DOE/FE/61679P-H1 Volume 2 of 2 Volumes
•
POTENTIAL CUMULATIVE IMPACTS OF
ENVIRONMENTAL REGULATORY
INITIATIVES ON U.S. CRUDE OIL
EXPLORATION AND PRODUCTION
VOLUME 2: FINAL REPORT
Prepared for:
U.S. Department of Energy
Assistant Secretary for Fossil Energy
Office of Planning and Environment
Under Contract No. DE-AC01-88FE61679 (Task 3)
DECEMBER 1990
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DISCLAIMER
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DOE/FE/61679P-H1 Volume 2 of 2 Volumes
Dist. Category UC-121 & 122
POTENTIAL CUMULATIVE IMPACTS OF
ENVIRONMENTAL REGULATORY
INITIATIVES ON U.S. CRUDE OIL
EXPLORATION AND PRODUCTION
VOLUME 2: FINAL REPORT
Prepared by:
ICF Resources Incorporated
Fairfax, Virginia 22031-1207
Under Contract No. DE-AC01-88FE61679 (Task 3)
Prepared for:
U.S. Department of Energy
Assistant Secretary for Fossil Energy
Office of Planning and Environment
Washington, DC 20585
DECEMBER 1990
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ACKNOWLEDGEMENTS
This study was conducted by ICF Resources Incorporated under contract (No. DE-AC01-
88FE61679 - Task 3) to the U.S. Department of Energy, Office of Fossil Energy. The project was managed
by Mr. Michael Godec. Critical project staff on the project included Mr. Khosrow Biglarbigi, Mr. Don
Remson, Mr. Hugh Guinn, and Ms. Bundhrig Kosowski, who performed the data preparation, model
updates, and computer analyses; Mr. Geoff Hobday, who provided graphical support, and Ms. Kathy Kelly,
who was responsible for the typing and preparation of the final report.
Several people at the U.S. Department of Energy also provided timely and insightful review, input,
and guidance throughout this project. Ms. Nancy Johnson of the Office of Planning and Environment
served as Project Officer and provided invaluable input throughout the project. Mr. H. William Hochheiser
and Mr. R. Michael Ray also provided important technical assistance and guidance.
Various drafts of the report were reviewed and critiqued by Mr. William Freeman (Shell Oil Co.),
Ms. Debra Eno (Exxon Co.), Mr. Harold Yates (Exxon Co.), Ms. Connie Ericson (Mitchell Energy Co.), Ms.
Susan Stark (ARCO Oil and Gas Co.), Mr. Neal Thurber (Amoco Co.), and Mr. Tom Randolph (Shell Oil
Co.). Their timely review, critique, and guidance at critical stages of the project was extremely valuable.
While we acknowledge the wisdom and assistance of these advisors, we do not imply necessarily that
any of them agrees with or endorses the results of this study.
Finally, while we acknowledge the guidance and assistance of all these contributors, errors in fact,
analysis, or interpretation are the responsibility of ICF Resources and this effort's project manager.
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TABLE OF CONTENTS
ACKNOWLEDGEMENTS
I. INTRODUCTION 1-1
II. ENVIRONMENTAL INITIATIVES CONSIDERED 11-1
A. Resource Conservation and Recovery Act 11-1
B. Safe Drinking Water Act II-5
C. Clean Water Act II-6
D. Clean Air Act II-9
E. Estimated Costs of Regulatory Initiatives 11-16
III. SUMMARY OF ANALYTICAL APPROACH 111-1
A. Resources Considered III-4
1. Current Production III-4
2. Unrecovered Mobile Oil in Known Oil Fields III-7
3. Enhanced Oil Recovery in Known Fields III-8
4. Undiscovered Crude Oil Resources III-9
5. General Assessment Procedure 111-10
IV. CUMULATIVE IMPACT OF ENVIRONMENTAL INITIATIVES - DISCUSSION OF
RESULTS IV-1
A. Introduction IV-1
B. Current Production IV-2
1. Analysis of Potential Under Current Regulations IV-2
2. Impact of Initiatives IV-4
C. Unrecovered Mobile Oil in Known Fields IV-18
1. Analysis of Potential Under Current Regulations IV-18
2. Impact of Initiatives IV-23
D. Enhanced Oil Recovery in Known Fields IV-47
1. Analysis of Potential Under Current Regulations IV-47
2. Impact of Initiatives IV-52
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TABLE OF CONTENTS, continued
E. Undiscovered Crude Oil Resources IV'75
1. Analysis of Potential Under Current Regulations IV-75
2. Impact of Initiatives IV-76
V. CONCLUSIONS V-1
VI. REFERENCES VI-1
APPENDIX A Description of Environmental initiatives
APPENDIX B Analytical Approach
APPENDIX C Cost Estimates Used in Economic Analysis of MMS Proposed Offshore Air Quality
Regulations
APPENDIX D - Updated Forecast of Future Abandonment Rates of the Known Domestic Oil Resource
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LIST OF TABLES
Table 11-1 Summary of Assumptions Corresponding to Three Regulatory Scenarios
Resources Conservation and Recovery Act II-3
Table II-2 Summary of Estimated Incremental Unit Compliance Costs Corresponding to
Three Regulatory Scenarios Resources Conservation and Recovery Act II-4
Table II-3 Summary of Assumptions Corresponding to Three Regulatory Scenarios - Safe
Drinking Water Act II-7
Table II-4 Summary of Estimated Incremental Unit Compliance Costs Corresponding to
Three Regulatory Scenarios - Safe Drinking Water Act II-8
Table II-5 Summary of Assumptions Corresponding to Three Regulatory Scenarios - Clean
Water Act 11-10
Table II-6 Summary of Estimated Incremental Unit Compliance Costs Corresponding to
Three Regulatory Scenarios - Clean Water Act 11-11
Table II-7 Summary of Assumptions Corresponding to Three Regulatory Scenarios - Clean
Air Act 11-14
Table II-8 Summary of Estimated Incremental Unit Compliance Costs Corresponding to
Three Regulatory Scenarios - Clean Air Act 11-15
Table II-9 Estimates of Total Industry Costs of Compliance Associated with the Regulatory
Initiatives Considered in this Analysis 11-17
Table 111-1 Original and Remaining Oil Resources in Nine States Analyzed for Resource
Abandonment Potential III-5
Table IV-1 Forecast Crude Oil Production and Percentage Resource Abandonments in Nine
States without Reserve Additions IV-5
Table IV-2 Impact of Environmental Regulations on Current Crude Oil Production in Nine
States Analyzed IV-8
Table IV-3 Incremental Reserve Additions from UMO Extraction by Process for Texas,
Oklahoma, and New Mexico, Implemented Technology IV-19
Table IV-4 Incremental State and Federal Revenues from UMO Extraction in Texas,
Oklahoma, and New Mexico, Implemented Technology IV-21
Table IV-5 Incremental Reserve Additions from UMO Extraction by Process for Texas,
Oklahoma, and New Mexico, Advanced Technology IV-22
Table IV-6 Incremental State and Federal Revenues from UMO Extraction in Texas,
Oklahoma, and New Mexico, Advanced Technology IV-24
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LIST OF TABLES, continued
Table IV-7 Impact of Environmental Regulations on Reserves from UMO Extraction in Texas,
Oklahoma, and New Mexico, Implemented Technology IV-26
Table IV-8 Impact of Environmental Regulations on Incremental UMO Recovery by Process
in Texas, Oklahoma, and New Mexico, Implemented Technology IV-28
Table IV-9 Impact of Environmental Regulations on Reserves from UMO Extraction in Texas,
Oklahoma, and New Mexico, Advanced Technology IV-30
Table IV-10 Impact of Environmental Regulations on Incremental UMO Recovery by Process
in Texas, Oklahoma, and New Mexico, Advanced Technology IV-32
Table IV-11 Impact of Environmental Regulations on Total Public Sector Revenues Associated
with UMO Reserves in Texas, Oklahoma, and New Mexico, Implemented
Technology IV-33
Table IV-12 Impact of Environmental Regulations on Total Public Sector Revenues Associated
with UMO Reserves in Texas, Oklahoma, and New Mexico, Advanced
Technology IV-36
Table IV-13 Impact of Environmental Regulations on Total Industry Investment and Operating
Expenditures for UMO Development in Texas, Oklahoma, and New Mexico,
Implemented Technology IV-38
Table IV-14 Impact of Environmental Regulations on Total Industry Investment Expenditures
for UMO Development in Texas, Oklahoma, and New Mexico, Implemented
Technology IV-41
Table IV-15 Impact of Environmental Regulations on Total Direct Industry Operating
Expenditures for UMO Development in Texas, Oklahoma; and New Mexico,
Implemented Technology IV-42
Table IV-16 Impact of Environmental Regulations on Total Industry Investment and Operating
Expenditures for UMO Development in Texas, Oklahoma, and New Mexico,
Advanced Technology IV-43
Table IV-17 Impact of Environmental Regulations on Total Industry Investment Expenditures
for UMO Development in Texas, Oklahoma, and New Mexico, Advanced
Technology IV-45
Table IV-18 Impact of Environmental Regulations on Total Direct Industry Operating
Expenditures for UMO Development in Texas, Oklahoma, and New Mexico,
Advanced Technology IV-46
Table IV-19 Incremental Reserve Additions from EOR by Process in the U.S. - Implemented
Technology . IV-49
Table IV-20 Incremental State and Federal Revenues from EOR Production in the U.S. -
Implemented Technology IV-50
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Page iv
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LIST OF TABLES, continued
Table IV-21
Table lV-22
Table IV-23
Table IV-24
Table IV-25
Table IV-26
Table IV-27
Table IV-28
Table IV-29
Table IV-30
Table IV-31
Table IV-32
Table IV-33
Table IV-34
Table IV-35
Table IV-36
Incremental Reserve Additions from EOR by Process in the U.S. Advanced
Technology
Incremental State and Federal Revenues from EOR Production in the U.S.
Implemented Technology
Impact of Environmental Regulations on EOR Reserves Development in the U.S. -
Implemented Technology
Impact of Environmental Regulations on Incremental EOR by Process in the U.S. -
Implemented Technology
Impact of Environmental Regulations on Total EOR Reserves Development in the
U.S. - Advanced Technology
Impact of Environmental Regulations on Incremental EOR by Process in the U.S. -
Advanced Technology
Impact of Environmental Regulations on Public Sector Revenues from EOR
Reserves Development in the U.S. Implemented Technology
Impact of Environmental Regulations on Public Sector Revenues from EOR
Reserves Development in the U.S. - Advanced Technology
Impact of Environmental Regulations on Total Industry Investment and Operating
Expenditure for EOR Development in the U.S. Implemented Technology
Impact of Environmental Regulations on Total Industry Investment Expenditure for
EOR Development in the U.S. Implemented Technology
Impact of Environmental Regulations on Total Industry Operating Expenditure for
EOR Development in the U.S. Implemented Technology
Impact of Environmental Regulations on Total Industry Investment and Operating
Expenditure for EOR Development in the U.S. - Advanced Technology
Impact of Environmental Regulations on Total Industry Investment Expenditure for
EOR Development in the U.S. - Advanced Technology
Impact of Environmental Regulations on Total Industry Operating Expenditure for
EOR Development in the U.S. - Advanced Technology
Incremental Reserve Additions from Undiscovered Crude Oil Fields in the
U.S
Incremental State and Federal Revenues from Undiscovered Crude Oil
Development in the U.S
IV-51
IV-53
IV-54
IV-57
IV-58
IV-60
IV-62
IV-64
IV-66
IV-69
IV-70
IV-71
IV-73
IV-74
IV-77
IV-79
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Table IV-37
LIST OF TABLES, continued
Impact of Environmental Regulations on Undiscovered Reserves in the
U.S
IV-80
Table IV-38 Impact of Environmental Regulations on Undiscovered Reserves in the Lower-48
Onshore IV-83
Table IV-39 Impact of Environmental Regulations on Undiscovered Reserves in the Lower-48
Offshore IV-85
Table IV-40 Impact of Environmental Regulations on Undiscovered Reserves in Alaska
(Onshore and Offshore) IV-88
Table IV-41 Impact of Environmental Regulations on Incremental Reserves from Undiscovered
Crude Oil Fields in the U.S IV-90
Table IV-42 Impact of Environmental Regulations on Public Sector Revenues from
Undiscovered Reserves Development in the Lower-48 Onshore IV-91
Table IV-43 Impact of Environmental Regulations on Public Sector Revenues from
Undiscovered Reserves Development in the Lower-48 Offshore IV-94
Table IV-44 Impact of Environmental Regulations on Public Sector Revenues from
Undiscovered Reserves Development in Alaska IV-95
Table IV-45 Impact of Environmental Regulations on Total Industry Investment and Operating
Expenditures from Undiscovered Crude Oil Development in the
U.S IV-96
Table IV-46 Impact of Environmental Regulations on Total Industry Investment Expenditures
from Undiscovered Crude Oil Development in the U.S IV-98
Table IV-47 Impact of Environmental Regulations on Total Industry Direct Operating
Expenditures from Undiscovered Crude Oil Development in the U.S IV-99
Table V-1 Impact of Potential Environmental Regulations on U.S. Crude Oil Supplies at an
Oil Price of $16/Bbl V-2
Table V-2 Impact of Potential Environmental Regulations on U.S. Crude Oil Supplies at an
Oil Price of $20/Bbl V-3
Table V-3 Impact of Potential Environmental Regulations on U.S. Crude Oil Supplies at an
Oil Price of $24/Bbl V-4
Table V-4 Impact of Potential Environmental Regulations on U.S. Crude Oil Supplies at an
Oil Price of $32/Bbl V-5
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LIST OF FIGURES
Figure 111-1 Over 300 Billion Barrels of Known Oil Resources will Remain After Conventional
Figure IV-1
Figure IV-2
Figure IV-3
Figure IV-4
Figure IV-5
Figure IV-6
Figure IV-7
Figure IV-8
Figure IV-9
Figure IV-10
Figure IV-1 1
Figure IV-1 2
Figure IV-1 3
Production
Forecast of Conventional Crude Oil Production in the Nine States Analyzed
Impact of Environmental Regulations on Abandonment of the Crude Oil Resource
in the Nine States Analyzed (Reference Case)
Impact of Proposed Environmental Regulations on Crude Oil Production in the
Nine States Analyzed ($16/Bbl Oil Price)
Impact of Proposed Environmental Regulations on Crude Oil Production in the
Nine States Analyzed ($20/Bbl Oil Price)
Impact of Proposed Environmental Regulations on Crude Oil Production in the
Nine States Analyzed ($24/Bbl Oil Price)
Impact of Proposed Environmental Regulations on Crude Oil Production in the
Nine States Analyzed ($32/Bbl Oil Price)
Impact of Environmental Regulations on Abandonment of the Crude Oil Resource
in the Nine States Analyzed ($16/Bbl Oil Price)
Impact of Environmental Regulations on Abandonment of the Crude Oil Resource
in the Nine States Analyzed ($20/Bbl Oil Price)
Impact of Environmental Regulations on Abandonment of the Crude Oil Resource
in the Nine States Analyzed ($24/Bbl Oil Price)
Impact of Environmental Regulations on Abandonment of the Crude Oil Resource
in the Nine States Analyzed ($32/Bbl Oil Price)
Impact of Environmental Regulations on UMO Reserves in Texas, Oklahoma, and
New Mexico - Implemented Technology
Impact of Environmental Regulations on UMO Reserves in Texas, Oklahoma, and
New Mexico - Advanced Technology
Impact of Environmental Regulations on Total Public Sector Revenues from UMO
III-2
IV-3
IV-6
IV-9
IV-10
IV-11
IV-1 2
IV-1 3
IV-1 4
IV-1 5
IV-1 6
IV-27
IV-31
Development in Texas, Oklahoma, and New Mexico Implemented
Technology IV-34
Figure IV-14 Impact of Environmental Regulations on Total Public Sector Revenues from UMO
Development in Texas, Oklahoma, and New Mexico Advanced
Technology IV-37
Figure IV-15 Impact of Environmental Regulations on Total Industry Expenditures for UMO
Development in Texas, Oklahoma, and New Mexico Implemented
Technology IV-39
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LIST OF FIGURES, continued
Figure IV-16 Impact of Environmental Regulations on Total Industry Expenditures for UMO
Development in Texas, Oklahoma, and New Mexico - Advanced
Technology IV-44
Figure IV-17 Impact of Environmental Regulations on EOR Reserves in the U.S. - Implemented
Technology - All Projects IV-55
Figure IV-18 Impact of Environmental Regulations on EOR Reserves in the U.S. Advanced
Technology - All Projects IV-59
Figure IV-19 Impact of Environmental Regulations on Total Public Sector Revenues from EOR
Reserves Development in the U.S. Implemented Technology - All
Projects IV-63
Figure IV-20 Impact of Environmental Regulations on Total Public Sector Revenues from EOR
Reserves Development in the U.S. - Advanced Technology All
Projects IV-65
Figure IV-21 Impact of Environmental Regulations on Total Industry Expenditures on EOR
Development in the U.S. - Implemented Technology All Projects IV-67
Figure IV-22 Impact of Environmental Regulations on Total Industry Expenditures on EOR
Development in the U.S. - Advanced Technology - All Projects IV-72
Figure IV-23 Project Undiscovered Crude Oil Reserves in the U.S. - Total U.S. - Reference
Case IV-78
Figure IV-24 Impact of Environmental Regulations on Undiscovered Crude Oil Reserves in the
U.S IV-81
Figure IV-25 Impact of Environmental Regulations on Undiscovered Crude Oil Reserves in the
U.S. - Lower-48 Onshore IV-84
Figure IV-26 Impact of Environmental Regulations on Undiscovered Crude Oil Reserves in the
U.S. Lower-48 Offshore IV-86
Figure IV-27 Impact of Environmental Regulations on Undiscovered Crude Oil Reserves in the
U.S. Alaska (Onshore and Offshore) IV-89
Figure IV-28 Impact of Environmental Regulations on Total Public Sector Revenues from
Undiscovered Crude Oil Development in the U.S IV-92
Figure IV-29 Impact of Environmental Regulations on Total Industry Expenditures for
Undiscovered Crude Oil Development in the U.S IV-97
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I. INTRODUCTION
A number of legislative and regulatory initiatives being considered by Congress and state and
federal government agencies to protect human health and the environment will affect domestic oil and
gas exploration and production (E&P) activities (Arscott, 1989). From a national perspective, the most
important statutes affecting the domestic E&P industry are the following:
• Resource Conservation and Recovery Act (RCRA)
Safe Drinking Water Act (SDWA)
Clean Water Act (CWA)
Clean Air Act (CAA)
• Superfund Amendments and Reauthorization Act (SARA)
• Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA).
Not all environmental statutes require the Environmental Protection Agency (EPA) or other
regulatory agencies to consider costs and/or energy impacts when establishing regulations or standards.
When energy impact analyses are performed, these analyses are often limited in scope, because they
generally only consider the impacts associated with a specific regulation, and almost always assume no
impacts from regulations in other areas.
However, many government and industry analysts have expressed growing concern that the
cumulative costs of multiple environmental initiatives could have significant impacts on domestic oil and
gas operations, especially for those operations conducted by smaller companies and those in marginally
economic fields. Moreover, some feel that while the costs of increased environmental regulations are
cumulative, the benefits from these regulations may not be.
A variety of factors can influence the ultimate economic recovery of crude oil reserves, including
oil prices, extraction technologies, taxes, and regulatory costs. Previous DOE studies have estimated the
potential impact of oil prices, extraction technologies, and taxes on crude oil reserves (IOCC, 1989; IOCC,
1987; DOE, 1989), however, in all of these studies, no changes in environmental compliance costs were
assumed. The intention of the present study is to assist policy makers by examining the cumulative
impact of the increased costs of environmental regulations on domestic crude oil supplies, to aid in
balancing energy/economic impacts with the environmental impacts associated with U.S. petroleum
operations. Hopefully, the study will help promote interagency dialogue in developing cost-effective
environmental regulations that both protect the environment and allow access to U.S. crude oil supplies
to be maintained.
06K00135.RPT page ^
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This study involved a review of selected environmental initiatives that could affect the U.S. oil and
gas E&P industry. The review examined the nature of and estimated incremental compliance costs
associated with each initiative. From a review of these initiatives, three regulatory scenarios were
developed, representing low, medium, and high levels of incremental compliance costs. The high
scenario represents a stringent but conceivable level of regulation, but should not necessarily be
considered a worst case scenario. For example, in reference to authority under RCRA, this would
represent a level of stringency similar to "modified" RCRA Subtitle C regulations (which pertain to solid
wastes characterized as hazardous under the statute), but which does not include all aspects of those
regulations as currently implemented). The low scenario represents a case that recognizes some change
in existing regulations is inevitable (though not necessarily the set of initiatives defined), and therefore
some impact on domestic E&P activities is likely. Finally, the medium scenario represents a case that
roughly balances the high and low case, but should not be considered a most likely scenario. Again,
using RCRA as an example, this would represent a set of regulations corresponding to a substantially
expanded and modified RCRA Subtitle D program (which would involve regulations affecting solid wastes
not classified as hazardous under the statute).
Using available models developed by the U.S. Department of Energy (DOE), the cumulative
impacts associated with each scenario were determined. Impacts were presented in terms of the
estimated incremental costs operators would have to incur to comply with each scenario and the crude
oil reserves and/or production that would become uneconomic as a result of imposing the regulations
considered. Other impacts were also considered, such as the impact on state and federal revenues from
royalty and tax receipts, and the impact of environmental regulations on industry expenditures for oil and
gas development.
This study does not consider every potential environmental initiative that may affect the economics
of U.S. E&P activities, since estimated compliance costs associated with many initiatives have not yet been
assessed. Consequently, the estimated impacts presented may be somewhat conservative. In addition,
the initiatives proposed or under consideration are constantly evolving; this study represents only those
under consideration at the time of the analysis.
The estimated compliance costs used in this study are based on data developed by EPA and/or
the American Petroleum Institute (API). The form of the compliance costs estimates were often modified
in order to appropriately incorporate them into the models used in the study. All costs presented are in
1988 dollars.
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Page I-2
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The analysis considered the economic recovery potential at four constant crude oil prices -- $16,
$20, $24, and $32 per barrel. The initial step in the analysis involved estimating economic recovery
potential under baseline conditions, which assumes costs of compliance with environmental regulations
currently in place. This analysis was based on regional average costs determined as a function of
reservoir depth and other relevant parameters, such as oil production rates, water depth (in the offshore),
etc. This established the recovery potential under baseline conditions, providing the reference case to
which the other scenarios were compared.
Four categories of domestic crude oil supplies were evaluated. The energy impacts associated
with the imposition of increased environmental compliance costs were assessed for each resource
category. Future production from four resource categories were considered:
• the continued conventional production of crude oil in known fields in the
Lower-48 onshore
• future infill drilling and waterflood projects in known fields in the Lower-48
onshore
• future enhanced oil recovery projects in known fields in the Lower-48
onshore
• onshore and offshore crude oil fields remaining to be discovered in the
Lower-48 and Alaska.
The entire U.S. crude oil resource base was not analyzed as part of this assessment. In most
cases, the reservoir data base available only represented a portion of the domestic resource base. The
results of the analyses for each subset of reservoirs were not extrapolated; i.e., the results only represent
the impacts that are explicit to the reservoirs analyzed. In these cases, the discussion clearly states the
portion of the U.S. resource base that the analysis considered. Any extrapolation of the results of this
analysis should be performed with caution. The extrapolation would assume that the resources not
considered are, on average, similar to those which were considered, which may not necessarily be true.
The three sets of regulatory initiatives proposed in this analysis do not necessarily represent any
set of regulations recommended or supported by EPA, or any other federal or state agency, or by any
specific association, company, or institution. The scenarios proposed are intended to represent a range
of possible combinations of regulations, corresponding to options which have been under consideration
or discussion, for use in determining the potential cumulative or combined impact of these initiatives on
domestic crude oil supplies.
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The following chapter provides a summary of the regulatory initiatives considered in this analysis,
defines the three regulatory scenarios that were developed from these initiatives, and discusses the overall
incremental compliance costs that correspond to the three scenarios. More detailed descriptions of the
assumptions associated with the three regulatory scenarios and the specific compliance costs associated
with the defined scenarios are presented in Appendix A.
Chapter III presents a summary of the resource categories considered in this assessment,
describes the models used in the analysis, and summarizes the analytical approach used in the study.
A more detailed description of the analytical approach is presented in Appendix B.
Chapter IV presents the results of this analysis for each resource category, oil price, and
technology assumption considered. Impacts are discussed in terms of abandoned production, lost
reserves, lost public sector revenues, and the total costs of compliance.
Finally, Chapter V summarizes the findings of this assessment and provides some concluding
remarks.
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II. ENVIRONMENTAL INITIATIVES CONSIDERED
This analysis considers only those environmental initiatives where incremental compliance costs
have previously been estimated and cited in other reports. These include initiatives which have been or
are being considered under the authority of the following statutes:
• Resource Conservation and Recovery Act
• Safe Drinking Water Act
Clean Water Act
• Clean Air Act.
Environmental initiatives under the Superfund Amendments and Reauthorization Act were also
examined (as described in Appendix A), but no incremental costs associated with complying with these
initiatives were estimated and considered in this analysis.
The environmental initiatives considered, organized by statute establishing regulatory authority,
are summarized below.
A. Resource Conservation and Recovery Act
On June 30, 1988, EPA delivered to Congress its regulatory determination concerning
environmental regulations associated with the exploration, development, and production of crude oil,
natural gas, and geothermal energy. In that determination, EPA concluded that regulation of E&P
activities under RCRA Subtitle C authority (i.e., regulation as hazardous wastes) is not warranted. Rather,
EPA recommended a three-pronged strategy to address the unique environmental and programmatic
issues posed by E&P activities by:
• Improving federal programs under existing authorities in Subtitle D of
RCRA (applied to the management and disposal of non-hazardous solid
wastes), the Clean Water Act, and the Safe Drinking Water Act.
• Working with states to improve their regulation and enforcement
programs.
Working with the Congress to develop any additional statutory authority
that may be required.
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As part of this strategy, EPA intends to develop tailored RCRA Subtitle D standards for oil and gas
operations. Potential modifications to Subtitle D considered in this analysis include the following activities
associated with E&P operations:
Management and disposal of drilling muds and cuttings
• Disposal of associated wastes into central disposal facilities
• Upgrading emergency pits
• Replacement of workover pits with portable rig tanks
Implementation of the Organic Toxicity Characteristic (OTC) test
• Corrective action (soil remediation) of contaminated sites.
The assumptions corresponding to the high, medium, and low regulatory scenarios for this set
of regulatory initiatives under RCRA are summarized in Table 11-1. The estimated incremental unit
compliance costs corresponding to the three scenarios under RCRA are summarized in Table II-2.
The requirements considered under RCRA Subtitle D authority, for purpose of this analysis, apply
only to onshore operations. Regulatory initiatives of concern under RCRA authority are discussed in more
detail in Appendix A.
The incremental compliance costs considered under RCRA include the management and disposal
of wastes which are intrinsic to E&P operations and are currently defined as exempt from RCRA Subtitle
C regulations by EPA. The management and disposal of wastes such as used oils, paints, solvents,
chemical products, and other materials not uniquely used as a part of the extraction of oil and gas are
not exempt under RCRA, and are therefore not considered in the incremental regulatory costs developed
for this analysis.
A number of other possible initiatives are also being considered under RCRA authority that could
have impacts on E&P activities. These considerations include the administration of and compliance with
a system for approving the use of generic muds, for example, through the use of a general permit
procedure. Also not considered are potential requirements associated with groundwater monitoring,
closure, post-closure care, and financial assurance at facilities subject to permitting similar to that required
for RCRA hazardous waste sites. In addition, potential requirements pertaining to E&P operations that
may affect wetlands, endangered species, or fish and wildlife habitats were also not considered.
06KD0135.RPT Page II-2
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TABLE 11-1
SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS
Resource Conservation and Recovery Act
1.
2.
3.
4.
5.
6.
Regulatory Initiative
Management and Disposal of
Drilling Waste
Disposal of Associated
Wastes into Central Disposal
Facilities
Low
Regulatory Scenario
Medium
Oil-based muds disposed into lined Oil-based muds use closed systems
pits
Salt water-based muds disposed into
Salt water-based muds disposed into lined pits
lined pits
Liquid wastes into offsite disposal Liquid wastes into offsite disposal
well; solid wastes into nonhazardous well; solid wastes into hazardous
waste landfill
Upgrading Emergency Pits All emergency pits must be lined.
Replace Workover Pits with
Portable Rig Tanks
Organic Toxicity
Characteristic Test
Corrective Action (Soil
Remediation Only)
Required on all rigs
waste landfill
Existing emergency pits must be
lined; new pits must be replaced with
tanks
Required on all rigs
High
Oil-based muds use closed systems
All water-based muds disposed into
lined pits
Liquid wastes into offsite disposal
well; combustible solid wastes into
incinerator; non-combustible solid
wastes into hazardous waste landfill
Tanks must replace emergency pits
for both new and existing pits
Required on all rigs
Applied to all facilities and new wells Applied to all facilities and new wells Applied to all facilities and new wells
Land treatment of hydrocarbon
contamination at 50% of tank
batteries and EOR projects*
Excavation of salt water contamina-
tion at 100% of SWD wells and 75%
of EOR projects* and tank batteries
Land treatment of hydrocarbon
contamination at 50% of tank
batteries and EOR projects*
Excavation of hydrocarbon and salt
water contaminated sites at same
frequency as Medium Scenario
EOR projects refers to both secondary and tertiary recovery prefects
06K00127.TBL
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TABLE 11-2
SUMMARY OF ESTIMATED INCREMENTAL UNIT COMPLIANCE COSTS CORRESPONDING TO THREE REGULATORY SCENARIOS
(1988 Dollars)
Resource Conservation and Recovery Act
Regulatory Initiative
1. Management and Disposal of
Drilling Waste - Costs per Well
(new wells only)*
2. Disposal of Associated Waste
into Central Disposal Facilities
- Ann. Oper. Costs
3. Replace Emergency Pits with
Tanks
4. Replace Workover Pits with
Portable Rig Tanks
5. Organic Toxicity Characteristic
Test
Low
$17,483/new producer
$17,483/new injector
$125.50/producer/yr
$355/existing producer
$123/existing producer
$110/producer
$100/injector
$1,725/new well
$1,712/existing producer
$489/existing injector
$463/producer/yr
$132/injector/yr
$3,875/existing producer
$1,550/existing injector
Regulatory Scenario
Medium
$18,258/new producer
$18,258/new injector
6. Corrective Action (Soil
Remediation Only)
* See Table A-3; Costs assume 1.15 Bbl waste per well, average depth of well of 5,000 feet
Source: ERT, 1988.
$1,521/producer/yr
$355/existing producer
$123/existing injector
$9,488/new producer
$3,300/new injector
$110/producer
$100/injector
$1,725/new well
$1,712/existing producer
$489/existing injector
$463/producer/yr
$132/injector/yr
$16,813/existing producer
$4,925/existing injector
High
$20,034/new producer
$20,034/new injector
$1,686/producer/yr
$9,488/producer
$3,300/injector
$110/producer
$100/injector
$1,725/new well
$1,712/existing producer
$489/existing injector
$463/producer/yr
$132/injector/yr
$18,563/existing producer
$5,625/existing injector
06K00127.TBL
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Regulatory initiatives are also being considered pertaining to the management of produced waters
from oil and gas E&P operations. The regulatory cost impacts pertaining to the management of
produced waters were considered under SDWA and CWA authority, discussed later in this report.
B. Safe Drinking Water Act
The Underground Injection Control (DIG) program was established under the Safe Drinking Water
Act of 1974 (SDWA), to protect underground sources of drinking water (USDWs) from endangerment by
subsurface emplacement of fluids. Part C of the SDWA requires EPA to establish minimum requirements
for state programs and, in cases where states cannot or will not assume primary enforcement
responsibility, to assume federal regulatory authority for the program.
Under Section 1422 of the SDWA, all subsurface injection associated with E&P activities must be
governed by a UIC program. This requirement has resulted in the formation of two main types of Class
II UIC programs (concerned with injection wells associated with oil and gas operations). States whose
UIC programs are administered directly by EPA are referred to as Direct Implementation (Dl) states. In
contrast, states that have received primary enforcement responsibilities for the UIC program are known
as Primacy states. For Dl states, EPA has promulgated minimum national standards. To date, primacy
for almost all delegated Class II programs has been requested and granted under Section 1425 of the
SDWA, which allows states to make an alternative demonstration in order to receive primacy. This
alternative demonstration consists of states showing that their program is effective in protecting USDWs
and it contains certain elements traditionally associated with regulatory programs (e.g., permitting,
reporting, surveillance). EPA issued its '1425 guidance1 in 1981 to assist states in making this
demonstration.
In approving programs under Section 1425, EPA has accepted variations among the states
consistent with the statutory requirements of the SDWA. EPA has recently conducted a Midcourse
Evaluation of the Class II UIC program to examine whether the program reflects the experience and insight
the Agency has acquired since the program went into effect, to review the adequacy of USDW protection
in Primacy States, and to identify differences in state UIC program implementation and enforcement and
recommend improvements in these areas.
As part of the Midcourse Evaluation process, EPA identified five major areas of potential concern
that would require investigation as part of the effort (EPA, 1989). These areas are:
• Operating, monitoring, and reporting requirements
06K00135.RPT
page |
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• Plugging and abandonment
Mechanical integrity testing (MIT) requirements
Well construction requirements
• Area of review (AOR) and corrective action requirements.
Of these, only the potential compliance costs associated with additional mechanical integrity
testing, area-of-review/corrective action, and well construction requirements were considered in this study.
The assumptions corresponding to the high, medium, and low regulatory scenarios
for this set of regulatory initiatives under SDWA are summarized in Table 11-3. The estimated incremental
unit compliance costs corresponding to the three scenarios under SDWA are summarized in Table 11-4.
Regulatory initiatives under SDWA authority are discussed in more detail in Appendix A.
A number of other possible initiatives are also under consideration under the authority of the
SDWA that could also impact E&P activities. These include potential additional operating, monitoring, and
reporting requirements; requirements for the temporary abandonment of existing wells; and requirements
for permanently plugging and abandoning wells, including those that may have been improperly plugged
and abandoned in the past and have not been identified and mitigated as part of the AOR permitting
process. The impacts of these potential regulatory initiatives on domestic crude oil supplies were not
analyzed as part of this assessment, since no compliance cost estimates for these initiatives have yet
been developed.
C. Clean Water Act
A number of regulatory proposals are also under consideration under the authority of the Clean
Water Act that will likely affect U.S. oil and gas operations. These initiatives concern discharges to rivers,
streams, and lakes in the onshore and discharges to offshore waters. They concern discharges directly
associated with normal E&P operations, as well as stormwater discharges and spills (e.g., from above
ground storage tanks).
Among the potential regulatory initiatives under consideration under the CWA are those
associated with the discharge of drilling fluids and cuttings from offshore facilities. Potential initiatives
under consideration include the development of a list of generic muds exhibiting low toxictty, where
offshore drilling operations would be limited to only using muds on the generic list. Other offshore
requirements could include specific toxicrty testing requirements of drilling fluids and cuttings; restrictions
on the discharge of deck drainage, produced sand, and well treatment fluids generated from offshore
00135.RPT
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TABLE 11-3
SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS
Safe Drinking Water Act
Regulatory Initiative
1. Mechanical Integrity Testing*
Part 1
Part 2
Non Injection-Related Fluid
Movement
2. Area of Review (on wells drilled
prior to 1984)
3. Corrective Action (on wells drilled
prior to 1984)
4. Construction Requirements
Low
Regulatory Scenario
Medium
No incremental requirements (5-year
pressure test)
Radioactive tracer test every five
years
No incremental requirements
No incremental requirements
No incremental requirements
No incremental requirements
Pressure test frequency based on
corrosive potential of basin
Radioactive tracer test and noise or
temperature log run to injection zone,
frequency based on basin corrosivity
Oxygen activation log and noise or
temperature log run to lowermost
underground source of drinking
water.
1/4 mile area of review (AOR) under
area permit
5% of producing wells within AOR
assumed to require remedial squeeze
10% of abandoned wells within AOR
assumed to require reentering and
replugging
1% of producing wells within AOR
must be redrilled
10% of injectors require remedial
squeeze
2% of injectors must be redrilled
MIT Part 1 addresses tubing, casing, and packer integrity. MIT Part 2 addresses fluid movement behind the casing.
High
Continuous positive annular pressure
monitoring and 5-year pressure test
Radioactive tracer test, noise, and
temperature log run to injection zone,
frequency based on basin corrosivity
Oxygen activation, noise, and
temperature log run to lowermost
underground source of drinking water
1/4 mile area of review (AOR) under
individual injector permit
15% of producing wells within AOR
assumed to require remedial squeeze
30% of abandoned wells within AOR
assumed to require reentering and
replugging
3% of producing wells within AOR
must be redrilled
30% of injectors require remedial
squeeze
6% of injectors must be redrilled
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TABLE 11-4
SUMMARY OF ESTIMATED INCREMENTAL UNIT COMPLIANCE COSTS CORRESPONDING TO THREE REGULATORY SCENARIOS
(1988 Dollars)
Safe Drinking Water Act
Requlatorv Initiative
1. Mechanical Integrity Testing
Part 1
New Fields:
- Capital Costs
Low
None
Requlatorv Scenario
Medium
High
$1 500/injector
- Ann. Oper. Costs
Discovered Fields:
- Capital Costs
- Ann. Oper. Costs
Part 2
- Ann. Oper. Costs**
NIR Fluid Movement
Area of Review
None
($200+0.05/ft)/injector/yr
($20+0.005/ft)/producer/yr
None
None
0.90 (400/x-80)/injector/yr
0.09 (400/x-80)/producer/yr
0.90(400/x-80)/injector/yr
0.09(400/x-80)/producer/yr
[($2014+0.43/ft)/x]/injector/yr
[(201.4+0.043/ft)/x]/producer/yr
(771+0.17/ft)/injector/yr
(77+0.02/ft)/producer/yr
$1,528 per injector
$608 per well within the AOR
0.75 (3046+0.605/ft) per injector
0.20 (2) (3046+0.605/ft) per producer
within AOR
$150/producer
$285/injector/yr
$123.5/producer/yr
$1,350/injector
$135/producer
$256.50/injector/yr
$111.50/producer/yr
[($2464+0.53/ft)/x]/injector/yr
[(246+0.05/ft)/x]/producer/yr
(771+0.17/ft)/injector/yr
(77+0.02/ft)/producer/yr
$23,340 per injector
0.75 (3045+0.605/ft) per injector
0.20 (2) (3046+(0.605/ft) per
producer within AOR
3. Correction Action None
4. Construction Requirements None
** x is the testing cycle frequency (see Table A-12)
Source: Gruy, 1989
See Table A-16
See Table A-17
See Table A-16
See Table A-17
06K00127.TBL
Page II-8
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facilities, and the use of effluent dispersion models to evaluate potential risks associated with offshore E&P
activities. Potential requirements associated with discharges from onshore E&P facilities include National
Pollution Discharge Elimination System (NPDES) permit requirements for stormwater discharges, the
design and operation of above ground storage tanks, and requirements for estuaries and other sensitive
coastal environments.
The regulatory initiatives explicitly considered in this analysis under CWA authority include the
following:
• Discharge of drilling fluids and cuttings and produced waters from offshore facilities
NPDES permit requirements for stormwater discharges
• Regulations affecting the design and operation of above ground storage tanks
• The banning of onshore and coastal discharges.
The assumptions corresponding to the three scenarios for this set of regulatory initiatives under
CWA are summarized in Table 11-5. The estimated incremental unit compliance costs corresponding to
the three scenarios under CWA are summarized in Table 11-6. Regulatory initiatives of concern under
CWA authority are detailed in Appendix A.
D. Clean Air Act
On July 20, 1989, President Bush presented the Administration's proposed Clean Air Act
Amendments of 1989. The proposed bill was subsequently introduced by Congressmen Dingell in the
House, as H.R.3030, and by Senator Chafee in the Senate, as S.1490. Three similar bills were introduced
in Congress prior to the release of the President's Clean Air legislative proposal - S.816, H.R.4, and
H.R.2585.
In early 1990, representatives of the Administration and members of the Senate from both parties
reached a compromise agreement concerning amendments to the Clean Air Act to support on the Senate
floor. This agreement was comprehensive in both the breadth and specificity of its provisions.
Although concerned with all major air pollutants, the primary concern of this agreement for the
domestic E&P industry pertains to hazardous air pollutants. Like the Administration's proposal and the
three Congressional bills submitted prior to this compromise, the agreement does not specify the level
of control emitters of hazardous air pollutants must achieve; the proposed standard is 'maximum
06K00135.RPT page ||.g
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TABLE 11-5
SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS
Clean Water Act
Regulatory Initiative
1. NSPS for Offshore Discharge of
Muds and Cuttings*
2. NSPS for Offshore Discharge of
Produced Water
3. NPDES Stormwater Permits
4. Above Ground Storage Tanks
5. Ban on Onshore Surface and
Coastal Discharge of Produced
Waters
Low
Regulatory Scenario
Medium
EPA Approach A (EPA's estimate of
facilities affected and associated
compliance costs)
Existing facilities: no change
New facilities: treat to 59 mg/l
Required for 55% of facilities
API Partial Discharge Limitation
Scenario (EPA Approach A with API
estimates of compliance costs)
Existing facilities: treat to 59 mg/l
New facilities: shallow water, no
discharge; deep water, treat to
59 mg/l
Required for 55% of facilities
Only leak detection and financial All aspects+ considered for new
responsibility for new tanks larger tanks larger than 500 barrels;
than 1,000 barrels financial responsibility for all tanks
High
API Zero Discharge Limitation
Scenario (API assumption that all
facilities are affected, using API cost
estimates)
Existing facilities: shallow water, no
discharge; deep water, treat to
59 mg/l
New facilities: no discharge all
depths
Required for 55% of facilities
All aspects"1" considered for all new
and existing tanks
No incremental requirements
Ban on discharges from new facilities Ban on discharges from all facilities
SeeEAl, 1988.
Aspects of regulations include injection and integrity testing, overflow prevention equipment, leak detection equipment, additional corrosion protection, and
financial responsibility requirements.
06KOO127.TBL
3age 11-10
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TABLE 11-6
SUMMARY OF ESTIMATED INCREMENTAL UNIT COMPLIANCE COSTS CORRESPONDING TO THREE REGULATORY SCENARIOS
(1988 Dollars)
Clean Water Act
Regulatory Initiative
1. NSPS for Offshore Discharge
of Muds and Cuttings
2. NSPS for Offshore Discharge
of Produced Waters
Low
See Table A-21
Regulatory Scenario
Medium
See Table A-21
See Tables A-22 through A-25
See Tables A-22 through A-25
High
See Table A-21
See Tables A-22 through A-25
3. NPDES Stormwater Permits
4. Above Ground Storage
Tanks
5. Ban on Onshore Surface
Discharges of Produced
Water
$2,475/producer
$80/new producer
See Table A-28
$2,475/producer
$1440/new producer
$1000/existing producer
See Table A-28
$2,475/producer
$5000/producer
See Table A-28
Sources: 53FR41356; October 21, 1988; Walk, Haydel, 1989; ICF-Lewin Energy, 1988; Entropy Limited, 1989; ERT, 1988.
06K00127.TBL
Page 11-11
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achievable control technology1, considering cost and feasibility. API (Jones, Martin, and Hoffman, 1989),
in order to develop a preliminary estimate of the potential costs to the petroleum industry in implementing
some of the emissions controls under consideration, developed two regulatory scenarios to roughly
bracket the likely stringency of eventual standards, defined as follows:
• Case I estimates assume MACT is interpreted to require nationwide
controls approximately equivalent to the controls required now in
California ozone non-attainment areas.1
Case II estimates the additional costs (beyond Case I) if MACT is
interpreted to require technologies which are currently experimental or
not otherwise in significant commercial use.
The two cases reflect the range of uncertainty in the definition of MACT. The ultimate cost to the
petroleum industry of air toxics legislation is thus dependent in large measure on the definition of MACT
as interpreted by EPA in regulatory proceedings or as more explicitly defined by Congress.
Each bill contains a list of toxic air pollutants, proposes a schedule for controlling specific
categories of pollutants, and contains a provision for assessing residual risk to determine if implemented
controls achieve an 'acceptable1 level of risk.
The regulatory initiatives affecting domestic E&P operations concern the emission of NOX, volatile
organic compounds (VOCs), SOX, particulates and other constituents from both onshore and offshore
operations. Nearly all domestic E&P operations could potentially be affected by proposed CAA revisions
currently under consideration. Other initiatives associated with amending the CAA that could potentially
be considered include regulations concerning the catastrophic release of acutely toxic substances and
the costs of proposals that would place restrictions on the composition and use of motor vehicle fuels.
In this analysis, only regulatory initiatives directly affecting E&P operations and the continuous,
relatively low-level releases of toxic air pollutants from these operations were considered. Although the
proposed legislation also concerns acid rain and ozone precursors, only controls on toxic air pollutants
are considered in this study.
Trie air toxics cost estimates do not take into account future developments in ozone regulation. That is,
some of the costs could also result (in the absence of air toxics legislation) from additional ozone controls
in non-attainment areas. A comprehensive analysis of the costs of Clean Air Act Amendments would
require some care to avoid double-counting costs that could be allocated to either ozone or air toxics
controls.
06K00135.RPT Page 11-12
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Prior to the introduction of the various legislative proposals concerning hazardous air pollutants,
the Minerals Management Service (MMS) issued a proposed rule to impose- stricter emission control
standards for oil and gas operations off the coast of California. The major aspect of this rule would
require offshore operations to install additional and best available pollution control equipment for all
phases of California Outer Continental Shelf (OCS) development. The rule would also require emission
offsets at lower levels of pollution, control of the number of simultaneous exploration activities by different
operators, regulate and limit the use of crew and supply boats, and require companies to examine the
use of onshore sources of electricity for offshore platforms and rigs.
Although issued prior to the President's proposed Clean Air Act Amendments or the introduction
of the various legislative proposals concerning air toxics, the proposed MMS guidelines established
controls at a level that could be considered consistent with the MACT Case I standard for operations off
the coast of California. The strict nature of the proposed guidelines is in response to California's unique
non-attainment situation for air pollutants, resulting in standards more strict than those in the rest of the
OCS, and a regulatory standard similar to Case I assumed for onshore E&P operations.
The assumptions corresponding to the three scenarios for this set of regulatory initiatives under
CAA are summarized in Table 11-7. The estimated incremental unit compliance costs corresponding to
the three scenarios under CAA are summarized in Table 11-8. Regulatory initiatives of concern under CAA
authority are discussed in more detail in Appendix A.
Analyses performed to determine the costs of possible CAA Amendments concerning air toxics
were somewhat limited in scope. Consequently, several categories of potential compliance costs for air
emission regulations were not considered to this analysis. One category of costs not considered included
those associated with potential catastrophic releases of acutely toxic substances such as ammonia,
chlorine, and hydrogen sulfide, which are not subject to the control technologies primarily concerned with
low levels of continuous emissions. Another category of costs not considered was those pertaining to
proposals to modify the constituents of gasoline.
In addition, another potential cost not considered was that associated with dismantling Case I
controls if Case II controls are determined to be more effective, and the costs of proposals to reduce VOC
emissions that would not be reduced from the implementation of the air toxics emission controls
considered in the analysis.
Finally, this assessment only considered air toxics control costs affecting the production sector.
Although cost impacts on the marketing, transportation, and refining sectors of the petroleum industry will
06K00135.RPT Page 11-13
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TABLE 11-7
SUMMARY OF ASSUMPTIONS CORRESPONDING TO THREE REGULATORY SCENARIOS
Clean Air Act
Regulatory Initiative Regulatory Scenario
Low Medium High
1. Onshore Air Toxics Emissions API Case I scenario API Case I Scenario API Case II Scenario
Standards*
2. Offshore Air Toxics Emissions California only; no mitigation costs California only; mitigation costs Entire DCS; mitigation costs for
Standards considered considered California only
See Jones, Martin, and Hoffman, 1989
06K00127.TBL ' " Page |M4
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1.
TABLE II-8
SUMMARY OF ESTIMATED INCREMENTAL UNIT COMPLIANCE COSTS CORRESPONDING TO THREE REGULATORY SCENARIOS
(1988 Dollars)
Clean Air Act
Regulatory Initiative
Onshore Air Toxics Emission
Standards
Low
$12,200/producer
$400/producer/yr
2. Offshore Emissions Control See Table A-31
Regulatory Scenario
Medium
$12,200/producer
$400/producer/yr
High
$40,450/producer
$400/producer/yr
Source:
Jones, Martin, and Hoffman, 1989; MMS, 1989 (see Appendix C)
06K00127.TBL
Page 11-15
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also be felt, those costs were not included. Also, no consideration was given to potential emission
controls to address acid rain, ozone non-attainment, or global climate change.
E. Estimated Costs of Environmental Initiatives
The incremental compliance costs associated with the potential environmental initiatives
considered in this assessment could be substantial. As shown in Table 11-9, potential industry
compliance costs could range from $15 to $79 billion initially, and from two to seven billion dollars per
year thereafter, assuming 1985 levels of oil and gas drilling and development. This assumption may lead
to an overestimate of true industry costs, however, because the incremental costs could result in reduced
industry activity, as will be discussed in more detail in Section IV.
Under the high scenario, the potential initial capital cost impacts of changes in RCRA, SDWA, and
CAA are approximately the same order of magnitude at over $20 billion. The initial capital costs
associated with CWA are somewhat lower, but annual costs are similar to those associated with initiatives
under the other statutes, ranging from one to three billion dollars per year.
A number of environmental initiatives were not considered as part of this analysis. These
initiatives were not considered because incremental compliance costs associated with them were not
available, or the models used in this assessment could not assess their impact. In addition, this analysis
only considered potential requirements applicable to exploration and production operations. It did not
consider initiatives that may affect other segments of the U.S. petroleum industry. These initiatives could
further increase the costs that the domestic petroleum industry must incur to comply with potential
environmental regulations.
06K00135.RPT Page 11-16
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ESTIMATES OF TOTAL INDUSTRY COSTS OF COMPLIANCE ASSOCIATED
WITH THE REGULATORY INITIATIVES CONSIDERED IN THIS ANALYSIS
(Millions of 1988 Dollars)
Regulatory Initiative
Low
Medium
High
RCRA
Management and Disposal
of Drilling Wastes (1)
Disposal of Associated
Wastes in Central Facility (2)
Replace Emergency Pits
With Tanks (3)
Replace Workover Pits
With Tanks (4)
Organic Toxicity
Characteristic (5)
Corrective Action (6)
Initial Annual Initial
1,222
111
268 -- 268
95 - 95
,330 360 1,330
1,598 - 12.781
Annual Initial Annual
1,276 -- 1,400
1,345 -- 1,491
7,167
95
360 1,330 360
14,407
Subtotal
5,292 1,693 14,475
2,981 22,999 3,252
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TABLE 11-9 (Continued)
ESTIMATES OF TOTAL INDUSTRY COSTS OF COMPLIANCE ASSOCIATED
WITH THE REGULATORY INITIATIVES CONSIDERED IN THIS ANALYSIS
(Millions of 1988 Dollars)
Regulatory Initiative
Low
Medium
Initial
Annual
Initial
Annual
High
Initial
Annual
SDWA
MIT Part 1 (7)
MIT Part 2 (7)
NIR Fluid (8)
Area of Review (8)
Corrective Action (8)
Construction Requirements (8)
Subtotal
--
77
--
--
--
--
--
--
2,294
5,525
958
9 232
239
191
4,307
14,271
2,873
44
294
191
--
--
—
77
8,776
439
21,683
529
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Page II-1B
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TABLE 11-9 (Continued)
ESTIMATES OF TOTAL INDUSTRY COSTS OF COMPLIANCE ASSOCIATED
WITH THE REGULATORY INITIATIVES CONSIDERED IN THIS ANALYSIS
(Millions of 1988 Dollars)
Regulatory Initiative
Low
Medium
Initial
Annual
Initial
Annual
High
Initial
Annual
CWA
Offshore Muds and Cuttings (9)
Offshore Produced Water (10)
Stormwater Discharges (11)
Above Ground Storage Tanks (12)
Ban of Onshore Surface (13)
Discharge of Produced Brines
76
2,564
2,564
864
1,868
289
260
362
385
1,641
2,564
4,318
•L868
362
Subtotal
2,564
76
5,296
911
8,750
2,388
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TABLE 11-9 (Continued)
ESTIMATES OF TOTAL INDUSTRY COSTS OF COMPLIANCE ASSOCIATED
WITH THE REGULATORY INITIATIVES CONSIDERED IN THIS ANALYSIS
(Millions of 1988 Dollars)
Regulatory Initiative
CAA
Onshore Emissions (14)
Offshore Emissions (1 5)
Subtotal
Low Medium
Initial Annual Initial
7,538 247 7,538
n.e.
7,538 247 7,538
Annual
247
42
289
Hidh
Initial
24,992
850
25,842
Annual
247
800
1,047
TOTAL
n.e. = not estimated
15,394 2,093 36,085
4,620 79,274 7,216
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TABLE 11-9 (Continued)
ESTIMATES OF TOTAL INDUSTRY COSTS OF COMPLIANCE ASSOCIATED
WITH THE REGULATORY INITIATIVES CONSIDERED IN THIS ANALYSIS
(Millions of Dollars)
Footnotes
1. Assumes onshore well drilling at 1985 levels; 69,906 total wells; of which, an estimated 50,629 were oil wells (successful and dry). (API, 1987)
2. Assumes 884,581 onshore producing wells; 642,299 of which were onshore oil wells (well count in 1985). (IPAA, 1989)
3. Assumes that there are 219,300 tank batteries, 12,848 EOR projects, and 39,854 SWD wells in the U.S. (as of 1985).
4. Assumes 6,361 working rigs, amortized over 8 years at a 10% discount rate.
5. Assumes 219,300 production sites, 12,848 EOR sites, and 39,854 SWD wells, at capital costs of $4,890/site and operating costs of $41,324/site.
Does not consider the costs for new wells.
6. Based on number of EOR facilities, tank batteries, and SWD wells shown in footnote 5.
7. Assumes, where appropriate, an average three year testing frequency (based on corrosivity), an average 5,000 foot depth to the injection zone,
and 172,183 Class II injectors (based on Gruy, 1989).
8. Assumes 172,183 existing Class II injectors (based on Gruy, 1989), and an average three-year testing frequency.
9. Assumes 978 offshore wells per year (EPA's estimate of wells drilled per year, 53 FR 41356; Oct. 21, 1988).
10. Medium Scenario uses Walk, Haydel's (1984) estimate of compliance, adjusting for Lewin's (1986) modification for the number of platforms affected.
High Scenario adjusts Medium Scenario costs, accounting for the ratio of total offshore platforms affected versus those within the shallow water
demarcation.
11. Assumes 884,581 existing onshore producers and 172,183 existing injectors (from 1985 data) applied to the 55% of facilities that are within one
mile of navigable waters.
12. Assumes 884,581 existing onshore producers in the U.S.
13. Assumes a 7% increase in operating injection wells in the U.S., where 50% of the new wells are converted producers (at a cost of $35,000 per
well), and the remaining required injectors are drilled (at a cost of $275,000 per well).
14. Assuming 617,852 oil wells operating (as of 1985).
15. Assumes MMS's estimated compliance costs for the Medium Scenario. For the High Scenario, assumes costs from Table V-3 and the following
assumptions (based on 1985 data): 391 offshore exploration wells drilled in Gulf of Mexico; 692 offshore development wells drilled in Gulf of
Mexico; 214 offshore platforms installed in Gulf of Mexico; approximately 4,300 offshore platforms operating in Gulf of Mexico; approximately
12,000 offshore wells producing in Gulf of Mexico.
06K00127.TBL Page 11-21
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III. SUMMARY OF ANALYTICAL APPROACH
After currently proved reserves are produced by conventional (primary and secondary) recovery
methods, nearly two-thirds of the known U.S. oil resource (over 300 billion barrels) will remain unrecovered
(Figure 111-1). Nearly 100 billion barrels are displaceable by water but are left in the reservoir at the end
of conventional recovery operations. Another 242 billion barrels are not displaceable by water; the
recovery of this resource depends on the application of tertiary recover processes. Although not all of
this remaining resource in place could ever be recovered, it represents a substantial target for future
advanced recovery operations. DOE estimates that approximately 76 billion barrels of this resource could
be recovered at a price of $32/Bbl, given some advances in extraction technologies over the next 15
years.
However, for the most part, the future recovery of this resource presupposes that existing wells,
producing reservoirs, and the existing infrastructure will be available, and that operators can retain the
rights to produce oil from specific reservoirs. Once these reservoirs are abandoned, the resource
associated with the reservoirs becomes essentially inaccessible to future development within the range
of prices generally considered likely over the next 15 to 20 years, even with further improvements in
recovery technologies.
The analysis of the recovery potential of the known (already discovered) oil resource is based on
recovery performance and economic modeling using resource data of critical properties for major U.S.
crude oil reservoirs. The analysis uses the Tertiary Oil Recovery Information System (TORIS), developed
and maintained at DOE's Bartlesville Project Office. TORIS was originally developed by the National
Petroleum Council (NPC) in their 1984 assessment of enhanced oil recovery (NPC, 1984). DOE has
expanded the capabilities of TORIS to include the analysis of the recovery potential of the unrecovered
mobile oil (UMO) resource; i.e., oil that may be recovered by intensive infill drilling and waterflooding; and
the analysis of the continued conventional production from producing crude oil reservoirs.
TORIS utilizes comprehensive oil reservoir data bases and detailed engineering and economic
evaluation methodologies, considering data for individual reservoirs to predict crude oil recovery,
investment and operating costs, and ultimately, project economics. The system evaluates recovery and
costs associated with the development of specific crude oil reservoirs, based on the geographic location,
depth, reservoir properties, and operating conditions of the reservoir. Analyses can be conducted for
various recovery technologies and crude oil prices.
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Figure 111-1
Over 300 Billion Barrels of Known U.S. Oil Resources Will
Remain After Conventional Production (As of 12/31/87)
Economically Recoverable
at $32/Bbl with
Advanced Technology
Remaining Oil-In-Place
341 Billion Barrrels
(67%)
Unrecoverable
69 Billion Barrels
Cumulative Production
145 Billion Barrels
(28%)
Recoverable
30 Billion Barrels
Mobile Oil
99 Billion Barrels
(20%)
Recoverable
46 Billion Barrels
Proved Reserves
27 Billion Barrels
(5%)
Immobile Oil
242 Billion Barrels
(47%)
,196 Billion Barrels'
Conventional Recovery
172 Billion Barrels
(33%)
Source: DOE, 1989
513 Billion Barrels
Original Oil-In-Place
06K00135.RPT
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The analysis of the recovery potential of the U.S. crude oil resource remaining to be recovered
— the undiscovered resource — uses models also developed by DOE as part of its Replacement Costs
of Crude Oil (REPCO) Supply Analysis System. This system is designed to determine the 'replacement
cost' of developing U.S. undiscovered crude oil resources. The replacement cost is defined as the
minimum levelized oil price that a project must receive to recover all costs and achieve a reasonable
return on capital. This fully risked' cost assumes one theoretical operator finds and develops a crude
oil field, and includes the allocated cost for all exploratory wells and associated exploratory and
developmental dry holes.
The REPCO system characterizes the undiscovered resource uniquely for numerous, distinct
crude oil supply regions, disaggregating the resource into characteristic fields. Appropriate recovery
technologies are selected for the characteristic fields in each region, and the recovery potential and
economic viability of each characteristic field is determined based on the region-specific and reservoir
characteristics describing it. Similar to the models used for examining the known crude oil resource,
analyses can be performed considering a variety of recovery technologies and crude oil prices.
An important feature of the engineering costing and field development components of both the
TORIS and REPCO systems is that costs are determined as a function of price and other market
(infrastructural) factors. Analyses of historical oil field cost data have demonstrated conclusively that these
costs are intimately related to crude oil prices (Kuuskraa and others, 1987). Algorithms relating costs to
oil prices are incorporated into the TORIS and REPCO costing analysis systems.
For purposes of this study, both the TORIS and REPCO systems were enhanced to incorporate
the addition of incremental costs associated with potential environmental regulations and to provide output
in a form that allows the results for the different resource categories considered to be presented on a
consistent basis. Analyses were performed for each regulatory scenario, with the specific, incremental
environmental compliance costs associated with the scenario considered. The results for each regulatory
scenario were then compared to those obtained under the reference case, in order to estimate the energy
and economic impacts associated with each regulatory scenario.
For some categories of crude oil resources, analyses were performed assuming two levels of
technology, implemented and advanced. The implemented technology case assumes recovery practices
currently available for implementation in the field. The advanced technology case assumes improvements
in extraction technologies and reductions in extraction costs will result from successful research and
development within a reasonable period of time, and will be widely applied in the field.
06K00135.RPT Page III-3
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The analytical approach used for assessing the impacts of each resource category are
summarized below. A more detailed discussion of the characteristics of each resource category and the
analytical approach used to assess the energy and economic impacts of increased environmental
regulations are presented in Appendix B.
A. Resources Considered
1. Current Production
DOE, in a recent study entitled.Abandonment Rates of the Known Domestic Oil Resource (DOE,
1989), concluded that the U.S. will inevitably continue to face increasing resource abandonments, with
future crude oil prices determining the level and pace of these abandonments. This analysis served as
the basis for this assessment of the impact of increased costs of environmental regulations on the
continued production from currently producing U.S. oil reservoirs.
For purposes of this study, the previous analysis (DOE, 1990) was updated to incorporate more
recent reservoir-specific production data, additional reservoirs, and modeling enhancements. A
description of these updates is presented in Appendix D to this report. Nine major oil producing states
were analyzed: California, Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and
Wyoming. These states were chosen for the availability, magnitude, and comprehensiveness of resource
data, production data, and well counts; because the states represent various stages of oil resource
maturity; and because the states account for 83% of the original-oil-in-place and 75% of the remaining
oil in place in the Lower-48 states (Table 111-1).
The data contained in the TORIS data base for the reservoirs in the targeted nine states allowed
for production decline curve analyses of each reservoir. Exponential decline functions were developed
for each reservoir based on historical production data, beginning in the year of highest reported
production. The historical exponential decline curves that demonstrated the best fit with the actual data
were selected and used to project future production.
In the reference case, the analysis assumes that future production in each reservoir continues at
declining rates until the economic limit of production is reached. The economic limit of production is
defined as the minimum production at which revenues from production meet or exceed production costs
at a given oil price. This projection assumes that historical activities to maintain and/or increase
production in the reservoir, as implied by the historical decline curve, are continued in the future.
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TABLE 111-1
ORIGINAL AND REMAINING OIL RESOURCES IN NINE STATES
ANALYZED FOR RESOURCE ABANDONMENT POTENTIAL
(Billion Barrels)
State
California
Colorado
Illinois
Kansas
Louisiana
New Mexico
Oklahoma
Texas
Wyoming
Original
Oil-in-Place
84.7
4.3
9.1
16.3
41.2
14.9
39.0
154.7
16.7
Cumulative
Production
to date (12/31/87)
20.8
1.4
3.2
5.3
22.7
5.2
12.7
57.4
5.1
Remaining
Reserves
5.8
0.2
0.1
0.4
2.6
0.7
0.9
7.9
1.0
Remaining
Oil-in-Place
58.1
2.7
5.8
10.6
15.9
9.0
25.4
89.4
10.6
Total, 9 States 380.9
Other States 79.1
Lower-48 States 460.0
133.8
3.2
137.0
19.6
1.7
21.3
227.5
74.2
301.7
Source: DOE, 1989
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The economic limit determined in the reference case establishes the productive life of the reservoir
under current operating conditions and the assumed constant oil price. Baseline costs were established
as those currently in the TORIS system, which were based on regional average costs reported by API
(API, 1989) and the Energy Information Administration (EIA, 1987), adjusted to 1988 conditions for the
depth and geographic location of each reservoir. Current environmental regulations were assumed to be
included in these baseline costs.
Oil prices, incremental investment costs, and production costs are the major independent
variables considered by TORIS in this analysis. As oil prices increase, the economic limit is lowered and
the productive life of a reservoir extended. Similarly, as production costs are increased (e.g., due to
increased costs of compliance with environmental regulations), the economic limit is raised and the
productive life of a reservoir shortened.
The impacts of the incremental costs associated with the regulatory scenarios considered were
estimated by performing a conventional discounted cash flow analysis for each reservoir over its
productive life, assuming that the project must incur the incremental investment and operating costs
associated with the specified regulatory scenario. The analysis was performed from the perspective of
the operator of the reservoir, who would conduct a financial analysis examining the impact of the
incremental costs of compliance over the productive life of the reservoir, at the time the regulations go
into effect. At this point in time, each operator would make a decision whether to continue with the
production, or, if the incremental costs were too high to justify continued economic viability, begin to shut
in production. As a result, a considerable portion of current production could be abandoned immediately
after the implementation of the new regulations.
As well abandonments erode access to the remaining resource, fewer future recovery projects,
particularly those utilizing advanced recovery technologies, will be economically justifiable. These projects
will not recover sufficient oil to justify both the high start up costs associated with advanced recovery
technologies and the costs of redrilling new wells or re-entering old wells in abandoned reservoirs. As
the costs of compliance with environmental regulations increase, the costs of operating marginally
economic wells in producing reservoirs will increase, resulting in the accelerated abandonment of these
wells. The impact of the increased compliance costs are consequently two-fold. First, reserves are lost
because of the earlier abandonment of these wells. Second, access to the remaining resources
associated with these abandoned wells will be lost, and hence, the potential future production from
advanced recovery technologies in reservoirs containing these wells will be economically prohibitive.
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This analysis provided a high side, or leading indicator, of resource abandonment. The analysis
of production was performed reservoir-wide, based on average reservoir properties, production, and well
counts. The analysis was based on the average well in each reservoir. The abandonment of the average
well precedes the abandonment of better-than-average wells that would continue to produce even though
the TORIS analyses would predict reservoir abandonment. However, some below average wells would
have already been abandoned before the average well. Given current economic conditions, it is likely that
most of these below average wells have already been abandoned.
On the other hand, no attempt was made to explicitly account for the reservoir data not
considered in TORIS or included in this analysis. The reported results were based on only those
reservoirs actually considered, and were not extrapolated to represent the entire U.S. crude oil resource
base. If the entire U.S. resource base was considered, the volume of resource abandoned would be
greater than that estimated in this analysis.
2. Unrecovered Mobile Oil In Known Oil Fields
While TORIS was originally developed to evaluate the potential of enhanced oil recovery (NPC,
1984), the system structure also proved to be well suited for analyzing the recovery potential of
unrecovered mobile oil (UMO). Unrecovered mobile oil is left in the reservoir because of reservoir
heterogeneity or mobility differences that cause injected water to finger through or around the oil, or
because it exists in isolated compartments not in communication with wells at existing pattern spacings.
As a result, portions of the reservoir are left at near original oil saturation. Producing more oil requires
additional wells drilled at closer spacing, in order to improve contact with the uncontacted and/or unswept
oil and improve waterflood sweep and pattern conformance. Additional improvements in recovery can
be achieved with the application of polymers to improve mobility control or gel treatments to reduce
permeability differences between reservoir layers. In many reservoirs, the greatest recovery efficiency is
obtained with the combined application of infill drilling and these improved secondary recovery
techniques.
The analysis of the economic impact of environmental regulations on the UMO resource was
based on analyses of nearly 700 crude oil reservoirs in Texas, Oklahoma, and New Mexico. The
reservoirs are estimated to contain almost 112 billion barrels of original oil in place, representing about
one-fourth of the total resource in place in the U.S.
In this analysis, three recovery processes for improving the recovery of mobile oil were
considered: infill drilling, permeability modification treatments (which directs the flow of injected water to
06K00135.RPT Page III-7
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lower-permeability, less-swept reservoir zones), and polymer-augmented waterilooding (where polymers
are added to the injected water to obtain a more favorable water-oil mobility ratio and improve recovery
efficiency).
Two technology cases were assumed in the evaluation of UMO recovery potential. The cases
were based on two different levels of geologic understanding and using two classes of polymers. The
first level, corresponding to technology that can currently be implemented in the field, reflects limited
geologic understanding of reservoir heterogeneity and the technical shortcomings of currently available
polymers. This implemented technology scenario assumed a blanket or uniform approach to infill
development, where a single one-half reduction in reservoir-wide well spacing, or one drilldown, is
assumed. This scenario is based on the assumption that the operator would be unwilling to assume the
risk of further infill development without the acquisition of additional geologic information on reservoir
heterogeneity, and would therefore only pursue a 'one-drilldown-at-a-time' approach.
The second level, corresponding to an advanced technology case, assumes a significantly
improved understanding of reservoir heterogeneity and improvements in advanced waterflooding
techniques that increase the applicability and productivity of these processes, including the development
of improved polymers available for field application in higher temperature and higher salinity settings. This
scenario assumes that sufficient geologic data would exist to characterize the reservoir and delineate it
into distinct segments, or facies, with reservoir parameters and heterogeneity relationships developed
independently for each segment. This scenario assumes the availability of more detailed geologic
information, so the operator can make a more informed assessment and be willing to undertake a
geologically targeted infill drilling program in each facies to the minimum spacing economically justifiable.
3. Enhanced Oil Recovery in Known Fields
Enhanced oil recovery (EOR), for purposes of this study, is defined as the incremental recovery
of oil in a reservoir over that produced by conventional primary and secondary recovery methods. Primary
recovery of crude oil relies on the natural energy of the reservoir to drive oil through the reservoir to
production wells. As this energy dissipates as a reservoir is depleted, secondary recovery methods can
be undertaken which introduce additional energy to a reservoir through the injection of water or gas under
pressure.
Tertiary or enhanced oil recovery methods involve the injection of fluids with specific properties
designed to improve oil recovery efficiency. EOR methods are effective in displacing waterflood residual
oil which is trapped in the reservoir pore spaces by capillary, viscous, and surface-tension forces. These
06K00135.RPT Page III-8
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recovery methods include miscible gas injection (typically carbon dioxide), immiscible gas injection
(typically nitrogen or CO2), chemical flooding (using surfactants and alkalines to modify rock-fluid
interactions) and thermal recovery, which relies on the introduction of thermal energy, (most commonly
in the form of injecting steam or by injecting air and starting a combustion front in the reservoir), to reduce
oil viscosity and increase recovery.
The analysis of EOR potential in this study also uses TORIS. However, the assessment of EOR
potential used the entire TORIS reservoir data base, consisting of over 3,700 reservoirs corresponding to
approximately 70% of the U.S. crude oil resource in place.
Two levels of EOR technology were evaluated. The first level, the implemented technology case,
represents technology currently in place and proven in successful field tests. The second level, the
advanced technology case, assumes technological improvements resulting from successful research and
development, improving EOR efficiencies, and expanding the resource applicable to EOR processes.
4. Undiscovered Crude Oil Resources
Undiscovered crude oil resources, as defined by the U.S. Geological Survey (USGS) and the
Minerals Management Service (MMS), are those resources judged to exist in geologically promising but
unexplored or undrilled areas. The existence of these resources are based on broad geologic knowledge
and theory, in settings outside of known accumulations of hydrocarbons. This resource includes
undiscovered fields and pools within known fields that occur as unrelated accumulations controlled by
distinctly separate structural features or stratigraphic conditions. For purposes of this analysis, the
economic feasibility of undiscovered resources was determined assuming that the production of crude
oil from a discovery must support all costs associated with its development. The undiscovered resource
base evaluated as part of this study was based on the most recent assessment of the U.S. Department
of Interior (DOI, 1989).
REPCO is an analytical model which utilizes the USGS and MMS estimates of recoverable crude
oil resources, and rigorously assesses the economic feasibility and recovery potential of these reservoirs.
Analysis of the Lower-48 onshore resources is performed using a finding rate approach, where resources
are developed based on historical relationships between drilling effort and reserve discoveries. Analysis
of the Lower-48 offshore and Alaska resources uses a field size distribution approach, where the model
distributes the resource yet to be recovered into prospects by field size. Appropriate exploration and
production technologies are chosen for each resource and region considered in the analysis.
Relationships between field size and well productivity, based on historical production data and/or analog
06K00135.RPT Page III-9
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regions, are used to determine the number of wells required, anticipated production rates, and
consequently, the costs associated with finding, developing, and producing undiscovered fields. Full
costs of exploration and development, including the costs associated with all geological and geophysical
work, lease bonuses, exploration and development wells, and all anticipated dry holes are considered in
the economic evaluation.
The analysis represents the entire U.S undiscovered crude oil resource. No exclusions for land
set aside from leasing or currently under leasing moratoria, such as that in the Arctic National Wildlife
Refuge (ANWR) or certain areas off the coast of California and Florida, were considered.
In the analysis, resources believed to exist in the Lower-48 onshore, Lower-48 offshore, and Alaska
(onshore and offshore) are analyzed separately. In addition, this analysis only considers the conventional
primary and secondary recovery of the undiscovered crude oil resource. The recovery potential of
intensive infill drilling or EOR in these undiscovered fields was not evaluated, nor was the potential
associated with advanced recovery technologies.
5. General Assessment Procedure
The analysis considers the economic recovery potential of both the known and the undiscovered
crude oil resource under a reference case and under the three environmental compliance scenarios.
Results for four constant crude oil prices (in 1988 dollars) are presented - $16, $20, $24, and $32 per
barrel (/Bbl). Oil prices of $16, $20, and $24/Bbl were selected to represent most forecasters' expected
range of world crude oil prices over the next decade. The $32/Bbl oil price was selected in order to
evaluate the impact of environmental initiatives if crude oil prices approach their historic high values.
Baseline costs embedded in the economic analysis models are based on region-specific,
engineering-based costs of typical crude oil exploration, development, and production operations for the
recovery processes and resource categories considered. These baseline costs represent current costs,
and include the costs incurred to comply with current state and federal regulations. The incremental costs
associated with the environmental initiatives were developed to represent requirements beyond those
currently established by state and federal regulations, but that could potentially be included in future
statutory or regulatory revisions.
The analyses were performed for each scenario, incorporating the specific, incremental
environmental compliance costs associated with each scenario. Incremental compliance costs were
06K00135.RFT Page 111-10
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based on the specific environmental initiatives discussed in Chapter II and in Appendix A. Where
necessary, these costs were converted to units appropriate for inclusion into the various models used.
The results for each scenario were then compared to that obtained under the reference case, in
order to estimate the energy and economic impacts associated with that scenario. These results are
discussed in the following chapter.
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IV. CUMULATIVE IMPACT OF ENVIRONMENTAL
INITIATIVES - DISCUSSION OF RESULTS
A. Introduction
The cumulative energy and economic impacts of the environmental initiatives considered are
presented in terms of the following for the specific resource categories and crude oil prices analyzed:
• Economically recoverable resources (reserves) lost and/or production
abandoned as a result of the imposition of the incremental regulations.
• State and federal revenues (from federal royalty payments, federal
corporate income taxes, state corporate income taxes and state
severance and production taxes) lost as a result of the incremental
regulations.
• Total investment and operating expenditures operators could incur as a
result of the incremental regulations accounting for reserves which
become uneconomic as a result.
The increased costs of environmental regulations can cause some reserves recoverable prior to
the imposition of the additional regulations to become uneconomic to develop and produce once the
regulations are in place. Incremental compliance costs are evaluated as they effect the economic viability
of crude oil projects over their productive life. Consequently, both incremental investment and annual
operating costs are considered.
The loss in recoverable reserves could result in a loss in state and federal revenues that would
have been collected from production and income taxes associated with foregone projects. Even where
increased costs of regulation are not sufficient to make some reserves uneconomic to develop, the
increased costs will affect project cash flows, reduce project income, and therefore, reduce corporate
income taxes collected by state and federal governments. For purposes of this analysis, only public
sector revenues collected directly from taxes and royalties on oil production are considered; no secondary
revenue effects, such as those associated with taxes on incomes of oil industry employees, were included
in this analysis.
In Chapter II of this report, estimates of total industry compliance costs were presented which
assumed 1985 levels of domestic industry activity. That is, incremental unit compliance costs were
multiplied by the number of units (for most cases, production and injection wells in 1985) to determine
total industry costs of compliance. These estimates assumed a specified level of industry activity which
06KD0135.RFT Page |V-1
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would remain the same for all environmental scenarios considered. The imposition of the regulations was
assumed, for purposes of this calculation, to not affect industry activity. In reality, however, some
previously viable projects will no longer be economic to pursue due to increased environmental
regulations. Consequently, these projects will not be developed, and the compliance costs associated
with pursuing these projects would not be incurred. Therefore, the amount industry expends to develop
crude oil reserves may decrease as a result of the new regulations. Estimates of industry compliance
costs that assume an unchanging level of activity probably overestimate the actual industry costs of
compliance. These estimates fail to account for lost or deferred domestic reserve additions and
production, state and federal revenues, and economic activity that industry expenditures prior to the new
regulations may have stimulated.
The results of this analysis are discussed below for each of the resource categories considered.
B. Current Production
Evaluation of the impact of environmental regulatory initiatives on the future, conventional
production potential from existing projects was conducted using a decline curve analysis. The method
was based on the analysis of nearly 800 reservoirs in nine oil-producing states (California, Colorado,
Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and Wyoming), representing 230 billion barrels
of remaining oil in place (Table 111-1). The analytical method is based on detailed information on the oil
production history of these reservoirs, along with reservoir data such as depth, oil in place, oil gravity, and
gas-oil ratios for each reservoir, as discussed in more detail in Chapter III and in Appendix B.
1. Analysis of Potential Under Current Regulations
In the early 1970's crude oil production in the nine states peaked at about 4.6 million barrels per
day, (MMB/D), as shown in Figure IV-1. By 1990, production in these states had dropped to 2.2 MMB/D,
a 55% decrease in production over the 20-year time period. Figure IV-1 was developed from historical
reservoir-by-reservoir production data through 1989 (the most recent date comprehensive, reservoir-
specific production data were available). TORIS predictions of reservoir-specific production were used
over the 1990 through 2015 time period. In this analysis, 1990 was assumed to be the year the
environmental initiatives under each scenario are implemented.
Figure IV-1 shows that if no new reserves are added, production in these nine states are forecast
to continue to decline rapidly, regardless of oil price. The production forecast demonstrates that many
operations are currently on the verge of abandonment. For example, if prices remain at approximately
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Figure IV-1
Forecast of Conventional Crude Oil Production
in the Nine States Analyzed
Reference Case
TORIS Projections
$32/Bbl
$24/Bbl
$20/Bbl
$16/Bbl
1970 1975 1980 1985 1990 1995
Year
2000
2005
2010
2015
06K00135.RPT
Page IV-3
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$20/Bbl, production in these states will decrease to about 1.44 MMB/D by 1995, and to about 920,000
barrel per day by the year 2000. If oil prices drop to and remain at around $16/Bbl, production in these
states will drop to about 1.21 MMB/D by 1995, and to about 860,000 barrels per day by the year 2000,
not much different than that reached at $20/Bbl. If prices rise to $32/Bbl, however, the rate of production
decline would be somewhat slower; by 1995, production will drop to about 1.58 MMB/D and by the year
2000, production in these states will amount to about 1.14 MMB/D. These projections are summarized
in Table IV-1.
If oil prices remain at about $20/Bbl, approximately 44% of the domestic resource is predicted to
be abandoned by 1990, 55% would be abandoned by 1995, and 71% would be abandoned by the year
2000 (Figure IV-2 and Table IV-1). If prices drop to and remain around $16/Bbl, approximately 52% of
the domestic resource is predicted to be abandoned by 1990, 65% would be abandoned by 1995, and
75% would be abandoned by the year 2000. However, if prices rise to $32/Bbl, resource abandonments
are forecast to be about 30% in 1990, 43% of these resources would be abandoned by 1995, and 55%
would be abandoned by the year 2000.
The results of the reference case analyses show that, regardless of the oil price track achieved,
production from existing fields will decline rapidly. Without major new reserve additions, most of the
producing domestic crude oil resource will be abandoned by the end of the decade. This abandoned
resource will essentially become unavailable for the application of advanced recovery technologies that
are currently unproven or uneconomic. Crude oil prices will only increase or decrease the rate of
resource abandonments somewhat; declining production and a rapid rate of abandonment, without new
reserve additions, is inevitable.
2. Impact of Initiatives
The imposition of additional environmental regulations on current oil producers could impact the
economic viability of these operations, with the extent and timing of regulations determining the magnitude
of this impact. For example, if additional environmental regulations are instituted, operators would have
a specified time period within which they must comply. To account for uncertainties concerning the length
of this compliance period, two additional scenarios were developed for the current production analysis.
The first scenario assumed operators would have five years to comply with new regulations. Investments
required to bring operations into compliance were assumed to be evenly spread over the five-year period.
The second scenario represents the extreme case in that it assumed operators have only one year to
comply with new regulations, and that all investments must be incurred in the year the new environmental
regulations go into effect.
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TABLE IV-1
FORECAST CRUDE OIL PRODUCTION AND PERCENTAGE RESOURCE
ABANDONMENTS IN NINE-STATES WITHOUT RESERVE ADDITIONS
Reference Case
Year
1990
1995
2000
2005
2010
2015
$16;
Prod
(MMB/D)
1.93
1.21
0.86
0.55
0.45
0.32
'Bbl
Abd
(%)
52
65
75
82
85
87
$20/
Prod
(MMB/D)
2.03
1.44
0.92
0.60
0.48
0.38
Bbl
Abd
(%)
44
55
71
78
82
83
$24;
Prod
(MMB/D)
2.09
1.46
0.97
0.64
0.51
0.41
'Bbl
Abd
(%)
40
52
67
75
79
82
$32
Prod
(MMB/D)
2.19
1.58
1.14
0.72
0.59
0.50
;/Bbl
Abd
(%)
30
43
55
67
71
74
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Figure IV-2
Impact of Environmental Regulations on Abandonment of the
Crude Oil Resource in the Nine States Analyzed (Reference Case)
100%
90%
c 80%
o
•
70%
8
I 50%
o
c 40%
-------
The results showed that the impact of the various regulatory scenarios would be slightly more
rapid if only a one-year compliance period is implemented. However, in the long term (by the year 2000),
the impact on the resource in the nine states considered would be about the same regardless of whether
operators had one or five years within which they must comply. Therefore, to simply this presentation,
only the results from the five-year compliance period are presented.
The analysis of production lost from resource abandonment shows that for all prices considered,
crude oil production by the year 2000 in the nine states analyzed will drop to about the same level
regardless of the imposition of the regulatory initiatives. However, under all prices considered, the
imposition of additional environmental regulations could rapidly accelerate the pace of declining
production. This is shown in Table IV-2 and Figures IV-3 to IV-6, for the various oil prices considered.
Since the impact of these regulations on the future production from current operations is
determined at the time the proposed regulations go into effect, most of the impact would be felt
immediately after the regulations are implemented. For example, at an oil price of $20/Bbl, by 1995,
production in the nine states would drop by about 318,000 B/D in the medium scenario (a 22% decrease
from that in the reference case). Production in 1995 would drop by 450,000 B/D in the high scenario,
compared to the reference (Figure IV-4 and Table IV-2), a 31% decrease. By the year 2000, production
under the medium scenario would decrease 110,000 more than the reference case, a 12% difference.
In the high scenario, approximately 190,000 B/D of production would be lost by 2000, a decrease of 21%
compared to the reference case.
The volume of production over the 1990 through 2000 time period that would be foregone due
to increased environmental regulations could amount to about 100 MMB in the low scenario, 1,200 MMB
in the medium scenario, and as much as 1,800 MMB in the high scenario.
b. Resources Abandoned. Although rapidly declining production would have detrimental
effects, the more important impact of these regulatory initiatives on current production would be the
resources becoming unavailable for future application of advanced recovery technologies. The impacts
of the three scenarios on the abandonment of crude oil resources in the nine states are shown in Table
IV-2 and Figures IV-7 through IV-10 for the four oil prices considered. At an oil price of $20/Bbl (Figure
IV-8), 2% more of the resource in place in the nine states would be immediately abandoned (in 1990)
under the low scenario than that abandoned in the reference case. Under the medium scenario, 23%
more of the resource in place would be abandoned immediately, while an additional 30% of the resource
would be immediately abandoned under the high scenario, when compared to the reference case. The
06K00135.RPT Page IV-7
-------
TABLE IV-2
IMPACT OF ENVIRONMENTAL REGULATIONS ON CURRENT
CRUDE OIL PRODUCTION IN NINE STATES ANALYZED
1,213
864
52
75
1,210 (<1%)
848 (2%)
55
76
997 (18%)
712 (18%)
73
83
913 (25%)
660 (24%)
78
85
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Production (MBbl/day)
1995
2000
Abandonments (% of OOIP)
1990
2000
$20/Bbl
Production (MBbl/day)
1995
2000
Abandonments (% of OOIP)
1990
2000
$24/Bbl
Production (MBbl/day)
1995 1,464 1,452(1%) 1,272(13%) 1,108(24%)
2000 991 964(1%) 869(11%) 842(13%)
Abandonments (% of OOIP)
1990 40 41 57 69
2000 67 68 73 77
Production (MBbl/day)
1995 1,583 1,572(1%) 1,413(11%) 1,274(20%)
2000 1,142 1,132(1%) 995(13%) 899(21%)
Abandonments (% of OOIP)
1"0 30 32 50 59
2000 55 56 66 71
* Numbers in parenthesis are the percentage reduction compared to the reference case.
1,436
917
44
71
1,427 (1%)
904 (1%)
46
72
1,118(22%)
811 (12%)
67
79
989 (31%)
723 (21%)
74
82
06K00127.TBL Page IV-8
-------
Q
s
(0
m
o
o
'•5
I
Figure IV-3
Impact of Proposed Environmental Regulations on Crude Oil
Production in the Nine States Analyzed ($16/Bbl Oil Price)
1970
2010
2015
Reference Case
Low Scenario
Medium Scenario
High Scenario
06K00135.RPT
Page IV-9
-------
Figure IV-4
Impact of Proposed Environmental Regulations on Crude Oil
Production in the Nine States Analyzed ($20/Bbl Oil Price)
•s 3
CO
CD
O
Q. 1
Historical
TORIS Projections
Y'-...
1970 1975
1980 1985
1990 1995
Year
2000 2005 2010 2015
Reference Case Low Scenario
Medium Scenario High Scenario
06K00135.RPT
Page A/-1O
-------
Figure IV-5
Impact of Proposed Environmental Regulations on Crude Oil
Production in the Nine States Analyzed ($24/Bbl Oil Price)
O
-------
Figure IV-6
Impact of Proposed Environmental Regulations on Crude Oil
Production in the Nine States Analyzed ($34/Bbl Oil Price)
(0
1 3
2
§
S
1 ,
Historical
TORIS Projections
1970
1975
1980
1985 1990 1995
Year
2000
2005
2010
2015
Reference Case
Low Scenario
Medium Scenario
High Scenario
O6KO0135.RPT
Page IV-12
-------
Figure IV-7
Impact of Environmental Regulations on Abandonment of the
Crude Oil Resource in the Nine States Analyzed ($16/Bbl Oil Price)
100%
90%
"8 80%
o
?
£ 70%
60%
| 50%
"5
I 40%
o
Q_
30%
20%
1990 1995
Reference Case
2000 2005
Year
Low Scenario Medium Scenario
2010
High Scenario
2015
06K00135.RPT
Page IV-13
-------
Figure IV-8
Impact of Environmental Regulations on Abandonment of the
Crude Oil Resource in the Nine States Analyzed ($20/Bbl Oil Price)
100%
20% "-1
1990
1995
2000
2005
2010
2015
Year
Reference Case Low Scenario Medium Scenario High Scenario
06K00135.RPT
Page IV-14
-------
Figure IV-9
Impact of Environmental Regulations on Abandonment of the
Crude Oil Resource in the Nine States Analyzed ($24/Bbl Oil Price)
100%
90%
80%
70%
o
T3
o 60%
CO
-------
Figure IV-10
Impact of Environmental Regulations on Abandonment of the
Crude Oil Resource in the Nine States Analyzed ($34/Bbl Oil Price)
o
TO
100%
90%
80%
70%
3 60%
cc
50%
c 40%
o
o>
o.
30%
20%
1990
1995
2000 2005
Year
2010
2015
Reference Case Low Scenario Medium Scenario High Scenario
06K00135.RPT
Page IV-16
-------
analysis shows that by the year 2000, the imposition of the incremental regulations have little effect on
resources ultimately abandoned, but only on the rate of these abandonments.
At all prices considered, the imposition of the incremental regulations could have a significant and
immediate effect on the rate of resource abandonments. This is crucially important since once these
resources are abandoned, they essentially become unavailable for the implementation of advanced
recovery technologies unless very high oil prices become a reality. This is critically important because
the next 10 to 15 years, the time period when most of these resources could be abandoned, is also the
time period when R&D on advanced oil extraction technologies is expected to come to fruition. Therefore,
the pace of resource abandonments is critical to the implementation of potential advanced, more efficient,
recovery technologies in the field.
Ultimately (by the year 2000), however, the increased regulations have little impact on predicted
resource abandonments. For example, by the year 2000, all three regulatory scenarios result in roughly
the same portion of resource ultimately abandoned as that achieved in the reference case.
c. Summary. This analysis further demonstrates that the next ten years will be an extremely
important period for U.S. crude oil production, and that efforts to minimize resource abandonments are
crucial to guarantee future access to domestic resources. The analysis concludes that increased
environmental regulations could result in a substantial increase in the rate of resource abandonments
compared to the reference case, for all oil prices considered.
Under the low scenario as defined in this assessment, the impacts are relatively small, but are not
insignificant, when compared to the reference case. Considerable future production could be lost, and
a number of currently producing projects could be prematurely abandoned. Under either the medium or
high scenarios, however, as shown in Figures IV-7 to IV-10, the imposition of additional environmental
regulations could increase the pace of resource abandonments significantly. At oil prices of $20/Bbl and
less, resource abandonments in the medium and high scenarios are predicted to reach over 70% of the
domestic resource base, compared to approximately 40 to 50% of the resource base becoming
abandoned without the imposition of additional regulations. In the reference case, approximately 70% of
the resource base is expected to be abandoned by the year 2000. Therefore, increased regulations can
increase the pace of domestic crude oil resource abandonments by approximately ten years. This can
result in a significant reduction in the time available for technological development to make a contribution
to production in reservoirs on the verge of abandonment.
06K00135.RPT Page IV-17
-------
Three sets of environmental requirements dominate the incremental unit compliance costs that
could affect the economics of continued conventional production. These initiatives correspond to the
corrective action associated with salt water and hydrocarbon-contaminated E&P sites, area of
review/corrective action requirements proposed for existing wells, and air quality control requirements for
air toxics emitted from existing E&P facilities.
Most of the impact of environmental initiatives on the abandonment of the producing domestic
resource base occurs immediately after the proposed initiatives go into affect. This implies that the
incremental, initial capital costs associated with the regulatory initiatives have the greatest impact on
current production, though both initial capital and future annual operating costs associated with new
environmental regulations could impact future resource abandonments.
Unlike the resource categories considered (and discussed below), no analysis was conducted of
the impacts of increased environmental regulations on public sector revenues and total industry
expenditures associated with the continued production of producing acreage in existing fields. The
analysis system used at its current state of development, lacks the capability for performing this analysis.
C. Unrecovered Mobile OH In Known Fields
The analysis of the economic impact of environmental regulations on the UMO resource was
based on the analyses of nearly 500 crude oil reservoirs in Texas, Oklahoma, and New Mexico. The
reservoirs are estimated to contain almost 112 billion barrels of original oil in place, representing about
one-fifth of the total U.S. resource in place.
1. Analysis of Potential Under Current Regulations
a. Implemented Technology. As discussed in Chapter III, two technology cases were
considered in the UMO analysis - an implemented and an advanced technology case. Under the
implemented technology case, only infill drilling and advanced secondary recovery processes currently
implemented in the field were considered. Depending on oil price, UMO recovery techniques under the
implemented technology case, applied to the reservoirs analyzed in the three states, are predicted to
result in reserve additions ranging from 1.5 billion barrels at $16/Bbl to 2.6 billion barrels at $32/Bbl. As
shown in Table IV-3, a large portion of the UMO resource is recoverable at lower oil prices under the
implemented technology reference case, where UMO recovery amounts to nearly 2.1 billion barrels at
$20/Bbl, which is nearly 80% of the resource economically recoverable at $32/Bbl.
06K00135.RPT
page |
-------
TABLE IV-3
INCREMENTAL RESERVE ADDITIONS FROM UMO EXTRACTION BY PROCESS
FOR TEXAS, OKLAHOMA, AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Barrels)
Reference Case
Polymer Only
Profile Modification Only
Total Adv. Secondary
Infill Drilling Only
Infill w/ Polymer
Infill w/ Profile Mod.
Total Infill Related
Total UMO
173
171
344
373
619
139
1,131
1,476
140
164
304
804
687
282
1,773
2,077
112
144
256
874
748
292
1,914
2,172
110
149
259
1,219
727
372
2,318
2,578
Note: Numbers may not add exactly due to rounding.
06K00127.TBL
Page IV-19
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The analysis of UMO considered three categories of UMO processes - infill drilling, profile
modification techniques, and polymer flooding - along with the combination of infill drilling and the other
secondary recovery processes. This results in five possible processes that can be considered for each
reservoir. As shown in Table IV-3, infill drilling, alone and in combination with the other advanced
secondary recovery processes, contributes the greatest portion of the reserve additions forecast. Infill
drilling-related techniques could recover from 1.1 billion barrels at a price of $16/Bbl to 2.3 billion barrels
at a price of $32/Bbl. At an oil price of $20/Bbl, infill drilling-related techniques account for 1.8 of the 2.1
billion barrels economically recoverable at that price (approximately 85%). As oil prices increase, infill
drilling-related techniques correspond to an increasing portion of the UMO resource that is economically
recoverable, ranging from 77% at $16/Bbl to 90% at $32/Bbl.
Advanced secondary processes, applied alone, would contribute from 256 to 344 million barrels
over the oil prices considered ($16 to $32/Bbl). The reason that reserves from advanced secondary
recovery projects do not rise with oil prices is that these processes compete with the more prolific infill
drilling-related techniques. In this analysis, only one of the five possible processes can be implemented
in each reservoir. As oil prices rise, thereby justifying the more expensive infill drilling and combination
processes, many reservoirs that were assigned to advanced secondary projects (alone) at lower prices
become candidates for infill drilling-related projects at higher prices, because incremental oil recovery will
be greater for these now economically viable projects.
Table IV-4 shows the anticipated state and federal revenues that would be associated with the
UMO recovery projects under implemented technology at the various oil price tracks considered. State
revenue collections over the life of the economic projects would range from $1.4 billion at $16/Bbl to $5.1
billion at $32/Bbl. At $20/Bbl, state revenues would amount to $2.5 billion. Similarly, federal revenues
would range from $3.2 billion at $16/Bbl to $12.7 billion at $32/Bbl. At $20/Bbl, federal revenues would
amount to $5.4 billion. Total public sector revenues at $20/Bbl, consequently, would amount to $7.9
billion under the implemented technology UMO case, ranging from $4.6 to $17.8 billion over the $16 to
$32/Bbl price range.
b. Advanced Technology. The advanced technology case assumes a significantly improved
understanding of reservoir heterogeneity and improvements in advanced waterflooding techniques that
increase the applicability and productivity of the recovery processes considered. This case includes the
development of improved polymers available for field application in higher temperature and higher salinity
settings. Depending on oil price, UMO recovery techniques under the advanced technology case will
result in reserve additions in the three states ranging from 4.4 billion barrels at $16/Bbl to 7.1 billion
barrels at $32/Bbl (Table IV-5). Similar to the implemented technology case, a large portion of the UMO
06K00135.RPT page (v_20
-------
TABLE IV-4
INCREMENTAL STATE AND FEDERAL REVENUES FROM UMO EXTRACTION
IN TEXAS, OKLAHOMA, AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
Reference Case
State Revenues
Federal Revenues
$16/Bbl
1,394
3,201
$20/Bbl
2,503
5,374
$24/Bbl
3,111
7,187
$32/Bbl
5,096
12,670
Total Revenues
4,595
7,877
10,298
17,766
06K00127.TBL
IV-21
-------
TABLE IV-5
INCREMENTAL RESERVE ADDITIONS FROM UMO EXTRACTION BY PROCESS
FOR TEXAS, OKLAHOMA, AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Barrels)
Reference Case
Polymer Only
Profile Modification Only
Total Adv. Secondary
Infill Drilling Only
Infill w/ Polymer
Infill w/ Profile Mod.
Total Infill Related
Total UMO
$16/Bbl
331
299
630
1,351
1,789
646
3,786
4,417
$20/Bbl
321
298
619
1,772
2,175
960
4,907
5,525
$24/Bbl
240
302
542
2,047
2,327
1.328
5,702
6,244
$32/Bbl
254
324
578
2,443
2,792
1.310
6,545
7,123
Note: Numbers may not add exactly due to rounding.
06K00127.TBL
Page IV-22
-------
resource is recoverable at lower oil prices. As shown in Table IV-5, UMO recovery under the advanced
technology case amounts to nearly 5.5 billion barrels at $20/Bbl, which is about 78% of the reserves at
$32/Bbl.
Infill drilling, alone and in combination with the other advanced secondary recovery processes,
again contributes the greatest portion of the reserve additions forecast. Infill drilling-related techniques
would recover from 3.8 billion barrels at $16/Bbl to 6.5 billion barrels at $32/Bbl. At an oil price of $20/Bbl,
infill drilling-related techniques account for 4.9 of the 5.5 billion barrels economically recoverable at that
price (approximately 89%). As oil prices increase, similar to the implemented technology case, infill
drilling-related techniques correspond to a increasing portion of the UMO resource that is economically
recoverable, ranging from 86% at $16/Bbl to 92% at $32/Bbl. In addition, infill drilling-related techniques
contribute a larger portion of total UMO reserves than that predicted under the implemented technology
case.
Advanced secondary processes under the advanced technology case, applied alone, would
contribute from 542 to 630 MMB over the oil prices considered, roughly double that obtained in the
implemented technology case.
Table IV-6 shows the anticipated state and federal revenues that would be associated with the
UMO recovery projects for the various oil prices considered under the advanced technology case. State
revenue collections for economic projects would range from $4.0 billion at $16/Bbl to $13.7 billion at
$32/Bbl over the life of these projects. At $20/Bbl, state revenues would amount to $6.4 billion. Similarly,
federal revenues would range from $9.1 billion at $16/Bbl to $32.6 billion at $32/Bbl. At $20/Bbl, federal
revenues would amount to $13.7 billion. Total public sector revenues at $20/Bbl would amount to $20.1
billion under the advanced technology UMO case, ranging from $13.1 to $46.3 billion of total public sector
revenues over the $16 to $32/Bbl oil price range.
2. Impact of Initiatives
a. Reserves Lost. Based on the reservoirs analyzed, increased environmental regulations
could have a significant impact on UMO reserves under all three scenarios considered for both the
implemented and advanced technology cases. In the low scenario under the implemented technology
case, up to 330 MMB of reserves would become uneconomic to develop, with the greatest impact on
reserves occurring at $20/Bbl (near current oil prices), or 16% reduction in recoverable reserves.
Presumably, the greatest number of marginal projects with significant recovery under implemented
technology must become economically viable at a price near $20/Bbl. At other crude oil prices, only 3%
06K00135. RPT Page IV-23
-------
TABLE IV-6
INCREMENTAL STATE AND FEDERAL REVENUES FROM UMO EXTRACTION
IN TEXAS, OKLAHOMA, AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Dollars)
Reference Case
State Revenues
Federal Revenues
$16/Bbl
4,044
9,078
$20/Bbl
6,355
13,740
$24/Bbl
8,571
18,988
13,697
32,613
Total Revenues
13,122
20,095
27,559
46,310
06K00127.TBL
Page IV-24
-------
to 4% of otherwise economically recoverable resources would be impacted. These results are
summarized in Table IV-7 and in Figure IV-11.
Under the implemented technology, low scenario, the impact of increased environmental
regulations on recoverable reserves does not change uniformly with price. This is because the basic unit
of analysis in performing the economic evaluation is an oil reservoir, rather than an oil well or barrel of oil.
Each reservoir represents a portion of the resource in each resource category assessed. For each
reservoir, the return on investment is determined for each crude oil price considered. The cost/supply
curves associated with the various resource categories, therefore, many not necessarily be uniform, since
the economic supplies added with increasing prices (or lost because of increasing compliance costs) will
be in the form of discrete quantities of reserves of varying size (corresponding to the reservoirs affected).
Consequently, the economic impact of the increased costs associated with environmental regulations may
not be felt uniformly across the entire cost/supply curve, and the economic impact of proposed
regulations on various resource categories may vary. For example, the economic impact on resource
categories typified by smaller fields will be different than that typified by larger fields. Similarly, the
economic impact of environmental regulations on resource categories typified by many reservoirs which
are marginally economic at a given price under baseline conditions will be different than a case with few
reservoirs which are marginally economic under baseline conditions. Other, region-specific or resource-
specific factors may also affect costs.
Under the implemented technology case, medium scenario, from 318 to 718 MMB of reserves
would be lost over the price range considered, with the greatest impact again occurring at an oil price
of $20/Bbl. At this price, 718 MMB, or 35% of the recoverable UMO reserves would become uneconomic.
At other crude oil prices, from 21 % to 25% of otherwise recoverable reserves would be impacted (Table
IV-7 and Figure IV-11).
Finally, under the implemented technology case, high scenario, from 377 to 892 MMB of reserves
would become uneconomic to recover over the price range considered. As in the other scenarios, the
greatest impact occurs at $20/Bbl, where 892 MMB, or 43% of otherwise recoverable reserves under
implemented technology would become uneconomic. At other crude oil prices, from 25% to 34% of
otherwise recoverable reserves would become uneconomic.
More detailed results of the analysis of UMO potential under the implemented technology case
for all UMO recovery processes considered are presented in Table IV-8.
06K00135.RPT Page W-25
-------
TABLE IV-7
IMPACT OF ENVIRONMENTAL REGULATIONS ON RESERVES FROM UMO EXTRACTION
IN TEXAS, OKLAHOMA, AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Barrels)
Reference Case
$16/Bbl
Reserves 1 ,476
Incremental Decrease
%
$20/Bbl
Reserves 2,077
Incremental Decrease
%
$24/Bbl
Reserves 2,172
Incremental Decrease
%
$32/Bbl
Reserves 2,578
Incremental Decrease
%
Reaulatorv
Low
1,413
63
4%
1,747
330
16%
2,148
24
1%
2,509
69
3%
Scenario
Medium
1,158
318
21%
1,359
718
35%
1,632
540
25%
2,047
531
21%
High
1,099
377
26%
1,185
892
43%
1,442
730
34%
1,933
645
25%
06K00127.TBL
Page IV-26
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Figure IV-11
JO
-------
TABLE IV-8
IMPACT OF ENVIRONMENTAL REGULATIONS ON INCREMENTAL UMO RECOVERY
BY PROCESS IN TEXAS, OKLAHOMA, AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Barrels)
$16/Bbl Reference
Low
Medium
High
$20/Bbl - Reference
Low
Medium
High
$24/Bbl - Reference
Low
Medium
High
$32/Bbl
Reference
Low
Medium
High
Infill Related
Grand
Total
1,476
1,413
1,158
1,099
2,077
1,747
1,359
1,185
2,172
2,148
1,632
1,442
2,578
2,509
2,047
1,933
Subtotal
1,131
1,104
918
872
1,773
1,438
1,097
967
1,914
1,887
1,406
1,249
2,318
2,248
1,842
1,756
Infill
Only
373
348
186
180
804
558
357
239
874
861
529
453
1,219
1,154
801
721
Infill w/
Profile
619
617
554
514
687
725
574
562
748
737
598
596
727
722
697
691
Infill w/
Poly
139
139
178
178
282
155
166
166
292
289
279
200
372
372
344
344
Not Infill Related
Subtotal Poly Profile
344
309
241
227
304
309
262
218
256
261
226
192
259
260
204
175
173
152
117
88
140
149
132
106
112
116
91
77
110
109
79
59
171
157
124
139
164
160
130
112
144
145
135
115
149
151
125
116
Note:
Numbers may not add exactly due to rounding.
06K00127.TBL
Page IV-28
-------
In the advanced technology case, low scenario, from 167 to 415 MMB of reserves would be
affected, with the greatest impact, in terms of reserves lost, occurring at an oil price of $32/Bbl. However,
in terms of the portion of otherwise recoverable reserves impacted, the impact of the low scenario is about
the same at all oil prices considered, ranging from 4% to 6% of reserves becoming uneconomic to
develop, as shown in Table IV-9 and Figure IV-12.
Under the advanced technology case, medium scenario, the impacts are again significantly
greater than those felt under the low scenario. Under the medium scenario, from 610 to 1,393 MMB of
reserves could become uneconomic over the price range considered as a result of the increased
environmental regulations corresponding to the scenario. From 14% to 24% of otherwise recoverable
reserves would be lost over the price range considered. The greatest impact in terms of reserves lost
occurs at an oil price of $24/Bbl, where 1,393 MMB, or 22% of the otherwise recoverable UMO reserves,
would become uneconomic. In terms of fraction of resource lost, the greatest impact is felt at $20/Bbl,
where 24% of otherwise economic reserves would be impacted (Table IV-9 and Figure IV-12).
Finally, under the advanced technology case, high scenario, from 1,058 to 1,736 MMB of reserves
would be impacted over the price range considered. From 21 % to 28% of recoverable reserves would
be lost over the prices considered. The greatest volume of reserves lost again occurs at $24/Bbl, where
1,736 MMB would become uneconomic. In terms of fraction of reserves lost, the greatest impact is felt
at prices of $20 and $24/Bbl, where 28% of otherwise recoverable reserves would become uneconomic.
More detailed results of the analysis of UMO potential under the advanced technology case for
all UMO recovery processes considered are presented in Table IV-10.
This analysis shows that over one-fourth of the otherwise recoverable UMO reserves could be lost
as a result of the regulatory scenarios specified. As much as 1.7 billion barrels of reserves could be lost
in the three states analyzed - Texas, Oklahoma, and New Mexico. (U.S. crude oil reserves at the end of
1988, excluding those in Alaska but including offshore reserves, are about 20 billion barrels. Crude oil
production in 1988 amounted to about 2.1 billion barrels.)
b. Public sector revenues lost. Under the implemented technology case, the low scenario
would result in foregone public sector revenues (federal and state) ranging from $0.3 to $1.2 billion for
the three states analyzed, amounting to a 5% to 16% loss in public sector revenues (Table IV-11 and
Figure IV-13). Under the medium scenario, from $1.4 to $4.7 billion would be foregone, a 26% to 35%
loss in revenues for the three states. Finally, under the high scenario, from $1.6 to $5.6 billion would be
06K00135.RPT Page IV-29
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TABLE IV-9
IMPACT OF ENVIRONMENTAL REGULATIONS ON RESERVES FROM UMO EXTRACTION
IN TEXAS, OKLAHOMA, AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Barrels)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Reserves 4,417 4,250 3,807 3,359
Incremental Decrease 167 610 1,058
% 4% 14% 24%
$20/Bbl
Reserves 5,525 5,218 4,218 3,979
Incremental Decrease 307 1,307 1,546
% 6% 24% 28%
$24/Bbl
Reserves 6,244 5,913 4,851 4,508
Incremental Decrease 331 1,393 1,736
% 5% 22% 28%
$32/Bbl
Reserves 7,123 6,708 6,100 5,637
Incremental Decrease 415 1,023 1,486
% 6% 14% 21%
06K00127.TBL ' Page W-30
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v>
-------
TABLE IV-10
IMPACT OF ENVIRONMENTAL REGULATIONS ON INCREMENTAL UMO RECOVERY
BY PROCESS IN TEXAS, OKLAHOMA, AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Barrels)
Infill Related
$16/Bbl
$20/Bbl
$24/Bbl
$32/Bbl
Reference
Low
Medium
High
Reference
Low
Medium
High
Reference
Low
Medium
High
Reference
Low
Medium
High
Grand
Total
4,417
4,250
3,807
3,359
5,525
5,218
4,218
3,979
6,244
5,913
4,851
4,508
7,123
6,708
6,100
5,637
Subtotal
3,786
3,636
3,349
2,961
4,907
4,589
3,716
3,582
5,702
5,358
4,376
4,099
6,545
6,165
5,642
5,219
Infill
Only
1,351
1,197
1,022
2,057
1,772
1,618
1,085
1,055
2,047
2,008
1,414
1,234
2,443
2,295
1,855
1,642
Infill w/
Profile
1,789
1,921
1,727
108
2,175
2,153
1,857
1,873
2,327
2,332
2,022
2,010
2,792
2,573
2,623
2,582
Infill w/
Poly
646
518
600
796
960
818
774
654
1,328
1,018
940
855
1,310
1,297
1,164
995
Not Infill Related
Subtotal
630
615
459
397
619
628
501
396
542
554
474
408
578
544
459
418
Poly
331
327
245
183
321
337
265
204
240
248
229
216
254
238
186
167
Profile
299
288
214
214
298
291
236
192
302
306
245
192
324
306
273
251
Note:
Numbers may not add exactly due to rounding.
06K00127.TBL
Page IV-32
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TABLE IV-11
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL PUBLIC SECTOR
REVENUES ASSOCIATED WITH UMO RESERVES IN TEXAS, OKLAHOMA,
AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
Regulatory Scenario
Reference Case Low Medium
$16/Bbl
Revenues 4,595 4,289 3,243 3,019
Incremental Decrease 306 1,352 1,576
% 7% 29% 34%
$20/Bbl
Revenues 7,877 6,643 5,093 4,328
Incremental Decrease 1,234 2,784 3,549
% 16% 35% 45%
$24/Bbl
Revenues 10,298 9,823 7,205 6,387
Incremental Decrease 475 3,093 3,911
% 5% 30% 38%
$32/Bbl
Revenues 17,766 16,953 13,100 12,157
Incremental Decrease 813 4,666 5,609
% 5% 26% 32%
06KD0127.TBL Page IV-33
-------
25.0
FigurelV-13
Impact of Environmental Regulations on Total Public
Sector Revenues from UMO Development
in Texas, Oklahoma, and New Mexico
Implemented Technology
tn
-------
lost to public treasuries, a 32% to 45% loss. As shown in Table IV-11, the percentage of public revenues
lost are highest at $20/Bbl, i.e., near current oil prices.
Under the advanced technology case, the low scenario would result in foregone public sector
revenues of $0.7 to $3.2 billion for the three states analyzed, a 5% to 7% loss in revenues (Table IV-12
and Figure IV-14). Under the medium scenario, from $2.8 to $9.4 billion would be foregone, a 20% to
26% loss in revenues for the three states. Finally, under the high scenario, from $4.1 to $12.3 billion
would be lost to the public sector, a 27% to 32% loss. Public sector revenues lost in the advanced
technology UMO case are estimated to be approximately twice that which could occur under the
implemented technology case.
c. Impact on Industry Expenditures. In Chapter II, estimates were made of total industry
compliance costs assuming 1985 levels for industry activities in well drilling, development, and production.
These estjmates assumed that industry activity would remain relatively constant at 1985 levels, and that
the increased regulations would not affect industry activity except in adding costs to operations that would
be pursued regardless of whether or not the regulations would be implemented. Under this assumption,
additional environmental regulationc would lead to greater industry expenditures.
However, as this analysis clearly demonstrates, total industry expenditures may not necessarily
increase because of increased environmental regulations. This analysis shows that the increased
environmental regulations could result in some previously viable projects becoming uneconomic to
pursue. Consequently, reduced development of crude oil resources could more than offset the increased
compliance costs. Ultimately, industry investment and operating expenditures could in fact decrease as
a result of the increased regulatory requirements.
This factor is important to consider because, as previously discussed, industry expenditures in
oil and gas activities have secondary economic impacts on communities in which these expenditures are
made. More is potentially at stake than just increased costs to the petroleum industry. Decreases in
economic activity related to oil and gas operations could have a significant impact on these communities.
However, estimating these impacts was outside the scope of this analysis.
Overall, under the implemented technology case, increased environmental regulations could
impact total industry investment and operating expenditures in UMO operations in Texas, Oklahoma, and
New Mexico. These impacts could range from a 5% increase in expenditures at $24/Bbl under the low
scenario to a 39% decrease in expenditures under the high scenario at $20/Bbl (Table IV-13 and Figure
IV-15). Total incremental industry investment expenditures in UMO operations in the three states would
06K00135.RPT Page IV-35
-------
TABLE IV-12
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL PUBLIC SECTOR
REVENUES ASSOCIATED WITH UMO RESERVES IN TEXAS, OKLAHOMA,
AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Dollars)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Revenues 13,122 12,465 10,306 8,971
Incremental Decrease 657 2,816 4,151
% 5% 21% 32%
$20/Bbl
Revenues 20,095 18,722 14,881 13,830
Incremental Decrease 1,373 5,214 6,265
% 7% 26% 31%
$24/Bbl
Revenues 27,559 25,628 20,507 18,715
Incremental Decrease 1,931 7,052 8,844
% 7% 26% 32%
$32/Bbl
Revenues 46,310 43,068 36,880 33,972
Incremental Decrease 3,242 9,430 12,338
% 7% 20% 27%
Page IV-36
-------
50.0
Figure IV-14
Impact of Environmental Regulations on Total Public
Sector Revenues from UMO Development
in Texas, Oklahoma, and New Mexico
Advanced Technology
40.0
o
Q
c
o
30.0
§
I
20.0
C0
.o
5
10.0
$20 $24
Oil Price ($/Bbl)
Low Scenario
$32
Medium Scenario
High Scenario
06K00135.RPT
Page IV-37
-------
TABLE IV-13
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT
AND OPERATING EXPENDITURES FOR UMO DEVELOPMENT IN TEXAS, OKLAHOMA,
AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
7,816
7,775
( 95)
( 1%)
7,286
( 530)
( 7%)
7,054
( 762)
( 10%)
Total Costs
Incremental Increase
% Change
14,348
11,911
( 2,357)
( 16%)
9,735
(4,613)
( 32%)
8,687
(5,661)
( 39%)
Total Costs
Incremental Increase
% Change
16,587
17,453
866
5%
14,483
(2,104)
( 13%)
12,656
( 3,931)
( 24%)
Total Costs
Incremental Increase
% Change
25,845
26,134
289
1%
24,086
(1,759)
( 7%)
23,275
( 2,570)
( 10%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-38
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50.0
Figure IV-15
Impact of Environmental Regulations on Total Industry
Expenditures for UMO Development in Texas, Oklahoma,
and New Mexico
Implemented Technology
40.0 -
J2
o
Q
c 30.0
o
TJ
I
20.0 -
10.0 -
$16
Operating Costs
Investment Costs
$2° Oil Price ($/Bbl) $24
$32
Reference Case Low Scenario Medium Scenario High Scenario
ep.l?6 15
06K00135.RPT
Page IV-39
-------
range from a 7% increase in expenditures at $24/Bbl under the low scenario to a 37% decrease in
expenditures under the high scenario at $20/Bbl (Table IV-14). Similarly, total direct industry operating
expenditures over the life of economic UMO development projects in the three states analyzed could
decrease as much as 42%, occurring at $20/Bbl under the high scenario (Table IV-15).
Under the advanced technology case, increased environmental regulations could result in
changes in industry investment and operating expenditures in the three states ranging from a 2%
decrease in expenditures at $16/Bbl under the low scenario to a 24% decrease in expenditures under the
high scenario at $20/Bbl (Table IV-16 and Figure IV-16). Increased environmental regulations could result
in incremental industry investment expenditures in UMO operations in the three states ranging from a 2%
increase in expenditures at $24/Bbl under the low scenario to a 22% decrease in expenditures under the
high scenario at $20/Bbl (Table IV-17). Total direct industry operating expenditures over the life of
economic UMO development projects in the three states analyzed under the advanced technology case
could decrease as much as 27% at $20/Bbl under the high scenario (Table IV-18).
Under most sets of conditions considered, the implementation of additional environmental
regulations are predicted to result in a decrease in UMO development and production expenditures in the
three states analyzed. Over $6 billion in investment expenditures and over $5 billion in operating
expenditures could be lost to Texas, Oklahoma, and New Mexico over the next two decades if something
similar to the high regulatory scenario is implemented. In these states already suffering from decreased
state revenues and depressed economies resulting from the downturn in the oil and gas industry, this
decrease in industry expenditures could have a significant impact.
d. Summary. The analysis of the impact of environmental initiatives on UMO development
in Texas, Oklahoma, and New Mexico shows that under all regulatory and oil price scenarios considered,
the development of otherwise economically viable projects may not be pursued. This will result in lower
domestic crude oil production, decreased revenues to state and federal governments from taxes collected
on oil and gas operations, and decreased industry expenditures for crude oil development, detrimentally
affecting communities economically dependent on the petroleum industry. Detrimental economic and
energy impacts are predicted under all regulatory scenarios and oil prices considered, with all UMO
recovery processes potentially affected.
Depending on the level of environmental regulations implemented as much as 43% of the
potentially recoverable UMO reserves in these states could become uneconomic to develop, assuming
the application of current recovery technologies. This could result in as much as a 45% decrease in
revenues to public treasuries due to foregone crude oil development.
06K00135.RPT Page IV-40
-------
TABLE IV-14
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT
EXPENDITURES FOR UMO DEVELOPMENT IN TEXAS, OKLAHOMA,
AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
3,782
4,014
232
6%
3,730
(52)
(1%)
3,633
(149)
Total Costs
Incremental Increase
% Change
7,252
6,124
(1,128)
(16%)
4,809
(2,443)
(34%)
4,602
(2,670)
(37%)
Total Costs
Incremental Increase
% Change
8,814
9,414
600
7%
7,747
(1,067)
(12%)
6,900
(1,914)
(22%)
Total Costs
Incremental Increase
% Change
14,145
14,438
293
2%
13,044
(1,101)
(8%)
12,704
(1,441)
(10%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-41
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TABLE IV-15
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL DIRECT INDUSTRY
OPERATING EXPENDITURES FOR UMO DEVELOPMENT IN TEXAS, OKLAHOMA,
AND NEW MEXICO - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
Reference Case
Requlatorv Scenario
Low Medium
High
Total Costs
Incremental Increase
% Change
4,034
3,761
( 273)
( 7%)
3,556
( 478)
( 12%)
3,421
( 613)
( 15%)
Total Costs
Incremental Increase
% Change
7,096
5,867
(1,229)
( 17%)
4,926
(2,170)
( 31%)
4,085
(3,011)
( 42%)
Total Costs
Incremental Increase
% Change
7,773
8,039
266
3%
6,736
( 1,037)
( 13%)
5,756
(2,017)
( 26%)
Total Costs
Incremental Increase
% Change
11,700
11,696
4
< 1%
11,042
(658)
( 6%)
10,571
( 1,129)
( 10%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-42
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TABLE IV-16
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT AND
OPERATING EXPENDITURES FOR UMO DEVELOPMENT IN TEXAS, OKLAHOMA,
AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Dollars)
Reference Case
Requlatorv Scenario
Low Medium
High
Total Costs
Incremental Increase
% Change
24,993
24,414
( 579)
( 2%)
24,593
( 400)
( 2%)
21,888
(3,105)
( 12%)
Total Costs
Incremental Increase
% Change
40,443
38,595
( 1,848)
( 5%)
32,063
( 8,380)
( 21%)
30,752
( 9,691)
( 24%)
Total Costs
Incremental Increase
% Change
53,432
52,039
(1,393)
( 3%)
44,450
( 8,982)
( 17%)
42,003
(11,429)
( 21%)
Total Costs
Incremental Increase
% Change
79,224
75,638
( 3,586)
( 5%)
77,094
(2,130)
( 3%)
71,371
( 7,853)
( 10%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-43
-------
Figure IV-16
Impact of Environmental Regulations on Total Industry
Expenditures for UMO Development in Texas, Oklahoma
and New Mexico
Advanced Technology
100.0
80.0 -
3
c
o
1
c 60.0
o
40.0
'•o
20.0 -
$16 $20 $24
Oil Price ($/Bbl)
Operating Costs "~
Investment Costs
Reference Case Low Scenario Medium Scenario High Scenario
ep326 16
06K00135.RPT
Page IV-44
-------
TABLEIV-17
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT
EXPENDITURES FOR UMO DEVELOPMENT IN TEXAS, OKLAHOMA,
AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Dollars)
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
14,253
14,283
30
< 1%
13,928
( 325)
( 2%)
12,838
(1,415)
( 10%)
Total Costs
Incremental Increase
% Change
23,156
Total Costs
Incremental Increase
% Change
30,725
22,611
( 545)
( 2%)
31,200
475
2%
18,280
(4,876)
( 21%)
25,362
(5,363)
( 17%)
18,147
(5,009)
( 22%)
24,550
(6,175)
( 20%)
Total Costs
Incremental Increase
% Change
47,059
45,565
(1,494)
( 3%)
45,568
(1,491)
( 3%)
44,140
(2,919)
( 6%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-45
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TABLE IV-18
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY OPERATING
EXPENDITURES FOR UMO DEVELOPMENT IN TEXAS, OKLAHOMA,
AND NEW MEXICO - ADVANCED TECHNOLOGY
(Millions of Dollars)
Reference Case
Reaulatorv Scenario
Low Medium
Hiqh
Total Costs
Incremental Increase
% Change
10,740
10,131 10,665
( 609) ( 75)
( 1%) ( 1%)
9,050
(1,690)
( 16%)
Total Costs
Incremental Increase
% Change
17,287
15,984 13,783
(1,283) (3,484)
( 7%) ( 20%)
12,605
(4,682)
( 27%)
Total Costs
Incremental Increase
% Change
22,707
20,839
( 1,868)
( 8%)
19,088
(3,619)
( 16%)
17,453
( 5,254)
( 23%)
Total Costs
Incremental Increase
% Change
32,165
30,073
(2,092)
( 7%)
31,526
( 639)
( 2%)
27,231
( 4,934)
( 15%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
Page IV-46
-------
The development of the UMO resource requires that a considerable number of new production
and injection wells be drilled. Environmental regulations that apply directly to drilling these wells, such
as management and disposal requirements for drilling muds and cuttings and area-of-review and
corrective action requirements for both new and existing injection wells, are the most significant
environmental compliance cost factors influencing the economics of developing the UMO resource.
For the UMO resource in known Lower-48 onshore fields, the impact of increased initial capital
and annual operating costs are roughly equivalent; however, the combined impact of both incremental
capital and annual operating costs has the greatest affect on reducing potentially recoverable UMO
reserves under all regulatory scenarios.considered.
D. Enhanced Oil Recovery In Known Fields
Like the UMO analysis discussed above, the analysis of EOR potential in this study also used
TORIS. The analysis of EOR potential was based on an oil reservoir data base consisting of over 3,700
reservoirs throughout the nation, corresponding to approximately 70% of the domestic crude oil resource
in place.
1. Analysis of Potential Under Current Regulations
The analysis of the impact of increased environmental regulations on potential reserves from EOR
considered both ongoing and new EOR reservoirs or projects. Ongoing projects consisted primarily of
producing steamfloods in California, along with some large CO2 projects in West Texas. For purposes
of this analysis, production projected from ongoing CO2 projects was assumed to be included in booked
reserves; therefore, no distinct, separate analysis of ongoing CO2 projects are performed. Analyses of
ongoing projects considered the continued production from producing acreage in those reservoirs with
ongoing EOR projects, along with the development of currently undeveloped acreage. New EOR projects
were assumed to be new projects in reservoirs with no current EOR activity in place.
As discussed in Chapter III, two levels of EOR technology were evaluated in this assessment. The
EOR analyses considered three categories of EOR processes - thermal recovery, chemical flooding, and
gas miscible flooding. The first level, the implemented technology case, represents technology currently
in place and proven in successful field tests. The second level, the advanced technology case, assumes
technological improvements resulting from successful research and development, improving EOR
efficiencies and expanding the resource applicable to EOR processes. The results of the EOR analyses
06K00135.RPT Page IV-47
-------
under baseline conditions, or assuming current environmental regulations applied to EOR operations, are
discussed below.
a. Implemented Technology. Depending on oil price, EOR techniques under the
implemented technology case, applied to the reservoirs analyzed, are predicted to result in reserve
additions ranging from 1.0 billion barrels at $16/Bbl to 10.2 billion barrels at $32/Bbl. Including only
reservoirs without ongoing EOR projects, reserve additions ranging from 0.8 billion barrels $16/Bbl to 7.2
billion barrels at $32/Bbl are realizable. As shown in Table IV-19, EOR amounts to nearly 2.7 billion
barrels at $20/Bbl. If reservoirs with no previous EOR projects in them are considered, approximately 1.8
billion barrels of reserves are potentially recoverable at this price.
Ongoing thermal EOR projects are projected to recover from 0.21 billion barrels at $16/Bbl to 3.0
billion barrels at $32/Bbl. No new thermal projects are economic at $16/Bbl, but as much as 1.5 billion
barrels are economic at $32/Bbl. New miscible projects can recover from 0.8 billion barrels at $16/Bbl
to 5.1 billion at $32/Bbl. Finally, new chemical flooding projects are predicted to produce as much as 0.6
billion barrels under implemented technology at $32/Bbl, with relatively small amounts (20 MMB)
recoverable at a price of $16/Bbl (Table IV-20).
Projected state and federal revenues from EOR projects under the implemented technology case
are shown in Table IV-20. Considering both new and ongoing projects, state revenue collections from
EOR processes in the U.S., over the life of these projects, could range from $0.8 billion at a $16/Bbl price
to $17.2 billion at $32/Bbl. At $20/Bbl, state revenues of $2.6 billion are forecast from EOR projects under
the implemented technology case. Federal revenues are predicted to range from $0.4 billion at $16/Bbl
to $24.5 billion at $32/Bbl; at a $20/Bbl price, $2.6 billion in federal revenues would be collected. Overall,
public sector revenues of $5.1 billion would be collected under the implemented technology case at
$20/Bbl. Public sector revenues can range from $1.2 billion at $16/Bbl to $41.7 billion at $32/Bbl.
b. Advanced Technology. EOR techniques under the advanced technology case will result
in domestic reserve additions ranging from 1.6 billion barrels at $16/Bbl to 16.4 billion barrels at $32/Bbl.
Including only new EOR reservoirs, reserve additions ranging from 1.4 billion barrels at $16/Bbl to 13.4
billion barrels at $32/Bbl are realizable. As shown in Table IV-21, EOR under the advanced technology
case amounts to nearly 6.1 billion barrels at an oil price of $20/Bbl, over twice that achievable under the
implemented technology case.
Under the advanced technology reference case, ongoing thermal recovery projects are projected
to recover from 0.21 billion barrels at $16/Bbl to 3.0 billion barrels at $32/Bbl (the same as under the
06K00135.RPT Page IV-48
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TABLE IV-19
INCREMENTAL RESERVE ADDITIONS FROM EOR BY
PROCESS IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Barrels)
Reference Case
Ongoing Projects
New Thermal
New Miscible
New Chemical
Total
Total (New Only)
$16/Bbl
214
—
814
20
1,048
834
$20/Bbl
887
97
1,441
263
2,688
1,801
$24/Bbl
2,258
137
2,502
221
5,118
2,859
$32/Bbl
3,018
1,469
5,113
569
10,169
7,151
Numbers may not add precisely due to rounding.
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Page IV-49
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TABLE IV-20
INCREMENTAL STATE AND FEDERAL REVENUES FROM EOR
PRODUCTION IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
Reference Case
All Projects:
State Revenues
Federal Revenues
Total
New Projects Only:
State Revenues
Federal Revenues
807
418
1,225
682
334
2,530
2.612
5,142
1,874
2,044
5,712
6.715
12,427
3,716
4,977
17,183
24.513
41,696
13,215
19.936
Total
1,016
3,918
8,693
33,151
Page IV-50
-------
TABLE IV-21
INCREMENTAL RESERVE ADDITIONS FROM EOR BY
PROCESS IN THE U.S. - ADVANCED TECHNOLOGY
(Millions of Barrels)
Reference Case
Ongoing Projects
New Thermal
New Miscible
New Chemical
Total Reserves
Total (New Only)
$16/Bbl
214
331
815
223
1,583
1,369
$20/Bbl
887
1,028
1,572
2.595
6,082
5,195
$24/Bbl
2,258
1,598
3,096
1.047
7,999
5,741
$32/Bbl
3,018
2,822
6,194
4,396
16,430
13,412
Numbers may not add precisely due to rounding.
06K00127.TBL
Page IV-51
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implemented technology case; by definition in this analysis, advanced technologies are assumed to have
no effect on reservoirs with thermal projects ongoing). Reserve additions from new thermal projects are
estimated to range from 0.3 billion barrels at $16/Bbl to over 2.8 billion barrels at $32/Bbl. New miscible
projects can recover from 0.8 billion barrels at $16/Bbl to 6.2 billion barrels at $32/Bbl. New chemical
flooding projects can result in reserve additions ranging from 0.2 billion barrels at $16/Bbl to 4.4 billion
barrels at a price of $32 barrel (Table IV-21).
Projected state and federal revenues from EOR projects under the implemented technology case
are shown in Table IV-22. State revenue collections from advanced EOR processes in the U.S.,
considering both new and ongoing projects, could range from $1.3 billion at $16/Bbl to $31.2 at $32/Bbl.
At $20/Bbl, state revenues of $7.1 billion are forecast from EOR projects under the advanced technology
case. Federal revenues are predicted to range from $1.2 billion at $16/Bbl to $39.9 at $32/Bbl; at a
$20/Bbl price, $7.7 billion in federal revenues would be collected. Public sector revenues of $14.8 billion
would be collected under the advanced technology case at an oil price of $20/Bbl. Public sector
revenues from EOR development could range from $2.6 billion at $16/Bbl to $71.1 billion at $32/Bbl.
2. Impact of Initiatives
a. Reserves Lost. Based on the reservoirs analyzed, which represent about 70% of the
resource in place in the U.S., increased environmental regulations could also have a significant impact
on EOR reserves under all three scenarios for both the implemented and advanced technology cases.
In the low scenario under the implemented technology case, for example, up to 341 MMB of reserves
could become uneconomic to develop, with the greatest impact on reserves lost occurring at an oil price
of $24/Bbl. The fraction of reserves lost is also highest at $24/Bbl, where 7% of the reserves that would
otherwise be economic at this price become uneconomic. At other crude oil prices, from 1% to 12% of
otherwise recoverable resources would be impacted. These results are summarized in Table IV-23 and
in Figure IV-17 for all EOR projects.
In the medium scenario under the implemented technology case, up to 1.5 billion barrels of
reserves could become uneconomic to develop, with the greatest impact on the volume of reserves lost
occurring at $32/Bbl. The fraction of reserves lost, however, is highest $16/Bbl, where 46% of the reserves
that would otherwise be economic at this price become uneconomic. From 11% to 46% of otherwise
recoverable resources in the medium scenario could become uneconomic, depending on oil price.
Finally, in the high scenario under the implemented technology case, up to 2.1 billion barrels of
reserves could be impacted, with the greatest impact on reserves lost again occurring at $32/Bbl. The
06K00135.RPT Page IV-52
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TABLE IV-22
INCREMENTAL STATE AND FEDERAL REVENUES FROM EOR
PRODUCTION IN THE U.S. - ADVANCED TECHNOLOGY
(Millions of Dollars)
Reference Case
All Projects:
State Revenues
Federal Revenues
1,344
1,217
7,116
7,666
9,667
10,780
31,163
39,947
Total
New Projects Only:
State Revenues
Federal Revenues
Total
2,561
1,219
1,133
2,352
14,782
6,460
7,098
13,558
20,447
7,671
9.042
16,713
71,110
27,195
35,370
62,565
06K00127.TBL
Page IV-53
-------
TABLE IV-23
IMPACT OF ENVIRONMENTAL REGULATIONS ON EOR RESERVES
DEVELOPMENT IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Barrels)
All Projects
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Reserves 1,048 1,046 571 492
Incremental Decrease 2 477 556
% < 1% 46% 53%
$20/Bbl
Reserves 2,688 2,603 2,050 1,920
Incremental Decrease 85 638 768
% 3% 24% 29%
$24/Bbl
Reserves 5,118 4,777 4,550 3,964
Incremental Decrease 341 568 1,154
% 7% 11% 23%
$32/Bbl
Reserves 10,169 9,901 8,632 8,t04
Incremental Decrease 268 1,537 2,065
% 3% 15% 20%
06KQ0127.TBL
-------
CO
CD
o
12.0
10.0 -,
i 8.0
m
o 6.0 \-
0)
CC
CC
o
HI
I 4-° ^
0)
2.0 -
Figur© IV-17
Impact of Environmental Regulations on
iOR Reserves in the U,S.
Implemented Technology • All Projects
$16
Ongoing Projects
New Projects
$20 $24
Oil Prise ($/Bbl)
$32
Reference Case Low Scenario Medium Scenario High Scenario
•P326-17
06K00135.RPT
Page IV-55
-------
fraction of reserves lost is again greatest at low prices ($16/Bbl), where 53% of the reserves that would
otherwise be economic at this price become uneconomic. From 20% to 53% of otherwise economically
recoverable resources would be impacted in the high scenario (Table IV-23).
Table IV-24 shows the EOR potential by process for the reference scenario and the three
regulatory scenarios under the implemented technology EOR case. As shown, the impact of
environmental regulations on thermal recovery projects is less significant than that on either miscible or
chemical projects.
In the advanced technology case, low scenario, up to 669 MMB of otherwise recoverable reserves
could become uneconomic, with the greatest impact on reserves lost occurring at $20/Bbl. The fraction
of reserves lost under the advanced technology is highest at $16/Bbl, where from 21 % of the reserves that
would otherwise be economic become uneconomic. At other crude oil prices, up to 11 % of otherwise
recoverable reserves would be impacted. These results are summarized in Table IV-25 and in Figure IV-
18.
In the medium scenario under the advanced technology case, up to 3.2 billion barrels of reserves
could become uneconomic. The greatest impact on reserves lost again occurs at $32/Bbl. The fraction
of reserves lost, however, is highest at $16/Bbl, where 51% of the reserves that would otherwise be
economic at this price become uneconomic. From 20% to 51% of otherwise recoverable reserves would
be impacted in the medium scenario.
In the high scenario under the advanced technology case, up to 4.8 billion barrels of reserves
could become uneconomic as a result of the increased regulatory requirements, with the greatest impact
on the volume of reserves lost again occurring at $32/Bbl. The fraction of reserves lost is again greatest
at low prices; at a $16/Bbl oil price, as much as two-thirds of the reserves that would otherwise be
economic at this price become uneconomic. From 29% to 66% of otherwise recoverable reserves would
be impacted in the high scenario.
Table IV-26 shows the EOR potential by process for the reference scenario and the three
scenarios under the advanced technology case. Under the advanced scenario, increased environmental
regulations can have a significant impact on all EOR processes for all oil prices considered under the
implemented technology scenario, increased environmental regulations had little impact on the economic
viability of thermal recovery projects.
06K00135.RPT Page IV-56
-------
TABLE IV-24
IMPACT OF ENVIRONMENTAL REGULATIONS ON INCREMENTAL
EOR BY PROCESS IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Barrels)
Total
$16/Bbl-
$20/Bbl
$24/Bbl -
$32/Bbl -
Reference
Low
Medium
High
Reference
Low
Medium
High
Reference
Low
Medium
High
Reference
Low
Medium
High
New
834
831
357
278
1,801
1,716
1,163
1,033
2,859
2,518
2,292
2,122
7,151
6,883
5,796
5,427
All
1,048
1,045
571
-493
2,688
2,603
2,050
1,920
5,118
4,777
4,550
3,964
10,169
9,901
8,632
8,104
Thermal
New
~
—
—
97
97
80
80
137
137
137
137
1,469
1,469
1,399
1,399
AN
214
214
214
214
984
984
967
967
2,395
2,395
2,395
1,979
4,487
4,487
4,235
4,075
Miscible
814
811
354
276
1,441
1,365
1,035
914
2,502
2,151
2,030
1,881
5,113
4,861
3,899
3,536
Chemical
20
20
3
3
263
253
47
38
221
231
125
103
569
553
498
4,93
Numbers may not add precisely due to rounding.
06K00127.TBL
Page IV-57
-------
TABLE IV-25
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL EOR RESERVES
DEVELOPMENT IN THE U.S. - ADVANCED TECHNOLOGY
(Millions of Barrels)
All Projects
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Reserves 1,583 1,249 780 545
Incremental Decrease 334 803 1,038
% 21% 51% 66%
$20/Bbl
Reserves 6,082 5,413 3,917 3,543
Incremental Decrease 669 2,165 2,539
% 11% 36% 42%
$24/Bbl
Reserves 7,999 7,635 6,435 5,437
Incremental Decrease 364 1,564 2,562
% 5% 20% 32%
$32/Bbl
Reserves 16,430 16,324 13,192 11,639
Incremental Decrease 106 3,238 4,791
% 1% 20% 29%
06K00127.TBL Page IV-58
-------
JO
-------
TABLE IV-26
IMPACT OF ENVIRONMENTAL REGULATIONS ON INCREMENTAL
EOR BY PROCESS IN THE U.S. - ADVANCED TECHNOLOGY
(Millions of Barrels)
Total
$16/Bbl
$20/Bbl
$24/Bbl
$32/Bbl -
Reference
Low
Medium
High
Reference
Low
Medium
High
Reference
Low
Medium
High
Reference
Low
Medium
High
New
1,369
1,035
566
331
5,195
4,526
3,030
2,647
5,740
5,377
4,177
3,595
13,412
13,308
10,355
8,964
AJ!
1,583
1,249
780
545
6,082
5,413
3,917
3,536
7,999
7,635
6,435
5,437
16,430
16,324
13,192
11,639
Thermal
New
331
--
--
—
1,028
924
268
268
1,598
1,624
1,292
762
2,822
3,349
3,268
2,860
All
545
214
214
214
1,915
1,811
1,155
1,155
3,856
3,882
3,550
2,604
5,840
6,367
6,104
5,536
Miscible
815
812
355
276
1,572
1,487
1,147
894
3,096
2,764
2,113
2,134
6,194
5,972
4,926
4,515
Chemical
223
223
211
54
2,595
2,116
1,616
1,487
1,047
989
772
699
4,396
3,985
2,162
1,588
Numbers may not add precisely due to rounding.
06K00127.TBL
Page IV-60
-------
Table IV-26 shows another interesting aspect of the economic impact of environmental regulations
on U.S. EOR potential. For some processes, the implementation of increased environmental regulations
may increase the recovery potential for that process. For example, at a $32/Bbl price, the recovery
potential of new thermal recovery projects increases in the low scenario when compared to the reference
case. This is because the TORIS system assesses the potential recovery of each economically viable
EOR process in each reservoir, and the process producing the most oil is the one selected for the
reservoir. In this case, non-thermal EOR processes are the most viable for some reservoirs under
reference conditions, but once the additional regulations were imposed, these processes became
uneconomic in these reservoirs. However, the regulations were not costly enough to make thermal
operations in these same reservoirs uneconomic. Consequently, some reserves recoverable from non-
thermal EOR processes become uneconomic under the low regulatory scenario, but some of these are
still economic as thermal processes, which add to recoverable reserves for that process.
b. Public Sector Revenues Lost. Under the implemented technology case, the low scenario
would result in lost public sector revenues (federal and state) from foregone EOR projects of as much as
to $1.8 billion. Depending on oil prices, public sector revenues could decrease by as much as 10% under
the low scenario (Table IV-27 and Figure IV-19). Under the medium scenario, from $0.7 to $8.0 billion
ould be lost, a 18% to 58% loss in public sector revenues from U.S. EOR projects. Finally, under the high
scenario, from $0.9 to $10.4 billion would be lost to public treasuries, a 25% to 72% loss of revenues that
would have been collected under the reference scenario. As shown in Table IV-27, the percentage of
public revenues lost are highest at low ($16/Bbl) oil prices.
Under the advanced technology case, the low scenario would result in lost public sector revenues
$0.8 to $2.2 billion for the three states analyzed, a 2% to 32% loss (Table IV-28 and Figure IV-20). Under
the medium scenario, from $1.5 to $17.3 billion would be lost, depending on oil price, a 23% to 58% loss
in public sector revenues from EOR projects in the U.S. Finally, under the high scenario, from $2.2 to
$25.6 billion would be lost to public treasuries, a 36% to 84% loss.
c. Impact on Industry Expenditures. Under the implemented technology case, increased
environmental regulations could greatly impact total industry investment and operating expenditures for
domestic EOR operations. These impacts could range from a 1 % increase in expenditures at $16/Bbl
under the low scenario to a 52% decrease in expenditures under the high scenario at the same price
(Table IV-29 and Figure IV-21). Under the high scenario at high oil prices, industry expenditures in EOR
development under the implemented technology case could decrease by as much as $27 billion. The
change in investment expenditures in EOR operations in the U.S. could range from a 8% increase at
$16/Bbl under the low scenario to a 19% decrease in expenditures under the high scenario at the same
06K00135.RPT Page IV-61
-------
TABLE IV-27
IMPACT OF ENVIRONMENTAL REGULATIONS ON PUBLIC SECTOR REVENUES
FROM EOR RESERVES DEVELOPMENT IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
All Projects
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Revenues 1,225 1,181 518 345
Incremental Decrease 44 707 880
% 4% 58% 72%
$20/Bbl
Revenues 5,142 4,862 3,488 3,082
Incremental Decrease 280 1,654 2,060
% 5% 32% 40%
$24/Bbl
Revenues 12,427 11,150 10,163 8,955
Incremental Decrease 1,272 2,264 3,472
% 10% 18% 28%
$32/Bbl
Revenues 41,696 39,862 33,729 31,275
Incremental Decrease 1,834 7,967 10,421
% 4% 19% 25%
06K00127.TBL Page IV-62
-------
Figure IV-19
Impact of Environmental Regulations on Total Public
Sector Revenues from EOR Reserves Development in the U.S.
50.0
40.0
§
g
Si 30.0
I
I
E 20.0
10.0
CO
o
implemented Technology - All Projects
$16
$20 $24
Oil Price ($/Bbl)
Reference Case ;ji|l!nifcS Low Scenario
Medium Scenario
$32
High Scenario
•p3 26-21
06K00135.RPT
Page IV-63
-------
TABLE IV-28
IMPACT OF ENVIRONMENTAL REGULATIONS ON PUBLIC SECTOR REVENUES
FROM EOR RESERVES DEVELOPMENT IN THE U.S. - ADVANCED TECHNOLOGY
(Millions of Dollars)
AH Projects
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Revenues 2,561 1,748 1,064 398
Incremental Decrease 813 1,497 2,163
% 32% 58% 84%
$20/Bbl
Revenues 14,782 12,614 8,567 7,777
Incremental Decrease 2,168 6,213 7,003
% 15% 42% 47%
$24/Bbl
Revenues 20,447 19,233 15,798 12,922
Incremental Decrease 1,214 4,649 7,525
% 6% 23% 37%
$32/Bbl
Revenues 71,110 69,346 53,833 46,560
Incremental Decrease 1,764 17,277 25,550
% 2% 24% 36%
06K00127.TBL Page IV-64
-------
75.0
Figure IV-20
Impact of Environmental Regulations on Total
Public Sector Revenues from EOR Reserves
Development in the U.S.
Advanced Technology - All Projects
60.0
&
o
40.0
CO
_o
5
D
QL
20.0
$16
Reference Case
$20 $24
Oil Price ($/Bbl)
Low Scenario
Medium Scenario
$32
High Scenario
06K00135.RPT
Page IV-65
-------
TABLE IV-29
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT AND OPERATING
EXPENDITURES FOR EOR DEVELOPMENT IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
All Projects
Regulatory Scenario
Reference Case
Low
Medium
High
Total Costs
Incremental Increase
% Change
10,723
10,825
102
1%
5,855
(4,868)
(45%)
5,185
(5,538)
(52%)
Total Costs
Incremental Increase
% Change
26,591
25,910
(681)
(3%)
19,979
(6,612)
(25%)
18,782
(7,809)
(29%)
Total Costs
Incremental Increase
% Change
51,940
48,078
(3,862)
(7%)
46,279
(5,661)
(11%)
41,430
(10,510)
(20%)
Total Costs
Incremental Increase
% Change
131,796
128,519 111,442
(3,277) (20,354)
(2%) (15%)
104,857
(26,939)
(20%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-66
-------
Figure
140,0
Impact of Environmental Regulations on Total
Industry Expenditures on EOR Development In the U.S.
Implemented Technology - Ail Projects
$20 $24
Oil Price ($/Bbl)
Reference Case 111 Low Scenario B Medium Scenario
$32
High Scenario
Page IV-67
-------
price (Table IV-30). Total operating expenditures over the life of economic EOR projects in the reservoirs
analyzed could decrease as much as 55% because of environmental regulations, occurring at $16/Bbl
under the high scenario (Table IV-31).
Under the advanced technology case, increased environmental regulations could change total
industry investment and operating expenditures in the U.S. ranging from a slight increase in expenditures
at $32/Bbl under the low scenario to a 58% decrease in expenditures under the high scenario at $16/Bbl
(Table IV-32 and Figure IV-22). Under the high scenario at high oil prices, industry expenditures in EOR
development under the advanced technology case could decrease by as much as $77 billion. Increased
environmental regulations could result in a change in total industry investment expenditures in EOR
operations ranging from a 22% increase at $32/Bbl under the low scenario to a 41 % decrease under the
high regulatory scenario at $16/Bbl (Table IV-33). Total industry direct operating expenditures over the
life of economic UMO development projects in the three states analyzed under the advanced technology
case could decrease as much as 60% at $16/Bbl under the high scenario (Table IV-34).
d. Summary. The analyses of the impact of environmental initiatives on EOR development
in the U.S. have shown that under most regulatory and oil price scenarios considered, additional crude
oil reserves, otherwise economically viable, may not be developed. This will result in further decreases
in revenues to public sector treasuries, due to foregone taxes collected on production otherwise collected
from EOR operations. In addition, decreased industry expenditures for crude oil development are likely
to result.
Under the low scenario, where, depending on the extent of technology advancement, up to 21%
of otherwise recoverable reserves could be lost. Under the other regulatory scenarios, as much as 53%
of the potentially recoverable EOR reserves in the U.S. will become uneconomic to develop, assuming the
application of current recovery technologies. This could result in as much as a 66% decrease in revenues
to public treasuries due to foregone crude oil development.
The development and introduction of advanced EOR extraction technologies will not completely
help overcome these impacts. Clearly, the advent of advanced recovery technologies will increase the
amount of reserves recoverable from EOR projects under reference conditions. Recoverable reserves
under the advanced technology case are roughly three times that under the implemented technology
case, for most oil prices considered. Nonetheless, under the advanced technology scenario, the impacts
in terms of volumes of reserves lost and portion of reserves impacted are greater than those predicted
under the implemented technology case. Depending on the level of environmental regulations
implemented and the future price of oil, as much as 66% of the potentially recoverable EOR reserves in
06K00135.RPT page jv.68
-------
TABLE IV-30
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT
EXPENDITURES FOR EOR DEVELOPMENT IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
All Projects
Reference Case.
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
831
894
63
8%
670
(161)
(19%)
696
(135)
(16%)
Total Costs
Incremental Increase
% Change
1,952
2,037
85
4%
1,844
(108)
(6%)
2,096
144
7%
Total Costs
Incremental Increase
% Change
3,550
3,597
47
1%
3,950
400
11%
4,003
453
13%
Total Costs
Incremental Increase
% Change
10,135
10,532
397
4%
10,127
(8)
(< 1%)
10,721
586
6%
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-69
-------
TABLE IV-31
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY OPERATING
EXPENDITURES FOR EOR DEVELOPMENT IN THE U.S. - IMPLEMENTED TECHNOLOGY
(Millions of Dollars)
All Projects
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
$20/Bb1
Total Costs
Incremental Increase
% Change
9,892
Total Costs
Incremental Increase
% Change
24,639
48,390
9,931
39
< 1%
23,873
(766)
(3%)
44,481
(3,909)
(8%)
5,185
(4,707)
(48%)
18,135
(6,504)
(26%)
42,329
(6,061)
(13%)
4,489
(5,403)
(55%)
16,686
(7,953)
(32%)
37,427
(10,963)
(23%)
Total Costs
Incremental Increase
% Change
121,661
117,987
(3,674)
(3%)
101,315
(20,346)
(17%)
94,136
(27,525)
(23%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
Page IV-70
-------
TABLE IV-32
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT AND
OPERATING EXPENDITURES FOR EOR DEVELOPMENT IN THE U.S. - ADVANCED TECHNOLOGY
(Millions of Dollars)
All Projects
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
14,149
12,323
(1,826)
(13%)
7,518
(6,631)
(47%)
5,879
8,270
(58%)
Total Costs
Incremental Increase
% Change
59,850
52,956
(6,894)
(12%)
39,286
(20,564)
(34%)
34,598
(25,252)
(42%)
Total Costs
Incremental Increase
% Change
84,570
80,059
(4,511)
(5%)
64,945
(19,625)
(23%)
58,115
(26,455)
(31%)
Total Costs
Incremental Increase
% Change
236,573
236,933
360
< 1%
182,760
(53,813)
(23%)
159,276
(77,297)
(33%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-71
-------
Figure IV-22
250.0
| 200.0
o
Q
§
Impact of Environmental Regulations on Total
Industry Expenditures on EOR Development in the U.S.
Advanced Technology • All Projects
o
Q
- 150.0
£
o>
o
= 100.0
TJ
50.0
Reference Case
Oil Price ($/Bbl)
Low Scenario
$32
Medium Scenario
High Scenario
•P326-24
06K00135.RPT
Page IV-7',
-------
TABLE IV-33
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT
EXPENDITURES FOR EOR DEVELOPMENT IN U.S. - ADVANCED TECHNOLOGY
(Millions of Dollars)
All Projects
Regulatory Scenario
Reference Case Low Medium High
Total Costs 1,503 1,067 919 883
Incremental Increase (436) (584) (620)
% Change (29%) (39%) (41%)
Total Costs 4,681 4,428 3,309 3,575
Incremental Increase (253) (1,372) (1,106)
% Change (5%) (29%) (24%)
Total Costs 6,556 6,445 5,802 5,424
Incremental Increase (111) (754) (1,132)
% Change (2%) (12%) (17%)
Total Costs 16,030 19,588 17,596 17,076
Incremental Increase 3,558 1,556 1,046
% Change 22% 10% 7%
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL Page IV-73
-------
TABLE IV-34
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY OPERATING
EXPENDITURES FOR EOR DEVELOPMENT IN THE U.S. - ADVANCED TECHNOLOGY
{Millions of Dollars)
Atl Projects
Reference Case
Regulatory Scenario
Low
iMedium
High
Total Costs
Incremental Increase
% Change
12,646
11,256
(1,390)
(11%)
'(48%)
Total Costs
Incremental Increase
% Change
55,169
48,528
(6,641)
(12%)
35,977
(19,192)
(35%)
31,,!0)23
(24,146)
(44%)
Total Costs
Incremental Increase
% Change
$32/Bbl
Total Costs
Incremental Increase
% Change
78,014
22Qr543
73,614
(4,400)
(6%)
217,345
(3,198)
0%)
59,143
{18,871)
(24%)
165,164
(55,379)
52,691
(25,323)
(32%)
142,200
(78,343)
(36%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-74
-------
the U.S. will become uneconomic to develop under the advanced technology scenario. This would result
in as much as a 72% decrease in revenues to public treasuries due to foregone development of EOR
projects.
The impact on EOR from the increased costs of environmental regulations is similar to that
impacting the development of the UMO resource. EOR projects also generally require the drilling of
additional production and injection wells; consequently, the incremental compliance costs associated with
this activity will greatly influence project economics.
For the resource potentially recoverable from EOR processes in known Lower-48 onshore fields,
the impact of increased initial capital and annual operating costs are roughly equivalent, similar to that
affecting the UMO resource. Moreover, the combined impact of both incremental capital and annual
operating costs has the greatest affect on reducing potentially recoverable EOR reserves under all
regulatory scenarios considered.
E. Undiscovered Crude Oil Resources
The assessment of undiscovered crude oil resources considered the entire U.S undiscovered
resource base. Unless otherwise noted, no exclusions for land set aside from leasing or currently under
leasing moratoria, such as that in the Arctic National Wildlife Refuge (ANWR) or certain areas off the coast
of California and Florida, were considered. Resources believed to exist in the Lower-48 onshore, Lower-48
offshore, and Alaska (onshore and offshore) were analyzed separately. In addition, this analysis only
considered the conventional primary and secondary recovery of the undiscovered crude oil resource. The
recovery potential of intensive infill drilling or EOR in these undiscovered fields was not evaluated, nor was
the potential associated with advanced recovery technologies in these fields.
1. Analysis of Potential Under Current Regulations
The analyses of undiscovered crude oil resources considered the entire crude oil resource base
remaining to be discovered, as estimated by the USGS for resources that may be onshore and/or under
state waters and by the MMS for resources that are in the OCS. Since the entire resource base is
considered for the undiscovered crude oil resource category, the impacts estimated, in terms of volumes
of resources affected, appear considerable larger than those estimated for the other resource categories.
Depending on oil price, the development of undiscovered crude oil resources under reference
conditions could result in reserve additions ranging from 8.0 billion barrels at an oil price of $16/Bbl to
06K00135.RPT Page IV-75
-------
31.0 billion barrels at $32/Bbl. Onshore Lower-48 resources will contribute reserve additions ranging from
3.1 billion barrels at $16/Bbl to 8.2 billion barrels at $32/Bbl. Offshore Lower-48 resources will contribute
reserve additions ranging from 4.9 billion barrels at $16/Bbl to 7.7 billion barrels at $32/Bbl. No
recoverable reserves exist in Alaska at $16/Bbl, but up to 15.1 billion barrels are potentially recoverable
at $32/Bbl, with both onshore and offshore undiscovered crude oil resources considered. These results
are summarized in Table IV-35 and Figure IV-23.
Projected state and federal revenues from the development of undiscovered crude oil reserves
in the U.S. under reference conditions are shown in Table IV-36. Over the life of these projects, state
revenues from production from these projects could range from $3.8 billion at $16/Bbl to $40.3 billion at
$32/Bbl. At $20/Bbl, state revenues of $8.0 billion are forecast from all undiscovered crude oil reserves
development. Federal revenues, considering only revenues for income taxes and federal royalty payments
(excluding lease bonus payments and rentals), are predicted to range from $29.5 billion at $16/Bbl to
$187.4 billion at $32/Bbl; at $20/Bbl, $50.4 billion in federal revenues could be collected from production
from crude oil prospects which remain to be discovered. Obviously, the bulk of these federal revenues
would be collected as a result of developments in the OCS. Overall, public sector revenues of $58.4
billion could be collected as a result of undiscovered crude oil resource development at $20/Bbl. Public
sector revenues could range from $33.3 billion at $16/Bbl $227.7 billion at $32/Bbl.
2. Impact of Initiatives
a. Reserves Lost. The three regulatory scenarios considered as part of this analysis are
expected to have a significant impact on the economic viability of finding, developing, and producing the
domestic undiscovered crude oil resource base. Under the low regulatory scenario, up to 3.0 billion
barrels of otherwise economic reserves will become uneconomic to develop as the result of increased
environmental regulations, with this maximum impact, in terms of reserves lost, occurring at $32/Bbl. The
greatest impact on undiscovered reserves under the low scenario in terms of the portion of reserves lost
occurs at $16/Bbl, where 12% of recoverable reserves would be lost. For the range of prices considered,
from 1.0 to 3.0 billion barrels could become uneconomic under the low scenario, representing from 8%
to 12% of otherwise economic reserves. These results are summarized in Table IV-37 and in Figure
IV-24.
Under the medium scenario, up to 3.7 billion barrels of otherwise economic reserves could be lost
as the result of increased environmental regulations. The greatest impact on undiscovered reserves under
the medium scenario, in terms of fraction of resource lost, occurs at $16/Bbl, where 25% of otherwise
06K00135.RPT Page IV-76
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TABLE IV-35
INCREMENTAL RESERVE ADDITIONS FROM
UNDISCOVERED CRUDE OIL FIELDS IN THE U.S.
(Millions of Barrels)
Reference Case
Lower-48 Onshore
Lower-48 Offshore
Alaska (Onshore & Offshore)
Total
3,070
4,940
8,010
4,561
5,692
1.344
11,597
6,245
6,993
7.332
20,570
31,037
Numbers may not add precisely due to rounding.
06K00127.TBL
Page IV-77
-------
Figure IV-23
Projected Undiscovered Crude Oil Reserves in the U.S.
35.0
Total U.S. - Reference Case
$16
Lower-48 Onshore
$20 $24
Oil Price ($/Bbl)
Lower-48 Offshore
Alaska (Onshore & Offshore)
«p3 26-25
06KOO135.RPT
Page IV-78
-------
TABLE IV-36
INCREMENTAL STATE AND FEDERAL REVENUES
FROM UNDISCOVERED CRUDE OIL DEVELOPMENT IN THE U.S.
(Millions of Dollars)
Reference Case
State Revenues:
Lower-48 Onshore
Lower-48 Offshore
Alaska
Total State
Federal Revenues:
Lower-48 Onshore
Lower-48 Offshore
Alaska
Total Federal
Total Revenues
Lower-48 Onshore
Lower-48 Offshore
Alaska
$16/Bbl
3,810
3,810
5,232
24,234
29,466
9,042
24,234
$20/Bbl
7,151
850
8,001
11,170
36,025
3.164
50,359
18,320
36,025
4.014
$24/Bbl
11,733
6,649
18,382
19,182
53,309
20,028
92,519
30,915
53,309
26,677
mm
20,395
19,882
40,277
36,422
83,034
67,928
187,384
56,817
83,034
87,810
Total
33,276
58,359
110,901
227,661
06K00127.TBL
Page IV-79
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TABLE IV-37
IMPACT OF ENVIRONMENTAL REGULATIONS
ON UNDISCOVERED RESERVES IN THE U.S.
(Millions of Barrels)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Reserves 8,010 7,051 6,038 5,103
Incremental Decrease 959 1,972 2,907
% 12% 25% 36%
$20/Bbl
Reserves 11,597 10,603 9,501 6,714
Incremental Decrease 994 2,096 4,883
% 9% 18% 42%
$24/Bbl
Reserves 20,570 18,855 17,117 12,728
Incremental Decrease 1,715 3,453 7,842
% 8% 17% 38%
$32/Bbl
Reserves 31,037 28,019 27,381 24,239
Incremental Decrease 3,018 3,656 6,798
% 10% 12% 22%
7.TBL Page IV-80
-------
Figure IV-24
35.0
30.0 -
25.0 -
20.0 -
15.0
10.0 -
5.0 -
CD
.g
m
^^r
CO
-------
recoverable reserves could be lost. For the range of prices considered, from 2.0 to 3.7 billion barrels
could become uneconomic, representing from 17% to 25% of otherwise recoverable reserves.
Finally, under the high scenario, up to 7.8 billion barrels of otherwise economic reserves could
be lost. The greatest impact on undiscovered reserves under the medium scenario, in terms of fraction
of reserves lost, occurs at $20/Bbl, where 42% of recoverable reserves could be lost. From 2.9 to 7.8
billion barrels could become uneconomic, representing from 22% to 42% of otherwise recoverable
reserves.
The increased regulations will have the greatest impact on undiscovered crude oil reserves in the
onshore Lower-48. As shown in Table IV-38 and in Figure IV-25, from 17% to 27% of reserves could be
lost under the low scenario; from 25% to 51 % of reserves could be lost under the medium scenario, and
in the high scenario, increased environmental regulations could result in from 29% to 66% of the otherwise
recoverable reserves becoming uneconomic. In terms of volumes of reserves lost, from 0.7 to 1.7 billion
barrels could be lost under the low scenario, from 1.6 to 2.4 billion barrels could be lost in the medium
scenario, and from 1.6 to 3.5 billion barrels could become uneconomic in the high regulatory scenario.
The greatest impact, in terms of volume of reserves lost, are predicted to occur at prices of $20 to
$24/Bbl; in terms of fraction of reserves lost, the greatest impacts occur at prices below $24/Bbl.
The impact on offshore Lower-48 reserves, compared to undiscovered crude oil reserves in the
onshore Lower-48, are relatively small under the low and medium regulatory scenarios, as shown in Table
IV-39 and Figure IV-26. In the offshore, the increased costs of environmental compliance make up a
smaller portion of total project costs. Consequently, the environmental initiatives have only a small impact
on project economics. In terms of volumes of reserves lost, up to 0.4 billion barrels could be lost under
the low and medium scenarios. The greatest impact in terms of volume of reserves lost occurs at $16/Bbl.
In terms of fraction of reserves lost, the greatest impacts are at also at lower oil prices, below $20/Bbl,
where up to 8% of the otherwise recoverable reserves could be lost.
Under the high regulatory scenario, however, the impacts of increased regulations on
undiscovered crude oil reserves are considerably greater. From 0.1 to 1.3 billion barrels of reserves could
be lost, with the greatest impact occurring at low (around $16/Bbl) oil prices, where as much as 27% of
reserves could become uneconomic.
Finally, increased regulations could also have a small impact on Alaska crude oil resources,
compared to undiscovered crude oil resources in the Lower-48 onshore. It should be noted, however,
that in this analysis, incremental environmental compliance costs in Alaska, with the exception the
06K00135.RPT page |V-82
-------
TABLE IV-38
IMPACT OF ENVIRONMENTAL REGULATIONS ON
UNDISCOVERED RESERVES IN THE LOWER-48 ONSHORE
(Millions of Barrels)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Reserves 3,070 2,330 1,489 1,489
Incremental Decrease 740 1,581 1,581
% 24% 51% 51%
$20/Bbl
Reserves 4,561 3,567 2,465 1,548
Incremental Decrease 994 2,096 3,013
% 22% 46% 66%
$24/Bbl
Reserves 6,245 4,561 3,880 2,725
Incremental Decrease 1,684 2,365 3,520
% 27% 38% 56%
$32/Bbl
Reserves 8,184 6,810 6,177 5,791
Incremental Decrease 1,374 2,007 2,393
% 17% 25% 29%
06K00127.TBL Page IV-83
-------
Figure IV-25
1
_o
fi
-------
TABLE IV-39
IMPACT OF ENVIRONMENTAL REGULATIONS ON
UNDISCOVERED RESERVES IN THE LOWER-48 OFFSHORE
(Millions of Barrels)
$16/Bbl
Reserves
Incremental Decrease
%
$20/Bbl
Reserves
Incremental Decrease
%
$24/Bbl
Reserves
Incremental Decrease
%
$32/Bbl
Reserves
Incremental Decrease
%
Requlatorv
Reference Case Low
4,940 4,721
219
4%
5,692 5,692
—
-
6,993 6,962
31
< 1%
7,730 7,730
~
—
Scenario
Medium
4,549
391
8%
5,692
--
--
6,801
192
3%
7,724
6
< 1%
High
3,614
1,326
27%
4,721
971
17%
5,686
1,307
19%
7,614
116
2%
06K00127.TBL
Page IV-85
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Figure IV-26
35.0
30.0
«S 25.0
_o
£• 20.0
I
(D
b
15.0
10.0
5.0
Impact of Environmental Regulations on
Undiscovered Crude Oil Reserves in the U.S.
Lower-48 Offshore
$20 $24
Oil Price ($/Bbl)
ep3 26-28
06K00135.RPT
-------
management and disposal costs for drilling muds and cuttings, were assumed to be the same as those
in the Lower-48. No unit compliance cost data explicitly appropriate for Alaska conditions were available
for this study. However, it is likely that environmental compliance costs in Alaska will be considerable
greater than those in the Lower-48. Therefore, the analysis of Alaska in this assessment will likely
represent an underestimate of the impacts of environmental regulations on Alaskan crude oil supplies.
As shown in Table IV-40 and Figure IV-27, impacts on Alaskan undiscovered crude oil reserves
are relatively small under the low and medium scenarios. Like the Lower-48 offshore, the increased costs
of environmental compliance make up a smaller portion of total project costs; thus, the environmental
initiatives considered for these scenarios in this analysis have only a small impact gn project economics.
In terms of volumes of reserves lost, up to 1.6 billion barrels could be lost under the low and medium
scenarios. The greatest impact in terms of the volume of reserves lost occur at higher oil prices of
$32/Bbl. In terms of fraction of reserves lost, the greatest impacts occur at lower oil prices (below
$20/Bbl), where up to 12% of the otherwise recoverable reserves would be lost. No impacts are felt at
low oil prices, because reserves at low prices under baseline conditions are small, and those that are
economic are sufficiently profitable that increased environmental costs can be incurred with no major
impact on economic viability.
Under the high scenario, on the other hand, the impacts of increased regulations on undiscovered
crude oil reserves in Alaska are considerably greater. From 0.9 to 4.3 billion barrels of reserves could be
lost, with the greatest impact, in terms of the fraction of otherwise recoverable reserves impacted,
occurring at relatively low ($20/Bbl) prices, where as much as two-thirds of reserves could become
uneconomic.
Economically recoverable undiscovered crude oil reserves are summarized by resource category
(Lower-48 onshore, Lower-48 offshore, and Alaska), regulatory scenario, and crude oil price in Table
IV-41.
b. Public Sector Revenues Lost. The low scenario would result in lost public sector revenues
(federal and state) from undiscovered crude oil development in the Lower-48 onshore of as much as $9.0
billion. Depending on oil prices, public sector revenues could decrease by as much as 37% at low oil
prices ($16/Bbl) (Table IV-42 and Figure IV-28). Under the medium scenario, from $5.1 to $17.2 billion
could be lost, a 30% to 56% loss in revenues from the development of undiscovered crude oil in the U.S.
Lower-48 onshore. Finally, under the high regulatory scenario, $5.2 to $20.5 billion could be lost to public
treasuries, a 36% to 66% loss. As shown in Table IV-42, the percentage of revenues lost are highest at
lower prices (below $20/Bbl) oil prices.
06K00135.RPT Page IV-87
-------
TABLE IV-40
IMPACT OF ENVIRONMENTAL REGULATIONS ON
UNDISCOVERED RESERVES IN ALASKA (ONSHORE AND OFFSHORE)
(Millions of Barrels)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Reserves
Incremental Decrease
$20/Bbl
Reserves 1,344 1,344 1,344 445
Incremental Decrease - -- 899
% -- -- 67%
$24/Bbl
Reserves 7,332 7,332 6,436 4,317
Incremental Decrease -- 896 3,015
% - 12% 41%
$32/Bbl
Reserves 15,122 13,479 13,479 10,832
Incremental Decrease 1,643 1,643 4,288
% 11% 11% 28%
Page IV-88
-------
Figure IV-27
35.0
Impact of Environmental Regulations on
Undiscovered Crude Oil Reserves in the U.S.
Alaska (Onshore and Offshore)
CO
1
(0
CO
30.0 -
25.0 -
LLJ
CO
CD
1
OJ
Incremer
20.0
15.0
10.0
5.0
n
—
—
I " {'-'"I
$16
Reference Case
$20 $24
Oil Price ($/Bbl)
$32
Low Scenario , \ Medium Scenario
High Scenario
•P326-29
06K00135.RPT
-------
TABLE IV-41
IMPACT OF ENVIRONMENTAL REGULATIONS ON INCREMENTAL
RESERVES FROM UNDISCOVERED CRUDE OIL FIELDS IN THE U.S.
(Million Barrels)
Oil Price
($/Bbl)
1 6 Reference
Low
Medium
High
20 Reference
Low
Medium
High
24 Reference
Low
Medium
High
32 Reference
Low
Medium
High
Total
8,010
7,051
6,038
5,103
11,597
10,603
9,501
6,714
20,570
18,855
17,117
12,728
31,037
28,019
27,381
24,239
Lower-48
Onshore
3,070
2,330
1,489
1,489
4,561
3,567
2,465
1,548
6,245
4,561
3,880
2,725
8,184
6,810
6,177
5,791
Lower-48
Offshore*
4,940
4,721
4,549
3,614
5,692
5,692
5,692
4,721
6,993
6,962
6,801
5,686
7,730
7,730
7,724
7,614
Alaska
—
—
--
—
1,344
1,344
1,344
445
7,332
7,332
6,436
4,317
15,122
13,479
13,479
10,834
Numbers may not add precisely due to rounding.
* Federal waters only
06K00127.TBL
Page IV-90
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TABLE IV-42
IMPACT OF ENVIRONMENTAL REGULATIONS ON PUBLIC SECTOR REVENUES
FROM UNDISCOVERED RESERVES DEVELOPMENT IN THE LOWER-48 ONSHORE
(Millions of Dollars)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Revenues 9,042 5,686 3,953 3,860
Incremental Decrease 3,356 5,089 5,182
% 37% 56% 57%
$20/Bbl
Revenues 18,320 14,288 8,816 6,181
Incremental Decrease 4,032 9,504 12,139
% 22% 52% 66%
$24/Bbl
Revenues 30,915 23,298 17,319 12,979
Incremental Decrease 7,617 13,596 17,936
% 25% 44% 58%
$32/Bbl
Revenues 56,817 47,823 39,573 36,277
Incremental Decrease 8,994 17,244 20,540
% 16% 30% 36%
06K00127.TBL Page IV-91
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o
CO
0)
3
I
cc
(0
u
5
Q_
Figure \V-28
Impact of Environmental Regulations on Total Public Sector
Revenues from Undiscovered Crude Oil
Development in the U.S.
250.0
200.0
Si 150.0
100.0
50.0
$16
Reference Case
$20 $24
Oil Price ($/Bbl)
$32
Low Scenario
Medium Scenario
High Scenario
Op3 26-30
06K00135.RPT
Page IV-92
-------
Lost public sector revenues from foregone undiscovered crude oil development in the Lower-48
offshore are significantly smaller than that forecast for the onshore Lower-48, especially under the low and
medium scenarios. For example, the low scenario would result in lost revenues from undiscovered crude
oil development in the Lower-48 offshore ranging from $162 to $907 million. Depending on oil prices,
public sector revenues could decrease by only as much as 4% (Table IV-43). Under the medium
scenario, from $0.3 to $1.7 billion could be lost, a 1% to 7% loss in revenues. Under the high scenario,
the impacts are somewhat greater, where $6.3 to $19.1 billion could be lost to public treasuries, a 17%
to 28% loss of revenues that would have been collected under the reference scenario. As shown in Table
IV-43, the percentage of revenues lost are highest at lower prices (below $20/Bbl).
Lost public sector revenues from foregone undiscovered crude oil development in the Alaska are
similar to those experienced in the offshore Lower-48. Under the low scenario, public sector revenues
from undiscovered crude oil development in the Alaska could decrease by as much as $7.3 billion, an 8%
loss in revenues at $32/Bbl (Table IV-44). Under the medium scenario, from $0.1 to $9.7 billion could be
lost, a 3% to 14% loss in revenues from the development of undiscovered crude oil in Alaska. Under the
high scenario, the impacts are again somewhat greater, where from $2.6 to $26.0 billion could be lost to
public treasuries, a 30% to 64% loss. As shown in Table IV-44, the percentage of public revenues lost
are highest at higher oil prices (above $20/Bbl), since in Alaska, only a small amount of resources are
economic at low prices, even under reference conditions.
c. Impact on Industry Expenditures. Increased environmental regulations could greatly
impact total industry investment and operating expenditures for developing domestic undiscovered crude
oil reserves. These impacts could range from a 12% decrease in expenditures at an oil price of $20/Bbl
under the low regulatory scenario to a 53% decrease in expenditures under the high regulatory scenario
at the same price (Table IV-45 and Figure IV-29). The change in total investment expenditures in
undiscovered crude oil developments in the U.S. could range from a 11% decrease at $24/Bbl under the
low regulatory scenario to a 49% decrease in expenditures under the high regulatory scenario at $20/Bbl
(Table IV-46). Total operation expenditures over the life of economic undiscovered crude oil development
projects in the U.S. could decrease as much as 63%, at $20/Bbl under the high regulatory scenario (Table
IV-47). Overall, increased environmental regulations could result in a maximum decrease of expenditures
for undiscovered crude oil exploration and development of as much as $89 billion at an oil price of
$24/Bbl.
d. Summary. Increased environmental regulations will have a significant impact on
undiscovered crude oil reserves under all regulatory scenarios and oil prices considered. Under the low
scenario, up to 10% of undiscovered reserves will become uneconomic to find and develop. Most of the
06K00135.RPT Page IV-93
-------
TABLE IV-43
IMPACT OF ENVIRONMENTAL REGULATIONS ON PUBLIC SECTOR REVENUES
FROM UNDISCOVERED RESERVES DEVELOPMENT IN THE LOWER-48 OFFSHORE
(Millions of Dollars)
Reference Case
Regulatory Scenario
Low
Medium
High
$16/Bbl
Revenues
Incremental Decrease
$20/Bbl
Revenues
Incremental Decrease
$24/Bbl
Revenues
Incremental Decrease
$32/Bbl
Revenues
Incremental Decrease
24,234
36,025
53,309
83,034
23,332
902
4%
35,863
162
< 1%
52,905
404
1%
82,722
312
< 1%
22,485
1,749
7%
35,715
310
1%
51,828
1,481
3%
82,339
695
1%
17,546
6,688
28%
29,740
6,285
17%
43,454
9,855
18%
63,975
19,059
23%
06K00127.TBL
Page IV-94
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TABLE IV-44
IMPACT OF ENVIRONMENTAL REGULATIONS ON PUBLIC SECTOR REVENUES
FROM UNDISCOVERED RESERVES DEVELOPMENT IN ALASKA
(Millions of Dollars)
Regulatory Scenario
Reference Case Low Medium High
$16/Bbl
Revenues
Incremental Decrease
$20/Bbl
Revenues 4,014 3,974 3,911 1,464
Incremental Decrease 40 103 2,550
% 1% 3% 64%
$24/Bbl
Revenues 26,677 26,489 22,942 15,345
Incremental Decrease 188 3,735 11,332
% 1% 14% 42%
$32/Bbl
Revenues 87,810 80,499 78,158 61,841
Incremental Decrease 7,311 9,652 25,969
% 8% 11% 30%
06K00127.TBL Page IV-95
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TABLE IV-45
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT AND
OPERATING EXPENDITURES FOR UNDISCOVERED CRUDE OIL DEVELOPMENT IN THE U.S.
(Millions of Dollars)
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
55,188
39,883
(15,305)
(28%)
34,771
(20,417)
(37%)
29,874
(25,314)
(46%)
Total Costs
Incremental Increase
% Change
98,228
86,414
(11,814)
(12%)
74,004
(24,224)
(25%)
46,438
(51,790)
(53%)
Total Costs
Incremental Increase
% Change
193,879
169,005
(24,874)
(13%)
156,427
(37,452)
(19%)
104,415
(89,464)
(46%)
Total Costs
Incremental Increase
% Change
387,875
334,142
(53,733)
14%)
339,473
(48,402)
•(12%)
304,652
(83,223)
(21%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-96
-------
Figure IV-29
300.0
250.0 -
o
= 200.0
CO
2
=6 150.0
0)
100.0 -
in
•o
% 50.0 -
Impact of Environmental Regulations on Total
Industry Expenditures for Undiscovered Crude Oil
Development in the U.S.
$16
Reference Case
$20 $24
Oil Price ($/Bbl)
Low Scenario
Medium Scenario
High Scenario
•p32«-31
06K00135.RPT
Page IV-97
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TABLE IV-46
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY INVESTMENT
EXPENDITURES FOR UNDISCOVERED CRUDE OIL DEVELOPMENT IN THE U.S.
(Millions of Dollars)
Reference Case
Regulatory Scenario
Low
Medium
High
Total Costs
Incremental Increase
% Change
39,851
30,503
( 9,348)
( 23%)
26,796
( 13,055)
( 33%)
22,521
(17,330)
( 43%)
Total Costs
Incremental Increase
% Change
70,767
63,247
( 7,520)
( 11%)
54,878
( 15,889)
( 22%)
36,166
(34,601)
( 49%)
Total Costs
Incremental Increase
% Change
142,009
125,756
(16,253)
( 11%)
114,789
( 27,220)
( 19%)
77,047
(64,962)
( 46%)
Total Costs
Incremental Increase
% Change
288,084
248,688
( 39,396)
( 14%)
250,726
( 37,358)
( 13%)
225,735
( 62,349)
( 22%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-98
-------
TABLE IV-47
IMPACT OF ENVIRONMENTAL REGULATIONS ON TOTAL INDUSTRY DIRECT OPERATING
EXPENDITURES FOR UNDISCOVERED CRUDE OIL DEVELOPMENT IN THE U.S.
(Millions of Dollars)
Reference Case
Reaulatory Scenario
Low Medium
High
Total Costs
Incremental Increase
% Change
15,337
9,380
( 5,957)
( 39%)
7,975
( 7,362)
( 48%)
7,353
( 7,994)
( 52%)
Total Costs
Incremental Increase
% Change
27,461
23,167
( 4,294)
( 16%)
19,126
( 8,335)
( 30%)
10,272
(17,189)
( 63%)
Total Costs
Incremental Increase
% Change
51,870
43,429
( 8,441)
( 16%)
41,638
(10,232)
( 20%)
27,368
(24,502)
( 47%)
Total Costs
Incremental Increase
% Change
99,791
85,454
(14,337)
( 14%)
88,747
(11,044)
( 11%)
78,917
(20,874)
( 21%)
Note: Parentheses indicate a negative change, or decrease in expenditures.
06K00127.TBL
Page IV-99
-------
impact will be on undiscovered crude oil reserves in the Lower-48 onshore, the impacts on offshore and
Alaska reserves will be considerably less significant. Because of the very high costs associated with
finding and developing crude oil reserves in the offshore and in Alaska, the incremental compliance costs
associated with these resource categories, under the low and medium scenarios, are small relative to
overall project costs. Therefore, the impact of these increased compliance costs have less an effect than
that experienced by onshore undiscovered crude oil development activities.
The increased costs under the high scenario will have significant impact on all undiscovered
resource categories considered. Under the high scenario, up to two-thirds of domestic undiscovered
reserves will become uneconomic to find and develop. Corresponding public sector revenues for this
foregone development will be significant. In total, public sector revenues lost could decrease by as much
as $89 billion at an oil price of $24/Bbl.
Page IV-100
-------
V. CONCLUSIONS
This assessment of potential U.S. environmental initiatives and their impact on U.S. crude oil
supplies reviewed selected regulatory initiatives that could affect U.S. oil and gas E&P operations. It
examined the nature of and estimated incremental compliance costs associated with these initiatives, and
estimated the energy and economic impacts of these initiatives on U.S. crude oil supplies.
Regulatory initiatives were considered under the authority of the Resource Conservation and
Recovery Act, the Safe Drinking Water Act, the Clean Water Act, and the Clean Air Act. From a review
of these initiatives, three regulatory scenarios were developed, representing low, medium, and high levels
of incremental compliance costs, to account for a range of costs associated with the regulatory initiatives
under consideration.
The economic recovery potential of the various crude oil resource categories considered at four
constant crude oil prices - $16, $20, $24, and $32 per barrel. Four categories of U.S. crude oil supplies
were evaluated: oil recoverable from the continued conventional production of crude oil in known fields
in the Lower-48 onshore, oil recoverable from future infill drilling and waterflood projects in known fields
in the Lower-48 onshore, oil recoverable from future enhanced oil recovery projects in known fields in the
Lower-48 onshore, and oil recoverable from onshore and offshore crude oil fields remaining to be
discovered in the Lower-48 and Alaska.
The estimated impacts correspond only to the resource analyzed in each resource category,
which in most cases represented less than the entire U.S. resource base. No attempt was made to
extrapolate the results. The resource considered in each case corresponds to the extent and quality of
the data available.
The overall results of this assessment, for all resource categories considered, are summarized in
Tables V-1 through V-4 for each of the four oil price scenarios considered. The results show that for all
oil prices, resource categories, levels of technology, and environmental regulatory scenarios evaluated,
considerable amounts of crude oil reserves could become uneconomic to develop as the result of
increased costs of environmental compliance, and that these regulations can lead to the accelerated
abandonment of the existing, accessible domestic reserves.
The results of this analysis lead to the following major conclusions:
06K00135.RPT Page V-1
-------
TABLE V-1
IMPACT OF POTENTIAL ENVIRONMENTAL REGULATIONS
ON U.S. CRUDE OIL SUPPLIES AT AN OIL PRICE OF $16/BBL
Level of Assessment
Implemented Technology
Resource Lost (%)
Low Scenario
Medium Scenario
High Scenario
Public Sector Revenues Lost (%)
Low Scenario
Medium Scenario
High Scenario
Resource Category
Conventional
Production*
Nine States**
3
21
26
n/a
n/a
n/a
Unrecovered
Mobile Oil
Texas, Oklahoma
and New Mexico
Enhanced Oil
Recovery
Lower 48 States
(Onshore)
Undiscovered
Entire U.S.
4
21
26
7
29
34
46
53
4
58
72
12
25
36
13
21
36
Advanced Technology
Resource Lost (%)
Low Scenario
Medium Scenario
High Scenario
Public Sector Revenues Lost (%)
Low Scenario
Medium Scenario
High Scenario
n/a
n/a
n/a
n/a
n/a
n/a
4
14
24
5
21
32
21
51
66
32
58
84
n/a
n/a
n/a
n/a
n/a
n/a
n/a = not analyzed
* Represents incremental resource lost (over the reference case) immediately from premature abandonment
** California, Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and Wyoming
OfoKOOlZ/. IBL
Page V-2
-------
TABLE V-2
IMPACT OF POTENTIAL ENVIRONMENTAL REGULATIONS
ON U.S. CRUDE OIL SUPPLIES AT AN OIL PRICE OF S20/BBL
Resource Category
Conventional Unrecovered Enhanced Oil
Production* Mobile Oil Recovery Undiscovered
Level of Assessment Nine States** Texas, Oklahoma Lower 48 States Entire U.S.
and New Mexico (Onshore)
Implemented Technology
Resource Lost (%)
Low Scenario 2 16 3 9
Medium Scenario 23 35 24 18
High Scenario 30 43 29 42
Public Sector Revenues Lost (%)
Low Scenario n/a 16 5 7
Medium Scenario n/a 35 32 17
High Scenario n/a 45 40 36
Advanced Technology
Resource Lost (%)
Low Scenario n/a 6 11 n/a
Medium Scenario n/a 24 36 n/a
High Scenario n/a 28 42 n/a
Public Sector Revenues Lost (%)
Low Scenario n/a 7 15 n/a
Medium Scenario n/a 26 42 n/a
High Scenario n/a 31 47 n/a
n/a = not analyzed
* Represents incremental resource lost (over the reference case) immediately from premature abandonment
** California, Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and Wyoming
06K00127.TBL Page V-3
-------
TABLE V-3
IMPACT OF POTENTIAL ENVIRONMENTAL REGULATIONS
ON U.S. CRUDE OIL SUPPLIES AT AN OIL PRICE OF $24/BBL
Resource Category
Conventional Unrecovered Enhanced Oil
Production* Mobile Oil Recovery Undiscovered
Level of Assessment Nine States** Texas, Oklahoma Lower 48 States Entire U.S.
and New Mexico (Onshore)
Implemented Technology
Resource Lost (%)
Low Scenario 11 78
Medium Scenario 17 25 11 17
High Scenario 29 34 23 38
Public Sector Revenues Lost (%)
Low Scenario n/a 5 10 7
Medium Scenario n/a 30 18 17
High Scenario n/a 38 28 35
Advanced Technology
Resource Lost (%)
Low Scenario n/a 5 5 n/a
Medium Scenario n/a 22 20 n/a
High Scenario n/a 28 32 n/a
Public Sector Revenues Lost (%)
Low Scenario n/a 7 6 n/a
Medium Scenario n/a 26 23 n/a
High Scenario n/a 32 37 n/a
n/a = not analyzed
* Represents incremental resource lost (over the reference case) immediately from premature abandonment
California, Colorado, "Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and Wyoming
**
06K00127.TBL Page v-4
-------
TABLE V-4
IMPACT OF POTENTIAL ENVIRONMENTAL REGULATIONS
ON U.S. CRUDE OIL SUPPLIES AT AN OIL PRICE OF S32/BBL
Resource Category
Conventional Unrecovered Enhanced Oil
Production* Mobile Oil Recovery Undiscovered
Level of Assessment Nine States** Texas, Oklahoma Lower 48 States Entire U.S.
and New Mexico (Onshore)
Implemented Technology
Resource Lost (%)
Low Scenario 2 3 3 10
Medium Scenario 20 21 15 12
High Scenario 29 25 20 22
Public Sector Revenues Lost (%)
Low Scenario n/a 5 47
Medium Scenario n/a 26 19 12
High Scenario n/a 32 25 29
Advanced Technology
Resource Lost (%)
Low Scenario n/a 6 1 n/a
Medium Scenario n/a 14 20 n/a
High Scenario n/a 21 29 n/a
Public Sector Revenues Lost (%)
Low Scenario n/a 7 2 n/a
Medium Scenario n/a 20 24 n/a
High Scenario n/a 27 36 n/a
n/a = not analyzed
* Represents incremental resource lost (over the reference case) immediately from premature abandonment
** California, Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma, Texas, and Wyoming
06K00127.TBL Page V-5
-------
New environmental requirements could substantially decrease the future recovery
potential from all resource categories considered.
• Abandonment of remaining resources in known, producing oil reservoirs could be
accelerated by approximately 10 years.
The evaluated environmental scenarios have important implications for DOE-sponsored
research and development, as the increased costs of compliance reduces recovery under
both implemented and advanced technology conditions.
The results of this assessment clearly demonstrate that increased regulations on U.S. crude oil
E&P operations can have a significant impact on the potential recovery of future crude oil supplies and
U.S. energy security. The extent of regulations imposed clearly will determine the level of impact, but
significant impacts result over a wide range of regulations, over a wide range of crude oil prices, and at
both current and advanced levels of development for extraction technologies. All resource categories
result in lost reserves due to environmental regulations, when compared to reference conditions. In many
cases, over 50% of otherwise recoverable reserves could become uneconomic to produce.
The resulting losses in future U.S. crude oil supplies will have associated impacts in terms of
decreased tax revenues, fewer oil field jobs, and increased levels of crude oil imports. Moreover, the
ability of the U.S. petroleum industry to compete in the world oil market could be significantly diminished.
UDMJUl.3o.nrl
Page V-6
-------
VI. REFERENCES
AAPG, "North American Drilling Activity in 1987" (along with previous years), American Association
of Petroleum Geologists Bulletin. Vol. 20, No. 20 (October 1988).
American Petroleum Institute, Quarterly Completion Report, Fourth Quarter, 1987. February 1988.
American Petroleum Institute, 1988 Joint Association Survey on Drilling Costs. October 1989.
Arscott, R.L, "New Directions in Environmental Protection in Oil and Gas Operations,' Journal of
Petroleum Technology. April 1989.
Dougherty, Rae Ann, "SARA Title III: A Petroleum Industry Perspective," paper presented at the
Annual Meeting of the Interstate Oil Compact Commission, Overland Park, Kansas, December 4-7,
1988.
Economic Analysis, Inc., Economic Analysis of Proposed EPA Regulations on Drilling Fluids and
Cuttings: Offshore Oil and Gas Industry, report prepared for the American Petroleum Institute,
December 31, 1988.
Entropy Limited, Aboveground Storage Tank Survey, report prepared for the American Petroleum
Institute, April 1989.
Environmental Protection Agency, Management of Wastes from the Exploration, Development, and
Production of Crude Oil. Natural Gas and Geothermal Energy. Report to Congress, December
1987.
Environmental Protection Agency, Economic Impact Analysis of Proposed Effluent Limitation
Standards for the Offshore Oil and Gas Industry, EPA 44D/2-85-003, July 1985.
Environmental Protection Agency, Underground Injection Control Branch, Office of Drinking Water,
Mid-Course Evaluation of the Class II Underground Injection Control Program: Final Report of the
Mid-course Evaluation Workgroup. August 22, 1989.
ERT, Exploration and Production Waste Economic Analysis, Phase 1 Report. Document No. 0300-
011-004 report, prepared for the American Petroleum Institute, August 1988.
Gruy Engineering Corporation, Midcourse Evaluation Economics Study Phases I. II. and III:
Estimated Costs for Certain Proposed Revisions in the Underground Injection Control Regulations
for Class II Injection Wells, report prepared for the American Petroleum Institute, June 9, 1989.
ICF, Summary and Discussion of Analysis and Discussion Paper: Alternative Reporting
Thresholds, Costs, and Small Business Impacts of Extending Coverage Under SARA Section 311
and 312 to Non-Manufacturers, submitted to the EPA Office of Solid Waste and Emergency
Response, August 8, 1988.
ICF, Technical Support Document - Onshore Oil and Gas Exploration. Development, and
Production: Human Health and Environmental Risk Assessment, report prepared for the Office
of Solid Waste, U.S. Environmental Protection Agency, December 1987.
06K00135.RPT Page VI-1
-------
ICF-Lewin Energy, The Economic Impact of Proposed Regulations on the Discharge of Drilling
Muds and Cuttings from Offshore Facilities on U.S. Undiscovered Crude Oil Reserves, report
prepared for the U.S. Department of Energy, Office of Fossil Energy, January 13, 1989.
ICF-Lewin Energy, The Impact of Increased Waste Management Regulations on the Economics
of Developing U.S. Undiscovered Crude Oil Resources, report prepared for the U.S. Department
of Energy, Office of Fossil Energy, March 1988.
ICF-Lewin Energy, A Model for the Economic Analysis of U.S. Undiscovered Crude Oil Resources
in the Lower-48 Offshore, report prepared for the U.S. Department of Energy, Office of Fossil
Energy, June 1988.
ICF Resources Incorporated and the Bureau of Economic Geology, University of Texas at Austin,
Producing Unrecovered Mobile Oil: Evaluation of the Potentially Economically Recoverable
Reserves in Texas, Oklahoma, and New Mexico, report prepared for the U.S Department of
Energy, May 1989.
Independent Petroleum Association of America (IPAA), The Oil and Natural Gas Producing
Industry in Your State. 1989-1990, Petroleum Independent. September 1989.
Interstate Oil Compact Commission, An Evaluation of the Known Remaining Oil Resource in the
State of Texas, November 1989.
Interstate Oil Compact Commission, The Potential of Enhanced Oil Recovery in Oklahoma. April
1987.
Jones, Jeff, Gary Marfin, and Lisa Hoffman, An Analysis of Petroleum Industry Costs Associated
With Air Toxics Amendments to the Clean Air Act, report prepared for The American Petroleum
Institute, Interim Final Report, October 17, 1989.
Kuuskraa, V.A., F. Morra, Jr. and M.L. Godec, 'Importance of Cost/Price Relationships for Least
Cost Oil and Gas Reserves,' SPE Paper No. 16289 presented at the 1987 SPE Hydrocarbon
Economics and Evaluation Symposium, Dallas, Texas, March 2-3, 1987.
Lai, Manohar and Neal Thurber, 'Drilling Wastes Management and Closed-Loop Systems," in
Drilling Wastes, Engelhardt and others, ed., Elsevier Applied Science, London and New York,
1989, pp. 213-228.
Larry Browning Geological Engineering Specialties (LBGES), Technical Criteria and Costs of UIC
Class 2 Midcourse Issues Part 1: Temporary Abandonment, Area of Review, and Corrective
Action,' (Draft), report prepared for the Environmental Protection Agency, November 8, 1988.
Larry Browning Geological Engineering Specialties (LBGES), 'Cost Estimates of Proposed
Completion Requirements for Class 2 Injection Wells,1 (Preliminary), report prepared for the
Environmental Protection Agency, April 10, 1989a.
Larry Browning Geological Engineering Specialties (LBGES), 'Cost Estimates of Mechanical
Integrity Testing for Class 2 Injection Wells," (Draft), report prepared for the Environmental
Protection Agency, April 12, 1989b.
Lewin and Associates, Inc., Estimated Impacts of the Proposed NSPS Regulations on the
Reinjection of Produced Water from Offshore Oil Production Facilities, report prepared for the U.S.
Department of Energy, Office of Fossil Energy, March 10, 1986.
uoK.ocn3o.Hrr PageVI-2
-------
Lewin and Associates, Inc., Replacement Costs of Domestic Crude Oil: Supply Analysis
Methodology, report prepared for the U.S. Department of Energy, Office of Fossil Energy, July
1985.
Michie & Associates, Inc., Oil and Gas Industry Water Injection Well Corrosion, report prepared
for the American Petroleum Institute, February 1988.
National Petroleum Council, Enhanced Oil Recovery, June 1984.
Randolph, Thomas M. and Jay P, Simpson, Offshore Effluent Guidelines Drilling Discharge
Regulatory Import Model, December 1988.
Roy F. Weston, Inc., The University of Massachusetts, Environmental Science Program, Division
of Public Health, Remedial Technologies for Leaking Underground Storage Tanks, Lewis
Publishers, 1988.
U.S. Department of Energy/Fossil Energy, Office of Oil, Gas, Shale, and Special Technologies, Oil
Research Program Implementation Plan, April 1990.
U.S. Department of Energy, Bartlesville Project Office, Abandonment Rates of the Known Domestic
Oil Resource. April 1989.
U.S. Department of Interior, U.S. Geological Survey, Minerals Management Service, Estimates of
Undiscovered Conventional Oil and Gas Resources in the United States -- A Part of the Nation's
Energy Endowment, U.S. Government Printing Office, 1989.
Walk, Haydel and Associates, Inc., Economic Impact Estimate of the Proposed Effluent Limitation
Guidelines and New Source Performance Standards, Summary Report No. 18, WH&A Job No.
3504, February 16, 1986.
Walk, Haydel & Associates, Inc., Potential Impacts of Proposed BAT/NSPS Standards for
Produced Water Discharges from Offshore Oil and Gas Extraction Industry, report prepared for
the American Petroleum Institute, Offshore Operations Committee, January 1984.
Walk, Haydel & Associates, Inc., Water-Based Drilling Fluids and Cuttings Disposal Study Update,
WH&A Job No. 3778, January 1989.
Wakim, Paul G., API 1985 Production Waste Survey; Statistical Analysis and Survey Results,
American Petroleum Institute, October 1987.
06K00135.RPT Page VI-3
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APPENDIX A
Description of
Regulatory Initiatives
06K00136.RPT
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APPENDIX A
DESCRIPTION OF REGULATORY INITIATIVES
I. INTRODUCTION
Each regulatory initiative considered in this analysis is discussed in this appendix. First, a general
description of the initiative is presented. This provides an overview of the motivation of the initiative and
any controversy associated with it. Second, the basis for estimating potential compliance costs is
presented, which includes a discussion of the source(s) of the compliance cost estimates, key
assumptions, and the method for modifying costs for incorporation into the analysis models used in the
assessment. Third, a description of the three potential scenarios corresponding to the regulatory initiative
is presented. Finally, an estimate of the total cost to industry associated with each initiative is presented,
consistent with the compliance cost estimates and regulatory scenarios developed. Estimates of total
industry costs of compliance correspond to industry activity in 1985, with the exception of some costs in
the offshore where compliance cost estimates are based on an assumed future level of E&P activity.
Throughout this report, reference is made to compliance costs associated with existing and new
wells or facilities. Existing facilities or wells refer to those operating at the time the regulations are
implemented (i.e., those currently in place). New facilities or wells are those that will be put into operation
according to the development sequences assumed in the models. Where no distinction is made between
existing or new facilities, the incremental compliance costs apply to both.
The estimates of total industry compliance costs, as stated above, generally assume 1985 levels
of activity. This is consistent with most of the cost impact assessments performed by EPA and API, and
represents the period before the petroleum industry took its most recent, drastic downturn. It is important
to note that during a period of lower oil prices and decreased industry activity, the cost impacts to the
industry as a whole could be smaller than those reported. Equally important, however, is that during this
period of low prices and depressed activity, the impacts on economically recoverable supplies could be
greater, since a greater portion of the resource would be considered marginal.
The regulatory initiatives considered in this analysis, organized in terms of the statute establishing
regulatory authority, are discussed in the following chapters.
06K00136.RPT Page A-1
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II. RESOURCE CONSERVATION AND RECOVERY ACT
A. Background
Under Section 3001 (b) (2) (A) of the 1980 amendments to RCRA, Congress exempted several types
of wastes from regulation as hazardous wastes under federal RCRA Subtitle C, pending further study by
EPA. Among the wastes exempted were drilling fluids and cuttings, produced waters, and other wastes
associated with the exploration, development, and production of crude oil, natural gas, and geothermal
energy. Section 8002(m) of RCRA required EPA to study these wastes and submit a report to Congress
concerning its findings. This report was to include findings and recommendations for federal and non-
federal actions concerning the effects of these wastes on human health and the environment. Six months
later, EPA was required to submit a regulatory determination. EPA failed to meet the original October
1982 deadline for this report.
After the Alaska Center for the Environment sued EPA for its failure to conduct the study, EPA
entered into a consent order obligating it to submit the report by August 31, 1987. In April 1987, this
order was modified and the submission date was extended to December 31, 1987. EPA met the
December deadline for its report (EPA, 1987).
On June 30, 1988, EPA delivered to Congress its regulatory determination for environmental
regulations associated with the exploration, development, and production of crude oil, natural gas, and
geothermal energy. In that determination, EPA concluded that regulation of-E&P activities under RCRA
Subtitle C authority (i.e., regulation of hazardous wastes) is not warranted. Rather, EPA recommended
a three-pronged strategy to address the unique environmental and programmatic issues posed by E&P
activities by:
Improving federal programs under existing authorities in Subtitle D of
RCRA (applied to the management and disposal of non-hazardous solid
wastes), the Clean Water Act and the Safe Drinking Water Act.
Working with states to improve their regulation and enforcement
programs.
• Working with Congress to develop any additional statutory authority that
may be required.
06K00136.RPT
Page A-2
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B. Summary of Proposed Initiatives
As part of the strategy to address regulatory issues pertaining to E&P activities, EPA intends to
develop tailored RCRA Subtitle D standards for oil and gas operations. Potential modifications in federal
programs under other federal statutes are discussed in subsequent sections of this report. Potential
modifications to Subtitle D that are considered include the following activities associated with E&P
operations:
• Management and disposal of drilling muds and cuttings
• Disposal of associated wastes into central disposal facilities
Upgrading emergency pits
• Replacement of workover pits with portable rig tanks
Implementation of the Organic Toxicity Characteristic (OTC) test
• Corrective action (soil remediation) of contaminated sites.
The incremental compliance costs considered under RCRA include the management and disposal
of wastes, which are intrinsic to E&P operations and are currently defined as exempt from RCRA Subtitle
C regulations by EPA. The management and disposal of wastes such as used oils, paints, solvents,
chemical products, and other materials not uniquely used as a part of the extraction of oil and/or gas are
not exempt under RCRA, and are therefore not considered in the incremental regulatory costs developed
for this analysis.
In addition, some potential requirements under consideration for RCRA reauthorization legislation
could impose hazardous waste-type requirements for site-specific permitting, groundwater monitoring,
post-closure care, and financial assurance. These requirements were not analyzed in this study because
their potential compliance costs have not yet been estimated. Some analysts believe that the economic
impacts of many of these requirements would be severe, resulting in a significant portion of domestic
crude oil reserves becoming uneconomic to develop and produce.
C. Regulatory Initiatives Considered
The regulatory initiatives where potential compliance costs have been estimated and that will be
examined in this paper concern new requirements on the management and disposal of drilling muds and
cuttings, the management and disposal of associated wastes, the potential phasing out of emergency and
06KD0136.RPT Page A-3
-------
workover pits, toxicity testing of associated wastes and produced waters, and soil remediation corrective
action for existing sites. For this analysis, the requirements considered under RCRA Subtitle D authority
apply only to onshore operations. Regulatory initiatives concerning each of these areas are discussed
below in more detail.
1. Management and Disposal of Drilling Muds and Cuttings
a. General Description. One potential regulatory initiative that has been considered under
RCRA Subtitle D authority could require that all drilling mud reserve pits be constructed with a synthetic
liner and that the pits be capped and revegetated when closed. Pit liquids would likely require offsite
disposal. This requirement could apply to pits containing oil and salt water-based fluids, and could also
include those pits containing fresh water-based fluids. In addition, closed systems could be required for
drilling operations using oil-based drilling fluids.
b. Estimate of Potential Compliance Costs. Based on a survey sponsored by API, an
estimated 94% of all wells drilled onshore in 1985 used water-based drilling fluids; 62% of these used
fresh water-based muds (Wakim, 1987). Approximately 65% of all U.S. wells were drilled using unlined
reserve pits in 1985. Approximately 59% of the wells were drilled to depths 7,500 feet deep or less and,
for purposes of estimating costs, were assumed to require a 40-foot by 90-foot pit. The 41% of the wells
drilled deeper than 7,500 feet were assumed to require a 90-foot by 120-foot pit.
Oil-based drilling fluids were used in 6% of the wells drilled in 1985 (Wakim, 1987). If operators
are required to use closed systems for oil-based drilling fluids, recycling these fluids where feasible, and
transporting drilling wastes to an offsite disposal facility, the following costs are assumed (ERT, 1988):
• The use of a closed system would increase normal drilling costs by an
average $4 per foot drilled.
• Drilling fluid volumes requiring disposal could be reduced in a closed
system by 90%.
Transportation, treatment, and disposal costs would be $25/Bbl of waste.
• A credit of $4,386 should be taken for normal construction and closure
costs, since these costs would no longer be incurred under this scenario.
Under the closed drilling system scenario considered here, a closed system would result in
approximately double the mud management and disposal costs of an open system. However, some in
06K00136.RPT Page A-4
-------
industry believe that the optimum use of closed-loop mud processing and solids control systems could
result in a substantial reduction in costs, because of improved solids control, improvements in drilling
efficiency, and lower requirements for dilution and mud additives, (Lai and Thurber, 1989). One case
history has shown that the use of an optimum closed loop system can reduce mud reclamation and
disposal costs by 50%, while in another case, drilling days were reduced by 20% through better waste
management (Lai and Thurber, 1989). If such cost reductions can be universally achieved, the costs
assumed for closed systems may be too high. However, since in this analysis only oil-based mud
systems are assumed to be closed, and since oil-based mud systems make up only a small portion of
all systems, the impact of reduced costs for closed systems in the overall analysis would not be
significant.
The regulatory scenarios assumed by ERT (1988) for API compare closely to EPA's Intermediate
Scenario, as presented in the December 1987 Report to Congress (EPA, 1987), where drilling fluids
characterized as hazardous under RCRA would be disposed in a single liner pit, and would be buried,
capped, and revegetated. However, EPA's cost estimates failed to explicitly account for the costs of
disposing the liquid portion of these fluids. As a result, EPA's incremental cost estimates were
considerably lower than ERT's. For purposes of this analysis, ERT's cost estimates are used.
However, in EPA's Report to Congress, regional variation in drilling fluid volumes produced per
foot drilled and the average depth per well were accounted for in their analysis of potential compliance
costs. This regional variability was also considered in this analysis. The drilling waste volumes assumed
for each analysis region were estimated based upon region-specific estimates developed by API (Wakim,
1987). The average well depths shown for each region (regions are shown in Figure A-1) were based
on the average depth of new field and new pool oil wells for each region, as reported in the data series
published by the American Association of Petroleum Geologists (AAPG, 1988), which were based on new
field and new pool drilling over the 1981 through 1987 time period. Table A-1 summarizes the depths
used for assessing the economic impact of these regulations on the future economics of finding and
developing newly discovered crude oil fields (for evaluating the impact on known fields, actual average
well depths for the fields considered are used).
The assumed distribution of drilling sites using lined and unlined reserve pits, which represents
current practices, is presented in Table A-2 for the analysis regions used in this study. Nationwide,
approximately 62% of all muds previously discharged to unlined pits were assumed to be fresh water-
based (ERT, 1988); this proportion is consistently applied to each analysis region. All compliance costs
used in this analysis assume this distribution of disposal practices. The estimated unit compliance costs
associated with restrictions on unlined reserve pits are shown in Table A-3.
06K00136.RPT Page A-5
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Figure A-1
Replacement Cost System
Onshore Supply Analysis Regions
Northern Rockies
West Coast>S5SSS5
Central Rockies
Southern Rockies
Appalachia/Atlantic
West Texas
06K00135.RPT
Page A-6
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TABLE A-1
KEY REGIONAL PARAMETERS FOR DRILLING WASTE REGULATORY SCENARIOS
Analysis
Reqion
Alaska
West Coast
Northern Rockies
Central Rockies
Southern Rockies
Mid-Continent
West Texas
East Texas
Gulf Coast
North Central
Appalachia
Southeast
Average
Well Depth*
9,000
8,036
7,864
7,004
4,408
3,833
5,602
6,637
7,583
2,970
1,556
10,005
* For new tield/new pool discoveries.
** For API drilling depth category associated with the
Sources: AAPG, 1988; EPA, 1987
Drilling Waste
Volume Per Foot
Drilled-1985**
(Bbl/Foot)
0.84
0.61
1.25
1.25
1.22
1.15
0.86
0.86
1.18
0.60
1.28
3.28
average well depth in the region.
06K00138.TBL
Page A-7
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TABLE A-2
DISTRIBUTION OF 1985 DRILLING SITES USING
LINED AND UNLINED RESERVE PITS BY ANALYSIS REGION
Distribution of
Drilling Waste Disposal Method
Supply Analysis
Reqion
Alaska
West Coast
Northern Rockies
Central Rockies
Southern Rockies
Mid-Continent
West Texas
East Texas
Gulf Coast
North Central
Appalachia
Southeast **
National Average
** Same as Gulf Region
Source: EPA 1987
(Percent of Drill Sites)
Unlined
Facilities
67
99
65
65
50
60
60
60
89
47
23
89
65
Lined
Facilities
33
1
35
35
50
40
40
40
11
53
77
11
35
Page A-8
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TABLE A-3
ESTIMATED REGULATORY COMPLIANCE COSTS FOR
MANAGEMENT AND DISPOSAL OF DRILLING WASTES IN THE LOWER-48 ONSHORE"
Water-Based Muds (94% of all projects)
Install pit liner, cap, and revegetate (Costs in dollars per well)
depth <7,500 feet
depth >7,500 feet
Transport of liquid wastes for offsite disposal
Liquid waste assumed to represent 90% of total
drilling waste per foot drilled obtained from
Table 11-1.
$3,930.00 (40 ft. x 90 ft. pit)
$5,781.00 (90ft. x 120 ft. pit)
$3.00/Bbl of waste
Oil-Based Muds (6% of all projects)
Additional drilling and completion costs
Disposal of liquids*
Disposal of cuttings**
Credit for pit construction and closure
$4.00/foot
$25.00/Bbl
$25.00/Bbl
($4,386.00)
+ Compliance costs for Alaska onshore are estimated to be three times Lower-48 onshore costs.
* Liquids represent 90% of total drilling wastes; volume reduction of 90% assumed because of
closed system.
** Cuttings represent approximately 10% of total drilling wastes, assuming no reduction in
volume.
Sources: ERT, 1988; Wakim, 1987
06K00138.TBL
Page A-9
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TABLE A-3 (Continued)
ESTIMATED REGULATORY COMPLIANCE COSTS FOR
THE MANAGEMENT AND DISPOSAL OF DRILLING WASTES IN THE LOWER-48 ONSHORE+
Nomenclature
LC = Liner installation cost ($), function of well depth
FUP = Fraction of pits in region that are unlined (see Table 11-2)
WD = Well depth (feet)
DWF = Drilling waste volume per foot drilled (Bbl/foot) (see Table 11-1)
Low Scenario
Assumes oil-based muds are discharged into lined reserve pits, fresh water-based muds can be
discharged into unlined pits, and salt water-based muds are discharged into lined pits.
Cost = (0.94) {(LC) (FUP) (1-0.62) + (0.06) {(LC) (FUP)}
+ (3.00) (DWF) (WD) (0.90)
Example calculation for West Texas well:
Cost = (0.94) {(3930) (0.60) (1-0.62)} + 0.06 {(3930 (0.60)}
+ (3.00)(0.86) (5602) (0.90)
= $13,992/well
Medium Scenario
Assumes oil-based drilling fluids use closed systems, fresh water-based muds can be discharged into
unlined reserve pits, salt water-based muds discharged into lined pits.
Cost = (0.94) {(LC) (FUP) (1-0.62) + (3.00) (DWF) (WD) (0.90)}
+ 0.06 {(4.00) (WD) - 4386 + (DWF) (WD) (25.00) [0.10 + (0.90) (0.10)]}
Example calculation for a West Texas well:
Cost = (0.94) {(3930) (0.60) (1-0.62) + (3.00)(0.86)(5602)(0.90)}
+ 0.06 {(4.00)(5602) - 4386 + (0.86)(5602)(25.00)[0.10+0.90(0.10]}
= $15,524/well
ObK.00138.TBL PageA-10
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TABLE A-3 (Continued)
ESTIMATED REGULATORY COMPLIANCE COSTS FOR
THE MANAGEMENT AND DISPOSAL OF DRILLING WASTES IN THE LOWER-48 ONSHORE*
High Scenario
Assumes oil-based drilling fluids use closed systems; all water-based muds discharged into lined pits.
Cost = (0.94) { (LC) (FUP) + (3.00) (DWF) (WD) (0.90)}
+ 0.06 { (4.00) (WD) - 4386 + (DWF) (WD) (25.00) [0.10 + (0.90) (0.10)]}
Example calculation for a West Texas Well:
Cost = (0.94) {(3930) (0.60) + (3.00) (0.86) (5602) (0.90)}
+ 0.06 {(4.00) (5602) - 4386 + (0.86) (5602) (25.00) [(0.10) + (0.90) (0.10)]}
= $16,898/well
06K00138.TBL PageA-11
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c. Description of Scenarios. Under the medium and high regulatory scenarios proposed for
this analysis, the use of oil-based drilling muds was assumed to require closed drilling systems, with
disposal of spent muds at a central disposal facility. Under the low regulatory scenario, oil-based muds
are allowed to be discharged into lined pits. Under the low and medium scenarios, fresh water-based
muds are allowed to be discharged into unlined reserve pits, while salt water-based muds are required
to be discharged into lined pits. Under the high scenario, all water-based muds would be required to be
discharged into lined pits. In all scenarios, all liquid wastes were assumed to be disposed offsite. These
scenarios are summarized in Table A-3.
d. Total Compliance Cost. The costs of waste management and disposal of drilling fluids
and cuttings are estimated to range from $1.2 to $1.4 billion per year, based on oil and gas well drilling
at 1985 levels. (If only oil well drilling is considered, the compliance costs would be approximately $1.0
billion.) These costs include the installation of liners and caps, revegetation, and transport of pit liquids
to a centralized disposal facility. Table A-3 summarizes estimated total industry compliance costs for all
the initiatives considered.)
2. Disposing of Associated Hydrocarbon Wastes in Central Disposal Facilities
a. General Description. Another potential RCRA Subtitle D revision under consideration is
the requirement that all roadspreading, landspreading, and burial of hydrocarbon-bearing wastes
associated with oil and gas extraction activities be banned, and that these wastes be disposed at central
disposal facilities.1' This would likely involve the disposal of all liquid wastes into offsite Class I or Class
II disposal wells. Solid wastes could be disposed at nonhazardous or hazardous waste landfills, or could
be incinerated.
b. Estimate of Potential Compliance Costs. Incremental compliance costs associated with
these scenarios would involve the costs to construct, equip, and operate the additional central disposal
facilities that would be required to handle the increased volumes of wastes. Additional costs would also
be incurred for all tank batteries to meet RCRA Subtitle C requirements for facilities handling waste
characterized as hazardous and to transport and dispose of these wastes at the central disposal facilities.
In the incremental unit compliance cost estimates assumed in this study, the costs to install the
additional injection wells that would be required to dispose the increased volumes of liquid waste were
1/The disposal of produced waters by roadspreading, by surface discharge, and for beneficial uses is
addressed under the Clean Water Act requirements (as part of non-injected produced waters), discussed later in
this report.
06K00136. RPT Page A-12
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not included, and only the costs to transport the liquid waste to central facilities was considered.
Moreover, it was assumed that the existing solid waste disposal facilities and incinerators would have the
capacity to handle the increased waste volumes. Therefore, no costs for new solid waste disposal
facilities were included. Estimated incremental unit compliance costs associated with these scenarios are
presented in Table A-4.
c. Description of Scenarios. Three regulatory scenarios were considered by ERT (1988), and
these scenarios were incorporated into this analysis. In all three scenarios, consistent with the ERT
assumptions, hydrocarbon-bearing liquid wastes are transported and disposed into an offsite disposal
well. The requirements for disposal of solid wastes vary, however. Under the low scenario, solid
associated wastes would be discharged at nonhazardous industrial waste disposal facilities. Under this
case, the liquid and solid wastes would not be classified as hazardous under RCRA. Under the medium
scenario, solid wastes would require disposal at hazardous waste disposal facilities. Finally, in the high
scenario, combustible solid wastes would require incineration, and non-combustible solid wastes, such
as spent iron sponge and produced sand, would be disposed at a hazardous waste disposal facility.
d. Total Compliance Costs. Estimated incremental annual costs associated with compliance
could be as high as $1.5 billion per year, if the costs apply to both oil and gas operations at 1985 levels.
3. Upgrading Emergency Pits
a. General Description. Another potential regulatory initiative under consideration is a
requirement to upgrade all existing unlined emergency pits. These emergency pits are associated with
tank batteries, enhanced recovery projects, and salt water disposal (SWD) wells. (Throughout this
appendix, enhanced recovery or EOR projects refer to both secondary and tertiary recovery projects. This
is consistent with the terminology used by EPA.) Two types of pit upgrading are considered: the
installation of pit liners and the replacement of emergency pits with tanks.
b. Estimate of Potential Compliance Costs. ERT (1988) estimated the cost of installing a 500-
barrel tank to be $33,000. The cost to line an emergency pit, based on costs of synthetic liners and
geotextile support fabrics, was estimated to be approximately $1,235 per pit (EPA, 1987). In this analysis,
unlined pits were assumed to exist at all EOR projects and SWD wells, while 75% of existing tank batteries
were assumed to have unlined pits, with the remaining 25% having lined pits. These costs are
summarized in Table A-5.
06K00136.RPT Page A-13
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TABLE A-4
ESTIMATED COSTS FOR THE DISPOSAL OF ASSOCIATED
WASTES IN CENTRAL DISPOSAL FACILITIES
Waste Volumes Assumed
Solids disposed into non-hazardous waste facilities:
2,662,000 Bbls from 884,581 producing onshore oil and gas wells in 1985, or approximately 3
Bbl/well/year1. (Low Case).
Total hazardous solids disposed or incinerated:
4,080,000 Bbls from 884,581 producing oil and gas wells in 1985, or approximately 5
Bbl/well/year2 (Medium and High Case).
Approximately 55% of all hazardous solid wastes can be incinerated.
Liquids injected:
19,437,000 Bbls from 884,581 wells, or approximately 22 Bbl/well/year3.
Cost Assumptions
Waste disposal costs:
Solids, Nonhazardous $12.50/Bbl of waste (Low Case)
Solids, Hazardous $25.00/Bbl of waste (Medium and High Case)
Solids, Incineration $85.00/Bbl of waste (High Case)
Liquids (Transport) $4.00/Bbl of waste (All Cases)
Cost for tank batteries .to comply with RCRA Subtitle C requirements (applied to cases where waste
produced is considered hazardous):
Annual Operating Costs: $5,230.00 per tank battery per year4
Four producing wells are assumed to be associated with each tank battery.
Includes only those solid wastes currently not sent to offsite commercial disposal facilities.
Includes all solid wastes generated by E&P operations.
Includes all liquid wastes generated by E&P operations.
Includes only those costs not included in the costs for conducting the Organic Toxicity
Characteristics Test. (See Table II-7)
Source: ERT, 1988; well counts for 1985 (consistent with year for waste volumes) from IPAA (1989) for
onshore wells.
06K00138.TBL PageA-14
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TABLE A-4 (Continued)
ESTIMATED COSTS FOR THE DISPOSAL OF ASSOCIATED
WASTES IN CENTRAL DISPOSAL FACILITIES
Note: These costs do not include the costs to install and operate new disposal facilities
required for waste previously disposed on site, in particular, the cost of the additional,
offsite disposal wells required for liquid waste disposal.
Low Scenario
Liquid wastes disposed into offsite disposal wells; solid wastes into nonhazardous waste disposal
facilities.
Annual Costs: ($12.50/Bbl) (3 Bbl solid/producer)
+ ($4.00/Bbl liquid) (22 Bbl liquid/producer)
= $125.50/producer/year
Medium Scenario
Liquid wastes disposed into offsite disposal wells; solid wastes disposed into hazardous waste
disposal facilities.
Annual Costs: ($5,230/battery) / (4 producer/battery)
+ ($25.00/Bbl solid) (5 Bbl solid/producer)
+ ($4.00/Bbl liquid) (22 Bbl liquid/producer)
= $1,520.50/producer/year
High Scenario
Liquid wastes disposed into offsite disposal wells; combustible solid wastes incinerated;
noncombustible solid wastes disposed into hazardous waste disposal facilities.
Annual Costs: ($5,230/battery) / (4 producers/battery) +
($25.00/Bbl solid) (0.45) (5 Bbl solid/producer) +
($85.00/Bbl solid) (0.55) (5 Bbl solid/producer) +
($4.00/Bbl liquid) (22 Bbl liquid/producer)
= $1,686/producer/year
06K00138.TBL Page A-15
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TABLE A-5
ESTIMATED COSTS FOR UPGRADING EMERGENCY PITS
Assumptions:
One tank battery per four producing wells
One SWD well per 10 producing wells
An "EOR project" consists of 10 injection wells
75% of existing emergency pits associated with tank batteries are unlined
100% of existing emergency pits associated with EOR projects and SWD wells are unlined
Cost to Replace Emergency Pit with Tank:
Cost per pit replaced = $33,000
Cost per production well
Cost per injection well
0.75(33,000/4) + (33,000/10) = $9,488
33,000/10 = $3,300
Cost to Line Emergency Pit
Cost of 30 mil HOPE synthetic liner
Cost of geotextile support fabric
$0.50/ft2
$0.16/ft2
$0.66/ft2
Assuming emergency pit can hold 1,000 barrels and is approximately 3 feet deep:
1,000 barrels (42 gal/bbl) (1 ft3/7.48 gal) =
(5,615ft3/3feet) ($0.66/ft2) = $1,235/pit
5,615 fT
Cost per production well
Cost per injection well
0.75 (1,235/4) + (1,235/10)
1,235/10
$355.00
$123.50
Sources: ERT, 1988; EPA, 1987
06K00138.TBL
Page A-16
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TABLE A-5 (Continued)
ESTIMATED COSTS FOR UPGRADING EMERGENCY PITS
Low Scenario
Assumes all (existing and new) emergency pits must be lined.
Medium Scenario
Assumes all existing emergency pits be lined; tanks must be installed rather than new emergency pits
at new facilities.
High Scenario
Assumes all existing and new emergency pits be replaced with 500-barrel tanks.
06K00138.TBL PageA-17
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c. Description of Scenarios. For purposes of this analysis, the low scenario assumed that
all existing and new emergency pits would be required to install synthetic liners. Under the medium
scenario, liners would be required for existing emergency pits, while 500-barrel tanks would be required
for all new emergency pits. Under the high scenario, all existing and new facilities would be required to
install 500-barrel tanks rather than emergency pits.
d. Total Compliance Costs. Total industry compliance costs for this initiative are estimated
to range from approximately $0.3 billion if only liners are required on emergency pits, to $7.2 billion if all
facilities must install 500-barrel tanks rather than emergency pits. This estimate only includes the cost
to upgrade existing facilities (tank batteries, waterflood projects, and SWD wells), and not the incremental
costs to be incurred by new facilities.
4. Replace Workover Pits with Portable Rig Tanks
a. General Description. Another regulatory initiative under consideration is a requirement
that all available workover rigs become retrofitted with a portable rig tank to replace existing workover pits.
This requirement is intended to minimize potential contamination associated with pits used in workover
operations.
b. Estimate of Potential Compliance Costs. The cost to retrofit a workover rig to include a
portable rig tank is estimated to be $15,000 per rig (ERT, 1988). Assuming project amortization at a 10%
discount rate for eight years, and that one workover rig can service about 40 wells per year, this amounts
to about $100 per well worked over. This cost estimate is summarized in Table A-6.
c. Description of Scenarios. For this analysis, it was assumed that all workover rigs would
have to be retrofitted with rig portable tanks in all three scenarios.
d. Total Compliance Cost. The total cost for industry to comply with this initiative is
estimated to be about $95 million, given the total number of rigs operating in 1985.
5. Organic Toxicitv Characteristic (OTC) Rule
a. General Description. In the 1984 amendments to RCRA, Congress required that EPA
develop a new toxicfty test to establish which wastes require hazardous waste management. EPA is close
to finalizing this rule, called the Organic Toxicity Characteristic (OTC), which could expand the number
of wastes potentially falling under RCRA hazardous waste authority. If E&P waste is not exempt from the
06K00136.RPT PageA-18
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TABLE A-6
ESTIMATED COSTS OF REPLACING
WORKOVER PITS WITH PORTABLE RIG TANKS
Estimated Retrofit Cost: $15,000.00 per rig
Assumes project amortization at a 10% rate for 8 years, with a rig fleet of 6,361 rigs (average of the
available and working workover rig fleet in 1985).
Assumes one workover rig can service 40 wells per year.
(15,000) (1+OJO)8 = $4,000.00/rig
8
($4,000.00/rig) (1 rig/40 wells/year) = $100.00/well
Cost per producer (including allocated SWD wells)* $110.00/well
Cost per injector $100.00/well
These costs are assumed to apply for all three scenarios.
* Assuming 10 producers per SWD well.
Source: ERT, 1988
06K00138.TBL Page A-19
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application of this proposed rule, most E&P waste streams would test as hazardous, primarily because
of the low concentration limit for benzene (0.5 ppm).
Although many E&P wastes are exempt from RCRA, this new test could have significant impacts.
Wastes characterized as hazardous under the test, even if considered exempt under RCRA, may still be
subject to requirements similar to those concerning wastes that are not currently exempt. If this occurs,
E&P facilities could be required to:
• Notify EPA of the types and amounts of waste handled and get EPA
identification numbers.
• Comply with standards for hazardous waste storage and handling,
including storage time limits and quantity and handling requirements for
containers and tanks.
Obtain RCRA hazardous waste storage permits if held greater than 90
days.
• Manifest all shipments of hazardous waste for offsite disposal.
In addition to these primary impacts, other potential secondary impacts could result under this
rule, if many previously exempt wastes become subject to hazardous waste-type requirements. These
include removing the exemption of E&P sites from CERCLA changing requirements for National Pollution
Discharge Elimination System (NPDES) permits for produced waters, and changing potential underground
injection requirements under the SDWA.
b. Estimate of Potential Compliance Costs. The incremental compliance costs considered
for this potential regulatory initiative are only those that explicitly correspond to the OTC test, and not
those costs associated with remedial actions, site closure, or the management of wastes classified as
hazardous under the test that would not be subject to an exemption. These costs are summarized in
Table A-7.
c. Description of Scenarios. In this analysis, the new OTC rule was assumed to apply to all
E&P operations under all scenarios.
d. Total Compliance Costs. Estimated total compliance costs for performing the OTC test
are on the order of $1.3 billion initially, with an average annual cost of $360 million per year. This cost
estimate is based on the number of production sites (tank batteries), EOR facilities, and SWD wells
operating in 1985.
06K00136.RFT page £.20
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TABLE A-7
ESTIMATED COSTS FOR THE NEW RCRA
ORGANIC TOXICITY CHARACTERISTIC
1 . Estimated Costs for New Wells (Assume one analysis for every 4 wells)
Cost ($/Wein
I.D. Number 240
Manifest 35
Biannual Report 10
Contingency Plan 800
Training 1 5
Waste Analysis 625
1,725
2. Estimated Cost Per Project (New and Existing)
Cost ($/Site) Annual Cost ($/Site)
I.D. Number 240
Contingency Plan 160
Training 640 64
Waste Analysis Plan 200
Closure Plan 500
Tank Assessment 640
Biannual Report 10
Waste Analysis 2.500
Assumptions:
1. Each tank battery, EOR project, and SWD well corresponds to a "site."
2. Four producing wells are associated with a tank battery.
3. One SWD well is associated with 10 producing wells.
4. An "EOR project" consists of 1 0 injection wells.
* Includes one initial analysis plus one analysis every two years.
Sources: Memorandum from H.W. Yates to B.H. Freeman, June 26, 1989; ERT, 1988.
06K00138.TBL Page A-21
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TABLE A-7 (Continued)
ESTIMATED COSTS FOR THE NEW RCRA
ORGANIC TOXICITY CHARACTERISTIC
Cost Estimates:
Initial Capital Costs:
• $1,725 per new well (producers and injectors) drilled
• (4,890/4) + (4,890/10) = $1,712 per existing production well
(4,890/10) = $489 per existing injection well
Annual Operating Costs:
(1,324/4) + (1,324/10) = $463 per producer per year
(1,324/10) = $132 per injector per well
These costs apply to all three scenarios.
06K00138.TBL ' Page A-22
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6. Corrective Action (Soil Remediation)
a. General Description. Under an expanded RCRA Subtitle D program, some industry
observers believe that corrective action could be required to remediate hydrocarbon or salt water
contamination at existing facilities, subject to possible regulations similar to RCRA hazardous waste
regulatory provisions. This required remediation could include soil reconditioning or replacement,
groundwater reclaiming (through stripping or flushing), and the purchase of unreclaimable properties.
For purposes of this analysis, the costs of only soil remediation are considered.
b. Estimate of Potential Compliance Costs. Cost estimates for this regulatory initiative were
based on remediation cost estimates associated with leaking underground storage tanks (Roy F. Weston,
Inc. and others, 1988). For purposes of this analysis, the remediation costs for E&P facilities and those
for leaking underground storage tanks were assumed to be similar. Two potential types of moderate-cost
remediation techniques were considered. The first technique was land treatment, which could consist of
either biodegradation or leaching-type processes. Biodegradation is an in situ process by which the
growth and activity of naturally occurring microorganisms are stimulated in their natural environment, and
through their metabolic processes, degrade the constituents of concern. Leaching is another low-cost
in situ process by which soils are flushed with water (often mixed with a surfactant) in order to leach
constituents of concern from the soil. Biodegradation and in situ leaching were considered relatively low
cost remediation techniques, and for purposes of this analysis, were assumed to be approximately
equivalent in cost (Roy F. Weston, Inc. and others, 1988).
The primary higher-cost remediation technique considered was excavation, where contaminated
soil is removed from the site for disposal in an appropriate facility. The costs for remediation by
excavation are generally higher than those for either biodegradation or leaching. Either land disposal or
incineration are generally required for the excavated soil. (In this analysis, the cost of land disposal and/or
incineration of the excavated contaminated soil was not considered.)
Not all sites containing soil contamination will necessarily pose an environmental threat, however.
ICF (1987) developed environmental setting characteristic data for use in the EPA's human health and
environmental risk assessment performed as part of their Report to Congress (EPA, 1987). In this
characterization, the following weighted national distributions of hydrogeologic settings for oil and gas
production sites were determined:
• 46% of all sites could be categorized as located over deep groundwater
aquifers (characterized at a depth of approximately 60 feet)
06K00136.RPT Page A-23
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44% of all sites could be categorized as having low groundwater
recharge rates (characterized as an average recharge rate of one inch
per year)
44% of all sites could be categorized as having a low unsaturated zone
permeability or hydraulic conductivity (characterized as a permeability of
10"7 cm2/sec)
64% of all sites could be categorized as far (greater than 2000 meters)
away from the nearest exposure (i.e. water supply) well
60% of all sites could be categorized as far (greater than 2000 meters)
from surface water.
These characteristic hydrogeologic settings serve as the basis for assuming the occurrence
frequencies associated with the scenarios considered. However, the settings are not intended to be a
characterization of potential risks posed.
For this potential regulatory initiative, incremental costs for remedial action were assumed to be
incurred only by existing facilities. The estimated incremental unit compliance costs associated with these
scenarios are presented in Table A-8.
c. Description of Scenarios. The scenarios developed for this initiative represent a range
of frequency of potential contaminated sites posing an unacceptable environmental or health risk. In
addition, two types of remediation techniques were assumed, to represent the range of possible
techniques acceptable under potential corrective action guidelines. Under the low scenario, land
treatment of hydrocarbon-contaminated sites to a three foot depth was assumed, applied to 50% of
existing tank batteries and EOR projects. (This amounts to one in eight producing wells and one in 20
injection wells having associated hydrocarbon contamination.) Under the medium scenario, the
requirements for hydrocarbon-contaminated sites were the same as those in the low scenario, while
excavation was assumed to be required to remediate salt water-contaminated sites, assumed at 100% of
existing SWD wells and 75% of existing tank batteries. Finally, in the high scenario, excavation was
assumed for both hydrocarbon and salt water-contaminated sites, at the same frequency of occurrence
as that in the medium scenario.
d. Total Compliance Costs. Estimated costs for potential corrective action associated with
existing E&P sites is estimated to range from $3.6 to $14.4 billion, given the total number of existing E&P
facilities in 1985.
06K00136.RPT Page A-24
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TABLE A-8
ESTIMATED COSTS FOR SOIL REMEDIATION
CORRECTIVE ACTION FOR EXISTING E&P SITES
Assumptions:
1.
2.
3.
4.
5.
6.
7.
Cost of biodegradation or leaching to a 3-foot depth
Cost of excavation to a 3-foot depth
Cost of clay cap 1 -foot thick
Size of contaminated site
Four producing wells assumed per tank battery
One SWD well per 1 0 producing wells
An "EOR facility0 consists of 1 0 injection wells
$55/yd3
$77.50/yd3
$13/yd3
100ft. xSOft.
All costs are assumed to apply only to existing facilities.
Low Scenario
Assumes biodegradation or leaching of hydrocarbon-contaminated sites at 50% of existing facilities
(tank batteries and EOR facilities) to 3-foot depth
• Cost per site =
((100) (50) (3) ft3) (1 yd3/27 ft3) ($55/yd3) = $31,000
((31,000/4) (0.50) = $3,875 per existing producer
• (31,000/10) (0.50) = $1,550 per existing injector
Medium Scenario
Assumes land excavation for salt water-contaminated sites, and biodegradation or leaching for
hydrocarbon-contaminated sites. Hydrocarbon contamination is assumed at 50% of existing facilities
(same as the low scenario); while 100% of existing salt water disposal wells and 75% of existing tank
batteries and EOR projects are assumed to contain salt water contamination.
Source: Roy F. Weston, Inc. and others, 1988.
06K00138.TBL Page A-25
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TABLE A-8 (Continued)
ESTIMATED COSTS FOR SOIL REMEDIATION
CORRECTIVE ACTION FOR EXISTING E&P SITES
• Costs per hydrocarbon-contaminated site: $31,000
• Cost per salt water-contaminated site
((100) (50) (3) ft3) (1 yd3/27 ft3) ($77.50/yd3)
+ ((100) (50) (1)) (1 yd3/27ft3) ($13/yd3)
= $45,000
($31,000/4) (0.50)
+ (45,000/10) (1.00) + (45,000/4) (0.75)
= $16,813 per existing producer
(31,000/10) (0.50) + (45,000/10) (0.75)
= $4,925 per existing injector
High Scenario
Assumes land excavation for both hydrocarbon and salt water-contaminated sites, at the same
frequencies as the medium scenario
(45,000/4) (0.50) +
(45,000/10) (1.00) + (45,000/4) (0.75)
= $18,563 per existing producer
(45,000/10) (0.50) + (45,000/10) (0.75)
= $5,625 per existing injector
06K00138.TBL Page A-26
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D. Regulatory Initiatives Not Analyzed
A number of other possible initiatives are also being considered under RCRA authority that could
have impacts on E&P activities. These considerations include the administration of and compliance with
a generic mud system and the increased costs potentially associated with groundwater monitoring,
closure, post-closure care, and financial assurance requirements associated with facilities subject to
permitting similar to RCRA hazardous waste sites. In addition, potential requirements pertaining to E&P
operations that may affect wetlands, endangered species habitats, or fish and wildlife habitats, were also
not considered.
Regulatory initiatives are also being considered under RCRA that could affect the management
of produced waters from oil and gas E&P operations. The regulatory cost impacts pertaining to the
management of produced waters were considered under SDWA and CWA authority, discussed in detail
later in this report.
III. SAFE DRINKING WATER ACT
A. Background
The Underground Injection Control (DIG) program was established under the Safe Drinking Water
Act of 1974 (SDWA), to protect underground sources of drinking water (USDWs) from endangerment by
subsurface emplacement of fluids. Part C of the SDWA requires EPA to establish minimum requirements
for state programs and, in cases where states cannot or will not assume primary enforcement
responsibility, to assume federal regulatory authority for the program.
In 1980, Congress amended the SDWA by adding Section 1425. This section allows states to
demonstrate the effectiveness of their in-place regulatory programs for Class II (oil- and gas-related)
injection wells in lieu of demonstrating that they meet the minimum requirements specified in the 1980
federal UIC regulations. In order to be deemed effective, state Class II programs have to include
prohibition of unauthorized injection and protection of USDWs.
Under Section 1422 of the SDWA, all subsurface injection associated with E&P activities must be
governed by a UIC program. This requirement has resulted in the formation of two main types of Class
II UIC programs. States whose UIC programs are administered directly by EPA are referred to as Direct
Implementation (Dl) states. In contrast, states that have received primary enforcement responsibilities for
the UIC program are known as Primacy states. For Dl states, EPA has promulgated minimum national
06K00136.RPT " " * Page A-27
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standards. To date, primacy for almost all delegated Class II programs has been requested and granted
under Section 1425 of the SDWA, which allows states to make an alternative demonstration in order to
receive primacy. This alternative demonstration consists of states showing that their program is effective
in protecting USDWs and it contains certain elements traditionally associated with regulatory programs
(e.g., permitting, reporting, surveillance). EPA issued its "1425 guidance" in 1981 to assist states in
making this demonstration.
In approving programs under Section 1425, EPA has accepted variations among the states
consistent with the statutory requirements of the SDWA. EPA has recently conducted a Midcourse
Evaluation of the Class II UIC program to examine whether it reflects the experience and insight the
Agency has acquired since the program went into effect, to review the adequacy of USDW protection in
Primacy states, and to identify differences in state UIC program implementation and enforcement and
recommend improvements in these areas.
B. Summary of Proposed Initiatives
As part of the Midcourse Evaluation process, EPA identified five major areas of potential concern
that would require investigation as part of the effort (EPA, 1989). These areas are:
• Operating, monitoring, and reporting requirements
• Plugging and abandonment
• Mechanical integrity testing (MIT) requirements
Well construction requirements
• Area of review (AOR) and corrective action requirements.
C. Regulatory Initiatives Considered
Of the concerns listed above, only the potential compliance costs associated with mechanical
integrity testing, area-of-review/corrective action, and well construction requirements were considered in
this study. Cost estimates for potential operating, monitoring, and reporting requirements and plugging
and abandonment were not addressed.
Potential regulatory revisions for each set of requirements considered are discussed in the
paragraphs below.
06K00136.RPT Page A-28
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1. Mechanical Integrity Testing
a. General Description. Mechanical integrity testing (MIT) normally consists of two parts.
Part 1 MIT addresses casing, tubing, and packer integrity and is traditionally demonstrated by a periodic
pressure test of the tubing-casing annulus. Part 2 MIT addresses fluid movement behind the casing and
traditionally has been demonstrated by cementing records as an indicator of proper construction.
Part 1 MIT requires pressure testing of the tubing-casing annulus once every five years, except
for those wells currently using annulus pressure monitoring. Potential changes in Part 1 MIT primarily
focus on the frequency of testing, or the possible introduction of continuous positive annulus pressure
monitoring (PAPM). The frequency of testing could potentially be based on the corrosive nature of a
basin in which injection is taking place. Regarding PAPM, many industry experts feel that the requirement
of narrow pressure limitations for annular pressure fluctuations for the purpose of demonstrating
mechanical integrity is impractical (Gruy, 1989). Significant changes in annular pressure in a mechanically
sound well can occur under normal operating conditions, due only to typical temperature fluctuations of
the injected fluid (Gruy, 1989).
Part 2 MIT addresses fluid movement behind the casing and has traditionally used cementing
records as demonstration of mechanical integrity. EPA is considering the additional use of periodic
wireline logging to assess behind-casing fluid flow and the quality of the cement job, with the frequency
of testing possibly dependent on the corrosive potential at the well location. Several logging techniques
are under consideration, including noise, differential temperature, cement bond, radioactive tracer (RAT),
and oxygen activation (OA) logs. Some of these tools require that the tubing be pulled from the well so
that adequate cement can be evaluated and fluid movement can be more precisely detected.
The cement bond and OA logging tools can often provide subjective and/or inconclusive results
and have varying levels of acceptance within the industry. For example, EPA gave interim approval to the
use of the OA log in October 1988 because they felt it could be effective in detecting non-injection-related
(NIR) fluid movement outside the casing while running the tool through the tubing. However, the opinion
of many oil and gas operators is that the OA log, at its present state of development, cannot reliably
determine NIR fluid movement by running the tool through the tubing (Gruy, 1989).
b. Estimate of Potential Compliance Costs. In estimating the costs for Part 1 MIT, Gruy
(1989) assumed that 90% of all injectors have tubing and packer and will require testing once every five
years, or perhaps more frequently in areas with a high corrosive potential. LBGES (1989), on the other
hand, developed Part 1 MIT cost estimates assuming that all wells be pressure tested annually, including
06K00136.RPT = = Page A-29
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wells with and without packers. Ten percent of the wells were assumed to be packerless. These wells
currently require MIT annually. No changes to pressure testing packerless wells were assumed in this
analysis; thus, no incremental costs for packerless wells would be incurred.
Both sets of cost estimates for Part 1 MIT assume roughly the same regulatory scenarios. Despite
some differences in methodology and assumptions, the Gruy and LBGES (1989b) cost estimates were
similar. The incremental unit compliance costs used in this study were based on those estimated by Gruy
(1989). These costs are summarized in Table A-9.
For undiscovered fields, all new injection wells were assumed to be constructed with tubing and
packer, so none of the requirements for packerless wells were assumed in the economic evaluations of
these fields. For discovered fields, on the other hand, 10% of all wells (both existing and new wells) were
assumed to be packerless.
The incremental costs for monitoring injection fluid movement make up most of the costs
associated with potential revisions to Part 2 MIT requirements. In estimating future costs from potential
revisions to Part 2 MIT, Gruy (1989) assumed that a FIAT, noise, and temperature log would be run to the
depth of the injection zone to demonstrate injection fluid confinement. Moreover, to determine the
movement of NIR fluid behind the casing, OA, noise, and temperature logs would be run to the depth of
the lowermost USDW. To run the OA log, Gruy (1989) assumed that the tubing and packer would have
to be pulled.
If costs are based on a five-year testing frequency for Part 2 MIT, and the same set of required
tests are assumed, the Gruy and LBGES (1989b) cost estimates are comparable. However, if the
corrosive potential of some basins requires that a more frequent testing cycle be implemented, estimated
costs increase by about 40%. For purposes of this analysis, the costs and testing requirements assumed
for Part 2 MIT (injection zone confinement) were the same as those estimated by Gruy (1989), Estimated
costs for Part 2 MIT are presented in Table A-10, and estimated costs for assessing potential NIR fluid
movement are presented in Table A-11.
c. Description of Scenarios. For Part 1 MIT under the low scenario, the current five-year
testing frequency was assumed to be continued; therefore, no incremental compliance costs were
assumed. Under the medium scenario, adjustments in pressure testing frequency were assumed, with
the testing frequency based on the corrosive potential of the basin in which the well is located (after
Michie, 1988 and Gruy, 1989). Finally, under the high scenario, continuous PAPM was assumed, with
annual pressure testing for packerless wells. These scenarios are summarized in Table A-9.
06K00136. RPT page A-30
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TABLE A-9
ESTIMATED COSTS FOR PART 1
MECHANICAL INTEGRITY TESTING
Assumptions:
• 10% of existing wells are packerless
• All new wells will have tubing and packers
• Annular pressure monitoring required weekly on SWD wells and monthly on waterflood
injectors
• Annular pressure monitoring not required on packerless wells
Cost Estimates
Cost to pressure test well with tubing $400 per well
and packer
Cost for annular pressure monitoring $23.75 per well per visit
Cost to install annular pressure $1,500 per well
monitoring equipment
* Corresponds to cost for a SWD well, assuming one SWD well per 10 producing wells.
Source: Gruy, 1989
06K00138.TBL Page A-31
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TABLE A-9 (Continued)
ESTIMATED COSTS FOR PART 1
MECHANICAL INTEGRITY TESTING
Low Scenario
Pressure testing continues at current five-year frequency; no incremental compliance costs are
assumed.
Medium Scenario
Pressure testing frequency based on the corrosive potential of the basin in which the well is located.
Minor Casing Corrosion: 5 year testing frequency (see Figure 2 and Table III-3)
Possible Casing Corrosion: 3 year testing frequency
Significant Casing Corrosion: Annual testing frequency
New Fields:
Incremental Operating Costs: 0.90 (400/x-SO) per injector
(0.10) (0.90) (400/X-80) per producer*
where x is the required testing frequency in the basin
Discovered Fields:
Incremental Operating Costs: 0.90 (400/x-SO) per injector
(0.10) (0.90) (400/X-80) per producer*
where x is the required testing frequency in the basin
06K00138.TBL
Page A-32
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TABLE A-9 (Continued)
ESTIMATED COSTS FOR PART 1
MECHANICAL INTEGRITY TESTING
High Scenario
Assumes continuous positive annulus pressure monitoring on wells with packer; annual pressure
testing for existing packerless wells.
New Fields:
Incremental Capital Costs: Waterflood Injector $1,500 per injector
Producing Well $150 per producer*
Incremental Operating Costs: $23.75 (12) = $285 per injector per year
$23.75 (52) (0.10) = $123.50 per producer per year*
Discovered Fields:
Incremental Capital Costs: Waterflood Injector 0.90($1,500) = $1,350 per
injector
Producing Well 0.90($150) = $135 per
producer*
Incremental Operating Costs: 0.90(23.75)(12) = $256.50 per injector per year
0.90(23.75) (52) (0.10) = 111.15 per producer per
year*
06K00138.TBL Page A-33
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TABLE A-10
ESTIMATED COSTS FOR PART 2
MECHANICAL INTEGRITY TESTING*
Low Scenario:
Radioactive tracer test performed once every five years.
Cost of Radioactive Tracer Test: $1,000 + 0.24/ft
Allocating Costs of RAT on an Annual Basis:
Cost per Injector per Year: ($1,000 + 0.24/ft)/5
= 200 + 0.05/ft
Cost per Producer per Year:** ($1,000 + 0.24/ft)/5/10
= 20 + 0.005/ft
Medium Scenario:
Radioactive tracer test and noise or temperature log, with testing frequency based on basin
corrosivity.
Minor Casing Corrosion: 5 year testing frequency (see Figure 111-1 and Table III-4)
Possible Casing Corrosion: 3 year testing frequency
Significant Casing Corrosion: Annual testing frequency
Cost of Noise or Temperature Log: ($1,014 + 0.192/ft)
Allocating costs of RAT and noise or temperature log on an annual basis:
• Cost per Injector per Year: ($2,014 + 0.43/ft)/x
Cost per Producer per Year:** ($201.4 + 0.043/ft)/x
where x is the testing frequency in the basin, in years
All tests are run to the depth of the injection zone.
Assuming one SWD well per 10 producing wells.
Source: Gruy, 1989
06K00138.TBL Page A-34
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TABLE A-10 (Continued)
ESTIMATED COSTS FOR PART 2
MECHANICAL INTEGRITY TESTING
High Scenario
Radioactive tracer test, noise, and temperature log, performed at a frequency that is dependent on the
corrosivity of the basin.
• Cost of Noise and Temperature Logs: $1,464 + 0.288/ft
Allocating costs of RAT and noise and temperature logs on an annual basis:
Cost per Injector Per Year: ($2,464 + 0.53/ft)/x
Cost per Producer Per Year:** ($246 + 0.05/ft)x
where x is the testing frequency in the basin, in years
06K00138.TBL Page A-35
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TABLE A-11
ESTIMATED COSTS FOR ASSESSING
POTENTIAL NON-INJECTED-RELATED FLUID MOVEMENT
Low Scenario
No incremental costs.
Medium Scenario (Performed only on wells drilled prior to 1984, which were permitted by rule. This
corresponds to approximately 86% of all wells.)
Noise or temperature log to injection zone, and oxygen activation log (pulling tubing and packer) run
to lowermost USDW.
Cost to Pull Tubing and Packer:* $3,400 + 0.51/ft
Cost to Run OA Log: $1,420 + 0.515/ft
• Cost per Injector per Year:**
0.86(0.90(3,400 + 0.51/ft) + (1,420 + 0.515/ft)]/5
= 771 + 0.17/ft
Cost per Producer per Year:** $77 + 0.02/ft
High Scenario (Performed only on wells drilled prior to 1984, 86% of all wells.)
Same as Medium Scenario.
Tubing and packer pulled on 90% of wells with tubing and packer.
Assuming one SWD well per 10 producing wells.
Source: Gruy, 1989
06K00138TBL Page A-36
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A map indicating the corrosive potential of producing oil and gas basins in the U.S. is shown in
Figure A-2. Areas with minor casing corrosion were assumed to have a five-year testing frequency; areas
with possible casing corrosion were assumed to have a three-year testing frequency; and areas with
significant casing corrosion were assumed to require annual tests. For purposes of this study, some state
and regional aggregation of basins was performed to be consistent with the geographical disaggregation
assumed in the models used. The average testing frequencies assumed for the regions in this analysis
are presented in Table A-1 2.
For Part 2 MIT under the low scenario, the RAT test was assumed to be required once every five
years. Under the medium scenario, a FtAT and noise or temperature log were assumed to be required,
with the testing frequency depending on the corrosive potential of the basin. In the high scenario, a RAT,
noise, and temperature log were assumed, again with the testing frequency depending on the corrosivity
of the basin. All logs are run to the depth of the injection zone. These scenarios are summarized in
Table A-1 0.
Assessing potential NIR fluid movement was also considered in this analysis. Under the low
scenario, no NIR fluid testing requirements were assumed. Under the medium scenario, an OA log is was
assumed to be required to the lowermost USDW, with the tubing and packer pulled in the 90% of the
wells that have tubing and packer. Also, a noise or temperature log was required to the lowermost
USDW. In this case, however, only the incremental costs of the OA log were considered, since the costs
associated with the noise and/or temperature logs run for Part 2 MIT correspond to running the logs to
the depth of the injection zone, and therefore would already consider the run to the lowermost USDW.
Moreover, for purposes of this analysis, it was assumed that all required logs were run concurrently.
Under the high regulatory scenario, a noise and temperature log were assumed to be required with the
OA log. These scenarios are summarized in Table A-1 1 .
d. Total Compliance Costs. Estimated costs to comply with the potential revisions to MIT,
as discussed in this analysis, could range as high as $530 million per year, with initial investment costs
as high as $230 million. These costs include compliance with MIT Parts 1 and 2, and requirements for
monitoring potential NIR fluid movement, and are based on the number of injectors operating in the U.S.
in 1985.
2. Area of Review (APR)
a. General Description. Currently, every new injection well permit requires that an area of
review (AOR) investigation take place to see if any adjacent production or abandoned wells penetrate the
06K00136.RPT page
-------
Figure A-2
County Outline Map of the United States Showing
Counties Currently Productive of Oil and/or Gas and
Levels of Casing Corrosion
Corrotiv* Ariot ihoxn on thit mop Oft at dcdntd in iludy o*.
"Oil and Go> Industry Waltr Inaction Wtll CornMton", Prepared for
American Pilrolmm InnlluU. by MicftNi a Auocialti. Inc.,
Ftbfuor,, 1968.
MINOR CASINO CORROSION
POSSIBLE CASING CORROSION
SIGNIFICANT CASINO CORROSION
COUNTY OUTLINE MAP
OF THE
UNITED STATES
COUNTIES CURRENTLY PRODUCTIVE OF OIL AND/OR GAS
AND
LEVELS OF CASING CORROSION
SCAl E IN MILES
too u too too 100 400
WU1 ENGINFERIHG CORPORATrON
06K00135.RPT
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TABLE A-12
AVERAGE MECHANICAL INTEGRITY TESTING
FREQUENCY ASSUMED FOR EACH ANALYSIS REGION
BASED ON REGION'S CORROSIVE POTENTIAL
Supply Analysis Region Average Testing Frequency (years)
Alaska 5.00
West Coast 3.66
Northern Rockies 4.25
Central Rockies 3.20
Southern Rockies 3.00
Mid-Continent 3.30
West Texas 3.00
East Texas 3.00
Gulf Coast 4.33
North Central 5.00
Appalachia 5.00
Southeast 5.00
Source: Michie, 1988.
06K00138.TBL Page A-39
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proposed injection zone within a specified radius of the new injection well. If such wells are found, it must
be demonstrated that they pose no threat to USDWs. If there is a potential threat, corrective action must
be taken before the permit is granted.
As described in the Midcourse Evaluation draft final report (EPA, 1989), EPA is assessing the
feasibility of requiring AOR investigations for injection wells drilled prior to 1984, which were permitted by
rule and were not required to conduct an AOR evaluation. Gruy (1989) has estimated the costs of
obtaining required permits and of potential corrective action that may be required.
b. Estimate of Potential Compliance Costs. Gruy (1989) estimated the cost of obtaining a
permit to be about $23,340, plus the variable costs associated with logging wells within the AOR. For
such a well-specific permit, Gruy (1989) assumed that this cost would be the same regardless of the
number of wells within the AOR. However, if injection wells can be permitted by project through area
permits, rather than permitting each well individually, some cost savings can be incurred. Under this
scenario, Gruy (1989) estimated that the costs for area permits would be $15,280, plus $608 for each well
within the AOR, along with the variable costs associated with logging some of the wells within the AOR,
as mentioned above. These costs are summarized in Table A-13.
c. Description of Scenarios. For purposes of this study, the low scenario assumed that no
AOR analyses are required on injection wells previously permitted by rule. Under the medium scenario,
Gruy's (1989) estimate for performing 1/4 mile AORs under an area permit approach was assumed.
Finally, under the high scenario, Gruy's cost estimate for performing a 1/4 mile AOR on an individual well
was assumed. Estimates of the number of existing producers and abandoned wells within the AOR of
existing injectors are summarized by state in Table A-14, and by supply analysis region in Table A-15.
d. Total Compliance Costs. On a nationwide basis, the incremental costs for developing
AOR permitting applications for all wells previously permitted by rule are estimated to range from $2.3 to
$4.3 billion, based on the number of injection wells in 1985 that were permitted by rule. These costs do
not include corrective action resulting from performing the AORs.
3. Corrective Action
a. General Description. If wells are found within the AOR that pose a threat to groundwater,
corrective action must be taken concerning those wells. Possible corrective action includes squeeze
cementing the casing in active wells and plugging or replugging abandoned wells.
06K00136.RPT Page A-40
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TABLE A-13
ESTIMATED COSTS FOR PERFORMING AREA OF REVIEW
ANALYSES ON INJECTION WELLS DRILLED PRIOR TO 1984*
Low Scenario
No incremental costs assumed.
Medium Scenario
Gruy's (1989) cost estimate for performing a 1/4 mile AOR under an area permit.
• Cost of AOR Analysis $15,280 (assume 10 wells per area permit)
• Variable Logging Costs $3,046 + 0.605/ft (min. of 1,600 feet)
One log on 75% of injectors
Two logs on 20% of producing wells in AOR
$608 per well found within the AOR (see Tables III-6 and III-7).
Cost per existing injector =
0.86 { (0.10) 15,280 + [0.75 + (PW) (0.20) (2)] (3,046 + 0.605/ft)
+ 608 (1 + PW + AW)}
where PW = producing wells per injector within the AOR and AW = abandoned wells per injector
within the AOR (see Tables III-6 and III-7).
Example for a national-average, 5,000 foot injection well:
Cost = 0.86{ (0.10) (15,280) + [(0.75) + (2.44) (0.20) (2)] (3046 + 0.605(5000))
+ 608 (1+2.44+6.44)}
= $15,492/existing injector
Applies to wells currently permitted by rule; an estimated 86% of existing injectors were drilled
prior to 1984.
Source: Gruy, 1989
06K00138.TBL Page A-41
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TABLE A-13 (Continued)
ESTIMATED COSTS FOR PERFORMING AREA OF REVIEW
ANALYSES ON INJECTION WELLS DRILLED PRIOR TO 1984*
High Scenario
Gruy's (1989) cost estimates for performing 1/4 mile AOR analysis for an individual well.
Cost of AOR Analysis $23,340
• Variable Logging Costs $3,046 + 0.605/ft (min. of 1,600 feet)
One log on 75% of injectors
Two logs on 20% of producing wells in AOR
Cost per existing injector =
0.86 {23,340 + [0.75 + PW (0.20) (2)] (3,046 + 0.605/ft)}
Example for a national-average, 5,000-foot injection well:
Cost = 0.86{23,340+[(0.75)+ (2.44) (0.2) (2)] (3046+0.605(5000))
= $29,084/existing injector
06K00138.TBL Page A-42
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TABLEA-14
DISTRIBUTION BY STATE OF WELLS WITHIN TYPICAL AREA OF REVIEW
Wells Within AOR Wells Per Injector
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
West Virginia
Wyoming
Total
Injectors
215
511
5
1,235
19,481
983
77
14,548
3,307
14,861
5,417
4,159
1,657
981
402
1,330
717
12
4,451
3,254
529
3,956
24,916
6,183
41
10
52,740
654
572
4,979
Producers
127
353
3
3,891
45,172
703
26
27,989
7,101
45,257
16,075
5,577
1,909
465
172
2,040
505
9
6,994
8,263
307
11,014
79,312
17,508
21
4
134,401
694
861
3,733
Abandoned
Wells
67
241
19
7,000
58,964
1,628
89
76,628
29,833
109,134
23,978
17,854
6,860
2,072
1,066
5,981
2,280
21
7,664
4,483
385
21,523
149,576
237,440
47
5
333,302
1,556
1,997
7,715
Producers
0.59
0.69
0.60
3.15
2.32
0.72
0.34
1.92
2.15
3.05
2.97
1.34
1.15
0.47
0.43
1.53
0.70
0.75
1.57
2.54
0.58
2.78
3.18
2.83
0.51
0.40
2.55
1.06
1.51
0.75
Abandoned
Wells
0.31
0.47
3.80
5.67
3.03
1.66
1.16
5.27
9.02
7.34
4.43
4.29
4.14
2.11
2.65
4.50
3.18
1.75
1.72
1.38
0.73
5.44
6.00
38.40
1.15
0.50
6.32
2.38
3.49
1.55
TOTAL U.S.
172,183
420,486
1,109,408
2.44
6.44
Source:
Gruy, 1989
06K00138.TBL
Page A-43
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TABLE A-15
DISTRIBUTION BY REGION OF WELLS WITHIN THE
TYPICAL AREA OF REVIEW
Supply Analysis Region
Alaska
West Coast
Northern Rockies
Central Rockies
Southern Rockies
Mid-Continent
West Texas
East Texas
Gulf Coast
North Central
Appalachia
Southeast
Total
Injectors
511
19,493
1,859
6,616
4,456
42,131
28,755
5,756
22,388
19,512
19,392
1,273
Wells within
Producers
353
45,181
2,347
5,130
6,997
129,137
63,420
19,251
57,307
36,999
53,725
618
AOR
Abandoned
Wells
241
58,985
6,366
10,899
7,683
269,056
137,634
51,042
162,480
113,321
289,426
2,228
Wells per
Producers
0.69
2.32
1.26
0.78
1.57
3.07
2.21
3.34
2.56
1.90
2.77
0.49
Injector
Abandoned
Wells
0.47
3.03
3.42
1.65
1.72
6.39
4.79
8.87
7.26
5.81
14.93
1.75
Source: Gruy, 1989
06K00138.TBL
Page A-44
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b. Estimate of Potential Compliance Costs. LBGES (1988) estimates the cost for squeeze
cementing the production casing in active wells, including wireline, cement and rig
services, and supervision, to be approximately $26,000 per well. Gruy (1989) estimates that the cost for
the same activity would be about $20,650 per well. In this analysis, the Gruy cost estimates were used.
In addition, a certain number of the remedial squeeze attempts would not be successful.
Therefore, for purposes of this analysis, it was assumed that 20% of the remedial squeeze cementing
efforts attempted would fail. For these cases, the wells would have to be redrilled (this would be
consistent with the assumptions for construction requirements, discussed below).
Corrective action for abandoned wells was also considered by both Gruy and LBGES. In both
cases, two types of wells were considered: 1) wells with adequate surface casing that can be reentered,
where the cost to reenter and replug the well was estimated, and 2) wells without adequate surface casing
that cannot be reentered, where the cost to isolate and plug the well was considered. For abandoned
wells with adequate surface casing, Gruy (1989) estimated the costs to plug or replug to range from
$39,250 to $44,750 per 5,000-foot well, while LBGES (1988) estimated the costs for the same well to range
from $21,000 to $55,100 per well, with an average cost of $41,000 per well.
For abandoned wells without adequate surface casing, Gruy (1989) estimated the cost to isolate
and plug a 5,000-foot well to range between $63,750 and $71,250, while LBGES (1988) estimates of costs
for the same well depth range from $52,000 to $101,000 per well, with an average cost of $77,500 per
well.
Overall, the unit compliance costs estimated for corrective action by Gruy and LBGES were
comparable. Therefore, national estimates of the cost impacts of revisions in corrective action
requirements based on the two sets of incremental costs would not be very different. The true impact of
the potential revisions to AOR/corrective action requirements depends on the portion of wells requiring
corrective action. In this analysis, the compliance costs developed by Gruy were used.
c. Description of Scenarios. The low scenario assumes that no AORs on wells permitted by
rule would be required, and therefore no corrective action would be required. Under the medium
scenario, 5% of the producing wells within the AOR are assumed to require a remedial cement squeeze,
1% of the producers within the AOR would have to be redrilled, and 10% of the abandoned wells within
the AOR would have to be reentered and replugged. Under the high scenario, 15% of the producing
wells within the AOR would require a remedial cement squeeze, 3% of the producers within the AOR
06K00136.RPT Page A-45
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would have to be redrilled, and 30% of the abandoned wells within the AOR would require to be reentered
and replugged. These costs are summarized in Table A-16.
d. Total Compliance Costs. Estimated incremental compliance costs for correction action
could be as high as $14.3 billion, based on the number of injectors permitted by rule that were operating
in 1985.
4. Construction Requirements
a. General Description. Also under consideration is an extension of current construction
requirements for new wells to wells drilled prior to 1984, which were originally permitted by rule. The
construction requirements for new wells are intended to minimize groundwater contamination, and apply
to USDWs with less than 10,000 ppm total dissolved solids (TDS). The older wells generally had surface
pipe set to protect fresh water sources," which for most cases referred to a 3,000 ppm TDS limit. The
requirements under consideration generally consist of logging old wells to detect potential fluid movement,
pulling tubing, and squeeze cementing wells to the lowermost USDW (based on its 10,000 ppm TDS
definition).
b. Estimate of Potential Compliance Costs. Gruy (1989) assumed that 20% of the squeeze
jobs would have complications arise, and these wells would have to be plugged and redrilled. LBGES
(1988) assumed that 50% of the squeeze jobs would be unsuccessful in the first attempt, but a second
squeeze on these wells would always be successful. Thus, no wells would be abandoned under the
LBGES (1988) scenario. As a result, the unit costs of compliance for the construction requirements under
the Gruy scenario would be as much as 167% higher than those under the LBGES scenario, primarily
because of the costs associated with drilling new wells. In this analysis, the Gruy (1989) assumptions
concerning cement squeeze failure rates were assumed, since it is likely that some squeeze jobs would
fail. These costs are summarized in Table A-17.
c. Description of Scenarios. Under the low scenario, no incremental construction
requirements for wells permitted by rule were assumed. In the medium scenario, 10% of wells drilled prior
to 1984 were assumed to require a remedial squeeze. Of these wells, 20% (2% of all wells drilled before
1984) were assumed to fail the cement squeeze attempt, and would have to be plugged and redrilled.
In the high scenario, on the other hand, 30% of these wells were assumed to require a remedial squeeze.
Again, 20% of these wells (6% of all wells) were assumed to fail the cement squeeze attempt, and would
have to be plugged and redrilled.
06K00136.RPT PageA-46
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TABLE A-16
ESTIMATED COSTS FOR CORRECTIVE ACTION ASSOCIATED
WITH AREA OF REVIEW ANALYSES ON INJECTION WELLS DRILLED PRIOR TO 1984*
• Cost to Squeeze Cement Existing Producing Well within AOR
$18,000 + $0.53/ft
• Cost to Reenter and Replug Abandoned Wells within AOR
With adequate surface casing (90% of abandoned wells)
$30,250 + $2.35/ft
Without adequate surface casing (10% of abandoned wells)
$60,500 + $1.40/ft
• Cost to Redrill Well: Use Existing Model Estimates **
Low Scenario
No incremental costs assumed.
Medium Scenario
5% of existing producers within AOR require remedial squeeze.
10% of abandoned wells within AOR must be reentered and replugged.
1% of existing producers must be redrilled.
Cost per existing injector =
(PW) {(0.05) (18,000 + 0.53/ft) + (0.01) (Cost to redrill well)}
(AW) (0.10) (0.90 (30,250 + 2.35/ft) + 0.10 (60,500 + 1.40/ft)
Where PW = producing wells per injector with the AOR, AW = abandoned wells per injector within the
AOR
Applies to wells currently permitted by rule; an estimated 86% of existing injectors were drilled
prior to 1984.
Using existing model algorithms for well costs.
Source: Gruy, 1989
06K00138.TBL Page A-47
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TABLE A-16 (Continued)
ESTIMATED COSTS FOR CORRECTIVE ACTION ASSOCIATED
WITH AREA OF REVIEW ANALYSES ON INJECTION WELLS DRILLED PRIOR TO 1984*
High Scenario
15% of existing producers within AOR require remedial squeeze.
30% of abandoned wells within AOR must be reentered and replugged.
3% of existing producers must be redrilled.
Cost per existing injector =
(PW){(0.15) (18,000 + 0.53/ft) + (0.03) (Cost to redrill well)}
+ (AW) (0.30) (0.90 (30,250 + 2.35/ft) + 0.10 (60,500 + 1.40ft))
06K00138.TBL —
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TABLEA-17
COST ESTIMATES FOR POTENTIAL CONSTRUCTION
REQUIREMENTS FOR CLASS II INJECTION WELLS
(applied only to wells drilled prior to 1984)*
Cost Assumptions
Cost to Squeeze to Lowermost USDW $18,000 + $0.53/ft
Cost to Abandon Well $17,000 + $1.15/ft
Cost to Redrill Well Use Existing Model Estimates*
Low Scenario
No incremental costs assumed.
Medium Scenario
10% of wells require remedial squeeze
2% require redrilling
Cost per existing injector:
0.86 {(0.10)(18,000 + 0.53/ft) +
0.02 [ (17,000 + 1.15/ft) + (Cost to redrill well)]
High Scenario
30% of wells require a remedial squeeze
6% require redrilling
Cost per existing injector:
0.86 {(0.30)(18,000 + 0.53/ft) +
0.06 [ (17,000 + 1.15/ft) + (Cost to redrill well)]
Applies to wells currently permitted by rule; an estimated 86% of existing injectors were drilled
prior to 1984.
Using existing model algorithms for well costs.
Source: Gruy, 1989
06K00138.TBL Page A-49
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d. Total Compliance Costs. Nationwide compliance costs for this requirement are estimated
to be as high as $2.9 billion, given the number of injectors permitted by rule operating in 1985.
D. Regulatory Initiatives Not Analyzed
A number of other possible initiatives are also under consideration under the authority of the
SDWA that could also impact E&P activities. These include requirements for the temporary abandonment
of existing wells and requirements for plugging and abandoning wells, including those that may have been
improperly plugged and abandoned in the past and have not been identified and mitigated as part of the
AOR permitting process. The impacts of these potential regulatory initiatives on domestic crude oil
supplies were not analyzed as part of this assessment, since no compliance cost estimates for these
initiatives have yet been developed.
IV. CLEAN WATER ACT
A. Background
A number of regulatory proposals are also being considered under the authority of the Clean
Water Act that will likely affect U.S. oil and gas operations. These initiatives concern discharges to rivers,
streams, and lakes in the onshore and discharges to offshore waters. They concern discharges directly
associated with normal E&P operations, as well as stormwater discharges and spills (e.g., from above
ground storage tanks).
B. Summary of Proposed Initiatives
Among the potential regulatory initiatives under consideration under the Clean Water Act are
include those associated with the discharge of drilling fluids and cuttings from offshore facilities. Under
this category, potential initiatives include the development of a list of generic muds exhibiting low toxicity,
where offshore drilling operations would be limited to only using muds on the generic list. Other offshore
requirements could include specific toxicity testing requirements of drilling fluids and cuttings, restrictions
on the discharge of brines, deck drainage, produced sand, and well treatment fluids generated from
offshore facilities, and the use of effluent dispersion models to demonstrate potential risks associated with
offshore E&P activities. Potential requirements associated with discharges from onshore E&P facilities
include National Pollution Discharge Elimination System (NPDES) permit requirements for stormwater
discharges, regulations affecting the design and operation of above ground storage tanks, and
requirements for protecting wetlands and other sensitive coastal environments.
06K00136.RPT Page A-50
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C. Regulatory Initiatives Considered
The regulatory initiatives considered in this assessment under Clean Water Act authority concern
the discharge of drilling fluids and cuttings and produced waters from offshore facilities, NPDES permit
requirements for stormwater discharges, regulations affecting the design and operation of above ground
storage tanks, and the banning of onshore and coastal discharges. Each of these is discussed in detail
below.
1. Effluent Limitation Guidelines and New Source Performance Standards for the
Discharge of Drilling Fluids and Cuttings from Offshore Platforms
a. General Description. In August 1985, EPA proposed regulations under the Clean Water
Act to limit effluent discharges to U.S. waters from offshore oil and gas extraction facilities (50 FR 34592;
August 16, 1985). These proposed regulations established requirements for the discharge of produced
water, drilling fluids, drill cuttings, produced sand, and well treatment fluids from offshore operations. The
purpose of the proposal was to establish new source performance standards (NSPS), best available
technology economically achievable (BAT), and best conventional pollution control technology (BCT)
effluent limitation guidelines for the offshore segment of the oil and gas industry. The proposal also
amended the definition of "free oil" and the analytical method of compliance. After consideration of
comments on the proposal, EPA intended to promulgate a final rule.
Since the August 1985 proposal, EPA received numerous comments and collected additional
information on many aspects of the rulemaking. After assimilating and assessing this information, EPA
announced new proposed discharge regulations on drilling fluids and drill cuttings. (53 FR 41356; Oct.
21, 1988). This announcement also summarized the results of EPA's technical, economic, and
environmental assessments pertaining to these proposed regulations.
Regulations on the other waste streams included in the original August 1985 proposal were not
proposed and would be addressed in separate Federal Register announcements.
The proposed rule on the offshore discharge of drilling muds and cuttings consists of the following
limitations for both BAT and NSPS guidelines:
No discharge of oil-based fluids or cuttings associated with such fluids.
• No discharge of diesel oil in detectable amounts.
• No discharge of free oil' as measured by the static sheen test.
06K00136.RPT Page A-51
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Toxicity limitations measured by a 96-hour LC-50 test.
• Limitations on mercury and cadmium concentrations in drilling fluids.
For purposes of examining the potential impact of alternative regulatory scenarios on the
discharge of drilling fluids and cuttings from offshore facilities, EPA proposed four possible regulatory
approaches. These approaches were based on different toxicity failure rates for water-based drilling fluids
to which no oil has been added, and for different sets of effluent limitations for mercury (Hg) and cadmium
(Cd) in drilling fluids. These four approaches are summarized below:
Toxicity-Based Failure Rate for Limitations for
Approach Water-Based Fluids (%) + Hq & Cd*
A 15 1,1
B 2 1,1
C 15 1.5,2.5
D 2 1.5,2.5
+Assumes that no lubricity agents or spotting fluids have been added.
*1,1 means a maximum acceptable concentration of 1 mg/kg for mercury and cadmium in discharged
drilling fluids; 1.5, 2.5 means a maximum acceptable concentration of 1.5 mg/kg for mercury and 2.5
mg/kg for cadmium in discharged drilling fluids.
b. Estimate of Potential Compliance Costs. EPA's compliance cost estimates corresponding
to their proposed rule distinguished between offshore wells drilled with oil and water-based drilling muds
(53 FR 41356; Oct. 21,1988). Based on 1984 API drilling data, EPA determined that 30.8% of the offshore
wells drilled were deeper than 10,000 feet. In their costing analysis, welfs drilled deeper than 10,000 feet
were assumed to use oil-based muds for the depth interval greater than 10,000 feet, presumably because
of the more difficult drilling situation posed at greater well depths. Although some operators would
continue to use oil-based drilling muds for all depths of wells, the discharge of these muds is already
prohibited. Therefore, the current analysis only considered the incremental costs associated with
regulatory initiatives concerning water-based muds.
After examining various methods for treating oil-laden drilling wastes before discharging (including
thermal and solvent extraction techniques), EPA concluded that transport to shore for reconditioning or
land disposal was the lowest-cost method for managing drilling wastes which fail to meet the proposed
effluent limitation standards.
06K00136.RPT Page A-52
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Three possible land disposal alternatives were developed by EPA for purposes of their analysis
on the basis of the ability to store the wastes during high seas or offload these wastes for transport to
shore. These alternatives are presented below:
• Rigs with no storage space for drilling wastes, but designed for loading
boats in seas with wave heights of up to 6 feet. If wave heights
exceeded 6 feet, drilling would have to cease for the period that the wave
heights were in excess of 6 feet and supply boats were unable to tie up
at the facility.
• Rigs with no storage space for drilling wastes, but designed for loading
boats in seas with wave heights of up to 10 feet. If wave heights
exceeded 10 feet, drilling would have to cease for the period that the
wave heights were in excess of 10 feet and supply boats were unable to
tie up at the facility.
• Rigs retrofitted for drilling wastes storage. These rigs could continue to
drill even when supply boats were unable to tie-up at the facility.
EPA assumed that the majority of operators would retrofit rigs for drilling fluid storage, since this
would result in overall lower costs for the disposal of drilling fluids. The costs are lower because supply
boats would not be dedicated solely to drilling waste disposal. They estimated that 80% of the rigs would
be retrofitted, 10% would operate using a maximum permissible wave height of 10 feet and 10% would
operate using a maximum permissible wave height of 6 feet. This breakdown was also assumed in these
analyses.
The costs of waste transport to shore for water-based drilling fluids and drill cuttings associated
with water-based fluids used for assessing each of three alternatives (including downtime costs) are as
follows (53 FR 41356; Oct. 21, 1988):
Cost of Transport ($/Bbl of waste)
Transport Option Drilling Fluids Drill Cuttings
No storage, max. 6 ft. waves 78 58
No storage, max. 10 ft. waves 61 45
Rig retrofitted for storage 46 33
For all three alternatives, the costs assumed for onshore landfill disposal were $6.50 per barrel
of fluid and $6.00 per barrel of cuttings. These costs were added to the transportation costs for each
alternative.
06K00136.RPT Page A-53
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Estimates for the amount of fluid and cuttings generated during drilling were developed by EPA.
For a typical 10,000 foot well, 6,749 barrels of drilling fluids and 1,430 barrels of drill cuttings were
estimated to be generated (53 FR 41356; Oct. 21, 1988). An additional bulk mud discharge of 1,400
barrels, to account for the active mud system and the end of drilling operations, was also considered and
included in estimating potential mud handling and disposal costs.
The disposal costs assumed in this analysis were based on the relative frequency of occurrence
of each of the disposal scenarios. The determination of the weighted-average disposal cost developed
by EPA is summarized in Table A-18.
API also considered the costs of EPA's proposed rule on the offshore discharge of drilling fluids
and cuttings (Walk, Haydel, 1989; EAI, 1988). This analysis was based on EPA's Approach A, the most
costly of the four scenarios considered by EPA in their examination of the potential impacts of the
proposed rule and the scenario that most closely resembles the situation originally proposed by EPA in
1985.
In addition to this scenario, called the 'Partial Discharge Limitation" scenario, API also considered
a "Zero Discharge Limitation" scenario, where no offshore disposal of fluids and cuttings would be allowed.
Consideration of this scenario is justified since most operators will be unable to determine a priori whether
the drilling fluids they use or cuttings they generate will fail toxicity or static sheen tests, or whether the
conditions they encounter will require the addition of potentially toxic additives. These operators, in
economically justifying their projects, will assume onshore disposal (for a conservative prospect
evaluation).
API performed independent analyses of the compliances costs associated with the proposed rule.
In their analyses, they estimated the projected quantities of muds and cuttings to be disposed; onshore
disposal capabilities, limitations, and costs; offshore transportation limitations and costs; and downtime
costs, issues related to the safety aspects of the handling and transportation of fluids and cuttings, the
environmental impacts of onshore disposal, and issues related to disposal facility regulatory
compliance/permitting and clean-up exposure (Walk, Haydel, 1989).
API reported on what they believed to be several major shortcomings of the EPA analyses. First,
API believed that EPA erred in assuming that onshore disposal costs would remain constant, due to
increasing restrictions on landfill operations (higher costs and decreasing available disposal sites).
Moreover, API felt that other EPA-estimated costs, such as monitoring and "clean" barite costs, were also
too low (Randolph and Simpson, 1988). Also, API considered EPA estimates of the amount of fluids and
06K00136.RPT ~Page A-54
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TABLE A-18
COSTS ESTIMATED BY EPA FOR THE PROPOSED EFFLUENT LIMITATION
STANDARDS FOR THE OFFSHORE DISCHARGE OF DRILLING MUDS AND CUTTINGS
Frequency of Occurrence (%)
Volume of Waste per Well (Bbl)*
Muds
- Cuttings
Disposal Cost ($/Bbl)**
Muds
Cuttings
Disposal Cost ($/Well)**
Muds
Cuttings
Weighted Disposal Cost ($/Well)
Muds
Cuttings
Weighted Disposal Cost ($/Foot)*
Muds
Cuttings
Weighted Disposal Cost
Accounting for Frequency
of Discharge ($/Foot) +
Muds
Cuttings
6 Foot Max.
Wave Heiaht
10
8,149
1,430
84.50
64.00
688,590
91 .520
780,110
68,859
9,152
6.88
0.92
1.60
0.06
10 Foot Max.
Wave Height
10
8,149
1,430
67.50
51.00
550,058
72.930
622,988
55,006
7,293
5.50
0.73
1.28
0.05
Rig Retrofit
for Storage
80
8,149
1,430
52.50
39.00
427,822
55,770
483,592
342,258
44,616
34.23
4.46
7.98
0.30
Weighted
Total
466,123
61,061
46.61
6.11
52.72
10.86
0.41
11.27
* Assumes a 10,000 foot well.
** Includes transportation and disposal costs.
+ Assumes that 23.3% of drilling muds and 6.7% of drill cuttings are barged to shore.
Source: 53 FR 41356; October 21, 1988
06K00138.TBL Page A-55
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cuttings generated and requiring transport for onshore disposal to be too low. Finally, API felt that there
are significant differences in compliance costs in the different offshore regions, differences which EPA did
not consider.
API's estimates of the average costs of disposal for fluids and cuttings under their Partial
Discharge Limitation scenario are presented in Table A-19. Costs for the Zero Discharge Limitation
scenario are presented in Table A-20. These costs incorporate the volumes assumed by API for muds
and cutting requiring onshore disposal.
The models developed and maintained by ICF Resources to assess U.S. offshore crude oil
resources are only capable of examining that portion of the resource that remains to be discovered. No
current capability exists to examine the resource impacts on production from existing offshore facilities.
Therefore, no assessment of the energy impacts of this regulatory initiative on existing offshore facilities
was conducted.
c. Description of Scenarios. For purposes of this assessment, the low scenario corresponds
to the EPA estimate of costs for Approach A, which assumes that 23.3% of drilling fluids and 6.7% of drill
cuttings must be barged to shore and disposed at an onshore facility. The medium scenario corresponds
to the API estimates of costs for Approach A, or their Partial Discharge Limitation scenario. API assumed
that a higher portion of muds and cuttings must be transported to and disposed of onshore, relative to
EPA's determination (Randolph and Simpson 1988). Finally, the high scenario assumed API's estimated
costs of compliance for the Zero Discharge Limitation scenario. These scenarios are described in Table
A-21.
d. Total Compliance Costs. Assuming 1985 levels of offshore well drilling, total industry
compliance costs corresponding to this initiative are estimated to range from $76 to $385 million per year.
2. Effluent Limitation Guidelines and New Source Performance Standards for the
Discharge of Produced Waters from Offshore Facilities
a. General Description. The 1985 proposed rule concerning effluent guidelines under the
CWA (50 FR 34592; August 26, 1985) also contained provisions concerning the discharge of brines
produced from offshore oil and gas producing operations. Under this rule, BAT effluent limitation
guidelines for produced water; along with guidelines for pollutants other than free oil in deck drainage,
produced sand, and well treatment fluids were reserved for future rulemaking. New source performance
standards were also established that would prohibit the discharge of produced water from oil production
06K00136.RPT Page A-56
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TABLE A-19
AVERAGE DISPOSAL COSTS ESTIMATED BY API
FOR OFFSHORE DRILLING FLUIDS AND CUTTINGS DISPOSAL
FOR PARTIAL DISCHARGE LIMITATION SCENARIO
(Costs in Dollars per well except where noted)
Drilling Muds
1 . Disposal
2. Handling
3. Container Rental
4. Transportation
5. Contingency
TOTAL
Average Depth (feet)
Cost per Foot Drilled ($/ft)
Drill Cuttings
1 . Disposal
2. Handling
3. Container Rental
4. Transportation
5. Contingency
TOTAL
Average Depth (feet)
Cost per Foot Drilled ($/ft)
Gulf of
Mexico
70.4002
21,100
8,900
46,300
8.800
155,500
10,550
14.74
31.1002
9,300
53,300
15,500
6.600
115,800
10,550
10.98
Pacific
49,000
14,700
8,900
16,900
5.400
94,900
6,530
14.53
20,300
6,100
53,300
5,600
5.100
90,400
6,530
13.84
Atlantic
44,100
13,200
8,900
19,700
5.200
91,100
14,874
6.12
19,500
5,900
53,300
6,600
5.100
90,400
14,874
6.08
South
Alaska1
317,150
95,150
8,900
25,400
26.800
473,400
10,057
47.07
114,200
34,250
53,300
8,400
12.600
222,750
10,057
22.15
North
Alaska1
317,150
91,150
8,900
2,683,150
186,300
3,286,650
10,057
326.80
114,200
34,250
53,300
894,400
65.750
1,161,900
10,057
115.53
TOTAL COST PER FOOT
25.72
28.37
12.20
69.22
442.33
Represents midrange of costs presented in source document.
Includes barging from transfer station.
Source: Walk, Haydel, 1989.
06K00138.TBL
Page A-57
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TABLE A-20
AVERAGE DISPOSAL COSTS ESTIMATED BY API
FOR OFFSHORE DRILLING FLUIDS AND CUTTINGS DISPOSAL
FOR ZERO DISCHARGE LIMITATION SCENARIO
(Costs in Dollars per well except where noted)
Drilling Muds
1 . Disposal
2. Handling
3. Container Rental
4. Transportation
5. Downtime
6. Contingency (6%)
TOTAL
Average Depth (feet)
Cost per Foot Drilled ($/ft)
Drill Cuttings
1 . Disposal
2. Handling
3. Container Rental
4. Transportation
5. Downtime
6. Contingency (6%)
TOTAL
Average Depth (feet)
Cost per Foot Drilled ($/ft)
Gulf of
Mexico
141.2002
42,400
4,200
150,200
31,900
22.200
392,100
10,550
37.17
62,4002
18,700
25,200
50,100
10,600
10,000
177,000
10,550
16.78
Pacific
220,800
66,200
12,600
81,600
95,600
28,600
505,400
6,530
77.40
91,300
27,400
81,900
27,200
31,900
15,600
275,300
6,530
42.16
Atlantic
267,200
80,200
12,600
241,900
95,600
41.900
739,400
14,874
40.71
118,1002
35,400
81 ,900
80,600
31,900
20.900
368,800
14,874
24.79
South
Alaska1
1,369,050
410,750
12,600
143,500
900,000
170.150
3,006,050
10,057
298.90
496,400
148,950
81,900
47,800
300,000
64.550
1,139,600
10,057
113.31
North
Alaska1
1 ,369,050
410,750
12,600
7,875,000
6,750,000
985.050
8,701,225
10,057
865.19
496,400
148,950
81,900
2,625,000
2,250,000
336.150
5,938,400
10,057
590.47
TOTAL COST PER FOOT
53.94
119.56
74.51
412.22
1,455.67
1 Represents midrange of costs presented in source document.
Includes barging from transfer station.
Source: Walk, Haydel, 1989.
06K00138.TBL
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TABLE A-21
REGULATORY SCENARIOS CONCERNING EFFLUENT LIMITATION STANDARDS
FOR THE OFFSHORE DISCHARGE OF DRILLING FLUIDS AND CUTTINGS
Low Scenario
Assumes EPA Approach A (23.3% of drilling fluids and 6.7% of drill cuttings must be transported to
shore for disposal) and EPA's estimate of unit compliance costs, applied to the 69.2% of current
offshore wells which are assumed to require only water-based muds.
Cost = [(0.233)($46.61/foot) + 0.067($6.11/foot)] (10,000 feet/well)(0.692)
= $77,985/well
Medium Scenario
Assumes EPA Approach A and API's estimate of unit compliance costs (API's Partial Discharge
Limitation Scenario)
Cost per well = (WCp) (WD) (0.692)
where WC = API's estimate of compliance costs per foot drilled for each region for the Partial
Discharge Limitation Scenario, weighted for the frequency of occurrence of wastes requiring
onshore disposal
where WD = API's estimate of average well depth for each region.
High Scenario
Assumes API's Zero Limitation Discharge Scenario
Cost Per Well = (WCZ) (WD) (0.692)
where WCZ = API's estimate of compliance costs per foot drilled for each region for the Zero
Discharge Limitation Scenario
06K00138.TBL Page A-59
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facilities that would be located in or discharged to shallow water areas as defined in the proposed
regulations. Produced water discharges from new offshore facilities in deeper water would be limited to
a maximum oil and grease concentration of 59 mg/l (i.e., no single sample to exceed).
Under the rule, shallow water was defined by offshore region as follows:
Gulf of Mexico, Atlantic Coast, and Norton Basin: <; 20 meters
• Pacific Coast, Cook Inlet/Shelikof Strait, Bristol Bay,
and Gulf of Alaska: <; 50 meters
Beaufort Sea: <; 10 meters
As stated above, no final proposed rule concerning produced water or other constituents
discharged from offshore platforms other than drilling fluids and cuttings has been issued to date.
Treatment of produced water to a 59 mg/l concentration for oil and grease (the current
requirement is a 72 mg/l concentration) would utilize treatment systems modified to achieve the more
stringent standard. Systems considered by API (Walk, Haydel, 1984) to be appropriate for estimating
treatment costs include gas flotation systems, parallel plate coalescers, and loose media coalescers.
Other potential systems, such as gravity separation or chemical treatment systems, were not considered
by API.
b. Estimate of Potential Compliance Costs. EPA (50 FR 34592; August 26, 1985), in their
economic impact assessment, assumed that the costs of chemical treatment systems would be minimal.
API (Walk, Haydel, 1984) developed detailed cost estimates for these potential treatment systems prior
to the issuance of the proposed rule, demonstrating that these costs were probably larger than EPA
estimates. The produced water reinjection scenarios considered in this assessment assume preliminary
treatment to remove suspended material and to reduce concentration levels of oil and grease, followed
by subsurface injection.
Estimated compliance costs for treatment systems for existing facilities were developed by API
(Walk, Haydel, 1984) and were represented by a weighted-average cost curve for flotation, plate
coalescers, and loose media coalescers based on their current relative frequency of use in the Outer
Continental Shelf (OCS). Similar costs were developed for the tanks and advanced treatment systems
applicable for new facilities. These costs, which included allowances for desanders, slop oil tanks, and
tank separation, represented the entire treatment train for facilities which elect to use such systems for
final treatment. These costs are summarized in Table A-22.
06K00136.RPT Page A-60
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TABLE A-22
COST OF PRODUCED WATER TREATMENT SYSTEMS REQUIRED FOR
COMPLIANCE WITH POTENTIAL EFFLUENT LIMITATION GUIDELINES AND NEW SOURCE
PERFORMANCE STANDARDS FOR OFFSHORE PRODUCED WATER DISCHARGES
A. Existing Facilities (BAT) (based on new units added to existing facilities for incremental
treatment from 72 mg/l to 59 mg/l oil/grease concentration. This represents the weighted-
average capital cost for flotation, plate coalescers, and loose media coalescers as based on
their relative frequencies in the OCS).
Installed Capital Cost = 0.810 (106) (0.0468Q0-28)
where Q = Water Treatment Capacity, in Bbl/day (designed for maximum assumed
water throughput)
(Factor of 0.810 adjusts 1983 source costs to 1988 conditions in the oilfield, to be consistent
with other baseline model costs.)
Annual Direct Operating Costs = 0.11 (Capital Cost), in $/year
Annual Fuel Costs = $3,000/year
B. New Facilities (NSPS) (based on costs for tanks and advanced treatment systems, including
desanders, sumps, slop oil tanks, and tank separation)
Installed Capital Cost for Tanks = 0.810 (204C - 995)
where C = Tank Capacity, in Bbl (for purposes of analysis, a 3,000-barrel tank
capacity is assigned)
Installed Capital Cost for Advanced Treatment Systems =
0.810(1000) (exp(0.342ln(T) + 6.136))
where T = Water Treatment Capacity, in MBbl/day (designed for maximum assumed
water throughput)*
Annual Direct Operating Cost = 0.11 (Capital Costs)
Annual Fuel Costs = $3000/year
* Assuming an average producing watenoil ratio of 3 barrels of water per barrel of oil.
Source: Walk, Haydel, 1984.
06K00138.TBL Page A-61
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Estimated compliance costs were also considered for produced water injection, which includes
the costs for preinjection treatment and injection wells and equipment. Preinjection treatment included
costs for filtration, an injection feed tank, and injection pumps. For new facilities, costs also included
desanders, sumps, and slop oil tanks, but did not include the costs for the handling and disposal of fines.
Injection well costs were determined assuming a well capacity of 6,000 barrels per day with the rig
mobilization/demobilization costs shared with production wells at new facilities. No adjustment in project
economics was made to account for the platform slots that would be removed from production to allow
for the additional injection wells required, however. The costs assumed for produced water injection
systems are summarized in Table A-23.
Incremental platform costs were also considered for the additional facilities required to comply with
the proposed rule. For existing facilities, an auxiliary 1,000 square foot wing deck was assumed. For new
facilities, a pro rata share of incremental platform space for the additional required well slots and
equipment was determined and considered in the incremental compliance cost impacts, using platform
costing algorithms used in the ICF Resources economic analysis models. These costs are summarized
in Table A-24.
c. Description of Scenarios. For purposes of this analysis under the low regulatory scenario,
existing facilities were assumed to require treatment to 72 mg/l (which is the current requirement), thus
requiring no incremental compliance costs. New facilities under the low scenario were assumed to treat
waters to a oil/grease concentration of below 59 mg/l.
Under the medium scenario, existing facilities would require treatment to the 59 mg/l standard.
New facilities in shallow water would be prohibited from discharging produced water, while new facilities
in deep water would treat to the 59 mg/l standard.
Under the high scenario, existing facilities would be regulated like new facilities in the medium
scenario. However, under this scenario, it was assumed that all new facilities (at all depths) would be
prohibited from discharging produced waters.
The scenarios for offshore produced water disposal assumed in this study are summarized in
Table A-25.
As was the case for regulations associated with the discharge of drilling muds and cuttings, no
attempt was made in this analysis to examine the impacts of restrictions on produced water discharges
06K00136.RPT Page A-62
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TABLE A-23
COST OF PRODUCED WATER INJECTION SYSTEMS REQUIRED
FOR COMPLIANCE WITH POTENTIAL EFFLUENT LIMITATION GUIDELINES
AND NEW SOURCE PERFORMANCE STANDARDS FOR OFFSHORE PRODUCED
WATER DISCHARGES
A. Preelection Treatment
1. Capital Costs
a. BAT
Installed Cost = 0.810(106) (0.0374Q0-48)
b. NSPS
Installed Cost = 0.810(106) (0.043Q0-47)
where Q = Design Water Throughput, in Bbl/day (designed for maximum assumed water
throughput)*
2. Annual Operating Costs
a. BAT and NSPS
Direct Cost = 0.065 (Installed Capital Cost)
Fuel Cost = $3,500/year
B. Injection Wells
The number of injection wells required was determined based on the volume of produced
water to be discharged; accounting for water required in the waterflood operation, and
assuming a 6,000 Bbl/day disposal well capacity.*
The depth of the disposal wells are assumed to be 4,000 feet; costs of these wells are
determined by costing algorithms in the ICF Resources' analysis models.
Injection well operating costs also based on model algorithms.
* Assuming an average producing water-oil ratio of 3 barrels of water per barrel of oil.
Source: Walk, Haydel, 1984; ICF-Lewin Energy, 1988.
06K00138.TBL Page A-63
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TABLE A-24
INCREMENTAL PLATFORM COSTS REQUIRED FOR COMPLIANCE
WITH POTENTIAL EFFLUENT LIMITATION GUIDELINES AND NEW SOURCE
PERFORMANCE STANDARDS FOR PRODUCED WATER DISCHARGES
A. Existing Facilities
1. Treatment Equipment (assumes a 1,000 ft2 auxiliary wing deck)
Cost = 0.810 (150,000) = $121,500
2. Disposal Systems
For purposes of this analysis, existing slots and platform space on existing facilities was
assumed to be available for the incremental wells required; thus, no incremental platform costs
are assumed.
B. New Facilities
Incremental costs for new platforms were determined based on the additional number of well
slots and deck space required, using algorithms for platform costs already in the ICF
Resources' offshore analysis model.
C. Annual Direct Operating Costs
For both existing and new facilities, incremental platform maintenance/operating costs were
assumed to be 2% of incremental capital costs.
Source: Walk, Haydel, 1984; ICF-Lewin Energy, 1988.
06K00138.TBL Page A-64
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TABLE A-25
PROPOSED SCENARIOS FOR POTENTIAL EFFLUENT
GUIDELINES AND NEW SOURCE PERFORMANCE STANDARDS
FOR OFFSHORE PRODUCED WATER DISCHARGES
Low Scenario
Existing Facilities:
New Facilities:
Treatment to 72 mg/l
(no incremental costs)
Treatment to 59 mg/l; include costs for produced water treatment
systems
Medium Scenario
Existing Facilities:
New Facilities:
Treatment to 59 mg/l; include costs for produced water treatment
systems
Shallow water, no discharge; include costs for produced water pre-
injection treatment and re-injection.
Deep water, treatment to 59 mg/l; include costs for produced water
treatment systems
High Scenario
Existing Facilities:
New Facilities:
Shallow water, no discharge; include costs for produced water pre-
injection treatment and re-injection.
Deep water, treatment to 59 mg/l; include costs for produced water
treatment systems
All depths, no discharge; include costs for produced water pre-
injection treatment and re-injection systems and additional required
well slots and platform space.
06K00138.TBL
Page A-65
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on crude oil supplies from existing offshore facilities, even though the potential costs incurred by existing
facilities are presented in Tables A-22 through A-24.
d. Total Compliance Costs. Walk, Haydel (1984), in their work for API, estimated the total
compliance costs for complying with new BAT, BPT, and NSPS as described in the proposed rule. The
assumptions in the Walk, Haydel assessment are the same as those proposed here, except that some
additional modifications were made to the number of affected facilities, based on Lewin and Associates
(1986) modification to account for alternative assumptions for varying well productivity with field size, and
alternative assumptions for the volumes of water produced, as corrected.2' Walk, Haydel estimated that
the annualized cost for the Gulf of Mexico (where most of U.S. OCS activity will take place) to comply with
NSPS will average about $200 million per year (the costs for complying with the BPT and BAT standards
would be small relative to NSPS). Adjusting this for a revised estimate of the number of platforms affected
(resulting in 358 rather than 278 total platforms) would give the total annual industry compliance cost as
approximately $260 million per year (200 x 358/278). Based on EPA's projections (EPA, 1985), 16% of
the total platforms projected to the year 2000 will be within the shallow water demarcation. Based on this
assumption, if platforms at all water depths are prohibited from discharging produced brines, compliance
costs could be as high as $1.6 billion (260/0.16) per year.
3. NPDES Permits for Stormwater Discharges
a. General Description. Another regulatory initiative being considered under authority of
CWA concerns NPDES permit application regulations for stormwater discharges, as proposed in 53 FR
49416 (December 7, 1988). Under previous legislation (Section 401 of the Water Quality Act, amending
Section 402(1)(2) of the CWA), stormwater runoff from most oil and gas operations was not considered
a significant environmental concern. Consequently, Congress prohibited EPA from requiring NPDES
permits from oil and gas operations for stormwater discharges from point sources into navigable waters
if the discharges "... are not in contact with, or do not come into contact with, any overburden, raw
material, intermediate products, finished product, byproduct, or waste products located on the site of such
operations.1 However, in the proposed rule, EPA has significantly reinterpreted this statutory exemption.
b. Estimate of Potential Compliance Costs. An estimated 55% of above ground tanks
associated with existing production facilities are within a mile of navigable waters (Entropy Limited, 1989).
Consequently, the wells associated with these locations would require discharge permits since they risk
^Based on letter from Mr. J. A. Burgbacher, Shell Offshore to Mr. J.K. Jackson, API, entitled "Follow Up on
March 14, 1986 Meeting with OMB," which responds to a misinterpretation in the Lewin and Associates, Inc. (1986)
report.
06K00136.RPT Page A-66
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stormwater discharges to surface waters. Assuming that NPDES stormwater discharge permits cost
$4,500, this initiative would result in an incremental compliance cost of approximately $2,475 per producer
(55% of $4,500).
c. Description of Scenarios. For purposes of this analysis, these costs were assumed to
apply to all three regulatory scenarios.
d. Total Compliance Cost. Assuming the number of production and injection wells operating
in 1985, the costs incurred to comply with this initiative are estimated to be $2.6 billion.
4. Design and Operation of Above Ground Storage Tanks
a. General Description. Several recent incidents have significantly increased public concern
about regulating above ground storage tanks (ASTs). These incidents include the January 1989 spill at
Florette, Pennsylvania of 18,000 barrels of diesel fuel into the Monongahela River and numerous incidents
of groundwater contamination from leaking above ground storage tanks. As a result, several bills have
been introduced in Congress in response to concerns arising as a result of these incidents.
Following the spill in Pennsylvania, EPA convened a task force to examine existing regulatory
provisions for the prevention and control of oil spills. The task force was comprised of over 60 members,
including EPA staff, state officials, and representatives from other federal agencies. The major conclusion
of the task force was that the Spill Prevention, Control, and Countermeasure (SPCC) provisions of the
Clean Water Act remain the most appropriate regulatory authority for controlling above ground storage
and release of oil. With regards to the SPCC plans, the task force had the following recommendations:
EPA should survey facilities subject to SPCC regulations by:
Conducting an inventory of ASTs
Determining the amount of hazardous substances stored in ASTs.
EPA should amend SPCC regulations by:
Requiring notification to the EPA of each facility covered by a SPCC program
Changing several provisions from guidelines to mandatory requirements
Requiring inclusion of specific contingency plans
Adding requirements for tank integrity standards, testing (inspection), and
emergency response training
Relating SPCC stringency to facility size.
06K00136.RPT Page A-67
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• EPA should enhance inspection programs by:
Developing inspection manuals and training inspectors
Developing SPCC inspection target policy to prioritize inspections
Increasing the number of inspections from 1,000 in 1988 to 6,500 in 1993.
• EPA should develop a formal penalty policy.
As a result of the interim report, the EPA is now in the process of evaluating changes to the SPCC
Program. One proposal being considered is the changing of "shoulds" to "shalls1 within the regulations.
The petroleum industry is concerned that this change in wording could result in:
• Diking entire plant or facility areas
• Totally impervious dikes
• More rigorous requirements on partially buried storage tanks
• Periodic integrity testing of tanks and associated piping
• Utilization of blowout preventers on all workovers
• Sump systems for all facilities with automated pumping systems (which includes a spare
pump)
• Inclusion of shut-in valve operating guidelines as part of SPCC Plan
• Retention of records associated with inspections
• Fences and security lighting.
b. Estimate of Potential Compliance Costs. Based on the current regulatory proposals under
consideration, future above ground storage tank regulations could conceivably address the following
aspects:
• Inspection and integrity testing
• Overflow prevention equipment
• Leak detection equipment
• Additional corrosion protection
• Financial responsibility requirements.
Approximately 900,000 above ground storage tanks associated with E&P operations are
conservatively estimated to exist in the U.S., with a total storage capacity of 2.3 billion barrels (Entropy
Limited, 1989). An estimated 89% of the tanks associated with production operations have less than 500
06K00136.RPT Page A-68
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barrels capacity. Regulations addressing the aspects listed above are estimated to cost approximately
$5,000 per tank, with each aspect costing roughly $1,000 per tank. Each tank battery was assumed to
consist of four tanks. Four producing wells were assumed to be associated with each tank battery.
c. Description of Scenarios. For purposes of this analysis, the low scenario assumed that
existing tanks are 'grandfathered' from future regulatory proposals, and that limited regulations are applied
only to new tanks larger than 1,000 barrels (representing 4% of existing tanks). These regulations would
consist of leak detection and financial responsibility requirements and would represent a noticeable
deviation from the existing exemption. The medium scenario assumed that all new tanks greater than or
equal to 500 barrels would have to comply with all aspects of the regulations, and that existing tanks and
tanks smaller than 500 barrels would only need to meet the financial responsibility requirements. Finally,
the high scenario assumed that both existing and new tanks of all sizes are subject to all aspects of the
proposed regulations, similar to existing regulations for underground storage tanks. A description of these
scenarios and their associated costs is presented in Table A-26.
d. Total Compliance Costs. The total cost to comply with this initiative as described in the
scenarios presented above, considering only existing production facilities (as of 1985), is estimated to
range from $0.9 to $4.3 billion.
5. Ban on the Onshore and Coastal Surface Discharge of Drilling Fluids. Drill Cuttings.
and Produced Brines
a. General Description. Another set of potential regulatory revisions under consideration
pertain to the ban on the onshore and coastal surface discharge of drilling muds, drill cuttings, and
produced brines onshore. This could potentially include a ban on the discharge of drilling muds, drill
cuttings, and produced water to areas classified as coastal, the discharge of produced waters to unlined
surface pits such as percolation ponds or evaporation pits, and the discharge of produced waters for
beneficial uses, such as irrigation. Although these restrictions would only apply to unique practices in
specific regions, their impact on E&P operations in these regions could be significant.
b. Estimate of Potential Compliance Costs. A portion of the oil and gas wells drilled are
located in regions considered to be in the Coastal Subcategory. Assuming that these wells would dispose
of their muds and cuttings in lined reserve pits or other offshore disposal facilities, then the costs of
banning the discharge of these fluids to coastal waters have been implicitly considered in Section II.C.1.
Therefore, they were not included in this section.
06K00136. RPT Page A-69
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TABLE A-26
COMPLIANCE COST ESTIMATES FOR POTENTIAL REGULATIONS
AFFECTING ABOVE GROUND STORAGE TANKS
Assumptions
1. Above ground storage tank regulations would address five aspects:
• Injection and integrity testing
• Overflow prevention equipment
• Leak detection equipment
• Additional corrosion protection
• Financial responsibility requirements
The cost of each aspect is $1,000 per tank.
2. 89% of storage tanks associated with current production facilities have a capacity of 500
barrels or less.
3. 96% of storage tanks associated with current production facilities have a capacity of 1,000
barrels or less.
4. Each tank battery consists of four tanks.
5. Each tank battery is associated with four production wells.
Low Scenario
The regulations are assumed to apply to new tanks larger than 1,000 barrels, and would concern only
leak detection equipment and financial responsibility requirements.
($2,000/tank)(4 tanks/battery) (1 battery/4 wells) (0.04)
= $80 per new production well
Source: Entropy Limited, 1989; Jack Toellner, Exxon, personal communication
06K00138.TBL Page A-70
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TABLE A-26 (Continued)
COMPLIANCE COST ESTIMATES FOR POTENTIAL REGULATIONS
AFFECTING ABOVE GROUND STORAGE TANKS
Medium Scenario
The regulations are assumed to apply to all new tanks greater than or equal to 500 barrels, which
must comply with all aspects of regulations. Existing tanks and tanks smaller than 500 barrels would
only have to meet the financial responsibility requirements.
1. Existing Tanks
($1,000/tank) (4 tanks/battery) (1 battery/4 producers)
= $1,000/existing producer
2. New Tanks
[($1,000/tank)(0.89) + ($5,000/tank)(0.11)](4 tanks/battery)(1 battery/4 producers)
= $1,440/new producer
High Scenario
All aspects of the regulations are assumed to apply to all tanks (new and existing)
($5,000/tank)(4 tanks/battery) (1 battery/4 producers)
= $5,000/producer
06K00138.TBL Page A-71
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The ban on produced water discharges has not been considered elsewhere, however. According
to API (Wakim, 1987), approximately 9% of produced waters in the U.S. were not reinjected in 1985. This
fraction was considerably higher in some regions. For example, 22% of produced water was not
reinjected in California, and 44% of these brines was not reinjected in Louisiana. A breakdown of
produced water discharges by state is presented in Table A-27. Also shown in Table A-27 is the ratio
of new injectors (required if surface discharges are banned) to existing injectors in 1985.
The incremental compliance costs associated with a ban on the discharge of produced water to
the surface would correspond to additional Class II injectors and associated facilities that would be
required to dispose of the additional volume of brines requiring subsurface disposal. The volume of
brines requiring disposal would correspond to the brine volume currently discharged to the surface. In
this analysis, wells producing brines that are disposed at the surface and those reinjecting were assumed
to produce, on average, the same volume of water per barrel of oil.
The incremental costs assumed for this regulatory initiative are summarized in Table A-28.
c. Description of Scenarios. Under the low scenario, it is assumed that current discharges
to the surface are allowed to continue; as a result, no incremental costs are incurred. Under the medium
scenario, surface discharges associated with existing production are allowed to continue, but surface
discharges associated with new production are banned. Under the high scenario, surface discharges
associated with both existing and new production are banned. These scenarios are summarized in Table
A-28.
d. Total Compliance Costs. Based on the amount of surface disposal occurring in 1985, and
the number of new injection wells that would be required to inject this volume, estimated compliance costs
associated with this initiative could be as high as $1.9 billion, with estimated annual costs of $0.3 billion
per year thereafter. This assumes that 50% of the new injectors would be converted producers, and the
rest would be drilled.
D. Regulatory Initiatives Not Analyzed
The possible regulatory initiatives that could be implemented under the authority of the Clean
Water Act which were not considered in this analysis include the costs associated with the implementation
of a generic mud system for use in the offshore, the costs associated with the potential use of dispersion
models to evaluate potential risks, the costs associated with specific toxicity testing requirements, and
06K00136.RPT Page A-72
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TABLE A-27
BREAKDOWN OF PRODUCED WATER VOLUMES DISCHARGED IN 1985
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Florida
Illinois
Indiana
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Missouri
Montana
Nebraska
Nevada
New Mexico
New York
North Dakota
Ohio
Oklahoma
Pennsylvania
South Dakota
Tennessee
Texas
Utah
West Virginia
Wyoming
TOTAL U.S.
Number
of
Injectors
215
511
5
1,235
19,481
983
77
14,548
3,307
14,861
5,417
4,159
1,657
981
402
1,330
717
12
4,451
3,254
529
3,956
24,916
6,183
41
10
52,740
654
572
4,979
172,183
Total
Produced
Water Volume
(1000 Bbbl)
34,039
112,780
288
226,784
2,936,335
281 ,262
85,052
8,560
5,846
1,916,250
16,055
1 ,270,670
64,046
361,038
2,177
159,343
73,41 1
3,693
368,249
4,918
88,529
13,688
3,843,220
31,131
3,127
800
2,576,418
126,000
7,327
1 ,677,421
16,298,490
Fraction of
Produced Water
Not Injected
22%
44%
1%
80%
5%
1%
7%
9%
Average
Injection
Rate/Well
(Bbl/Day)
434
605
158
503
322
784
3,026
2
5
353
8
469
106
1,008
15
325
281
843
227
4
458
9
423
14
42
219
127
523
35
858
236
Number of
New Injectors
Required
._
5,495
3,268
13
164
2,776
7
375
12,097
Ratio of
New Injectors
Over Existing
Injectors
0.28
0.79
0.01
_ —
4.00
0.05
0.01
0.08
0.07
Source: Wakim 1987; Gruy 1988
06K00138.TBL
Page A-73
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TABLE A-2S
ESTIMATED COMPLIANCE COSTS ASSOCIATED WITH THE
BAN ON THE SURFACE DISCHARGE OF PRODUCED WATERS
Assumptions:
1. Cost to drill, equip, convert, and operate injection wells and facilities determined by
existing model algorithms.
2. Assume that 50% of the required new injection wells are drilled, and 50% are
converted.
3. If no restrictions were implemented, it is assumed that the current fraction of facilities
discharging to surface waters would remain constant.
Low Scenario
Assumes that surface water discharges are allowed to continue, therefore, no incremental costs are
incurred.
Medium Scenario
Assumes that discharges associated with existing production are allowed to continue; discharges from
new production are banned.
Initial incremental cost per injector = (FSD)[(0.50)(DC) + (0.50) (CC)]
where FSD = ratio of new required injectors to total existing injectors (see Table IV-10)
DC = cost to drill an injection well, in dollars
CC = cost to convert a producer to an injector, in dollars.
Incremental annual operating costs per new injector: (FSD)(30,000)
High Scenario
Assumes that discharges associated with both existing and new production are banned; costs are the
same as those in the Medium Scenario, apply to all (new and existing) injection wells.
Source: ERT, 1988
06K00138.TBL Page A-74
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restrictions on operations in sensitive environments, such as wetlands or areas which may pose a threat
to endangered species.
V. CLEAN AIR ACT
A. Background
On July 20, 1989, President Bush presented the Administration's proposed Clean Air Act
Amendments of 1989. The proposed bill was subsequently introduced by Congressmen Dingell in the
House, as H.R.3030, and by Senator Chafee in the Senate, as S.1490. Three similar bills were introduced
in Congress prior to the release of the President's Clean Air legislative proposal. Senator Durenberger
introduced a bill pertaining to hazardous air pollutants (S.816), while in the House, Congressman Dingell
introduced a bill containing air toxic emission provisions (H.R.4). In addition, Congressman Waxman also
introduced a comprehensive bill concerning air toxics in 1989 as H.R.2585.
In early 1990, representatives of the Administration and members of the Senate from both parties
reached a compromise agreement concerning amendments to the Clean Air Act. This agreement was
comprehensive in both the breadth and specificity of its provisions.
Although concerned with all major air pollutants, the primary concern of this agreement for the
domestic E&P industry pertains to hazardous air pollutants. The agreement does not specify the level
of control emitters of hazardous air pollutants must achieve; the proposed standard is 'maximum
achievable control technology1, considering cost and feasibility. Each bill contains a list of toxic air
pollutants, proposes a schedule for controlling specific categories of pollutants, and contains a provision
for assessing residual risk to determine if implemented controls achieve an "acceptable" level of risk.
B. Summary of Proposed Initiatives
The regulatory initiatives affecting domestic E&P operations concern the emission of NOX, volatile
organic compounds (VOCs), SOX, particulates and other constituents from both onshore and offshore
operations. Nearly all domestic E&P operations could potentially be affected by proposed revisions to
the Clean Air Act currently being considered by Congress. Other initiatives associated with amending the
Clean Air Act that could potentially be considered include regulations concerning the catastrophic release
of acutely toxic substances and the costs of proposals that would place restrictions on the composition
and use of motor vehicle fuels.
06K00136.RPT Page A-75
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C. Regulatory Initiatives Considered
In this analysis, only regulatory initiatives directly affecting E&P operations and the continuous,
relatively low-level releases of toxic air pollutants from these operations were considered. Although the
proposed legislation also concerns acid rain and ozone precursors, for purposes of this analysis, only
controls on toxic air pollutants were considered. The initiatives considered in this analysis are discussed
in detail below.
1. Air Toxics Emissions from Onshore E&P Facilities
a. General Description. The primary uncertainty in estimating potential costs of compliance
of regulations on the emissions of air toxics from onshore E&P operations is the eventual interpretation
of 'maximum achievable control technology1 (MACT) as described in the various proposals. In order to
develop a preliminary estimate of the potential costs to the petroleum industry in implementing emissions
controls under consideration, API developed two regulatory scenarios to roughly bracket the likely
stringency of eventual standards:
• Case I estimates assume MACT is interpreted to require nationwide
controls approximately equivalent to the controls required now in
California ozone non-attainment areas.3/
• Case II estimates the additional costs (beyond Case I) if MACT is
interpreted to require technologies which are currently experimental or
not otherwise in significant commercial use.
The large range in the estimates presented below reflects the uncertainty in the definition of
MACT. The ultimate cost to the petroleum industry of air toxics legislation is thus dependent in large
measure on the definition of MACT as interpreted by EPA in regulatory proceedings or as more explicitly
defined by Congress.
b. Estimate of Potential Compliance Costs. The API analysis departs in concept from
previous attempts to analyze petroleum industry costs of air regulations. Many of these previous analyses
were based on estimating emissions from various industry facilities (usually relatively large point sources)
and assuming a cost per ton for reducing these emissions.
3/The air toxics cost estimates would not take into account future developments in ozone regulation. That is,
some of the costs would also result (in the absence of air toxics legislation) from additional ozone controls in non-
attainment areas. A comprehensive analysis of the costs of Clean Air Act Amendments would require some care to
avoid double-counting costs that could be allocated to either ozone or air toxics controls.
C6K00136.RPT Page A-76
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The definitions of major and area sources contemplated in current legislative proposals make it
likely that many more small emissions sources will be covered by emissions standards. Because of the
number and relatively small individual contribution of these sources to total emissions, their control could
be considerably more expensive on a per-ton basis. For this reason, API chose to attempt a bottom-up
analysis of costs corresponding to amendments to the Clean Air Act.
API developed their compliance cost estimates by determining the number of potential sources
of pollution to be controlled and the unit costs for controlling emissions at these sources. API estimated
costs of compliance for the two scenarios for the production, transportation, refining, and marketing
sectors of the petroleum industry.
Estimates of unit compliance costs developed by API for Case I in the production sector and used
in this analysis are summarized in Table A-29. Similar unit compliance costs for Case II are summarized
in Table A-30.
c. Description of Scenarios. For purposes of this analysis, both the low and medium
regulatory scenarios assumed regulations similar to those described in API's Case I. The high regulatory
scenario assumed API's Case II.
d. Total Compliance Costs. Total industry costs for the Case I and Case II scenarios are
estimated by API to be $15 and $53 billion, respectively (Jones, Martin, and Hoffman, 1989). For the
production sector, initial compliance costs are estimated to range from $7.4 billion under Case I to $25.0
billion for Case II, with annual compliance costs on the order of $250 million per year.
2. Air Emissions from Offshore E&P Facilities
a. General Description. Prior to the introduction of the various legislative proposals
concerning hazardous air pollutants, the Minerals Management Service (MMS) issued a proposed rule
to impose stricter emission control standards for oil and gas operations off the coast of California. The
major aspect of this rule would require offshore operations to install additional and best available pollution
control equipment for all phases of California Outer Continental Shelf (OCS) development. The rule would
also require emission offsets at lower levels of pollution, control of the number of simultaneous exploration
activities by different operators, regulate and limit the use of crew and supply boats, and require
companies to examine the use of onshore sources of electricity for offshore platforms and rigs.
06K00136.RPT Page A-77
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TABLE A-29
ESTIMATED COST OF AIR EMISSION CONTROL REGULATIONS
ON DOMESTIC ONSHORE OIL PRODUCTION FACILITIES
(Excluding California)
API Case I Scenario
Applied
to the low and medium regulatory scenarios.
Item
Capital Cost
Casing Vent Recovery
Covers on New Water Tanks
Air-Fuel Ratio Controller for
Unit Cost per
Item
($)
1,000
7,500
10,000
Cost per
Production
($)
700
3,750
500
Well
(1)
(2)
(3)
1.
2.
3.
4.
5.
6.
Oil-Fired Vessels at Production
Facilities
Internal Floating Cover for 7,500
Storage Tanks
Air-Fuel Ratio Controller for 10,000
all l-Cs
Total
Annual Operating Costs
Quarterly Inspection and Maintenance 1,600
6,750
500
$12,200
(4)
(5)
Cost per Production
Well per Year
($/year)
$ 400 (6)
Based on 70% of all oil wells using artificial lift and venting casing gas.
Assuming 2 production wells per water storage tank.
Assuming 20% of oil production facilities have oil-fired vessels, with 4 wells per production
facility.
Assuming 10% of oil storage tanks already have vapor recovery units, at one storage tanks
per well.
Assuming 5% of all oil wells with artificial lift have internal combustion engines.
Assuming 4 inspections per year, 4 production wells per production facility.
Source: Jones, Martin, and Hoffman, 1989.
06K00138.TBL
Page A-78
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TABLE A-30
ESTIMATED COST OF AIR EMISSION CONTROL REGULATIONS
ON DOMESTIC ONSHORE OIL PRODUCTION FACILITIES
(Excluding California)
API Case II Scenario
Applies to the high regulatory scenario.
Item
Capital Cost
Casing Vent Recovery
Covers on New Water Tanks
Air Fuel Ratio Controller
for Fired Vessels at
Production Facilities
Air Fuel Ratio Controller
for all l-Cs
Vapor Recovery for Storage
Storage Tanks
3-Way Catalyst for l-Cs
Valve Replacement and
Flange Welding
Unit Cost per
Item
($)
1,000
7,500
10,000
10,000
50,000
30,000
1 ,000/valve
500/flange
Cost per
Production
($)
700
3,750
500
500
18,500
1,500
5,000
10,000
Well
(D
(2)
(3)
(4)
(5)
(6)
(7)
(20 valves and 80 flanges
per facility)
Total
Annual Operating Costs
Quarterly Inspection and Maintenance 1,600
$40,450
Cost per Production
Well per Year
($/year)
$ 400 (8)
Source: Jones, Martin, and Hoffman, 1989.
06K00138.TBL
Page A-79
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TABLE A-30 (Continued)
ESTIMATED COST OF AIR EMISSION CONTROL REGULATIONS
ON DOMESTIC ONSHORE OIL PRODUCTION FACILITIES
(Excluding California)
API Case II Scenario
1. Based on 70% of all wells using artificial lift and venting casing gas.
2. Assuming 2 production wells per water storage tank
3. Assuming 20% of oil production facilities have oil-fired vessels, with 4 wells per production
facility.
4. Assuming 5% of all oil wells with artificial lift have internal combustion engines.
5. Assuming 2.7 tanks per vapor recovery unit (adjacent tanks may share unit); one storage tank
per well.
6. Assuming 5% of all wells have internal combustion engines.
7. Assuming 20 valves and 80 flanges per oil production facility; 4 production wells per facility.
8. Assuming 4 inspections per year, 4 production wells per production facility
06K00138.TBL Page A-80
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Although issued prior to the President's proposed Clean Air Act Amendments or the introduction
of the various legislative proposals concerning air toxics, the proposed MMS guidelines established
controls at a level that could be considered consistent with the MACT Case I standard for operations off
the coast of California. The strict nature of the proposed guidelines is in response to California's unique
non-attainment situation for air pollutants, resulting in standards more strict than those in the rest of the
OCS, and a regulatory standard similar to Case I assumed for onshore E&P operations.
Industry's primary concern pertaining to the proposed guidelines, as articulated by API, is the
possible precedent-setting nature of this rule for other OCS regions. Potential amendments to the Clean
Air Act have emphasized those concerns. Thus, controls at levels for the rest of the OCS similar to those
implemented in California are not considered inconceivable.
The proposed MMS rule for California requires that BAT must be installed on all new OCS
platforms, regardless of size of the source, amount of emissions, or distance from shore. Moreover, MMS
proposed to extend onshore non-attainment areas out to the OCS, expanding the onshore area by a 25-
mile radius beyond the boundary of the traditional non-attainment area, thereby classifying much of the
California OCS as a non-attainment area.
The proposed rule also established that, above certain thresholds in non-attainment areas, OCS
air emissions must be mitigated. OCS operations in non-attainment areas (by the revised definition) with
emissions of volatile organic compounds (VOCs) or NOX greater than 46 tons per year must mitigate all
emissions (from zero tons per year) at an offset ratio of 1.2:1. In attainment areas, emissions greater than
100 tons per year must be mitigated at a 1:1 offset ratio. These requirements would apply to both
stationary and temporary sources of emissions.
A number of additional requirements are also established under the proposed rule. These include
more rigorous requirements for existing facilities imposing a "significant" impact on onshore air quality;
requirements for modifications made to new or existing OCS facilities resulting in a net increase of any
amount of any pollutant (NOX, SOX, VOC, etc.); and a requirement that an electrification analysis be
performed for each new facility, regardless of attainment status, to determine the pollution potential of
various alternatives.
b. Estimate of Potential Compliance Costs. The compliance cost estimates used in this
analysis were based on those developed by MMS. The costs and assumptions used in the economic
impact analysis for proposed OCS air quality regulations are presented in Appendix C, and are
summarized in Table A-31. The proposed rule includes costs associated with improvements in equipment
06K00136.RPT Page A-81
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TABLE A-31
ESTIMATED COMPLIANCE COSTS FOR PROPOSED
EMISSION CONTROL STANDARDS FOR THE
OUTER CONTINENTAL SHELF
Low Scenario
Assumes regulations are applicable to California only, and includes no costs for mitigation.
Exploration Phase: $49,400 per exploratory well
Platform Construction Phase:
Capital Costs $84,000 per platform
$1,392,000 per platform per year (during construction)
Development Drilling Phase
Capital Costs $5,000 per development well
$198,000 per platform (California and existing platforms)
$4,000 per well per year (during development)
$100,000 per platform per year (during development)
Production Phase:
Operating Costs $100,000 per platform per year (California and existing
platforms
$85,000 per platform per year (new platforms in rest of
OCS)
Medium Scenario
Assumes regulations are applicable to California only, and includes the cost of mitigation.
Exploration Phase: $597,400 per exploratory well
Platform Construction Phase:
Capital Costs $84,000 per platform
$2,960,000 per platform per year (during construction)
Source: See Appendix C
06K00138.TBL Page A-82
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TABLE A-31 (Continued)
ESTIMATED COMPLIANCE COSTS FOR PROPOSED
EMISSION CONTROL STANDARDS FOR THE
OUTER CONTINENTAL SHELF
Development Drilling Phase:
Capital Costs $5,000 per development well
$198,000 per platform
$198,000 per platform
$4,000 per well per year (during development)
$800,000 per platform per year (during development)
Production Phase:
Operating Costs $520,000 per platform per year
High Scenario
Assumes regulations apply to the entire U.S. offshore; mitigation costs are included in California and
are not included in the other regions.
Assumes Medium Scenario costs for California.
Assumes the following costs in the non-California DCS:
Exploration Phase: $49,400 per exploratory well
Platform Construction Phase:
Capital Costs $84,000 per platform
$1,392,000 per platform per year
Development Drilling Phase:
Capital Costs $5,000 per development well
^^ nQ f^f\r\ w^r^r i^lf^tf^sr-nrt /r\\fif*+ir~ts^
«po,uuu pel ueveiujji i iei n wen
$198,000 per platform (existing)
$99,000 per platform (new)
$4,000 per well per year (during development)
$100,000 per platform per year (existing; during
development)
development)
$85,000 per platform per year (new; during
development)
Production Phase:
$100,000 per platform per year (existing)
$85,000 per platform per year (new)
06K00138.TBL Page A-83
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and operating requirements and mitigation costs, which are costs assessed based on the amount of
emittants released from offshore operations.
Many of the emission controls considered for onshore facility compliance with potential
requirements under a reauthorized Clean Air Act would also apply to offshore facilities. However, many
of the controls considered under the scenarios developed by MMS would reduce levels of air toxics
emissions offshore. Consequently, to avoid potential double-counting, the onshore air emissions
compliance costs as described above were not included in the offshore cost estimates.
The economic analysis models used for this study can only assess the impact of increased
compliance costs on the development of offshore crude oil fields that remain to be discovered. No
assessment of the impact of the increased costs of air emissions controls on crude oil supplies from
discovered offshore fields were performed.
c. Description of Scenarios. In this analysis, under the low scenario, the proposed
regulations were assumed to apply only to the California OCS, and included no mitigation costs for
compliance. Under the medium scenario, mitigation costs are included in the compliance costs applicable
to the California OCS, under the assumption that minimum thresholds had been exceeded. In the high
scenario, incremental compliance costs were assumed to apply to all areas of the OCS, with mitigation
costs required off the coast of California, but not in the rest of OCS. These scenarios are summarized
in Table A-31.
d. Total Compliance Costs. MMS estimated that the total annual costs of compliance for the
proposed rule for California, including the costs of mitigation and based on projected (by MMS) OCS
development of the coast of California, to be on the order of $42 million per year. No estimate was made
by MMS of projected development in the remaining OCS regions. However, based on current facilities
operating in the Gulf of Mexico, and future development consistent with the level of activity in 1985, initial
compliance costs were estimated to be as high as $850 million, with annual compliance costs thereafter
as high as $800 million per year, given the high scenario described above.
D. Regulatory Initiatives Not Analyzed
The analyses performed by API to determine the costs of possible Clean Air Act Amendments
concerning air toxics were somewhat limited in scope. Consequently, several categories of potential
compliance costs for air emission regulations were not considered. One category of costs not considered
included those associated with potential catastrophic releases of acutely toxic substances such as
06K00136.RPT Page A-84
-------
ammonia, chlorine, and hydrogen sulfide, which are not subject to the control technologies primarily
concerned with low levels of continuous emissions. Another category of costs not considered was that
pertaining to proposals to modify the constituents of gasoline.
In addition, another potential cost not considered was that associated with dismantling Case I
controls if Case II controls are determined to be more effective, and the costs of proposals to reduce VOC
emissions that would not be reduced from the implementation of the air toxics emission controls
considered in the study.
Finally, this assessment only considered air toxics control costs affecting the production sector.
Although API also considered the cost impacts on the marketing, transportation, and refining sectors of
the petroleum industry, those costs were not included in this assessment. Also, no consideration was
given to potential emission controls associated with concerns about acid rain, ozone non-attainment, or
global climate change.
VI. SUPERFUND AMENDMENTS AND REAUTHORIZATION ACT
A. Background
Title III of the Superfund Amendments and Reauthorization Act (SARA Title III), or the Emergency
Planning and Community Right-to-Know Act, was enacted in 1986 to improve public awareness of
chemical hazards and enhance communities' emergency planning and response capabilities. The
requirements under SARA Title III do not involve explicit modifications to existing E&P operating practices,
but entail additional notification obligations and recordkeeping requirements which will be cumbersome
to implement, resulting in additional administrative costs that the oil and gas production industry must
bear (see Dougherty, 1988).
The Act contains two major sets of provisions which will impact E&P operations: 1) emergency
planning and response provisions, and 2) community right-to-know provisions. Each set of provisions is
discussed separately below.
1. Emergency Planning and Response Provisions
Sections 302, 303, and 304 of the Act require operators to notify agencies created by SARA Title
III if certain hazardous substances are present at the facility, or if certain substances are released to the
environment. Facilities where any of 366 extremely hazardous substances (EHSs) is present in a
06K00136.RPT Page A-85
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threshold planning quantity (TPQ) must report to a State Emergency Response Commission (SERC) and
Local Emergency Planning Committee (LEPC) within 60 days of having a TPQ onsite. In oil and gas
operations, hydrogen sulfide is the most likely EHS to be present in sufficient quantity (500 pounds); other
EHSs may include biocides, chlorine used to treat water, and hydrogen fluoride used in acid jobs.
Operators must report EHSs used by contractors, though they may be onsite only temporarily. After
notification, operators must provide any information on their operations required by the LEPC to develop
emergency response plans.
SARA Title 111 requires emergency notification of chemical releases with broader applications than
previously mandated by the Clean Water Act and CERCLA. Under SARA Title III, release notice is
required on previously unregulated substances. More significantly, releases previously reported to the
National Response Center also must be reported to the SERC and LEPC orally and in writing. Finally,
proposed regulations to interpret reporting exemptions in CERCLA could expand the number of reportable
releases significantly.
2. Community Rlqht-To-Know Provisions
Probably the greatest effect on E&P operations will result from Sections 311 and 312, concerning
inventory reporting. Section 311 requires the operator to submit Material Safety Data Sheets (MSDSs),
or a list of applicable chemicals, to local fire departments, LEPCs, and SERCs. The range of chemicals
covered is much broader than that required for emergency planning and response, and includes OSHA
hazardous chemicals (over 70,000) present in quantities greater than 10,000 pounds and EHSs present
in quantities greater than 500 pounds or the TPQ (whichever is lower). Section 312 requires annual
inventory reporting of these chemicals, including more detailed information to identify the chemical, the
quantity onsite, and the general location at the facility.
Nearly all E&P operators are affected by the 10,000 pound threshold, because the capacity of a
single tank battery exceeds the threshold for crude oil, which is a OSHA hazardous chemical. In addition,
most drilling, completion, production, and workover chemicals are OSHA hazardous chemicals. As with
the emergency planning and response requirements, reporting is required for all subject chemicals used
or stored at the site, including those onsite only temporarily and those used by contractors.
EPA allows two options for inventory reporting, the Tier I form requiring reports on hazardous
chemicals in aggregate by hazard type (fire hazard, sudden release of pressure hazard, acute health
hazard, reactivity hazard, and chronic health hazard), and the Tier II form requiring reports for individual
chemicals. Generally, the Tier II reports require that operators submit the maximum and average daily
06KQ0136. RPT Page A-86
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amounts within established ranges, number of days onsite, and the general location of chemicals of
concern. Both forms require basic identification of the facility and two emergency contacts. The Tier II
form also requires identification of the chemicals by chemical name, Chemical Abstracts Service (CAS)
number, description (solid, liquid, gas, mixture, pure), hazard type, and method of storage. Any state or
local agency can request Tier II information for chemicals present in any amount, :nd the operator must
respond to that request within 30 days. Most producing states require the Tier II report.
Because of the relatively low level of hazard generally posed by E&P operations and the significant
potential impact on the industry, EPA accepted a proposal by API, the Independent Petroleum Association
of America (IPAA) and various state agencies for alternative compliance procedures. This alternative is
the Generic Hazardous Chemical Category List and Inventory (generic reports) which represents a set of
two comprehensive reporting forms corresponding to Section 311 and 312, respectively. The purpose
of the generic reports is to comprehensively represent the types of chemicals used in E&P operations
both on a short-term and a continuing basis. The generic reports include information on 57 categories
of hazardous chemicals which can be present in E&P operations, rather than chemical or trade-name
information. This information actually may be more useful to emergency planning authorities than the
information specified in the regulations. The EPA also allows E&P operators to aggregate facilities,
submitting one report for multiple, similar facilities. Generic and aggregate reporting provides more
comprehensive information than a site-specific inventory would, and it greatly simplifies ongoing
maintenance of the list and inventory.
To date, no assessment of the costs likely to be incurred explicitly by the E&P industry from SARA
Title III has been conducted by industry or EPA. One study conducted by ICF (1988) looked at the cost
impacts of SARA Section 311 and 312 on the non-manufacturing industry, but the number of reportable
chemicals (those requiring MSDSs) considered to be representative of a "non-manufacturing facility' (the
study assumed 17 MSDSs per facility) is significantly smaller than that which would be reportable for a
typical E&P facility. In addition, that study reviewed only potential impacts from certain variations in the
federal requirements. Industry estimates that some of the most significant potential costs could arise from
state implementation of Sections 311 and 312. State-by-state program variations can erode the benefits
of generic and aggregate reporting, which industry estimates to have allowed a first-year cost savings of
$15 million. State and local filing fees, which have been authorized in only a fraction of the producing
states to date, vary widely (e.g., $10-250 per facility), and their impact can depend on a broad range of
options for the fee basis (number of pages, reports, chemicals, producing fields, or pieces of equipment),
as well as exemptions (e.g., first 35 wells) or fee caps (countywide, statewide). Consequently, no cost
or energy impact assessment associated with SARA Title III was included in this analysis.
06K00136.RPT Page A-87
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APPENDIX B
Analytical Approach
06K00136.RPT
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APPENDIX B
ANALYTICAL APPROACH
I. INTRODUCTION
The approach used in this analysis examined the cumulative economic and energy impacts of
potential environmental regulations on U.S. crude oil supplies. Four categories of U.S. crude oil supplies
were evaluated. The economic and energy impacts associated with the imposition of increased regulatory
costs were assessed for each of the four categories of resource, as follows:
• oil recoverable from the continued production from current producing fields
• oil recoverable from future infill drilling and waterflood projects in known fields in the
Lower-48 onshore
• oil recoverable from future enhanced oil recovery projects in known fields in the Lower-48
onshore
• oil recoverable from onshore and offshore fields remaining to be discovered in the Lower-
48 and Alaska
The analysis of the recovery potential of the known oil resource was based on recovery
performance and economic modeling using resource data of critical properties for major U.S. crude oil
reservoirs. The analysis used DOE's Tertiary Oil Recovery Information System (TORIS), developed and
maintained at DOE's Bartlesville Project Office. TORIS was originally developed by the National Petroleum
Council (NPC) in their 1984 assessment of enhanced oil recovery (NPC, 1984). DOE has expanded the
capabilities of TORIS to include analysis of the unrecovered mobile oil (UMO) resource; i.e., oil that may
be recovered by intensive infill drilling and waterflooding; and the analysis of the continued conventional
production from producing crude oil reservoirs.
TORIS utilizes comprehensive oil reservoir data bases and detailed engineering and economic
evaluation methodologies, considering data for individual reservoirs to predict crude oil recovery,
investment and operating costs, and ultimately, project economics. The system evaluates recovery and
costs associated with the development of specific crude oil reservoirs, based on the geographic location,
depth, reservoir properties, and operating conditions of the reservoir. Analyses can be conducted for
various recovery technologies and crude oil prices.
06K00136.RPT Page 8-1
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The analysis of the recovery potential of the U.S. crude oil resource remaining to be recovered
— the undiscovered resource — used models also developed by DOE as part of its Replacement Costs
of Crude Oil (REPCO) Supply Analysis System. This system was designed to determine the "replacement
cost" of developing U.S. undiscovered crude oil resources. The replacement cost is defined as the
minimum levelized oil price that a project must receive to recover all costs and achieve a reasonable
return on capital. This "fully risked" cost assumes one theoretical operator finds and develops a crude
oil field and includes the allocated cost for all exploratory wells and associated exploratory and
developmental dry holes.
The REPCO system characterizes the undiscovered resource uniquely for various distinct crude
oil supply regions, disaggregating the resource into characteristic fields. Appropriate recovery
technologies are selecte'd for the characteristic fields in each region, and the recovery potential and
economic viability of each characteristic field is determined based on the regional and reservoir
characteristics describing it. Explicit field-level evaluations are performed. Similar to the models used for
examining the known crude oil resource, analyses can be performed considering a variety of recovery
technologies and crude oil prices.
For purposes of this study, both the TORIS and REPCO systems were enhanced to incorporate
the addition of incremental costs associated with potential environmental regulations, and to provide
output in a form so that it allows the results for the different resource categories considered to be
evaluated on a consistent basis. Analyses were performed for each regulatory scenario, with the specific,
incremental environmental compliance costs associated with the scenario considered. The results for
each regulatory scenario were then compared to those obtained under the reference case, in order to
estimate the energy and economic impacts associated with each scenario.
For some categories of resource, analyses were performed assuming two levels of technology,
implemented and advanced. The implemented technology case assumed recovery practices currently
available for implementation in the field. The advanced technology case assumed improvements in
extraction technologies and reductions in extraction costs will result from successful research and
development within a reasonable period of time, and will be widely accepted and applied in the field. The
advanced technology case was included in this analysis so that energy and economic impacts from
environmental initiatives could be contrasted with potential improvements in recovery technologies.
The analytical approach used for assessing the impacts of each resource category are discussed
in more detail in the sections below.
06K00136.RPT
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II. CURRENT PRODUCTION
A. Nature of Resource
After currently proved reserves are produced by conventional (primary and secondary) recovery
methods, nearly two-thirds of the known U.S. oil resource (over 300 billion barrels) will remain unrecovered
(Figure 111-1). Nearly 100 billion barrels are displaceable by water but are left in the reservoir at the end
of conventional recovery operations. Another 242 billion barrels are not displaceable by water; the
recovery of this resource depends on the application of tertiary recovery processes. Although not all of
this remaining resource in place could "ever be recovered, it represents a substantial target for future
advanced recovery operations.
However, for the most part, the future recovery of this resource presupposes that existing wells,
producing reservoirs, and infrastructure will be available, and assumes that operators are able to maintain
access to these reservoirs within the constraints of their lease agreements. Once these reservoirs are
abandoned, the resource associated with these reservoirs becomes essentially inaccessible to future
development within the range of prices generally considered likely over the next 15 to 20 years, even with
further improvements in recovery technologies. DOE, in a recent study entitled Abandonment Rates of
the Known Domestic Oil Resource (DOE, 1989), concluded that the U.S. will inevitably continue to face
increasing reserve abandonments, with future crude oil prices determining the level and pace of these
abandonments.
As well abandonments erode access to the remaining resource, fewer future recovery projects,
particularly those utilizing advanced recovery technologies, will be economically justifiable. These projects
will not recover sufficient oil to justify both the high start up costs associated with advanced recovery
technologies and the costs of redrilling new wells or re-entering old wells in abandoned reservoirs.
As the costs of compliance with environmental regulations increase, the costs of operating
marginally economic wells in producing reservoirs will increase, resulting in the accelerated abandonment
of these wells. The impact of the increased compliance costs are consequently two-fold. First, reserves
are lost because of the earlier abandonment of these wells. Second, access to the remaining resource
associated with these abandoned wells will be lost, and hence the potential future production from
advanced recovery technologies in reservoirs containing these wells will be economically prohibitive.
06K00136.RPT Page B-3
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B. Analytical Approach
Previous analyses have estimated the portion of the known remaining oil resource associated with
abandoned wells and have projected future abandonments as a function of oil price (DOE, 1989). These
analyses served as the basis of this assessment of the impact of increased costs of environmental
regulations on the continued production from currently producing U.S. oil reservoirs. Nine major oil
producing states were analyzed: California, Colorado, Illinois, Kansas, Louisiana, New Mexico, Oklahoma,
Texas, and Wyoming. These states were chosen for the magnitude and comprehensiveness of resource
data, production data, and well counts, because the states represent various stages of resource maturity,
and as shown in Table B-1, the resource in these states represents 83% of the original-oil-in-place and
75% of the remaining crude oil resource in place in the Lower-48 states.
The data contained in the TORIS data base for the reservoirs in the nine states allowed for
production decline curve analyses of each reservoir. Exponential decline functions were developed for
each reservoir based on historical production data for each reservoir, beginning in the year of highest
reported production. The historical exponential decline curves that demonstrated the best fit with the
actual data were selected and used to project future production.
In the reference case, the analysis assumed that future production in each reservoir continues at
declining rates until the economic limit of production is reached. The economic limit of production is
defined as the minimum production at which revenues from production meet or exceed production costs
at a given oil price. This projection assumed that historical activities to maintain and/or increase
production in each reservoir, as implied by the historical decline curve, are continued in the future.
The economic limit determined in the base case established the productive life of the reservoir
under current operating conditions and the assumed oil price. Baseline costs were established as those
currently in the TORIS system, which were based on regional average costs reported by API (API, 1989)
and the Energy Information Administration (EIA, 1987), for the depth and geographic location of each
reservoir, adjusted to 1988 conditions. These baseline costs include costs for well workovers, general
operation and maintenance of wells and production equipment, adjusted to correspond to the oil price
considered.
Oil prices, incremental investment costs, and production costs are the major independent
variables considered by TORIS in this analysis. As oil prices increase, the economic limit is lowered and
the productive life of a reservoir extended. Similarly, as production costs are increased (e.g., due to
increased costs of compliance with environmental regulations), the economic limit is raised and the
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TABLE B-1
ORIGINAL AND REMAINING OIL RESOURCES IN NINE STATES
ANALYZED FOR RESOURCE ABANDONMENT POTENTIAL
(Billion Barrels)
Original
State Oil-in-Place
California
Colorado
Illinois
Kansas
Louisiana
New Mexico
Oklahoma
Texas
Wyoming
Total, 9 States
Other States
Lower-48 States
84.7
4.3
9.1
16.3
41.2
14.9
39.0
154.7
16.7
380.9
79.1
460.0
Cumulative
Production
To date (12/31/87)
20.8
1.4
3.2
5.3
22.7
5.2
12.7
57.4
5.1
133.8
3.2
137.0
Remaining
Reserves
5.8
0.2
0.1
0.4
2.6
0.7
0.9
7.9
19.6
1.7
21.3
Remaining
Oil-in-Place
58.1
2.7
5.8
10.6
15.9
9.0
25.4
89.4
10.6
227.5
74.2
301.7
Source: DOE, 1989
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Page B-5
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productive life a reservoir shortened. Although only oil prices and environmental compliance costs were
considered in this analysis, other factors such as tax incentives and well abandonment regulations could
also influence the productive life of these reservoirs.
The impacts of the incremental costs associated with the regulatory scenarios considered were
estimated by performing a conventional discounted cash flow analysis for each reservoir over its
productive life, assuming that the project must incur the incremental investment and operating costs
associated with the specified regulatory scenario. The analysis was performed from the perspective of
the operator of the reservoir, who would conduct a financial analysis examining the impact of the total
incremental costs of environmental compliance over the life of the reservoir, at the time the regulations
would go into effect. At this point in time, each operator would make a decision whether to continue with
the production, or, if the incremental costs are too high to justify continued economic viability, begin to
shut in production. As a result, a considerable portion of current production could be shut in immediately
after the implementation of the new regulations.
If additional environmental regulations are instituted, operators would have a specified time period
within which they must comply. To account for this compliance period, two additional scenarios were
developed to allow for this compliance period. The first scenario assumed operators would have five
years to comply with the new regulations, and for purposes of performing financial evaluations,
investments required to bring operations into compliance were assumed to be evenly spread over the five-
year period. The second scenario represents the extreme case in that it assumed operators have only
one year to comply with new regulations.
This analysis provided a high side, or leading indicator, of resource abandonment. The analysis
of production was performed reservoir-wide, based on average reservoir properties, production, and well
counts. Once continued operation of the average well in the reservoir becomes uneconomic, the entire
reservoir was assumed to be abandoned. Actually, the abandonment of the average well precedes tho
abandonment of better-than-average wells that would continue to produce even though the TORIS
analyses would predict reservoir abandonment, which would result in a longer life of the reservoir.
However, some below average wells would have already been abandoned before the average well. Given
current economic conditions, it is likely that most of these below average wells have already been
abandoned.
No attempt was made to explicitly account for the reservoir data not considered in TORIS or
included in this analysis. The reported results were based only on those reservoirs actually considered,
and was not extrapolated to represent the entire U.S. crude oil resource base.
06K00136.RPT Page B-6
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The methodology assumes fixed oil prices, and does not account for changes in future prices.
Consequently, rapid increases or decreases in prices would have a different effect on project
abandonments than that indicated in this analysis.
III. UNRECOVERED MOBILE OIL IN KNOWN OIL FIELDS
A. Nature of Resource Considered
Unrecovered mobile oil (UMO) is oil which is mobile to water that is left in the reservoir because
of reservoir heterogeneity or mobility differences that cause injected water to finger through or around the
oil. Reservoir heterogeneity refers to the complex variations of rock properties that exist in the reservoir.
Oil and gas reservoirs consist of a large number of individual compartments, reflecting internal
heterogeneity, which are a result of the depositional processes which formed the reservoir and the
digenesis or tectonic activity which later altered the reservoir rock. At a given well spacing, some
compartments will not be in pressure communication with other parts of the reservoir contacted by
producing wells. At wide well spacings, a significant portion of the reservoir will be uncontacted, leaving
large volumes of oil at near original reservoir conditions. This unrecovered mobile oil provides a
significant resource target for infill drilling and future recovery operations at closer well spacing.
This mobility difference between oil and water results in water injection operations to recover
incremental oil to bypass large volumes of oil, because water preferentially enters more permeable
portions of the reservoir. This further reduces the recovery efficiency of waterflood operations. Advanced
secondary recovery or waterflooding techniques are designed to overcome the inefficiencies caused by
such mobility differences, resulting in improved oil recovery.
Recovery inefficiencies associated with many traditional crude oil recovery operations leave
portions of the reservoir at near original oil saturation. Producing more oil requires additional wells drilled
at closer spacing, in order to improve contact with this uncontacted and/or unswept oil and improve
waterflood sweep and pattern conformance. Additional improvements in recovery can be achieved with
the application of polymers to improve mobility control or gel treatments to reduce permeability differences
between reservoir layers. In many reservoirs, the greatest recovery efficiency is obtained with the
combined application of infill drilling and such improved secondary recovery techniques.
In this analysis, three recovery processes for improving the recovery of mobile oil were
considered: infill drilling, permeability modification treatments (which directs the flow of injected water to
lower-permeability, less-swept reservoir zones), and polymer-augmented waterflooding (where polymers
06K00136.RPT Page B-7
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are added to injected water to obtain a more favorable water-oil mobility ratio and improve recovery
efficiency). The analysis was undertaken assuming two levels of geologic understanding and using two
classes of polymers. The first level, corresponding to technology that can currently be implemented in
the field, reflects limited geologic understanding of reservoir heterogeneity and the technical shortcomings
of currently available polymers. The second level, corresponding to an advanced technology case,
assumes a significantly improved understanding of reservoir heterogeneity and improvements in advanced
waterflooding techniques that increase the applicability and productivity of these processes. The
processes include the development of improved polymers available for field application in higher
temperature and higher salinity settings (ICF Resources and BEG, 1989).
B. Analytical Approach
The analysis of the economic impact of environmental regulations on the UMO resource was
based on analyses of nearly 700 crude oil reservoirs in Texas, Oklahoma, and New Mexico. The
reservoirs are estimated to contain almost 112 billion barrels of original-oil-in-place, representing about
one-fifth of the total U.S. resource in place. The UMO potential was analyzed in the three states using
the expanded and upgraded TORIS system.
Potential incremental recovery from infill drilling was estimated from the increased sweep efficiency
of similar reservoirs already operating at closer well spacings. Detailed investigations of ongoing
waterfloods in Texas and New Mexico demonstrated that waterflood sweep efficiency could be directly
related to well spacing. Specific relationships were developed for specific classes of reservoirs. From
these findings, continuity curves relating reservoir sweep to well spacing were derived for various
geologically classified reservoir types. These curves were used to calculate the increase in reservoir
contact that would result from a given decrease in spacing.
The continuity curves were used to estimate the additional reservoir contact achieved by a defined
reduction in pattern spacing. This reservoir contact was defined as the effective incremental volume (or
net pay) of reservoir contacted at the decreased pattern spacing. This additional reservoir contact was
input into recovery predictive models to determine the incremental waterflood recovery possible at the
reduced pattern spacing.
Two technology cases were assumed in the evaluation of UMO recovery potential. The
implemented technology scenario assumed a blanket or uniform approach to infill development, where
a single one-half reduction in reservoir-wide well spacing, or one drilldown, was assumed. This scenario
was based on the assumption that the operator would be unwilling to assume the risk of further infill
06K00136.RPT Page B-8
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development without the acquisition of additional geologic information on reservoir heterogeneity, and
therefore would pursue a 'one-drilldown-at-a-time' approach.
The second case, the advanced technology scenario, assumed that sufficient geologic data would
exist to characterize the reservoir and delineate it into distinct segments, or facies, with reservoir
parameters and heterogeneity relationships developed independently for each segment. This scenario
assumed the availability of more detailed geologic information, so the operator could minimize project risk
and be willing to undertake a geologically targeted infill drilling program in each facies to the minimum
spacing economically justifiable.
The continuity curves described above were used as the basis of both the current (blanket infill
drilling) and advanced (geologically targeted infill drilling) technology evaluations. In the current
technology case, infill drilling potential was estimated reservoir-wide under the assumption that sufficient
wells were drilled to reduce the entire reservoir spacing to one-half its current level, with each well
encountering the "average" continuity for that spacing. Incremental economic evaluations were performed
to determine whether this one-half decrease in pattern spacing was economically justifiable.
In the advanced technology scenario, each reservoir was assumed to be divided into two
segments, a more heterogeneous and less heterogeneous segment. Each reservoir segment was
analyzed independently, with drilling proceeding at one-half reductions in pattern spacing for as long as
these reductions were economically justifiable. Drilling in each segment, if economically justifiable, was
assumed to proceed to a minimum five-acre pattern spacing, or one-eighth of current spacing, the
maximum decrease in spacing considered.
The analysis of UMO considered three categories of UMO recovery processes -- infill drilling,
profile modification techniques, and polymer flooding, along with the combination of infill drilling with the
other two processes. This resulted in five possible processes that were considered for each reservoir.
Technical screening criteria were applied to each reservoir, to determine which processes could be
technically applicable for the reservoir. Each reservoir that satisfied the technical screening criteria for
a particular UMO recovery process was analyzed by detailed performance predictive models at each level
of technology. Each reservoir was then evaluated for its economic feasibility using detailed, engineering
costing and economic analysis models. Costs were developed based on the specific location and
properties of each reservoir, for each recovery process considered. For each reservoir with at least one
recovery process demonstrating economic viability, the process resulting in the greatest volume of
incremental oil recovery was assigned to that reservoir. The final results for the selected, economically
viable reservoirs were then aggregated for the reference case and each regulatory scenario considered.
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For a more complete description of the UMO resource and the analysis methodology used in this
assessment, see ICF Resources and BEG (1989) and IOCC (1989).
IV. ENHANCED OIL RECOVERY IN KNOWN FIELDS
A. Nature of Resource Considered
Enhanced oil recovery (EOR) is defined in this appendix as the incremental recovery of oil in a
reservoir over that produced by conventional primary and secondary recovery methods. Primary recovery
of crude oil relies on the natural energy of the reservoir to drive oil through the reservoir to production
wells. As this energy dissipates, the reservoir becomes depleted. To overcome this, secondary recovery
methods can be undertaken which introduce additional energy to a reservoir through the injection of water
or gas under pressure.
The oil remaining after conventional recovery lies in two defined regions within each reservoir.
In one zone of the reservoir, conventional operations have recovered a significant portion of the original
concentration of oil. The oil remaining in this relatively well swept zone is trapped in the reservoir pore
spaces or on the surface of the pores by capillary and surface tension forces. Additional flooding by
water can produce very little of this oil; the zone is at the 'waterflood residual" level of saturation. The
volume previously occupied by displaced oil now contains injected water (or, in some cases, natural gas).
EOR techniques are generally expected to reach only portions of reservoirs previously swept by
conventional techniques.
In the other zone of the reservoir, conventional recovery processes have not swept much of the
pore space; consequently, the oil saturation in this zone can range anywhere from the pressure-depleted,
post-primary saturation up to the original reservoir oil saturation. The objective of many infill drilling,
waterflooding, and other reservoir management techniques is to contact the oil in these unswept zones.
Only after these zones have been swept by water are EOR operations assumed feasible.
Proven enhanced recovery processes are classified into three categories: gas-miscible, chemical,
and thermal EOR. The following sections briefly describe how each process works to recover incremental
oil.
1 . Gas-Miscible EOR. Gas-miscible EOR is comprised of processes in which a gas, such
as carbon dioxide, nitrogen, flue gas, or enriched natural gas, is injected into a reservoir to mobilize and
displace waterflood residual oil. These processes have been shown to be highly effective in both
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sandstone and carbonate reservoirs, especially it injected at a pressure high enough to cause the gas
and components of the oil to completely mix and stay mixed (achieve miscibility).
The injected gas generally flows into the previously water-swept zones where it displaces the
mobile water and mixes with and swells the oil left in the pore space. With repeated contact of injected
gas and oil, the gas extracts the more volatile portions of the crude oil to form an enriched injected gas-
hydrocarbon mixture. This mixture then displaces most of the oil it contacts, leaving behind a very small
quantity of tar-like residue.
Because the injected gas has low viscosity relative to crude oil, it tends to sweep through the
more permeable parts of the reservoir and often overrides the oil. To minimize these effects, water is
sometimes injected in alternating "slugs" with the gas (particularly in carbon dioxide floods), to increase
the portion of the previously water-swept zone that is also swept by the injectant. Other materials (e.g.,
surfactant foams) are under development to help direct injectants to the relatively unswept areas and
sweep larger portions of the reservoir. The combination of swelling, mixing, and sweeping can effectively
contact, mobilize, and recover a significant portion of the immobile oil remaining in the reservoir. As gas
injection continues, water, oil, and the gas injectant are recovered at the producing wells. In larger
projects, the recovered gas is separated, repressurized, and reinjected.
Carbon dioxide is the most common miscible gas injectant. Carbonate (limestone and dolomite)
reservoirs are especially well suited to the injectant; below-average conventional recovery efficiencies in
these reservoirs have spurred many operators to implement enhanced recovery projects to contact and
produce the resultant large volumes of remaining oil. However, CO2-miscible EOR operations are
currently only economically feasible in areas located close to large sources of C02.
2. Chemical EOR. Chemical EOR involves the injection of chemicals into a reservoir to
reduce the interracial tension between residual oil and water and/or improve the mobility ratio (the contrast
in viscosities and relative permeabilities) between the injected, displacing fluids and the displaced fluid.
The major chemical processes are surfactant flooding, alkaline injection, and polymer flooding. Surfactant
flooding involves the injection of a chemical that is both oil and water soluble to reduce the interfacial
tension between these fluids at reservoir conditions. The chemical "slug" may include surfactant, water,
hydrocarbons, alcohols, polymers, and inorganic salts to mobilize the residual oil. Polymer slugs, injected
before and after the surfactant, provide mobility control and help maintain the integrity of the chemical
slug. Due to the high cost of surfactants, the slug is typically small relative to the volume of control agents
injected before and after it. Surfactant floods must be designed specifically for each reservoir as the most
effective combination of chemicals is highly dependent on the temperature, salinity, rock properties, and
06K00136.RPT Page B-11
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crude oil composition of the reservoir. As such, the process is relatively complicated, expensive, and
therefore risky compared to conventional recovery operations and other EOR processes.
Alkaline flooding uses chemicals such as sodium hydroxide, sodium silicate, and sodium
carbonate to enhance oil recovery by reducing interracial tension, emulsifying the oil, and/or altering
formation wettability. These mechanisms create a surfactant in the reservoir as the alkaline solution
neutralizes petroleum acids. Interfacial tension reduction and wettability reversal can reduce oil saturation
below the waterflood residual saturation, substantially increasing displacement efficiency and, therefore,
ultimate recovery (NPC, 1984). Potential recovery is highest with moderately viscous, napthenic, low API
gravity, high acid-number crude oils. Increased oil recovery from this process may differ substantially from
one application to another, depending upon the particular oil/water/rock system investigated.
3. Thermal EOR. Thermal EOR processes include steam drive, steam soak, and in-situ
combustion. The hydrocarbon displacement properties and process economics of steam soak and steam
drive processes have been extensively demonstrated in California. In fact, steam EOR projects account
for about three-fourths of all EOR production in the U.S. and are recognized as commercially proven
technologies in heavy oil (less than 20° API gravity) reservoirs at depths less than 3,000 feet. Most
operating steam projects in the U.S. are in California.
Thermal recovery processes involve the introduction of heat to reduce viscosity of remaining crude
oil to partially "crack" the heavy oil into lighter constituents. This process produces a pressure gradient
to drive the oil through the reservoir and into the producing wells. Steamflooding involves the injection
of steam to heat the reservoir oil, thus reducing its viscosity and stimulating its production. Steam heats
the oil and either pushes or drags it towards a production well, where it is pumped to the surface. When
steam flows into the reservoir, it condenses as the latent heat is transferred to the rocks and reservoir
fluids. The adjacent formations above and below the reservoir are also heated as the steam expands
outward from the injection well. The steam vapor tends to rise to the top of the reservoir, while the
condensed water tends to under-run the steam zone. This separation of the vapor and liquid phase,
frequently called gravity segregation, is due to their different densities. As the oil is heated, its viscosity
is reduced, thus allowing both the steam and condensed water phases to displace the oil toward a
production well.
In-situ combustion, another thermal recovery technique, is normally applied to reservoirs
containing low-gravity oil, but has been tested over perhaps the widest spectrum of conditions of any EOR
process. Heat is generated within the reservoir by injecting air and burning part of the crude oil, which
reduces the oil viscosity and partially vaporizes the oil in place. The oil is driven forward by a combination
06K00136.RPT Page B-12
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of steam, hot water, and gas drive. The relatively small portion of the oil that remains after these
displacement mechanisms have acted becomes the fuel for the in-situ combustion process. In some
applications, the efficiency of the total in-situ combustion operation can be improved by alternating water
and air injection. The injected water tends to improve the utilization of heat by transferring heat from the
rock behind the combustion zone to the rock immediately ahead of the combustion zone.
B. Analytical Approach
The analysis of EOR potential in this study also used TORIS, the integrated system of data bases,
models, and analytical procedures originally developed by the National Petroleum Council (NPC) for their
1984 study of U.S. EOR potential (NPC, 1984). The analysis of EOR potential was based on reservoir data
from over 3,700 reservoirs throughout the nation, corresponding to approximately 70% of the U.S. crude
oil resource in place. The approach for assessing EOR potential is summarized as follows:
• First, detailed reservoir data on U.S. crude oil reservoirs has been collected, maintained,
and continually updated and reviewed for comprehensiveness, consistency, and
accuracy. This data base serves as the cornerstone for all TORIS analyses.
Each reservoir in the data base was subjected to a screening process designed to
identify the technical applicability of the respective EOR technologies. Screening criteria
were performed under both implemented and advanced technology scenarios. These
screening criteria are summarized in Table B-2 for the implemented technology case, and
in Table B-3 for the advanced technology case. The EOR recovery processes considered
were:
Thermal recovery processes, consisting of steam
injection and in situ combustion
Miscible flooding, consisting primarily of CO2 injection
Chemical flooding, consisting of the injection of
surfactants and alkalines.
Each reservoir that satisfies the technical screening criteria for a particular EOR process
was analyzed by detailed EOR performance predictive models at each level of technology.
Each reservoir was then evaluated for its economic feasibility using detailed engineering
costing and economic analysis models. Costs were developed based on the specific
location and properties of each reservoir, for each recovery process considered.
. For each reservoir with at least one recovery process demonstrating economic viability,
the process resulting in the greatest volume of incremental oil recovery was assigned to
that reservoir. The selected, economically viable reservoirs were then aggregated to
summarize the final results.
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TABLE B-2
SCREENING CRITERIA FOR EOR CANDIDATES - IMPLEMENTED TECHNOLOGY CASE
Screening
Parameters*
Oil Gravity
Insitu Oil Viscosity (/u)
Depth
Pay Zone Thickness (h)
Reservoir Temperature (TR)
Porosity (0)
Permeability Average (k)
Transmissibility (kh//;)
Reservoir Pressure (PR)
Minimum Oil Content at
Start of Process (S0X0)
Salinity of Formation
Brine (IDS)
Rock Type
Miscible
Chemical Flooding Flooding Thermal
(Carbon
Units Surfactant Alkaline Dioxide) Steam
°API - <30 ;>25 10 to 34
cp <40 <90 - ^15,000
Feet - - - 5^3,000
Feet - - - ^20
°F <200 <200
Fraction -- - -- ;>0.20***
md >40 >20 - 250
md-ft/cp -- -- - ;>5
psi -- - ;>MMP** <;1,500
Fraction -- -- -- ;>0.10
ppm < 100,000 < 100,000
Sandstone Sandstone Sandstone Sandstone
or or
Carbonate Carbonate
Recovery
In-Situ
Combustion
10 to 35
s5,000
<;! 1,500
*20
--
^0.20***
35
*5
<;2,000
^0.08
-
Sandstone
or
Carbonate
* Other criteria of a geological and depositional nature were also considered. Generally, reservoirs with extensive faulting,
lateral discontinuities, or overlying gas caps are not prime candidates for field-wide EOR application. These factors were
considered during the manual screening step when they could be identified.
** MMP denotes minimum miscibility pressure, which depends on temperature and crude oil composition.
*** Ignored if oil saturation (SJ X porosity () criteria are satisfied.
Source: NPC, 1984.
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TABLE B-3
SCREENING CRITERIA FOR EOR CANDIDATES - ADVANCED TECHNOLOGY CASE
Screening
Parameters*
Oil Gravity
Insitu Oil Viscosity (/j)
Depth
Pay Zone Thickness (h)
Reservoir Temperature (TR)
Porosity (0)
Permeability Average (k)
Transmissibility (kh/p)
Reservoir Pressure (PR)
Chemical Flooding
Units Surfactant Alkaline
°API - <30
cp < 1 00 < 1 00
Feet
Feet
°F <250 <200
Fraction
md >10 >10
md-ft/cp
psi
Miscible
Flooding Thermal Recovery
(Carbon In-Situ
Dioxide) Steam Combustion
,25
5:5,000
5:5,000
,15 ,10
-
2:0.15*** ,0.15***
,10 ,10
-
,MMP** 5:2,000 5:4,000
Minimum Oil Content at
Start of Process (S0X0) Fraction
Salinity of Formation
Brine (TDS) ppm
Rock Type
^0.08
2:0.08
< 200,000
Sandstone
or
Carbonate
< 200, 000
Sandstone
—
Sandstone
or
Carbonate
—
Sandstone
or
Carbonate
—
Sandstone
or
Carbonate
Other criteria of a geological and depositlonal nature were also considered. Generally, reservoirs with extensive faulting,
lateral discontinuities, or overlying gas caps are not prime candidates for field-wide EOR application. These factors were
considered during the manual screening step when they could be identified.
MMP denotes minimum miscibilrty pressure, which depends on temperature and crude oil composition.
Ignored if oil saturation (S^ X porosity ($) criteria are satisfied.
Source: NPC, 1984.
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Two levels of EOR technology were evaluated in this assessment. The first level, the implemented
technology case, represented technology currently in place and proven in successful field tests. The
second level, the advanced technology case, assumed technological improvements resulting from
successful research and development, improving EOR recovery efficiencies and expanding the resource
applicable to EOR recovery processes.
A more detailed description the methodology employed to evaluate the potential of EOR is
presented elsewhere (NPC, 1984; IOCC, 1989).
V. UNDISCOVERED CRUDE OIL RESOURCES
A. Nature of Resource Considered
Undiscovered crude oil resources, as defined by the U.S. Geological Survey (USGS) and the
Minerals Management Service (MMS), are those resources judged to exist in geologically promising but
unexplored or undrilled areas. The existence of these resources are based on broad geologic knowledge
and theory, in settings outside of known accumulations of hydrocarbons. This resource includes
undiscovered fields and pools within known fields that occur as unrelated accumulations controlled by
distinctly separate structural features or stratigraphic conditions. For purposes of this analysis, the
economic feasibility of undiscovered resources was determined assuming that the production of crude
oil associated with a discovered hydrocarbon accumulation must support all costs associated with its
development, including all exploration costs, dry hole costs, and lease bonus payments and rentals. The
undiscovered resource base evaluated as part of this study was based on the most recent assessment
of the U.S. Department of Interior (DOI, 1989).
B. Analytical Approach
REPCO is an analytical model which utilizes the DOI estimates of recoverable undiscovered crude
oil resources and assesses the economic feasibility and recovery potential of this resource. Analyses of
undiscovered resources in the Lower-48 (a relatively mature region in terms of exploration history and
supporting data) is based on a finding rate approach, which uses historical relationships between drilling
effort and the amount of remaining undiscovered resources. Relationships between discovery rates and
estimated well recoveries are used to determine the typical field size of fields remaining to be recovered,
with field sizes decreasing within a region as the region becomes more developed. Analyses of the
Lower-48 offshore and Alaska undiscovered resources use a field size distribution approach, where the
undiscovered crude oil resource is distributed into prospects by field size.
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Appropriate exploration and production technologies were chosen for each region considered in
the offshore resource assessment in REPCO. For both the onshore and offshore undiscovered resource,
relationships between field size and well productivity for each region, based on historical development and
production data and/or analog regions, were used to determine the number of wells required, the timing
of development, and anticipated production rates over the life of a project.
The economics of developing the undiscovered crude oil resource included all costs associated
with its development. This included pre-development costs for geological and geophysical activity, lease
acquisition, and other pre-exploration activities; exploration costs for the initial successful wildcat well and
associated allocated unsuccessful wildcats; along with all other conventional development costs for wells,
equipment and facilities (including development dry holes), operation and maintenance costs, and all
royalties, taxes, and return on capital.
The assessment of undiscovered crude oil resources considered the entire U.S undiscovered
resource base. No exclusions for land set aside from leasing or currently under leasing moratoria, such
as that in the Arctic National Wildlife Refuge (ANWR) or certain areas off the coast of California and
Florida, were evaluated.
In the analysis, resources believed to exist in the Lower-48 onshore, Lower-48 offshore, and Alaska
(onshore and offshore) were analyzed separately. In addition, this analysis only considered the
conventional primary and secondary recovery of the undiscovered crude oil resource. The recovery
potential of intensive infill drilling or EOR in these undiscovered fields was not evaluated, nor was the
potential associated with advanced recovery technologies in these fields.
A more detailed description of the analysis methodology for undiscovered resources is provided
elsewhere (Lewin and Associates, Inc., 1985).
VI. ECONOMIC ANALYSES
An important feature of all the economic analysis models used in this analysis was that costs were
determined as a function of price and other market (infrastructural) factors. Analyses of historical data
demonstrate conclusively that oil field costs are intimately related to crude oil prices. However, in studying
cost trends since 1981, it has become increasingly apparent that other market factors also influence costs
(Kuuskraa and others, 1987). By expanding upon previous work (NPC, 1984), the impact of these factors
have been quantified. Oil field costs are shown to be directly related to both oil prices and rig utilizations
06K00136.RPT Page B-17
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rates. In short, when the demand for rigs is high, costs increase, since drillers are able to bid up costs.
Conversely, when the demand for rigs is low, drillers bid costs down.
Moreover, each of the three major components of oil field costs -- drilling and completion costs,
lease equipment costs, and operation and maintenance costs -- is influenced differently by the
cost/price/infrastructure relationship:
• Drilling and completion costs are strongly affected by both oil prices and rig utilization,
because drilling is essentially captive within the domestic market.
• Lease equipment costs such as valves, compressors, and pumps have alternative
markets outside the oil patch; thus the excesses or shortages of such equipment have
shorter term, more moderate impacts on equipment costs.
Operating costs include fuel, labor, and maintenance and services. The fuel component
is directly related to oil prices, although more directly related to electricity. The
maintenance component, which includes well workovers, is related to the oil industry
infrastructure. Finally, the labor component is related to general economic trends and
industry profitability.
Regressions have been developed to relate costs to prices and rig utilization for each of the three
cost categories. Including these relationships is essential for properly taking into account future oil field
activity. In this analysis, the algorithms for adjusting costs were included in the evaluation of all resources
considered, and were applied to both normal oil field costs and to all costs associated with environmental
compliance.
VII. GENERAL ASSESSMENT PROCEDURE
The economic and energy impact assessments were performed at several possible oil prices in
order to consider the impact of the regulatory options for various future economic conditions that could
result over the next 20 years. Oil prices varied from $16 to $32/Bbl, in real 1988 dollars. The oil recovery
potential was determined for each resource category at each price considered.
The applicable tax structures for each geographic area (state or federal OCS) were considered
for each reservoir. The federal corporate income tax was calculated based on the current marginal tax
rate of 34%.
The analyses were performed for each regulatory scenario, incorporating the specific, incremental
environmental compliance costs associated with each scenario. Incremental compliance costs were
based on the compliance requirements associated with each regulatory initiative, as discussed in
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Appendix A. Where necessary, these costs were converted to units appropriate for inclusion into the
analysis models used.
The first step in the analysis for each resource category was to estimate the economic recovery
potential for the reservoirs considered under baseline conditions, which included the costs of compliance
with current state and federal environmental regulations. Public sector revenues and incremental
compliance expenditures associated with the recoverable reserves were also determined. Next, analyses
were performed considering the incremental compliance costs associated with the set of potential
regulatory initiatives considered for each scenario. The incremental compliance costs corresponding to
each regulatory scenario were added to the baseline costs, specific for each region and resource
category considered. The economic recovery potential was determined for each scenario, along with the
public sector revenues and the incremental compliance expenditures associated with that scenario.
The analyses for each resource category were performed and the results were aggregated in a
consistent manner, in order that impacts between resource categories could be compared and contrasted.
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APPENDIX C
Cost Estimates Used in Economic
Analysis of MMS Proposed
Offshore Air Quality Regulations
06K00136.RPT
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APPENDIX C
COST ESTIMATES USED IN ECONOMIC ANALYSIS OF
MMS PROPOSED OFFSHORE AIR QUALITY REGULATIONS17
A. Exploration Phase
1. Drilling Vessel Engine Installation and Maintenance
a. Drilling vessels are assumed to drill 3.5 wells per year
b. Drilling vessels are assumed to be equipped with 6 prime movers (engines)
c. Estimated cost of BACT modifications is $6,000 per prime mover or engine
d. Maintenance costs are assumed to be $5,000 per engine per year
e. These costs are escalated by a factor of 1.187 to arrive at 1987 dollars
Installation Cost - (6 prime movers) ($6,000/mover/vessel)
= $36,000/vessel
Assuming this cost is amortized over 10 years at a 10% discount rate
(1.187) (36.000W1.10)10 = $11,084/year
10
($11,084/year)/(3.5 wells/year) = $3,167/well
Maintenance Cost = (1.187)(6 engine/vessel)($5,000/engine/year) = $35,610/vesseyyear
= $35.610/vessel/vear = $10,174/well/year
3.5 wells/vessel
2. Support Vessel Engine Installation and Maintenance
a. Assumes 2.5 support vessels per drilling vessel
b. Support vessels assumed to have 3 engines (movers)
c. Costs same as those for engines on drilling vessels
Installation Costs =
(3 engines/support vessel) ($6,000/engine) (2.5 support vessels/drill vessel) (1.187)
= $53,415/vessel
1/Assumptions based on MMS memorandum entitled, "Economic Analysis in Determination of Effect of Rule," in
support of Proposed Rule, 'Oil and Gas and Sulphur Operations in the Outer Continental Shelf, California;
Proposed Rule and Proposed Technical Determinations" (30 CFR Part 250, January 17, 1989), regarding air quality
control measures off the coast of California.
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Amortized at 10% discount rate for 10 years
= ($53,415H1.10)10 = ($13,854/year/drill vessel)
10
($13.854/drill vessel/year) = $3,958/well
3.5 wells/drill vessel
Maintenance Costs =
(1.187)(3 movers)($5,000/mover)(2.5 support vessel/drill vessel) = $44,512/vessel/year
= $44,512/vessel
3.5 wells/vessel = $12,718/well/year
3. Drilling Vessel Fuel Increase
a. Assume a 2% fuel increase on a base fuel cost of $520,000/well
Cost = 0.02(520,000) = $10,400/well
4. Toxic Assessment
a. Assumes a toxic risk assessment costing $5,000 per exploration plan
Cost = $5,000/well
5. Linear Modeling
a. Assumes a linear modeling run for inert dispersion is run for each exploration
plan
b. The cost to run model and analyze results in estimated to be $4,000.
Cost = $4,000/exploration well
6. Drilling Operations — Mitigation
a. BACT will reduce emissions to 48 tons per well drilled
b. Mitigation fee is $7,000/ton
Cost = (48 tons)($7,000/ton) = $336,000/well
7. Crew and Supply Vessels — Mitigation
a. BACT will result in 42.4 tons per year for drilling 3.5 wells
UoMXJioo.Hr I
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b. Assumes 2.5 support vessels per drill vessel
Tons/year = (42.4 tons/year/support vessel) (2.5 support vessel/drill vessel)
= 106 tons/year/drill vessel
(106 tons/vear/drill vesselU$7.000/ton)
(3.5 wells/year/drill vessel) = $212,000/well
8. Total Exploration Costs (assuming exploration drilling takes one year)
a. No Mitigation Costs
$3,167
10,174
3,958
12,718
10,400
5,000
4.000
$49,417
b. With Mitigation Costs
$49,417
336,000
212.000
$597,417
B. Development - Platform Construction Phase
1. Install Meteorological Station
a. Assumes an installation cost of $100,000 per station
b. Assumes one station per 2 platforms
c. Assumes an operation cost of $50,000 per station per year
Installation Cost = $50,000/platform
Operating Cost = $25,000/platform/year
2. Construction Vessel Engine Installation and Maintenance for BACT
a. Dredges, pile drivers and other construction vessels assumed to have 6 prime movers per
vessel.
b. Assumes 3 construction vessels per platform.
c. Assumes installation cost of $6,000 per engine.
d. Assumes maintenance costs of $5,000 per engine per year.
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Installation Cost = (6 engines/vessel)($6,000/engine)(1.187)
= $42,732/vessel
Assuming that the cost is amortized at a 10% rate for 10 years, the cost per platform installed
is:
($42,732/vessel) (3 vessels/platform) (1.1010/10) = $33,251/platform
Maintenance Cost =
($5,000/engine/year)(6 engines/vessel)(3 vessels/platform)(1.187)
= $106,830/platform/year
3. Construction Vessel Engine Fuel Costs
a. Assumes an increase of 80% in fuel cost per construction vessel.
b. Assumes baseline of $520,000 fuel cost per construction vessel.
Fuel Cost = 0.80($520,000/vessel)(3 vessels/platform)
= $1,248,000/platform/year
4. Support Vessel Engine Installation and Maintenance
See item A.2, applied per platform rather than per well
5. Electrification Analysis
a. Assumes electrification analysis of $50,000 per platform
b. Assumes that one-half of the analysis is attributable to the rule
Cost = $25,000/platform
6. Toxics Assessment
a. Assumes a toxics risk assessment costing $5,000 per development plan; assume one cost
per platform
Cost = $5,000 per platform (one time cost)
7. Construction Phase - Mitigation
a. Assume 224 tons of emittants per platform per year
Cost = ($7,000/ton)(224/tons/platform) = $1,568,000/platform
06K00136.HPI Page C-4
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8- Total Costs - Construction Phase
a. No Mitigation Costs
Cost/Platform
$50,000
3,958
25,000
5,000
$83,958
Cost/Platform/Year
$25,000
106,830
12,718
1.248,000
$1,392,548
b. With Mitigation Costs
Cost/Platform
$83,958
Cost/Platform/Year
$1,392,548
1,568,000
$2,960,548
C. Development Drilling and Production Operations Phases
1. Turbine Installation
a. Assumes 3 turbines/platforms includes drilling and production operations.
b. Assumes $60,000 installation of BACT per turbine
Installation Cost =
($66,000/turbine)(3 turbine/platform) = $198,000/platform
MMS assumes that future platforms in California would characteristically be 25 slots, with
three gas turbine generators to supply electrical power. While this may characterize existing
platforms in the Gulf of Mexico, future field discoveries will likely be smaller, corresponding
to smaller platforms. For purposes of this analysis, future platforms in the Gulf of Mexico and
the rest of the OCS will be assumed to have, on average, 1.5 turbines to supply electrical
power, at a cost of $99,000/platform
2. Turbine Maintenance
a. Assumes $10,000/turbine/year maintenance cost, 3 turbines per platform
Maintenance Cost (California and existing platforms) =
($10,000/turbine/year)(3 turbine/platform)
= $30,000 platform/year
For future platforms in the Gulf of Mexico, a cost of $15,000/platform/year is assumed.
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3. Fuel for Turbines
a. Assumes no increase in costs of fuel.
4. Emissions Inventory
a. MMS assumes an initial and annual cost for the inventory of $50,000 and $20,000,
respectively. In this analysis, assume that the cost is $20,000/platform/year.
5. Toxic Assessment
a. Assumes a one-time cost of $5,000 per development/production plan for a toxic assessment.
Cost = $5,000/development well
6. Source Test
a. Assume cost of $50,000/platform/year
7. Development Drilling Mitigation
a. Assume 100 tons of emittants per platform per year during drilling operations.
Cost = ($7,000/ton)(100) = $700,000/platform/year
8. Production Operations Mitigation Costs
a. Assumes 100 tons/year of emittants from production operations
b. Estimated reduction in emissions from use of water injection of the turbines is 40%.
Cost = (100 tons/year/platform)($7,000/ton)(1-0.40)
= $420,000/platform/year
9. Total Costs - Development Drilling
a. No Mitigation
Initial platform costs
$198,000 (California and existing platforms)
$99,000 (New platforms in rest of OCS)
06KQQ136.RPT Page C-6
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Annual platform costs (during development drilling)
California and existing platforms New platforms in rest of PCS
$30,000 $15,000
20,000 20,000
50.000 50.000
$100,000 $85,000
Initial Well Costs
$5,000
Annual Well Costs
$4,000
b. With Mitigation
Annual platform costs (during development drilling)
California and existing platforms
$100,000
700.000
$800,000
10. Total Costs - Production Operations
a. No Mitigation
California and existing platforms New platforms in rest of PCS
$30,000 $15,000
20,000 20,000
50.000 50,000
$100,000 $85,000
Annual Well Costs
California and existing platforms
$100,000
420.000
$520,000
06K00136.RPT Page C-7
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APPENDIX D
Updated Forecast of Future
Abandonment Rates of the Known
Domestic Oil Resource
06K00136.RPT
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APPENDIX D
UPDATED FORECAST OF FUTURE ABANDONMENT RATES
OF THE KNOWN DOMESTIC OIL RESOURCE
In 1989, the U.S. Department of Energy (DOE) prepared a report entitled Abandonment Rates of
the Known Domestic Oil Resource (DOE, 1989), which forecast future trends in the abandonment of U.S.
crude oil resources. The report was based on detailed analyses of historical production data on nearly
800 producing oil reservoirs in nine oil-producing states, using the Tertiary Oil Recovery Information
System (TORIS). The production data for individual reservoirs were evaluated using a decline curve
model to project the ultimate recovery and the time when each reservoir would reach its economic limit
of production. The analysis was performed at four constant oil prices, ranging from $16 to $34/Bbl. The
results for each reservoir were then aggregated to arrive at the reported estimates of resource
abandonments at each price.
Since the completion of the 1989 report, the TORIS reservoir and production data bases have
been updated to include additional production data and new reservoirs not previously considered. The
decline curve model used in the analysis was also updated to more accurately predict production decline
for the reservoirs in TORIS. The analyses presented in this report are based on the updated data bases
and models, and consequently yield forecasts which deviate somewhat from those reported in the original
DOE report (DOE, 1989).
Figures D-1 and D-2 provide a comparison of projected production decline and resource
abandonment rates between this study and the 1989 DOE report. Also shown in Figure D-2 is an estimate
of actual U.S. crude oil resource abandonments over the 1985 through 1989 time period, based on data
collected by Petroleum Information (PI) Corporation. The two cases in the figures are:
• Case 1: The original projection as reported by DOE (DOE, 1989). This curve
corresponds to the $16/Bbl case (in 1985 dollars) presented in the report, which is
roughly equivalent to an $18/Bbl case in 1988 dollars (the closest case comparable to
more recent runs).
• Case 2: Projections prepared for this report (as presented in Chapter IV) at a $20/Bbl oil
price, which incorporate recent modeling changes and updated reservoir-specific
production data for the years 1986 through 1988, and new reservoirs which were recently
added to the TORIS data base.
06K00136.RPT Pa9e
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Figure D-1
Comparison of Recent TORIS Projections
of U.S. Crude Oil Production Decline
2.0
1.5
(0
0)
O JO
£ 1.0
•o co
O CO
m
0.5
0
\
Case 1
Case 2
$18 (DOE 1989) —
$20 Current Report - —
(Oil Prices in 1988 $/Bbl)
j i i i i L
j i
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015
Year
EPA81090a
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Page D-2
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•(3
3
"5
T3
0)
O
<
0)
O
O)
c
'c
"(C
0)
a:
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0
Figure D-2
Comparison of Reeent TORIS Projections
of U.S. Crude Oil Resource Abandonments
Case 1
Case 2
$18 (DOE 1989) —
$20 Current Report _ _
(Oil Prices in 1988 $/Bbl)
PI Historical Data
i
i
1985
1990
1995
2000
Year
2005
2010
2015
epa81090b
06K00135.RPT
Page D-3
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The primary reason for the differences in the forecasts developed for the two studies is that
Case 1 was evaluated using historical annual production data from 1970 through 1985, the most recent
reservoir-specific production data available at the time the forecast was made for the earlier DOE report.
Case 2 includes additional reservoir-specific production data for 1986, 1987, and 1988 for the reservoirs
analyzed.
In addition, the Case 1 estimates assumed the National Petroleum Council's (NPC, 1984)
assumption of a constant severance tax rate of 5%, where actual state severance tax rates were assumed
for the reservoirs analyzed in the Case 2 forecasts. This latter modification has a moderate impact on the
calculation of economic limit of production for certain reservoirs.
Other modifications incorporated into Case 2 projections include:
• Addition of production data for 211 Texas reservoirs not previously included in TORIS.
Relaxation of the certain constraints on the best curve fit in the decline curve model for
reservoirs with fluctuating annual production, which otherwise resulted in steeper
projected production decline.
• Removal of 26 reservoirs from the analysis with missing values for formation depth, which
were previously assigned default values. The default values were believed to be
somewhat excessive, thus resulting in higher operating costs and a higher calculated
economic limit for these fields.
Given the extent of the modifications made to the TORIS data bases .and models, it is believed
that the Case 1 and Case 2 estimates are consistent and the differences shown between the two are
reasonable reflections of the changes made. In fact, the small degree of the difference in the Case 2
estimates reemphasizes the plausibility and the validity of the projections presented in the original DOE
report (DOE, 1989). Finally, the updated forecast of oil resource abandonments compares well to
estimated actual abandonments over the 1985 to 1989 time period as reported by PI, demonstrating the
claim that the TORIS-based methodology provides a leading indicator of future resource abandonments.
OoMXJI Jo.Mrl
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