bear ing formation to help maintain pressure and to displace
a portion of the remaining crude osl toward production wells. Injection wells used for waterflooding
may have different designs, operatir.g practices, and economic consideraiions than those of disposal
wells, which are yst-d simply to dispose of unwanted fluid underground.
V-13
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Table V-3 Drilling Pit Waste (Water-Based) Management Practices
Onsite
pit size
Waste
amount3
(barrels)
Disposal practice
Pit
${«3
L W 0
La roe
Med iurn
Small
59 47 2.31
32 25 2.
28,000 Reserve pit-unlmed
Reserve pit-lined.
capped
S.9QQ Reserve pu-unlined
ieserve pit-lined.
capped
1,650 Reserve pu~ynlined 1? 14 ].Sfc
Reserve pit-lined,
capped
aPer well drilled (includes solids and liquids).
Waste depths for large, medium, and small pits were 1,5. 1,2, and 1.1
meters, respecttvelj.
V-14
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Table V-6 Ceftnition of Best Estimate ana Conservative Release Assumptions
Release source
Release
assumption
Constituent
concent rat ion
in waste
Failure/re lease
t lining
Release volume
Unlifted Pits
iest-est imate 50th 1, (med;«jn) Release begins in year 1 Calculated by release equations
Conservative 90tn t.
Release begins »n year \ Calculated fey release equations
(same as best-estimatej
L ined Psts
8esi-est iir,ate 53th X
Liner failure begins in
year 25
Calculated by release equations
Conservative 90tN
Liner failure begins in
year 5
Calculated by release equations
(same as best-estimate)
Inject ion Wei Is/
Casing Fat lure
Beit-estimate 50th
One year release in year
i for waterflootJ wells,
constant annual releases
during years 11-13-for
disposal wells
0 ?-% bbl/d for naterflood
wells; 0 05-38 bbl.'d for
disposal wells
Conservative 90th %
Constant annual releases
during years 11-15 for
waterflood and disposal
wells
Same as best-est isute
Inject ion Wells/
Grout Seal failure
6est-estimate
50th
Constant annual releases
during years 11-15 for
naterflood and disposal
wells
0,00025-0,0025 bbl/d for
wdterflood wells; 0.00025-
0^0075 bbl/d for disposal wells
Conservat ive
90th
Constant annual releases
during years 1-20 for
waterflood and disposal
•ells {immediate failure.
no detect ion)
0.05-0.5 bbl/d for waterflood
wells; 0.05-1.5 bbl/d for
disposal wells
'See Table V-l.
V-18
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the same layers considered during the active period, for unlined pits,
release was assumed to begin immediately at the start of the modeling
period. For lined pits, failure (i.e., increase in hydraulic
conductivity of the liner) was assumed to occur either 5 or 25 years
after the start of the modeling period. It was assumed that any liquids
remaining in unlined reserve pits at the time of closure would be land
applied adjacent to the pit. Liquids remaining in lined pits were
assumed to be disposed offsite.
For modeling releases to surface aquifers from Class II injection
wells, a 20-year injection well operating period was assumed, and two
failure mechanisms were studied: (1) failure of the well casing (e.g., a
corrosion hole) and (2) failure of the grout seal separating the injection
zone from the surface aquifer. At this time, the Agency lacks the data
necessary to estimate the probability of casing or grout seal failures
occurring. A well casing failure assumes that injected fluids are exiting
the well through a hole in the casing protecting the surface aquifer. In
most cases, at least two strings of casing protect the surface aquifer
and, in those cases, a release to this aquifer would be highly unlikely.
The Agency has made exhaustive investigations of Class I well (i.e.,
hazardous waste disposal well) failures and has found no evidence of
release of injected fluids through two strings of casing. However, the
Agency is aware that some Class II wells were constructed with only one
string of casing; therefore, the scenarios modeled fall within the realm
of possible failures. Since integrity of the casing must be tested every
5 years under current EPA guidelines (more frequently by some States),
EPA assumed for the conservative scenarios that a release would begin on
the first day after the test and would last until the next test (i.e.,
5 years). For the best-estimate scenarios, EPA assumed that the release
lasted 1 year (the minimum feasible modeling period) in the case of
waterflood wells and 3 years in the case of disposal wells, on the
supposition that shorter release durations would be more likely for
V-19
-------
waterflooding where injection .flow rates and volumes are important
economic considerations for the operation. EPA also assumed here that
the release flow from a failed well would remain constant over the
duration of the failure. This simplifying assumption is more likely to,
hold in low-pressure wells than in the high-pressure wells more typical
of waterflcoding operations. In high-pressure wells the high flow rate
would likely enlarge the casing holes more rapidly, resulting in more
injection fluid escaping into the wrong horizon and a noticeable drop of
pressure in the reservoir.
For the grout seal type of failure, EPA estimated for conservative
modeling purposes that the failure could last for 20 years (i.e., as long
as the well operates). This is not an unreasonable worst-case assumption
because the current regulations allow the use of cementing records to
determine adequacy of the cement job, rather than actual testing through
the use of logs. If the cementing records were flawed at the outset, a
cementing failure might remain undetected. As part of -its review of the .
Underground Injection Control (UIC) regulations, the Agency is considering
requiring more reliable testing of the cementing of wells, which would
considerably lessen the likelihood of such scenarios. For an alternative
best-estimate scenario, the Agency assumed a 5-year duration of failure
as a more typical possibility.
Because of a lack of both data.and adequate modeling methods, other
potentially important migration pathways by which underground injection
of waste could contaminate surface aquifers (e.g., upward contaminant
migration from the injection zone through fractures/faults in confining
layers or abandoned boreholes) were not modeled.
Chemical transport was modeled for ground water and surface water
(rivers). Ground-water flow and mass transport were modeled using EPA's
Liner Location Risk and Cost Analysis Model (LLM) (USEPA 1986). The LLM
V-20
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uses a series of predetermined flow field types to define ground-water
conditions (see Table V-7); a transient-source, one-dimensional,
wetting-front model to assess unsaturated zone transport; and a modified
version of the Random Walk Solute Transport Model (Prickett et al. 1981}
to predict ground-water flow and chemical transport in the saturated
zone. All ground water exposure and risk estimates presented in this
report are for the downgradient center line plume concentration.
Chemical transport in rivers was modeled using equations adapted from EPA
(USEPA 1984a); these equations can account for dilution, dispersion,
particulate adsorption, sedimentation, degradation (photolysis,
hydrolysis, and biodegradation), and volatilization.
EPA used the LLM risk submodel to estimate cancer and chronic
noncancer risks from the ingestion of contaminated ground and surface
water. The measure used for cancer risk was the maximum (over the
200-year modeling period) lifetime excess7 individual risk, assuming an
individual ingested contaminated ground or surface water over an entire
lifetime (assumed to be 70 years). These risk numbers represent the
estimated probability of occurrence of cancer in an exposed individual.
For example, a cancer risk estimate of 1 x 10" indicates that the
chance of an individual getting cancer is approximately one in a million
over a 70-year lifetime. The measure used for noncancer risk was the
maximum (over the 200-year modeling period) ratio of the estimated
chemical dose to the dose of the chemical at which health effects begin
to occur (i.e., the threshold dose). Ratios exceeding 1.0 indicate the
potential for adverse effects in some exposed individuals; ratios less
than 1.0 indicate a very low likelihood of effect (assuming that
background exposure is zero, as is done in this study). Although these
ratios are not probabilities, higher ratios in general are cause for
greater concern.
Excess refers to the risk increment attributable only to exposure resulting froni the
releases considered in this analysts. Background exposures were assumed to bt? ;ero.
V-21
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Table V-7 Definition of Fiow Fields Used tn Ground-yater Transport Modeling
variables defining flow field*
F1o«* field Aquifer conf tgyrat ion
Confined aquifer
Horizontal grounn-nater
velocity
A
5
C
D
E
F
Unconfined agyifer
UnconftneJ aqytfer
Unconfined aquifer
Unccnfinec! aquifer
Unconfined aquifer
Confined aqyifer
1 m/yr
10 m/yr
100 m/yr
1,000 m/yr
10,000 m/yr
0,05 m/yr >r» the confining layer and
100 «/yf within the aquifer
0.05 m/yr in the confining layer and
10 m/yr within the aquifer
Several other variables, such as porosity, distinguish tne flow fields, but the
variables listed here are the most important for the purpose of this preserttat ion,
In general, an aquifer is defined as a geological unit that can transmit
significant Qaant it IBS of water. An ynconfir.ed aquifer is one that is only partly
filled with water, such that the ypper surface of the saturated zone is free to
rise and decline. A confined aquifer is one that is completely filled with water
and that is 0¥erlain by a confining layer (a rock unit that restricts the movement
of groynd water).
V-22
-------
As a means of assessing potential effects on aquatic organisms, EPA
estimated, for each model scenario involving surface water, the volume
contaminated above an aquatic effects threshold. EPA also estimated the
volumes of ground and surface water contaminated above various resource
damage thresholds (e.g., the secondary drinking water standard for
chloride).
QUANTITATIVE RISK MODELING RESULTS: HUMAN HEALTH
This section summarizes the health risk modeling results for onsite
reserve pits (drilling wastes), underground injection wells (produced
water), and direct discharges to surface water (produced water, stripper
well scenarios only). Cancer risk estimates are presented separately
from noncancer risk estimates throughout. This section also summarizes
EPA's preliminary estimates of the size of populations that could
possibly be exposed through drinking water.
Onsite Reserve Pits—Drilling Hastes
Cancer and noncancer health risks were analyzed under both
best-estimate and conservative modeling assumptions for 1,134 model
scenarios8 of onsite reserve pits. Arsenic was the only potential
carcinogen among the constituents modeled for onsite reserve pits. Of
the noncarcinogens, only sodium exceeded its effect threshold; neither
cadmium nor chromium VI exceeded their thresholds in any model scenarios
(in its highest risk scenario, cadmium was at 15 percent of threshold;
chromium VI, less than 1 percent).
a
1,134 » 9 inf i Itrat ion/unsaturated zone types x 7 ground-water flo«» field types x 3
exposure distances x 3 size categories x 2 liner types.
V-23
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Nationally Weighted Risk Distributions
Figure V-3 presents the nationally weighted frequency distributions
of human healtn risk estimates associated with unlined onsite reserve
pits. The figure includes best-estimate and conservative modeling
results for both cancer (top) and noncancer (bottom) risks. Only the
results for unlined reserve pits are given because the presence or
absence of a liner had little influence on risk levels (see section on
major factors affecting health risk). Many of the scenarios in the
figure show zero risk because the nearest potential exposure well was
estimated to be more than 2 kilometers away (roughly 61 percent of all
scenarios).
Under best-estimate assumptions, there were no cancer risks from
arsenic because arsenic was not included as a constituent of the modeled
waste (i.e., the median arsenic concentration in the field sampling data
was below detection limits; see Table V-l), Under conservative
assumptions, nonzero cancer risks resulting.from arsenic were estimated
for 18 percent of the nationally weighted reserve pit scenarios, with
roughly 2 percent of the scenarios having cancer risks greater than
1 x 10" . Even under conservative modeling assumptions, drilling waste
pit scenarios produced maximum lifetime cancer risks of less than 1 in
100,000 for individuals drinking affected water.
A few threshold exceedances for sodium were estimated under both
best-estimate and conservative assumptions. Under best-estimate
assumptions, more than 99 percent of nationally weighted reserve pit
scenarios posed no noncancer risk (i.e., they were below threshold). A
few model scenarios had noncancer risks, but none exceeded 10 times the
sodium threshold. Under conservative assumptions, 98 percent of
nationally weighted reserve pit scenarios did not pose a noncancer risk.
The remaining 2 percent of reserve pit scenarios had estimated exposure
point sodium concentrations between up to 32 times the threshold.
V-24
-------
TJ
O
JC
J»
*
5
M
.2
§»
n
c
«
u
o
»•
c
*
o
CANCER (Arsenic)
Best-estimate
Assumptions
Conservative
Assumptions
-?
10
-6
10
Risk
.5 .4
10 10
-3 -2 -1
10 10 10 1
NONCANCER (Sodium)
Best-estimate
Assumptions
Conservative
Assumptions
10
2 3
10 10
Dose: Threshold Ratio
Figure V-3 Nationally Weighted Distribution of Health Risk
Estimates. Unlined Reserve Pits
¥-25
-------
Based on a literature review conducted as part of the development of
the Liner Location Model data base (USEPA 1986), chloride is the only
model .drilling waste constituent for which either a taste or odor
threshold concentration is known. EPA (1984b) reports that the taste
threshold for chloride is roughly 250 mg/L (i.e., this is the minimum
chloride concentration in water that a person may be able to taste). For
the highest cancer risk case, the maximum chloride concentration at the
exposure well was estimated to be 400 mg/L; for the highest noncancer
risk case, the maximum chloride concentration at the exposure well was
estimated to be approximately 5,000 mg/L. Therefore, it appears that, if
water contained a high enough arsenic concentration to pose cancer risks
on the order of 1 x 10 or sodium concentrations 100 times the effect
threshold, people may be able to taste the chloride that would also
likely be present. The question remains, however, whether people would
actually discontinue drinking water containing these elevated chloride
concentrations. EPA (1984b) cautions that consumers may become
accustomed to the taste of chloride levels somewhat higher than 250 mg/L.
For purposes of illustration, Figure V-4 provides an example of the
effect of weighting the risk results to account for the estimated
national frequency of occurrence of the model scenarios. Essentially,
weighting allows risk results for more commonly occurring scenarios to
"count" more than results from less commonly occurring scenarios.
Weighting factors were developed and applied for the following variables,
based on estimated frequency of occurrence at oil and gas sites: pit
size, distance to drinking water well, ground-water type, depth to ground
water, recharge, and subsurface permeability. Other potentially
important risk-influencing factors, especially waste composition and
strength, were not modeled as variables because of lack of information
and thus are not accounted for by weighting.
In the example shown in Figure V-4 (conservative-estimate cancer
risks for unlined onsite pits), weighting the risk results decreases the
¥-26
-------
01
a
c
0
O
CO
10 10 10 10
Risk
Figure V-4
Weighted vs. Unweighted Distribution of Cancer Risk
Estimates. Unlined Reserve Pits. Conservative
Modeling Assumptions
¥-27
-------
risk (i.e., shifts the distribution toward lower risk). This happens
primarily because close exposure distances (60 and 200 meters), which
correspond to relatively high risks, occur less frequently and thus are
less heavily weighted than greater distances. In addition, the effect of
pit size weighting tends to shift the weighted distribution toward lower
risk because small (i.e., lower risk) pits occur more frequently and are
thus more heavily weighted. These factors override the effect of flow
field weighting, which would tend to shift the distribution toward higher
risk because the high-risk flow fields for arsenic (C and D) are heavily
weighted. The national weightings of recharge, depth to ground water,
and subsurface permeability probably had little overall impact on the
risk distribution (i.e., if weighted only for these three factors, the
distribution probably would not differ greatly from unweighted). All
weighting factors used are given in Appendix B of the EPA technical
support document (USEPA 1987a).
Zone-Weighted Risk Distributions
Overall, differences in risk distributions among zones were
relatively small. Cancer risk estimates under best-estimate modeling
assumptions were zero for all zones. Under conservative assumptions, the
cancer risk distributions for zones 2 (Appalachia), 4 (Gulf), 6 (Plains),
and 7 (Texas/Oklahoma) were slightly higher than the distribution for the
nation as a whole. The cancer risk distributions for zones 5 (Midwest),
8 (Northern Mountain), 9 (Southern Mountain), 10 (West Coast), and 11B
(Alaska, non-North Slope) were lower than the nationally weighted
distribution; zones 10 and 11B were much lower. The risk distributions
for individual zones generally varied from the national distribution by
less than one order of magnitude.
Noncancer risk estimates under best-estimate modeling assumptions
were extremely low for all zones. Under conservative assumptions, zones
2, 4, 5, 7, and 8 had a small percentage (1 to 10 percent) of weighted
V-28
-------
scenarios with threshold exceedances for sodium; other zones had less
than 1 percent. There was little variability in the noncancer risk
distributions across zones.
The reasons behind the differences in risks across zones are related
to the zone-specific relative weightings of reserve pit size, distance to
receptor populations, and/or environmental variables. For example, the
main reason zone 10 has low risks relative to other zones is that
92 percent of drilling sites were estimated to be in an arid setting
above a relatively low-risk ground-water flow field having an aquitard
(flow field F). Zone 11B has zero risks because all potential exposure
welljs were estimated to be more than 2 kilometers away.
In summary, differences in cancer risks among the geographic zones
were not great. Cancer risks were only prevalent in the faster aquifers
(i.e., flow fields C, D, and E, with C having the highest cancer risks).
Zone 4, with the highest cancer risks overall, also was assigned the
highest weighting among the zones for flow field C. Noncancer risks
caused by sodium were highest in zone 5. Noncancer risks occurred only
in the more slow-moving flow fields (i.e., flow fields A, B, and K, with
A having the highest noncancer risks); among the zones, zone 5 was
assigned the highest weighting for flow field A. EPA considered the
possible role of distributions of size and distance to exposure points,
but determined that aquifer configuration and velocity probably
contributed most strongly to observed zone differences in estimates of
human health risks. The consistent lack of risk for zone 11B, however,
is entirely because of the large distance to an exposure point. (See the
section that follows on estimated population distributions.)
Evaluationof Major Factors Affecting HealthRisk
EPA examined the effect of several parameters related to pit design
and environmental setting that were expected to influence the release and
V-29
-------
transport of contaminants leaking from onsite reserve pits. To assess
the effect of each of these parameters in isolation, all other parameters
were held constant for the comparisons. The results presented in this
section are not weighted according to either national or zone-specific
frequencies of occurrence. Instead, each model scenario is given equal
weight. Thus, the following comparisons are not appropriate for drawing
conclusions concerning levels of risk for the national population of
onsite reserve pits. They are appropriate for examining the effect of
selected parameters on estimates of human health risk.
The presence or absence of a conventional, single synthetic liner
underneath an onsite reserve pit had virtually no effect on the 200-year
maximum health risk estimates. A liner does affect timing of exposures
and risks, however, by reducing the amounts of leachate (and chemicals)
released early in the modeling period. EPA's modeling assumed a single
synthetic liner with no leak detection or leachate collection. (Note
that this is significantly different from the required Subtitle C liner
system design for hazardous waste land disposal units.) Furthermore, EPA
assumed that such a liner would eventually degrade and fail, resulting in
release of the contaminants that had been contained. Thus, over a long
modeling period, mobile contaminants that do not degrade or degrade very
slowly (such as the ones modeled here) will produce similar maximum risks
whether they are disposed of in single-synthetic-lined or unlined pits
(unless a significant amount of the contained chemical is removed, such
as by dredging). This finding should not be interpreted to discount the
benefit of liners in general. Measures of risk over time periods shorter
than 200 years would likely be lower for lined pits than for unlined
ones. Moreover, by delaying any release of contaminants, liners provide
the opportunity for management actions (e.g., removal) to help prevent
contaminant seepage and to mitigate seepage should it occur.
V-30
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Figure V-5 represents unweighted risks associated with unlined
reserve pits under the conservative modeling assumptions for three
reserve pit sizes and three distances to the exposure point. Each
combination of distance and reserve pit size includes the risk results
from all environmental settings modeled (total of 63), equally weighted.
Figure V-5 shows that the unweighted risk levels decline with increasing
distance to the downgradient drinking water well. The decline is
generally less than an order of magnitude from 60 to 200 meters, and
greater than an order of magnitude from 200 to 1,500 meters. Median
cancer risk values exceed 10" only at the 60-meter distance, and
median dose-to-threshold ratios for noncancer effects exceed 1.0 only for
large pits at the 60-meter distance. Risks also decrease as reserve pit
size decreases at all three distances, although risks for small and large
pits are usually within the same order of magnitude.
Figure V-6 compares risks across the seven ground-water flow field
types modeled in this analysis. Both cancer and noncancer, risks vary
substantially across flow fields. The noncancer risks (from sodium) are
greatest in the slower moving flow fields that provide less dilution
(i.e., flow fields A, B» and K), while the cancer risks (from arsenic)
are greatest in the higher velocity/higher flow settings (i.e., flow
fields C, D, and E). Sodium is highly mobile in ground water, and it is
diluted to below threshold levels more readily in the high-velocity/
high-flow aquifers. Arsenic is only moderately mobile in ground water
and tends not to reach downgradient exposure points within the 200-year
modeling period in the slower flow fields. If the modeling period were
extended, cancer risks resulting from arsenic would appear in the more
slowly moving flow field scenarios.
As would be expected, both cancer and noncancer risks increased with
increasing recharge rate and with increasing subsurface permeability.
Risk differences were generally less than an order of magnitude. Depth
to ground water had very little effect on the 200-year maximum risk,
V-31
-------
CANCER
•• MEDIAN
I — I soth %
n
S LMS LMS
200 1500
Distance to Well Cm)
PIT SIZE
QC
2
o
m
o
(0
o
o
104
10s
102
101
1
10'1
10-2
10*3
10'4
ID'6
10'8
NONCANCER
LMS LMS LMS
60 200 1500
Distance to Well (m)
PIT SIZE
L •- Large, M - MBdlum, S * Small Reserve P»ts
Figure V-5
Health Risk Estimates (Unweighted) as a Function of
Size and Distance. Unlined Reserve Pits.
Conservative Modeling Assumptions
V-32
-------
1
10-i -
tO 2 -
10 3 -
10 * -
10-6 -
io-r-
CANCER (Arsenic)
Median
fer-3 S3 '
-t A -ft -I f*"S?jJ ^yV*^ fy"^%l i
t0-9 -
10-io J
*"$&, p&S- x"$l '
il ^ ^
E^ 188% PX>Q Syi
B C D E F
Ground-Water Flow Field Type
K
104
103"
O i **
i 10'"
1 1
i»
H 10-2.
S io-3-
O
1 O-«
!
i
t
NONCANCER (Sodium)
Median
i
I
I
y//
l
'%
^
>A I
\ 'i
4
1/1 /
'j l
' J
B C D E F
Ground-Water Flow Field Type
Figure V-6
Health Bisk Estimates (Unweighted) as a Function of
Ground-Water Type. Unlined Reserve Pits (Large).
60-Meter Exposure Distance. Conservative Modeling
Assumptions
V-33
-------
although risks were slightly higher for shallow ground-water settings.
This lack of effect occurs because the risk-producing contaminants are at
least moderately mobile and do not degrade rapidly, if at all; thus, the
main effect observed for deeper ground-water settings was a delay in
exposures.
Underground Injection—Produced Hater
Cancer and noncancer health risks were analyzed under both best-
estimate and conservative modeling assumptions for 168 model Class II
underground injection well scenarios," Two injection well types
were differentiated in the modeling: waterflooding and dedicated
disposal. Design, operating, and regulatory differences between the two
types of wells possibly could affect the probability of*failure, the
probability of detection and correction of a failure, and the likely
magnitude of release given a failure.
Two types of injection well failure mechanism were modeled: grout
seal failure and well casing failure. All results presented here assume
that a failure occurs; because of a lack of sufficient information, the
probability of either type of failure mechanism was not estimated and
therefore was not directly incorporated into the risk estimates. If
these types of failure are low-frequency events, as EPA believes, actual
risks associated with them would be much lower than the conditional risk
estimates presented in this section. No attempt was made to weight risk
results according to type of failure, and the two types are kept separate
throughout the analysis and discussion.
National 1_y Weighted Risk pistrlbutions
The risk estimates associated with injection well failures were
weighted based on the estimated frequency of occurrence of the following
166 = 7 ground-water flov» field types x 3 exposure distances x 2 size categories x 2 well
types x 2 failure mechanisms.
V-34
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variables: injection well type, distance to nearest drinking water well,
and ground-water flow field type. In addition, all risk results for
grout seal failure were weighted based on injection rate. As for reserve
pits, insufficient information was available to account for waste
characteristics and other possibly important variables by weighting.
Grout seal failure: Best-estimate cancer risks, given a grout seal
failure, were estimated to be zero for more than 85 percent of the model
scenarios. The remaining scenarios had slightly higher risks but never
did the best-estimate cancer risk exceed 1 x 10 . Under conservative
assumptions, roughly 65 percent of the scenarios were estimated to have
zero cancer risk, while the remaining 35 percent were estimated to have
-4
cancer risks ranging up to 4 x 10 (less than 1 percent of the
4
scenarios had greater than 1 x 10 risk). These modeled cancer risks
were attributable to exposure to two produced water constituents, benzene
and arsenic. Figure V-7 {top portion) provides a nationally weighted
frequency distribution of the best-estimate and conservative-estimate
cancer risks, given a grout seal failure. Figure V-7 shows the combined
distribution for the two well types and two injection rates considered in
the analysis, the three exposure distances, and the seven ground-water
settings. As with drilling pits, many of the zero risk cases were
because the nearest potential exposure well was estimated to be more than
2 kilometers away (roughly 64 percent of all scenarios).
Modeled noncancer risks, given a grout seal failure, are entirely
attributable to exposures to sodium. There were no sodium threshold
exceedances associated with grout seal failures under best-estimate
conditions. Under conservative conditions, roughly 95 percent of the
nationally weighted model scenarios also had no noncancer risk. The
remaining 5 percent had estimated sodium concentrations at the exposure
point that exceeded the effect threshold, with the maximum concentration
exceeding the effect threshold by a factor of 70. The nationally
V-35
-------
•o
*
**
S
*•
c
o
o
e
•
u
CANCER (Arsenic and Benzene)
Best-estimate
Assumptions
Conservative
Assumptions
I I I I I I I
-10 -9 -t -7 -6 -S -4 -3 -2 -1
1 10 10 10 10 10 10 10 10 10 10 1
Risk
NONCANCER (Sodium)
1 10
10 10 10 10 1
Do**: Threshold Ratio
Best-estimate
Assumptions
Conservative
Assumptions
i
10
10 10
Figure V-7 Nationally Weighted Distribution of Health Risk
Estimates. Underground Injection Wells: Grout Seal
Failure Assumed
V-36
-------
weighted frequency distribution of the estimated dose/threshold ratios
for sodium is shown in the boitont portion of Figure V-7.
•
Data are available on the taste and odor thresholds of two produced
water model constituents: benzene and chloride. For the maximum cancer
risk scenario assuming a grout seal failure, the estimated concentrations
of benzene and chloride at the exposure well were below their respective
taste and odor thresholds. However, for the maximum noncancer risk
scenario assuming a grout seal failure, the estimated chloride
concentration did exceed the taste threshold by roughly a factor of
three. Therefore, people might be able to taste chloride in the highest
noncancer risk scenarios, but it is questionable whether anybody would
discontinue drinking water containing such a chloride concentration.
We11 casing failure: The nationally weighted distributions of
estimated cancer and noncancer risks, given an injection well casing
failure, are presented in Figures V-8 and V-9. Figure V-8 gives the risk
distributions for scenarios with high injection pressure, and Figure V-9
gives the risk distributions for scenarios with low injection pressure.
(Because of a lack of adequate data to estimate the distribution of
injection pressures, results for the high and low pressure categories
were not weighted and therefore had to be kept separate.)
Best-estimate cancer risks, given a casing failure, were zero for
approximately 65 percent of both the high and low pressure scenarios; the
remaining scenarios had cancer risk estimates ranging up to 5 x 10"
for high pressure and 1 x 10 for low pressure. The majority
(65 percent) of both high and low pressure scenarios also had no cancer
risks under the conservative assumptions, although approximately
5 percent of the high pressure scenarios and 1 percent of the low
pressure scenarios had conservative-estimate cancer risks greater than
-4 4
1 x 10 (maximum of 9 x 10 ). The rest of the scenarios had
conservative-estimate cancer risks greater than zero and less than
1 x 10"4.
V-37
-------
CANCER (Arsenic and Benzene)
Best-estimate
Assumptions
Conservative
Assumptions
10
1 1 i I I
< ,_,_-10 ., _-8 -8 -? -§ -S -4 -3 -2 -1
- 10 10 10 10 10 10 10 10 10 10 1
Risk
1QO
90
5 80
**
f 70
-» 60
CD
I 50
* .
£ 40
o
7:
o
k.
e
a.
30
20
10
NONCANCER (Sodium)
- 10 10 10 10 10 10
Best-estimate
Assumptions
Conservative
Assumptions
Dos*: Threshold Ratio
Figure V-8 Nationally Weighted Distribution of Health Risk
Estimates. High Pressure Underground Infection
Wells: Casing Failure Assumed
V-38
-------
•o
e
JC
*e
5
%•*
•
_o
e
*
Q.
90
80
70
60
50
40
20
10
CANCER (Arsenic and Benzene)
•S 30 -
Best-estimate
Assumptions
Conservative
Assumptions
1 10'1° 10'9 to'8 TO'7 10'6 1Q-S ID'4 1Q-3 10'2
Risk
1 10
-s
i
10"
NONCANCER (Sodium)
-4
10 10 10 10 1
Dose: Threshold Ratio
Best-estimate
Assumptions
Conservative
Assumptions
2 3
10 10
Figure V-9 Nationally Weighted Distribution of Health Risk
Estimates. Low Pressure Underground Injection Wells:
Casing Failure Assumed
V-39
-------
For noncancer effects, there were few threshold exceedances for
sodium under best-estimate assumptions, and the highest exceedanee was by
less than a factor of five. Under conservative assumptions, there were
more numerous exceedances of the threshold, given a well casing failure.
Approximately 22 percent of the nationally weighted high pressure
scenarios were estimated to exceed the sodium threshold, never by more
than a factor of 70. Approximately 14 percent of low pressure scenarios
were estimated to exceed the sodium threshold, never by more than a
factor of 35.
As was the case with grout seal failures, it does not appear that
people would taste or smell chloride or benzene in the maximum cancer
risk scenarios assuming casing failures (i.e., people would probably not
refuse to drink water containing these concentrations). For the maximum
noncancer risk scenarios, "sensitive individuals may be able to taste
chloride or smell benzene. It is uncertain whether people would
discontinue drinking water at these contaminant levels, however.
Zone-Weighted Risk Distributions
In general, the estimated cancer and noncancer risk distributions
associated with injection well failures (both grout seal and casing
failures) varied little among zones. Differences in risk across zones
were primarily limited to the extremes of the distributions (e.g., 90th
percentile, maximum).
The cancer risk distributions for both grout seal and casing failures
in zones 2 and 5 were siIqhtly higher than the distribution for the
nation as a whole. This is primarily because of the relatively short
distances to exposure wells in these two zones (compared to other
zones). In contrast, zones 8 and 11B had cancer risk distributions for
injection well failures that were slightly lower than the national
V-40
-------
distribution. This difference is primarily because of the relatively
long distance to exposure wells in these zones. (For almost 80 percent
of production sites in both zones, it was estimated that the closest
exposure well was more than 2 kilometers away.) A similar pattern of
zone differences was observed for the noncancer risk results.
Eva!uation of Major Factors Affecting Health Risk
In general, estimated risks associated with well casing failure are
from one to two orders of magnitude higher than risks associated with
grout seal failure. This is because under most conditions modeled, well
casing failures are estimated to release a greater waste volume, and thus
a larger mass of contaminants, than grout seal failures.
The risks estimated for disposal and waterflood wells are generally
similar in magnitude. For assumed casing failures, waterflood wells are
estimated to cause slightly (no more than a factor of 2,5 times) higher
risks than disposal wells. This pattern is the net result of two
differences in the way waterflood and disposal wells were modeled. The
release durations modeled for disposal wells are longer than those for
waterflood wells, but the injection pressures modeled for waterflood
wells are greater than those modeled for disposal wells. For assumed
grout seal failures, disposal wells are estimated to cause slightly (no
more than a factor of 3 times) higher risks than waterflood wells. This
pattern results because the injection rates modeled for disposal wells
are up to 3 times greater than those modeled for waterflood wells.
The distance to a potentially affected exposure well at an injection
site is one of the most important indicators of risk potential. If all
other parameters remain constant, carcinogenic risks decline slightly
less than one order of magnitude between the 60-meter and 200-meter well
distances; carcinogenic risks decline between one and two orders of
V-41
-------
magnitude from the 200-meter to the 1,500-meter well distances. The
effect of well distance is a little less pronounced for noncarcinogenie
risks. Sodium threshold exceedances drop by less than an order of
magnitude between the 60-meter and 200-meter well distances and by
approximately one order of magnitude between the 200 meter and
1,500-meter well distances. The reduction in exposure with increased
distance from the well is attributable to three-dimensional dispersion of
contaminants within the saturated zone. In addition, the 200-year
modeling period limits risks resulting from less mobile constituents at
greater distances (especially 1,500 meters). Degradation is not a factor
because the constituents producing risk degrade very slowly (if at all)
in the saturated zone.
Cancer and noncancer risk estimates decrease with decreasing
injection rate/pressure. This relationship reflects the dependence of
risk upon the total chemical mass released into the aquifer each year,
which is proportional to either the assumed injection flow rate (grout
seal failure) or pressure (casing failure-).
Figure V-10 shows how the unweighted health risk estimates associated
with injection well casing failures varied for the different ground-water
flow fields. The figure includes only results for the conservative
modeling assumptions, the high injection pressure, and the 60-meter
modeling distance, because risk estimates under best-estimate assumptions
and for other modeling conditions were substantially reduced and less
varied. As shown, conservative-estimate carcinogenic risks ranged from
roughly 2 x 10 (for flow field F) to approximately 6 x 10 (for
flow field D). The difference in the risk estimates for these two flow
fields is due primarily to their different aquifer configurations. Flow
field D represents an unconfined aquifer, which is more susceptible to
contamination than a confined aquifer setting represented by flow field F.
V-42
-------
10'2-
10-3-
10'6~
10-7-
10-*-
-,0
-10-1-
CANCER (Arsenic and Benzene)
B C D E F
Ground-Water Flow Field Type
K
n
tt
m
9
e
M
o
O
10
3_
10
10
10 '-
1 -
10'1-
10"2-
10
-s
NONCANCER (Sodium)
B C D E F
Ground-Water Flow Field Type
K
Figure V-10 Health Risk Estimates (Unweighted) as a Function of
Ground-Water Type. High Pressure Underground
Injection Wells: Casing Failure Assumed. 60-Meter
Exposure Distance. Conservative Modeling
Assumptions
V-43
-------
The ground-water flow field also influenced the potential for
noncarcinogenic effects. The conservative-estimate sodium concentrations
at 60 meters exceeded the threshold concentration by a factor ranging up
to 70 times. The unconfined flow fields with slow ground-water
velocities/low flows (A, B, C) produced the highest exceedances, which
can be attributed to less dilution of sodium in these flow fields.
Direct Discharge of Produced Hater to Surface Streams
Cancer and noncancer risks were analyzed under both best-estimate and
conservative waste stream assumptions {see Table V-l) for a total of
18 model scenarios of direct discharge of stripper well-produced fluids
to surface waters. These scenarios included different combinations of
three discharge rates (1, 10, and 100 barrels per day), three downstream
distances to an intake point (the length of the mixing zone,
5 kilometers, and 50 kilometers), and two surface water flow rates (40
and 850 cubic feet per second, or ft /s). The discharges in these
scenarios were assumed to be at a constant rate over a 20-year period.
Results presented for the stripper well scenarios are unweighted because
frequency estimates for the parameters that define the scenarios were not
developed.
For the best-estimate waste stream, there were no cancer risks
greater than 1 x 10 estimated for any of the scenarios. However,
cancer risks greater than 1 x 10" were estimated for 17 percent of the
scenarios with the conservative waste stream—the maximum was 3.5 x
10" (for the high-rate discharge into the low-flow stream, and a
drinking water intake immediately downstream of the discharge point).
These cancer risks were due primarily to exposure to arsenic, although
benzene also contributed slightly. For noncancer risks, none of the
scenarios had a threshold exceedance for sodium, regardless of whether
the best-estimate or conservative waste stream was assumed.
V-44
-------
EPA recognizes that the model surface water flow rates (40 and
850 ft /$) are relatively high and that discharges into streams or
rivers with flow rates less than 40 ft /s could result in greater risks
than are presented here. Therefore, to supplement the risk results for
the model scenarios, EPA analyzed what a river or stream flow rate would
have to be (given the model waste stream concentrations and discharges
rates) in order for the contaminant concentration in the nixing zone
(assuming instantaneous and complete mixing but no other removal
processes) to be at certain levels.
The results of this analysis, presented in Table V-8, demonstrate
that reference concentrations of benzene would be exceeded only in very
low-flow streams (i.e., less than 5 ft /s) under all of the model
conditions analyzed. It is unlikely that streams of this size would be
used as drinking water sources for long periods of time. However,
concentrations of arsenic and sodium under conservative modeling
conditions could exceed reference levels in the mixing zone in relatively
large streams, which might be used as drinking water sources. The
concentrations would be reduced at downstream distances, although
estimates of the surface water flow rates corresponding to reference
concentrations at different distances have not been made.
Potentially Exposed Population
Preliminary estimates of the potentially exposed population were
developed by estimating the number of individuals using private drinking
water wells and public water supplies located downgradient from a sample
of oil and gas wells. These estimates were based on data obtained from
local water suppliers and 300 USGS topographic maps. One hundred of the
maps were selected from areas containing high levels of drilling activity,
and 200 were selected from areas containing high levels of production.
V-45
-------
Table V-8 Surface Water Flow Rates At Which Concentrations of Waste Stream
Constituents in thfe Mixing Zone Will Exceed Reference Levels3
Concentrat ion
Const Hyent in waste
Arsenic Median
90th %
8enzer.e Hedtan
90th %
Sodium Median
90th X
Waste streaip rf'scharoe r=.te
High • Medium Low
(100 BPD) (10 BPO) (1 BPD}
3 b 3 3
<. 5 ft /s ^0.5 ft /s <. ,05 ft /$
33 3
<. 470 ft /s <. 50 ft /s i 5 ft /s
333
<. 1 ft /s i 0.1 ft /s ^ 0.01 ft /s
3 3 3
i 3 ft /s 1 0,3 ft /s l 0 03 ft is,
333
<. 3 ft /s i 0,3 ft /s f. 0.03 ft /s
333
i 20 ft /s i 2 ft /s £ 0.2 ft /s
The reference levels referred to are the arsenic and benzene concentrations
that correspond to a 1 x 10 lifetime cancer risk level (assuming a ?Q-kg
individual ingests 2 L/d) and EPA's suggested guidance level for sodium for the
prevention of hypertension in hign-risk individuals.
Should be interpreted to mean that the concentration of arsenic in the miking
zone would exceed the 1 x 10 lifetime cancer risk level if the receiving
Stream or river was flowing at a rate of 5 ft /s or lower. If the stream or
river was flowing at a higher rate, then the maximum concentration of arsenic
would not exceed the 1 x 10 lifetime cancer risk level.
V-46
-------
Table V-9 summarizes the sample results for the population potentially
exposed through private drinking water wells. As shewn in this table,
over 60 percent of the oil and gas wells in both the drilling and
production sample did not have private drinking water wells within 2,000
meters downgradient and only 2 percent of the oil and gas wells were
estimated to have private drinking water wells within the 60-meter (i.e.,
higher-risk) distance category. Moreover, the numbers of potentially
affected people per oil and gas well in the 60-meter distance category
were relatively small. One other interesting finding demonstrated in
Table V-9 is that fewer potentially affected individuals were estimated
to be in the 1,500-meter distance category than in the 200-meter
category. This situation is believed to occur because some residences
located farther from oil and gas wells were on the other side of surface
waters that appeared to be a point of ground-water discharge.
The sample results for the population potentially exposed through
public water supplies are summarized in Table V-10. These results show a
pattern similar to those for private drinking water wells; this is, most
oil and gas wells do not have public water supply intakes within 2,000
meters and of those that do only a small fraction have public water
supply intakes within the 60-meter distance category.
The results in Tables V-9 and V-10 are for the nation as a whole.
Recognizing the limitations of the.sample and of the analysis methods,
EPA's data suggest that zone 2 (Appalachia) and zone 7 (Texas/Oklahoma)
have the greatest relative number of potentially affected individuals per
oil and gas well (i.e., potentially affected individuals are, on the
average, closer to oil and gas wells in these zones relative to other
zones). In addition, zone 4 (Gulf) has a relatively large number of
individuals potentially affected through public water supplies. Zone 11
(Alaska) and zone 8 (Northern Mountain) appear to have relatively fewer
potentially affected individuals per oil and gas well. Further
V-47
-------
Table V-9 Population Potentially Exposed Through Private Or ink. ing
Hater Wells at Sample Drilling and Production Areas
Distance
category3
Drillmo sample results
Production sawcle results
to- I'M) of 01 I/gas
•ells »un private
drinking water
wel Is within
distance category
Maximum no, of
potentially affected
indiv idtwls per oil
and gas wel 1
No. (X) of oil/gas
••ells with private
drinking water
wells within
distance category
Ffaximum no. of
potentially affected
individuals per oi1
and gas wel1
60 neters
200 meters
1 , 530 meters
>Z.OOO meters
561(2)
4,765(17)
5.606IJO)
1 7.01»6(61)
0.11
0.44
0-32
HAC
64212)
5,139(16)
5.450(1?)
20,879(65}
0.17
O.S8
0.38
NA
Drinking water wells were counted as CO meters downgradient if they were within 0 ar.d 130 meters, were
coynted «js 200 twters dowogradtent if they were within 130 and 800 meters, and were counted as 1,500 meters
downgradiem if they .were within 800 and 2,000 aietcrs.
These ratios largely overestimate the number of people actually affected per oil and gas well (see text) and
should be used to estimate the total numoer of people affected only with caytton. The figures are intended
simply lo give a preliminary indication of the potential1y exposed population and the distribution of that
popylation in different distance categones.
ctot available; distances greater than 2,000 weters front oil and gas wells were not modeled.
V-48
-------
Table V-10 Pspalatton Poietnia1!,y Exposed Through Public Uaier
Supplies at Sample Drilling and Production Areas
Distance
category
Drillir.a
0 redact
-------
discussion of the differences in population estimates across zones is
provided in the supporting technical report (USEPA 1987a).
*
The number of potentially affected people per oil and gas well in
Tables V-9 and V-10 represents the maximum number of people in the sample
that coyld be affected if all the oil and gas wells in the sample
resulted in ground-water contamination out to 2,000 meters. The number
of persons actually affected is probably much smaller because ground
water may not be contaminated at all (if any) of the sites, some of the
individuals may rely on surface water or rainwater rather than on ground
water, and some of the individuals and public water supplies may not have
drinking water wells that are hydraulically connected to possible release
sources. Also, the sample population potentially exposed through public
water supplies is probably far less than estimated, because public water
is frequently treated prior to consumption (possibly resulting in the
removal of oil and gas waste contaminants) and because many supply systems
utilize multiple sources of water, with water only at times being drawn
from possibly contaminated sources. Therefore, these ratios largely
overestimate the number of people actually exposed per oil and gas well
and should be used to estimate the total number of people affected only
with caution. The figures are intended simply to give a preliminary
indication of the potentially exposed population and the distribution of
that population in different distance categories,
QUANTITATIVE RISK MODELING RESULTS: RESOURCE DAMAGE
For the purposes of this study, resource damage is defined as the
exceedance of pre-set threshold (i.e., "acceptable") concentrations for
individual contaminants, based on levels associated with aquatic
toxicity, taste and odor, or other adverse impacts. Potential
ground-water and surface water damage was measured as the maximum (over
the 200-year modeling time period) annual volume of contaminated water
V-50
-------
flowing past various points downgradient or downstream of the source.
Only the volume of water that exceeded a damage threshold concentration
was considered to be contaminated. This measure of potential
ground-water and surface water damage was computed for each of three
distances downgradient or downstream from a source: 60, 200, and
1,500 meters.
These estimates of resource damage supplement, but should be
considered separate from, the damage cases described in Chapter IV. The
resource damage results summarized here are strictly for the model
scenarios considered in this analysis, which represent: (1) seepage of
reserve pit wastes; (2) releases of produced water from injection well
failures; and (3) direct discharge of produced water from stripper wells
to streams and rivers. While these releases may be similar to some of
the damage cases described in Chapter IV, no attempt was made to
correlate the scenarios to any given damage case(s). In addition,
Chapter IV describes damage cases from several types of releases (e.g.,
land application) that were not modeled as part of this quantitative risk
analysis.
Potential Ground-Mater Damage--Drilling Wastes
Two contaminants were modeled for ground-water resource damage
associated with onsite reserve pits. These contaminants were chloride
ions in concentrations above EPA's secondary maximum contaminant level
and total mobile ions (TMI) in concentrations exceeding the level of
total dissolved salts predicted to be injurious to sensitive and
moderately sensitive crops. Chloride is highly mobile in ground water
and the other ions were assumed to be equally mobile.
On a national basis, the risks of significant ground-water damage
were very low for the model scenarios included in the analysis. Under
V-51
-------
the best-estimate modeling assumptions, only 2 percent of nationally
weighted reserve pit scenarios were estimated to cause measurable
ground-water damage at 60 meters resulting from TMI. Under the
conservative modeling assumptions, less than 10 percent of reserve pits
were associated with ground-water plumes contaminated by chloride and TMI
at 60 meters and fewer than 2 percent at 200 meters. On a regional
basis, the upper 90th percentile of the distributions for resource
damage, under conservative modeling assumptions, were above zero for
zones 2, 5, and 8, This zone pattern is similar to the zone pattern of
noncancer human health risks from sodium. Flow field A was more heavily
weighted for these three zones than for the remaining zones, and this
flow field also was responsible for the highest downgradient
concentrations of sodium of all the flow fields modeled.
The mobilities of chloride and total mobile salts in ground water
were the ssnie as the mobility of sodium, which was responsible for the
noncancer human health risks. Thus, the effects of several pit design
and environmental parameters on the volume of ground water contaminated
above criteria concentrations followed trends very similar to those
followed by the noncancer human health risks. These parameters included
reserve pit size, net recharge, subsurface permeability, and depth to
ground water. In contrast to the trend in noncancer human health risks,
however, the magnitude of resource damage sometimes increased with
increasing distance from the reserve pit. This is because contaminant
concentrations (and thus health risks) decrease with distance traveled;
however, the width"of a contaminant plume (and thus the volume of
contaminated water) increases up to a point with distance traveled.
Eventually, however, the center line concentration of the plume falls
below threshold, and the estimated volume of contaminated water at that
distance falls to zero. Finally, as was the case with noncancer human
health risks, only the slower aquifers were associated with significant
estimates of resource damage.
V-52
-------
Potential Ground-Water Damage--Produced Water
As they were for drilling wastes, chloride and total mobile ions were
modeled to estimate ground-water resource damage associated with
underground injection of produced water. Under best-estimate conditions,
the risk of ground water becoming contaminated above the thresholds if
injection well casing failures were to occur was negligible. Furthermore,
in all but a few scenarios (approximately 1 percent of the nationally
weighted scenarios), the resource damage estimates did not exceed zero
under conservative assumptions. Estimated resource damage was almost
entirely confined to the 60-meter modeling distance.
Grout seal failures were estimated to pose a slightly smaller risk of
contaminating ground water above the chloride or TMI thresholds than
injection well casing failures. In roughly 99 percent of the nationally
weighted scenarios, grout seal failures never resulted in threshold
exceedances, regardless of the set of conditions assumed (best-estimate
vs. conservative) or the downgradient distance analyzed. Again, estimated
resource damage was almost entirely confined to the 60-meter modeling
distance.
In general, injection well failures were estimated to contaminate
larger volumes of ground water above the damage criteria under conditions
involving higher injection rates/pressures and lower ground-water
velocities/flows (i.e., flow fields A, B, C, and K). The estimated TMI
concentration exceeded its threshold for the low injection rate very
rarely, and only out to a distance of 60 meters. Chloride and TMI
threshold exceedances were limited almost exclusively to conditions
involving the high injection rate or pressure. The slower velocity/lower
flow ground-water settings permit less dilution (i.e., a higher
probability of threshold exceedance) of constituents modeled for resource
damage effects. In a trend similar to that observed for health risks,
V-53
-------
waterflood wells were estimated to contaminate larger volumes of ground
water than disposal wells under conditions involving casing failures, but
disposal wells were estimated to contaminate larger volumes under
conditions involving grout seal failures. Finally, the resource damage
estimates for injection well failures (and also for reserve pit leachate)
indicate that TMI is a greater contributor to ground-water contamination
than chloride. The reason for this difference is that the mobile salts
concentration in the model produced water waste stream is more than three
times the chloride concentration (see Table V-l), while the resource
damage thresholds differ by a factor of two (see Table V-2).
Potential Surface Water Damage
EPA examined the potential for surface water damage resulting from
the influx of ground water contaminated by reserve pit seepage and
injection well failures, as well as surface water damage resulting from
direct discharge of stripper well produced water. For all model
scenarios, EPA estimated the average annual surface water concentrations
of waste constituents to be below their respective thresholds at the
point where they enter the surface water; that is, the threshold
concentrations for various waste constituents were not exceeded even at
the point of maximum concentration in surface waters. This is because
the input chemical mass is diluted substantially upon entering the
surface water. Surface water usually flows at a much higher rate than
ground water and also allows for more complete mixing than ground water.
Both of these factor suggest that there will be greater dilution in
surface water than in ground water. One would expect, therefore, that
the low concentrations in ground water estimated for reserve pit seepage
and injection well failures would be diluted even further upon seeping
into surface water.
V-54
-------
These limited modeling results do not imply that resource damage
could not occur from larger releases, either through these or other
migration pathways or from releases to lower flow surface waters (i.e.,
streams, with flows below 40 ft /s). In addition, surface water damages
could occur during short periods {less than a year) of low stream flow or
peak waste discharge, which were not modeled in this study.
EPA analyzed what a river or stream flow rate would have to be (given
the model produced water concentrations and discharge rates from stripper
wells) in order for contaminant concentrations in the mixing zone
(assuming instantaneous and complete mixing but not other removal
processes) to exceed resource damage criteria. The results of this
analysis are summarized in Table V-ll. As shown, the maximum
concentrations of chloride, boron, sodium, and TMI in streams or rivers
caused by the discharge of produced water from stripper wells would
(under most modeling conditions) not exceed resource damage criteria
unless the receiving stream or river was flowing at a 'rate below
1 ft /s. The exceptions are scenarios with a conservative waste stream
concentration and high discharge rate. If produced water was discharged
to streams or rivers under these conditions, the maximum concentrations
of sodium and TMI could exceed resource damage criteria in surface waters
flowing up to 5 ft /s. (The maximum concentrations in any surface
water flowing at a greater rate would not exceed the criteria.)
The results suggest that, if produced waters from stripper wells are
discharged to streams and rivers under conditions that are similar to
those modeled, resource damage criteria would be exceeded only in very
small streams.
ASSESSMENT OF WASTE DISPOSAL ON ALASKA'S NORTH SLOPE
In accordance with the scope of the study required by RCRA Section
8002(m), this assessment addresses only the potential impacts associated
V-55
-------
Tafcle V-H Surface Water Flo* Rates At Wtrtcn Concentrations of Waste Stream
Constituents in the Mining Zone Will Exceed
Aqyatic Effects and Sesoyrce Damage Threshotcs*
Concentration Uaste stream riischarre rate
Constituent m waste High (100 8?0) Medium (10 BPD) Lo» {! S?0)
Sod i urn
Median
90th %
Chlonae
Median
90th '»;
Borer,
Medi
an
90th «
Total Kobi le Ions
Median
90th X
<. 0.7 ft
1 5 ft
1 0.2 ft
1 0.5 ft
3 b
/s
3
/s
3
3
/s
£ 0.05 ftJ/s
1
1 0.8 ft"/s
1
i 0.4 fr/s
i Z ft3/s
*. 0.0?
<_ 0.5
1 0.02
<_ 0.09
<_ 0.006
^ 0.08
<. 0.04
1 0.2
3
ft /s
3
ft /s
ft3/s
3
ft /s
It3/s
JJ
ft /s
3
ft /s
ft3/s
« 0.
i 0
i 0.
1 0
£ 0
1 0
<_ 0.
1 0.
.007
.05
.003
009
.0006
008
.004
.02
ft
ft
ft
ft
3
3
3
3
ft
ft
ft
ft
3
^
3
/s
/s
/$
/s
3/s
/s
/'s
/s
aThe effect thresholds and effects considered in this analysis were as follows: Sodium-83
mg/L. which might result in toxic effects or osmoregylatory problems for freshwater aquatic
organisms fnote: while this threshold is based on tomcity data reported in the literature,
it is dependent on several assumptions and is specylat we); ch1onde--2SO mg/L, which is
EPA's secondary drinking water standard designed to prevent excess corrosion of pipes in hot
water systems and to prevent objectionable tastes; boron--] mg/l, which is a concentration in
irrigation water that could damage sensitive crops (e.g., citrus trees; plum, pear, and apple
trees; grapes; and avocados); and total mobile Jons--335 mg/L, which may be a tolerable level
for freshwater species by* would probably put them at a disadvantage in conjjeting with
brackish or nurine organisms.
Should be interpreted to man that the concentration of sodium in the mixing zone would
exceed the modeled effect threshold (described in footnote a) if the receiving stream or
river was flowing at a rate of 0.7 ftj/s or lower. If the stream or river was flowing at a
higher rate, then the maximum concentration of sodium would not exceed the effect level.
V-56
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with the management of exempt oil and gas wastes on Alaska's North
Slope. It does not analyze risks or impacts from other activities, such
as site development or road construction. The North Slope is addressed
in a separate, qualitative assessment because readily available release
and transport models for possible use ir» a quantitative assessment are
not appropriate for many of the characteristics of the North Slope, such
as the freeze-thaw cycle, the presence of permafrost, and the typical
reserve pit designs.
Of the various wastes and waste management practices on the North
Slope, it appears that the management of drilling waste in above-ground
reserve pits has the greatest potential for adverse environmental
effects. The potential for drilling wastes to cause adverse human health
effects is small because the potential for human exposure is small.
Virtually all produced water on the North Slope is reinjected
approximately 6,000 to 9,000 feet below the land surface in accordance
with discharge permits issued by the State of Alaska. The receiving
formation is not an underground source of drinking water and is
effectively sealed from the surface by permafrost. Consequently, the
potential for environmental or human health impacts associated with
produced fluids is very small under routine operating conditions.
During the summer thaw, reserve pit fluids are disposed of in
underground injection wells, released directly onto the tundra or applied
to roads if they meet quality restrictions specified in Alaska discharge
permits, or stored in reserve pits. Underground injection of reserve pit
fluids should have minor adverse effects for the same reasons as were
noted above for produced waters. If reserve pit fluids are managed
through the other approaches, however, there is much greater potential
for adverse environmental effects.
V--57
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Discharges of reserve pit fluids onto the tundra and roads are
regulated by permits issued by the Alaska Department of Environmental
Conservation (ADEC). In the past, reserve pit discharges have
occasionally exceeded permit limitations for certain constituents. New
permits, therefore, specify several pre-discharge requirements that must
be met to help ensure that the discharge is carried out in an acceptable
manner.
Only one U.S. Government study of the potential effects of reserve
pit discharges on the North Slope is known to be complete. West and
Snyder-Conn (1987), with the U.S. Fish and Wildlife Service, examined how
reserve pit discharges in 1983 affected water quality and invertebrate
communities in receiving tundra ponds and in hydrologically connected
distant ponds. Although the nature of the data and the statistical
analysis precluded a definitive determination of cause and effect,
several constituents and characteristics (chromium, barium, arsenic,
nickel, hardness, alkalinity, and turbidity) were found in elevated
concentrations in receiving ponds when compared to control ponds. Also,
alkalinity, chromium, and aliphatic hydrocarbons were elevated in
hydrologically connected distant ponds when compared to controls.
Accompanying these water quality variations was a decrease in
invertebrate taxonomic richness, diversity, and abundance from control
ponds to receiving ponds.
West and Snyder-Conn, however, cautioned that these results cannot be
wholly extrapolated to present-day oil field practices on the North Slope
because some industry practices have changed since 1983. For example,
they state that "chrome 1ignosulfonate drill muds have been partly-
replaced by non-chrome lignosulfonates, and diesel oil has been largely
replaced with less toxic mineral oil in drilling operations." Also,
State regulations concerning reserve pit discharges have become
increasingly stringent since the time the study was conducted. West and
V-58
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Snyder-Conn additionally concluded that reserve pit discharges should be
subject to standards for turbidity, alkalinity, chromium, arsenic, and
barium to reduce the likelihood of biological impacts. ADEC's 1987
tundra discharge permit specifies effluent limitations for chromium,
arsenic, barium, and several other inorganics, as well as an effluent
limitation for settleable solids (which is related to turbidity). The
1987 permit requires monitoring for alkalinity, but does not specify an
effluent limit for this parameter.
Reserve pits on the North Slope are frequently constructed above
grade out of native soils and gravel. Below-grade structures are also
built, generally at exploratory sites, and occasionally at newer
production sites. Although the mud solids that settle at the bottom of
the pits act as a barrier to fluid flow, fluids from above-ground reserve
pits (when thawed) can seep through the pit walls and onto the tundra.
No information was obtained on what percentage of the approximately 300
reserve pits on the North Slope are actually leaking; however, it has
been documented that "some" pits do in fact seep (ARCO 1985, Standard Oil
1987). While such seepage is expected to be sufficiently concentrated to
adversely affect soil, water, vegetation, and dependent fauna in areas
surrounding the reserve pits, it is not known how large an area around
the pits may be affected. Preliminary studies provided by industry
sources indicate that seepage from North Slope reserve pits, designed and
managed in accordance with existing State regulations, should not cause
damage to vegetation more than 50 feet away from the pit walls (ARCO
1986, Standard Oil 1987). It is important to note that ADEC adopted
regulations that should help to reduce the occurrence of reserve pit
seepage and any impacts of drilling waste disposal. These regulations
became effective in September 1987.
While some of the potentially toxic constituents in reserve pit
liquids are known to bioaccumulate (i.e., be taken up by organisms low in
V-59
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the food chain with subsequent accumulation in organisms higher in the
food chain), there is no evidence to conclude that bioaccumulation from
reserve pit discharge or seepage is occurring. In general,
bioaccumulation is expected to be small because each spring thaw brings a
large onrush of water that may help flush residual contamination, and
higher level consumers are generally migratory and should not be exposed
for extended periods. It is recognized, however, that tundra invertebrates
constitute the major food source for many bird species on the Arctic
coastal plain, particularly during the breeding and rearing seasons,
which coincide with the period that tundra and road discharges occur.
The Fish and Wildlife Service is in the process of investigating the
effects of reserve pit fluids on invertebrates and birds, and these and
other studies need to be completed before conclusions can be reached with
respect to the occurrence of bioaccumulation on the North Slope.
With regard to the pit solids, the walls of operating pits have
slumped on rare occasions, allowing mud and cuttings to spill onto the
surrounding tundra. As long as these releases are promptly cleaned up,
the adverse effects to vegetation, soil, and wildlife should be temporary
(Pollen 1986, McKendrick 1986).
ADEC's new reserve pit closure regulations for the North Slope
contain strengthened requirements for reserve pit solids to be dewatered,
covered with earth materials, graded, and vegetated. The new regulations
also require owners of reserve pits to continue monitoring and to
maintain the cover for a minimum of 5 years after closure. If the
reserve pit is constructed below grade such that the solids at closure
are at least 2 feet below the bottom of the soil layer that thaws each
spring, the solids will be kept permanently frozen (a phenomenon referred
to as freezeback). The solids in closed above-grade pits will also
undergo freezeback if they are covered with a sufficient layer of earth
material to provide insulation. In cases where the solids are kept
V-60
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permanently frozen, no leaching or erosicn of the solid waste
constituents should occur. However, ADEC's regulations do not require
reserve pits to be closed in a manner that ensures freezeback.
Therefore, some operators may choose to close their pits in a way that
permits the solids to thaw during the spring. Even when the,sol ids are
not frozen, migration of th
-------
(or 7 percent) have Federally designated critical habitats10 within their
boundaries. These 13 counties encompass the critical habitats for a
total of 10 different species, or about 10 percent of the species for
which critical habitats have been designated on the Federal level.
Wetlands create habitats for many forms of wildlife, purify natural
waters by removing sediments and other contaminants, provide flood and
storm damage protection, and afford a number of other benefits. In
general, Alaska and Louisiana are the States with the most wetlands and
oil and gas activity. Approximately 50 to 75 percent of the North Slope
area consists of wetlands (Bergman et al. 1977). Wetlands are also
abundant throughout Florida, but oil and gas activity is considerably
less in that State and is concentrated primarily in the panhandle area.
In addition, oil and gas activities in Illinois appear to be concentrated
in areas with abundant wetlands. Other States with abundant wetlands
(North Carolina, South Carolina, Georgia, New Jersey, Maine, and
Minnesota) have very little onshore oil and gas activity.
For the purpose of this analysis, public lands are defined as the
wide variety of land areas owned by the Federal Government and
administered by the Bureau of Land Management (BLM), National Forest
Service, or National Park Service. Any development on these lands must
first pass through a formal environmental planning and review process.
In many cases, these lands are not environmentally sensitive. National
Forests, for example, are established for multiple uses, including timber
development, mineral extraction, and the protection of environmental
values. Public lands are included in this analysis, however, because
they are considered "publicly sensitive," in the sense that they are
commonly valued more highly by society than comparable areas outside
Critical habtisJts, which are much sou Her and more rigorously defined than historical
ranges, are areas ccntrnr, tng physical or bio1ogicd' factors essential to the conservation of tne
species.
V-62
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their boundaries. The study focuses only on lands within the National
Forest and National Park Systems because of recent public interest in oil
and gas development in these areas (e.g., see Sierra Club 1986;
Wilderness Society 1987).
The National Forest System comprises 282 National Forests, National
Grasslands, and other areas and includes a total area of approximately
191 million acres. Federal oil and gas leases, for either exploration or
production, have been granted for about 25 million acres (roughly
27 percent) of the system. Actual oil and gas activity is occurring on a
much smaller acreage distributed across 11 units in eight States, More
than 90 percent of current production on all National Forest System lands
takes place in two units: the Little Missouri National Grassland in
North Dakota and the Thunder Basin National Grassland in Wyoming.
The National Park System contains almost 80 million acres made up by
337 units and 30 affiliated areas. These units include national parks,
preserves, monuments, recreation areas, seashores, and other areas. ATI
units have been closed to future leasing of Federal minerals except for
four national recreation areas where mineral leasing has been authorized
by Congress and permitted under regulation. If deemed acceptable from an
environmental standpoint, however, nonfederally owned minerals within a
unit's boundaries can be leased. Ten units (approximately 3
percent of the total) currently have active oil and gas operations within
their boundaries. Approximately 23 percent of the land area made up by
these ten units is currently under lease (approximately 256,000 acres);
however, 83 percent of the area within the ten units (almost one million
acres) is leasable. The National Park Service also has identified
32 additional units that do not have active oil and gas operations at
present, but do have the potential for such activities in the future.
Nonfederally ouned minerals t.ith;i National Pjri SySte« units exist where the Federal
Government does not own all the land »itrnn a unit's boundaries or does not possess the subsurface
mineral rights.
V-63
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Several of these units also have acres that are under lease for oil and
gas exploration, development, and production. In total, approximately
334,700 acres within the National Park System (or roughly 4 percent of
the total) are currently under lease for oil and gas.
CONCLUSIONS
EPA's major conclusions, along with a summary of the main findings on
which they are based, are listed below. EPA recognizes that the
conclusions are limited by the lack of complete data and the necessary
risk modeling assumptions. In particular, the limited amount of waste
sampling data and the lack of empirical evidence on the probability of
injection well failures have made it impossible to estimate precisely the
absolute nationwide or regional risks from current waste management
practices for oil and gas wastes. Nevertheless, EPA believes that the
risk analysis presented here has yielded many useful conclusions relating
to the nature of potential risks and the circumstances under which they
are likely to occur.
General Conclusions
For the vast majority of model scenarios evaluated in this
study, only very small to negligible risks would be expected to
occur even if the toxic chemical(s) of concern were of relatively
high concentration in the wastes and there was a release into
ground water as was assumed in this analysis. Nonetheless, the
model results also show that there are realistic combinations of
measured chemical concentrations (at the 90th percentile level)
and release scenarios that could be of substantial concern. EPA
cautions that there are other release modes not considered in this
analysis that could also contribute to risks. In addition, there
are almost certainly toxic contaminants in the large unsanpled
population of reserve pits and produced fluids that could exceed
concentration levels measured in the relatively small number of
waste samples analyzed by EPA.
V-64
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» EPA's modeling of resource damages to surface water—both in
terms of ecological impact and of resource degradation--generally
did not show significant risk. This was true both for ground-
water seepage and direct surface water discharge (from stripper
wells) pathways for drilling pit and produced water waste
streams. This conclusion holds for the range of receiving water
flowrates modeled, which included only moderate (40 ft^/s) to
large (850 ft3/s) streams. It is clear that potential damages
to smaller streams would be quite sensitive to relative discharge
or ground-water seepage rates.
• Of the hundreds of chemical constituents detected in both
reserve pits and produced water, only a few from either source
appear to be of primary concern relative to health or
environmental damages. Based on an analysis of toxicological
data, the frequency and measured concentrations of waste
constituents in the relatively small number of sampled waste
streams, and the mobility of these constituents in ground water,
EPA found a limited number of constituents to be of primary
relevance in the assessment of risks via ground water. Based on
current data and analysis, these constituents include arsenic,
benzene, sodium, chloride, cadmium, chromium, boron, and mobile
salts. All of these constituents were included in the
quantitative risk modeling in this study. Cadmium, chromium, and
boron did not produce risks or resource damages under the
conditions modeled. Note: This conclusion is quaMfied by the
small number of sampled sites for which waste composition could be
evaluated.
» Both for reserve pit waste and produced water, there is a very
wide (six or more orders of magnitude) variation in estimated
health risks across scenarios, depending on the different
combinations of key variables influencing the individual scenarios.
These variables include concentrations of toxic chemicals in the
waste, hydrogeologic parameters, waste amounts and management
practices, and distance to exposure points.
Drilling Wastes Disposed of in Onsite Reserve Pits
• Most of the 1,134 onsite reserve pit scenarios had very small or
no risks to human health via ground-water contamination of
drinking water for the conditions modeled. Under the
best-estimate assumptions, there were no carcinogenic waste
constituents modeled (median concentrations for carcinogens in the
EPA samples were zero or below detection), and more than
99 percent of the nationally weighted reserve pit scenarios
resulted in exposure to noncarcinogens (sodium, cadmium, chromium)
V-65
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at concentration levels below health effect thresholds. Under
more conservative assumptions, including toxic constituents at
90th percentile sair.ple concentrations, no scenarios evaluated
yielded lifetime cancer risks as high as 1 in 100,000 (1 x 10"5),1?
and only 2 percent of the nationally weighted conservative
scenarios showed cancer risks greater than 1 x 10. Noncancer
risks were estimated by threshold exceedances for only 2 percent
of nationally weighted scenarios, even when the 90th percentile
concentration of sodium in the waste stream was assuraed. The
maximum sodium concentration at drinking water wells was estimated
to be roughly 32 times the threshold for hypertension. In general,
these modeling results suggest that most onsite reserve pits will
present very low risks to human health through ground-water
exposure pathways.
It appears that people may be able to taste chloride in the
drinking water in those scenarios with the highest cancer and
noncancer risks. It is questionable, however, whether people
would actually discontinue drinking water containing these
elevated chloride concentrations.
Weighting the risk results to account for different distributions
of hydrogeologic variables, pit size, and exposure distance across
geographic zones resulted in limited variability in risks across
-zones. Risk distributions for individual zones generally did not
differ from the national distribution by more than one order of
magnitude, except for zones 10 (West Coast) and 11B (Alaska,
non-North Slope), which usually were extremely low. Note: EPA
was unable to develop geographical comparisons of toxic
constituent concentrations in drilling pit wastes.
Several factors were evaluated for their individual effects on
risk. Of these factors, ground-water flow field type and exposure
distance had the greatest influence (several orders of magnitude);
recharge rate, subsurface permeability, and pit size had less, but
measurable, influence (approximately one order of magnitude).
Typically, the higher risk cases occur in the context of the
largest unljned pits, the short (60-meter) exposure distance, and
high subsurface permeability and infiltration. Depth to ground
water and presence/absence of a single synthetic liner had
virtually no raeasurable influence over the 200-year modeling
period; however, risk estimated over shorter time periods, such as
50 years, would likely be lower for lined pits compared to unlined
pits, and lower for deep ground water compared to shallow ground
water.
A cancer risk estimate of 1 x 10"" indicates that the chance of an individual contracting
cancer over a JO-ye&r average lifeline it, appro*•male'!} 1 in 100.ODD. The Agency estdOlishes the
cutoff between acceptable and unacceptable levels of cancer risk between 1 x JO" and 1 x JO .
V-66
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» Estimated ground-water resource damage (caused by exceedance of
water quality thresholds for chloride and total mobile ions) was
very limited and essentially confined to the closest modeling
distance (60 meters). These resource damage estimates apply only
to the pathway modeled (leaching through the bottom of onsite
•pits) and not to other mechanisms of potential ground-water
contamination at drilling sites, such as spills or intentional
surface releases.
« No surface water resource damage (caused by exceedance of
thresholds for chloride, sodium, cadmium, chromium VI, or total
mobile ions) was predicted for the seepage of leachate-
contaminated ground water into flowing surface water. This
finding, based on limited modeling, does not imply that resource
damage could not occur from larger releases, either through this
or other pathways of migration, or from releases to lower flow
surface waters (below 40 ft3/s).
Produced Hater Disposal in Injection Hells
» All risk results for underground injection presented in this
chapter assume that either a grout seal or well casing failure
occurs. However, as anticipated under EPA's Underground Injection
Control (UIC) regulatory program, these failures are probably
low-frequency events, and the actual risks resulting from grout
seal and casing failures are expected to be much lower than the
conditional risks presented here. The results do not, however,
reflect other possible release pathways such as migration through
unplugged boreholes or fractures in confining layers, which also
could be of concern.
• Only a very small minority of injection well scenarios resulted
in meaningful risks to human health, due to either grout seal or
casing failure modes of release of produced water to drinking
water sources. In terms of carcinogenic risks, none of the
best-estimate scenarios (median arsenic and benzene sample
concentrations) yielded lifetime risks greater than 5 per
1,000,000 (5 x 1Q~6) to the maximally exposed individual. When
the 90th percentile benzene and arsenic concentrations were
examined, a maximum of 35 percent of EPA's nationally weighted
scenarios had risks greater than 1 x 10"L with up to 5 percent
having cancer risks greater than 1 x IO"4 (the highest risk was
9 x 10"^). The high cancer risk scenarios corresponded to a
very short (60-meter) exposure distance combined with relatively
high injection pressure/rates and a few specific ground-water flow
fields (fields C and D in Table V-7).
V-67
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Noncancer health effects modeled were limited to hypertension in
sensitive individuals caused by ingestion of sodium in drinking
water. In the best-estimate scenarios, up to 8 percent of EPA's
nationally weighted scenarios had threshold exceedances for sodium
in ground-water supplies. In the conservative scenarios, where
90th percentile sodium concentrations were assumed in the
injection waters, threshold exceedances in drinking water were
predicted for a maximum of 22 percent of the nationally weighted
scenarios. The highest sodium concentration predicted at exposure
we Vis under conservative assumptions exceeded the threshold for
hypertension by a factor of 70, The high noncancer risk scenarios
corresponded to a very short (60-meter) exposure distance, high
injection pressures/rates, and relatively slow ground-water
velocities/low flows.
It appears that people would not taste or smell chloride or
benzene at the concentration levels estimated for the highest
cancer risk scenarios, but sensitive individuals would be more
likely to detect chloride or benzene tastes or odors in those
scenarios with the%highest noncancer risks. It is questionable,
however, whether the detectable tastes or smells at these levels
would generally be sufficient to discourage use of the water
supply.
As with the reserve pit risk modeling results, adjusting
(weighting) the injection well results to account for differences
amon-g various geographic zones resulted in relatively small
differences in risk distributions. Again, this lack of
substantial variability in risk across zones may be the result of
limitations of the study approach and the fact that geographic
comparisons of toxic constituents in produced water was not
possible.
Of several factors evaluated for their effect on risk, exposure
distance and ground-water flow field type had the greatest
influence (two to three orders of magnitude). Flow rate/pressure
had less, but measurable, influence (approximately one order of
magnitude). Injection well type (i.e., waterflood vs. disposal)
had moderate but contradictory effects on the risk results. For
casing failures, high-pressure waterflood wells were estimated to
cause health risks that were about 2 times higher than the risks
from lower pressure disposal wells under otherwise similar
conditions. However, for grout seal failures, the risks associated
with disposal wells were estimated to be up to 3 times higher than
the risks in similar circumstances associated with waterflood
wells, caused by the higher injection rates for disposal.
V-68
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» Estimated ground-water resource damage (resulting from
exceedance of thresholds for chloride, boron, and total mobile
ions) was extremely limited and was essentially confined to the
60-meter modeling distance. This conclusion applies only to
releases from Class I! injection wells, and not to other
mechanisms of potential ground-water contamination at oil and gas
production sites (e.g., seepage through abandoned boreholes or
fractures in confining layers, leaching from brine pits, spalls).
• No surface water resource damage (resulting from exceedance of
thresholds for chloride, sodium, boron, and total mobile ions) was
predicted for seepage into flowing surface water of ground water
contaminated by direct releases from injection wells. This
finding does not imply that resource daiage could not occur via
mechanisms and pathways not covered by this limited surface water
modeling, or in extremely low flow streams.
Stripper Well Produced Water Discharged Directly into Surface Hater
• Under conservative modeling assumptions, 17 percent of scenarios
(unweighted) had cancer risks greater than 1 x 10"** (the maximum
cancer risk estimate was roughly 4 x 10"^).13 The maximum
cancer risk under best-estimate waste stream assumptions was 4 x 10 .
No exceedances of noncancer effect thresholds or surface water
resource damage thresholds were predicted under any of the
conditions modeled. The limited surface water modeling performed
applies oqly to scenarios with moderate- to high-flow streams (40
to 850 ft^/s). Preliminary analyses indicate, however, that
resource damage criteria would generally be exceeded in only very
small streams (i.e., those flowing at less than 5 ft^/s), given
the sampled waste stream chemical concentrations and discharge
rates for stripper wells of up to 100 barrels per day.
Drilling and Production Wastes Managed on Alaska's North Slope
« Adverse effects to human health are expected to be negligible or
nonexistent because the potential for human exposure to drilling
waste and produced fluid contaminants on the North Slope is very
small. The greatest potential for adverse environmental impacts
is caused by discharge and seepage of reserve pit fluids containing
toxic substances onto the tundra. A field study conducted in 1983
by the U.S. Fish and Wildlife Service indicates that tundra
discharges of reserve pit fluids may adversely affect water
quality and invertebrates in surrounding areas; however, the
Tncse results jrc unweighted because the frequency of occurrence of "He parameters that
e the stripper well sc?njr'os **2s not estimated
V-S9
-------
results of this study cannot be wholly extrapolated to present-day
practices on the North Slope because some industry practices have
changed and State regulations concerning reserve pit discharges
have become increasingly more stringent since 1983. Preliminary
studies from industry sources indicate that seepage from operating
above-ground reserve pits on the North Slope may damage vegetation
within a radius of 50 feet. The Fish and Wildlife Service is in
the process of studying the effects of reserve pit fluids on
tundra organisms, and these studies need to be completed before
more definitive conclusions can be made with respect to
environmental impacts on the North Slope.
Locations of Oil and Gas Activities in Relation to Environments
of Special Interest
• All of the top 26 States that have the highest levels of onshore
oil and gas activity are within the historical ranges of numerous
endangered and threatened species habitats; however, of 190
counties identified as having high levels of exploration and
production, only 13 (or 7 percent) have federally designated
critical habitats for endangered species within their boundaries.
The greatest potential for overlap between onshore oil and gas
activities and wetlands appears to be in Alaska (particularly the
North Slope], Louisiana, and Illinois. Other States with abundant
wetlands have very little onshore-oil and gas activity. Any
development on public lands must first pass through a formal
environmental review process and some public lands, such as
National Forests, are managed for multiple uses including oil and
gas development. Federal oil and gas leases have been granted for
approximately 25 million acres (roughly 27 percent} of the
National Forest System. All units of the National Park Systei
have been closed to future leasing of federally owned minerals
except for 4 National Recreation Areas where mineral leasing has
been authorized by Congress. If deemed acceptable from an
environmental standpoint, however, nonfederally owned minerals
within the park boundaries can be leased. In total, approximately
4 percent of the land area in the National Park System is
currently under lease for oil and gas activity.
V-70
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REFERENCES
ARCO, 1986, ARCO Alaska, Inc. Preliminary outline: Environmental risk
evaluation for drilling muds and cuttings on Alaska's North Slope.
Comments on ADEC Solid Waste Regulations, Attachment B.
ARCO. 1985, Report on releases of hazardous waste or constituents from
solid waste management units at the facil ity--Prudhoe Say Unit
Eastern Operating Area. Submitted to EPA Region X in support of an
Underground Injection Control permit application.
Bergman, R.D., Howard, R.L., Abraham, K.F., and Weller, M.W. 1977.
Water birds and theirwetland resources in relation to oil
development at Storkersen Point Alaska. Fish and Wildlife Service
Resource Publication 129. Washington, D.C.: U.S. Department of the
Interior.
HcKendrick, J.D. 1986. Final well site cleanup on National Petroleum
Reserve - Alaska. Volume 3, Recording oftundraplant responses.
U.S. Geological Survey.
NWWA. 1985. National Water Well Association. DRASTIC: A standardized
system for evaluating ground-water pollution potential using
hydroqeolnqic settings. NTIS PB-228145. Worthington, Ohio.
Pollen, H.R. 1986. Final well site cleanup on National Petroleum Reserve
Alaska. Volume 2,Sampling and testingof waters and bottom muds in
thereservepits. U.S. Geological Survey.
Prickett, T.A., Naymik, T.C., and Lonnquist, C.G. 1981. A random walk
solute transport model for selectedground-water quality evaluations.
Bulletin £65. Illinois State Water Survey. Champaign, Illinois.
Sierra Club. 1986. Yellowstoneundersiege: Oil and gas leasinginthe
Greater Yellowstone Region. Washington, D.C.
Standard Oil. 1987. The Standard Oil Company. Additional information on
Arctic exploration and production waste impact modeling.
USEPA. 1984a. U.S. Environmental Protection Agency. Technical guidance
manual for performing waste1oad allocations: Book 2, Streams and
rivers.
V-71
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USEPA. 1984b. U.S. Environmental Protection Agency. National secondary
drinking water regulations. EPA 570/9-76-000. Washington, D.C.:
U.S. Environmental Protection Agency.
USEPA. 1986, U.S. Environmental Protection Agency, Office of Solid
Waste. Liner location risk and cost analysis model. Draft Phase II
Report. Washington, D.C.: U.S. Environmental Protection Agency.
USEPA. 1987a. U.S. Environmental Protection Agency, Office of Solid
Waste. Onshore oil and cas andoeothermal energy exploration.
development, and production: .human health and environmental risk
assessment. Washington, D.C.: U.S. Environmental Protection Agency.
USEPA. J987b. U.S. Environmental Protection Agency, Office of Solid
Waste, Technical report: exploration, development., and production
of crude oil and natural _qaj.a_f_1lld_ sampj ing and analysis report, and
accompanying data tape. Washington, D.C.: U.S. Environmental
Protection Agency.
West, R.L., and Snyder-Conn, E. 1987. Effects of Prudhoe Bay reserve pit
fluids on water quality and macroinvertebrates of Arctic tundra ponds
inAlaska. Biological Report 87(7). U.S. Department of the
Interior, fish and Wildlife Service, Washington, D.C.
Wilderness Society. 1987. Ma nag ernentd 1 r ec t i on s f o r t he _n a t io n a 1
forests of the Greater Yellowstone ecosystem. Washington, D.C.
V-72
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CHAPTER VI
COSTS AND ECONOMIC IMPACTS OF ALTERNATIVE
WASTE MANAGEMENT PRACTICES
OVERVIEW OF THE COST AND ECONOMIC IMPACT ANALYSIS
This chapter provides estimates of the cost and selected economic
impacts of implementing alternative waste management practices by the oil
and gas industry. The industry's current or "baseline" practices are
described in Chapter III. In addition to current practices, a number of
alternatives are available. Some of these offer the potential for higher
levels of environmental control. Section 8002(n) of RCRA requires an
assessment of the cost and impact of these alternatives on oil and gas
exploration, development, and production.
This chapter begins by providing cost estimates for baseline and
alternative waste management practices. The most prevalent current
practices are reserve pit storage and disposal for drilling wastes and
Class II deep well injection for produced water. In addition, several
other waste management practices are included in the cost evaluation.
The cost estimates for the baseline and alternative waste management
practices are presented as the cost per unit of waste disposal (e.g.,
cost per barrel of drilling waste, cost per barrel of produced water).
These unit cost estimates allow for a comparison among disposal methods
and are used as input information for the economic impact analysis.
After establishing the cost of baseline and alternative practices on
a unit-of-waste basis, the chapter expands its focus to assess the impact
of higher waste management costs both on individual oil and gas projects
and on the industry as a whole. For the purpose of this assessment,
three hypothetical regulatory scenarios for waste management are
defined. Each scenario specifies a distinct set of alternative
environmentally protective waite management practices for
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oil and gas projects that generate potentially hazardous waste. Projects
that do not generate hazardous waste may continue to use baseline
practices under this approach.
After the three waste management scenarios have been defined, the
remainder of the chapter provides estimates of their cost and economic
impact. First, the impact of each scenario on the capital and operating
cost and on the rate of return for representative new oil and gas
projects is estimated. Using these cost estimates for individual
projects as a basis, the chapter then presents regional- and national -
level cost estimates for the waste management scenarios.
The chapter then describes the impact of the waste management
scenarios on existing projects (i.e., projects that are already in
production). It provides estimates of the number of wells and the amount
of current production that would be shut down as a result of imposing
alternative waste management practices under each scenario. Finally, the
chapter provides estimates of the long-term decline in domestic
production brought about by the costs of the waste management scenarios
and estimates of the impact of that decline on the U.S. balance of
payments, State and Federal revenues, and other selected economic
aggregates.
The analysis presented in this chapter is based on the information
available to EPA in November 1987. Although much new waste generation
and waste management data was made available to this study, both by EPA
and the American Petroleum Institute, certain data limitations did
restrict the level of analysis and results. In particular, data on waste
generation, management practices, and other important economic parameters
were generally available only in terms of statewide or nationwide
VI-2
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averages. Largely because of this, the cost study was conducted using
"average regional projects* as the basic production unit of analysis.
This lack of desired detail could obscure special attributes of both
marginal and above average projects, thus biasing certain impact effects,
such as the number of well closures.
The scope of the study was also somewhat limited in other respects.
For example, not all potential costs of alternative waste management
under the RCRA amendments could be evaluated, most notably the land ban
and corrective action regulations currently under development. The
Agency recognizes that this could substantially understate potential
costs of some of the regulatory scenarios studied. The analysis was able
to distinguish separately between underground injection of produced water
for disposal purposes and injection for waterflooding as a secondary or
enhanced energy recovery method. However, it was not possible during the
course of preparing this report to evaluate the costs or impacts of
alternative waste management regulations on tertiary (chemical, thermal,
and other advanced EOR) recovery, which is becoming an increasingly
important feature of future U.S. oil and gas production.
COST OF BASELINE AND ALTERNATIVE WASTE MANAGEMENT PRACTICES
Identification of Haste Management Practices
The predominant waste management practices currently employed by the
oil and gas industry are described in Chapter III of this report. For
drilling operations, wastes are typically stored in an unlined surface
impoundment during drilling. After drilling, the wastes are dewatered,
either by evaporation or vacuum truck, and buried onsite. Where vacuum
trucks are used for dewatering, the fluids are removed for offsite
Vl-3
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disposal, typically in a Class II injection well. For production
operations, the predominant disposal options are injection into a Class
II onsite well or transportation to an offsite Class II disposal
facility. Where onsite injection is used, the Class II well may be used
for disposal only or it may be used to maintain pressure in the reservoir
for enhanced oil recovery.
In addition to the above disposal options, a number of additional
practices are considered here. Some of these options are fairly common
(Table VI-1). For example, 37 percent of current drill sites use a lined
disposal pit; 12 percent of production sites in the lower 48 States
(Lower 48) discharge their produced water to the surface. Other disposal
options considered here (e.g., incineration) are not employed to any
significant extent at present.
For drilling waste disposal, nine alternative practices were reviewed
for the purpose of estimating comparative unit costs and evaluating
subsequent cost-effectiveness in complying with alternative regulatory
options:
1. Onsite unlined surface impoundment;
2. Onsite single-synthetic-liner surface impoundment;
3. Offsite single-synthetic-liner surface impoundment;
4. Offsite synthetic composite liner with leachate collection (SCLC),
Subtitle C design;
5. Landfarming consistent with current State oil and gas field
regulations;
6. Landfarming consistent with RCRA Subtitle C requirements;
7. Waste solidification;
8. Incineration; and
9. Volume reduction.
VI-4
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le VI*! Smnnjry of Baseline D-sspesa! Practices, by Zone, 1985
Drilling waste disposal
[percent of drill sites)
Un lined Lined
Zone facilities facilities
Appalachian 23 7?
Gulf 89 11
HicUest 4? S3
Plains 43 S!
Texas/ 80 40
Ok lahcnid
Northern 65 35
Mounts IP
Southern 50 50
Mountain
Uest Coast 99 1
Alaska 67 33
total 05, 63 37
Lower 4g 63 37
States
Produced water disposition
(percent of produced watersl
Class 11 In lection
Surface
discharge EOR Disposal
50 25 25
34 11 55
0 91 9
0 38 62
4 69 27
12 45 42
0 84 16
23 • 54 23
0 71 29
11 59 28
1? 80 28
Sources: Drilling waste and produced water disposal information from API, 1987a except
for produced water disposal percents for the Appalachian zone, which are based on
persona! coBwunications with regional industry sources.
NOTE: Produced water disposition percents for total U.S. and Lower 48 are based on
survey sample weights. Weighting by oil production resylts in a figure of 9 percent
discharge in the Lower 48 (API 1987b).
Vl-5
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In addition to these disposal options, costs were also estimated for
ground-water monitoring and general site management for waste disposal
sites. These latter practices can be necessary adjunct requirements for
various final disposal options to enhance environmental protection.
For produced water, two alternative practices were considered in the
cost analysis: Class I injection wells and Class II injection wells.
Both classes may be used for water disposal or for enhanced energy
recovery waterflcoding. They may be located either onsite or, in the
case of disposal wells, offsite. To depict the variation in use patterns
of these wells, cost estimates were developed for a wide range of
injection capacities.
Cost of Waste Management Practices
For each waste disposal option, engineering design parameters of
representative waste management facilities were established for the
purpose of costing (Table VI-2). For the baseline disposal methods,
parameters were selected to typify current practices. For waste
management practices that achieve a higher level of environmental control
than the most common baseline practices, parameters were selected to
typify the best (i.e., most environmentally protective) current design
practices. For waste management practices that would be acceptable for
hazardous waste under Subtitle C of RCRA, parameters were selected to
represent compliance with these regulations as they existed in early 1987,
Capital and operating and maintenance (O&M) costs were estimated for
each waste management practice based on previous EPA engineering cost
documents and tailored computer model runs, original contractor
engineering cost estimates, vendor quotations, and other sources.1
Capital costs were annualized using an 8 percent discount rate, the
See footnotes to Tables VI-3 and VI-4 and Eastern Research Group 1987 for a detailed
source list,
VI-6
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Table ¥1-2 Summary of Engineering Design Elements for Baseline and Alternative Waste Management Practices
Alternat ive
Capital costs
0 & H costs
Closure costs
Post-closure costs
Unlined pit
• Pit excavation (0,25 acre)
• Clearing and grubbing
« Contingency
• Contractor fee
Negligible
• Pit burial (earth fill only)
• Cont tngency
« Contractor fee
One-liner p
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Table V]-? (cent mued)
Alternalive
Capita) costs
0 & H costs
Closure costs
l*0st-c losure costs
Offsite SCLC facility
• Pit excavation (15 acres)
* Same costs as commercial
one-liner pit with the
addition of:
- additional pit liners
- clay liner replaces
geottxtile subliner
Same costs as
commercial one-liner pit
•Same costs as onsite one-
liner pit with addition of
synthet ic cap
« Equipment decontamination
(See ground-water
monitoring and site
management)
Ground water monitoring
and site management
oo
» Ground-water monitoring
wells
» leachate collection
system
- drainage tHes
- leachate collect ion
layer (sand or gravel)
for single-1 iner case
only
- leachate collection
liner for single-liner
case only
• Signs/fencing
• RCRA permitting (for RCRA
scenario)
Ground-water
monitoring wells
sampling and
laboratory fees
leachate treatment
• Soi 1 poisoning (to
prevent disruption by
long-rooted plants)
• Cover drainage tile
- collection layer
(sand or gravel)
- geotext i le f i Her
fabric in one-liner pit
» Honttoring
« Cert if icat ion,
supervision
» Monitoring well
sampling
• Leachate treatment
• Notice to local
author it ies
» Notation on property
deed
• Facility inspection
« HainttMnce and
repa ir
• Cover replacement
• Engineering and
inspect ion fees
• Contingency
Offsite, multiple-
application landfarming
• Land cost
• Land clearing cost
* Bui Iding cost
• Lysimeter cost (RCRA
scenario)
« Cluster wells {RCRA
scenario)
• Labor
» Ground-water
monitoring
* Soi1 core cost
* Maintenance
• Utilities
• Insurance, taxes, and
G 6 A
« Revegetat ion
* Testing
» Land authority and
property deed cost
» Ground-water monitoring
cost
• Soi 1 core cost
» Eros ton control cost
« Vegetative cover cost
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Table VI-2 (continued)
Alternative
Capital costs
0 & M costs
Closure costs
Post-closure costs
Qffiite, multiple-
application laridf arming
(continued)
Mind dispersal control
(RCRA scenario)
Storage tanks
Engineering and inspection
Contingency
Retention pond {RCRA
scenario)
Berras (RCRA scenario)
Engineering and
inspection costs
Contingency
Volume reduction
• Equipment rental
- mechanical or vacuum
separation equipment
• Tanks
* Chemicals
• Labor
Injection (Class II)
• Convert existing well to
disposal well
- completion rig contract
- drilling fluids
- cement ing
- logging and perforating
- stimulation
- liner and tubing
• Site work/building
• Holding tanks
• Skim tanks
• Fi Iters and pumps
• Pipelines
« Labor
* Chemicals
• Electricity
• Filters
• Ofsposal of filtrates
• Pump maintenance
• Pressure tests
* Liability costs
* Plug and abandon
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Table Vl-2 (continued)
Alternat ive
Capital costs
0 5 H costs
Closure cost!
Post-closure costs
Injection (Class 1}
• Or i H new we 11
- drill ing rig contract
- completion rig contract
- cementing
- logging and perforating
- site preparation
- casing
- liner
- tubing
• Storage tanks
• Annular fluid tank
» Filters
• Pumps
« Pipelines
» Sitt work/buildings
• RCRA permit cost (RCRA
scenario)
Same costs as Class II
wells with addition of:
- tracer survey
- cement bond log
- pipe evaluation
- disposal of
filtrate in
hazardous waste
fact lity
Plug and abandon
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approximate after-tax real cost of capital for this industry. Annualized
capital costs were then added to O&M costs to compute the total annual
costs for typical waste management unit operations. Annual costs were
*
divided by annual waste-handling capacity (in barrels) to provide a cost
per barrel of waste disposal. Both produced water disposal costs and
drilling waste (i.e., muds and cuttings) disposal costs are expressed on
a dollars-per-barrel basis.
The average engineering unit cost estimates for drilling wastes are
presented in Table VI-3 for each region and for a composite of the
Lower 48. Regional cost variations were estimated based on varying land,
construction, and labor costs among regions. The costs for the Lower 48
composite are estimated by weighting regional cost estimates by the
proportion of production occurring in each region. (Throughout the
discussion that follows, the Lower 48 composite will be referenced to
illustrate the costs' and impacts in question.)
For the Lower 48 composite, the drilling waste disposal cost
estimates presented in Table VI-3 range from S2.04 per barrel for onsite,
unlined pit disposal to S157.50 per barrel for incineration. Costs for
the disposal options are significantly higher for Alaska because of the
extreme weather conditions, long transportation distances from population
and material centers to drill sites, high labor costs, and other unique
features of this region.
Costs for produced water are presented in Table VI-4. Disposal costs
include injection costs, as well as transport, loading, and unloading
charges, where appropriate. Injection for EOR purposes occurs onsite in
either Class II or Class I wells. Class II disposal occurs onsite in all
zones except Appalachia. Class I disposal occurs offsite except for the
Northern Mountain and Alaska zones. Well capacities and transport
distances vary regionally depending on the volume of water production and
the area under production.
VI-11
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Table VI-3 Unil Costs of Drilling Waste Disposal Options, by lone fOoltars per Barrel of Waste. 1985 Basis)
Zoie
Disposal option Appalachian
Surface impoundment
Unlined (0.25 acre)
Single- liner {0.25 acre)
SCLC (15 acres)
Landf arming
Current
Subtitle C
Sol idif icat ion
Incineration
Volume reduction and off site
single-liner disposal6
Volume reduction and
offsite SCLC disposal6
$ 2.09
4.62
18.26
13.21
30.23
8.00
157.50
15.16
19.27
Texas/ Northern
Gulf Midwest Plains Oklahoma Mountain
ft
$ 1.98 $ 2,00 S 1 98 $ 2 10 $ 2.00
4 32 4 35 4.29 4 63 4 35
12,41 256! 19.54 11.60 13.73
12,06 12 41 IS 91 1? 01 16.14
31.58 28.34 39.14 4031 36.45
8.00 8 00 8.00 8,00 8,00
157.50 157,50 157.50 157 50 157.50
3.18 1? 24 9.50 583 5. 40
7.94 25.50 15,94 991 11.90
Southern
Mounta in
$ 2,00
4 35
20,69
15.99
36.38
fl.OO
157.50
6.15
12 93
West
Coast Alaska
$ 2 04 t 2 69
4.46 6 16
27,54 20 27
16.4? N.E.
38.45 N,E.
8 00 N.E.
157.50 N.E.
21 .87 5.67
30,71 12.57
Lower 48
$ ?.04
4 46
15 52
15,47
37,1?
8 00
15? 50
6 74
11 95
N.E. = Not estimated; disposal method not practical and/or information not available for Alaska
*Source: Pope Reid Associates I985a, I985b. 198?a; costs for SCLC disposal include transportation charges.
Source: Pope Reid Associates 1987b
cSource; Erlandsnn 1986; Webster 1987; lesar 1986; Camp, Dresser 8 McK.ee 1986; Hanson and Jones 1986; Cullinane et al. 1986; North American
Environmental Service 1985.
dSource: USEPA 1986.
eSource: Slaughter 1987; Rafferty 1987. Costs include equipment rental and transport and disposal of reduced volume of waste. All costs are allocated
over the original volume of waste so that per-barrel costs of waste disposal are comparable to the other cost estimates in the table.
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Table VI-« Unit Casts of Underground Injection
of Produced Water, by Zone
(Dollars per Barrel of Water)
Zone
Appalachian1"*
Gulf
Midwest
Plains
Texas/Oklahoma
Northern Kcuntain
Southern Mountain
West Coast
Alaska
Lower 4b States
CUss 1! >r
Disposal
$1.26-1 33
0.10
0.29
0.14
0,11
0.01
0.0?
0.04
Q.05
O.iO
>ect sen
EOR
$0.75
0.23
0,13
0.19
0,14
0.14
0.14
0.05
0.41
0.14
Class I in
Disposal
$2 45
0.84
1,14
0,86
0.96
0,40
1.05
0.72
1.28
0,92
•ect sen1*
EOR
16. 12
1.35
0.84
1.21
0,76
0.58
0.67
0.25
2.15
0.78
a Disposal costs for Class I injection irclyde transportation and
loading/unloading charges except for the Northern Mountain zone and
Alaska, where onsite disposal is expected to occur.
Class 31 disposal costs for Appalachian zone includes transport and
loading/unloading cnarges. Lower estimate is for intermediate scenarios;
higher estimate is for baseline-practice due to change in transport
distances. For all other zones. Class II disposal is assigned to occur
onsite.
Sources: Tilden 1987a. 19875,
NOTE: Base year for costs is 1985.
VI-13
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Produced water disposal costs range from SO,01 to SI.33 per barrel
for Class II disposal and EOR injection and from 50.40 to S6.12 per
barrel for Class I disposal and EOR injection. Costs for Class I
facilities are substantially higher because of the increased drilling
completion, monitoring, and surface equipment costs associated with waste
management facilities that accept hazardous waste.
The transportation of waste represents an additional waste management
cost for some facilities. Transportation of drilling or production waste
for offsite centralized or commercial disposal is practiced now by some
companies and has been included as a potential disposal option in the
waste management scenarios. Drilling waste transport costs range from
SO.02 per barrel/mile for nonhazardous waste to SO.06 per barrel/mile for
hazardous waste. Produced water transport costs range from SO.01 per
barrel/mile (nonhazardous) to SO.04 per barrel/mile (hazardous).
Distances to disposal facilities were estimated based on the volume of
wastes produced, facility Capacities, and the area served by each
facility. Waste transportation also involves costs for loading and
unloading.
WASTE MANAGEMENT SCENARIOS AND APPLICABLE WASTE MANAGEMENT
PRACTICES
In order to determine the potential costs and impacts of changes in
oil and gas waste disposal requirements, three waste management scenarios
have been defined. The scenarios have been designed to illustrate the
cost and impact of two hypothetical additional levels of environmental
control in relation to current baseline practices. EPA has not yet
identified, defined, or evaluated its regulatory options for the oil and
gas industry; therefore, it should be noted that these scenarios do not
represent regulatory determinations by EPA. A regulatory determination
will be made by EPA following the Report to Congress.
VI-14
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Baseline Scenario
The Baseline Scenario represents the current situation. It
encompasses the principal waste management practices now permitted under
State and Federal regulations. Several key features of current practice
for both drilling waste and produced water were summarized in Table VI-1,
and the distribution of disposal practices shown in Table VI-1 is the
baseline assumption for this analysis.
Intermediate Scenario
The Intermediate Scenario depicts a higher level of control.
Operators generating wastes designated as hazardous are subject to
requirements more stringent than those in the Baseline Scenario. An
exact definition of "hazardous" has not been formulated for this
scenario. Further, even if a definition were posited (e.g., failure of
the E.P. toxicity test), available data are insufficient to determine the
proportion of the industry's wastes that would fail any given test.
Pending an exact regulatory definition of "hazardous" and the development
of better analytical data, a range of alternative assumptions has been
employed in the analysis. In the Intermediate 10% Scenario, the Agency
assumed, for the purpose of costing, that 10 percent of oil and gas
projects generate hazardous waste and in the Intermediate 70% Scenario
that 70 percent of oil and gas projects generate hazardous waste.
For drilling wastes designated hazardous, operators would be required
to use a single-synthetic-liner facility, landfarming with site
management (as defined in Table VI-2), solidification, or incineration.
Operators would select from these available compliance measures on the
basis of lowest cost. Since a substantial number of operators now employ
a single synthetic liner in drilling pits, only those sites not using a
liner would be potentially affected by the drilling waste requirements of
the Intermediate Scenario.
VMS
-------
For produced waters, the Intermediate Scenario assumes injection into
Class II facilities for any produced water that is .designated hazardous.
Operators now discharging waste directly to water or land (approximately
9 to 12 percent of all water) would be required to use a Class II
facility if their wastes were determined to be hazardous.
"Affected operations" under a given scenario are those oil and gas
projects that would have to alter their waste management practices and
incur costs to comply with the requirements of the scenario. For
example, in the Intermediate 10% Scenario, it is assumed that only
10 percent of oil and gas projects generate hazardous waste. For
drilling, an estimated 63 percent of oil and gas projects now use unlined
facilities and are therefore potentially affected by the requirements of
the scenario. Since 10 percent of these projects are assumed to generate
hazardous waste, an estimated 6.3 percent of the projects are affected
operations, which are subject to higher disposal costs.
The Subtitle C Scenario '
In the Subtitle C Scenario, wastes designated as hazardous are
subject to pollution control requirements consistent with Subtitle C of
RCRA. For drilling wastes, those wastes that are defined as hazardous
must be disposed of in a synthetic composite liner with leachate
collection (SCLC) facility employing site management and ground-water
monitoring practices consistent with RCRA Subtitle C, a landfarming
facility employing Subtitle C site management practices, or a hazardous
waste incinerator. In estimating compliance costs EPA estimated that a
combination of volume reduction and offsite dedicated SCLC disposal would
be the least-cost method for disposal of drilling waste. For production
wastes, those defined as hazardous must be injected into Class I disposal
or EOR injection wells.
VI-16
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Since virtually no drilling or production operations currently use
Subtitle C facilities or Class I injection wells in the baseline, all
projects that generate produced water are potentially affected. In the
Subtitle C 10% Scenario, 10 percent of these projects are assumed to be
affected; in the Subtitle C 70% Scenario, 70 percent of these projects
are affected. The Subtitle C Scenario, like the Intermediate Scenario,
does not establish a formal definition of "hazardous"; nor does it
attempt to estimate the proportion of wastes that would be hazardous
under the scenario. As with the Intermediate Scenario, two assumptions
(10 percent hazardous, 70 percent hazardous) are employed, and a range of
costs and impacts is presented.
This Subtitle C Scenario does not, however, impose all possible
technological requirements of the Solid Waste Act Amendments, such as the
land ban and corrective action requirements of the Hazardous Solid Waste
Amendments (HSWA), for which regulatory proposals are currently under
development in the Office of Solid Waste. Although the specific
regulatory requirements and their possible applications to oil and gas
field practices, especially deep well injection practices, were not
sufficiently developed to provide sufficient guidelines for cost
evaluation in this report, the Agency recognizes that the full
application of these future regulations could substantially increase the
costs and impacts estimated for the Subtitle C Scenario.
The Subtitle C-l Scenario
The Subtitle C-l Scenario is exactly the same as the Subtitle C
Scenario, except that produced water used in waterfloods is considered
part of a production process and is therefore exempt from more stringent
(i.e., Class I) control requirements, even if the water is hazardous. As
shown in Table VI-1, approximately 60 percent of all produced water is
used in waterfloods. Thus, only about 40 percent of produced water is
potentially affected under the Subtitle C-l Scenario. The requirements
VI-17
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of the Subtitle C-l Scenario for drilling wastes are exactly the same as
those of the Subtitle C Scenario. As with the other scenarios,
alternative assumptions of 10 and 70 percent hazardous are employed in
the Subtitle C-l Scenario.
Summary of Waste Management Scenarios
Table VI-5 summarizes the major features of all the waste management
scenarios. It identifies acceptable disposal practices under each
scenario and the percent of wastes affected under each scenario. The
Subtitle C 70% Scenario enforces the highest level of environmental
control in waste management practices, and it affects the largest percent
of facilities.
COST AND IMPACT OF THE WASTE MANAGEMENT SCENARIOS FOR TYPICAL
NEW OIL AND GAS PROJECTS
Economic Models
An economic simulation model, developed by Eastern Research Group
(ERG) and detailed in the Technical Background Document (ERG 1987), was
employed to analyze the impact of waste management costs on new oil and
gas projects. The economic model simulates the performance and measures
the profitability of oil and gas exploration and development projects
both before and after the implementation of the waste management
scenarios. For the purposes of this report, a "project" is defined as a
single successful development well and the leasing and exploration
activities associated with that well. The costs for the model project
include the costs of both the unsuccessful and the successful leasing and
exploratory and development drilling required, on average, to achieve one
successful producing well.
VI-18
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37202
VI-5 Assumed Waste Ha na semen i Practices for Alternative Waste
Scenarios
WeSte
management
scenario
Or i lima wastes
Potentially
Disposal metnod affected operations
Produced waters
Potentially
Disposal method affected operations
Unlined surface
Lined surface impoundment
Class II injection
Surface discharge
N.A.
Intermediate
Baseline practices for
nonhazareaus wastes
For hazardous wastes:
- t med surface
impoundment
- Landfarming with site
management
- Solidification
- Jnc meroI ion
fatilit «es not now
using liners
appr0
-------
For this study, model projects were defined for oil wells (with
associated casinghead gas) in the nine active oil and gas zones and for a
Lower 48 composite. Model gas projects were defined for the two most
*
active gas-producing zones (the Gulf and Texas/Oklahoma zones). Thus, 12
model projects have been analyzed. The Technical Background Document for
the Report to Congress provides a detailed description of the assumptions
and data sources underlying the model projects.
A distinct set of economic parameter values is estimated for each of
the model projects, providing a complete economic description of each
project. The following categories of parameters are specified for each
project:
1. Lease Cost: initial payments to Federal or State governments or
to private individuals for the rights to explore for and to
produce oil and gas.
2. Geological and Geophysical Cost: .cost of analytic work prior to
drilling,
3, Drill ing Cost per Well. •
4, Cost of Production Equipment.
5. Discovery Efficiency: the number of wells drilled for one
successful well.
6, Production Rates: initial production rates of oil and gas and
production decline rates.
7. Operation and Maintenance Costs.
8. Tax Rates: Rates for Federal and State income taxes, severance
taxes, royalty payments, depreciation, and depletion.
9, Price: wellhead selling price of oil and gas (also called the
"first purchase price" of the product).
10. Cost of Capital: real after-tax rate of return on equity and
borrowed investment capital for the industry.
11. Timing: length of time required for each project phase (i.e.,
leasing, exploration, development, and production).
VI-20
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The actual parameter values for the 12 model projects are summarized in
Table VI-6.
For each of the 12 model projects, the economic performance is
estimated before (i.e., baseline) and after each waste management
scenario has been implemented. Two measures of economic performance are
employed in the impact assessment presented here. One is the after-tax
rate of return. The other is the cost of production per barrel of oil
(here defined as the cost of the resources used in production, including
profit to the owners of capital, excluding transfer payments such as
royalties and taxes). A number of other economic output parameters are
described in the Technical Background Document.
Quantities of Hastes Generated by the Model Projects
To calculate the waste management costs for each representative
project, it was necessary to develop estimates of the quantities of
drilling and production wastes generated by .these facilities. These
estimates, based on a recent API survey, are provided in Table VI-7.
Drilling wastes are shown on the basis of barrels of waste per well.
Production wastes are provided on the basis of barrels of waste per
barrel of oil.
For the Lower 48 composite, an estimated 5,170 barrels of waste are
generated for each well drilled. For producing wells, approximately 10
barrels of water are generated for every barrel of oil. This latter
statistic includes waterflood projects, some of which operate at very
high water-to-oil ratios.
Model Project Waste Management Costs
Model project waste management costs are estimated for the baseline
and for each waste management scenario using the cost data presented in
VI-21
-------
Table VI-6 Economic Parameters of Model Projects for U.S Producing Zones
(All Costs in Thousands of 1965 Dollars. Other Units as Noted}
Parameter
Product ion
Yr of f trst prod.
Lease cost
G & G expense
Well cost
Disc efficiency
Infrastructure cost
0 5 M costs (per yr)
Initial prod, rales
Oil (bbl/day)
Gas (Mcf/day)
Prod, decline rates
Federal corp tax
Slate corp. tax
Royalty rate
Severance tax
Oil
Gas
Wei thead price
OH ($/bbl)
Gas ($/Mcf)
ftppa lachian
Oil/Gas
1
1.K6
58,3%
63 911
85%
45 000
4.500
4
16
9X
34%
OX
18.75?.
o.sr.
1.5%
$20.90
$ 2.00
Gulf
Oil/Gas
1
19.296
58.3%
244.276
59%
73.189
13.349
60
82
19%
34%
8%
18.75%
12,5%
4.25%
$21,65
$ 1.99
Gulf
Gas
1
154.368
58.3%
640.146
59%
35.297
18.486
0
1295
19%
34*
8%
18,75%
12 5%
4.25%
$21.65
$ 1.99
Midwest
Oil/Gas
1
2.509
58,3%
122.138
51%
60.788
11.807
16
15
17%
34%
4%
1 2 . 50%
OX
4.84%
$22.11
$ 2.03
Plains
Oil/Gas
1
2.080
58.3%
186.347
52%
81.855
14.529
26
34
19%
34%
6.75%
12.50%
8%
0%
$21.14
$ 1.43
0V lahotna
Oil/Gas
1
11 200
58.3%
246 324
7ir,
86.820
15.114
37
69
12%
34X
5%
20 , OOX
n
ex
$22,03
$ 1.58
Texas/
Oklahoma
Gas
1
22.400
58,37.
727.636
71%
39.824
21.048
0
1038
12%
34X
5X
20.00%
7X
7X
$22.03
$ 1.58
Northern
Mounta in
Oil/Gas
2
4.992
5B.35C
421 142
55Xq
102 CC2
17.015
53
72
13%
34y.
OX
12.50X
6?
U
$20,74
$ 1.77
Southern
Mounta in
Oil/Gas
1
2 251
58.3%
4S2.053
72%
109.357
17.781
32
69
13X
34 X
BX
16. OOX
4X
67
$21,16
$ 1.98
West
Coast
Oil/Gas
1
33.178
58 . 3%
160.995
90%
82 . 560
13.370
35
0
7%
34%
9.35%
18.75%
0.14X
4%
$18.38
$ 2.21
Alaska
Oi I/Gat,
10
161 0%
58 , 37,
3.207 388
88%
45,938.400
690 900
3700
686
9%
34X
9.40X
14.30X
a
0.14%
$16.37
$ 0.49
lomer 48
States
Oil/Gas
1
14.877
58 . 37,
248,607
69X
83.952
14.463
41
57
12%
34%
6.14%
18,24%
6.67%
a
$20.00
$ 1.65
a Tax based on formula in tax code, not * flat percentage.
Source: ERG 1987.
-------
Taijle V!-? Average Qyantities of Haste Senerated, by Zone
Model project/
zone
Appalachian
Gulf
Midwest
Plains
Texas/Oklahoma
Northern Mountain
Southern Mountain
West Coast
Alaska
Lower 48 States
Gulf |§as only)
lexas/Oklahoma (gas only)
Dri 1 1 ing waste
barrels/.*!!
2,344
10,987
1,853
3,623
5,555
8,569
7.153
1,414
7.504
5.170
10,987
5,555
Produced water
(barrels/barrel
of oil)
2 41
8,4?
23.61
9.11
10.62
12.30
7.31
a. 05
0.15
9.98
17.17*
1M7'
a Barrels of water per million cubic feet of natural gas.
Sources: API 1987a; fTannery and Lanoan 1987,
VI-23
-------
Tables VI-3 and VI-4 and the waste quantity data shown in Table VI-7.
For each model project, waste management costs are calculated for each
waste management scenario.
For each model project and scenario, the available compliance methods
were identified (Table VI-5). Cost estimates for all available
compliance methods, including transportation costs for offsite methods,
were developed based on the unit cost factors (Tables VI-2 and VI-3) and
the waste quantity estimates (Table Vl-7). Each model facility was
assumed to have selected the lowest cost compliance method. Based on
compliance cost comparisons, presented in more detail in the Technical
Background Document, the following compliance methods are employed by
affected facilities under the waste management scenarios:
%
1 nt.ermed i a t e Seen a r i o
1. Drilling wastes - single-liner onsite facility; volume reduction
and transport to offsite single-liner facility if cost-effective.
2. Production wastes - Class II onsite facility.
Subtitle C Scenario
1. Drilling wastes - transport to offsite SCLC facility with site
management and with volume reduction if cost-effective.
2. Production wastes - for waterfloods, onsite injection in Class I
facility; for nonwaterfloods, transport and disposal in offsite
Class I facility.
Sybti 11e C-1 Scenario
1. Drilling wastes - transport to offsite SCLS facility with site
management and with volume reduction if cost-effective.
2. Production wastes - waterfloods exempt; for nonwaterfloods,
transport and injection in offsite Class I facility.
For each model facility under each scenario, the least-cost
compliance method was assumed to represent the cost of affected
projects. Costs for unaffected projects were estimated based on the cost
VI-24
-------
of baseline practices. Weighted average costs for each model under each
scenario (shown in Tables VI-8 and VI-9) incorporate both affected and
unaffected projects. For example, in the Subtitle C 70% Scenario, while
70 percent of projects must dispose of drilling wastes in Subtitle C
facilities, the other 30 percent can continue to use baseline practices.
The weighted average cost is calculated as follows:
Percentage Drilling waste Weighted
Project category of projects disposal cost cost
Affected operations 70% $61,782 $43,248
Unaffected operations 30% $15,176 $ 4,552
Weighted average $47,800
For drilling wastes, the weighted average costs range from $15,176
per well in the Baseline to $47,800 per well in the RCRA Subtitle C 70%
case. Thus, the economic analysis assumes that each well incurs an
additional $32,624 under the RCRA Subtitle C 70% Scenario. For produced
water, costs per barrel of water disposed of range from $0.11 in the
Baseline to $0.62 in the RCRA Subtitle C 70% Scenario. Thus, there is an
additional cost of $0.51 per barrel of water under this scenario.
Impact of Waste Management Costs on Representative Projects
The new oil and gas projects incur additional costs under the
alternative waste management scenarios for both drilling and production
waste management. By incorporating these costs into the economic model
simulations, the impact of these costs on financial performance of
typical new oil and gas projects is assessed. These impacts are
presented in Tables VI-10 and VI-11.
As shown in Table VI-10, the internal rate of return can be
substantially affected by waste management costs, particularly in the
Subtitle C 70% Scenario. From a base case level of 28.9 percent, model
VI-25
-------
fable VI-8 Weighted Average Regional Costs of Drilling Waste Management
for Hodel Projects Under Alternative Waste Managetwnt Scenarios
{Dollars per yell)
Model project/
zone
Appalachian
Gulf
Midwest
Plains
Texas/Oklahoma
Northern Mountain
Soutnern ftoyntain
West Coast
Alaska
Lower 48 States
Baseline
$ S,4§5
24,582
6,014
11,442
17,398
24,186
22,711
2.919
28,779
15.175
fnf e media! e
10S
S 9.102
25.756
6.219
11, §52
*
18.258
25.495
23,511
3.258
30.277
15.964
70%
$10,420
32.796
7.447
14,312
23.418
33.348
28.5S4
5,290
3§,266
20,i64
Subtitle C 10*
and
Subtitle C-l 10»
$12,799
30.848
10,138
16.073
21.163
31.965
29. §83
6,521
35,333
19,837
Subtitle C 701
and
Subtitle C-l 70%
$ 32,801
68.440
34,880
43. ess
43,755
76,636
71,555
28,135
74,661
47,800
NOTE: Costs in 1985 dollars, based on 1985 cost factors.
Source: £Ri estimates.
¥1-26
-------
Table VI-3 Ueignted Average Unit Costs of Produced Water Management
for Model Projects under Alternative Waste Management Scenarios
(Dollars per Barrel of Water)
Model project/
zone
Appa lachian
Golf
Midwest
Plains
Texas/OK lahoraa
Northern Mountain
Southern Mountain
West Coast
Alaska
Lower Ati States
Baseline
$0.52
0.08
0.14
0.16
0.13
0.07
0.13
0.04
0.3!
0.11
lire-mediate
10%
$0 57
0.06
0.14
0.16
0.13
O.C7
0.13
0.04
0.31
0.11
70%
$0.94
0.10
0.14
0.16
0.13
0.07
0,13
0.04
0.31
0.12
SuhT it 'P C
10%
$0,80
0.16
0.22
0.24
O.ZO
0.11
0.19
0.08
0.46
0.18
70;,
$2.51
0.65
0.65
0.74
0 61
0.36
0.55
0.34
1.42
0.62
Subt it
10v.
$0.67
0.15
0.15
0.20
0.15
0.09
0.14
. 0.07
0.34
0.15
!e C-!
70%
$1.57
0.57
0.20
0,47
C.31
0.22
0.24
0.26
0.56
0.35
NOTE: Waste management costs applied to both oil and gas production wastes.
Costs in 1985 dollars.
Source: ERG estimates.
VI-27
-------
Table VI-10 Impact of Waste Management Costs on Model Projects: Comparisons
of After-lax Internal Rate of Return
CO
Alternative waste ma
Model project/
zone
Appalachian
Gulf-gas
Gulf-oil
Midwest
Plains
Texas/Ok lahowa-gas
Texas/Ok lahoma-oi 1
Northern Mountain
Southern Mountain
West Coast
Alaska
Lower 48 States
Basel me
10, 3X
22.9
36.4
12 1
9,0
19, S
29.6
19 .6
9.2
35.0
10.9
28.9
Intermtdiate
I OX
10. 2X
22.8
36.2
12.1
9.0
19.5
29.5
19.5
9.2
35.0
10.9
28.8
70X
8.9X
n s
34.5
11.6
8,6
19,3
28,9.
19.0
9.0
34.5
10.9
28.0
Suht
10X
8.9X
22.5
33.2
8.2
6,9
19.4
27.4
18.2
8.3
33,6
#
10.8
2C.6
r»aqe?nent scenarios
itle C
70'X
0.9X
20.7
15.6
-19.4
-5.6
18.3
14.6
10.1
3.3
25.4
10.6
13.0
Suhtit le C-
10%
9,2%
22.6
33.5
10.9
7.7
19.4
28.4
18.6
8.7
33.8
10.9
27.6
" 1
70'X
3.6X
20,7
17,9
5,1
0,0
18.5
22.1
13.1
6.3
26 9
10.8
19,7
NOTE: Both drilling and production wastes regulated,
alnternal rate of return defined as return after corporate taxes, to total invested capital including both equity and debt,
Source: ERG estimates.
-------
lable Vl-ll Impact of Waste Hanageinent Costs or. ModeJ Projects:
Increase in Total Cost of Production1*
(Dollars per Barrel of Oil Produced)
Model project/
lone
Appalachian
Gulf-gas
Gulf-oil
Midwest
Plains
Texas/Ok lahoma-gas
Texas/Ok lahoma-oi 1
Northern Mountain
Southern Mountain
West Coast
Alaska
Lower 48 States
Total
basel me
cost
$11 22
9.4$
15 65
19 4$
18 46
7,61
14,86
15.51
18.05
13 .19
15.02
14.11
Incrt-ase in cost under alternat
Intermediate
10%
$ 0.05 $
0.01
0.01
0.01
0.02
0.01
0 01
0.02
0 01
0,00
0.00
0.01
m
0.44
0.03
0.17
0.0?
0 03 '
0.02
0 07
0.12
0.08
0.07
0.00
0.11
Sutit it le
I OX
J 0.41,
0.03
0.40
1,11
0 51
t
0 02
0.40
0.36
0.29
0.23
0.01
0,40
ive waste mar
C
7 OK
S 3,24
0,20
2. 8S
8,31
3,69
0.11
1.24
2.56
2,01
1.G8
0.10
2 88
,aqr!Ti«>nt scenarios
Subt it le C-
10X
$ 0.33
0.03
0.36
0.34
0.33
0.0?
0.20
0.23
0.16
0.18
0,00
0.20
1
JQK
$ 2 35
0.20
2 48
M2
2 «C
0 09
2 74
1.65
0 99-
I 34
0.03
1.15
a Total cost of production defined to include capital costs, operating costs, lease bonys costs, and pollution control costs,
as well as transfer payments such as federal income taxes, royalties, arid State severance taxes.
Source: ERG estimates.
-------
project after-tax internal rates of return decline under the waste
management scenarios to the 13.0 to 28.8 percent range for the Lower 48
average.
The after-tax cost of producing hydrocarbons can also increase
substantially. As Table VI-11 shows, these costs can increase by up to
52.98 per barrel of oil equivalent (BOE), a 20 percent increase over
baseline costs. The impacts of these cost increases on a national level
are described further below.
REGIONAL- AND NATIONAL-LEVEL COMPLIANCE COSTS OF THE WASTE
MANAGEMENT SCENARIOS
The cost of waste management for the typical projects under each
waste management scenario (see Tables VI-8 and Vl-9) were used in
conjunction with annual drilling (API 1986} and production levels (API
1987c) to estimate the regional- and national-level annual costs of the
waste management scenarios. These costs, which include both drilling and
production waste disposal costs, are presented in Table Vl-12.
National-level costs range from S49 million in the Intermediate 10%
Scenario to more than S12.1 billion in the Subtitle C 70% Scenario.
The costs presented in Table VI-12 do not include the effects of
closures. They are based on 1985 .drilling and production levels,
assuming that no activities are curtailed because of the requirements of
the waste management scenarios. In reality, each of the waste managsijent
scenarios would result in both the early closure of existing projects and
the cancellation of new projects. To the extent that the level of oil
and gas activity declines, total aggregate compliance costs incurred
under each waste management scenario will be lower, but there will be
other costs to the national economy caused by lower levels of oil
production. These effects are described more fully below.
VI-30
-------
Table Vl-1? Annual Regional and national RCRft Compliance Cost of Alternative Waste
(Mi llions of Dollars)
Scenarios
OJ
Model project/
zone
Appalachian
Gulf
Hi**»t
Plains
Texas/Oklahoma
Northern Mountains
Southern Mountains
West Coast
Alaska
Lower 48 States
National lotal
Intermediate
10X
$5
8
1
2
26
3
3
1
0
49
49
70*
$43
94
6
17
181
19
21
36
2
418
420
Waste management
Subtitle C
10K
$57
200
120
128
879
94
92
126
17
1.693
1.710
scenarios
70X
$403
1.417
870
907
6.1%
677
643
936
118
12.007
12.125
Sub! it It C-l
1 OX 70Z
$47 $3?8
180 1.239
31 185
77 576
44? 2.873
S'j 404
47 297
97 736
*> 34
9?S 6.637
980 6.67J
NOTE: Figures represent before-tax total annual increase in waste management tost over baseline costs at 198S levels
of drilling and production, without adjusting for decreases in industry activity caused by higher production costs at
affected sites. Column totals may differ because of independent rounding Base year for all costs is 138S,
-------
CLOSURE ANALYSIS FOR EXISTING WELLS
The potential of the waste management scenarios to shut down existing
producing wells was estimated using the model facility approach. The
model facility simulations for existing projects, however, do not include
the initial capital cost of leasing and drilling the production well.
For the analysis of existing projects, it is assumed that these costs
have already been incurred. The projects are simulated for their
operating years. If operating revenues exceed operating costs, the
projects remain in production.
Closures of existing wells are estimated by using a variable called
the economic limit (i.e., a level of production below which the project
cannot continue to operate profitably). Under the waste management
scenarios, produced water disposal costs are higher and, therefore, the
economic limit is higher. Some projects that have production levels that
exceed the baseline economic limit would fall below the economic limit
under the alternative waste management scenarios. Those projects not •
meeting this higher level of production can be predicted to close. This
analysis was conducted only with respect to stripper wells. To the
extent that certain high-volume, low-margin wells may also be affected,
the analysis may understate short-term project closures.
The economic limit analysis requires information on the distribution
of current production levels across wells. Because of the lack of data
for most States, the economic limit analysis is presented here only for
Texas and on a national level. The 1985 distribution of production by
volume size class for Texas and for the Nation as a whole is shown in
Table Vl-13.
Table VI-14 displays the results of the economic limit analysis.
Under baseline assumptions, the representative Lower 48 project requires
2.40 barrels per day to remain in operation. The economic limit for
VI-32
-------
Table VI-I3 Distribution of Oil Production
Across Existing Projects, 1985
Region
Production
Interval (BOPD)
bbl/d
Number
of Wells
Total 0*1
Product ion
1000 bb/d
(tdl icrtal
0 - 1
1 - 2
2 - 3
3 - 4
4 - 5
5 - 6
& - 7
7 - B
8 - 9
9 - 10
112,000
112,000
78.000
65.000
20,000
27,000
21,000
16.000
15.000
9.000
n
165
206
231
92
154
142
119
129
63
!?5,000
1.371
Texas
1.0 - 1,5
1.6 - 2.5
2 6 - 3.5
3.S - 4,5
4.6 - 5.5
5.6 - 6.5
6.6 - 7.5
7,6 - 8,6
9,6 - 1.05
42,831
15.018
20.856
14.018
11,303
9.665
7,638
6,201
5,420
4,441
19
43
43
46
45
46
44
44
45
Total
446
142,743
Sources: :The Effect of Lower Oil Prices on Production From Proved U.S.
Oil Reserves," Energy and Environmental Analysis, Inc.,
February 1987, taken from Figyre 2-2. Indicators:... A
Pata Revie*-Apri1 1986. Railroad Conmission of Teas, April
1986.
Vi-33
-------
Table VI -14 Impact of Waste Managtment Cost on Existing Production
GJ
Lower-ranqe effects
Region Scenario
Texas
Baseline8
Intermediate 10X
Intermediate 70%
Subtitle C 10%
Subtitle C 70%
Subtitle C-l 10X
Subtitle C-l 70S
National: Lower 48 States
Basel ineb
Intermediate 10%
Intermediate 70%
Subtitle C 10%
Subtitle C 70*
Subtitle C-l 108
Subtitle C-l 70%
Economic
1 imit
(bbl/d)
2,30
2,32
2.38
3 89
3,89
2,73
2,73
2,40
2,42
2 42
4 20
4.20
3,01
3,0!
Well c
Number
of wells
42
292
2,260
15,818
740
5,177
156
1,092
11,580
81.060
4,745
33,215
losures
Percent
of wells
0.02
0.15
113
7 94
0.37
2,60
0.03
0.18
1.87
13.07
0.77
5.36
tost product ion
1000
bbl/d
0,09
0.60
' 6.92
48 «1
1.84
11,87
0,41
2,88
37,3?
261.23
13 00
88.14
Percent of
product ion
0 00
0,03
0.30
2.0?
0 00
0 55
0 00
0.03
0 44
3.07
0 15
1 04
Upper -ranoe effects
Well c losurr?
Number Ptfcent
of we) Is of wi-1 Is
6.562
45.931
8.780
61,457
7.259
50.816
20,652
144.564
32,076
224.532
25.241
176.687
3 29
23,05
4 41
30 S4
3 64
25 SO
3.33
23.31
517
36. 20
4.07
?8.49
Lost
1000s
bbl/d
5.60
33,22
12.00
87.04
7,36
51 49
21,00
148 45
58.00
406,79
33 00
233.70
product ion
Percent of
product ion
0 24
1 67
0,53
3 71
0.31
2.20
0.25
1,75
0,68
4 79
0.39
2,75
Baseline production level is 2,3 million bbl/d; baseline well total is 199,000,
Baseline production level is 8,6 million bbl/d; baseline well total is 620.000.
Source: ERG estimates.
-------
affected operations rises to 3.01 to 4.20 barrels per day under the waste
management scenarios. The increase in the economic limit results in
closures of from 0.03 percent to 36.20 percent of all producing wells.
The "lower-range effects" in Table VI-14 assume that only affected
wells (i.e., wells generating hazardous produced waters) producing at
levels between the baseline economic limit and the economic limit under
the waste management scenarios will be closed. The "upper-range effects"
assume that all affected wells producing at levels below the economic
limit under the waste management scenarios will be closed, and are
adjusted to account for the change in oil prices from 1985 to 1986.
Under the lower-range effects case, production losses are estimated
at between 0.00 and 3.07 percent of total production. Under the
upper-range effects assumptions, production closures range from 0,25 to
4.79 percent of the total. These results are indicative of the
immediate, short-term impact of the waste management scenarios caused by
well closures.
The results of the Texas simulation mirror those of the
national-level analysis. This would be expected, since nearly 30 percent
of all stripper wells are in Texas, and the State is, therefore,
reflected disproportionately in the national-level analysis. Under the
lower-range effects assumptions, Texas production declines between 0.00
and 2.07 percent. Under the upper-range effects assumptions, Texas
production declines between 0.24 and 3.71 percent.
THE INTERMEDIATE AND LONG-TERM EFFECTS OF THE WASTE
MANAGEMENT SCENARIOS
Production Effects of Compliance Costs
The intermediate and long-term effects of the waste management
scenarios will exceed the short-term effects for two principal reasons.
VI-35
-------
First, the increases in drilling waste management cost, which do not affect
existing producers, can influence new project decisions. Second, the
higher operating costs due to produced water disposal requirements may
result in some project cancellations because of the expectation of reduced
profitability during operating years. Although such projects might be
expected to generate profits in their operating years (and therefore might
be expected to operate if drilled), the reduced operating profits would not
justify the initial investment.
The intermediate and long-term production effects were estimated using
Department of Energy (DOE) production forecasting models. As described
above, an economic simulation model was used to calculate the increase in
the cost of resource extraction under each waste management scenario.
These-costs were used in conjunction with the DOE FOSSIL2 model (DOE 1935)
and the DOE PROLOG model (DOE 1982) to generate estimates of intermediate
and long-term production effects of the waste management scenarios.
For the FOSSIL2 model, an estimate of the increase in resource
extraction costs for each waste management scenario, based on model project
analysis, was provided as an input. Simulations were performed to measure
the impact of this cost increase on the baseline level of production.
For the PROLOG model, no new simulations were performed. Instead,
results of previous PROLOG modeling were used to calculate the elasticity
of supply with respect to price in the PROLOG model. The model project
simulation results were used to calculate an oil price decline that would
have the same impact as the cost increase occurring under each alternative
waste management scenario. These price increases were used in conjunction
with an estimate of the price elasticity of supply from the PROLOG model to
estimate an expected decline in production for each waste management
scenario.
VI-36
-------
Table VI-15 shows the results of this analysis. The long-term impacts
of the waste management scenarios range from levels that are below the
detection limits of the modeling system to declines in production ranging
up to 32 percent in the year 2000, based on the PROLOG analysis. For the
FOSSIL2 simulations, production declines were estimated to range from "not
detectable" to 18 percent in the year 2000 and from "not detectable" to 29
percent in the year 2010.
Additional Impacts of Compliance Costs
The decline in U.S. oil production brought about by the cost of the
waste management scenarios would have wide-ranging effects on the U.S.
economy. Domestic production declines would lead to increased oil imports,
a deterioration in the U.S. balance of trade, a strengthening of OPEC's
position in world markets, and an increase in world oil prices. Federal
and State revenues from leasing and from production and income taxes would
decline. Jobs would be lost in the oil and gas drilling, servicing, and
other supporting industries; jobs would bfe created in the waste management
iiidustries (e.g., contractors who drill and complete Class I injection
wells).
It is beyond the scope of this report to fully analyze all of these and
other macroeconomic effects. To illustrate the magnitude of some of these
effects, however, five categories of impacts were defined and quantified
(oil imports, balance of trade, oil price, Federal leasing revenues, and
State production taxes). These are presented in Table VI-16. Measurable
effects are evident for all but the lowest cost (Intermediate 10% Scenario).
The impacts of the waste management scenarios on the U.S. economy were
analyzed utilizing the DOE FOSSIL2/WOIL modeling system. Cost increases
for U.S. oil producers create a slight decrease in the world oil supply
curve (i.e., the amount of oil that would be brought to market at any oil
price declines). The model simulates the impact of this shift on the world
petroleum supply, demand, and price.
VI-37
-------
Table VI-15 long-Term Impacts on Production of Cost Increases
under Waste Management Scenarios
III
Estimated resource
Decline of domestic oil production in.lower 43 Stales
Scenario
Intermediate 101
extraction cost
increase (%)
0.16
Year ]'•
FOSS1L2
No detectable
change
'?0
PROLOG
' No detectable
change
Year
FOSSIL?
No detectable
change
?000
PROLOG
No detectable
change
Year ?010
FOSSIL?
No delectable
change
Intermediate 7QX
43
No detectable Mo detectable
change change
1.4X NO rleteclahle
change to 0.4"X
1.63J
Subtitle C 107,
9.51
No detectable 0.3X to 0.45C
change
1.6X to 3.55!
C.3X
GJ
CO
Subtitle C 70%
Subtitle C-l 10X
Subtitle C-l 70X
68.84
4.73
36. SI
3.2X
No detectable
change
2. IX
6.9X to 7.8X
No detectable
change
3.7X to 4.3X
18. IX
1.4X
12.5%
19 .17. to 32. K
0.3X to 1.4X
10. n to 18.5%
?a . ex
3.?X
19. OX,
Soyrce: ERG estimates for extraction cost increase and for PROLOG impacts. Applied Energy Services of Arlington, Virginia.
(Wood 1987) for FOSSIL? results, based on specific runs of U.S. Department of Energy FOSSU2 Model for alternative scenario cost
increases. Department of Energy baseline crude oil price per barrel assumptions in FOSS1L2 were i?0 ?4 in 1990, $33.44 in 2COO,
and $52.85 in ?010.
-------
Table VI-16 Effect of Domestic Production Decline on
Selected Economic Parameters in the Year 2000
Waste management
scenario
Intermediate 10X
Intermtdtate 70X
Subtitle C \m
Subtitle C 70%
Subtitle C-l 10X
Subtitle C-l 7 OX
Increase in
Projected decline petroleum imports
in lower 48 (mi) lions of
production (X) barrels per day)
N.O. NO.
1.4X N D.
4.2X 0.2
18.1% 11
1.4% 0.1
12. SX 07
Increase in U.S
balance of trade
deficit
($ bi 11 ions
per year)
N.O.
$0.2
$3 .2
$17. S
$1.6
$11.3
Increase in
world 01 1 price
(dollars ptr
barrel)3
N.O.
$0.00
$0.21
$1.08
JO. 12
$0.76
Annual cost to De-crease in
consumers of the oil Federal leasing
price increase revenues
($ bill ions ($ mill ions
per year) per year)
NO NO.
JO. 4 $19.1
$1.2 J53.6
$6.4 $279.8
$0.7 $209
$4.5 $176?
Decrease in State
ta* revenues
($ mi 1 lions
per year)
N.O.
$71 .0
$208.9
$903.2
$60.7
$616 1
N.O. - Not detectable using the FOSSllH/WQil modeling system
8 Revised baseline values for year ?000 in the FOSS1L2 modeling system include (1) lower 48 States crude oil production of 7.? million barrels per day,
(2) U.S. imports of 9.2 million barrels per day; and (3) world crude oil pMce of $33.44 per barrel.
Source; Results based on U.S Department of Energy's FOSS1L2/UOH energy modeling system, with special model runs for individual waste management scenario
production costs effects conducted by Applied Energy Services of Arlington. Virginia (Mood 1987) [RG estimates based on FOSSH2 results.
-------
A new equilibrium shows the following effects:
• A lower level of domestic 'supply (previously depicted in
Table VMS);
• A higher world oil price (see Table VI-16);
• A decrease in U.S. oil consumption caused by the higher world
oil price; and
• An increase in U.S. imports to partially substitute for the
decline in domestic supply (also shown in Table VI-16).
The first numerical column in Table VI-16 shows the decline in U.S.
production associated with each waste management scenario. These
projections, derived from simulations of the FOSSIL2/WOIL modeling
system, were previously shown in Table VI^15. The second column in
Table VI-16 provides FOSSIL2/WOIL projections of the increase in
petroleum imports necessary to replace the lost domestic supplies. The
projections range from "not detectable" to 1.1 million barrels per day,
equal to 1.4 to 18.1 percent of current imports of approximately 6.1
million barrels per day.
The third column in Table VI-16 shows the increase in the U.S.
balance of trade deficit resulting from the increase in imports and the
increase in the world oil price. The increase in the U.S. balance of
trade deficit ranges from SO.2 to $17.5 billion under the waste
management scenarios. The projected increase in petroleum imports under
the most restrictive regulatory scenarios could be a matter for some
concern in terms of U.S. energy security perspectives, making the country
somewhat more vulnerable to import disruptions and/or world oil price
fluctuations. In the maximum case estimated (Subtitle C 70% Scenario),
import dependence would increase from 56 percent of U.S. crude oil
requirements in the base case to 64 percent in the year 2000.
VI-40
-------
The fourth column shows the crude petroleum price increase projected
under each of the waste management scenarios by the FOSSIL2/WOIL inodeling
system. This increase ranges from SO.06 to SI.08 per barrel of oil (a
0.2 to 3 percent increase). This increase in oil price translates into
an increase in costs to the consumer of SO.4 to S6.4 billion in the year
2000 (column five). These estimates are derived by multiplying
FOSSILZ-projected U.S. crude oil consumption in the year 2000 by the
projected price increase. The estimates assume that the price increase
is fully passed through to the consumer with no additional downstream
markups.
Federal leasing revenues will also decline under the waste management
scenarios. These revenues consist of lease bonus payments (i.e., initial
payments for the right to explore Federal lands) and royalties (i.e.,
payments to the Federal government based on the value of production on
Federal lands). Both of these revenue sources will decline because of
the production declines associated with the waste management scenarios.
If the revenue sources are combined, there will be a reduction of $19 to
S280 million in Federal revenues in the year 2000.
State governments generally charge a tax on crude oil production in
the form of severance taxes, set as a percentage of the selling price.
On a national basis, the tax rate currently averages approximately 6.7
percent. Applying this tax rate, the seventh column in Table VI-16 shows
the projected decline in State tax revenues resulting from the waste
management scenarios. These estimates range from about $60 million to
$900 mill ion per year.
VI-41
-------
REFERENCES
API. 1986, American Petroleum Institute, Jointassociation survey on
drill ing costs.
. 1987a. American Petroleum Institute. API_1985 production waste
survey. June draft.
. 1987b. American Petroleum Institute. API 1985 production waste
survey supplement. Unpublished.
. 1987c. American Petroleum Institute. Basic petroleum data
book. Volume VII, No. 3. September 1987.
Camp, Dresser & McKee, Inc. 1986. Superfund treatment technologies: a
vendor inventory. EPA 540/2-8/004.
Cullinane, M. John, Jones, Larry W., arid Malone, Phillip G. % 1986.
Handbook for stabil izat ion/sol.idrfjcation of hazardous w%aste.
EPA/540/2-86/001. June.
Eastern Research Group (ERG), Inc. 1987. Economic impacts of
alternative waste management scenarios for the onshore- oil and gas
Industry. Report 1: baseline cases. Report prepared for the U.S.
Environmental Protection Agency, Office of Solid Waste. Revised
December 1987.
Erlandson, Steven. 1986. Personal communication between Anne Jones,
ERG, and Steven Erlandson, Enreco, Inc., December 22, 1986.
Flannery, David. 1987. Personal communication between Maureen Kaplan,
ERG, and David Flannery, Robinson and McElwee, Charleston, West
Virginia, October 13, 1987.
Flannery, David, and Lannan, Robert E. 1987. An analysis of the economic
impact ofnewhazardous waste regulations onthe Appalachian Basin
0.1.1 and gas industry. Charleston, West Virginia: Robinson & McElwee.
Freeman, B.D., and Deuel, L.E, 1986. Closure of freshwater base drilling
mud pits in wetland and upland areas in Proceedings of a National
Conference on Drilling Muds: Hay 1986. Oklahoma: Environmental
and Ground Water Institute.
Hanson, Paul M., and Jones, Frederick V. 1986. Mud disposal, an
industry perspective. Dr i11inq. May 1986.
North America Environmental Service. 1985. Closure plan for theBig
Diamond Trucking Service,Inc.. drilling mud disposal pit near Sweet
Lake. LA.
VI-42
-------
Pope Reid Associates. 1985a. Appendix F - cost model in liner location
risk and cost ana1ysismode 1. Prepared for U.S. Environmental
Protection Agency, Office of Solid Waste.
. 198Sb. Engineering costs ..supplement to Appendix F of the liner
location report. Prepared for U.S. Environmental Protection Agency,
Office of Solid Waste.
. 1987a. Facilities design tool cost model. Available on the U.S.
Environmental Protection Agency computer in Research Triangle Park,
North Carolina.
. 1987b. Land treatment computer cost model. Available on the
U.S. Environmental Protection Agency computer in Research Triangle
Park, North Carolina,
Rafferty, Joe. 1987. Personal communication between Scott Carl in, ERG,
and Joe Rafferty, Ramteck Systems, Inc., February 4, 1987.
. 1985. Recommended practices for the reduction of drill site
wastes in Proceedings .of ...a National Conference on Dri1Tinq_Mud
Wastes.:.,. Hay 1985. Oklahoma; Environmental and Ground Water
Institute.
Slaughter, Ken, 1987. Personal communication between Scott Carl in, ERG,
and Ken Slaughter, New Park Waste Treatment Systems, February 5, 1987.
Tesar, Laura, 1986. Personal communication between Anne Jones, ERG, and
Laura Tesar, VenVirotek, December 31, 1986.
Texas Railroad Commission. 1986. Indicators: a monthly data review,
April 1986.
Tilden, Greg. 1987a. Class I and class II disposal well cost
estimates. Prepared by Epps & Associates Consulting Engineers, Inc.,
for Eastern Research Group, Inc., February 1987.
. 1987b. Revised class 1 and class II disposal well cost
estimates. Prepared for Eastern Research Group, Inc., November 1987.
U.S. Department of Energy. 1982. Production of onshore Lower 48 oil and
gas - model methodology and data description. DOE/EIA -0345;
DE83006461.
. 1985. National energy policy plan projections to 2010.
DOE/PE - 0029/3.
USEPA. 1986. U.S. Environmental Protection Agency, Office of Policy
Analysis. 1985 survey of selected firmsinthe commercial hazardous
waste management industry.
VI-43
-------
Vidas, E, Harry, 1987, The effect of lower oil prices on productionfrom
proved U.S. oil reserves. Energy and Environmental Analysis, Inc.
Webster, William. 1987. Personal communication between Anne Jones, ERG,
and William Webster, Envirite, January 7, 1987,
Wood, Francis. 1987. Personal communication between David Meyers, ERG,
and Francis Wood, Applied Energy Services of Arlington, Virginia,
regarding FOSS1L2 results, December 1987.
VI-44
-------
CHAPTER VII
CURRENT REGULATORY PROGRAMS
INTRODUCTION
A variety of programs exist at the State and Federal levels to
control the environmental impacts of waste management related to the oil
and gas industry. This chapter provides a brief overview of the
requirements of these programs. It also presents summary statistics on
the implementation of these programs, contrasting the numbers of wells
and other operations regulated by these programs with resources available
to implement regulatory requirements.
State programs have been in effect for many years, and many have
evolved significantly over the last decade. The material presented here
provides only a general introduction to these complex programs and does
not attempt to cover the-details of State statutes and current State
implementation policy. Additional material on State regulatory programs
can be found in Appendix A. Federal programs are administered both by
the Environmental Protection Agency and by the Bureau of Land Management
within the U.S. Department of the Interior.
STATE PROGRAMS
The tables on the following pages compare the principal functional
requirements of the regulatory control programs in the principal oil- and
gas-producing States that have been the focus of most of the analysis of
this study. These States are Alaska, Arkansas, California, Colorado,
Kansas, Louisiana, Michigan, New Mexico, Ohio, Oklahoma, Texas, West
Virginia, and yyoming.
-------
Table VII-1 covers requirements for reserve pit design, construction,
and operation; Table VII-2 covers reserve pit closure and waste removal.
Table VII-3 presents requirements for produced water pit design and
construction, while Table VII-4 compares requirements for the produced
water surface discharge limits. Table VII-5 deals with produced water
injection well construction; these requirements fall under the general
Federal Underground Injection Control program, which is discussed
separately below under Federal programs. Finally, Table VI1-6 discusses
requirements for well abandonment and plugging.
FEDERAL PROGRAMS — EPA
Federal programs discussed in this section include the Underground
Injection Control (UIC) program and the Effluent Limitations Guidelines
program administered by the EPA.
Underground Injection Control
The Underground Injection Control (UIC) program was established under
Part C of the Safe Drinking Water Act (SDWA) to protect underground
sources of drinking water (USDWs) from endangerment by subsurface
emplacement of fluids through wells. Part C of the SDWA requires EPA to:
I. Identify the States for which UIC programs may be necessary--EPA
listed all States and jurisdictions;
2. Promulgate regulations establishing minimum requirements for State
programs which:
• prohibit underground injection that has not been authorized by
permit or by rule;
» require applicants for permits to demonstrate that underground
injection will not endanger USDWs;
• include inspection, monitoring, record-keeping, and reporting
requirements.
VII-2
-------
*
These minimum requirements are contained in 40 CFR Parts 144 and
]46, and were promulgated in June 1980.
3. Prescribe by regulation a program applicable to the States, in
cases where States cannot or will not assume primary enforcement
responsibility. These direct implementation (DI) programs were
codified in 40 CFR Part 147.
The regulations promulgated in 1980 set minimum requirements for 5
classes of wells including Class II wells—wells associated with .oil and
gas production and hydrocarbon storage. In December 1980, Congress
amended the SDWA to allow States to demonstrate the effectiveness of
their in-place regulatory programs fpr Class II wells, in lieu of
demonstrating that they met the minimum requirements specified in the UIC
regulations. In order to be deemed effective, State Class II programs
had to meet the same statutory requirements as the other classes of
wells,' including prohibition of unauthorized injection and protection of
underground sources of drinking water. (§1425 SDWA). Because of the
large number of Class II wells, the regulations allow for authorization
by rule for existing enhanced recovery wells (i.e., wells that were
injecting at the time a State program was approved or prescribed by
EPA). In DI States, these wells are subject to requirements specified in
Part 147 for authorization by rule, which are very similar to
requirements applicable to permitted wells, with some relief available
from casing and cementing requirements as long as the wells do not
endanger USDWs. In reviewing State programs where the intent was to
"grandfather" existing wells as long as they met existing requirements,
EPA satisfied itself that these requirements were sufficient to protect
USDWs. In addition, all States adopted the minimum requirements of
§146.08 for demonstrating mechanical integrity of the wells (ensuring
that the well was not leaking or allowing fluid movement in the
borehole), at least every 5 years. This requirement was deemed by EPA
VII-3
-------
to ba§absolutely necessary in order to prevent endangerment of USDWs. In
addition, EPA and the States have been conducting file reviews of all
wells whether grandfathered or subject to new authorization-by-rule
requirements. File reviews are assessments of the technical issues that
would normally be part of a penit decision, including mechanical
integrity testing, construction, casing and cementing, operational
history, and monitoring records. The intent of the file review is to
ensure that injection wells not subject to permitting are technically
adequate and will not endanger underground sources of drinking water.
Because of §1425 and the mandate applicable to Federal programs
not to interfere with or impede underground injection related to oil and
gas production, to avoid unnecessary disruption of State programs and to
consider varying geologic, hydrologic, and historical conditions in
different States, EPA has accepted more variability in this program than
in many of its other regulatory programs. Now that the program has been
in place for several years, the Agency is starting to look at the
adequacy of the current requirements and may eventually require more
specificity and less variation among States.
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 as 41 FR (44942). The rulemaking also
proposed Best Available Technology Economically Achievable (BAT) and New
Source Performance Standards.
VII-4
-------
On April 13, 1979, BPT Effluent Limitations Guidelines were
promulgated for the Onshore Subcategory, Coastal Subcategory, and
Agricultural and Wildlife Water Use Subcategory of the Oil and Gas
Extraction Industry (44 FR 22069). Effluent limitations were reserved
for the Stripper Subcategory because of insufficient technical data.
The 1979 BPT regulation established a zero discharge limitation for
all wastes under the Onshore Subcategory. Zero discharge Agricultural
and Wildlife Subcategory limitations were established, except for
produced water, which has a 35-mg/L oil and grease limitation.
The American Petroleum Institute (API) challenged the 1979 regulation
(including the BPT regulations for the Offshore Subcategory) (661
F.20.340(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.
Summary of Major Regulatory Activity Related to Onshore Oil and Gas
October 13, 1975 - 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
VII-5
-------
July 21, 1982 - Response to American Petroleum Institute vs. EPA
Court Decision
- Recategorization of 1,700 "onshore" wells to
Coastal Subcategory
- Suspension of regulations for Santa Maria Basin,
California
- Planned reexamination of marginal gas wells for
separate regulations
Onshore Segment Subcategories
Onshore
• BPT Limitation
-- Zero discharge
• Defined; NO 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).
Stripper (Oil Wells)1
• Category reserved
• Defined: TEN barrels per well per calendar day or less of crude
oil.
This subcategory does not include marginal gas wells.
VII-6
-------
Coastal
» BPT Limitations
-- No discharge of free oil (no sheen)
-- Oil and grease: 72 mg/L (daily)
48 mg/L (average monthly)
(produced waters)
• Defined: Any body of water landward of the territorial seas or
any "wetlands adjacent to such waters.
Wildlife and Agriculture Use
» BPT Limitations
-- Oil and Grease: 35 mg/L (produced -waters)
-- Zero Discharge: ANY waste pollutants
• 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.
VII-7
-------
FEDERAL PROGRAMS--BUREAU OF LAND MANAGEMENT
Federal programs under the Bureau of Land Management (BLM) within the
U.S. Department of the Interior are discussed in this section.
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 exercises authority under 43 CFR
3160 for regulation of onshore oil and gas practices on Federal and
Indian lands,. The Department of the Interior administers its regulatory
program through BLM offices in the producing States. These offices
generally have procedures in place for coordination with State agencies
on regulatory requirements. Where written agreements are not in place,
BLM usually works cooperatively with the respective State agencies.
Generally, where State requirements are more stringent than those of BLM,
operators must comply with the State requirements. Where State
requirements are less stringent, operators must meet the BLM requirements.
The Bureau works closely with the U.S. Forest Service for surface
stipulations in Federal forests or Federal grasslands. This cooperative
arrangement is specifically provided for in the Federal regulations.
VII-8
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Rules and Regulations
BLM has authority over oil and gas activities on Federal lands. The
authority includes leasing, bonding, royalty arrangements, construction
and well spacing regulations, waste handling, most waste disposal, site
reclamation, and site maintenance.
Historically, BLM has controlled oil and gas activities through
Notices to Lessees (NTLs) and through the issuance of permits. The
Bureau is working to revise all notices into Oil and Gas Orders, which
will be Federally promulgated. To date, Oil and Gas Order No. 1 has been
issued.
While the regulations, NTLs, and orders provide the general basis for
regulation of oil and gas activities on Federal and Indian lands, there
are variations in actual application of some of the requirements among
BLM districts. In many cases, the variations are in response to specific
geographical or geological characteristics of particular areas.
For example, in middle and southern Florida, the water table is near
the surface. As a result, BLM requires the use of tanks instead of mud
pits for oil and gas drilling activities on Federal lands in this area.
In southeast New Mexico, there is simultaneous development of potash
resources and oil and gas resources, and drilling and development
requirements are imposed to accommodate the joint development
activities. In general, more stringent controls of wastes and of
disposal activities are required for oil and gas activities that could
affect ground-water aquifers used for drinking water.
VII-9
-------
Dr i 11inq
Before beginning to drill on Federal land, operators roust receive a
permit to drill from BLM. The permit application must include a
narrative description of waste handling and waste disposal methods
planned for the well. Any plans to line the reserve pit must be detailed.
The lease is required to be covered by a bond prior to beginning
drilling of the well. But the bonds may be for multiple wells, on a
lease basis, statewide basis, or nationwide basis. The current bond
requirement for wells on a single lease is $10,000. Statewide bonds are
$25,000, but bonds must be provided separately for wells on public land
and wells on Federally acquired land. The requirement for a nationwide
bond is $150,000.
BLM considers reserve pits, and some other types of pits, as
temporary. Except in special circumstances, reserve pits do not have to
be lined. NTL-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 pit
walls without the prior authorization of the authorized officer.
Unlined pits may be retained as emergency pits, if approved by the
authorized officer, when a well goes into production.
Landspreading of drilling and reworking wastes by breaching pit walls
is allowed when approved by the authorized officer.
VII-10
-------
Production
Produced waters may be disposed of by underground injection, by
disposal into lined pits, or "by other acceptable methods." An
application to dispose of produced water must specify the proposed method
and provide information that will justify the method selected. One
application may be submitted for the use of one disposal method for
produced water from wells and leases located in a single field, where the
water is produced from the same formation or is of similar quality.
Disposal in Pits: A number of general requirements apply to disposal
into permanent surface disposal pits, whether lined or unlined. The pits
must:
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;
3. Be fenced to prevent livestock or wildlife entry to the pit, when
required by an authorized officer;
4. Be kept reasonably free from surface accumulations of liquid
hydrocarbons by use of approved skimmer pits, settling tanks, or
other suitable equipment; and
5. Be located away from the established drainage patterns in the area
and be constructed so as to prevent the entrance of surface water.
Approval of disposal of produced water into unlined pits will be
considered only if one or more of the following applies:
The water is of equal or better quality than potentially
affected ground water or surface waters, or contains less than
5,000 ppm total dissolved solids (annual average) and no
objectionable levels of other toxic constituents;
vn-n
-------
• A substantial proportion of the produced water is being used for
beneficial purposes, such as irrigation or livestock or wildlife
watering;
• The volume of water disposed of does not exceed a monthly
average of 5 barrels/day/facility; and
• A National Pollutant Discharge Elimination System (NPDES) permit
has been granted for the specific disposal method.
Operators using unlined pits 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."
Unlined pits may be used for temporary containment of fluids in
emergency circumstances as well as for disposal of produced water. The
pit must be emptied and the fluids appropriately disposed of within 48
hours after the emergency.
Where disposal in lined pits is allowed, the linings of the pits must
be impervious and must not deteriorate in the presence of hydrocarbons,
acids, or alkalis. 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 and methods may be
considered acceptable upon application and evaluation. The authorized
officer must be given the opportunity to examine the leak detection
system before installation of the pit liner.
When applying for approval of surface disposal into a lined pit, the
operator must provide information including the lining material and leak
detection method for the pit, the pit's size and location, its net
evaporation rate, the method for disposal of precipitated solids, and an
analysis of the produced water. The water analysis must include
concentrations of chlorides, sulfates, and other (unspecified)
constituents that could be toxic to animal, plant, or aquatic life.
VII-12
-------
Injection: Produced waters may be disposed of into the subsurface,
either for enhanced recovery of hydrocarbon resources or for disposal.
Since the establishment of EPA's underground injection control program
for Class II injection wells, BLM no longer directly regulates the use of
injection wells on Federal or Indian lands. Instead, it defers to either
EPA or the State, where the State has received primacy for its program,
for all issues related to ground-water or drinking water protection.
Operators must obtain their underground injection permits from either EPA
or the State.
BLM still retains responsibility for making determinations on
injection wells with respect to lease status, protection of potential oil
and gas production zones, and the adequacy of pressure-control and other
safety systems. It also requires monthly reports on ^volumes of water
injected.
PIuggi ng/Abandonment
When a well is a dry hole, plugging must take place before removal of
the drilling equipment. The mud pits may be allowed to dry before
abandonment of the site. No abandonment procedures may be started
without the approval of an authorized BLM representative. Final approval
of abandonment requires the satisfactory completion of all surface
reclamation work called for in the approved drilling permit.
Within 90 days after a producing well ceases production, the operator
may request approval to temporarily abandon the well. Thereafter,
reapproval for continuing status as temporarily abandoned may be required
every 1 or 2 years. Exact requirements depend on the District Office and
on such factors as whether there are other producing wells on the lease.
The well may simply be defined as shut-in if equipment is left in place.
¥11-13
-------
Plugging requirements for wells are determined by the BLM District
Office. Typically, these will include such requirements as a 100-foot
cement plug over the shoe of the surface casing (half above, half below),
a 20- to 50-foot plug at the top of the hole, and plugs (usually 100 feet
across) above and below all hydrocarbon or freshwater zones.
IMPLEMENTATION OF STATE AND FEDERAL PROGRAMS
Table VII-? presents preliminary summary statistics on the resources
of State oil and gas regulatory programs for the 13 States for which
State regulatory programs have been summarized in Tables VII-1 through
VII-6, Topics covered include rates of gas and oil production, the
number of gas and oil wells, the number of injection wells, the number of
new wells, the responsible State agency involved, and the number of total
field staff in enforcement positions.
Table VII-8 presents similar statistics covering activities of the
Bureau of Land Management. Since offices in one State often have
responsibilities for other States, each office is listed separately along
with the related States with which it is involved. Statistics presented
include the number of oil and gas producing leases, the number of
nonproducing oil and gas leases, and the number of enforcement personnel
available to oversee producing leases.
VII-14
-------
Table VII- I Reserve Pit Design, Construction and Operation
State
General statement of
objective/purpose Liners
Overtopping
Cotnminq ] ing
prov is ion
Permit t ing/
overs ight
Alaska
Arkansas
(revisions
due in '88)
Cal ifornia
The pits must be
rendered impervious.
011 & Gas Coirntission
(OGC); no specific regu-
lations governing con-
struction or management
of reserve pits, Dept,
of Pollution Control 6
Ecology (DPCE) incorpo-
rates specific require-
ments in letters of
authorisataton serving
as informal permits, but
regulatory basis and
legal enforceabilily not
supported by OGC.
No degradat ion of
ground-water quality; if
waste is hazardous, de-
tailed standards apply
to the pits as "surface
Whether reserve pit re-
quires lining (and what
kind of lining) depends
on proximity to surface
water and populations.
whether the pit is
above permafrost, and
what k ind of pit
management strategy is
used; visual monitoring
required, and ground
water monitoring
usually required.
QGC: No regulatory re-
quirement .
DPCE; 20-mi1 synthetic
or 18-?4 inch thick lin-
er (per authorisation
letter).
Liners may or may not be
required, depending on
location and local regu-
lations; in limited
cases where f luids
Fluid mgmt provision
entaiIs use of
dewatering practices to
keep to a minimum the
hydrostatic head in a
containment structure
to reduce the potential
for seepage and to
prevent overflow during
Spring thaw.
1-ft freeboard (DPCE:
?-ft per authorisation
letter).
Reserve pit "drI 1 I ing
wastes" defined as in-
cluding "drilling muds,
cuttings. Hydrocarbons,
brine, acid, sand, and
emulsions or mixtures of
fluids produced from and
unique to the operation
or maintenance of a
we 11 "
DPCC only no high IDS
completion fluids (per
authorisation letter).
Use of norujpproved ad-
ditives and fluids ren-
ders the waste subject
to regulation as a has-
ardous waste.
Individual permit for
act ive and new pits,
OGC. No separate permit
for reserve pit.
DPCE. Terms of permit -
ting for reserve pits
incorporated in letter
of authorisation.
Regional Water Quality
Control Boards (RWQCBs)
have authority to per-
mit, oversee management.
-------
tali It V; 1 i (CO"! n A -.)
'A ilt
od icet
Ov* 't
Conning", inq
P"JV is i delcc-
t ion systems qentrallx
rcqd (or p'ts with a
caoac ity areatcr th*n
100 hhl/d and a ID?,
content greater than
'j.OOO ppm. liners also
rerjd tn det igriJited
areas overlying domestic
water supplier
No prohibition on co.il-
mnqltng of drillttiq
niuil'. and irn t id I Mtnr
product 'cn. U.I rJir,-
po«.c reset vt* pit
suhiect to recu la!ions
for pits receiwina pro
duccd water, no wills
dr i I led with 01 l-ln';ed
mud%
Indiv idua ) permit if
fill r tret-1 veil wore I h«jn
*j bar i a )«, flu id per itoy.
Specific delineation of
areas requiring liners
No gentral requ i
liners may be required
in qeoloqtea 1 ly or hy-
d'ologically sensitive
areas (eg., ovtr sandy
soils); Co,TtRisiion may
require observation
trenches, hole'., or
mo'i i tor ing we 1 K
1-ft freeboard
regs)
General perm 11'j for pits
operating for lesr, than
! yen- (exle'ii ions
graiiterj); individual
ptrmits granted yriiess
d»rtted within 10 days
of appl ication (pro-
po'.»d reg- )
-------
'.Uir
1 OU IS i«t"a
General it*t*nii>r.t of
object ivfc/rjrrio'.e
Prevent contact 'Ml ion of
aqmfers, irtcludiri
USDWs. and protect su'-
face water
t ine>r' Ov0rto^Dlng
liws not regjirp'! ft" ?-ft ' rtfjlio^'d. prnttL-
onsHlf rgserv^ f>i!^, t n^ of Surfdtfr w^tor by
tmtr* (10 fH/sfc) l«?vei;: . wd'I", , aw'
rtqd foi o'lsitt ttun- d'amaQt' ditiht".
Co'Tnnq 1 inq
pr ov ^ s ic*fi
Mo prodijte") v>at*r or
waste o i ! at on«, i • t>
fa: i lit ics
I'f'imit t iri'j/
tvi'i '. »
-------
II 1 konl iriui-l)
Mates
General state'fli'rU of
oh iect ive/purpo«.«? I iner
(fiTT inq I i'iq
t'.trtopfil'-rj piirv 'Si"i
P'.-f ir 1 1 1
Ov'f-- ' '
inq,'
CV lahomtt Prevent pollution o'
surface and sutsur'aee
water, canrnert H ' fts
must be sealed w:t- fln
Ho 1 tner rfccju i'ew?r>t for
reserve pits fof »(?'!;
ustna freohwiiter d«»ll-
•ng mudt>. 20-r.il Impri
(c' metal t-inl-i) reqd
for p»ti conta Hi inq
"deletrT 1005. fluids
other
co
dr I U trig mudl.
1?- inch, 1C cm/sec
SCI 1 1 mer for
conwercia) pits;
Conner c ta I piti oust be
at least 2' ffefct
«bo»e highest aquifer.
site-spec if ic reql
for coml pits contain-
ing deleter iou!i fluids,
IK- uich freeboard «f
ru' "0" tonfoli. V,
TtN«', fcr
H I", '•
More slrinoc'it rj-tjts
( i e . 1 liters) for
f lutih OlHer tM"
wittr -bi*>(:<1 mu'J',
pf o« ule an inr f-ri-
I tve to m.f^fjf t')!'*,«•
waste1; seiMta1«,-)y
Permit r-ot rcfl'l for on-
S i! >,' pits; no t i f i r a t ")r
reri'J 'or cmr-rficnt y and
Uur'1 [ills
May not cause or allow
pollution of surface or
subsurface watt'
Liners not required
Use of reserve pits «imi
mud circu la t ion pits is
restricted to drilling
f lu ids, dr i 11 tut t tnqr,,
sards, ••' its. war.r;
water .
-------
v: i
Still', oh'ett ivo/pjif'.t
W Virginia Prevent r,i
aid tw i fit a m
pit ir.leqr it,1.
t inert, not req
Ct-pt where jO i ' ii not
IP to r."*(«cri(
Or l^^k^ijf
t rc(,t<*j,trr)
N'o pradjf.f-'l Krtti", ui-'j'.ctl Cj'-r.er a 1 permit, ofl:, n«
'»ot.*jruic fluiO 0" cli^thflrse ot f Ujid', re
•if '(I. ; Off ff"' 'ir O't. c-j'rr' in 'inltv I'Hit I
ri-'lu'-*-, d *>n'»o^ei iin»j
COTi(i Ii.'l >ri'i [MtS COfitrtli
iriq oil rtr.fli'rjr w-iter;
fore '.trinqi.nl ilf^iqn
'eqt s for coojtiferc ia 1
pit:.
-------
Table VI!*? Reserve Pit Closure/Waste Removal
Slate
Deadline/
general standard
Land disposal/
applicat ion
Road
appl ical ton
Surface water
discharge
Annular
inject ion
Alaska Must be operated with a
fluid management plan
and must be closed
within I year after
final disposal of
drilling wastes 'n pit,
or must be designed for
? years" disposal and
closed in that time
period: numerous
performance reqts added.
General permit for dis-
charge of flytds to tun-
dra; prior written ap-
proval reqd; specs and
effluent monitoring for
metals and conventional
pollutants; only pits
eligible are those that
have received no drill-
ing wastes since pre-
vious summer (last
freeze-thaw cycle), to
allow precipitation of
contaminants.
Individual permit; com-
pliance point is edge of
the road for same specs
as for land application
(except pH). no require-
ment for freeze-thaw
eye le.
See land application;
specs same as AK UQS
(except TDSJ pending
study to determine
effect on MIIdlifc.
Gcneral permit for N,
Slope; pnor written ap-
proval reqd; discharge
must occnr below the
permafrost into a zone
containing greater than
3.000 ppm IDS.
INS
o
Arkansas Q&C: No specific regu-
frevisions latory requirements,
due in "88) OPCE: within 60 days of
rig's removal, reclaim
to grade and reseed;
fluids myst be consigned
to state-permitted dis-
posal service (per auth-
orization letter).
OPCE only: waste analy-
sis and landowner's con-
sent reqd for land ap-
plication (per authori-
zation letter).
Prohibited.
DPCE: prior approval
reqd (per authorization
letter).
California When drilling operations
cease, remove either (1)
all wastes or (2) all
free liquids and hazard-
ous residuals.
Offsite disposal reqts
depend on whether waste
is "hazardous" (double
liners), "designated"
(single liner) or non-
hazardous.
Permit reqd from RUQCB;
disposal may not cause
damage to surface water.
Colorado for dry arid abandoned
wells, within 6 months
of a well's closure, de-
cant the fluids, back-
fill and reclaim.
ttewatered sediment may
be 11 lied into the
ground.
Permits for discharge
may be issued if
effluent meets stream's
classification standard.
-------
Table VII-2 (continued)
State
Deadline/
general standard
Land disposal/
appl icat ion
Road
applical ion
Surface water
discharge
Annular
inject ion
Kansas
Louisiana
«—t Michigan
New Hex ico
As soon as praet ical,
evaporate or dewater and
backf ill; 365 days, or
sooner if specifically
required by Conwission
(proposed).
Within 6 months of com-
pletion of drilling or
workover act ivities,
fluids must be analyzed
for pH, O&G, mttals and
sal inity, and then re-
moved; exemption for
wells less than 5,000 ft
deep if native mud used.
At closure, all free
liquids must be removed
and the residue encapsu-
lated onsite or dis-
posed of offsite.
Landfarming is prohib-
ited; in-s'tu disposal
may be prohibited in
sensitive areas.
Onsite land treatment
or trenching of fluids
and land treatment, bur-
ial or solidification of
nonfluids allowed pro-
vided specs are met {in-
cluding pH. electrical
conductivity, and certain
metals).
In-situ encapsulat tori
requires a 10-mil PVC
cap 4 ft below
grade; offsite disposal
must be in a lined land-
fill with leachate col-
lect ion and ground-water
monitoring
Pits are evaporated and
residue generally buried
onsite.
If approved by Kansas
Department of Health
and Environment.
Prohibited.
Permits issued for dis-
charge of wastewaler
from treated drilling
site reserve pits, so
long as 1 i«nitat ions
for oil and grease, TSS,
metals, chlorides, pH
are met. Dilution allowed
to meet chloride limits.
Prohibited.
Prohibited.
Prohibited
Surface casing must be
at least ?00 ft below
the lowest USDW.
Well must have produc-
tion casing and injected
fluid must be isolated
below freshwater hori-
zons; exception granted
if, among other things,
pressure gradient is
less than 0.7 psi,
-------
'ai,-e vl!
Deadline/ laid disposal.'
'..tut'. Q'-ner-il t.tan'la'0 - appl"atic'i
Read Sy f j>c( »at PI
arr.lii.ul >0!< '.'fic^aiq*.
Annu Mr
n It'll Hi"
Ohio
Within 'j month', of the
CO'inencement of drill-
ing, backfill and remove
concrete bases and
df i 11 >nq equipment,
within '- months, qrade
and revegetate area not
reqd for production
Dt 111 ing ' luidj m^y be
disposed of h^ Unr) an
pi KM 'O'i; pil SO' ids
may be buried oi-S'te.
e»ci|»t where hiMor,- of
!'erm«t
Standard well t
f lu ids C-tn df in l
sa""*1 rent'. -", fo' annu
lar prodjieil w-tt«-f
tli',pO'-i '. p'-r;'iU
a'«tit"f « 1 ly re»|rl
INJ
Oklahoma Within 1? months o'
dr i 11 mq operat ion's
cessation, dewater and
leave, 6-month extension
for good cause, only 60
days allowed for circu-
lating and fracture pits.
Within 30 days to 1 year
f row when dr 111 intj
ceases (depending on
the fluid's C' content)
dewater, bacMttl, and
compact
rw.ng of
muds is allowed,
permit refjd. siting arid
rate application rcqls.
waste analysis, revege-
tat ion *l?rve p'tS; prior
no! i f an'l (-4
hou» bioa'iSrty tc-:,t
reqd; discharge m
-------
Oea-flin*
l«rr| r! !-,(,;,>, 1,'
<)pn 1 K -u 10*1
Within 6 month1
when drilling cease
Cutting:, may be buried
tre»l"t"it. fluid', rw-ct •
mq bpcci can I* api<on reit
iT.pOM-') Ihrcugl1 Ot 0
Ci oh itii t(-d. ccttpt where
0( 0 (le t (.' rm i r-(- •, d i',(, hrt r tjf
will not r.i»u'.«* '., iq
fnvtr (MTi-if}p of contiti i -
rutte pi/ti 1 ic rt^tf Vjrr
plies, ijfjo t !<-•»( ion mu'i!
include cowpU'tt' *na ly-
*>!',. vo'uTt. Ic*. alinn,
a ii 11 nani" of (ift.eivtnrj
Our • i tme miff I ion a '-
Uiwi/ft under '.oinc conrli-
! >c:ns a*, m UK pprtnit
-------
Table VII-3 Produced Water Pit Design and Construct ion
State
General statement of
object ive/purpose
Itners
E»cnpt ions
Permitting/over sight
Alaska Produced water is a "drilling
waste" and is subject to the
same reqts as in Table VII-1.
Arkansas No discharge into any water of
(revisions the State (including ground
due in 'flfl) water).
Pits must be lined or underlaid
by tight soil; pits prohibited
over porous soil; (DPCE author-
ization letter requires tanks)
Individual permit, application
reqd wilhm 30 days of produc-
ing waste
California Nondegradation of State
waters; pits not permitted in
natural drainage channels or
where they may be in communica-
tion with freshwater-bearing
aquifers.
Liners reqd whert necessary to
comply with the State's nondeg-
radation policy, specific stan-
dards for construction/opera-
tion may be established by
RWQCBs.
Subject to permitting authority
of Regional WQCfl
1—1 Colorado
fsj
Prevent pollution (broadly de-
fined) of State waters:
prevent exceeding of stream
standards.
Same as for reserve pits (for
pits receiving more than 5 bbl/d
90X of the ptts are
lined; 2/3 day. 1/3 synthetic)
Exemptions from liner
requirement for pits overlying
impermeable watertaIs or
receiving water with less than
$.000 ppffl IDS.
Individual permit,
Kansas Consideration of protection of
soil and water resources from
pollution,
Strict liner and seal
requirements in conjunction
with hydrogeologic
invest igat ion
Mo permits issued for unlined
pits
Louisiana
All pits must be lined such
that the hydraulic conductivity
is less than 10 cm/sec.
Pits in certain coastal areas,
provided they are part of a
treatment tram for oil and
grease removal.
-------
ilatr
General statement o'
Objt'Ct i vt'purpose
Nt«
Ohio
Texas
en
ferine cannot be »un !o earthe*>
reservoirs or pond'.
Pits must be liquid tight.
waste cannot be stored for more
than 180 days; pits may not be
used for ultimate disposal.
Pits must he sealed with an im-
pervious material, in adoption.1
nffsite pits must contain flu-
ids with less than 3.500 ppw Cl
Permit for unlm»d pit denied
unless operator conclusively
shows pit will not pollute
agricultural land, surface or
subsurface water, emergency
[ills Generally exempted
In the southe**, I , ?0 ">• I I m*
with leak detect ic-i a't rt-q-1,
in thp nor I hue",, I, liners art
reqd ever spt( '(ied vt, l«e» altl
aqu' f '.'ft
l?-tnth, 10 cm/sec soil
liner for cofl pits, site-
specific liner reqt if cowl
pit contains deleterious fluids
Generally, all pits other than
emergency pits require- liners
unless (1) there is no surface
or subsurface water in the
area. Of I?) the pit is under-
laid fcy a fiatural)y ocurr>ng
impervious barrier, liners
required 'or pfwqency pit*, n>
sensitive area'.
*.fVi I I - V'l hjlll" |,ll'.. -i'lfl I'll', 'n
Sf.'t't, l'lf"i ,|M'.i: tf'rtt rtMj ,i I
r(-.)'ly S-l I ('!•' rtii'J |t. nH-n'. Mill'
Out ( f C' *> •»'""!' '
f;Driiiit
p Idfi
mu*! be Mihniitt (.*du^ t permit
W Virginia Same as for reserve pits.
Wyoming
Same as for reserve pits
liners not reqd except where
the potential for corvnunica.1 ton
between the pit contents arid
surface water or shallow ground
water is hiqh.
Same as for reserve pits
Individual permit reqd if pit
receives more than *, bh I/day
produced water, area-*ide per-
mits also granted, individual
permits and more stringent
term', for commercial pits
-------
Table Vll-4 Produced Water Surface Discharge limits
State
Onshore
Coastal/tidal
Beneficis I use
Permitt ing/oversight
Alaska
Arkansas
Cal tforrua
Prohibited.
In some cases, produced waters
ultimately disposed of in sumps
are a 1 lower) to first be dis-
charged into canals or ephemer-
al streams that carry the
salt water to the sumps.
Not applicable
Policy for enclosed bays and
estuaries prohibits discharge
of materials of petroleum ori-
gin in sufficient quantities to
be visible or in violation of
waste discharge reqts; Ocean
Plan sets limits for 06G, arse-
nic, total chromium, etc, •
Discharge allowed to canals,
ditches, and ephemeral streams
before reuse; specs issued by
one RWQC8 include ORG (35 mg/L)
and Cl (?00
Produced water ts subject to
the discharge reqts for reserve
pit fluids HI lablc VI !-l.
Permit reqd from RVQLB lor
'C'a 1 use
i Colorado
r\»
en
Discharge must not cause pollu-
tion (broadly defined} of any
waters of the state; must not
cause exceeding of stream
standards.
N/A
Specs for wildlife and agricul-
tural use include 06G (10 mg/L)
and TOS (5.000 tng/l, 30-day av-
erage) ,
Permit reqd from Water Quality
Control Division of Department
of Health.
Kansas
Prohibited,
N/A
Road application requires ap-
proval by Dept. of Health and
Env(ronment
Louisiana Discharges allowed into lower
distributaries of Mississippi
and Atchafalaya Rivers; dis-
charges into waters of the
State require a permit after
11/20/86; facility deemed in
compliance except where an in-
vest igat ton or a complaint has
been filed.
Discharge allowed if treated to
remove residual O&G.
Individual permits for surface
discharges required after
-------
CV.ld I/I I'M I
Htnt I if iil u',11
Pfohihi ted
1(11 left
rites lor duM f-o
luti, lo :let<-r>"tif
(l lit- CC>'I If.iK
l'r_.» no Prori'bilpd except if oneroen- N/'fl
CtCS Of for construction, flp-
p! "tat ion tpqd
o Discharge must not caut,e f>allu- N/A
tior, of »ny wateri of U' '""J n-iif r ti:1 < .1*
I '«. i'«l i'i i.c-'i%t ' Jl ', I'J'i, 'ID
( O'l! ""i Tn'rt I'-V. I'. '|i>" t'ii'
-------
Table VII-5 Produced Water Injection Well Construct son
State
Cas ing
MIT pressure
and riuration
HIT frequency
Abandoned wel Is
Alaska Safe and appropriate casing,
cemented to protect oil. gas.
and fresh water; detailed
casing specs
30 min at 1,100 psi or 0 ZS
psi/ft times vertical depth of
casing shoe, whichever is
greater; max. pressure decline
10X,
Before operation; thereafter
monthly reporting of casing-
tubing annulus pressure.
1/4-mile area of review.
Arkansas Well must be cased and cemented
so as not to damage oil, gas, or
fresh water.
Determined by AOGC on a case-
by-case basis.
Before operation; thereafter
every 5 years
l/?-mile area of review.
California
Safe and appropriate casing;
cementing specs.
^ Colorado
rs>
CD
Kansas
Safe and adequate casing or
tubing to prevent leakage, and
cemented so as not to damage
oil. gas. or fresh water.
Well must be cased and cemented
to prevent damage to hydrocar-
bon sources or fresh and usable
water
From hydrostatic to the pres-
sure reqd to fracture the in-
jection tone or the proposed
injection pressure, whichever
occurs first; step rate test
may be waived.
IS min at 300 psi or the min-
imum injection pressure, which-
ever is greater; max. variance
10X.
For old wells, 100 psi; for
new wells, 100 psi or the
authorized pressure, whichever
is greater; alternative tests
allowed; 30-minute test
Withm 3 months after in-
jection conr.icnces and annually
thereafter, after any anomalous
rale or pressure change, or as
requested by DOG
Before operation, thereafter
every S years; except ions for
wells monitor ing anrtulus pres-
sure monthly
Before operation, thereafter
every 5 years
1/4-mile fired radius in combi-
nation with radial (tow equa-
tion and documented geological
features are used to define
area of review
1/4-mile area of review; notice
to surface and work ing interest
owners within 1 mile
1/4-mtle arts of review.
Louisiana Casing must b« set through the
deepest USDW and cemented to
the surface.
For new wells. 30 mm at 300
psi. or max allowable pres-
sure, whichever is greater, for
converted wells, the lesser of
1,000 psi or max, allowable
pressure, but no lower than 300
psi; max. variance of 5 psi
Before operation, thereafter
every 5 years
1/4-mile area of review.
-------
1ol.it Vi : ' Uti'«I I'm* ",
".talc-
MI i p-er.sur».'
i'-d do'it ion
MM I ri«q.,ei.(, ,
AI,.("l!t<'fK'd we 1 I'
Casing and seal to prevent the 30 mfi At 300 psi. 3' a I'o»
loss of prcducfH water into an able bleeHoH
unapproved forn.-st 10'
A- scheduled !<> RA (Ft- It •« i
itt to [, IiltJ
fit*
Ohio
Casing or tubirg to prevent l'-30 'in at ?'C-300 p1. >,
leal'agf- *nrj fluid me v omen t from ma» va» t-jnce 1C"1
the inject to" zone
In addition to use of injection
wells, annular disposal of
produced water is a'lowed, max
annular disposal ViO bM/d;
use only force of g'-ivity. system*,
must be airtight
Casing must be set at least SO
ft below the deepest USOW and
must be cemented to the surface.
1 *j mm at 300 psi. or ma*
aHowahle pressure, whiche
is greater, max decline
alternative tests allowed
tt'o'B Of".''rt' Ifl'i. |tlt"*»') I ti."l
liP rtq;( l«-nf» file'., «ir>tul,j«>
n:o'i i tOf H 1 icfijtrt'J month I/
Before opettit ion, thereafter
every '. ye,nr;,
wpl'v; "f If/ in lie ctpf). well plu-jtjifiq fund
Casinq mn',' be set *t least ^0
ft he low the surface or SO ft
below treatable water, which-
ever n lower, ind ^ust be ce-
mented to the surface
»',, I on i', >ar«a. e«ccpt ma><-
mum bleedoff of IO/
tffo'C Of''"«)" I OM. t hf»r 0,)f ; c;r
every 'i vt'-K"., except toit for
wells muMtor trig pressure*
monthly afi'J report inq -jrinu^ll
of review,
fu'it!
Surface casing cetneited to
surface; tubing and cemented
casing string to isolate
inject ion /one
Test at SOD psig, or max al-
lowable pressure, whichever is
less, hut at least ?00 psig;
ma>. decline of I OX. once
pressure stabilises. 30
minute:* with no variation.
Before injection, after
workover. and thereafter
every "j years (exception for
wells monitoring annulus pres-
sure monthly and rpt'q annua 1
ly, or for other v tab If a'tcr-
net ive ter»! )
!/<-mile area of review; notice
to surface owners and offset
operators, we II plugging fund
(main ioijrt'.' ilOO dr i 1 I i».q
pe r m 11 f t;(:)
-------
I
co
o
itate
w.'l !•
Virginia
?CJ irtn at 1 > to ? times the
inject iOP pre^su^e. m.»» »*n
Surface tastng mult he set be-
low freshwater wjrces; casing
cemented to the surface.
ai toui s >tir.4
Pffo't in |i", t ion
Hot u.r- to liiri(!rj*-!er- H'icl oii^-r-i
tot', » 'thin i/? T !«••, M« rut k-
f't.t f)f H'V tf't.
-------
Table VI1-6 Wtlt Abandonment/Plugging
States
Plagg-.r.g
i me
Plugging oversignt
Alaska
1 year following end of ope'atsr'i ac-
ttvtt) wtrnn ".he fiels, if we!' not
completed, must be aSanoooed or sus-
pended lefore removal of on!'mg
etjyjpraent; brsdge plutjs reqd for sys-
penoed we'Is.
Plugging method sust be approwee
beg'nntng work, inceimuy bond released
after approval of »e ' 1
Arkansas If not completed, must be
plugged before or ill ing equip 15
released form the drilling operation;
no time limn for temporary
abandonment of properly cased well.
Plucjg'ng permit, onstte Supervision by
AOGC official; bond or otner evidence
of finanacial responsibility reqd, and
released only after plugg>nga*e opportunit> to witness.
tlanket or
l bond reqd
Plugging plan reqd before beginning
worn.; report reqd after CM? let ion
Within 90 days of notice in "Inactive
Well Repoit" unless a plan is submitted
describing the well's future use.
Michigan Within 60 days after cessation of
drilling activities; within 1 year af-
ter cessation of production (with ex-
tensions, if sufficient reason to re-
ta in wel 1}
Plugging method must be approved.
VII-31
-------
"isuie !>;;-"„ ircr,: truej,'
M„{:;}'ng de.»C°iine
P luqqina overs:gnt
ei1 ps^anjfa c lar mast tw approves:
lugct'.rc tvn;: releases after inspection
»l..c-T'~c. ,irpr3vj reqd, .i**e~
plus.iirc;. recirt re-oa 'ncl..ninn taen-
tit> 2» n'tnessei. ^.doilit> ir-surar.cc
rfcpj, Su'"t-'. . Donn 'orfeiteo if nancorr.-
pi i.:r:e «.*,*- rerti
d'lei teiiSl ion c! Jnllinj (iiunt^Ou
e>,"ept icnt, ) , \e: i, t iiw- «nere no. or
O'-'if Surface. ca!-ir,g r^n. iuec'dl ru
flugO'ro -T.LiSt Le i-Defv'SeS D> ar oy-
ttiut u'tru i t;p ot mt Zonservdt ion Jui
sion. plu,jg>r.g report reqrt, proof o?"
finar.cifl jr:'itj to comply t»ith plug-
ging ffcq:
WH'in ^C rsiyr, after .irillin;; nr o:ierd-
t ea'J. e>.:en-
siO"5 a', Oireciot'j dis;retior. (n no
pollution n.irjirdj with plugijtng nanrt
or letter of credit or plan to use for
ennanceo recover^,
Before p"...iq'ng notification and
Approvjl resc, after plugging, report
reqd, cpeta'.oi* irujt D= present o-rtng
plygy ing
b V ii',) m 13
Prpnr*; p lugging rtfr,.1 i» dr_j holfei ami
»e11s net in use for 12 mo, e\ien-
s ion;, for gooa cause.
Hf.firovfll frj^t the 5-tite reqd if tn: * '
is "temporarily ofcjndanec!" for mere
man l year,
Plugging iij»d JR.I not if to the 0«rec-
tor ana wart-} coal operators reqd.
Before plummy, jpprovjl reqc, after
plugging, reoort re;d, well plugging
eonef releasec after the State inspe:-
t ton.
VII-32
-------
Tibl« VII-7 Slit* Enforcement Matrix
Slat* Gas Production
OH Production Oat wells Oil walls Injecilon wells
New walls
Agency
Personnel*
Alaska
Arkansas
California
Kansas
Louisiana
NawMoxco
Ohio
Oklahoma
Pennsylvania
Texas
West Virginia
Wyoming
316,000 Mmd 1986
194.483 Mmd 1985
433.000 Mmd 1085
466,600 Mmd 1904
5,867.000 Mmd 1984
893,300 Mmd 1985
182.200 Mmd 1985
1,996,000 Mmd 1984
166,000 Mmd 1984
5.805.000 Mmd 1085
142,500 Mmd 1906
597 .896 Mmd 1965
681.309.821 bbl 1966
19.715,691 bbl 19B5
423.900,000 bbl 1905
75.723.000 bbl 1984
449,545,000 bbl 1984
78.500.000 bbl 198S
1 4.987,588 bbl 1985
153,250,000 bbl 1964
4,825,000 bbl 1984
830,000.000 bW 1985
3,600.000 bbl 1986
130.984 ,91 7 bbl 1985
104
2,492
1,566
12.680
14,436
18.308
31.343
23.647
24.050
68.811
32.500
2,220
1.191
9,490
55,079
57,633
25,823
21,066
29,210
99,030
20,739
210,000
15,895
12,2)8
472 Class II
425 ion
47 Disposal
1,211 Class II
239 EOH
972 Disposal
11, 066 Class II
10,047 EOO
1,019 Disposal
14.902 Class II
9,366 EOR
• 5,536 Disposal
4,436 Class II
1.283 EOR
3,153 Oi^osal
3,871 Class II
3.508 EOR
363 Disposal
3.956 Class II
127 EOR
3.829 Disposal
22.803 Class II
14.901 EOR
7^902 Disposal
6,1 S3 Class II
4,315 EOR
1 .868 Disposal
53,141 Class II
45.223 EOR
7,918 Disposal
761 Class II
687 EOR
74 Disposal
5,880 Class II
5,257 Eon
623 Disposal
100 new onshore wells
completed in 198S
1,055 new walls
completed in 1985
3,413 new wells
completed In 1985
6.025 n«w wo Is
completed In 1985
5,447 now onshore
wells compteled 1985
1.747 new w«Bs
comploledin 1985
6.297 no* w»ls
completed in 1985
9, 176 new we Us
completed In 1985
4.627 new wolls
completed in 1985
25,72! new wells
completed In 1985
1,839 new wells
completed In 1985
1,735 new wols
completed In 1985
Oil and Gas Conservation Commission
Department ol Environmental Conservation
Arkansas Oil and Gas Commission
Department dt Pollution Control and Ecology
Conservation Dept., Division o) Oil and Gas
Department ol Fteh and Game
Kansas Corporation Commission
Department ol Environmental Quality
Office ol Conservation - In(ec1ion and Mining
Energy and Minerals Department,
Oil Conservation Division
Ohio Department dk Natural Resources,
Division ol Oil and Gas
Oklahoma Corporation Commission
Department ol Environmental Resources,
Bureau d Oil and Gas Management
Texas Hailroad Commission
West Virginia Departmonl ol Energy
Oil and Gas Conservation Commission
Department ol Environmental Quality
8 enforcement positions
8 enforcement positions
7 enforcement positions
2 enforcement positions
3 1 enforcement positions
30 enforcement positions
32 enforcement positions
36 enforcement positions
10 enforcement positions
66 enforcement positions
52 enlorcemenl positions
34 enlorcemenl positions
120 enlorcemenl positions
15 enlorcemenl positions
7 enlorcemenl positions
45 enlorcemenl positions
UJ
'Only Held stall are Included In total enforcement postlions.
-------
Table VB-* BLM Enforcement Matrix*
Office
location
Other States
for which effle*
ia raaportflpla
Producing oil and gas
ieaaaa
Nonproducing oil and gaa
leaaea"
Personnel
(for producing leases only)
Alaska
California
Colorado
Idaho
Mississippi
Alabama
Arkansas
Florida
Kentucky
Louisiana
VirfWa
ToW
Montana
North Dakota
South Dakota
Total
Nevada
Now Mexico
Arizona
Kansas
Oklahoma
Texas
Total
Oregon
Utah
Wisconsin
Maryland
Michigan
Missouri
Ohw
Pennsylania
West Virgins
TolaJ
Wyoming
Nebraska
Total
Total
43
305
3J73
0
118
12
161
1
13
121
1
425
968
456
90
1,512
43
S.72S
10
ISO
2,717
61
8,713
0
1*64
0
2
a
1
33
§
46
116
42
5,079
22,037
8,443
1,383
4,463
471
1,518
567
1,099
0
65
48?
S3
4,721
1.991
572
7,284
3,045
9,306
306
227
2,754
271
12.S52
1513
7^22
0
11
603
6
68
1
54
844
28,044
582
28.626
102,251
7 enforcement positions
10 enforcement positions
0 enforcement positions
3 enforcement positions
12 enforcement positions
1 enforcement position
43 enforcement positions
0
10 enforcement positions
1 enforcement position
27 enforcement positions
115 enforcement posMoos
* at and gas inspectors wxkjng in the 5eW as ol March 30, 1967. Allhal time
there were eight vacancies nationwide.
" Includes leases that have never been drilled, have been drilled and abandoned,
or are producing wells that have been temporarily shut down.
J!
'I
_lt
•y
•„(
VII-34
-------
REFERENCES
43 CFR 3100 (entire group).
U.S. Bureau of Land Management. (Not dated.) Federal Onshore Oil and
Gas Leasing and Operating Regulations.
U.S. Bureau of Land Management. NTL-2B.
U.S. Department of the Interior - Geological Survey Division. (Not
dated.) Notice to Lessees and Operators of Federal and Indian Oil and
Gas Leases (NTL-2B).
Personal communication with Mr. Steve Spector, September 23, 1986.
VII-35
-------
CHAPTER VIII
CONCLUSIONS
From the analysis conducted for this report, it is possible to draw a
number of general conclusions concerning the management of oil and gas
wastes. These conclusions are presented below.
Available waste management practices vary in their environmental
performance.
Based on its review of current and alternative waste management
practices, EPA concludes that the environmental performance of existing
waste management practices and technologies varies significantly. The
reliability of waste management practices will depend largely on the
environmental setting. However, some methods will generally be less
reliable than others because of more direct routes of potential exposure
to contaminants, lower maintenance and operational requirements,
inferiority of design, or other factors. Dependence on less reliable
methods can in certain vulnerable locations increase the potential for
environmental damage related to malfunctions and improper maintenance.
Examples of technologies or practices that are less reliable in locations
vulnerable to environmental damage include:
* Annular disposal of produced water (see damage case OH 38,
page IV-16);
» Landspreading or roadspreading of reserve pit contents (see
damage case WV 13, page 1V-24);
• Use of produced water storage pits (see damage case AR 10,
page IV-36); and
-------
• Surface discharges of drilling waste and produced water to
sensitive systems such as estuaries or ephemeral streams (see
damage cases TX 55, page IV-49; TX 31, page 1V-50; TX 29,
page IV-51; WY 07, page IV-60; and CA 21, page 1V-68).
Any program to improve management of oil and gas wastes in the near
term will be based largely on technologies and practices in current use.
Current technologies and practices for the management of wastes from
oil and gas operations are well established, and their environmental
performance is generally understood. Improvements in State regulatory
requirements over the past several years are tending to increase use of
more desirable technologies and practices and reduce reliance on others.
Examples include increased use of closed systems and underground
injection and reduced reliance on produced water storage and disposal
pits.
Long-term improvements in waste management need not rely, however,
purely on increasing the use of better existing technology. The Agency
does foresee the possibility of significant technical improvements in
future technologies and practices. Examples include incineration and
other thermal treatment processes for drilling fluids; conservation,"
recycling, reuse, and other waste minimization techniques; and wet air
oxidation and other proven technologies that have not yet been applied to
oil and gas operations.
Because of Alaska's unique and sensitive tundra environment, there
has been special concern about the environmental performance of waste
management practices on the North Slope. Although there are limited and
preliminary data that indicate some environmental impacts may occur,
these data and EPA's initial analysis do not indicate the need to curtail
current or future oil exploration, development, and production operations
on the North Slope. However, there is a need for more environmental data
VIII-2
-------
on the performance of existing technology to provide assurance that
future operations can proceed with minimal possible adverse impacts on
this sensitive and unique environment. The State of Alaska has recently
enacted new regulations which will provide additional data on these
practices.
EPA is concerned in particular about the environmental desirability
of two waste management practices used in Alaska: discharge of reserve
pit supernatant onto tundra and road application of reserve pit. contents
as a dust suppressant. Available data suggest that applicable discharge
limits have sometimes been exceeded. This, coupled with preliminary
biological data on wildlife impacts and tundra and surface water
impairment, suggests the need for further examination of these two
practices with respect to current and future operations. The new
regulations recently enacted by the State of Alaska should significantly
reduce the potential for tundra and wildlife impacts.
increased segregation of waste may help improve management of oil and
gas wastes.
The scope of the exemption, as interpreted by EPA in Chapter II of
this report, excludes certain relatively low-volume but possibly
high-toxicity wastes, such as unused pipe dope, motor oil, and similar
materials. Because some such wastes could be hazardous and could be
segregated from the large-volume wastes, it may be appropriate to require
that they be segregated and that some of these low-volume wastes be
managed in accordance with hazardous waste regulations. While the Agency
recognizes that small amounts of these materials may necessarily become
mixed with exempt wastes through normal operations, it seeks to avoid any
deliberate and unnecessary use of reserve pits as a disposal mechanism.
Segregation of these wastes from high-volume exempt wastes appears to be
desirable and should be encouraged where practical.
VIII-3
-------
Although this issue is not explicitly covered in Chapter VII, EPA is
aware that some States do require segregation of certain of these
low-volume wastes. EPA does not have adequate data on which to judge
whether these State requirements are adequate in coverage, are
enforceable, are environmentally effective, or could be extended to
general operations across the country. The Agency concludes that further
study of this issue is desirable.
Stripper operations constitute a special subcategory of the oil and gas
industry.
Strippers cumulatively contribute approximately 14 percent of total
domestic oil production. As such, they represent an economically
important component of the U.S. petroleum industry. Two aspects of the
stripper industry raise issues of consequence to this study.
First, generation of production wastes by strippers is more
significant than their total petroleum production would indicate. Some
stripper wells yield more than 100 barrels of produced water for each
barrel of oil, far higher on a percentage production basis than a typical
new well, which may produce little or no water for each barrel of oil.
Second, stripper operations as a rule are highly sensitive to small
fluctuations in market prices and cannot easily absorb additional costs
for waste management.
Because of these two factors — inherently high waste-production rates
coupled with economic vulnerability--EPA concludes that stripper
operations constitute a special subcategory of the oil and gas industry
that should be considered independently when developing recommendations
for possible improvements in the management of oil and gas wastes. In
VIII-4
-------
the event that additional Federal regulatory action is contemplated, such
special consideration could indicate the need for separate regulatory
actions specifically tailored to stripper operations.
Documented damage cases and quantitative modeling results indicate
that, when managed in accordance with State and Federal requirements,
exempted oil and gas wastes rarely pose significant threats to human
health and the environment.
Generalized modeling of human health risks from current waste
management practices suggests that risks from properly managed operations
are low. The damage cases researched in the course of this project,
however, indicate that exempt wastes from oil and gas exploration,
development, and production can endanger human health and cause
environmental damage when managed in violation of existing State
requirements.
Damage Cases
In a large portion of the cases developed for this study, the types
of mismanagement that lead to such damages are illegal under current
State regulations although a few were legal under State programs at the
time when the damage originally occurred. Evidence suggests that
violations of regulations do lead to damages. It is not possible to
determine from available data how frequently violations occur or whether
violations would be less frequent if new Federal regulations were imposed.
Documented damages suggest that all major types of wastes and waste
management practices have been associated to some degree with
endangerment of human health and damage to the environment. The
principal types of wastes responsible for the damage cases include
general reserve pit wastes (primarily drilling fluids and drill cuttings,
VIII-5
-------
but also miscellaneous wastes such as pipe dope, rigwash, diesel fuel,
and crude oil}; fracturing fluids; production chemicals; waste crude oil;
produced water; and a variety of miscellaneous wastes associated with
exploration, development, or production. The principal types of damage
sometimes caused by these wastes include contamination of drinking-water
aquifers and foods above levels considered safe for consumption, chemical
contamination of livestock, reduction of property values, damage to
native vegetation, destruction of wetlands, and endangerment of wildlife
and impairment of wildlife habitat.
Ri sk Model ing
The results of the risk modeling suggest that of the hundreds of
chemical constituents detected in both reserve pits and produced fluids,
only a few from either source appear to be of concern to human health and
the environment via ground-water and surface water pathways. The
principal constituents of potential concern, based on an analysis of
their toxicological data, their frequency of occurrence, and their
mobility in ground water, include arsenic, benzene, sodium, chloride,
boron, cadmium, chromium, and mobile salts. All of these constituents
were included in the quantitative risk modeling; however, boron, cadmium,
and chromium did not produce risks or resource damages under the
conditions modeled.
For these constituents of potential concern, the quantitative risk
modeling indicates that risks to human health and the environment are
very small to negligible when wastes are properly managed. However,
although the risk modeling employed several conservative assumptions, it
was based on a relatively small sample of sites and was limited in scope
to the management of drilling waste in reserve pits, the underground
injection of produced water, and the surface water discharge of produced
water from stripper wells. Also, the risk analysis did not consider
VI1I-6
-------
migration of produced water contaminants through fractures or unplugged
or improperly plugged and abandoned wells. Nevertheless, the relatively
low risks calculated by the risk modeling effort suggest that complete
adherence to existing State requirements would preclude most types of
damages.
Damages may occur in some instances even where wastes are managed in
accordance with currently applicable State and Federal requirements.
There appear to be some instances in which endangerment of human
health and damage to the environment may occur even where operations are
in compliance with currently applicable State and Federal requirements.
Damage Cases
Some documented damage cases illustrate the potential for human
health endangerment or environmental damage from such legal practices as
discharge to ephemeral streams, surface water discharges in estuaries in
the Gulf Coast region, road application of reserve pit contents and
discharge to tundra in the Arctic, annular disposal of produced waters,
and landspreading of reserve pit contents.
Risk Model ing
For the constituents of potential concern, the quantitative
evaluation did indicate some situations (less than 5 percent of those
studied) with carcinogenic risks to maximally exposed individuals higher
.4
then 1 in 10,000 (1x10 ) and sodium levels in excess of interim limits
for public drinking water supplies. Although these higher risks resulted
only under conservative modeling assumptions, including high (90th
percentile) concentration levels for the toxic constituents, they do
indicate potential for health or environmental impairment even under the
VIII-7
-------
general assumption of compliance with standard waste management
procedures and applicable State and Federal requirements. Quantitative
risk modeling indicates that there is an extremely wide variation (six or
more orders of magnitude) in health and environmental damage potential
among different sites and locations, depending on waste volumes, wide
differences in measured toxic constituent concentrations, management
practices, local hydrogeological conditions, and distances to exposure
points.
Unplugged and improperly plugged abandoned wells can pose significant
environmental problems.
Documentation assembled for the damage cases and contacts with State
officials indicate that ground-water damages associated with unplugged
and improperly plugged abandoned wells are a significant concern.
Abandoned disposal wells may leak disposed wastes back to the surface or
to usable ground water. Abandoned production wells may leak native
brine, potentially leading to contamination of usable subsurface strata
or surface waters.
Hany older wells, drilled and abandoned prior to current improved
requirements on well closure, have never been properly plugged. Many
States have adequate regulations currently in place; however, even under
some States' current regulations, wells are abandoned every year without
being properly plugged.
Occasionally companies may file for bankruptcy prior to implementing
correct plugging procedures and neglect to plug wells. Even when wells
are correctly plugged, they may eventually leak in some circumstances in
the presence of corrosive produced waters. The potential for
environmental damage occurs wherever a well can act as a conduit between
usable ground-water supplies and strata containing water with high
VIII-B
-------
chloride levels. This may occur when the high-chloride strata are
pressurized naturally or are pressurized artificially by disposal or
enhanced recovery operations, thereby allowing the chloride-rich waters
to migrate easily into usable ground water.
Discharges of drilling muds and produced waters to surface waters have
caused locally significant environmental damage where discharges are not
in compliance with State and Federal statutes and regulations or where
NPDES permits have not been issued.
Damage cases indicate that surface water discharges of wastes from
exploration, development, and production operations have caused damage or
danger to lakes, ephemeral streams, estuaries, and sensitive environments
when such discharges are not carried out properly under applicable
Federal and State programs and regulations. This is particularly an
issue in areas where operations have not yet received permits under the
Federal NPOES program, particularly along the Gulf Coast, where permit
applications have been received but permits have not yet been issued, and
on the Alaskan North Slope, where no NPDES permits have been issued.
For the Nation as a whole, Rrgulation of all oil and gas field wastes
under unmodified Subtitle C of RCRA would have a substantial impact on
the U.S. economy.
The most costly hypothetical hazardous waste management program
evaluated by EPA could reduce total domestic oil production by as much as
18 percent by the year 2000. Because of attendant world price increases,
this would result in an annual direct cost passed on to consumers of over
S6 billion per year. This scenario assumes that 70 percent of all
drilling and production wastes would be subject to the current
requirements of Subtitle C of RCRA. If only 10 percent of drilling
wastes and produced waters were found to be hazardous, Subtitle C
regulation would result in a decline of 4 percent in U.S. production and
VIII-9
-------
a SI.2 billion cost increase to consumers, compared with baseline costs,
in the year 2000.
EPA also examined the cost of a Subtitle C scenario in which produced
waters injected for the purpose of enhanced oil recovery would be exempt
from Subtitle C requirements. This scenario yielded production declines
ranging from about 1.4 to 12 percent and costs passed on to consumers
ranging from SO.7 to S4.5 billion per year, depending on whether 10
percent or 70 percent of the wastes (excluding produced waters injected
for enhanced oil recovery) were regulated as hazardous wastes.
These Subtitle C estimates do not, however, factor in all of the
Hazardous and Solid Waste Act Amendments relating to Subtitle C land
disposal restrictions and corrective action requirements currently under
regulatory development. If these two requirements were to apply to oil
and gas field wastes, the impacts of Subtitle C regulation would be
substantially increased.
The Agency also evaluated compliance costs and economic impacts for
an intermediate regulatory scenario in which moderately toxic drilling
wastes and produced waters would be subject to special RCRA requirements
less stringent than those of Subtitle C. Under this scenario, affected
drilling wastes would be managed in pits with synthetic liners, caps, and
ground-water monitoring programs and regulated produced waters would
continue to be injected into Class II wells (with no surface discharges
allowed for produced waters exceeding prescribed constituent
concentration limits). This scenario would result in a domestic
production decline, and a cost passed on to consumers in the year 2000,
of 1.4 percent and $400 million per year, respectively, if 70 percent of
VIIMO
-------
the wastes were regulated. If only 10 percent of the wastes were subject
to regulation, this intermediate scenario would result in a production
decline of less than 1 percent and an increased cost to consumers of
under S100 million per year.
The economic impact analysis also estimates affects on U.S. foreign
trade and State tax revenues. By the year 2000, based on U.S. Department
of Energy models, the EPA cost results projected an increase in national
petroleum imports ranging from less than 100 thousand to 1.1 million
barrels per day and a corresponding increase in the U.S. balance of
payments deficit ranging from less than S100 thousand to S18 billion
annually, depending on differences in regulatory scenarios evaluated.
Because of the decline in domestic production, aggregated State tax
revenues would be depressed by an annual amount ranging from a few
million to almost a billion dollars, depending on regulatory assumptions.
Regulation of all exempt wastes under full, unmodified RCRA Subtitle C
appears unnecessary and impractical at this time.
There appears to be no need for the imposition of full, unmodified
RCRA Subtitle C regulation of hazardous waste for all high-volume exempt
oil and gas wastes. Based on knowledge of the size and diversity of the
industry, such regulations could be logistically difficult to enforce and
could pose a substantial financial burden on the oil and gas industry,
particularly on small producers and stripper operations. Nevertheless,
elements of the Subtitle C regulatory program may be appropriate in
select circumstances. Reasons for the above tentative conclusion are
described below.
The Agency considers imposition of full, unmodified Subtitle C
regulations for all oil and gas exploration, development, and production
wastes to be unnecessary because of factors such as the following.
VIII-11
-------
Damages and risks posed by oil and gas operations appear to be
linked, in the majority of cases, to violations of existing State
^nd Federal regulations. This suggests that implementation and
"enforcement of existing authorities are critical to proper
management of these wastes. Significant additional environmental
protection could be achieved through a program to enhance
compliance with existing requirements.
State programs exist to regulate the management of oil and gas
wastes. Although improvements may be needed in some areas of
design, implementation, or enforcement of these programs, EPA
believes that these deficiencies are correctable.
Existing Federal programs to control underground injection and
surface water discharges provide sufficient legal authority to
handle most problems posed by oil and gas wastes within their
purview.
The Agency considers the imposition of full Subtitle C regulations
for all oil and gas exploration, development, and production wastes to be
irnpractical because of factors such as the following:
• EPA estimates that the economic impacts of imposition of full
Subtitle C regulations (excluding the corrective action and land
disposal restriction requirements), as they would apply without
modification, would significantly reduce U.S. oil and gas
production, possibly by as much as 22 percent.
• If reserve pits were considered to be hazardous waste management
facilities, requiring permitting as Subtitle C land disposal
facilities, the administrative procedures and lengthy application
processes necessary to issue these permits would have a drastic
impact on development and production.
• Adding oil and gas operations to the universe of hazardous waste
generators would potentially add hundreds of thousands of sites to
the universe of hazardous waste generators, with many thousands of
units being added and subtracted annually.
» Manifesting of all drilling fluids and produced waters offsite to
RCRA Subtitle C disposal facilities would pose difficult logistical
and administrative problems, especially for stripper operations,
because of the large number of wells now in operation.
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States have adopted variable approaches to waste management.
State regulations governing proper management of Federally exempt oil
and gas wastes vary to some extent to accommodate important regional
differences in geological and climatic conditions, but these regional
environmental variations do not fully explain significant variations in
the content, specificity, and coverage of State regulations. For
example, State well-plugging requirements for abandoned production wells
range from a requirement to plug within 6 months of shutdown of
operations to no time limit on plugging prior to abandonment.
Implementation of existing State and Federal requirements is a central
issue in formulating recommendations in response to Section 8002(m).
A preliminary review of State and Federal programs indicates that
most States have adequate regulations to control the management of oil
and gas wastes. Generally, these State programs are improving. Alaska,
for example, has just promulgated new regulations. It would be
desirable, however, to enhance the implementation of, and compliance
with, certain waste management requirements.
Regulations exist in most States to prohibit the use of improper
waste management practices that have been shown by the damage cases to
lead to environmental damages and endangerment of human health.
Nevertheless, the extent to which these regulations are implemented and
enforced must be one of the key factors in forming recommendations to
Congress on appropriate Federal and non-Federal actions.
VIII-13
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CHAPTER IX
RECOMMENDATIONS
Following public hearings on this report, EPA will draw more
specific conclusions and make final recommendations to Congress regarding
whether there is a need for new Federal regulations or other actions.
These recommendations will be made to Congress and the public within
6 months of the publication of this report,
Use of Subtitle D and other Federal and State authorities should be
explored as a means for implementing any necessary additional controls on
oil and gas wastes.
EPA has concluded that imposition of full, unmodified RCRA Subtitle C
regulation of hazardous waste for all exempt oil and gas wastes may be
neither desirable nor feasible. The Agency believes, however, that
further review of the current and potential additional future use of
other Federal and State authorities (such as Subtitle D authority under
RCRA and authorities under the Clean Water Act and the Safe Drinking
Water Act) is desirable. These authorities could be appropriate for
improved management of both exempt and nonexempt, high-volume or
low-volume oil and gas wastes.
EPA may consider undertaking cooperative efforts with States to review
and improve the design, implementation, and enforcement of existing State
and Federal programs to manage oil and gas wastes.
EPA has concluded that most States have adequate regulations to
control most impacts associated with the management of oil and gas
wastes, but it would be desirable to enhance the implementation of, and
compliance with, existing waste management requirements. EPA has also
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concluded that variations among States in the design and implementation
of regulatory programs warrant review to identify successful measures in
some States that might be attractive to other States. For example, EPA
may want to explore whether changes in State regulatory reporting
requirements would make enforcement easier or more effective. EPA
therefore recommends additional work, in cooperation with the States, to
explore these issues and to develop improvements in the design,
implementation, and enforcement of State programs.
During this review, EPA and the States should also explore
nonregulatory approaches to support current programs. These might
include development of training standards, inspector training and
certification programs, or technical assistance efforts. They might also
involve development of interstate commissions or other organizational
approaches to address waste management issues common to operations in
major geological regions {such as the Gulf Coast, Appalachia, or the
Southwest). Such commissions might serve as a forum for discussion of
regional waste management efforts and provide a focus for development and
delivery of nonregulatory programs.
The industry should explore the potential use of waste minimization,
recycling, waste treatment, innovative technologies, and materials
substitution as long-term improvements in the management of oil and gas
wastes.
Although in the near term it appears that no new technologies are
available for making significant technical improvements in the management
of exempt wastes from oil and gas operations, over the long term various
innovative technologies and practices may emerge. The industry should
explore the use of innovative approaches, which might include
conservation and waste minimization techniques for reducing generation of
drilling fluid wastes, use of incineration or other treatment
technologies, and substitution of less toxic compounds wherever possible
in oil and gas operations generally.
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