Cost Analysis for the Federal 

 Requirements Under the Underground 

 Injection Control Program for Carbon 

Dioxide Geologic Sequestration Wells 

(Final GS Rule)
Office of Water (4606M) 

EPA 816-R10-013 

November 2010 

http://water.epa.gov/drink/ 
Cost Analysis for the i November 2010 

Final GS Rule

Contents 

Appendices.................................................................................................................................... iv

Exhibits ...........................................................................................................................................v

List of Acronyms......................................................................................................................... vii

1. Introduction.......................................................................................................................... 1-1

 1.1         Technical, Public Health, and Regulatory Issues Addressed by the GS Rule...........1-2

 1.1.1     Description of the Issue ................................................................................1-3

 1.1.2     Public Health Concern to Be Addressed....................................................... 1-4

 1.1.3     Statutory Authority for Promulgating the Rule ............................................ 1-5

 1.2 Regulatory History....................................................................................................1-6

 1.3         Economic Rationale................................................................................................... 1-7 

2. Consideration of Regulatory Alternatives......................................................................... 2-1

 2.1         Introduction ...............................................................................................................2-1

 2.2         Process for Development of Regulatory Alternatives...............................................2-1

 2.3         Regulatory Alternatives Considered.......................................................................... 2-4

 2.3.1     Regulatory Alternative 1................................................................................2-4

 2.3.2     Regulatory Alternative 2................................................................................2-4

 2.3.3     Regulatory Alternative 3................................................................................2-6

 2.3.4     Regulatory Alternative 4..............................................................................2-10

 2.3.5     Comparative Summary of Regulatory Alternatives ....................................2-12

 2.4        Final Rule Requirements.......................................................................................... 2-27 

3. Baseline Analysis.................................................................................................................. 3-1

 3.1 Introduction.................................................................................................................3-1

 3.2      Data Sources ............................................................................................................... 3-1

 3.2.1 Published Data ............................................................................................... 3-1

 3.2.2 Department of Energy Pilot Project Data ...................................................... 3-2

 3.2.3 DOE Inventory Data ......................................................................................3-3

 3.2.4    Laboratory Research.......................................................................................3-3

 3.3     Hydrogeologic Settings ............................................................................................... 3-3

 3.3.1 Formation Types ............................................................................................ 3-4

 3.3.2    Formation Capacity ........................................................................................ 3-5

 3.4      Geologic Sequestration Rule Baseline......................................................................... 3-5

 3.4.1    Projects Comprising the Baseline...................................................................3-6

 3.4.2    Project Characteristics....................................................................................3-8

 3.5     Sources of Uncertainty .............................................................................................. 3-10 
Cost Analysis for the ii November 2010 

Final GS Rule

4. Benefits Analysis .................................................................................................................. 4-1

 4.1     Introduction .................................................................................................................4-1

 4.2    Relative Risks – Qualitative Analysis .........................................................................4-1

 4.2.1      Site Characterization......................................................................................4-4

 4.2.2      Area of Review (AoR) and Corrective Action ..............................................4-5

 4.2.3      Injection Well Construction...........................................................................4-6

 4.2.4      Injection Well Operation................................................................................4-7

 4.2.5      Mechanical Integrity Testing .........................................................................4-8

 4.2.6      Testing, Monitoring, and Reporting...............................................................4-9

 4.2.7       Injection Well Plugging, Post-Injection Site Care (PISC), and Site 

 Closure .........................................................................................................4-10

 4.2.8      Financial Responsibility............................................................................... 4-11

 4.2.9      Emergency and Remedial Response............................................................ 4-11

 4.2.10   Adaptive Regulatory Process .......................................................................4-11

 4.2.11   Overall Estimate of Change in Risk ............................................................. 4-12

 4.3    Ancillary Benefits...................................................................................................... 4-13

 4.4    Uncertainty in Benefits Estimates ............................................................................. 4-15

5. Cost Analysis ........................................................................................................................ 5-1 

 5.1 Introduction .................................................................................................................5-1 

 5.2 General Cost Assumptions and Methodology............................................................. 5-2 

 5.2.1 Labor Rates ....................................................................................................5-4 

 5.2.2 General and Administrative Costs ................................................................. 5-5 

 5.3 Projecting and Discounting National Costs ................................................................ 5-5 

 5.4 Derivation of Costs for Owners and Operators of GS Wells and the Permitting 

 Authority..................................................................................................5-6 

 5.4.1 Rule Implementation and Annual Administration......................................... 5-9 

 5.4.2 Geologic Site Characterization ...................................................................... 5-9 

 5.4.2.1 Annualized Costs for Geologic Site Characterization ................5-11 

 5.4.3 Area of Review and Corrective Action........................................................ 5-11 

 5.4.3.1 Annualized Costs for Area of Review and Corrective Action....5-12 

 5.4.4 Injection Well Construction.........................................................................5-13 

 5.4.4.1 Annualized Costs for Injection Well Construction..................... 5-16 

 5.4.5 Injection Well Operation..............................................................................5-16 

 5.4.5.1 Annualized Costs for Injection Well Operation.......................... 5-19 

 5.4.6 Mechanical Integrity Testing ....................................................................... 5-19 

 5.4.6.1 Annualized Costs for Mechanical Integrity Testing ...................5-20 

 5.4.7 Monitoring ...................................................................................................5-21 

 5.4.7.1 Annualized Costs for Monitoring ...............................................5-25 

 5.4.8 Well Plugging and Post-injection Site Care.................................................5-26 

 5.4.8.1 Annualized Costs for Well Plugging and PISC .......................... 5-28 

 5.4.9 Financial Responsibility...............................................................................5-28 

 5.4.9.1 Annualized Costs for Financial Responsibility...........................5-29 

 5.4.10 Emergency and Remedial Response Plans .................................................. 5-30 

 5.4.11 Permitting Authority Costs .......................................................................... 5-30 

 5.4.11.1 Rule Implementation and Annual Administration...................... 5-31 

 5.4.11.2 Geologic Site Characterization ...................................................5-31 

 5.4.11.3 Area of Review and Corrective Action.......................................5-31 

 5.4.11.4 Injection Well Construction........................................................ 5-31 
Cost Analysis for the iii November 2010 

Final GS Rule

 5.4.11.5 Injection Well Operation............................................................. 5-32 

 5.4.11.6 Mechanical Integrity Testing ...................................................... 5-32 

 5.4.11.7 Monitoring ..................................................................................5-32 

 5.4.11.8 Well Plugging and PISC .............................................................5-32 

 5.4.11.9 Financial Responsibility.............................................................. 5-33 

 5.4.11.10 Emergency and Remedial Response Plans ................................. 5-33 

 5.5 Estimated Costs to Households................................................................................ 5-37 

5.6 Comparison of Annualized Incremental Costs for All Regulatory Alternatives 

 Considered ............................................................................................................... 5-37 

 5.6.1 Costs Summed by Type of Expenditure ...................................................... 5-38 

 5.6.2 Costs Summed by Rule Component ............................................................ 5-39 

 5.7 Comparison of Costs and Benefits........................................................................... 5-40 

 5.8 Other Economic Measures ....................................................................................... 5-40 

 5.9 Non-quantified Costs and Uncertainties in Cost Estimates ..................................... 5-40 

 5.9.1 Non-quantified Costs ................................................................................... 5-40 

 5.9.2 Uncertainties in Cost Estimates ................................................................... 5-41 

6. Economic Impact Analysis.................................................................................................. 6-1

 6.1      Introduction ................................................................................................................ 6-1

 6.2      Executive Order 12866: Regulatory Planning and Review........................................ 6-2

 6.3      Paperwork Reduction Act...........................................................................................6-2

 6.4      Regulatory Flexibility Act.......................................................................................... 6-3

 6.5      Unfunded Mandates Reform Act (UMRA)................................................................ 6-4

 6.6      Executive Order 13132: Federalism...........................................................................6-4

6.7      Executive Order 13175: Consultation and Coordination with Indian Tribal 

 Governments .............................................................................................................. 6-5

6.8      Executive Order 13045: Protection of Children from Environmental Health Risks 

 and Safety Risks......................................................................................................... 6-5

6.9      Executive Order 13211: Actions that Significantly Affect Energy Supply, 

 Distribution, or Use.................................................................................................... 6-6

 6.10     National Technology Transfer and Advancement Act............................................... 6-6

 6.11     Executive Order 12898: Federal Actions to Address Environmental Justice in 

 Minority Populations and Low-Income Populations ................................................. 6-6 

7. References..................................................................................................7-1 
Cost Analysis for the iv November 2010 

Final GS Rule

Appendices 

Appendix A Pro Forma Projects 

Appendix B Project Algorithms 

Appendix C Summary of Rule Costs 
Cost Analysis for the v November 2010 

Final GS Rule

Exhibits 

Exhibit 2.1 Comparison of Alternatives for GS of CO2 ...................................................2-13 

Exhibit 3.1 Schedule of Baseline Project Deployment by Formation Type and 

 Project Size ................................................................................................3-7 

Exhibit 3.2 Project Characteristics By Formation Type and Size ....................................3-9 

Exhibit 4.1 Estimated Change in Risk for Components of the RAs Compared to the 

Regulatory Baseline.......................................................................................4-3 

Exhibit 5.1 Loaded Labor Rates by Standard Occupational Classification (SOC) 

 and Government Schedule Codes- 2008$......................................................5-5 

Exhibit 5.2 Project Characteristics By Formation Type and Size ....................................5-8 

Exhibit 5.3 Owner and Operator Burden and Unit Cost Estimates for Geologic 

 Site Characterization (2008$) ........................................................................5-10 

Exhibit 5.4 Owner and Operator Cost Estimates for Geologic Site 

 Characterization – Annualized Values Using a 3% and 7% Discount 

 Rate ($Millions, 2008$).................................................................................5-11 

Exhibit 5.5 Owner and Operator Burden and Unit Cost Estimates for AoR and 

 Corrective Action (2008$) .............................................................................5-12 

Exhibit 5.6 Owner and Operator Cost Estimates for AoR and Corrective 

 Action – Annualized Values Using a 3% and 7% Discount Rate 

 ($Millions, 2008$) .........................................................................................5-13 

Exhibit 5.7 Owner and Operator Burden and Unit Cost Estimates for Injection 

 Well Construction (2008$) ............................................................................5-15 

Exhibit 5.8 Owner and Operator Cost Estimates for Injection Well Construction – 

 Annualized Values Using a 3% and 7% Discount Rate 

 ($Millions, 2008$) .........................................................................................5-16 

Exhibit 5.9 Owner and Operator Burden and Unit Cost Estimates for Well 

 Operation (2008$)..........................................................................................5-18 

Exhibit 5.10 Owner and Operator Cost Estimates for Well Operation – Annualized 

 Values Using a 3% and 7% Discount Rate ($Millions, 2008$).....................5-19 

Exhibit 5.11 Owner and Operator Burden and Unit Cost Estimates for Conducting 

 MIT (2008$) ................................................................................................5-20 

Exhibit 5.12 Owner and Operator Cost Estimates for MIT – Annualized Values 

 Using a 3% and 7% Discount Rate ($Millions, 2008$).................................5-21 

Exhibit 5.13 Owner and Operator Burden and Unit Cost Estimates for 

 Monitoring (2008$)........................................................................................5-23 

Exhibit 5.14 Owner and Operator Cost Estimates for Monitoring – Annualized 

 Values Using a 3% and 7% Discount Rate ($Millions, 2008$).....................5-26 

Exhibit 5.15 Owner and Operator Burden and Unit Cost Estimates for Well 

 Plugging and PISC (2008$) ...........................................................................5-27 

Exhibit 5.16 Owner and Operator Cost Estimates for Well Plugging and PISC – 

 Annualized Values Using a 3% and 7% Discount Rate 

 ($Millions, 2008$) .........................................................................................5-28 

Exhibit 5.17 Owner and Operator Burden and Unit Cost Estimates for Financial 

 Responsibility (2008$)...................................................................................5-29 

Exhibit 5.18 Owner and Operator Cost Estimates for Financial Responsibility – 

 Annualized Values Using a 3% and 7% Discount Rate (2008$)...................5-30 
Cost Analysis for the vi November 2010 

Final GS Rule

Exhibit 5.19 Permitting Authority Burden and Unit Cost Estimates (2008$)....................5-34 

Exhibit 5.20 Permitting Authority Cost Estimates – Annualized Values Using a 

 3% and 7% Discount Rate ($Millions, 2008$) ..............................................5-36 

Exhibit 5.21 Incremental Rule Costs for All Regulatory Alternatives Considered – 

 Annualized Values Using a 3% and 7% Discount Rate 

 ($Millions, 2008$) .........................................................................................5-38 

Exhibit 5.22 Incremental Rule Costs – Annualized Values Using a 3% and 7% 

 Discount Rate ($Millions, 2008$)..................................................................5-38 

Exhibit 5.23 Total and Incremental Rule Costs by Regulatory Alternative and Rule 

 Component – Annualized Values Using a 3% and 7% Discount Rate 

 ($Millions, 2008$) .........................................................................................5-39 

Exhibit 5.24a Total and Incremental Rule Costs by Cost Type, Assuming 5 Pilot 

 Saline Projects are Implemented During the Period of Analysis 

 ($Millions, 2008$) .........................................................................................5-44 

Exhibit 5.24b Total and Incremental Rule Costs by Cost Type, Assuming 54 Large 

 Saline Projects are Implemented During the Period of Analysis 

 ($Millions, 2008$) .........................................................................................5-45 

Exhibit 5.25 Total and Incremental Rule Costs Based on 50% Increased Labor 

 Rate - Annualized Values Using a 3% Discount Rate ($Millions, 2008$)....5-45 

Exhibit 5.26 Total and Incremental Rule Costs, Change in Cost from Primary 

 Analysis Resulting from 25% Increase/Decrease in Monitoring Wells – 

 Annualized Values Using a 3% Discount Rate ($Millions, 2008$) ..............5-46 

Exhibit 5.27 Annualized Rule Costs By Project Type Per Metric Tonne and 

 Per Project (2008$) ........................................................................................5-46 

Exhibit 6.1 Average Annual Net Change Burden and Costs for the GS ICR ....................6-3 
Cost Analysis for the vii November 2010 

Final GS Rule

List of Acronyms 

AAPG American Association of Petroleum Geologists 

AoR Area of Review 

API American Petroleum Institute 

ASTM American Society for Testing and Materials 

BLS Bureau of Labor Statistics 

CCS Carbon Capture and Storage 

CFR Code of Federal Regulations 

CIR Color Infrared Orthoimagery 

CO2 Carbon Dioxide 

CSLF Carbon Sequestration Leadership Forum 

DOE Department of Energy 

ECBM Enhanced Coal Bed Methane 

EO Executive Order 

EPA United States Environmental Protection Agency 

ER Enhanced Oil and Gas Recovery 

FR Federal Register 

G&A General and Administrative 

GIS Geographic Information System 

GS Geologic Sequestration 

Gt Gigatons 

GWPC Ground Water Protection Council 

ICR Information Collection Request 

IOGCC Interstate Oil & Gas Compact Commission 

IPCC Intergovernmental Panel on Climate Change 

IZ Injection Zone 

LBNL Lawrence Berkley National Laboratories 

LIDAR Light Detection and Ranging 

MI Mechanical Integrity 

MIT Mechanical Integrity Testing 

MMV Measurement, Monitoring, and Verification 

NAICS North American Industry Classification System 

NATCARB National Carbon 

NETL National Energy Technology Laboratory 

NGO Non-governmental Organization 

NODA Notice of Data Availability 

NTTAA National Technology Transfer and Advancement Act 

O&M Operation and Maintenance 

OAL Oxygen Activation Log 

OMB Office of Management and Budget 

OPM Office of Personnel Management 

PBMS Performance Based Measurement System 

PISC Post-injection Site Care 

PRA Paperwork Reduction Act 

PV Present Value 

RA Regulatory Alternative 
RCSP Regional Carbon Sequestration Partnership 

RFA Regulatory Flexibility Act 

SBA Small Business Association 

SBREFA Small Business Regulatory Enforcement Fairness Act 

SDWA Safe Drinking Water Act 

SOC Standard Occupational Classification 

SPE Society for Petroleum Engineers 

TDS Total Dissolved Solids 

UIC Underground Injection Control 

UMRA Unfunded Mandates Reform Act 

USDW Underground Source of Drinking Water 

 

Cost Analysis for the viii November 2010 

Final GS Rule
Cost Analysis for the 1-1 November 2010 

Final GS Rule 

 

 

1. Introduction 

This Cost Analysis evaluates the costs and potential benefits of the new Federal 

Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide 

(CO2) Geologic Sequestration (GS) Wells (the GS Rule). Executive Order (EO) 12866, 

Regulatory Planning and Review (58 FR 51735) requires the United States Environmental 

Protection Agency (EPA) to estimate the economic impact of rules that have an annual effect on 

the economy of over $100 million and make that analysis available to the public in conjunction 

with publication of the final rule. EPA has chosen to publish a comprehensive cost analysis and 

a relative risk analysis to accompany the GS rule even though the Agency has determined that 

the annual cost is below the $100 million threshold. These analyses consider both the relative 

costs of the regulatory alternatives and the reduction in risk relative to baseline provided by each 

alternative in selecting the final rule.1

 

The final GS rule establishes minimum Federal requirements under the Safe Drinking 

Water Act (SDWA) for injection of CO2 for the purposes of long-term storage (also known as 

GS). The final rule creates a new class of injection well, Class VI, and sets minimum technical 

criteria for the purposes of protecting underground sources of drinking water (USDWs). The 

elements of the GS Rule are based on the existing Underground Injection Control (UIC) 

regulatory framework with modifications to address the unique nature of GS in the anticipation 

of its eventual use to reduce CO2 emissions to the atmosphere. 

An outline of the organization of this Cost Analysis is provided below. The remainder of 

this chapter summarizes the technical, regulatory, and public health issues addressed by the final 

rule (Section 1.1) and provides an overview of the UIC Program regulatory framework on which 

the rule is based (Section 1.2). It also explains the statutory authority for the rule and the 

economic rationale for adopting a regulatory approach (Section 1.3).

The remainder of this cost analysis is organized into the following chapters: 

• Chapter 2 presents a review of the alternative regulatory approaches EPA considered 

during development of the GS rule and the rationale for selecting the minimum 

requirements that comprise the final rule. 

• Chapter 3 characterizes conditions that exist prior to promulgation of the GS rule. It 

includes a profile of hydrogeologic settings available for GS and potential CO2

storage capacity. It also provides projection estimates of the number and types of GS 

projects likely to be affected by the rule. 

1

EPA developed a relative risk analysis in place of a quantified assessment of risk because GS is a new technology 

and the results from research on the potential effects of GS on underground sources of drinking water (USDWs) are 

not yet available. 
Cost Analysis for the 1-2 November 2010 

Final GS Rule 

 

• Chapter 4 presents a discussion of the risk and benefit tradeoffs between compliance 

with existing UIC regulations and the four regulatory alternatives considered. A 

qualitative discussion of the potential economic benefits of the final rule is also 

presented. 

• Chapter 5 presents an estimate of the costs of implementing the final rule to owners 

and operators and primacy agencies. The costs of the other regulatory alternatives that 

were considered are compared. 

• Chapter 6 discusses the effects of the GS rule on different segments of the population 

and considers the executive orders and requirements applicable to this rulemaking, 

including the Regulatory Flexibility Act (RFA) and Unfunded Mandates Reform Act 

(UMRA). 

• Chapter 7 lists references cited in Chapters 1 - 6. 

This Cost Analysis presents results from detailed and complex analyses. To help the 

reader track the various calculations and analyses, the following are provided: 

• Appendices 

- Appendix A presents the characteristics that factor into costs for each pro forma 

(representative project type) case. 

- Appendix B presents a matrix that includes the algorithms that define unit costs 

for different regulatory components, and an application factor that describes the 

extent to which each cost applies under each regulatory alternative. 

- Appendix C presents detailed cost spreadsheets that are output from the cost 

model for each of the regulatory alternatives considered in this cost analysis. 

• Exhibits - Most tabular exhibits include a row that provides the formulas used to 

calculate the contents of each column. 

• Sources for information that is used, but not calculated within the exhibits. 

• Supporting electronic file output (i.e., GS rule cost model output). 

1.1 Technical, Public Health, and Regulatory Issues Addressed by the GS Rule 

The Agency has developed a final rule that has tailored the existing UIC regulatory 

framework to address the unique nature of CO2 injection for GS for the purposes of protecting 

USDWs. The rule contains tailored requirements for the following criteria: 

1. Site Characterization, 

2. Area of Review and Corrective Action, 
Cost Analysis for the 1-3 November 2010 

Final GS Rule 

 

 

3. Injection Well Construction, 

4. Injection Well Operation, 

5. Mechanical Integrity Testing, 

6. Monitoring, 

7. Injection Well Plugging, Post-injection Site Care (PISC) and Site Closure, 

8. Financial Responsibility, and 

9. Emergency and Remedial Response. 

1.1.1 Description of the Issue 

Geologic sequestration is the process of injecting CO2 captured from an emissions source 

(e.g., a power plant or industrial facility) into deep subsurface rock formations for long-term 

storage to reduce CO2 emissions to the atmosphere. To inject captured CO2, the CO2 is typically 

converted from a gaseous state to a supercritical state. The CO2 is then delivered from the source 

to the GS site where it is injected into deep subsurface rock formations (such as deep saline 

formations and oil and gas reservoirs) via an injection well. 

Many of the injection and monitoring technologies that may be applicable to GS are 

commercially available today and are being used by the oil and gas industry for enhancing oil 

and gas production. However, these technologies have yet to be widely demonstrated at the 

larger scale needed for GS. It is expected that GS projects will inject large volumes of CO2. CO2

in the subsurface is buoyant and is highly mobile. While CO2 itself is not a drinking water 

contaminant, CO2 in the presence of water forms a weak acid and can cause leaching and 

mobilization of naturally-occurring metals and/or other contaminants from geologic formations 

into groundwater if injection wells are not properly sited, operated and monitored. The GS Rule 

provides minimum requirements to protect USDWs from endangerment as this climate 

mitigation technology is developed and deployed. 

Experimental field research on GS in the U.S. is being led by the Department of Energy 

(DOE) under the Regional Carbon Sequestration Partnerships (RSCPs) program. In recent years, 

several experimental pilot or demonstration projects for GS have come into operation or have 

completed injection. Before promulgation of this rule, these projects were permitted under the 

existing UIC Program regulations as either Class V experimental technology wells2

, Class I 

industrial non-hazardous waste injection wells (the baseline scenario for this cost analysis), or 

Class II injection wells (where the CO2 injection is associated with oil or gas recovery). 

Following promulgation of the GS Rule, projects whose primary purpose is to inject CO2 for 

long-term storage will be permitted as Class VI. 

2

 This classification is appropriate for experimental GS projects, and is addressed in EPA’s March 2007 UIC 

Program Guidance # 83: Using the Class V Experimental Technology Well Classification for Pilot Carbon 

Geologic Sequestration Projects. 
Cost Analysis for the 1-4 November 2010 

Final GS Rule 

 

 

For the purpose of developing the baseline estimate of projects to deploy as required for 

the cost analysis, EPA considered the current legislative environment only, as recommended in 

EPA’s Guidelines for Preparing Economic Analysis (USEPA, 2000). EPA acknowledges that if 

legislation is passed that limits CO2 emissions to the atmosphere in the future, it will create an 

economic incentive for more projects to deploy. Although GS is occurring now on a relatively 

small scale, it could play a larger role in mitigating CO2 emissions from a variety of stationary 

sources. For example, 95 percent of the 500 largest stationary sources are located within 50 

miles of a candidate GS reservoir (Dooley et al., 2006). 

While predictions about large-scale availability and the rate of GS deployment are subject 

to considerable uncertainty, EPA analysis of Congressional climate change legislative proposals 

indicate that GS has the potential to play a significant role in climate change mitigation 

scenarios. EPA’s summary of this analysis is provided in the preamble cost section (Section IV) 

of the final rule. In addition, because of this uncertainty in the actual number of projects 

expected to deploy over the period of this analysis (2011-2060), EPA conducted sensitivity 

analyses reflecting projections under certain current legislation or policy positions. Chapter 5 of 

this Cost Analysis presents a sensitivity analysis that considers costs for 5 and 54 projects as the 

lower and upper bound number of projects deployed. These analyses are comparable to analyses 

performed to support the Regulatory Impact Analysis for Mandatory Reporting of Greenhouse 

Gases: Injection and Geologic Sequestration of CO2 Rule (Subpart RR) 3

. 

1.1.2 Public Health Concern to Be Addressed 

The injection of CO2, if not properly managed, could endanger USDWs because the large 

injection volumes expected, the relative buoyancy of CO2 and its potential mobility within 

subsurface geologic formations, combined with the corrosive nature of CO2 in the presence of 

water, could mobilize contaminants from the surrounding formations and decrease pH of the 

groundwater. In addition, large injection volumes could push saline ground water into fresh 

water sources. 

Such changes to ground water quality could compromise drinking water quality, 

requiring treatment to make the water potable, and in some cases resulting in the inability to 

produce potable water (e.g., where the cost of treatment is prohibitive). The GS rule will protect 

USDWs by requiring that appropriate measures related to proper siting, injection well 

construction and operation, monitoring and testing, plugging, PISC, and site closure that mitigate 

the risks to USDWs be implemented for all GS wells. 

3 Simultaneous development of the Mandatory Reporting of Greenhouse Gases: Injection and Geologic 

Sequestration of CO2 Rule (Subpart RR) and the GS Rule was coordinated by EPA. As a part of the coordinated rule 

making efforts, EPA developed these sensitivity analyses to ensure consistency of requirements and costs between 

the two rules.
Cost Analysis for the 1-5 November 2010 

Final GS Rule 

 

 

1.1.3 Statutory Authority for Promulgating the Rule 

The GS rule is focused on USDW protection under the authority of Part C of SDWA 

(SDWA § 1421 et seq., 42 U.S.C. 300h et seq.) and applies to injection wells in the U.S., 

including those in State territorial waters. 

SDWA is designed to protect the quality of drinking water sources in the U.S. and 

prescribes that EPA issue regulations for State4 UIC Programs that contain “minimum 

requirements for effective programs to prevent underground injection which endangers drinking 

water sources.” Congress further defined endangerment as follows: 

Underground injection endangers drinking water sources if such injection may result in 

the presence in underground water which supplies or can reasonably be expected to 

supply any public water system of any contaminant, and if the presence of such 

contaminant may result in such system’s not complying with any national primary 

drinking water regulation or may otherwise adversely affect the health of persons 

(SDWA §1421(d)(2)). 

Under this authority, the Agency has promulgated a series of UIC regulations at 40 CFR 

Parts 144 through 148 for Federally approved UIC programs. The chief goal of any Federally 

approved UIC Program (whether administered by a State, Territory, Tribe or EPA) is the 

protection of USDWs. This includes not only those formations that are presently being used for 

drinking water, but also those that can reasonably be expected to be used in the future. EPA has 

established through its UIC regulations that USDWs are underground aquifers with less than 

10,000 milligrams per liter (mg/L) total dissolved solids (TDS) and which contain a sufficient 

quantity of ground water to supply a public water system (40 CFR 144.3). Section 1421(b) 

(3)(A) of the SDWA also provides that EPA’s UIC regulations shall “permit or provide for 

consideration of varying geologic, hydrological, or historical conditions in different States and in 

different areas within a State.”5

 

Under the SDWA, the injection of any “fluid” is subject to the requirements of the UIC 

Program. A “fluid” is defined under §144.3 as any material or substance that flows or moves 

whether in a semisolid, liquid, sludge, gas or other form or state, and includes the injection of 

liquids, gases, and semisolids (i.e., slurries) into the subsurface. Examples of the fluids currently 

injected into wells subject to UIC requirements include: CO2 for the purposes of enhancing 

recovery of oil and natural gas, water that is stored to meet water supply demands in dry seasons, 

and wastes generated by industrial users. CO2 injected for the purpose of GS is subject to the 

SDWA. 

4

 Reference to “States” includes Tribes and Territories. 

5

 The Federal codes under which EPA promulgated these administrative and permitting regulations and associated 

dates of passage are described in the Preamble for the GS rule. 
Cost Analysis for the 1-6 November 2010 

Final GS Rule 

 

 

1.2 Regulatory History 

When EPA initially promulgated its UIC Program regulations, it defined five classes of 

injection wells based on similarities in the fluids injected, construction, injection depth, design, 

and operating techniques. This categorization ensures that wells with common design and 

operating techniques are required to meet appropriate performance criteria and is described in the 

following paragraph. 

Class I wells, which inject hazardous wastes, industrial non-hazardous liquids, or 

municipal wastewaters beneath the lowermost USDW, are technically sophisticated and subject 

to stringent construction and operation standards. Class II wells inject fluids (including CO2) 

associated with oil and gas production. Class III wells inject fluids associated with solution 

mining of minerals. Class IV wells inject hazardous or radioactive wastes into or above 

USDWs.6

 Class V includes all injection wells that are not included in Classes I-IV. In general, 

Class V wells inject non-hazardous fluids into or above USDWs; however, there are some deep 

Class V wells that inject below USDWs. Class V wells include GS experimental technology 

wells used for GS pilot projects. 

Currently, almost all existing CO2 injection in the U.S. involves Class II wells (for oil and 

gas production purposes) and Class V experimental technology wells, with a very limited amount 

involving Class I wells: 

• For the past several decades CO2 has been injected via Class II wells for enhanced oil 

and gas recovery (ER). In ER operations, CO2 is injected to make the residual oil in a 

reservoir more mobile and facilitate recovery. Class II well operators and permitting 

authorities have decades of expertise with injection, including injection of CO2 for the 

purposes of oil and gas production, with oil and gas reservoir dynamics, and with 

injection well construction. Although the majority of CO2 is likely to be injected into 

saline formations over the long term, it is anticipated that, given the experience and 

the availability of background data and infrastructure related to Class II injection, 

many Class II projects will want to transition to long-term storage projects in oil and 

gas reservoirs early in the deployment phase. 

• Over the past decade, pilot-scale projects began injecting small volumes of CO2 to 

test GS technologies and inform EPA’s final decision on how to regulate GS 

activities. To allow permitting of pilot-scale GS projects in advance of a GS 

rulemaking, EPA issued guidance to assist State and EPA regional UIC Programs in 

processing permit applications for pilot and other small-scale experimental GS 

projects. In the UIC Program Guidance # 83: Using the Class V Experimental 

Technology Well Classification for Pilot Carbon Geologic Sequestration Projects 

(USEPA, 2007), EPA recommends that pilot GS projects be permitted as Class V 

experimental technology wells. The guidance applies to pilot CO2 injection projects 

of an experimental nature that are designed to assess the efficacy of CO2 injection for 

the purposes of long-term GS. 

6

 Class IV wells are currently banned unless authorized under an approved Federal or State ground water 

remediation project. 
Cost Analysis for the 1-7 November 2010 

Final GS Rule 

 

The final rule defines a new class of injection well (Class VI) that is specifically tailored 

to injection of CO2 into deep subsurface formations for long-term storage. 

1.3 Economic Rationale 

This section addresses the economic rationale for choosing a regulatory approach to 

govern GS and thus protect public drinking water supplies (i.e., by protecting USDWs) rather 

than nonregulatory alternatives. Although the final rule is not subject to the requirement 

(including provision of an economic rationale) of EO 12866, Regulatory Planning and Review

(58 FR 51735) for an economic rationale for the rule because it is not economically significant, 

EPA is providing the rationale below. 

EO 12866 states the following: 

[E]ach agency shall identify the problem that it intends to address (including, 

where applicable, the failures of the private markets or public institutions that 

warrant new agency action) as well as assess the significance of that problem. 

(Section 1, b(1)) 

In addition, Office of Management and Budget (OMB) Circular A-4, dated September 

17, 2003, states that “...[the analyst] should try to explain whether the action is intended to 

address a significant market failure or to meet some other compelling public need such as 

improving governmental processes or promoting intangible values such as distributional fairness 

or privacy.” (OMB, 2003). 

In the case of large-scale GS, two major types of market failures are present—the 

presence of externalities (related to the nature of the affected resources facing complex property 

rights issues and being generally regarded as public goods); and information asymmetry between 

GS injection well operators and potentially affected public water systems and private well users. 

These market failures work separately and together to distort the workings of a free market. 

Furthermore, the promulgation of a regulation that limits CO2 emissions during the period of this 

analysis would exacerbate these market failures based on the expected increase in GS projects 

and amplification of the issues described below. 

The presence of externalities is the first market failure, resulting from the nature of the 

affected resources. In this case, there are two resources that will be potentially affected by 

injection of CO2 under the final rule—the aquifers that serve as USDWs and the underground 

formations that can sequester CO2. Under the SDWA, EPA protects USDWs for public use and 

establishes a regulatory structure (the UIC Program) to prevent potential contamination that 

supersedes property rights/ownership issues. Because the UIC Program focuses specifically on 

protection of USDWs, there exists less regulatory history in defining ownership/property rights 

for underground formations not containing viable drinking water resources. Because of the 

complexity in defining property rights for non-USDW underground formations, for the purpose 

of this analysis non-USDWs are treated consistently with the treatment of USDWs, i.e., they are 

regarded as public goods. As public goods, the potential side effects from the operation of GS 

wells (i.e., contamination of USDWs or other underground formations due to improper siting, 

construction, operation, or closure) would likely be uncompensated by those responsible for such 
Cost Analysis for the 1-8 November 2010 

Final GS Rule 

 

contamination in absence of the UIC Program regulations. The costs of the final GS Rule as 

presented in this analysis represent the costs for the additional protection of USDWs provided by 

the Class VI regulation, which tailors protective measures to the risks posed by GS projects. 

The second market failure results from an asymmetry in information held by GS well 

owners and operators versus potentially affected public water system and private well users. 

There are an estimated 105,249 smaller public water systems in the United States out of a total of 

153,530 public water systems (USEPA, 2005a). This estimate includes Transient and NonTransient Non Community Water Systems and Community Water Systems serving fewer than 

1,001 customers. Additionally, many families in rural communities operate private wells. All of 

these systems and individuals would be at a disadvantage in trying to maintain a quality water 

supply if they were not informed of the potential risks that a GS project in their community 

might pose to their current or future potential water supplies. However, GS by nature is complex. 

The potential risk for water quality changes may be difficult to convey in a meaningful way to 

the large number of people that could be affected, i.e., those who are current and potential future 

consumers of the water from the aquifers under consideration, and the large associated 

transaction costs in educating a large number of people in a complex, nuanced discussion of GS. 

The SDWA provides a level of protection from exposure to drinking water contaminants 

for which consumers may not be in a position to advocate for themselves. SDWA regulations are 

not intended to restructure market mechanisms or to establish competition in supply; rather, they 

establish minimum performance requirements and the level of service to be provided that best 

reflect public preferences for protectiveness. The Federal regulations reduce the high information 

and transaction costs by acting on behalf of consumers in balancing risk reduction and the social 

costs of achieving this risk reduction. 

Two of the major types of market failures are present in the implementation of GS 

operations and are interrelated. USDWs and other injection formations are generally considered 

public goods which subject them to potential adverse externalities without a non-market 

intervention. Further, the complex nature of GS and the potential resulting water quality issues 

may be difficult to convey in a meaningful way to the potentially affected water systems with an 

amount of effort that is reasonable for both sides. These market failures distort the workings of a 

free market and are the basis for governmental intervention. Congress acknowledged these 

market conditions when it established a Federal regulatory approach to protecting USDWs under 

SDWA. 
2. Consideration of Regulatory Alternatives 

2.1 Introduction 

The United States Environmental Protection Agency (EPA) is finalizing minimum Federal 

Requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon dioxide 

(CO2) for the purposes of Geologic Sequestration (GS Rule). The GS Rule was developed to ensure 

consistency in permitting underground injection of CO2 at geologic sequestration (GS) operations across 

the U.S. and provide requirements to prevent endangerment of underground sources of drinking water 

(USDWs) in anticipation of the eventual use of GS to reduce CO2 emissions to the atmosphere. This 

cost analysis has been informed by Federal and non-Federal entities to determine how best to tailor 

existing underground injection requirements for CO2 for GS (described in Section 2.2). Four regulatory 

alternatives (RAs) (see Section 2.3) were developed for managing the risks to USDWs associated with 

GS. Benefits and costs are estimated for each of the regulatory alternatives in this Cost Analysis. EPA 

selected an alternative (RA3) as the final GS Rule, which is described in Section 2.4 of this chapter. 

2.2 Process for Development of Regulatory Alternatives 

The GS Rule builds upon longstanding programmatic requirements that have been in place since 

the 1980s and are used to manage over 800,000 injection wells nationwide. EPA has taken a number of 

steps to inform the GS rule including: conducting research; conducting stakeholder coordination and 

outreach (including technical workshops); issuing a proposed rulemaking and soliciting and reviewing 

public comment; and publishing a Notice of Data Availability (NODA) for comment to seek additional 

input on the rulemaking. 

The following workshops were held to identify technical, administrative, and regulatory issues 

associated with pilot and large-scale GS projects: 

• Measurement, Monitoring, and Verification (MMV) Workshop. On January 16, 2008 EPA held a 

technical workshop on MMV in New Orleans, LA. The workshop included presentations by 

industry, academic, and government researchers on their experience with and use of subsurface and 

near-surface monitoring techniques. The presentations were followed by “round table” breakout 

discussions where participants discussed the availability and utility of various monitoring techniques 

that may be applicable to GS projects. 

• Geologic Setting and Area of Review Considerations Workshop. EPA held a technical workshop in 

Washington, D.C. on July 10 and 11, 2007 to discuss geologic considerations and Area of Review 

(AoR) issues related to GS. The workshop consisted of three presentation sessions, during which 

industry and government experts described current research on: subsurface geologic information 

needed to determine whether a site is appropriate for GS, the role of artificial conduits in the AoR on 

siting decisions, factors that affect the size and shape of the AoR, and corrective actions to address 

wells in the AoR. To conclude the workshop, a panel of experts representing the Regional 

Partnerships and Interstate Oil & Gas Compact Commission (IOGCC) presented their experiences 

with pilot and experimental GS projects. 

Cost Analysis for the 2-1 November 2010 

Final GS Rule 
• Well Construction and Mechanical Integrity Testing Workshop (MIT). EPA held a technical 

workshop in Albuquerque, New Mexico on March 14, 2007 to address well construction and MIT 

issues related to GS. The workshop format included technical presentations on current research by 

industry, academia, and government agencies on experimental research in the U.S. and Canada into 

wellbore integrity and CO2-cement interactions, modeling, the impact of wellbore integrity on GS 

site selection, and industry research on well construction. 

• State Regulators’ Workshop on Geologic Sequestration of CO2. At the Ground Water Protection 

Council’s (GWPC) UIC Technical meeting in San Antonio, Texas on January 24, 2007, EPA and 

DOE collaborated on a workshop to discuss and formulate the questions related to CO2 injection that 

EPA would need to answer in its rulemaking process. In sessions led by the National Energy 

Technology Laboratory (NETL), experts presented the status of Department of Energy (DOE) 

research projects on AoR studies, injection well management, and MMV. 

• International Symposium on Site Characterization for CO2 Geologic Storage. Participants at this 

symposium, held in Berkeley, CA on March 20-22, 2006, discussed various aspects of 

characterization and selection of potential CO2 storage sites. The symposium emphasized advances 

in process understanding, development of measurement methods, identification of key site features 

and parameters, site characterization strategies, and case studies. The presentations and discussions 

addressed: site characterization methods; regional-scale site selection; site characterization case 

studies; leakage from storage formations, including pathways, effects, and implications for site 

characterization; fundamental processes and technical issues related to site characterization; 

screening and characterization tools; and regulatory and social issues. 

• Risk Assessment for Geologic CO2 Storage Workshop. Following the GWPC fall meeting in 

Portland, Oregon, State and EPA experts on GS, ground water and underground injection, and health 

and environmental effects of CO2 met on September 28-29, 2005. They discussed the development 

of a risk assessment framework to identify potential risks and to consider relevant field experience 

that could be applicable to injection and long-term storage of CO2. Some of the key topics addressed 

at the workshop were abandoned wells, faults, and ground water displacement. Participants 

discussed key issues in conducting a risk assessment of geologic carbon storage. 

• Modeling and Reservoir Simulation for Geologic Carbon Storage Workshop. On April 6-7, 2005, 

EPA held a workshop for 60 EPA headquarters and regional staff in Houston, Texas to assess the 

potential application of reservoir models and reservoir simulation to GS and to provide EPA with 

information about the ‘state of the art’ in the development and application of modeling approaches 

and numerical simulators for geologic CO2 storage. They also discussed the role of models and 

reservoir simulation in supporting risk assessment and risk communication for GS sites. The 

workshop informed EPA about ways that geologic models and reservoir simulation might be applied 

during key stages in the life cycle of a CO2 storage reservoir, from site selection and characterization 

through injection operations and post-injection verification of CO2 containment. 

Throughout the rulemaking process, the Agency conducted public workshops and public hearings, consultations with specific groups, and EPA representatives attended meetings to explain the GS rulemaking effort to interested public and stakeholder groups. 

Cost Analysis for the 2-2 November 2010 

Final GS Rule 
EPA held public meetings to discuss EPA’s rulemaking approach, and consulted with other 

stakeholder groups including non-governmental organizations (NGOs) to gain a better understanding of 

stakeholder interests and concerns. As part of this outreach, EPA conducted two stakeholder workshops 

with participants from industry, environmental groups, utilities, academia, States, and the general public. 

These workshops, held in December 2007 and February 2008. EPA also specifically targeted outreach 

and consultation efforts to engage States and Tribes. 

EPA has also been monitoring ongoing GS research and work by academia, the 

Intergovernmental Panel on Climate Change (IPCC), and World Resources Institute’s Carbon Capture 

and Storage (CCS) working group. 

Agency Activities Conducted for Proposed Rulemaking 

On July 25, 2008, EPA published the proposed “Federal Requirements Under the Underground 

Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells” (73 FR 

43492). The Agency proposed a new class of injection well (Class VI), along with technical criteria for 

permitting GS wells that tailored the existing UIC regulatory framework to address the unique nature of 

CO2 injection for GS. 

During the public comment period, the Agency held public hearings on the proposed rule in 

Chicago, IL on September 30, 2008 and in Denver, CO on October 2, 2008. The two hearings 

collectively drew approximately 100 people representing non-governmental organizations, academia, 

industry, and other organizations. At the hearings, 29 people submitted oral comments. Transcripts of 

the public hearings are in the rulemaking docket (Docket ID Nos. EPA-HQ-OW-2008-0390-0185 and 

EPA-HQ-OW-2008-0390-0256). 

Based on public comments received on the proposed rule, the Agency identified several topics 

upon which it needed additional public comment. On August 31, 2009, EPA published supplemental 

information related to geologic sequestration in a NODA (74 FR 44802). The NODA presented new 

data and information from the DOE’s NETL, including preliminary field data from the DOE-sponsored 

Regional Carbon Sequestration Partnership (RCSP) projects. The Notice presented the results of GSrelated studies conducted by the Lawrence Berkeley National Laboratory (LBNL) concerning both GS 

projects and modeling to predict the potential impacts on ground water from GS activities (discussed in 

section II.C.2 of today’s publication). The NODA also presented an alternative to address public 

comments and concerns about the proposed injection depth requirements for Class VI wells. 

Following publication of the NODA and Request for Comment, EPA initiated a 45-day public 

comment period, which closed on October 15, 2009. EPA received 67 unique submittals from 64 

commenters, many of whom commented on the proposed rule. The Agency also held a public hearing in 

Chicago, IL on September 17, 2009. Six people, representing the oil and gas industry, electric utilities, 

water associations, and academia attended the hearing. Two attendees submitted oral comments at the 

hearing. A transcript of the public hearing is in the rulemaking docket (EPA-HQ-OW-2008-0390-391). 

Cost Analysis for the 2-3 November 2010 

Final GS Rule 
2.3 Regulatory Alternatives Considered 

EPA developed four RAs that address the unique technical and administrative considerations 

posed by the GS of CO2. These four RAs are described in subsequent sections and in Exhibit 2.1. 

2.3.1 Regulatory Alternative 1 

Under this first alternative, GS wells would need to be sited, constructed, operated, maintained, 

monitored, and closed in a manner that protects USDWs. RA1 would apply the performance standard 

under 40 Code of Federal Regulations (CFR) 144.12(a) that prohibits fluid movement that endangers 

USDWs. For the purpose of this analysis, EPA assumed that operators would construct wells to inject 

below the lowermost USDW. 

No specific “technology” standards would accompany the performance standard and each 

permitting authority would be left to interpret what technical standards or best management practices 

would be included in GS well permits based on the geology of the proposed site and the proposed 

injection activity. Permitting authorities are encouraged to issue permits for GS wells so that owners and 

operators would be subject to enforceable standards. 

This alternative would offer flexibility to each permitting authority to interpret what would need 

to be included in GS well permits. While some stakeholders advocated a flexible approach for certain 

elements of a GS regulation, none advocated complete flexibility in the GS rule. If this alternative were 

adopted, EPA would need to develop numerous technical guidances to assist permitting authorities and 

to help injection well owners and operators understand and interpret the performance standards. 

2.3.2 Regulatory Alternative 2 

This RA is similar to the “basic” UIC Program regulatory standards for injection associated with 

oil and gas recovery, modified to address the potential impacts to USDWs from the injection of large 

volumes of potentially corrosive CO2. The GS-specific components of this RA include the use of 

corrosion-resistant construction materials and surface atmospheric or soil gas monitoring. This RA also 

gives permitting authorities flexibility to interpret certain elements in their permit requirements. For the 

purpose of this analysis, EPA assumed that operators would construct wells to inject below the 

lowermost USDW. 

Geologic Site Characterization: Under this RA, GS wells would need to be sited in an area with 

geological layers that are adequate for receiving proposed volumes of injected CO2, confining it below 

USDWs, and providing long-term storage with no movement of any fluids that endangers a USDW. An 

adequate site would consist of: an injection zone of sufficient areal extent, thickness, porosity, and 

permeability; a containment mechanism that is free of major non-sealing faults; and a primary confining 

system of sufficient areal extent and integrity to allow injection at the proposed rates and volumes 

without initiating or propagating fractures. Similar configurations are typical of oil and gas wells which 

are typically located in areas where the natural geology confines oil and/or natural gas in permeable 

formations below a confining system. 

Cost Analysis for the 2-4 November 2010 

Final GS Rule 
Under this RA, owners or operators of a proposed GS injection well would demonstrate the 

presence and adequacy of the injection zone and confining system by providing geological data, 

including geological names and lithologic descriptions of the formations, and information on their 

thickness and depth. Owners or operators would also provide a map of the injection well and the 

applicable AoR and other information, such as maps, cross-sections, and a list of penetrations into the 

injection zone. Under this RA, owners or operators would also provide the geologic name and thickness 

of all USDWs that may be affected by the injection. 

AoR and Corrective Action: Under this RA, owners and operators would define the AoR for the 

GS project based on a calculated radius or by modeling. The use of models is encouraged, but would not 

be required. Within the defined AoR, owners or operators would locate and identify all artificial 

penetrations (including active and abandoned wells and mines) that penetrate the confining system; 

provide a description of each well’s type, construction, date drilled, location, and depth; determine, 

based on publicly available data, whether the abandoned wells have been plugged in a manner that 

prevents the movement of CO2 or associated fluids; and employ corrective action at all wells that may 

endanger USDWs using appropriate methods approved by the Director.

Injection Well Construction: Under this RA, GS wells would be cased and cemented to prevent 

movement of fluids into or between USDWs. This mirrors the current Class II requirements; however 

this RA includes additional components to address the unique nature of CO2 injected for GS. For 

example, RA2 would require that the casing and tubing for GS wells be adequate to withstand the 

corrosive nature of the injected CO2 and any impurities at the anticipated operational conditions, and 

meet American Petroleum Institute (API) standards for casing, tubing, and packer. GS wells would also 

be constructed using corrosion-resistant cement in zones where contact between the cement and CO2 is 

likely or where cement integrity is critical (e.g., through the primary confining system). Owners or 

operators would need to verify the integrity and location of the cement using the best available 

technologies for evaluating cement quality, identifying the location of channels or contaminated cement, 

and validating the casing-cement and cement-formation bonds through the primary confining system. 

Owners and operators will also be required to inject below the lowermost USDW, except in the limited 

number of cases where operators apply for and receive a permit for a waiver of this requirement. Waiver 

applications will demonstrate that USDWs above and below the injection zone will not be endangered as 

a result of CO2 injection and will evaluate the following components: the integrity of the upper and 

lower confining units; the suitability of the injection zone; the potential capacity of the geologic 

formation to sequester CO2; community needs, demands, and supply from drinking water sources; and 

any other applicable considerations or information requested by the director. 

Injection Well Operation: Under this RA, CO2 injection for GS should be conducted such that 

the pressure during injection does not initiate new fractures or propagate existing fractures in the 

confining zone adjacent to the USDWs. Higher operating pressures may be allowed if approved by the 

permitting authority. 

MIT: Under this RA, owners and operators of GS wells would demonstrate that their wells have 

internal MI (i.e., that there is no significant leak in the casing, tubing or packer) and external MI, (i.e., 

there is no significant fluid movement into a USDW through vertical channels adjacent to the injection 

well bore). 

Cost Analysis for the 2-5 November 2010 

Final GS Rule 
Under this RA, owners and operators of GS wells would demonstrate internal MI by 

continuously monitoring injection pressure, flow rate, injected volumes, and pressure on the annulus 

between the tubing and the long-string casing. This RA does not stipulate specific testing methods for 

external MITs; rather, flexibility is provided to owners and operators and permitting authorities to 

propose and approve methods that are appropriate to the specific project. A variety of testing methods 

are available and a flexible approach would allow owners and operators to adopt new testing 

technologies that are appropriate to CO2 injection if they become available. Under this RA, MITs would 

be conducted at a frequency determined by the permitting authority. 

Monitoring: Under this RA, GS well owners and operators would monitor the nature of injected 

fluids at a frequency sufficient to yield data representative of their characteristics, as determined by the 

permitting authority. Owners and operators would report annually on the characteristics of injection 

fluids, injection pressure, flow rate, temperature, volume and annular pressure, and on the results of 

MITs. 

Injection Well Plugging and Post-Injection Site Care (PISC): When injection through a well is 

concluded, the injection well would be plugged in a way that ensures that it would not serve as a conduit 

for future fluid movement. Under this RA, owners and operators of GS wells would take appropriate 

actions, as approved by the permitting authority, to plug the injection well. Plugging activities may 

include ensuring that the well is in a state of static equilibrium with mud or equalized prior to placement 

of the plugs; plugging the well with cement in a manner that will not allow the movement of fluids 

either into or between USDWs; placing cement plugs; and tagging and testing each plug used for seal 

and stability. RA2 would also require owners and operators of GS wells to submit to the permitting 

authority a plan for conducting post-injection monitoring for ten years after injection wells are plugged 

to confirm that any post-injection CO2 movement is limited to intended zones (it does not specify the 

methods by which accurate monitoring data may be collected, however). Once approved, owners and 

operators would then be required to implement the approved plan. 

Financial Responsibility: Under this RA, owners and operators would demonstrate the resources 

necessary to plug the injection well. 

2.3.3 Regulatory Alternative 3 

For reasons discussed in Chapters 4 and 5 of this Cost Analysis, RA 3 has been selected as the 

final rule. 

Many of the geologic data elements under this RA are similar to those required under the Class I 

non-hazardous regulations. This RA contains technical standards that mirror the stringent deep-well 

requirements for disposal of non-hazardous industrial wastes, with some additional requirements to 

account for the unique nature of CO2 injection for GS. It is more stringent and prescriptive than RA2. 

The paragraphs below describe the specific elements of this alternative, highlighting the differences 

between RA2 and RA3. 

Site Characterization: Under this RA, in addition to an adequate injection zone, containment 

mechanism, and primary confining system, an owner or operator of a proposed GS site may be required, 

at the Director’s discretion, to characterize additional zones that could impede vertical fluid movement, 

Cost Analysis for the 2-6 November 2010 

Final GS Rule 
allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation, and 

remediation. 

This RA is more prescriptive than RA2 regarding the types and level of detail of the geological 

information that owners and operators would submit. The owner or operator of a proposed GS project 

site demonstrate the presence and adequacy of the injection and confining zones by providing 

information on the geologic structure, overburden and subsurface structures, and geochemical 

information about native and injected fluids. 

To evaluate the potential for adverse effects associated with CO2 injection, owners and operators 

also provide information on fractures in the confining zone and, if directed, any additional zones. Under 

RA3, owners and operators also eliminate sites with potential seismic risks. Additionally, under RA3, 

owners and operators characterize the overburden and subsurface structures, and provide data on 

subsurface porosity and permeability and geomechanical information, e.g., on fractures, stress, rock 

strength, and formation fluids. 

Operators and operators also submit data on geochemistry within the injection zone and above 

the confining zone, including USDWs; this serves as baseline data to which results of future monitoring 

would be compared throughout the injection phase. Geochemical data could also serve as inputs for 

modeling to predict CO2 movement. 

AoR and Corrective Action: Under this RA, owners and operators of GS wells determine, in 

three dimensions, the extent of the AoR based on computational modeling that accounts for the physical 

and chemical properties of all phases of the injected CO2 stream, CO2 plume, and the associated pressure 

front. The models will be based on data collected at the site as part of the site characterization as well as 

anticipated operating data. Additionally, owners and operators identify all artificial penetrations 

(including active and abandoned wells and mines) in the AoR, determine based on publically available 

data which of these pose a risk to USDWs and therefore need corrective action, and apply corrective 

action using materials compatible with the carbon dioxide stream and other appropriate methods. At the 

Director’s discretion, owners and operators have the option to phase-in corrective action and focus on 

those wells in the portion of the AoR that would be intersected by the CO2 plume or pressure front over 

the early years of the injection operation. 

This RA also requires all owners and operators to develop and submit an AoR and corrective 

action plan as a part of the permit application. The plan will describe how the owner or operator would 

determine the initial AoR, what corrective action will be performed up front and what will be phased in, 

and a plan for periodic reevaluation of the AoR (at least every 5 years) to incorporate monitoring and 

operational data to verify that the CO2 is moving as predicted within the subsurface. The requirement to 

maintain and implement an approved plan is directly enforceable regardless of whether the requirement 

is a condition of the permit. 

Injection Well Construction: This RA prescribes that the well’s surface casing be set through the 

base of the lowermost USDW (unless a waiver is granted to inject above the USDW) and be cemented 

to the surface. Under this RA, owners and operators will also be required to inject below the lowermost 

USDW, except in the limited number of cases where operators apply for and receive a permit for a 

waiver of this requirement. Waiver applications will demonstrate that USDWs above and below the 

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Final GS Rule 
injection zone will not be endangered as a result of CO2 injection and will evaluate the following 

components: the integrity of the upper and lower confining units; the suitability of the injection zone; the 

potential capacity of the geologic formation to sequester CO2; community needs, demands, and supply 

from drinking water sources; and any other applicable considerations or information requested by the 

director. 

Under RA3, the long string casing and cement would extend to the injection zone and be 

cemented to the surface. A packer will be required and be set opposite a cemented interval of the long 

string casing, at a depth approved by the Director. As with RA2, the well will be constructed with 

materials that meet or exceed standards developed by API or American Society for Testing and 

Materials (ASTM) International and can withstand the corrosive nature of the injected CO2 and any 

impurities throughout the life of the project. Cements would be required to be compatible with the CO2,

and the adequacy of the cement would be verified using the best available technologies. During drilling 

and construction, the owner or operator run logs, surveys, and tests to determine or verify the properties 

of subsurface formations to assure conformance with the construction requirements. 

Injection Well Operation: Under this RA, the CO2 injection pressure will not be permitted to 

exceed 90 percent of the fracture pressure of the injection zone, and injection would not be allowed to 

initiate new fractures, propagate existing fractures, or cause fluid movement into USDWs. 

The owner or operator will be required to equip the well with alarms and automatic surface shutoff systems or, at the discretion of the Director, down-hole shut-off systems (e.g., automatic shut-off 

check valves) for onshore wells or, other mechanical devices that provide equivalent protection; and 

alarms and automatic down-hole shut-off systems for wells located offshore but within State territorial 

waters, designed to alert the operator and shut-in the well when operating parameters such as annulus 

pressure, injection rate, or other parameters diverge beyond permitted ranges and/or gradients specified 

in the permit. UIC Permits for Class VI wells will be issued for the operating life of the facility and the 

PISC period. The Director will review each issued Class VI well UIC permit at least once every 5 years 

to determine whether it should be modified, revoked and reissued, terminated or modified. 

MIT: As with RA2, owners and operators of GS wells will need to demonstrate that their wells 

have internal and external MI. It differs from RA2 in that it specifies the tests that may be used to 

demonstrate external MI, e.g., a tracer survey, temperature or noise logs, a casing inspection log, or 

another suitable method required and/or approved by the Director. Additionally, under this RA, MITs 

will be conducted at least once every year. 

Monitoring: Like RA2, this RA requires owners and operators to monitor their injectate. 

However, this RA also requires owners and operators to continuously monitor injection pressure, rates, 

and volumes, as well as the pressure on the annulus. Owners and operators also monitor the well 

materials for signs of corrosion. Operators would submit semi-annual operating reports, and would 

submit MIT and other test results within 24 hours if they indicate a problem with operations. 

Under this RA3, owners and operators of GS wells develop and implement a plan to perform 

testing and monitoring to protect USDWs by tracking the position of the CO2 plume and pressure front; 

monitoring for geochemical changes in subsurface formations; and if directed, monitoring at the surface 

for evidence that CO2 may have leaked to USDWs. 

Cost Analysis for the 2-8 November 2010 

Final GS Rule 
Owners and operators conduct a pressure fall-off test at least once every five years. The owner or 

operator also track the subsurface extent of the CO2 plume and pressure front by monitoring pressure 

changes above the confining zone, or using geophysical techniques (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or other down-hole CO2 detection tools). 

This RA also requires owners and operators to monitor ground water quality and geochemical 

changes above the confining zone using a network of monitoring wells and track changes relative to 

baseline geochemical data. 

Finally, under this RA, owners and operators report twice per year, rather than annually, on all 

required monitoring. 

Injection Well Plugging and PISC: Under this RA, owners and operators submit, gain approval 

for, and implement a well plugging plan. To plug injection wells owners and operators: flush the well 

with a buffer fluid, perform an MI test, and plug the well in a manner that will prevent the movement of 

fluid that may endanger USDWs. 

Under this RA, owners and operators develop and implement a plan for PISC and site closure 

and submit the plan as part of the permit application. For at least 50 years (unless the Director approves 

a shorter time frame based on data submitted as part of the permit application, or collected during PISC), 

owners and operators monitor the site to show the position of the CO2 plume and pressure front and to 

demonstrate that USDWs are not being endangered. After 50 years, owners and operators perform a 

non-endangerment demonstration that the CO2 plume and pressure front have stabilized and that no 

additional monitoring is needed to assure that the project does not pose an endangerment to USDWs. At 

this point, the Director will determine whether further monitoring is necessary or authorize closure of 

the site. 

Financial Responsibility: Under RA3, owners and operators demonstrate and maintain financial 

responsibility and resources for plugging the injection well, corrective action, remediation, providing 

post-injection site monitoring and closure (accounting for inflation) and emergency and remedial 

response. The requirement to maintain adequate financial responsibility and resources is directly 

enforceable regardless of whether the requirement is a condition of the permit. The Director is charged 

with approving financial instruments submitted by owners and operators that he or she deems sufficient 

to address endangerment to USDWs. Acceptable financial instruments include: trust funds, surety 

bonds, letters of credit, escrow accounts and insurance. The owner or operator must maintain such 

financial responsibility and resources until (1) The Director receives and approves the completed PISC 

and site closure plan; and (2) The Director determines that the site has reached the end of the post 

injection site care period. 

Emergency and Remedial Response: Under RA3, owners and operators develop, implement and 

periodically update a plan that describes actions to be taken to address events that may cause 

endangerment to USDWs during the construction, operation and PISC periods of a GS project. If there is 

evidence of potential endangerment of USDWs, the owner or operator would be required to cease 

injection, investigate and identify the release, notify the Director within 24 hours, and implement the 

emergency and remedial response plan. 

Cost Analysis for the 2-9 November 2010 

Final GS Rule 
2.3.4 Regulatory Alternative 4 

This RA prescribes specific technologies that GS well owners and operators would use for 

geologic studies, models, and well materials to protect USDWs from the injection of large volumes of 

CO2. This alternative is the most prescriptive; it provides the most regulatory certainty and consistency 

(and therefore the least flexibility). Many components of this RA equal or exceed the activities 

performed by owners and operators of Class I hazardous waste injection wells and it includes additional 

elements beyond the other RAs. The following sections describe this RA, highlighting the differences 

from RA3. 

Site Characterization: Under this RA, all GS sites would need to have, in addition to the 

injection zone, containment mechanism, and confining system, additional zones that will impede vertical 

fluid movement, allow for pressure dissipation, and provide additional opportunities for monitoring, 

mitigation, and remediation. This differs from RA3 in that every GS site would need to have these 

additional layers. It is equivalent to the current requirements for Class I hazardous waste injection wells, 

and differs from RA3 in that it applies to all GS projects. 

Under this RA, owners and operators would provide more detailed data about the injection zone 

and confining zones than under the other alternatives. In addition to the data that owners and operators 

would submit under RA3, they would also need to submit geological core data, outcrop data, 3-

dimensional seismic survey data, and well logs. In areas with insufficient data, owners and operators 

would be encouraged to drill at least one stratigraphic test well to describe the specific petrophysical 

parameters of the injection zone and the primary confining system and additional confining and 

containment zones. Under this RA, the baseline geochemical data would include more detailed 

information, e.g., on water-rock-CO2 geochemistry and mineral reactions. 

AoR and Corrective Action: As with RA3, owners and operators would be required to develop 

and implement an AoR and corrective action plan describing the process by which they would define the 

AoR, apply corrective action, and periodically reevaluate the AoR. As with RA3, owners and operators 

would define the AoR using computational models of the injected CO2 stream, CO2 plume and the 

associated pressure front that are based on information collected as part of the site characterization as 

well as anticipated operating data. This RA would also specify that the models predict the CO2 plume 

movement over 10,000 years. 

As with RA3, owners and operators would determine which wells in the AoR require corrective 

action based on recent, reliable plugging records and remediate any wells that may endanger USDWs. 

This RA would also specify that wells needing corrective action be remediated using materials 

compatible with the carbon dioxide stream or other appropriate corrective action methods. As in RA3, 

owners and operators would, at the Director’s discretion, have the option to phase in corrective action. 

This RA would specify that the AoR reevaluation be performed at least once every 5 years. 

Injection Well Construction: As with RA3, this RA would specify the use of well materials and 

technologies (e.g., for casing, tubing, and cements) that employ the corrosion-resistant technologies. 

However, several elements of this RA are more prescriptive. For example, this RA would require the use 

of specialized, corrosion-resistant materials such as latex cement, metal alloys, and specialized tubing. 

Cost Analysis for the 2-10 November 2010 

Final GS Rule 
RA4 also specifies that the surface casing be set 100 feet below the lowermost USDW and that the 

packer be set no more than 100 feet above the uppermost perforation. Owners and operators would have 

to construct injection wells to inject below the lowermost USDW, and at a sufficient depth so the CO2

would remain in a supercritical state (to potentially avoid MI concerns associated with CO2 phase 

changes). As with RA3, during drilling and construction, the owner or operator would run logs, surveys, 

and tests to determine or verify the properties of subsurface formations to assure conformance with the 

construction requirements. 

Injection Well Operation: Under this RA, injection should be conducted such that pressure in the 

injection zone does not exceed 90 percent of the fracture pressure in any portion of the area defined by 

the anticipated pressure front, or the capillary entry pressure at any point in the lower-most portion of 

the primary confinement system. As with RAs 2 and 3, injection may not initiate new fractures, 

propagate existing fractures, or cause fluid movement into USDWs. 

RA4 contains one additional element that is specific to injection of CO2 for GS. Owners and 

operators would, at the Director’s discretion, be required to add an odorant or a tracer to the injected 

CO2 to facilitate early detection of leaks or movement outside of the intended injection zone to protect 

USDWs. 

MIT: As with RA3, owners and operators of GS wells would demonstrate that their wells have 

internal and external MI. The sole difference is that this RA would require that the testing be conducted 

at least twice annually. 

Monitoring: Some of the monitoring elements of this RA parallel those in RA3 (i.e., owners or 

operators would conduct baseline geochemical monitoring and develop and implement plans for 

monitoring geochemical changes in the subsurface, monitoring their injectate, tracking the CO2 plume 

and pressure front, and conducting surface atmospheric or soil gas CO2 monitoring). This RA also 

requires that a pressure fall-off test be conducted annually. 

This RA differs from RA3 in that it would prescribe the use of certain sophisticated technologies, 

which exceed the detail prescribed in the existing regulations. For example, it specifies that the network 

of monitoring wells used for geochemical monitoring should be constructed, using best available 

technologies, of corrosion-resistant materials that could withstand extended contact with the CO2 to 

provide some assurance that monitoring wells in the AoR do not potentially become conduits for 

movement of fluids out of the injection zone. 

Under this RA, surface atmospheric or soil gas monitoring would be expanded to include 

monitoring at all artificial penetrations and at other sensitive areas (e.g., in buildings and man-made 

surface structures that are intended for human occupancy) within the AoR. 

In addition, under this RA, operators or operators would report monthly on the characteristics of 

injection fluids, injection pressure, flow rate, temperature, volume and annular pressure, and on the 

results of MITs, and ground water and atmospheric/soil gas monitoring. 

Injection Well Plugging and PISC: Under this RA, owners and operators would develop and 

implement well plugging and PISC and site closure plans specified under RA3. Plugging activities 

Cost Analysis for the 2-11 November 2010 

Final GS Rule 
Cost Analysis for the 2-12 November 2010 

Final GS Rule 

would be similar to those required under RA3. This RA differs from RA3 in that the post-injection 

monitoring period would be over a period of 100 years (also followed by a non-endangerment 

demonstration). 

Financial Responsibility: The financial responsibility requirements under this RA are the same 

as under RA3, i.e., the owners and operators would demonstrate financial responsibility for plugging the 

well, corrective action, remediation, providing post-injection monitoring, and emergency and remedial 

response, accounting for inflation. 

Emergency and Remedial Response: The requirements for developing and implementing an 

emergency and remedial response plan to address movement of injection or formation fluids that may 

endanger USDWs under RA4 are the same as those that would be required under RA3. 

2.3.5 Comparative Summary of Regulatory Alternatives 

Exhibit 2.1 below summarizes the components of each RA of the GS rule. 
Cost Analysis for the 2-13 

Final GS Rule 

Exhibit 2.1 Comparison of Alternatives for GS of CO2 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Site CharacterizationGS wells must be sited in a manner that protects USDWs from endangerment. 

A geologic system comprised of: 

• A receiving zone of sufficient areal 

extent, thickness, porosity, and permeability; 

• A containment mechanism that is 

free of transmissive faults or fractures; and 

• A confining zone of sufficient areal 

extent and integrity to contain all injected fluid to allow injection at proposed rates and volumes without initiating or propagating fractures in the confining zone. 

A geologic system comprised of: 

• An injection zone of sufficient areal extent, 

thickness, porosity, and permeability; 

• A containment mechanism that is free of 

transmissive faults or fractures; 

• A confining zone of sufficient areal extent and 

integrity to contain all injected fluid to allow injection at proposed rates and volumes without initiating or propagating fractures in the confining zone; and 

• At the Director’s discretion, additional zones 

that will impede vertical fluid movement, allow for pressure dissipation, are free of faults and fractures, and provide additional opportunities for monitoring, mitigation, and remediation. 

A geolog• A 

arepe

• A c

of 

• A 

cietaiat inico

• Ad

cadisturnitrem

Provide geological data on the injection zone and confining zone, including: 

• Lithologic description. • Geological name. • Thickness and depth. 

Provide information on the geologic structure of the proposed site, including: 

• Maps and cross sections of local geologic 

structure; 

• Identification of faults and fractures in the 

confining zone and determination that they would not interfere with containment; 

• At the Director’s discretion, identification of 

faults and fractures in additional zones and determination that they would not interfere with containment; 

• Eliminate sites with potential seismic risks. 

Provide ture of th• Ma

log

• Ide

the terfer

• Ide

adthatai

• Inf

pre
Cost Analysis for the 2-14 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Provide a map of the injection well and the applicable AoR. 

Characterize the geologic structure and hydrogeologic properties of the proposed storage site and overlying formations based on: 

• Data on the areal extent, thickness, capacity, 

porosity, and permeability of the receiving formations, the confining zones and, at the Director’s discretion, any additional zones. 

• Geomechanical information on fractures, 

stress, rock strength, and in situ fluid pressures within the confining zones. 

• Geologic and topographic maps and cross 

sections illustrating regional geology. 

Charactedrogeolog

age site a

• Da

cathe cofining on dimlog

• In 

ing weterramfor

• Ge

turflufinan

• Ge

croolo

Provide the geologic name and depth to bottom of all USDWs that may be affected by the injection. 

Provide geochemical information on subsurface aquifers, including all USDWs: • Baseline geochemistry. • Maps and cross sections of USDWs. 

Provide face aqu• Ba

roc

rea

• Ma

Conduct baseline geochemical monitoring within the injection system and above the confining system before injection commences. 

Conduct within thconfining mences
Cost Analysis for the 2-15 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERN

ATIVE 3 RE

Provide information on the AoR: • Maps and cross sections of the 

AoR. 

• List of penetrations into the injection zone. 

Provide information on the AoR: • Maps and cross sections of the AoR. • List and maps of all penetrations into the injection zone and confining zones, and at the 

Director’s discretion, into any additional zones, including structures that are intended for human occupancy using publicly available data.. 

• List and associated data (well type and construction, date drilled, location, depth, plugging record, and any other information required by the Director) for all wells into the 

confining zones. 

Provide • Ma• Lis

injanstrocta. 

• Lis

codeinffor crezo

Provide information on proposed: • Testing and Monitoring Plan • Injection well plugging plan • PISC and site closure plan • Emergency and remedial plan; and 

Any other information requested by the Director 

Provide information on proposed: • Operating data • Formation testing program • Stimulation program • Injection procedure • Surface and subsurface well construction (including schematic) • Contingency plan to address well shut-ins and 

failures 

• Testing and Monitoring Plan • Injection well construction procedures • Federal Register (FR) responsibility demonstration • Injection well plugging plan • PISC and site closure plan • Emergency and remedial plan; and • Any other information requested by the Director 

Provide in• Ope• Form• Stim• Injec• Surfa

(inclu

• Cont

ins a

• Test• Injec• FR r• Injec• PISC • EmeAny othetor 
Cost Analysis for the 2-16 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Provide, in operating permit application: • All available logging and testing data • MI demonstration • Anticipated max. injection pressure • Formation testing results • Injection procedure • Information on the compatibility of CO2 stream 

with formation fluids and minerals in the injection and confining zones and with proposed well construction materials 

• Modeled AoR • Status of corrective action on wells in the AoR; 

and, 

Any other information required by the Director. 

Provide, • All av• MI d• Antic• Form• Injec• Infor

streain the with 

• Mod• Statu

AoR

• Any 

Direc

AoR Study and Corrective Action 

The AoR may be determined by a calculating a fixed radius or by modeling. The AoR is delineated using computational model- ing that accounts for the physical and chemical 

properties of all phases of the injected CO2 stream, 

CO2 plume, and pressure front for an appropriate 

timeframe to ensure there is no longer a threat to USDWs based on proposed injection rates and volumes. Models must be based on site specific information, geologic information collected to characterize the injection zone, confining zones, and additional zones, as well as anticipated operating data. 

The AoR modeling chemical jected CO

front for 1injection based on informatiojection zozones, as 

As a part of the permit application, the owner/operator develops and submits an AoR and corrective action plan for Director approval that: • Requires the reevaluation of the AoR at a minimum fixed frequency not to exceed five years; 

and; 

• Describes how and when (prior to/outside of 

the minimum fixed frequency) the AoR will be reevaluated taking into account: changes in site operation; when monitoring data differs from modeling results; and, considerations for maintaining site access; and 

• Corresponds with the CO2 plume and pressure 

front and indicates whether corrective action will performed up-front or on a phased-in basis; how corrective action will be adjusted if the AoR changes; and how site access will be guaranteed for future corrective action. 

As a part er/operatand correproval tha• Requ

a min

• Desc

reevin sitdiffesiderand 

• Corr

presrectivon a tion wand for fu
Cost Analysis for the 2-17 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Identify all artificial penetrations (including active and abandoned wells and mines) in the AoR that penetrate the confining zone. Provide: a description of each well's type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require. 

Identify all artificial penetrations (including active and abandoned wells and mines) in the AoR that penetrate the confining t zones (and at the Director’s discretion any additional zones) and pose an endangerment to USDWs. Provide: a description of each well's type, construction, date drilled, location, depth, record of plugging and/or completion, and any additional information the Director may require. 

Identify aactive anthe AoR tsystem ament zonUSDWs. type, condepth, reand any amay requ

Determine if they have been plugged in a manner that prevents the movement of CO2 or associated fluids, and identify those that need corrective action. 

Determine if they have been plugged in a manner that prevents the movement of CO2 or associated 

fluids based on reliable, recent plugging records, and identify those that need corrective action. 

Determinmanner t

or associplugging corrective 

Conduct corrective action for the entire AoR prior to injection, remediating those wells in the AoR that pose a risk to USDWs using appropriate corrective action methods determined by the permitting authority 

Corrective action will be conducted up-front or on a phased-in basis as per the AoR and corrective action plan (and if approved by the director). This includes, remediating those wells in the AoR that pose a risk to USDWs using materials compatible with the CO2 stream and other appropriate corrective action methods. 

Correctivor on a pcorrective director). wells in thusing ma

stream antion meth

Injection Well ConstructionGS wells must be constructed in a manner that protects USDWs from endangerment. 

The well must be cased and cemented to prevent movement of fluids into or between USDWs. 

Provide to the Director for approval of casing and cementing program: Depth to injection zone; injection, external, internal pressure and axial loading; hole size; size and grade of casing strings; information about CO2

stream (corrosiveness, quantity, composition, temperature) and formation fluids; down-hole temperatures; lithology of injection and confining zones; type/grade of cement; and cement additives; And, for approval of tubing and packer use: (in addition to information above) Depth of setting; annular pressure; injection rate; casing size; and tubing tensile, burst, and collapse strengths. 

Provide tand cemeDepth to internal psize and about CO

compositfluids; doinjection cement.
Cost Analysis for the 2-18 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Injection must be below the lowermost USDW, except in the limited number of cases in which a waiver application is approved. (See RA3 for waiver application requirements.) 

Injection must be below the lowermost USDW, except in the limited number of cases in which a waiver application is approved. (See RA3 for waiver application requirements.) 

Surface casing should be set through the base of the lowermost USDW and cemented to the surface through the use of a single or multiple strings of casing and cement. Injection must be below the lowermost USDW, except in the limited number of cases in which a waiver application is approved. Owners/operators seeking a waiver to inject below the lowermost USDW must submit to the Director a supplemental report that demonstrates USDWs will not be endangered as a result of CO2 injection. 

Before being granted a waiver, owners/operators would have to evaluate the following components as they relate to their GS projects: 

• the integrity of the upper and lower confining 

units; 

• the suitability of the injection zone; • the potential capacity of the geologic formation 

to sequester CO2; 

• community needs, demands, and supply from 

drinking water sources; and 

• any other applicable considerations or information requested by the Director. 

The director will give public notice that a waiver application has been submitted. The supplemental report must include the following: 

• Injection zone is laterally continuous, not hydraulically connected to USDWs; does not outcrop; and has adequate injectivity, volume, 

and sufficient porosity to safely contain the injected CO2 and formation fluids, and has appropriate geochemistry. 

• Injection zone is adequate to prevent fluid 

movement and pressure buildup outside of the injection zone; and, that the confining units are free of transmissive faults and fractures. 

• Using computational modeling, show that 

USDWs above and below the injection zone will not be endangered as a result of fluid movement. 

• Well design and construction, in conjunction 

with the waiver, will ensure isolation of the injectate. 

• Monitoring and testing and any additional 

plans will be tailored to the GS project to ensure protection of USDWs above and below the injection zone. 

Surface cbe set 10cemented Injection USDW an

critical stawith phas
Cost Analysis for the 2-19 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

The integrity and location of the cement must be verified using technology capable of radially evaluating cement quality, identifying the location of channels or contaminated cement, and validating the casing-cement and cementformation bonds through primary confining system. 

At least one long-string casing, using a sufficient number of centralizers, must extend to the injection zone and must be cemented by circulating cement to the surface in one or more stages. The integrity and location of the cement must be verified using the best available technology capable of radially evaluating cement quality and identifying the location of channels to ensure that USDWs are not endangered. 

At least ocient numthe injectcirculatinmore stagcement mable techcement qchannels dangered

Casing, tubing, and packer should be adequate to withstand the corrosive nature of the injected CO2 and any impurities at the anticipated pressure, 

temperature and other operational conditions and meet API standards. 

Casing, tubing, and packer should be adequate to withstand the corrosive nature of the injected CO2

and any impurities at the anticipated pressure, temperature and other operational conditions and meet API standards. 

Use specsuch as mtubing thaof the inje

anticipateoperationstandards 

Inject through tubing and packer that is set at a depth opposite a cemented interval of the longstring casing at a depth approved of by the Director. 

Inject throa depth olong-strinfeet abovhole for t

Use corrosion resistant cements in zones where cement-CO2 contact is 

likely or cement integrity is critical (e.g. cement zones through primary confining system). 

Use corrosion-resistant cement (e.g., phosphatebased non-Portland cements), that can withstand extended contact with injected CO2 and associated 

impurities throughout the life of the project. 

Use specment that with injec

througho
Cost Analysis for the 2-20 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY A

LTERNATIVE 3 RE

Logging, Sampling, and Testing Prior to Injection Well OperationGS wells must be operated in manner that protects USDWs from endangerment. Submit to the Director: 

• A schedule of all logging, sampling, and testing activities to be completed 30 days prior to 

conducting first test and notification of any changes 30 days prior to next test. 

• A report prepared by a knowledgeable log 

analyst that includes an interpretation of all logs and tests conducted to determine or verify depth, thickness, porosity, permeability, and lithology of, and formation fluid salinity of, all relevant geologic formations. Logs and tests must include: • Deviation checks • Other logs as required by Director at various intervals, including: 

Before surface casing installation: resistivity, sp, and caliper logs; and After casing is set and cemented: cement bond and variable density log to evaluate cement quality radially; Before long-string casing installation: resistivity, spontaneous potential, porosity, caliper, gamma ray, fracture finder, and any other logs required by Director; and After long-string casing is set and cemented: cement bond and variable density log, and a temperature log; and A series of MIT logs which may include pressure test, tracer survey, temperature or noise log, casing inspection log and any other tests required by Director. 

Submit to • A sc

testinprior tion otest. 

• A rep

log aof almine permtion fformLogs • • 

Before susp, and cAfter casbond and Before loity, spontgamma rlogs requAfter longcement btemperatA series osure test, log, casintor and a

Take whole cores and sidewall cores in the injection zone and confining systems and formation fluid samples from the injection zone(s) and submit to the director a detailed report and well log information about the cores and formation fluid samples, prepared by a log analyst; and any other or comparable information required and approved of by Director. 

Take and sidewall cfining systhe injectrable infoDirector. 
Cost Analysis for the 2-21 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Record fluid temperature, pH, conductivity, reservoir pressure, and static fluid level of the injection zone(s). 

Record flreservoir injection 

Determine or calculate injection and confining zone fracture pressure; physical and chemical characteristics of the injection zone, confining zone, and injection zone formation fluids. 

Determinzone fraccal charafining zonids. 

Perform a pump test or injectivity test prior to operation to verify hydrogeologic characteristics of the injection zone. 

Perform a operation tics of the 

Injection Well OperationGS wells must be operated in a manner that protects USDWs from endangerment. 

Injection should be conducted such that the pressure during injection does not initiate new fractures or propagate existing fractures in the confining zone adjacent to the USDWs. Higher operating pressures may be allowed if approved by the permitting authority. 

Injection should be conducted such that pressure in the injection zone does not exceed 90 percent of the fracture pressure of the injection zone in any portion of the area defined by the anticipated pressure front. Injection may not initiate new fractures, propagate existing fractures in the injection zone, or cause fluid movement into USDWs; and, annulus pressure should exceed operating injection pressure unless otherwise specified by the Director. 

Injection pressure ceed 90 pthe injectdefined bthe capilllower mosystem. Itures, profluid movpressure pressure Director. 

Owners and operators are be required to equip the well with alarms and down-hole shut-off systems or other safety devices (e.g., check valves) approved by the Director, designed to alert the owner or operator and shut-in the well when operating parameters such as annulus pressure, injection rate, or other parameters diverge beyond permitted ranges and/or gradients specified in the permit. 

Equip witthat engadiverge bannulus pAt the dira tracer t

detection intended endange

If a shutdown (i.e. down-hole or at the surface) is triggered, cease injection; investigate and identify cause of shutdown; determine if CO2 has leaked 

into unintended zones; notify Director; restore and demonstrate MI to Director; notify Director when injection will resume. 

If a downinjection; shutdown

unintendedemonstrwhen inje
Cost Analysis for the 2-22 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

MITGS wells must be monitored in a manner that protects USDWs from endangerment. 

Demonstrate internal MI by monitoring injection pressure, flow rate, injected 

volumes, and pressure on the annulus as specified by the permitting authority. 

Demonstrate internal MI by continuously monitoring injection pressure, flow rate, injected volumes, and pressure on the annulus between the tubing and the long-string casing. 

Demonstmonitorinjected vobetween ing. 

Demonstrate external MI, i.e., there is no significant fluid movement into a USDW through vertical channels adjacent to the injection well bore at a frequency specified by the permitting authority. 

Demonstrate external MI, i.e., there is no significant fluid movement into a USDW through vertical channels adjacent to the injection well bore using a tracer survey of the bottom-hole cement (using a CO2 -soluble tracer or a suitable alternative method 

(e.g., Oxygen Activation Log (OAL)), a temperature or noise logs or other tests suitable to wells injecting liquid/super critical CO2 fluids as approved by 

the permitting authority), or if required by the director a casing inspection log; or, another suitable method required and/or approved by the Director at least once per year.

Demonstsignificanthrough vjection webottom-htracer or OAL), a ttests suitcritical COting authocasing inmethod rrector at 

Report within 30 days (or with the next reporting 

period, whichever is later) the results of periodic MI tests, other tests required by the Director, or well workovers. 

Report wing periodperiodic MDirector, 

Monitoring 

As a part of the permit application, develop and submit a testing and monitoring plan for Director approval. 

As a part and submDirector a

GS wells must be monitored in a manner that protects USDWs from endangerment. 

Monitor the nature of injected fluids at a frequency sufficient to yield data representative of their characteristics. 

Monitor the nature of injected fluids at a frequency sufficient to yield data representative of their characteristics. 

Monitor thquency sof their chtheir com

Monitor injection wells for loss of mass, thickness, 

cracking, pitting and other signs of corrosion on a quarterly basis to ensure that the well components maintain integrity using coupons, routing CO2

through a loop in the well, or an alternative method approved by the Director. 

Monitor inness, crarosion on well compcoupons, 

well, or athe Direc

Conduct a pressure fall-off test at least once every 5 years. 

Conduct per year. 
Cost Analysis for the 2-23 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Track the subsurface extent of the CO2 plume and pressure front using pressure and temperature gauges, resistivity logs, and other monitoring tools or using geophysical techniques (e.g., seismic, electrical, gravity, or electromagnetic surveys) and/or other down-hole CO2 detection tools or other methods as determined by the director. 

Track the 

plume antemperater monitotechniqueor electrohole CO2 

the direct

Monitor geochemical changes above the confining zone (and at the Director’s discretion any additional zones). The number of monitoring wells should be based on site-specific information and may be a function of CO2 injection rate and volume, geology, 

the presence of artificial penetrations, or other factors. 

Monitor gfining zontainment nologies. the numbbased on be a func

ume, geotrations, ostructed o

At the Director’s discretion and as part of the permit application, develop and implement a plan for surface air monitoring and/or soil gas monitoring to detect leakage of CO2 in the AoR to ensure that 

CO2 and any other contaminants moving with the 

CO2 have not migrated through USDWs. 

Develop monitorintect leaka

penetratiosensitive made surhuman oc

any other 

have not 

Report annually on the characteristics of injection fluids, injection pressure, flow rate, temperature, volume and annular pressure, and on the results of MITs. 

Report twice per year on the characteristics of injection fluids and any changes from proposed operating data; injection pressure, flow rate, temperature, volume and annular pressure; a description of events that exceed operating parameters for annulus or injection pressures and any events that trigger a shutdown and response taken; monthly volume of CO2 stream injected; and results of all 

monitoring. Report on MIT results within 30 days of testing, except in the cases where MIT or other test indicates a problem with the operations, which would be reported within 24 hours. Reports must be submitted to an electronic EPA system. Records on operational data are kept for 10 years after collection and certain other data are kept until 10 years after site closure. 

Report mjection fluoperating temperatdescriptioparameteand any eresponse 

stream inReport on ing, excetest indicwhich woReports mEPA systare kept ftain other site closu
Cost Analysis for the 2-24 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Well Plugging, PISC and Site Closure 

 As a part of the permit application, develop and submit a well plugging plan for Director approval. 

As a part of the permit application, develop and submit a well plugging plan for Director approval which includes: appropriate test methods to determine bottom-hole reservoir pressure and MIT to be used; type and number of plugs; location/placement of each plug; type of CO2 compatible material to be used in plugging; and the method 

of plug placement. 

As a part and submapproval methods pressure ber of plutype of C

plugging; 

GS wells must be closed in a manner that protects USDWs from endangerment. Ensure that the well is in a state of stat- ic equilibrium with mud equalized prior to placement of the plugs (or as required by the permitting authority). Flush the well with a buffer fluid and determine bottom-hole reservoir pressure prior to well plug- ging. Flush the 

mine bottwell plugg

Perform an MIT prior to plugging the well to ensure the integrity of that portion of the long-string casing and cement that will be left in the ground after plugging. 

Perform aensure thstring casthe groun

Plug the well with cement in a manner that will not allow the movement of fluids either into or between USDWs (or as required by the permitting authority), placing the cement plugs in a manner specified by the Director. 

Notify the Director at least 60 days before plugging the well, submitting any revisions to the well plugging plan for Director approval; and, plug the injection well per the approved well plugging plan. 

Notify the plugging the well pand, plug well plugg

Within 60 days after plugging or at the time of the next quarterly report (whichever is less), owner/operator must submit a certified plugging report to the Director. The owner or operator shall retain the well plugging report for ten years following site closure. 

Within 60 the next qowner/op

ging repo
Cost Analysis for the 2-25 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

As a part of the permit application, develop and submit a plan for Director approval to address PISC and site closure requirements and monitoring, for 10 years after project closure. 

As a part of the permit application, develop and submit a plan for Director approval to address PISC (and monitoring) and closure requirements, for 50 years after cessation of injection. The plan should include the:  Pressure differential between pre-injection and 

post-injection pressures in the injection zone 

 Predicted position of the CO2 plume and pressure front 

 A description of post-injection monitoring (location, methods, and frequency)  A proposed schedule for submitting monitoring 

results to the Director. 

Upon cessation of injection, the plan should be reapproved by the Director, amended or original. The default PISC period is 50 years; data submitted as part of the permit application, or collected during PISC and submitted to the Director can be used to request a shorter PISC period, subject to Director approval. At the end of the PISC period, a non-endangerment demonstration will be performed and the director will determine if further monitoring is necessary. 

As a part and submaddress Prequireminjection. The plan  Pres

injecthe in

 Pred

pres

 A de

(loca

 A pro

itorin

Upon cesbe re-apporiginal. After 100 tor approstration wdetermine 

Conduct post-inject site monitoring per 

the Director-approved plan to confirm that CO2 movement is limited to intended zones 

Conduct post-injection site monitoring per the Director-approved plan (which may include pressure fall-off test; seismic monitoring, if appropriate; monitoring in and above the injection zone and the USDW) to confirm that CO2 movement is limited to 

intended zones. 

Conduct Director-apressure appropriajection zoCO2 mov

After site-closure is authorized by the Director, plug all monitoring wells in a manner that will prevent endangerment of USDWs. 

After sitetor, plug awill preve

Submit a site closure report to the Director within 90 days, that must be retained for ten years, that includes: documentation of (all) well plugging; submission of a survey plat to specified parties; documentation of notification to parties that may have authority over future drilling activities in the AoR; records reflecting CO2 characteristics 

Submit a within 90 of (all) weplat to spnotificatio

over futucords ref

Record a notation on the deed to the facility property indicating that the land was used for GS; name of authority with which survey plat was filed; injection volume, zones, and duration. 

Record a property GS; namwas filedtion. 
Cost Analysis for the 2-26 

Final GS Rule 

REGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2 REGULATORY ALTERNATIVE 3 RE

Retain for 10 years following site closure, and, after three years deliver to the Director, records of the nature, composition, and volume of the CO2

stream. 

Retain foafter threcords of tof the CO

Financial Responsibility

Provide through a performance bond, or other appropriate means, the resources necessary plug the well. 

Demonstrate and maintain financial responsibility and resources for plugging the well, corrective action, remediation and providing post-injection site monitoring and closure, accounting for inflation. 

Demonstsibility for remediatimonitorintion. 

Emergency and Remedial Response

As a part of the permit application, develop and submit an emergency and remedial response plan for Director approval that describes actions to be taken to address movement of injection or formation fluids that may endanger USDWs. The requirement to maintain and implement an approved plan is directly enforceable regardless of whether the requirement is a condition of the permit. 

As a part and submsponse pscribes amovemenmay enda

If evidence shows potential endangerment of USDWs, the owner or operator should cease injection; notify the Director; investigate and identify CO2 release; implement the emergency and remedial response plan; 

And, prior to re-commencing injection, demonstrate to the Director non-endangerment to USDWs. 

If evidencUSDWs, injection; identify C

implemensponse pAnd, prioonstrate tUSDWs. 

Notify the Director and obtain approval for well workovers. 

Notify the well work

Periodically review the emergency and remedial response plan at least once every five years. Any amendments to the emergency and remedial response plan must be approved by the Director and shall be submitted within one year of an AOR reevaluation. 
Cost Analysis for the 2-27 November 2010 

Final GS Rule 

2.4 Final Rule Requirements 

 EPA selected RA3 as the best alternative for the final rule. Compared to the baseline 

condition of the current UIC Program regulations, RA3 offers significantly greater protection to 

USDWs because it is tailored specifically to GS and includes requirements necessary to prevent 

endangerment via migration of fluids into USDWs than RA1 and RA2 Additionally, RA3 offers 

greater protection over the baseline (Class I non-hazardous wells) because the RA3 requirements 

are tailored to address the unique nature of injection of CO2 for the purposes of GS. This 

alternative also incorporates flexibility or Director’s discretion wherever appropriate. RA4 

provides the most reduction in risks and overall costs because it prescribes the most stringent 

standards. However, EPA does not believe that the increased requirements under RA4 compared 

to RA3 are necessary to provide the necessary protection to USDWs. Detailed results of the 

costs for the regulatory alternatives considered are provided in Chapter 5 and Appendix C of this 

Cost Analysis. 
Cost Analysis for the 3-1 November 2010 

Final GS Rule

3. Baseline Analysis 

3.1 Introduction 

This chapter describes the carbon dioxide (CO2) geologic sequestration (GS) projects that 

form the baseline incorporated into the GS Rule Cost Analysis including their hydrogeologic 

characteristics and other project characteristics affecting the costs of the rule. It presents the data 

sources for the baseline information and an overview of the uncertainty associated with these 

data. The United States Environmental Protection Agency (EPA) has estimated the 

characteristics for a representative group of projects that are expected to deploy under existing 

legislation over the 50-year period of analysis of the GS Rule. This chapter summarizes the 

information relevant to the cost analysis presented in Chapter 5, and is organized as follows: 

• Section 3.2 describes the data sources used to inform development of the project 

baseline. These sources include published data sources, data from current pilot 

projects submitted by Department of Energy (DOE), and laboratory data. 

• Section 3.3 provides background that describes the various types and distribution of 

hydrogeologic settings identified as potential receiving formations for CO2 injected 

for the purpose of GS in the U.S. 

• Section 3.4 introduces the group of GS projects constituting the baseline by size of 

project and type of receiving formation, and presents characteristics for each type of 

project. 

• Section 3.5 identifies the sources of uncertainty in the baseline analysis.

3.2 Data Sources 

EPA used a variety of data sources to create baseline forecasts for the cost analysis, 

including data published/collected by DOE, industry, and academia, pilot project data and 

laboratory data from efforts by DOE in conjunction with seven CO2 GS Regional Carbon 

Sequestration Partnerships (RCSPs). These data sources are described below. 

3.2.1 Published Data 

Over the past several years, DOE and seven regional sequestration partnerships 

(comprising private sector, academia, and government representatives) have assessed and 

characterized the potential CO2 sequestration capacity in the United States. Through their efforts, 

DOE published the National Carbon (NATCARB) Atlas (DOE, 2008), which categorizes GS 

potential by geologic setting and geologic basin or State, often providing the data in geographic 

information system (GIS) format. The NATCARB Atlas also presents information on the 

research conducted regarding various potential receiving formations, and includes an estimated 

total U.S. CO2 GS capacity of approximately 3,500 gigatons (Gt) although the actual capacity 

may be lower once site-specific technical and economic considerations are addressed. 
Cost Analysis for the 3-2 November 2010 

Final GS Rule

 

To estimate non-DOE large-scale projects, EPA consulted sources including the Carbon 

Sequestration Leadership Forum (CSLF) Carbon Capture and Storage Demonstration Database 

(updated June, 2009), which EPA downloaded1

 and filtered for U.S. based projects of a 

significant scale.2 

3.2.2 Department of Energy Pilot Project Data 

 The research sponsored by DOE began in 2003 with the Characterization Phase, in which 

the National Energy Technology Laboratory (NETL) in Morgantown, West Virginia and the 

seven regional partnerships conducted the geologic analysis that resulted in the NATCARB Atlas 

described above. During the Validation Phase (2005-2009), field researchers conducted 

validation tests of reservoir simulation methods, data collection methods for capacity and 

injectivity, and the performance of monitoring technologies. The partnerships are also field 

testing approaches to well completion methods, operations, and site closure, with a variety of 

objectives including: 

• Testing the effectiveness of various well materials and injection practices; 

• Validating models of the fate and transport of CO2 in the subsurface; 

• Developing a thorough understanding of the geology, hydrogeology, and 

geochemistry at potential GS sites; 

• Assessing the usefulness of geophysical survey and monitoring techniques; 

• Testing failure scenarios; 

• Developing experience necessary for deployment of large-scale CO2 GS; and 

• Building public confidence that GS can be performed without adverse risks. 

The results of research at three of these sites (in Escatawpa, Mississippi; the Aneth Field in the 

Paradox Basin, Southeast Utah; and the Pump Canyon Site, New Mexico) were presented in 

EPA’s August 31, 2009 Notice of Data Availability (NODA) (74 FR 44802). 

During the Deployment Phase (2008-2017), the partnerships are conducting large volume 

carbon storage tests to demonstrate that large-scale CO2 injection and storage can be achieved 

safely and economically. 

 

1 http://www.cslforum.org/projects/index.html

2 For the purposes of this analysis, a threshold of 1 million tons CO2 per year injection volume was used to 

determine those projects likely to be large-scale. 
Cost Analysis for the 3-3 November 2010 

Final GS Rule

3.2.3 DOE Inventory Data 

EPA consulted with DOE in conjunction with the partnerships to inform the baseline 

number of GS projects estimated to deploy in the U.S. over the timeframe of this analysis. DOE 

relied on information about existing projects, funding estimates and discussions with members of 

the regional partnerships to develop the projected baseline inventory and associated project data 

elements (e.g., duration and volume of injection, formation type, etc.). 

3.2.4 Laboratory Research 

EPA and DOE have co-funded research by the Lawrence Berkeley National Laboratory 

(LBNL) to study and evaluate the physiochemical processes of CO2 injection and to explore any 

potential impacts on ground water aquifers and drinking water sources. Current research includes 

the following: 

• Modeling potential impacts of CO2 injection on ground water aquifers and drinking 

water sources; 

• Assessing potential changes in regional ground water flow, including displacement of 

pre-existing saline water or hydrocarbons that could impact underground sources of 

drinking water (USDWs) or other resources; and 

• Integrating laboratory, field and modeling efforts with the objective of evaluating the 

potential consequences of CO2 leaks from GS operations into ground water resources. 

 The results of some of this research were published in the NODA. See Section 2.2 of this 

Cost Analysis for additional information. Information gained from this research will be used to 

evaluate potential risks and develop safeguards to protect USDWs from endangerment. As 

described in the preamble to the final GS Rule, EPA plans to adapt the rule over time as relevant 

information emerges from research and from GS field experience. 

3.3 Hydrogeologic Settings 

 

The various hydrogeologic settings of the formations across the U.S. that may serve as 

targets for long-term GS represent a significant range of storage potential, geographic location, 

and technical and economic merits, which could all affect the potential costs of GS. The 

variables that define the hydrogeologic setting include the type and properties of injection zone 

and confining formation, other components of the reservoir overburden, the location of current or 

potential USDWs, and the presence of artificial penetrations, fractures, or other potentially 

vulnerable attributes of the system. These variables are important in determining project 

parameters such as the required minimum depth of the injection well (or whether an injection 

depth waiver will be sought); the minimum number of monitoring wells; and maximum injection 

rates, volumes, and pressures. The geographic location of the potential injection zones can also 

determine the feasibility of injection projects depending on the location of the CO2 source. 

Although the costs of CO2 transport do not fall within the scope of this rule, the locational 

advantages of one type of formation over another will be an important consideration in the siting 

of the forecasted projects that compose the baseline of this Cost Analysis. 
Cost Analysis for the 3-4 November 2010 

Final GS Rule

 

3.3.1 Formation Types 

 

The requirements in the final rule are designed to ensure protection of USDWs through 

proper siting, well construction, operation, monitoring, and post-injection site care (PISC) at all 

sites selected for GS irrespective of formation type. For the purpose of conducting this Cost 

Analysis, EPA has identified several types of geologic formations that may serve as suitable 

formations for sequestering CO2.

3

Saline Formations 

Saline formations are deep and geographically extensive water-saturated rock layers with 

a high total dissolved solids (TDS) content (i.e., over 10,000 ppm TDS). Using volumes from the 

Carbon Sequestration Atlas of the United States and Canada (DOE, 2007b) EPA estimates that 

between 91.8 and 97.6 percent of potential GS storage capacity is in deep saline formations. 

Their geographic distribution covers all regions of the U.S. and because many are overlain by 

impermeable formations it makes them leading candidates for GS. Many are in close proximity 

to major CO2 stationary sources, which has the potential to substantially lower CO2

transportation costs. However, because they are currently of limited economic value (i.e., they 

are not used as drinking water sources or contain any mineral resources), most saline formations 

are not as well studied as other formation types being considered for GS. Pilot tests are currently 

being performed in saline formations to further evaluate their large-scale GS potential. 

Oil and Gas Reservoirs 

Enhanced oil recovery (EOR) and enhanced gas recovery (EGR) technologies, 

collectively referred to as enhanced recovery (ER), are used in oil and gas reservoirs to improve 

production efficiency. Injection of CO2 is one of several ER techniques that have successfully 

been used to boost production efficiency of oil and gas by re-pressurizing the reservoir, and in 

the case of oil, by also increasing its mobility. Injection wells used for ER are regulated through 

the Underground Injection Control (UIC) Class II program. 

Oil and gas reservoirs are very well studied and understood due to the amount of research 

needed for oil and gas exploration, and account for between 1.1 to 3.8 percent of the potential 

storage capacity in the U.S. (DOE, 2008). The volumes of CO2 to be injected and left behind in 

the formation for the purpose of GS would be much greater than traditionally seen in CO2

enhanced oil and gas recovery operations. Geographic distribution of oil and gas reservoirs 

corresponds to areas that have been drilled for oil and gas in the past including Appalachia, the 

Gulf Coast, Mid-Continent, and the Rockies. 

Unmineable Coal Seams 

CO2 may be injected into coal seams to displace methane that adsorbs onto the surface of 

the coal, provided injection does not endanger USDWs; such formations account for 

approximately 1.4 – 4.4 percent of the potential U.S. storage capacity (DOE, 2008). DOE 

estimates that for every molecule of methane displaced in enhanced coal bed methane (ECBM) 

3

 CO2 injection in certain situations such as for the purpose of enhanced oil and gas recovery (ER) operations may 

not be covered under the GS rule. The preamble provides a full discussion of applicability under the GS rule for 

different injection scenarios. 
Cost Analysis for the 3-5 November 2010 

Final GS Rule

operations, three to thirteen CO2 molecules are adsorbed. (DOE OFE, 2007) This process allows 

the methane to be captured and produced for economic purposes. Coalbed methane potential is 

concentrated in the areas of New Mexico and Wyoming. There are currently no large-scale CO2

ECBM projects, but DOE reports that initial field studies have demonstrated that CO2 ECBM and 

GS into coal seams is technically feasible. 

Other Formation Types 

Other types of formations such as basalts, organic rich shales, and abandoned mines also 

could potentially serve as CO2 reservoirs, provided injection does not endanger USDWs. In 

particular, shale gas is important to consider. The new shale gas basins that have emerged over 

the past decade are not as well studied and are not believed to be as technologically or 

economically feasible as saline formations, oil and gas reservoirs, and unmineable coal seams for 

GS. Research is ongoing in these formations and their viability as sequestration sites has not 

been proven. Therefore, EPA expects that CO2 injection into these types of formations will be 

permitted as Class V experimental technology wells. 

3.3.2 Formation Capacity 

EPA has developed estimates of the total U.S. CO2 storage potential by type of injection 

formation. This estimate extrapolates from prior NATCARB estimates into the previously 

excluded geographic areas of the United States to yield a total U.S. estimate of 3,374 Gt. Deep 

saline formations account for the largest estimated potential CO2 storage at 2,990 Gt, followed 

by oil and gas at 126 Gt, shale formations at 107 Gt, coal and coalbed methane at 51 Gt, and 

onshore saline-filled basalt at 100 Gt. 

3.4 Geologic Sequestration Rule Baseline 

 

This analysis estimates the anticipated level of GS activity in the United States under the 

existing regulatory conditions, as per EPA guidelines on economic analysis. In this baseline 

analysis, the Agency assumes that there will be no new national climate change legislation. In 

the absence of the development of new requirements for GS wells, EPA anticipates that GS wells 

would be permitted as Class V experimental technology wells, in accordance with UIC Program 

Guidance #83. This class of wells affords the UIC primacy agency discretion to issue permits 

that meet site-specific conditions for experimental projects. Based on review of early permits 

issued, the permit conditions for existing Class V experimental technology wells that test GS 

technology have been similar in stringency to those for Class I industrial wells, which will 

provide USDWs with protection that meet the goals of the Safe Drinking Water Act (SDWA). 

Specific requirements that may involve a great deal of discretion and thus greater variability in 

implementation (e.g., area of review (AoR) determinations) can have a significant impact on the 

amount of USDW protection under a particular permit. 

This cost analysis includes estimated costs projected over a 50-year instead of a 25-year 

time period, as is normally performed for EPA drinking water regulations. EPA elected to 

increase the analysis period to better reflect the lifecycle costs of GS projects. For large projects, 

this includes 1 year of construction, 40 years of injection, and 9 years of post-closure monitoring 

which concludes the timeframe of analysis. For pilot projects, this analysis captures the entire 15 

year period, including 1 year of construction, 4 years of injection, and 10 years of post closure 
Cost Analysis for the 3-6 November 2010 

Final GS Rule

monitoring. For projects in oil and gas reservoirs transitioning to GS, this includes 20 years of 

operating for the primary purpose of oil and gas production under an existing UIC Class II 

permit, and 10 years under Class VI permit where the primary purpose is long-term storage. 

 

3.4.1 Projects Comprising the Baseline 

 

 Based on analysis of existing data obtained from DOE on GS and current pilot programs 

as described in Section 3.2, EPA assumes there will be 29 projects for the baseline that are 

anticipated to be affected by the GS rule. These projects include 2 DOE-sponsored pilot saline 

projects, 8 large-scale DOE-sponsored projects in saline formations, and 4 projects at ER sites 

for a total of 14 DOE-sponsored projects. In addition, EPA estimates from the CSLF database as 

described in Section 3.2 that 15 projects not sponsored by DOE should be included in the 

baseline: 3 saline and 12 ER. 

Projects permitted prior to the finalization of the GS rule will be managed under existing 

UIC Program requirements and are not included in this baseline. Initially, the primary purpose of 

ER projects will continue to be oil and gas production, thus CO2 sequestration (as the primary 

purpose) is modeled to start later in the analysis period compared to other project types. Exhibit 

3.1 summarizes the forecast for deployment of these projects by type of project and project scale 

(pilot vs. large) over 50 years. 
Exhibit 3.1 Schedule of Baseline Project Deployment by Formation Type and 

Project Size

Pilot 

Project

Large 

Project

Waivered 

Saline ER

Waivered 

ER

2011 - - - - - 

2012 - 0.86 0.05 - - 

2013 - 0.86 0.05 - - 

2014 - 1.71 0.10 - - 

2015 - - - - - 

2016 - 1.71 0.10 - - 

2017 2 4.28 0.24 - - 

2018 - - - - - 

2019 - - - - - 

2020 - - - - - 

2021 - - - - - 

2022 - - - - - 

2023 - - - - - 

2024 - - - - - 

2025 - - - - - 

2026 - - - - - 

2027 - - - - - 

2028 - - - - - 

2029 - - - 0.86 0.05 

2030 - - - - - 

2031 - - - 0.86 0.05 

2032 - - - 3.42 0.19 

2033 - - - 2.57 0.14 

2034 - - - 0.86 0.05 

2035 - - - 1.71 0.10 

2036 - - - 2.57 0.14 

2037 - - - 0.86 0.05 

2038-2060 - - - - - 

Total 2.0 9.4 0.5 13.7 0.8 

Type of Formation

Year

Notes:

1) Numbers may not add due to rounding.

2) Estimates represent modeled parameters, and therefore do not represent any 

one individual project and are generally not whole numbers.

3) Under RA3, it is estimated that 26.4 of the 29 baseline projects will 

successfully deploy over the 50 year period of analysis. Chapter 5 of this Cost 

Analysis describes the deployment assumptions in more detail.

4) This analysis covers a 50 year timeframe, and includes construction, 

injection, and post-injection monitoring phases for projects in each of the 

different formations. Depending on when a given GS project begins, some of 

the post-injection monitoring may fall outside of the 50 year timeframe of this 

analysis.

5) On an annual basis, large saline projects are expected to inject more CO2 

than pilot saline projects or ER projects. 

Saline Formations Enhanced Recovery

Cost Analysis for the 3-7 November 2010 

Final GS Rule
Cost Analysis for the 3-8 November 2010 

Final GS Rule

3.4.2 Project Characteristics 

Exhibit 3.2 summarizes the project characteristics that drive differentials in costs for the 

baseline projects. Some items, such as the costs of permitting, are expected to be fairly uniform, 

regardless of project type. However, characteristics such as storage capacity, injection depth, and 

storage efficiency are all affected by the local geologic conditions. Additional information on the 

derivation of the estimates presented in Exhibit 3.2 can be found in the Geologic CO2

Sequestration Technology and Cost Analysis (EPA, 2010a). 
Exhibit 3.2 Project Characteristics By Formation Type and Size 

Cost Analysis for the 3-9 November 2010 

Final GS Rule

16

4

10

Pilot Large

Large 

Waivered

Depth to Top of Injection 

Interval (ft) 7,900 7,900 4,400 5,700 3,312

Depth to Bottom of 

Injection Interval (ft) 8,500 8,500 5,000 5,800 3,412

Metric tonnes capacity at 

100% storage efficiency 30,022,272 737,154,000 737,154,000 32,574,981 29,860,399

Storage efficiency 10.0% 10.0% 10.0% 49.4% 49.4%

Area of Review (mi2

)

 4 0.9 23.3 23.8 8.4 8.2

Total Number of wells in 

Area of Review 5 116 119 167 165

Injection Wells Required 

(total) 3 4 417

Tubing Diameter (inches) 6664

Depth of Stratigraphic 

Tests (ft.) 2,400 9,350 5,500 2,400 2,400

Number of Monitoring 

Wells above Injection 

Zone1 1.0 5.8 8.7 2.1 3.1

Number of Monitoring 

Wells into Injection Zone1 1.0 5.8 8.7 2.1 3.1

Depth of Monitoring Wells2 

(feet) 5,783 5,783 4,783 4,192 3,266

Long-string Casing of 

Monitoring Wells (diam. 

inches) 5.5 5.5 5.5 5.5 5.5

Injection Period (years)3 4 40 40 10

Source: Appendix A

Type of Project

Saline

Characteristic ER

ER 

Waivered

Notes:

(5) Projects that receive approval of a waiver of the requirement to inject below the lowermost USDW 

have reduced depth and a higher number of monitoring wells; this information is provided in the pro 

forma sheets presented in Appendix A of this Cost Analysis.

(3) GS projects in oil and gas reservoirs are assumed to operate for 30 years: 20 years under the existing 

UIC class II well regulations while the site is still used primarily for oil/gas production, and for the 

remaining 10 years under class VI for the primary purpose of long-term storage. This cost analysis 

includes costs for ER projects beginning with their transition from production to GS, i.e., 20 years into the 

30 year injection period. 

(4) The Area of Review is the size of the area estimated to encompass the plume throughout the project 

lifecycle.

(1) The number of monitoring wells per site varies according to the RA and the size of the project area 

assumed for a representative project. Shown are the required number of wells in the pro forma of each 

project type for the selected RA (RA3). 

(2) Well depths shown represent the typical (mean) monitoring well depth. Shown are the figures for 

RA3. Under RA3 and RA4, one half of the monitoring wells would be drilled to the bottom of the injection 

zone, while the other monitoring wells for RA3 and RA4, and all monitoring wells for RA1 and RA2, would 

be drilled to a depth halfway between the bottom of the lowest USDW and the top of the containment 

formation.
Cost Analysis for the 3-10 November 2010 

Final GS Rule

3.5 Sources of Uncertainty 

Because of the nascent nature of the climate change legislative landscape, the number and 

characteristics of projects comprising the baseline represent a source of uncertainty in this Cost 

Analysis. Pilot projects are defined by the type of geologic formation that will receive the CO2, 

the number of injection wells, the volume of CO2 to be injected, and the length of the injection 

period, all of which are incorporated into the baseline estimate for the GS Rule Cost Analysis. 

Some parameters, such as the number of projects and the length of the injection period, represent 

direct multipliers used to develop costs in this analysis. For example, a doubling of the number 

of projects (all else being equal) would double the estimated cost of the regulation, assuming the 

costs of those projects are not attributable to another regulation. Other uncertainties affect unit 

cost estimates, which have a less direct impact on the regulation cost; there are more than 100 

unit costs, and doubling one of them has a relatively small impact on total cost. For example, 

injection volumes would influence injection rates, the needed areal extent of the CO2 injection 

zone, and the size of the AoR, which in turn influences unit cost parameters such as the cost of 

corrective action, the numbers of injection and monitoring wells deployed, and operation and 

maintenance costs. 

At this time, the Agency regards the baseline estimates presented in this chapter as 

reasonable and representative of the current industry status. Depending on how many of these 

projects actually deploy during the 50-year period of analysis and the associated characteristics 

of those projects, the baseline estimates used in this Cost Analysis may result in an over- or 

underestimate of GS Rule costs. Detailed discussion and analyses considering the uncertainty in 

the total number of projects, the labor rates used in the Cost Analysis, and the number of 

monitoring wells per project site are presented in Section 5.9.2 of this Cost Analysis. 
Cost Analysis for the 4-1 November 2010 

Final GS Rule 

 

4. Benefits Analysis 

4.1 Introduction 

The regulatory alternatives (RAs) considered during the development of the Federal 

Requirements under the Safe Drinking Water Act (SDWA) for underground injection of carbon 

dioxide (CO2) for the purposes of Geologic Sequestration (GS Rule) were designed to protect 

underground sources of drinking water (USDWs). This protection is the direct benefit of the GS 

Rule. Each of the alternatives considered provides a level of USDW protection that corresponds 

to the stringency of the requirements of that alternative. This chapter uses a qualitative approach 

to examine the risk tradeoffs between compliance with existing requirements, (i.e., the regulatory 

baseline) and the four regulatory alternatives considered. 

The regulatory baseline, for the purpose of this analysis, consists of Agency estimates of 

the decisions regarding GS projects permitting authorities and owners and operators would have 

made under current Underground Injection Control (UIC) Program regulations. The Agency 

assumes that, absent a GS rule, permitting authorities would issue permits with conditions that 

are similar in stringency to those for Class I industrial waste disposal wells. A review of permits 

issued to early pilot projects indicates that this is the case. Current permits require that these 

projects have siting, construction, operating (i.e., injection below the lowermost USDW), and 

monitoring and testing requirements that match Class I requirements. Consistent with UIC 

Program Guidance # 83, some of these wells are classified as Class V experimental technology 

wells; however they have permit conditions that meet the requirements of Class I non-hazardous 

wells. 

As described in Section 4.2.11 of this chapter, this qualitative consideration of reduction 

in risks to USDWs under each alternative relative to the baseline scenario indicates that risks are 

reduced the most under RA4, the most prescriptive of the alternatives, and least under RA1 and 

RA2. While this analysis shows that both RA3 and RA4 significantly increase protection of 

USDWs over baseline and over RA1 and RA2, EPA does not believe that the increased 

requirements under RA4 as compared to RA3 are necessary to provide the necessary protection 

to USDWs. Therefore the United States Environmental Protection Agency (EPA) has selected 

RA3 as the best alternative. 

4.2 Relative Risks – Qualitative Analysis 

The direct benefit of the GS Rule is the protection of USDWs from potential 

contamination related to the GS activity. Due to the anticipated large CO2 injection volumes 

associated with GS, the buoyant and mobile nature of the injectate and its corrosivity in the 

presence of water, EPA has determined that tailored requirements, modeled on the existing UIC 

regulatory framework, are appropriate for wells injecting CO2 for GS.1

 Because GS is still in the 

early phases of deployment, quantitative correlations between GS project components, such as 

site characteristics or operating parameters, and the incidence of migration of fluid away from 

the injection site or leakage from the borehole are not available. This limited availability of data 

1

 A detailed description of these concerns is provided in section II.3 of the Preamble for the GS Rule. 
Cost Analysis for the 4-2 November 2010 

Final GS Rule 

precludes development of a quantitative risk analysis with regard to the probability of 

contamination. However, considerable work has been done to qualitatively assess the 

vulnerabilities in various geologic settings for GS projects that could result in an increased 

probability of leakage or fluid migration away from the injection zone or borehole. Further 

evaluation of these potential risks is provided in the Vulnerability Evaluation Framework for 

Geologic Sequestration of Carbon Dioxide (USEPA, 2010c). Section 4.3 of this document 

discusses these vulnerabilities and the broader ramifications of such contamination on the 

ecological and human environment, the protection of which is largely outside the statutory 

authority of the SDWA (except as it relates to protection of USDWs) but is included here to 

provide for a broader understanding of the nature of the risk from GS. 

The current assumptions are that: 1) CO2 injection could cause the movement of brine or 

brackish water into a USDW, thereby requiring further treatment of that water to meet drinking 

water requirements; and 2) the presence of CO2 and associated impurities could acidify 

formation fluids or the soil or rock matrix, and could mobilize arsenic or other drinking water 

contaminants that were previously adsorbed to the soil/rock matrix into the ground water. Since 

these risks are not yet quantified, the information available is not conducive to quantifying the 

potential costs avoided by mitigating them. 

It should be noted that this analysis is not intended to quantify the magnitude of the 

increase or decrease in risk relative to the baseline or determine which requirements have the 

greatest effect on the increase/decrease in risk relative to baseline or each other. Because of the 

limited implementation of GS projects, particularly at the scales intended at full deployment, no 

data exist to support a quantitative analysis of which requirements (or lack thereof) would 

decrease or increase risk to the greatest extent. 

This analysis instead presents the estimated direction of change in risk for regulatory 

alternatives of the GS Rule considered relative to the existing (baseline) conditions. The term 

“baseline” in this chapter refers to risks as they exist under current regulations, which are 

summarized in the first column of Exhibit 4.1. The terms “increase,” “decrease,” and “no 

change,” indicate the direction of risk change when comparing the regulatory alternatives to the 

baseline, and not the magnitude of any such change. A discussion of risk change associated with 

each of the regulatory components presented follows Exhibit 4.1. 
Cost Analysis for the 4-3 November 2010 

Final GS Rule 

Exhibit 4.1 Estimated Change in Risk for Components of the RAs Compared to 

the Regulatory Baseline 

Risk Change Relative to Baseline for RAs Considered BASELINE 

Alternative 1 Alternative 2 Alternative 3 Alternative 4 

1. Site Characterization

Geologic system consisting of an 

injection zone; trapping mechanism; 

and confining system to allow injection 

at proposed rates and volumes. 

Provide maps and cross sections of 

local and regional geology, Area of 

Review (AoR), and USDWs; 

characterize the overburden and 

subsurface; and provide information on 

fractures, stress, rock strength, and in 

situ fluid pressures within cap rock and 

storage reservoir. 

Increase Increase Decrease Decrease 

2. AoR and Corrective Action

AoR is either a 1⁄4 mile radius or 

determined by mathematical formula. 

Identify all wells in the AoR that 

penetrate the injection zone and 

provide a description of each; identify 

the status of corrective action for wells 

in the AoR; and remediate those 

posing the risk to USDWs. 

Increase Decrease Decrease Decrease 

3. Injection Well Construction

The well must be cased and cemented 

to prevent movement of fluids into or 

between USDWs and to withstand the 

injected materials at the anticipated 

pressure, temperature and other 

operational conditions. The well must 

be below the lowermost USDW. 

Increase Decrease 

(enhanced well 

construction 

requirements) 

Increase (waiver 

to inject above 

lowermost USDW 

in limited cases) 

Decrease 

(enhanced well 

construction 

requirements) 

Increase (waiver 

to inject above 

lowermost USDW 

in limited cases)

Decrease

4. Injection Well Operation

Limit injection pressure to avoid 

initiating new fractures or propagating 

existing fractures in the confining zone 

adjacent to the USDWs. 

Increase Increase Decrease Decrease 

5. Mechanical Integrity Testing (MIT)

Demonstrate internal mechanical 

integrity (MI) every 5 years. Conduct a 

pressure fall-off test every 5 years. 

Increase Increase Decrease Decrease 

6. Monitoring

Monitor the nature of injected fluids at a 

frequency sufficient to yield data 

representative of their characteristics. 

Conduct ground water monitoring 

within the AoR. Report quarterly on the 

characteristics of injection fluids, 

injection pressure, flow rate, volume 

and annular pressure, and the results 

of MITs. 

Increase Increase Decrease Decrease 
Cost Analysis for the 4-4 November 2010 

Final GS Rule 

Risk Change Relative to Baseline for RAs Considered BASELINE 

Alternative 1 Alternative 2 Alternative 3 Alternative 4 

7. Well Plugging, Post-Injection Site Care (PISC), and Closure 

Ensure that the well is in a state of 

static equilibrium and plugged using 

approved methods. Plugs shall be 

tagged and tested. Conduct postinjection monitoring to confirm that CO2

movement is limited to intended zones. 

Increase Decrease Decrease Decrease 

8. Financial Responsibility

Demonstrate and maintain financial 

responsibility and resources to plug 

and abandon the injection well. 

Increase No Change Decrease Decrease 

9. Emergency and Remedial Response 

No specific requirement. No Change No Change Decrease Decrease 

Overall Increase Decrease Decrease Decrease 

Note: See Chapter 2 for a detailed description of the components of each regulatory alternative. 

4.2.1 Site Characterization 

Under current regulations, owners and operators of GS wells would need to demonstrate 

that the injection site is in an area with geologic formations that can receive and confine the 

injected fluids below USDWs such that these fluids remain isolated in order to ensure protection 

of USDWs from endangerment. Owners and operators must provide maps and cross sections of 

local geologic structure, USDWs, and the AoR and characterize the overburden using data on 

size, capacity, porosity, and permeability and geomechanical information on fractures, stress, 

rock strength, and in situ fluid pressures within the cap rock and storage reservoir. 

Compared to this baseline, RA1 increases risk because the performance standard that 

wells be sited in a manner that protects USDWs from endangerment is subject to considerable 

interpretation on the part of the owner and operator and permitting authority; this may result in a 

certain portion of owners and operators not characterizing the site as thoroughly as described in 

the baseline, which could potentially result in injection at a site with fewer of the protective 

safeguards that are necessary, given the unique nature of the CO2 injectate (as described in 

Section 4.2).

RA2 does prescribe some requirements regarding the geological data to be provided, but 

these are slightly less prescriptive than the baseline. Given the importance of a detailed sitespecific geologic characterization to selecting an adequate GS site, the lack of detail in RA2 may 

increase risk relative to the baseline. 

RA3 and RA4 both have requirements that are more stringent and specific than the 

baseline. Under these alternatives the owners and operators of GS wells would be required to 

perform a detailed assessment of the geologic, hydrogeologic, geochemical and geomechanical 

properties of the proposed GS site to ensure that the wells are sited in appropriate locations and 

inject into suitable formations. Additionally, some GS owners and operators would have to 

identify additional zones above the confining zone that will impede vertical fluid movement, 

allow for pressure dissipation, and provide additional opportunities for monitoring, mitigation, 

and remediation. Characterizing these layers would be at the Director’s discretion in RA3 and 

required for all GS sites in RA4. Further, many of the specific site characterization requirements 
Cost Analysis for the 4-5 November 2010 

Final GS Rule 

in RA3 and RA4 more adequately address the unique nature of CO2 injection for GS, such as: 

requirements for structural and hydrogeologic data, seismic history, geomechanical data, and 

identification and evaluation of faults and fractures. Additionally, RA4 would require owners 

and operators to further characterize the overburden using geologic cores, outcrop data, 3-

dimensional seismic surveys, and well logs and, at the Director’s discretion, drill a stratigraphic 

test well to provide more detailed baseline data on subsurface formations. Because a more 

detailed site characterization improves the owners and operator’s and Director’s ability to 

evaluate the presence (or absence) of necessary protective geologic elements, the greater detail 

involved in characterizing the site under these RAs will likely decrease risk to USDWs relative 

to the baseline. 

4.2.2 Area of Review (AoR) and Corrective Action 

Under current Class I non-hazardous regulations, the AoR for a GS site would be either a 

1⁄4 mile radius around the injection well or would be delineated by a mathematical formula. 

Within the delineated AoR, owners and operators must identify all wells that penetrate the 

injection zone and provide information about each well's type, construction, depth, and plugging, 

and identify which wells require corrective action. Wells in the AoR that pose a risk to USDWs 

must be addressed using appropriate corrective action methods. 

RA1 does not specify a minimum size of the AoR or methods for delineating the AoR; 

additionally this RA does not include specific requirements for identifying and addressing 

improperly plugged wells in the AoR. Due to this lack of specificity and the potential to 

inadequately address all conduits for fluid movement to USDWs, RA1 may further increase risk 

relative to the baseline. 

Under RA2, owners and operators would define the AoR based on a calculated fixed 

radius or by modeling. Assuming that some owners and operators choose to develop a model, 

this represents a slight decrease in risk from baseline. Within the defined AoR, owners and 

operators must identify all artificial penetrations; determine, based on publicly available data, 

whether abandoned wells have been plugged in a manner that prevents the movement of CO2 or 

associated fluids from the storage reservoir; and employ corrective action at those wells that pose 

a risk to USDWs using appropriate methods determined in consultation with the permitting 

authority. Because they directly address the potential for USDW contamination via abandoned 

wells, the additional requirements under RA2 result in a decrease in risk relative to the baseline 

regulatory requirements. 

RA3 and RA4 may further decrease risk by requiring owners and operators to define the 

AoR using sophisticated computational models based on site specific data that accounts for 

multiphase flow and the buoyancy of CO2. This type of modeling is the most accurate tool 

available for predicting the migration of the CO2 plume and associated pressure front in the 

subsurface until the plume movement ceases and pressures stabilize, or for a fixed time period 

determined by the Director. (RA4 would require that the models predict plume and pressure front 

movement over 10,000 years.) Additionally, the use of computational models improves 

predictions of the extent and direction of the CO2 plume and pressure front to allow better 

targeting of corrective action and monitoring. Because using a fixed radius would underrepresent the size and shape of the large volumes of injected CO2, the requirement to delineate 

the AoR using computational modeling decreases risk relative to baseline. This is because GS 
Cost Analysis for the 4-6 November 2010 

Final GS Rule 

projects would likely have an AoR much larger and less uniform in size than 1⁄4 mile AoR due to 

the large volumes injected and buoyancy of CO2.

As in RA2, RA3 and RA4 would require owners and operators to identify all well 

penetrations in the AoR, determine if they have been plugged in a manner that prevents fluid 

movement, and apply corrective action to those wells as needed. RA3 and RA4 are more specific 

in that they require that corrective action be performed using materials that are compatible with 

CO2, therefore reducing risk of degrading existing well materials that come in contact with 

injected CO2. These alternatives also allow owners and operators to “phase” corrective action (if 

allowed by the Director); this is not anticipated to increase or decrease risk relative to the 

baseline. 

Finally, RA3 and RA4 would require owners and operators to periodically reevaluate the 

AoR over the life of the injection project to account for any operational changes and incorporate 

monitoring data. Both RA3 and RA4 require this reevaluation at least every five years, or 

whenever operational changes or monitoring data dictate a need. This reevaluation would help 

owners and operators to verify that the CO2 plume is moving as predicted or provide an 

opportunity to adjust the injection operation, monitoring, or corrective action to address changes 

in the predicted AoR and therefore would reduce risk relative to baseline. 

4.2.3 Injection Well Construction 

For well construction activities, the baseline specifies that GS wells must be below the 

lowermost USDW and be cased and cemented to prevent movement of fluids into USDWs. RA1, 

with no explicit technical standards, requires generally that GS wells be constructed in a manner 

that will protect USDWs from endangerment; thus, the Agency assumes that given the 

uncertainty in how this standard would be implemented, wells could potentially be constructed 

without the appropriate materials and methods that specifically address the risks associated with 

CO2 injection and risk under RA1 increases from baseline. 

RA2, RA3, and RA4 would address risk by explicitly requiring that GS wells be 

constructed and cemented with casing, tubing, and packer that meet API or ASTM International 

standards and are compatible with CO2. Each RA provides increasing specificity. RA 2 allows 

the Director’s discretion to approve well materials and design. RA3 specifies the use of 

cemented surface casing (base of the lowermost USDW to surface) and long string casing 

(cemented from injection zone to surface) must be compatible with fluids with which they may 

be expected to come into contact. Additionally, RA3 also allows the use of horizontal well 

drilling techniques for GS wells which helps to reduce the number of injection wells potentially 

needed at a GS site thereby reducing the number of potential leakage pathways into USDWs. 

RA4 would require that the surface casing extend 100 feet below the lowermost USDW and the 

use of specialized, corrosion-resistant materials such as metal alloy casing, specialized tubing, 

and latex cements. These specific elements, which address the unique characteristics of CO2 in 

the presence of water and are demonstrated to reduce the chances of compromising well 

integrity, are therefore expected to decrease risk relative to the baseline. 
Cost Analysis for the 4-7 November 2010 

Final GS Rule 

EPA assumes in the analysis that under RA1 and RA2 operators would inject below the 

lowermost USDW, except for in limited cases when a waiver of this depth requirement was 

approved, as discussed further below with regard to RA3. The explicit formal waiver application 

process and additional permit conditions that directly address the presence of USDWs above and 

below the injection zone will result in a minimal increase in risk for RAs 1-3 relative to the 

baseline. 

RA4 would require that in all cases, operators inject below the lowermost USDW, as 

under the baseline scenario. This would apply in most cases to RA3, however, as for RA1 and 

RA2, owners and operators would have the option in limited circumstances to seek a waiver 

from this requirement to allow injection into non-USDW formations between USDWs in cases 

where there are deep USDWs and/or where injection into the lowermost USDW would result in 

impractical or technically infeasible well construction. The explicit formal waiver application 

process and additional permit conditions that directly address the presence of USDWs above and 

below the injection zone will result in a minimal increase in risk for RA3 relative to the baseline. 

In these limited circumstances owners and operators would be required to submit additional data 

and be subject to additional requirements above and beyond the RA3 requirements for wells 

injecting below the lowermost USDWs as added protection. By giving owners and operators the 

option of injecting above the lowermost USDW via the waiver process, there is an incremental 

risk increase relative to complete prohibition of the practice as under the baseline and RA4. 

4.2.4 Injection Well Operation 

Under current regulations, injection must be conducted such that the pressure during 

injection does not initiate new fractures or propagate existing fractures in the confining zone 

adjacent to the USDWs. . 

RA1 applies the performance standard that injection wells must be operated in a manner 

that protects USDWs from endangerment but does not explicitly limit injection pressure. 

Therefore, the Agency assumes that in a portion of the cases, appropriate injection pressure 

limitations may not be employed, suggesting an increase in risk for RA1 from the baseline. RA2 

has similar requirements as the baseline but allows for higher injection pressure at the Director’s 

discretion; to the extent that it is possible to allow pressures that increase the risk of fracture, 

RA2 may potentially increase risk relative to baseline. 

 

RA3 and RA4 require that owners and operators limit injection pressure to less than the 

fracture pressure of the injection formation in any portion of the area defined by the anticipated 

pressure front; RA4 additionally considers the capillary entry pressure at any point in the 

lowermost portion of the confining zone. To the extent that these limitations reduce the chance of 

initiating new fractures or propagating existing fractures in the injection zone, they decrease risk 

relative to the baseline. 

RA4 additionally requires that the depth be sufficient to retain the CO2 in a supercritical 

state; this can help reduce potential MI concerns associated with phase changes and decreases 

risk relative to baseline. 

RA3 and RA4 also require that injection wells are equipped with down-hole shut-off 

systems or other safety mechanisms, e.g., check valves, that engage if any critical operating 
Cost Analysis for the 4-8 November 2010 

Final GS Rule 

 

parameters are exceeded and describe the remedial actions that owners and operators must take if 

the devices engage. This requirement under RA3 allows for director’s discretion unless wells are 

located in offshore territorial State waters2 where they are required because EPA believes that 

devices besides down-hole shut-off systems, such as check valves, may provide equal protection 

in some instances and RA3 allows for their use, if approved by the Director, provided they offer 

an equal level of protection to USDWs as an automatic down-hole shut-off device. By not 

allowing the director to approve an alternative device in any case, RA4 offers the most 

protection, but possibly at an unnecessary cost in terms of the increased risk for damage to the 

wells during operation. The requirement for down-hole safety mechanisms under RA3 and RA4 

can help prevent leaks in the well or fractures in the confining layer that may in turn result in 

fluid movement that endangers a USDW. They also help assure that problems within the well 

system are addressed immediately, decreasing risk relative to the baseline. 

Additionally, RA4 allows the Director to require that an odorant or a tracer be introduced 

to the injected CO2 to facilitate early detection of leaks or movement outside of the intended 

injection zone in order to prevent endangerment of USDWs. To the extent that odorants or 

tracers are detected and result in modifications to the injection operation or early actions, RA4 

further decreases risk relative to baseline. 

Overall, under RA3 and RA4, there is expected to be a decrease in risk relative to the 

baseline for injection well operation requirements. 

4.2.5 Mechanical Integrity Testing 

Under the baseline, GS well owners and operators will be required to demonstrate that 

wells have internal mechanical integrity (MI) (i.e., there is no significant leak in the casing, 

tubing, or packer) every five years. Additionally, owners and operators may be required to 

conduct biannual tracer surveys of the bottom-hole cement using a CO2-soluble isotope, and 

pressure fall-off tests every five years. 

The general performance based measure of RA1, to monitor wells in a manner and 

frequency that protects USDWs from endangerment allows for greater interpretation in setting 

permit conditions. In some cases, directors may specify mechanical integrity testing (MIT) types 

and frequencies that are less protective than baseline requirements. Therefore, under RA1 there 

is a potential increase in the relative risk to the baseline for MIT requirements. 

RA2 does not specify a testing frequency; rather, it provides flexibility to permitting 

authorities to specify MIT methods and testing frequencies that are appropriate to the specific 

project. As such, the Agency assumes that Directors may choose a testing interval of more than 5 

years which could potentially allow MI problems to go undetected for longer periods of time; 

therefore, RA2 potentially increases risk from baseline. 

Under RA3 and RA4, owners and operators must demonstrate internal MI by 

continuously monitoring injection pressure, flow rate, injected volumes, and pressure on the 

annulus between the tubing and the long string casing. Continuous monitoring can provide 

2

 Requirements specific to ocean injection wells in the Federal outer continental shelf are to be proposed under a 

separate regulation by the Minerals Management Service, and are not included in the GS Rule. 
Cost Analysis for the 4-9 November 2010 

Final GS Rule 

almost immediate warning that there is a problem with the injection well’s internal MI, which is 

one of the most significant concerns, given the corrosive nature of CO2. This requirement would 

directly address the unique nature of CO2 injection for GS and therefore is expected to decrease 

risk from baseline. 

 

Under RA3 and RA4, owners and operators must demonstrate external MI using an 

approved tracer survey such as an oxygen-activation log or temperature or noise logs. The 

Director also has the discretion to require a casing inspection log to determine the presence or 

absence of any casing corrosion. The external MIT requirements in these RAs differ in their 

frequency: they must be performed at least annually in RA3 and twice annually in RA4. 

The more specific MIT requirements and the greater frequency of testing in RA3 and 

RA4 decrease risk from the baseline by providing earlier indication of any MI problems, and 

potentially to a greater degree in RA4, given the shorter frequencies. 

4.2.6 Testing, Monitoring, and Reporting 

Under the baseline, owners and operators of GS wells would monitor the nature of 

injected fluids; conduct ground water monitoring within the AoR (at the Director’s discretion); 

and report quarterly on these results and on the characteristics of injection fluids, injection 

pressure, flow rate, volume and annular pressure, and the results of MITs. 

RA1 would leave the specific monitoring requirements to the discretion of the Director; 

potentially reducing the amount of monitoring performed relative to the baseline and thus would 

mitigate less risk than the baseline scenario. 

Under RA2, owners and operators would monitor the nature of injected fluids at a 

frequency sufficient to yield data representative of their characteristics. Owners and operators 

would report annually on the characteristics of injection fluids, injection pressure, flow rate, 

temperature, volume and annular pressure, and on the results of MITs. Because ground water 

monitoring would not be performed under RA2, EPA assumes that this alternative would 

increase risk relative to baseline because it eliminates an opportunity to detect unacceptable 

movement of CO2 or other fluids. 

Under RA3, owners and operators would develop, implement, and periodically review a 

plan for conducting testing and monitoring that is tailored to the site. This RA includes additional 

monitoring, including injectate monitoring; corrosion monitoring of the well’s tubular, 

mechanical and cement components; pressure fall-off testing; CO2 plume and pressure front 

tracking; and ground water quality monitoring. Under RA3, owners and operators will report 

operating and monitoring results twice per year in operating reports, unless the monthly MIT or 

other periodic tests revealed operations were somehow compromised, in which case 24 hour 

notification is required. Because the required monitoring plan and these monitoring requirements 

are tailored to the risks associated with injection of large volumes of CO2 and to the specific 

aspects of the site and operational conditions, RA3 is expected to mitigate more risk than the 

baseline requirements. 

RA4 includes all of the monitoring requirements in RA3, with additional specificity on 

some elements. In addition to corrosion monitoring, owners and operators would need to 
Cost Analysis for the 4-10 November 2010 

Final GS Rule 

demonstrate compatibility of well materials to the injected CO2. Owners and operators would 

perform a pressure fall-off test annually instead of every 5 years as with RA3. The ground water 

monitoring requirements are more specific than under RA3, requiring that the monitoring wells 

are constructed with corrosion-resistant materials. It requires that the surface air and soil gas 

monitoring regime include all artificial penetrations within the AoR and other sensitive areas, 

e.g., in buildings and manmade surface structures that are intended for human occupancy. 

Finally, under RA4, owners and operators would submit monitoring reports every month. With 

additional monitoring requirements that are tailored to the GS site and address the specific 

contamination concerns associated with GS, RA4 would also be expected to mitigate more risk 

than the baseline requirements. 

4.2.7 Injection Well Plugging, Post-Injection Site Care (PISC), and Site Closure 

At the conclusion of injection of CO2 for GS, the injection well must be plugged in a way 

that ensures that it would not serve as a conduit for future fluid movement. Under the baseline, 

owners and operators would ensure that the well is in a state of static equilibrium, plug the well 

using approved methods, and tag and test all plugs. Owners and operators would also conduct 

post-injection monitoring to confirm that the CO2 movement is limited to intended zones. 

RA1 has no specific requirements with respect to plugging and post-injection monitoring 

and therefore increases risk relative to the baseline. RA2 includes some specific injection well 

plugging requirements, including ensuring that the well is in a state of static equilibrium, 

plugging the well using approved methods, and tagging and testing all plugs. This RA also 

would require owners and operators to conduct post-injection monitoring for 10 years per a 

Director-approved plan. The inclusion of specific PISC requirements that CO2 movement be 

monitored following injection activities to ensure that it is limited to intended zones in RA2 

would pose a decreased risk relative to the baseline. 

RA3 and RA4 contain more specific requirements for well plugging and PISC and site 

closure. Both alternatives would require owners and operators to flush the well with a buffer 

fluid, determine bottom-hole reservoir pressure, perform a final external MIT, and plug the well 

in a manner using approved methods that will prevent the movement of fluid that may endanger 

USDWs. Additionally, these RAs require owners and operators to develop and implement a plan 

to conduct PISC monitoring, (which may include pressure monitoring; geophysical monitoring, 

if appropriate; and geochemical monitoring in and above the injection zone and the USDW) to 

confirm that CO2 movement is limited to intended zones. The sole difference between the 

alternatives is the time frame: 50 years for RA3 (the Director has the discretion to shorten or 

lengthen timeframe based on data submitted as part of the permit application, or collected during 

PISC) and 100 years for RA4. Following the PISC monitoring, owners and operators would 

perform a non-endangerment demonstration to ensure that there is no threat to USDWs and that 

no further monitoring is necessary. At this point, closure of the site is authorized. 

The requirements in RA3 and RA4 for PISC monitoring for extended time frames that are 

tailored to site-specific conditions and the operational history of the injection operation and a 

final non-endangerment demonstration are specific to the unique nature of GS and are estimated 

to mitigate more risk than under the baseline regulatory scenario. 
Cost Analysis for the 4-11 November 2010 

Final GS Rule 

4.2.8 Financial Responsibility 

Under the baseline regulatory scenario, owners and operators must demonstrate that they 

have the resources necessary to plug and abandon the injection well through a performance bond, 

or other appropriate means. 

RA1 does not have such a requirement, and to the extent that there would not be 

resources to plug the injection well at the end of injection activities, suggests an increase in risk 

relative to the baseline. RA2 would require the operator to provide through a performance bond, 

or other appropriate means, the resources necessary to plug the well; this is the same requirement 

as in the baseline; thus there is no change relative to baseline. 

RA3 and RA4 require the operator to demonstrate and maintain financial responsibility 

for not only plugging the injection well, but also for all needed corrective action, emergency and 

remedial response, and PISC and closure. Owners and operators would need to adjust the cost 

estimates for these activities periodically to account for inflation and other conditions that may 

affect costs. RA3 and RA4 mitigate more risk relative to the baseline because they provide more 

assurance that funds will be available to pay for the necessary activities and also provide for 

funds to address additional protective activities, e.g., corrective action, PISC, and emergency and 

remedial response. 

4.2.9 Emergency and Remedial Response 

Emergency and remedial response plans outline the specific steps an operator would take 

in the event of evidence that injected fluids are endangering USDWs. Although injection well 

owners and operators are required to cease injection and take necessary actions if they discover 

evidence of USDW endangerment, the Class I non-hazardous regulations do not have a specific 

requirement to develop and implement such a plan; thus, the baseline is presumed to have no 

such requirement. RA1 and RA2 have no such requirements and are assumed to present no 

change in risk relative to the baseline. 

RA3 and RA4 would require GS well owners and operators to develop and periodically 

review an emergency and remedial response plan that describes actions to be taken to address 

events that may cause an endangerment to a USDW during the construction, operation and PISC 

periods of a GS project. In the event that there is evidence that the CO2 or pressure front is 

endangering USDWs, the operator would cease injection, take necessary steps to identify and 

characterize the extent of any release, and implement the emergency and remedial response plan. 

By providing a means to address a release of CO2 or endangerment of USDWs, RA3 and RA4 

decrease risk relative to the baseline. By following this site specific plan for this possible event, 

the steps that will be taken will prevent even greater damage and will facilitate prompt well 

repair if that is necessary. 

4.2.10 Adaptive Regulatory Process 

Under RA 3 and RA4, once the rule is final EPA will continue to collect and review all 

available information related to GS research to determine the need for modifications of the 

minimum Federal requirements for Class VI wells. Every six years, the Agency will collect and 

review data to determine if modifications to the requirements are necessary. By allowing for the 
Cost Analysis for the 4-12 November 2010 

Final GS Rule 

possible inclusion of added requirements (or modification of existing requirements) to ensure the 

safe injection and sequestering of CO2, RA3 and RA4 would result in a decrease in risk relative 

to the baseline regulatory requirements. RA1 and RA2 does not explicitly specify the inclusion 

of periodic evaluation for Class VI wells, thus there would be no change in risk relative to the 

baseline. 

4.2.11 Overall Estimate of Change in Risk 

Sections 4.2.1 through 4.2.11 describe the change in the direction of risk based on 

consideration of each regulatory alternative 1 – 4 relative to the baseline regulatory requirements. 

These changes were assessed for each component category of the GS Rule and RAs. An overall 

assessment of the direction of risk change for each regulatory alternative as a whole relative to 

the baseline requires consideration of the relative importance of each component to the risk 

mitigation provided by the alternative. 

As shown in Exhibit 4.1, EPA estimates that under RA1, risk will move from the baseline 

in the direction of increase for eight of the ten components assessed; no change in risk is 

estimated related to emergency and remedial response. Thus, EPA estimates an overall increase 

in risk relative to the baseline for RA1. 

Under RA2, EPA estimates that risk will increase for four of the eleven programmatic 

components of the GS rule (geologic characterization, injection well operation, MIT, and 

monitoring); that it will decrease in three categories (AoR /corrective action, well construction, 

and well plugging/PISC); and that it will not change from the baseline relative to four categories 

(financial responsibility, emergency and remedial response, injection depth waivers, and the 

adaptive rulemaking process). Although this alternative generally has many of the same 

requirements as the baseline, RA2 allows the Director to exercise discretion to modify these 

requirements. This introduces the potential for some permit standards to be less stringent than 

under the baseline. However, given the importance of the AoR/corrective action and construction 

components (which decrease risk relative to the baseline), it is expected that the overall resulting 

change in risk will be a slight decrease in comparison to the baseline. 

Both RA3 and RA4 uniformly decrease risk across all regulatory components, indicating 

an overall decrease in risk under both regulatory alternatives. This is primarily attributed to the 

additional specificity in each of these alternatives that are tailored to address the unique nature of 

GS. However, in many instances the requirements under RA4 are more prescriptive or specify 

better technologies than under RA3; this results in the potential for risk reduction to be greatest 

under RA4. 
Cost Analysis for the 4-13 November 2010 

Final GS Rule 

4.3 Ancillary Benefits 

In addition to the direct benefits associated with the GS Rule, the Agency has identified 

potential benefits in the protections provided to affected entities that are not directly addressed 

under the authority of the UIC Program as prescribed under the SDWA, which is limited to 

protection of USDWs. These ancillary protections apply to categories such as human health and 

welfare, the atmosphere, ecological receptors, surface water, and the physical environment. Risk 

to these entities from GS is not well understood; however, to the extent that such risk exists, the 

GS Rule mitigates it by requiring measures to protect USDWs from contamination. These 

measures include prevention of fluid migration away from the storage formation and injection 

site and extensive monitoring both during operations and after injection has ceased. These 

ancillary benefits are summarized below and are described in greater detail in the Vulnerability 

Evaluation Framework for Geologic Sequestration of Carbon Dioxide (USEPA, 2010c). 

Human Health/Welfare 

 By requiring owners and operators to employ measures to protect USDWs from 

endangerment, the GS Rule mitigates the risk of illness associated with ingestion of acidic or 

brackish water or water that may be contaminated by materials that are mobilized from the 

soil/rock matrix. These measures include monitoring requirements and appropriate operational 

thresholds that decrease the potential for large scale CO2 leaks. As CO2 is an asphyxiant, humans 

can experience adverse health effects at elevated CO2 concentrations (Raschi et al., 1997), and 

extremely high concentrations (above 30 percent) can result in fatality. Although the likelihood 

of CO2 release from a GS operation is not understood in quantified terms, the GS Rule mitigates 

this risk. 

Cultural and recreational resources may also be preserved by the GS Rule. Requirements 

for geological characterization of the well site and monitoring of the movement of the CO2

plume will help maintain the physical integrity of the project surface area by mitigating potential 

risk of uplift of the surface topography or induced seismicity. Ecological resources that are used 

as recreation resources, such as rivers and lakes, will also experience reduced risk of 

contamination as a result of the rule by confining the CO2 and brine below USDWs. The GS 

Rule may also mitigate potential risk to forests and other flora by protecting it from the harmful 

effects of exposure to elevated CO2 levels. 

Contaminated ground and surface water could have effects on surface and subsurface 

economic resources. The site characterization and monitoring aspects of the GS Rule mitigate 

this risk by ensuring fluid isolation. This ancillary benefit to the rule extends to forestry, 

agricultural, and other surface industries, which could experience reduced yields and diminished 

utility of land if ground or surface water is contaminated by CO2, brine, or mobilized 

contaminants. It also mitigates risk to subsurface resources such as oil and gas reservoirs, which 

could be affected by pressure from CO2 plumes. 

Surface Water 

Through geologic siting and well construction standards that prevent fluid movement in 

the subsurface and monitoring standards that would provide early warning of leakage out of 

intended zones, the GS Rule mitigates potential risk of contamination of surface water from GS 
Cost Analysis for the 4-14 November 2010 

Final GS Rule 

operations. Specifically, the GS Rule mitigates the risk of water quality degradation that is 

associated with CO2 contamination, including: increased salinity, increased acidity, and 

mobilization of metals and impurities. It also mitigates the risk that pressure from CO2 injection 

will affect regional ground water flow, which could affect the availability of water in certain 

areas. 

Ecological Receptors 

By requiring measures to contain the CO2 and preventing fluid movement away from the 

injection site and storage formation, the GS Rule helps to mitigate the risk that some animal 

species could experience negative health effects associated with CO2 exposure. Acidification of 

surface water due to CO2 contamination could kill species sensitive to changes in pH living in or 

consuming the water, and species that dwell in the soil may be especially vulnerable to the 

effects of contaminated surface water and soil. CO2 would also lower carbonate levels in water 

which would significantly affect calcifying aquatic organisms, which could be unable to form 

shells in acidic water. 

Atmosphere 

The GS Rule’s requirements that reduce the likelihood of CO2 migrating to USDWs will 

mitigate the risk of sequestered CO2 escaping to the atmosphere, helping to ensure that the 

benefits of reduced CO2 emissions to the atmosphere with regard to climate change are 

maintained. The well plugging and PISC requirements in the GS Rule further reduce the 

potential for leakage of CO2 into the atmosphere and ensure effective long-term storage. 

Additionally, plants relying on a water source that is impacted by injected CO2 may be 

intolerant of the pH change or high concentrations of CO2, which can inhibit root respiration and 

hinder oxygen uptake and plant growth. In the case of CO2 contamination of plant life, animal 

species depending on these plants would also suffer detrimental health effects. The extensive 

geologic siting process, well construction, and monitoring requirements associated with the GS 

Rule mitigate these potential risks by guarding against CO2 leakage. 

Physical Environment 

Uplift and induced seismic activity as a result of subsurface pressure changes associated 

with injecting large volumes of CO2 could have significant financial ramifications as well as 

negative effects on human health. Subsurface pressure changes that exceed a formation’s 

geomechanical strength could cause fracturing or reactivate faults and increase the potential for 

the aforementioned effects. The GS Rule helps to mitigate this kind of risk through evaluation of 

subsurface geomechanics, the presence of transmissive faults and fractures, and the seismic 

history of the site; injection pressure limitations; and monitoring of the CO2 plume and pressure 

changes.

Social Cost of Carbon 

The GS rule has many requirements that help ensure that CO2 is not being lost from GS 

sites to the atmosphere. They include pressure integrity requirements for injection wells, various 

types of CO2 detection and monitoring requirements, remedial action requirements, and required 
Cost Analysis for the 4-15 November 2010 

Final GS Rule 

minimum criteria for GS sites. These requirements provide assurance that sequestered CO2

remains underground, which in turn provide benefits in terms of avoided emissions from GS 

sites. In other words, if CO2 leaked out of a given GS site, a net reduction in emissions would not 

be realized. Therefore, ensuring that sequestered CO2 remains underground has a net benefit. The 

cost to society of CO2 emissions (and thus the value of avoided emissions) can be measured in 

dollars using an emerging metric called the Social Cost of Carbon (SCC). The SCC estimates 

allow benefits from reduced emissions in any future year to be estimated by multiplying the 

change in emissions in that year by the SCC value appropriate for that year. SCC estimates 

represent the dollar value of a one-ton change in CO2 emissions and reflect underlying 

assumptions about the growth of emissions and changes in socio-economic trajectories. In 

February 2010, an interagency working group published SCC estimates for use in regulatory 

impact analyses of government regulations. 

The interagency group selected four CO2 SCC estimates for use in regulatory analyses. 

For 2010, these estimates are $5, $21, $35, and $65 (in 2007 dollars). The first three estimates 

are based on the average SCC across models and socio-economic and emissions scenarios at the 

5, 3, and 2.5 percent discount rates, respectively. The fourth value, which corresponds to the 95th 

percentile SCC estimate at a 3 percent discount rate, represents higher-than-expected impacts 

from temperature change further out in the tails of the SCC distribution. The central value is the 

average SCC across models at the 3 percent discount rate. For purposes of capturing the 

uncertainties involved in regulatory impact analysis, the interagency group emphasized the 

importance and value of considering the full range. These SCC estimates also grow over time. 

For instance, the central value increases to $24 per ton of CO2 in 2015 and $26 per ton of CO2 in 

2020. 

Due to the fact that this final rule does not require owners or operators to mitigate climate 

impacts through geologic sequestration of CO2, the benefits (which can be measured using SCC) 

associated with geologic sequestration may be better ascribed to regulations that require and/or 

provide incentives for geologic sequestration. However, without the requirements of the GS 

Rule, a regulatory framework would not be in place to help ensure that CO2 is not being lost 

from GS sites to the atmosphere. Therefore, a small (but unquantified) portion of the benefits of 

those other regulations may be attributable to the GS Rule. 

4.4 Uncertainty in Benefits Estimates 

 In the absence of data allowing a quantitative assessment of GS rule benefits, the 

assessment of relative risks (and associated benefit potential) posed by each alternative 

considered is subjective. The four regulatory alternatives considered in this analysis represent 

increasing levels of regulatory certainty that are assumed to correlate with relative risk. This 

assumption is based on the potential differences in interpretations that can be made when sole 

discretion is given to different permitting authorities. The interpretation of how this discretion 

will be utilized is the major driver of uncertainty within the relative risk estimates presented in 

this chapter. EPA’s experience within the UIC Program suggests that in those areas where 

discretion is allowed there are distinct differences in interpretation among permitting authorities 

nationally. The magnitude and impact of such differences is difficult to predict for the GS rule, 

but EPA believes its general interpretation of a decrease in potential risks in correlation to 

decreasing regulatory discretion is justified. 
Cost Analysis for the 5-1 November 2010 

Final GS Rule

5. Cost Analysis 

5.1 Introduction 

This chapter presents an estimate of the national costs of the Federal Requirements under 

the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells (the GS Rule), as well as a brief qualitative discussion comparing costs 

to the benefits anticipated to accrue as a result of the GS Rule. This national cost estimate, 

prepared by the United States Environmental Protection Agency (EPA), is a summation of costs 

to owners and operators of GS wells and to the permitting authorities for complying with and 

implementing the GS Rule requirements. To develop this estimate, EPA calculated the 

incremental cost for GS Rule components that expand current GS operating practices to mitigate 

the risks to underground sources of drinking water (USDWs) that are particular to injection of 

CO2 for the purposes of long-term storage. The GS Rule defines a new class of injection well 

(Class VI), along with technical criteria that tailor the existing UIC Program regulatory 

framework to address the unique nature of CO2 injection for long-term storage in anticipation of 

the eventual use of GS to reduce CO2 emissions to the atmosphere. Technical components of the 

GS Rule include geologic site characterization; area of review (AoR) and corrective action; 

injection well construction; injection well operation; mechanical integrity testing (MIT); 

monitoring; well plugging, post-injection site care (PISC) and site closure; financial 

responsibility; and emergency and remedial response. 

Although the national costs estimated in this Cost Analysis are representative of costs 

that EPA expects owners and operators and permitting authorities to incur under the GS Rule, 

assumptions were made to facilitate development of a reasonably simple, transparent model. The 

cost model elements and assumptions therefore may not correspond directly with all rule 

requirements; for example, the Cost Analysis makes assumptions about the number of 

monitoring wells to be constructed although, in reality, the owners and operators and Director 

will determine this requirement on a site specific basis. The GS Rule language for some 

components provides for discretion on the part of the UIC Program Director and for site specific 

variability, therefore EPA has predicted how the Directors will apply this latitude for the purpose 

of estimating costs. EPA considered the various hydrogeologic conditions that might prevail in 

baseline projects and the level of stringency in protective measures that Directors would perceive 

as necessary for measures that are less than prescriptive in the GS Rule. 

The detailed descriptions and analyses presented in this chapter focus on the selected 

regulatory alternative (Regulatory Alternative 3, or RA3); however, assumptions and cost 

estimates for the baseline (RA 0) and the other three RAs considered (RAs 1, 2, and 4) are 

presented in the exhibits in this chapter. Incremental costs with respect to the baseline are shown 

for the selected RA as well as the other alternatives considered during the regulatory 

development process. In addition, some exhibits include cost elements that apply to at least one 

alternative but not to the selected alternative, RA3. Furthermore, some exhibits include costs that 

correspond to activities that the owners and operators will undertake under any regulatory 

scenario (i.e., lease of land or pore space) but are outside the authority of the Safe Drinking 

Water Act (SDWA) and therefore are not attributable to the GS Rule; these are included in 

estimates of total costs but not in the incremental rule costs. 
Cost Analysis for the 5-2 November 2010 

Final GS Rule

Owner and operator costs are estimated based on the scale of CO2 injection into the 

subsurface and the type of formation serving as a reservoir. At the time of this rulemaking, EPA 

anticipates the following types of GS projects will predominate in the near and predictable 

future: pilot-scale projects in saline reservoirs and large-scale projects in saline and oil and gas 

reservoirs. Permitting authority costs include a variety of implementation and oversight activities 

such as training, data system updates, primacy applications, permit reviews and approvals 

(including waiver application review), consultations, and report reviews (i.e., monitoring results), 

as well as all associated recordkeeping. 

 

EPA estimated owner and operator costs for the technical rule components using 

equipment price lists and quotes, wage rates from government sources (e.g., Bureau of Labor 

Statistics (BLS)) and industry sources, stakeholder input, and information developed for similar 

analyses (e.g., the UIC Program Information Collection Request (ICR)). The national costs are 

estimated using a spreadsheet model specifically developed for the GS Rule. The main advantage 

to this modeling approach is that it effectively captures point estimates of all cost information 

and presents them in a transparent manner. This information forms the basis for examining 

impacts of the GS Rule on owners and operators of GS wells. 

The remainder of this chapter is organized as follows: 

• Section 5.2 describes the general costing methodology and compliance assumptions 

used to estimate national costs for the GS Rule. 

• Section 5.3 describes the methodology for projecting costs over a 50-year period 

according to the GS Rule compliance schedule, estimating the present value of each 

cost, and annualizing each cost over this period. 

• Section 5.4 describes the methodology for developing costs for all rule components. 

• Section 5.5 presents consumer cost estimates. 

• Section 5.6 presents the total annualized costs for the GS Rule and compares them to 

estimates for the other regulatory alternatives considered. 

• Section 5.7 qualitatively compares the estimated costs for the GS Rule to the 

anticipated benefits. 

• Section 5.8 discusses other economic measures. 

• Section 5.9 presents a discussion of non-quantified costs and uncertainties in cost. 

5.2 General Cost Assumptions and Methodology 

The GS Rule Cost Model incorporates several data elements, including unit costs for each 

compliance activity, the baseline number of projects deploying or in operation during each year 
Cost Analysis for the 5-3 November 2010 

Final GS Rule

 

of the 50-year period of analysis, labor rates (discussed in Section 5.2.1), and general and 

administrative (G&A) costs (Section 5.2.2). 

The cost model comprises the following components: characteristic profiles for the five 

types of projects that represent the 291 projects of the cost analysis baseline; unit costs for each 

compliance activity; a site selection factor to account for the cost of geologic site 

characterization of sites that turn out to be unusable2

; an ER Applicability factor to account for 

how costs apply differently to transitioning GS projects (projects converting from existing Class 

II enhanced recovery (ER) operations to long-term storage operations) compared to saline 

projects; an application factor3

 and a schedule specific to each RA for each compliance activity; 

calculation of the costs for each compliance activity in nondiscounted, present value, and 

annualized dollars; and summation of these costs by rule component and by cost type (one-time, 

capital, and operations and maintenance (O&M) expenditures). 

The five project type profiles contain characteristics that define each project type 

represented in the 29 baseline projects, included in Appendix A to this Cost Analysis. Some of 

these characteristics vary by reservoir formation: the depth of the injection zone (IZ) and the 

primary containment formation are deepest in saline formations, and shallower in oil and gas 

reservoirs. Additionally, limited projects with an approved waiver to inject between USDWs are 

likely to be shallower than those with injection zones below the lowermost USDW. Other 

characteristics vary by the GS project scale: the injection period for all pilot-scale projects is 

assumed to be 4 years, and for large-scale saline projects is 40 years. The injection period for 

existing Class II ER projects that plans to transition to a Class VI project for the primary purpose 

of long-term storage is 10 years (after 20 years of Class II ER). The assumptions used in 

developing the GS Rule baseline are described in Chapter 3 (Baseline Analysis) of the Cost 

Analysis. 

The model is based on an algorithm for each compliance activity, which multiplies the 

unit cost by certain variables from the project type profiles and by the factors appropriate for a 

given project type (RA application factor, site selection factor, enhanced recovery application 

factor) to produce a project level cost (as opposed to a rule level cost) for each compliance 

activity. Descriptions of the unit costs, application factors, and algorithms developed in this 

analysis are provided in Appendix B, and the detailed derivation and sources of the unit costs are 

presented in the Geologic CO2 Sequestration Technology and Cost Analysis (EPA, 2010a). 

The model then multiplies the project level cost for each compliance activity by the 

corresponding number of respondents for that cost type, project type, and year to produce an 

1

 This number does not represent 29 specific projects, but rather a modeled probability of projects that in total adds 

up to 29. Due to the fractional probability of certain types of projects occurring at certain times, fractions of projects 

will be referred to thought this chapter. 

2

 The site selection factor applies to only the geologic site characterization costs. For saline projects, the factor is 

25%. This multiplies the geologic site characterization unit costs by four to account for the assumption that one out 

of four sites that are geologically characterized is determined to be suitable for GS. Put another way, an operator will 

on average have to characterize four sites to find one suitable one. For ER projects, the site selection factor is 100% 

(all sites chosen for GS using ER sites are assumed to be suitable sites). 

3

 The application factor is a percentage between 0 and 100 percent that is EPA’s best estimate of the percentage of 

owners and operators, or the extent to which all owners and operators, will engage in a given compliance activity; it 

takes into account those aspects of the rule that allow for Director discretion and site specific variability, as well as 

general trends in the methods or equipment used by the GS industry. 
Cost Analysis for the 5-4 November 2010 

Final GS Rule

 

annual rule cost for each compliance activity in each of the 50 years in the analysis period. The 

model calculates these annual estimates in nondiscounted dollars and in present value and 

annualized dollars discounted at both 3 percent and 7 percent. The model then summarizes the 

GS Rule costs for these activities for the 50-year period of analysis by rule component and 

further by cost type: one-time, capital, and O&M expenditures. 

Lastly, the model compares the baseline regulatory scenario (RA0) to each of the RAs 

(RA1 – RA4) to derive the incremental costs attributed to the GS Rule. The regulatory baseline, 

for the purpose of this analysis, consists of EPA estimates of the decisions regarding GS projects 

that permitting authorities as well as owners and operators would have made under current UIC 

Program regulations. EPA assumes that, absent a GS Rule, permitting authorities would issue 

permits with conditions that are similar in stringency to those for Class I industrial waste 

disposal wells. A review of permits issued to early pilot-scale projects indicates that this is the 

case. Current permits require that these projects have siting, construction, operating (i.e., 

injection below the lowermost USDW), and monitoring and testing requirements that match 

Class I requirements. Consistent with UIC Program Guidance # 83 (EPA, 2007), some of these 

wells are classified as Class V experimental technology wells; however they have permit 

conditions that meet the requirements of Class I non-hazardous wells. 

5.2.1 Labor Rates 

 For costing purposes, EPA estimated the labor needs and hourly labor rates for two 

occupations: geoscientists and mining and geological engineers (see Exhibit 5.1). EPA obtained 

the rates for geoscientists from the American Association of Petroleum Geologists’ (AAPG’s) 

2008-2009 annual salary survey. Assuming 15-19 years of experience, the hourly rate is $67.02 

(based on an annual salary of $139,400).4

 EPA obtained rates for mining and geological 

engineers from the Society for Petroleum Engineers (SPE) annual survey. For a reservoir 

engineer with 11-15 years of experience, the hourly rate is $69.14 (based on an annual salary of 

$143,800).5 EPA multiplied these rates by a loading factor of 1.6, as suggested by EPA’s 2005 

ICR Handbook, to account for overhead and benefits. Thus, the loaded labor rate for 

geoscientists is $107.23, and the rate for engineers is $110.62. 

 For this analysis, EPA assumed that the average hourly labor rate for a State employee is 

$30.90, based on the BLS average hourly wage for workers in the life, physical, and social 

science occupations in 2008.6

 This rate was multiplied by 1.6 to get a loaded rate of $49.44. The 

base hourly labor rate for EPA Regions directly implementing the Class VI program in States 

without primacy is $31.34. This rate is based on Federal employee pay scales issued by the U.S. 

Office of Personnel and Management7

 (OPM) and was multiplied by 1.6 for a loaded rate of 

$50.14. 

4

 http://www. aapg. org/explorer/salarysurvey. cfm 5

 Society for Petroleum Engineers Annual Membership Salary Survey Highlight Report. Prepared by Western 

Management Group. September 2008. p. 12 

http://www. spe. org/spe-site/spe/spe/career/salary_survey/08SalarySurveyHighlights. pdf 6

 Occupational Employment and Wages, 2008. Table 1. National employment and wage data from the Occupational 

Employment Statistics survey by occupation, May 2008. http://www. bls. gov/news. release/pdf/ocwage. pdf 7

 Salary Table 2008-GS, Incorporating the 2. 5 Percent General Schedule Increase, Effective 2008. Hourly/Overtime 

Rates by Grade and Step. Grade 12, Step 5. http://www. opm. gov/oca/08tables/html/gs_h. asp 
 In developing the permitting authority costs, EPA estimated that 32 of the 57 States, 

Territories, and Tribes that currently participate in the UIC Program will have primacy for Class 

VI wells. EPA based this estimate on the number of States with existing Class II programs 

because of the likelihood that oil and gas reservoirs will be used for the primary purpose of longterm storage once oil and gas production has ceased plus additional States for which GS projects 

are already planned or operating. Federal and Primacy Agency costs are provided in Section 

5.4.11. 

Exhibit 5.1 Loaded Labor Rates by Standard Occupational Classification (SOC) 

and Government Schedule Codes- 2008$ 

Source Occupation Mean Hourly Labor Rate

AAPG Geoscientist $107.23

SPE Mining & Geological Engineers $110.62

OPM Federal Employee, GS 12 - Step 5 $50.14

BLS

State employee, life, physical, and 

social sciences $49.44

Source: GS Cost Model

5.2.2 General and Administrative Costs 

 

 There are G&A costs that will be required during the life of the project that are incurred 

in day to day operations for all owners and operators, such as the costs for computers, 

telephones, lighting, office supplies, and maintenance and periodic replacement of such items. 

EPA estimates that G&A costs for the electric power generation, mining, and petroleum 

industries are 20% on average for all costs; therefore, the cost model multiplies the subtotal for 

each rule component by 1.20 to derive a total that includes G&A. The annualized costs for 

owners and operators summarized by rule component and by cost type include G&A costs. 

Permitting authority costs associated with G&A are included in Agency and State labor rates; 

thus, the annualized State/Agency totals also include G&A. 

 

5.3 Projecting and Discounting National Costs 

Cost estimates must be expressed in common units across the period of analysis so they 

can be summed and annualized. For the GS Rule and each RA considered, some activities occur 

once, such as the initial characterization of the geologic formations of the project site. Other 

activities, such as injectate analysis reports, will occur periodically throughout each year, and 

still others, such as mechanical integrity tests of the well or AoR reevaluations, are assumed to 

occur annually or less frequently (depending on the RA) during operations. 

Cost Analysis for the 5-5 November 2010 

Final GS Rule
Cost Analysis for the 5-6 November 2010 

Final GS Rule

 

Project level costs are projected over a 50-year instead of a 25-year time period, as is 

normally performed for EPA drinking water regulations. EPA elected to increase the analysis 

period to better reflect the lifecycle costs of GS projects. These costs are present value (PV) costs 

calculated using discount rates of 3 and 7 percent as recommended by Office of Management 

and Budget (OMB) guidance.8

 However, to make the analysis results more comparable to the 

majority of other SDWA rulemakings, the PV costs for the 50-year analysis are then annualized 

over just the first 25 years of that period.9

 

A summary of these adjustments is as follows: 

• Project all nondiscounted project costs over a 50-year time horizon based on the 

schedule for each compliance activity. 

• Calculate total present value rule costs using 3 and 7 percent discount rates. 

• Annualize the rule costs over 25 years using the same discount rates. 

Appendix C contains results from each step above for the selected alternative (RA3) and 

for RAs 0, 1, 2, and 4. 

5.4 Derivation of Costs for Owners and Operators of GS Wells and the 

Permitting Authority 

 

 This section presents the methodology and unit costs used to derive project and rule level 

costs for owners and operators of GS wells and UIC Program Directors to perform the activities 

required by the GS Rule, and a brief summary of the compliance activities comprising each rule 

component. This section includes an administrative subsection (5.4.1) in addition to the technical 

components introduced in Chapters 1, 2, and 4 of this Cost Analysis, shown below in subsections 

5.4.2 – 5.4.11. A detailed summary of the GS Rule (Class VI) regulatory requirements is 

provided in Chapter 2 by rule component. 

 

8

 The choice of an appropriate discount rate is a complex and controversial issue among economists and policy 

makers. Therefore, EPA compares streams of future national level costs using two alternative discount rates, 3 and 7 

percent. The underlying logic for each discount rate can be found in Guidelines for Preparing Economic Analyses

(EPA, 2000). 

9

 Annualizing 50 years of costs over just 25 years has the effect of making costs appear greater, but in this case most 

costs are actually incurred over the first 25 years so annualizing over that period avoids making costs appear 

artificially low. 
Cost Analysis for the 5-7 November 2010 

Final GS Rule

5.4.1 Rule Implementation and Annual Administration 

5.4.2 Geologic Site Characterization 

5.4.3 Area of Review and Corrective Action 

5.4.4 Injection Well Construction 

5.4.5 Injection Well Operation 

5.4.6 Mechanical Integrity Testing 

5.4.7 Monitoring 

5.4.8 Well Plugging and Post-Injection Site Care 

5.4.9 Financial Responsibility 

5.4.10 Emergency and Remedial Response Plans 

5.4.11 Permitting Authority Costs 

This chapter uses information presented in Chapter 3 as a starting point for analysis of 

owners and operators of GS wells that are subject to each rule component and associated 

compliance activities. Exhibit 5.2 presents data from the characteristic profiles of the five project 

types, which are referenced throughout this section, and summarizes the operating variables that 

drive costs for the baseline projects. For example, the cost associated with permit issuance is 

uniform for all formation types, but costs related to storage capacity, depth of injection interval, 

and storage efficiency are affected by the geology of the reservoir and containment formations. 
Exhibit 5.2 Project Characteristics By Formation Type and Size 

Cost Analysis for the 5-8 November 2010 

Final GS Rule

16

4

10

Pilot Large

Large 

Waivered ER

ER 

Waivered

Depth to Top of Injection 

Interval (ft) 7,900 7,900 4,400 5,700 3,312

Depth to Bottom of 

Injection Interval (ft) 8,500 8,500 5,000 5,800 3,412

Metric tonnes capacity at 

100% storage efficiency 30,022,272 737,154,000 737,154,000 32,574,981 29,860,399

Storage efficiency 10.0% 10.0% 10.0% 49.4% 49.4%

Area of Review (mi2

)

 4 0.9 23.3 23.8 8.4 8.2

Total Number of wells in 

Area of Review 5 116 119 167 165

Injection Wells Required 

(total) 3 4 417

Tubing Diameter (inches) 6664

Depth of Stratigraphic 

Tests (ft.) 2,400 9,350 5,500 2,400 2,400

Number of Monitoring 

Wells above Injection 

Zone1 1.0 5.8 8.7 2.1 3.1

Number of Monitoring 

Wells into Injection Zone1 1.0 5.8 8.7 2.1 3.1

Depth of Monitoring Wells2 

(feet) 5,783 5,783 4,783 4,192 3,266

Long-string Casing of 

Monitoring Wells (diam. 

inches) 5.5 5.5 5.5 5.5 5.5

Injection Period (years)3 4 40 40 10

Notes:

(5) Projects that receive approval of a waiver of the requirement to inject below the lowermost USDW 

have reduced depth and a higher number of monitoring wells; this information is provided in the pro 

forma sheets presented in Appendix A of this Cost Analysis.

(3) GS projects in oil and gas reservoirs are assumed to operate for 30 years: 20 years under the existing 

UIC class II well regulations while the site is still used primarily for oil/gas production, and for the 

remaining 10 years under class VI for the primary purpose of long-term storage. This cost analysis 

includes costs for ER projects beginning with their transition from production to GS, i.e., 20 years into the 

30 year injection period. 

(4) The Area of Review is the size of the area estimated to encompass the plume throughout the project 

lifecycle.

(1) The number of monitoring wells per site varies according to the RA and the size of the project area 

assumed for a representative project. Shown are the required number of wells in the pro forma of each 

project type for the selected RA (RA3). 

(2) Well depths shown represent the typical (mean) monitoring well depth. Shown are the figures for 

RA3. Under RA3 and RA4, one half of the monitoring wells would be drilled to the bottom of the injection 

zone, while the other monitoring wells for RA3 and RA4, and all monitoring wells for RA1 and RA2, would 

be drilled to a depth halfway between the bottom of the lowest USDW and the top of the containment 

formation.

Source: Appendix A

Type of Project

Saline

Characteristic

Enhanced Recovery
Cost Analysis for the 5-9 November 2010 

Final GS Rule

Sections 5.4.1 – 5.4.10 give a brief overview and unit costs of the activities that comprise 

each rule component. Section 5.4.11 provides a description of the compliance activities and 

associated costs for permitting authorities. An important distinction to note about the figures 

presented in Section 5.4 is that they provide both total and incremental costs incurred by owners 

and operators and the permitting authority during GS projects. The incremental, or rule, costs are 

those costs incurred to comply with regulatory requirements beyond those currently practiced by 

owners and operators of GS wells under existing UIC regulations for Class I non-hazardous 

wells. 

5.4.1 Rule Implementation and Annual Administration 

All owners and operators of GS wells subject to the GS Rule will incur one-time costs 

that include time for staff to become familiar with GS Rule provisions and to train employees on 

these activities. Owners and operators of all 29 projects subject to the GS Rule will perform 

implementation activities. The labor rates presented in Section 5.2.1 are used along with 

estimates of labor hours to generate implementation costs for all owners and operators. Based on 

previous experience with rule implementation, EPA estimates that each owner and operator will 

require a total of 80 hours to read and understand the rule, and a total of 16 hours to train 

personnel. These costs are included in the cost for filing a permit application, included in this 

analysis in Injection Well Construction costs (see Section 5.4.4). Costs for enforcement of the 

GS Rule are not included in this analysis but are understood to be the same for the rule as in the 

baseline regulatory scenario, resulting in no additional incremental cost for the GS Rule. 

5.4.2 Geologic Site Characterization 

The primary purpose of geologic site characterization is to determine whether a site is 

suitable and safe for injection and sequestration. The characterization process includes site 

evaluation and tests to support permit applications. It also involves the development of a baseline 

for the conditions (pressure, temperature, CO2 flux, etc.) in the AoR to allow long-term 

monitoring to be successful. Geologic site characterization is designed to provide the geologic 

and hydrologic data needed to design the subsurface infrastructure, develop reservoir models, 

and design a monitoring program. 

Under the GS Rule, all owners and operators of GS wells subject to the GS Rule will 

perform geologic site characterization in Year 1 of the project (not all projects will start at the 

same time). It is assumed that not all sites characterized will be suitable for GS; therefore a site 

selection success factor has been applied to the geologic site characterization unit costs to 

account for this extra cost. For saline projects, the analysis assumes that one in four sites 

characterized will be suitable for deployment. For sites transitioning from existing Class II 

(primary purpose is ER) to Class VI (primary purpose is long-term storage), which are already 

characterized as suitable for ER in advance of any effort for the purpose of GS, this analysis 

assumes that all sites characterized for GS will be suitable. Exhibit 5.3 presents the owner and 

operator burden and costs for the baseline, the GS Rule, and each RA considered for Geologic 

Site Characterization unit costs. The detailed calculations used to develop unit costs are 

presented in Appendix C of the Cost Analysis. 
Exhibit 5.3 Owner and Operator Burden and Unit Cost Estimates for Geologic 

Site Characterization (2008$) 

Compliance Activity

Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

 Nonlabor 

unit 

Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ 25,736 $ 25,736 $ 51,471 $ - -$ 

RA1 $ 6,434 $ 6,434 $ 12,868 $ - -$ 

RA2 $ 12,868 $ 12,868 $ 25,736 $ - -$ 

RA3 $ 25,736 $ 25,736 $ 51,471 $ - -$ 

RA4 $ 25,736 $ 25,736 $ 51,471 $ - -$ 

RA0 $ 1,839,242 $ 9,687,400 $19,697,002 $ 310,826 $ 616,490

RA1 919,621 $ $ 4,843,700 $ 9,848,501 $ 155,413 $ 308,245

RA2 1,839,242 $ $ 9,687,400 $ 310,826 19,697,002 $ $ 616,490

RA3 2,758,863 $ $ 29,545,503 14,531,099 $ 466,239 $ $ 924,735

RA4 3,678,484 $ $19,374,799 $39,394,004 $ 621,652 $ 1,232,980

RA0 $ 19,302 $ 19,302 $ 38,604 $ - -$ 

RA1 $ 6,434 $ 6,434 $ 12,868 $ - -$ 

RA2 $ 12,868 $ 12,868 $ 25,736 $ - -$ 

RA3 $ 25,736 $ 25,736 $ 51,471 $ - -$ 

RA4 $ 25,736 $ 25,736 $ 51,471 $ - -$ 

 RA0 $ 11,660 $ 67,257 $ 137,246 $ 752 $ 1,490

RA1 $ 11,660 $ 67,257 $ 137,246 $ 752 $ 1,490

RA2 $ 11,660 $ 67,257 $ 137,246 $ 752 $ 1,490

RA3 $ 11,660 $ 67,257 $ 137,246 $ 752 $ 1,490

RA4 $ 11,660 $ 67,257 $ 137,246 $ 752 $ 1,490

RA0 $ 10,294 $ 10,294 $ 20,589 $ 1,287 $ 2,574

RA1 $ 10,294 $ 10,294 $ 20,589 $ 1,287 $ 2,574

RA2 $ 10,294 $ 10,294 $ 20,589 $ 1,287 $ 2,574

RA3 $ 10,294 $ 10,294 $ 20,589 $ 1,287 $ 2,574

RA4 $ 10,294 $ 10,294 $ 20,589 $ 1,287 $ 2,574

RA0 $ 25,736 $ 25,736 $ 51,471 $ 643 $ 1,287

RA1 $ 25,736 $ 25,736 $ 51,471 $ 643 $ 1,287

RA2 $ 25,736 $ 25,736 $ 51,471 $ 643 $ 1,287

RA3 $ 38,604 $ 38,604 $ 77,207 $ 965 $ 1,930

RA4 $ 51,471 $ 51,471 $ 102,943 $ 1,287 $ 2,574

RA0 $ 205,800 $ 747,900 $ 895,200 $ 51,450 $ 102,900

RA1 205,800 $ $ 747,900 $ 895,200 $ 51,450 $ 102,900

RA2 205,800 $ $ 747,900 $ 895,200 $ 51,450 $ 102,900

RA3 411,600 $ $ 1,495,800 $ 1,790,400 $ 102,900 $ 205,800 RA4 $ 823,200 $ 2,991,600 $ 3,580,800 $ 205,800 $ 411,600

RA0 $ 10,294 $ 10,294 $ 20,589 $ 257 $ 515

RA1 $ 10,294 $ 10,294 $ 20,589 $ 257 $ 515

RA2 $ 10,294 $ 10,294 $ 20,589 $ 257 $ 515

RA3 $ 10,294 $ 10,294 $ 20,589 $ 257 $ 515

RA4 $ 10,294 $ 10,294 $ 20,589 $ 257 $ 515

RA0 $ 12,868 $ 12,868 $ 51,471 $ 1,608 $ 6,434

RA1 $ 6,434 $ 6,434 $ 25,736 $ 804 $ 3,217

RA2 $ 6,434 $ 6,434 $ 25,736 $ 804 $ 3,217

RA3 $ 25,736 $ 25,736 $ 102,943 $ 3,217 $ 12,868

RA4 $ 25,736 $ 25,736 $ 102,943 $ 3,217 $ 12,868

RA0 $ 36,036 $ 36,036 $ 108,107 $ 9,009 $ 27,027

RA1 $ 36,036 $ 36,036 $ 108,107 $ 9,009 $ 27,027

RA2 $ 72,071 $ 72,071 $ 216,214 $ 18,018 $ 54,054

RA3 $ 72,071 $ 72,071 $ 216,214 $ 18,018 $ 54,054

RA4 144,143 $ $ 144,143 $ 432,428 $ 36,036 $ 108,107

RA0 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA1 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA2 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA3 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA4 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA0 $ - -$ $ - -$ -$ 

RA1 $ - -$ $ - -$ -$ 

RA2 $ - -$ $ - -$ -$ 

RA3 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA4 $ 4,879 $ 119,805 $ 245,255 $ 1,075 $ 2,119

RA0 $ 3,659 $ 89,853 $ 183,941 $ 806 $ 1,589

RA1 $ 3,659 $ 89,853 $ 183,941 $ 806 $ 1,589

RA2 $ 3,659 $ 89,853 $ 183,941 $ 806 $ 1,589

RA3 $ 3,659 $ 89,853 $ 183,941 $ 806 $ 1,589

RA4 $ 14,638 $ 359,414 $ 735,766 $ 3,224 $ 6,357

 RA0 $ 102,943 $ 102,943 $ 257,357 $ 25,736 $ 64,339

RA1 102,943 $ $ 102,943 $ 257,357 $ 25,736 $ 64,339

RA2 102,943 $ $ 102,943 $ 257,357 $ 25,736 $ 64,339

RA3 102,943 $ $ 102,943 $ 257,357 $ 25,736 $ 64,339

RA4 102,943 $ $ 102,943 $ 257,357 $ 25,736 $ 64,339

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

$6,434 N/A 

$104,000/ 

square 

N/A mile 

Conduct 3D seismic survey to identify 

faults and fractures in primary and 

secondary containment units.

Develop maps and cross sections of 

local geologic structure.

$107.23 60

N/A N/A

Obtain data on area, thickness, 

capacity, porosity and permeability of 

receiving formations and confining 

systems.

$12,868

24

$107.23

$107.23 $2,574

120

N/A

N/A

240

60 $6,434

N/A

N/A

N/A

N/A

$415/squ

are mile

$3,100/sit

e

$6,434

N/A

Obtain and analyze seismic 

(earthquake) history. 60

Remote (aerial) survey of land, land 

uses, structures etc.

$107.23

N/A

Obtain geomechanical information on 

fractures, stress, rock strength, in situ 

fluid pressures (from existing data and 

literature).

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which 

each project under a given alternative is expected to engage in the activity (see Section 5.2).

$25,736

Provide information on water-rockCO2 geochemistry and mineral 

reactions. $107.23

Develop list of penetrations into 

injection zone within AoR (from well 

history data bases).

$25,736

$10,300/ 

site

N/A

$1,287/ 

square 

mile

Provide geochemical information and 

maps/cross section on subsurface 

aquifers. $107.23

List names and depth of all potentially 

affected Underground Sources of 

Drinking Water (USDWs).

N/A

$107.23

Obtain geomechanical information on 

fractures, stress, rock strength, in situ 

fluid pressures (new cores and tests). N/A

24

N/A

N/A

$78/ foot 

(depth)

$3,100/co

re

Develop list of penetrations into 

containment systems within AoR (from 

well history data bases). $107.23

12 hours/ 

square 

mile

$107.23

12 hours/ 

square 

mile

Prepare geologic characterization 

report demonstrating: suitability of 

receiving zone, storage capacity and 

injectivity, trapping mechanism free of 

nonsealing faults, competent confining 

system, etc. $107.23 240

Develop list of water wells within AoR 

(from public data). $107.23

36 hours/ 

square 

mile N/A

$3,860/ 

square 

mile

N/A

$2,574

$1,287/ 

square 

mile

Cost Analysis for the 5-10 November 2010 

Final GS Rule
5.4.2.1 Annualized Costs for Geologic Site Characterization 

Annualized costs for owners and operators under the geologic site characterization rule 

component for the baseline and RAs 1- 4 are presented in Exhibit 5.4. 

Exhibit 5.4 Owner and Operator Cost Estimates for Geologic Site 

Characterization – Annualized Values Using a 3% and 7% Discount Rate 

($Millions, 2008$) 

3% 7%

Baseline $ 6.70 $ 8.35

RA1 $ 4.12 $ 5.13

Incremental RA1 $ (2.58) $ (3.22)

RA2 $ 7.42 $ 9.25

Incremental RA2 $ 0.72 $ 0.90

RA3 $ 11.30 $ 14.10

Incremental RA3 $ 4.61 $ 5.75

RA4 $ 14.34 $ 17.87

Incremental RA4 $ 7.64 $ 9.52

Regulatory Alternative

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.3 Area of Review and Corrective Action 

 Owners and operators of GS wells will use computational models to determine, in three 

dimensions, the extent of the AoR. The models will account for the physical and chemical 

properties of all phases of the injected CO2 and the associated pressure front and will be based on 

information collected on site during geologic site characterization and during development of 

estimates for operating conditions. 

Owners and operators must identify all wells within the AoR that penetrate the injection 

zone or confining zone and determine which need to be addressed through appropriate corrective 

action. Old wells may provide conduits for the escape of injected CO2 or formation fluids into 

overlying units or USDWs. In the case of saline formations, there may be few if any existing 

wellbores; however, in oil and gas reservoirs there will likely be many existing wellbores. 

Corrective action on wells in the AoR may involve the removal of existing plugs and 

casing strings, and recompleting the well. This may involve the use of CO2 resistant cements in 

portions of the well. 

It is assumed that each well owner and operator will need to remediate 10 percent of old 

wells within the AoR. AoR costs will be incurred in Year 1 of each project, before the injection 

wells are put online, and at recurring intervals as the AoR is re-evaluated and potentially 

expanded or where phased corrective action is allowed. (The recurring cost for updating the AoR 

using computational models of CO2 fluid flows is included in the ongoing costs for monitoring in 

Section 5.4.7). Exhibit 5.5 presents the owner and operator burden and costs for the baseline, the 

Cost Analysis for the 5-11 November 2010 

Final GS Rule
GS Rule, and each RA considered for AoR and Corrective Action unit costs. The detailed 

calculations used to develop unit costs are presented in Appendix C of the Cost Analysis. 

Exhibit 5.5 Owner and Operator Burden and Unit Cost Estimates for AoR and 

Corrective Action (2008$) 

Compliance Activity

Labor Cost

($/hour)

Labor 

Burden 

(hours)

Labor Cost 

($)

 Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project - 

Saline

Project Cost 

Large Project 

- Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large Project 

- ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ - $ - $ - $ - $ -

RA1 $ 3,982 $ 4,646 $ 4,646 $ 13,275 $ 12,611

RA2 $ 3,982 $ 4,646 $ 4,646 $ 13,275 $ 12,611

RA3 $ - $ - $ - $ - $ -

RA4 $ - -$ $ - $ - $ -

RA0 $ 27,877 $ 30,532 $ 30,532 $ 65,047 $ 62,392

RA1 $ 13,939 $ 15,266 $ 15,266 $ 32,523 $ 31,196

RA2 $ 13,939 $ 15,266 $ 15,266 $ 32,523 $ 31,196

RA3 $ 30,532 $ 34,072 $ 34,072 $ 80,092 $ 76,552

RA4 $ - -$ $ - $ - $ -

RA0 $ - $ - $ - $ - $ -

RA1 $ - $ - $ - $ - $ -

RA2 $ - $ - $ - $ - $ -

RA3 $ - $ - $ - $ - $ -

RA4 $ 34,515 $ 39,382 $ 39,382 $ 102,659 $ 97,792

RA0 $ 4,435 $ 78,285 $ 80,099 $ 2,892 $ 2,853

RA1 $ 4,435 $ 78,285 $ 80,099 $ 2,892 $ 2,853

RA2 $ 4,435 $ 78,285 $ 80,099 $ 2,892 $ 2,853

RA3 $ 4,435 $ 78,285 $ 80,099 $ 2,892 $ 2,853

RA4 $ 17,742 $ 313,141 $ 320,397 $ 11,568 $ 11,413

RA0 $ 3,203 $ 18,023 $ 18,387 $ 9,126 $ 9,001

RA1 $ 3,203 $ 18,023 $ 18,387 $ 9,126 $ 9,001

RA2 $ 3,203 $ 18,023 $ 18,387 $ 9,126 $ 9,001

RA3 $ 3,203 $ 18,023 $ 18,387 $ 9,126 $ 9,001

RA4 $ 3,203 $ 18,023 $ 18,387 $ 9,126 $ 9,001

RA0 $ - $ - $ - $ - $ -

RA1 $ - $ - $ - $ - $ -

RA2 $ - $ - $ - $ - $ -

RA3 $ - $ - $ - $ - $ -

RA4 $ 2,517 $ 61,797 $ 63,253 $ 2,217 $ 2,186

 RA0 $ 19,879 $ 488,097 $ 499,599 $ 877,823 $ 865,507

RA1 $ 19,879 $ 488,097 $ 499,599 $ 877,823 $ 865,507

RA2 $ 19,879 $ 488,097 $ 499,599 $ 877,823 $ 865,507

RA3 $ 19,879 $ 488,097 $ 499,599 $ 877,823 $ 865,507

RA4 $ 19,879 $ 488,097 $ 499,599 $ 877,823 $ 865,507

 RA0 $ 7,455 $ 183,036 $ 374,699 $ 329,184 $ 649,130

RA1 $ 7,455 $ 183,036 $ 374,699 $ 329,184 $ 649,130

RA2 $ 7,455 $ 183,036 $ 374,699 $ 329,184 $ 649,130

RA3 $ 14,909 $ 366,073 $ 749,398 $ 658,367 $ 1,298,260

RA4 $ 14,909 $ 366,073 $ 749,398 $ 658,367 $ 1,298,260

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

N/A

Remediate old wells in AoR that pose 

a risk to USDWs. Use two cement 

plugs: one in producing formation and 

one for surface to bottom of USDWs, 

fill the remainder of the borehole with 

mud.

Remediate old wells in AoR that lack 

high quality cementing information. 

Use two cement plugs: one in 

producing formation and one for 

surface to bottom of USDWs, fill the 

remainder of the borehole with mud.

$56,100/oil 

or gas well

$20,700/wat

er well 

$56,100/oil 

or gas well

$20,700/wat

er well 

N/A

$664/ well

N/A

N/A 

N/A

N/A

$110.62

Aerial search for old wells (artificial 

penetrations). This includes helicopter 

magnetic survey and follow-up ground 

survey. 

Evaluate integrity of construction and 

record of completion and/or plugging 

of existing shallow wells that pose a 

threat to USDWs.

Evaluate integrity of construction and 

record of completion and/or plugging 

of existing wells that penetrate 

containment system.

N/A 

N/A

 $5,200/site

$13,230/sqa

re mile 

$19,912/ 

site + 

$4,867/ 

injection 

well

180 

hours/site

44 

hours/injecti

on well

24 

hours/site

$110.62 6 hours/well

$2,655/ site 

+ $664/ well N/A 

N/A

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which each project 

under a given alternative is expected to engage in the activity (see Section 5.2).

36 

hours/site

12 

hours/injecti

on well N/A 

$19,912/ 

site + 

$2,655/ 

injection 

well N/A 

6 hours/well

N/A

N/A

$3,982/ site 

+ $1,327/ 

injection 

well

180 

hours/site

24 

hours/injecti

on well

Complex modeling of CO2 fluid flows 

and migration (reservoir simulations) 

over 10,000 years, and prepare 

AOR/Corrective Action plan.

$110.62

Complex modeling of CO2 fluid flows 

and migration (reservoir simulations) 

over 100 years, and prepare 

AOR/Corrective Action plan.

$110.62

Simple fluid flow calculations to predict 

CO2 fluid flow.

$110.62

5.4.3.1 Annualized Costs for Area of Review and Corrective Action 

Annualized costs for owners and operators under the AoR and Corrective Action rule 

component for the baseline and RAs 1- 4 are presented in Exhibit 5.6. 

Cost Analysis for the 5-12 November 2010 

Final GS Rule
Exhibit 5.6 Owner and Operator Cost Estimates for AoR and Corrective Action – 

Annualized Values Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

Baseline $ 1.09 $ 0.98

RA1 $ 1.14 $ 1.04

Incremental RA1 $ 0.06 $ 0.05

RA2 $ 1.14 $ 1.04

Incremental RA2 $ 0.06 $ 0.05

RA3 $ 1.46 $ 1.32

Incremental RA3 $ 0.38 $ 0.34

RA4 $ 1.55 $ 1.46

Incremental RA4 $ 0.46 $ 0.47

Source: Appendix C, Exhibit C.67/C.68

Regulatory Alternative 

Discount Rate

5.4.4 Injection Well Construction 

The technologies for drilling and equipping oil and gas wells and injection wells are well 

established. Advanced technologies are being developed and used across the country to enhance 

the production of oil and gas. These include horizontal drilling and multi-stage fracturing in 

shale formations, high tech stimulation and completion methods in tight gas reservoirs, and 

directional and deepwater wells offshore. Many ER projects using CO2 are now active, 

especially in the Permian Basin of West Texas, and technologies have been developed to 

complete, produce, and maintain injection and production wells using this medium for long 

periods of time. 

The design of a GS injection well is similar to that of a conventional gas injection well or 

a gas storage well, with the exception that much of the down-hole equipment must be upgraded 

for high pressure and corrosion resistance (IPCC, 2005). Upgrades include special casing and 

tubing, safety valves, cements, and blowout preventers. GS well owners and operators must 

construct their injection wells using materials and cements that are compatible with the CO2

stream and/or other fluids with which they may come into contact. EPA assumes in this analysis 

that under RA1 and RA2 owners and operators would inject below the lowermost USDW, except 

for in limited cases when a waiver of this requirement was approved, as discussed further in 

Chapter 4, Section 4.2.4 with regard to RA3. Capital costs of injection well construction will be 

incurred by GS well owners and operators in Year 1 of each project, before injection begins.

Owners and operators of GS wells will need to obtain the right of way for surface use for 

injection and monitoring wells, and for subsurface or pore space use. While subsurface and pore 

space rights are an expense that is outside the authority of the Safe Drinking Water Act (SDWA) 

and therefore are not attributable to the GS Rule, they are included in the analysis because they 

are part of the total cost of a GS project, but in incremental (baseline minus RA), they are zero. 

These one-time costs will be incurred by GS well owners and operators prior to commencing the 

project, in Year 1 of the project. 

Each owner and operator will have to apply for a UIC Program permit for their well. The 

permit application is complex and often includes several volumes of geologic data, maps and 

cross sections, schematics, monitoring and testing plans, and plans for well plugging, PISC, and 

Cost Analysis for the 5-13 November 2010 

Final GS Rule
Cost Analysis for the 5-14 November 2010 

Final GS Rule

emergency and remedial response. The Geologic CO2 Sequestration Technology and Cost 

Analysis (EPA, 2010a) describes all of the documentation included in the permit application. 

Facility construction permits will also be necessary for air emissions and water use incurred 

during construction. Also included in this item is the development of a corrosion control program 

for the well. Owners and operators are assumed to incur this cost in Year 1 of the project, before 

well construction begins. 

Owners and operators will need to install monitoring equipment on each injection well to 

monitor injected volume, pressure, flow rate, and annulus pressure. Owners and operators will 

incur the costs of installing the monitoring equipment during Year 1 of the project, as wells are 

being constructed. 

To meet the GS Rule requirements, owners and operators will be required to monitor 

ground water quality above the confining zone to verify isolation of the injection fluid. To this 

end, owners and operators will be required to construct one monitoring well above the injection 

zone per two square miles of AOR; for monitoring wells into the injection zone, the Agency 

assumes one monitoring well per four square miles. EPA assumes monitoring wells into the 

injection zone will also be used to sample above the injection zone (see Exhibit 5.2 for the 

required number of wells in the pro forma of each project type for the selected alternative, RA3). 

As is the case with injection wells, costs for monitoring wells are well established in the industry. 

Capital costs for monitoring wells will be incurred in Year 1 of each project, as the wells are 

being constructed. 

Owners and operators will also need to build onsite pipelines to conduct the CO2 from the 

distribution piping to the injection well. The basis for these costs is well understood because they 

are used in the oil and gas industry. It is estimated that the average saline formation GS project 

site will need to install 48 inch-miles of pipeline, and the average oil and gas reservoir project 

will need to install 59 inch-miles of pipeline. CO2 pipeline costs are predominantly capital costs 

and will be incurred in Year 1 of each project. As with lease costs, the pipeline costs are outside 

the scope of the SDWA and are not attributable to the GS Rule; they are included in total project 

costs for completeness, but on an incremental (rule) basis they are zero. 

Exhibit 5.7 presents the owner and operator burden and costs for the baseline, the GS 

Rule, and each RA considered for Injection Well Construction unit costs. The detailed 

calculations used to develop unit costs are presented in Appendix C of the Cost Analysis. 
Exhibit 5.7 Owner and Operator Burden and Unit Cost Estimates for Injection 

Well Construction (2008$) 

Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project - 

Saline

Project Cost 

Large Project -

Saline

Project Cost 

Large 

Waivered 

Project - 

Saline

Project Cost 

Large Project -

ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ 337,410 $ 380,880 $ 380,880 $ 945,990 $ 902,520

RA1 $ 337,410 $ 380,880 $ 380,880 $ 945,990 $ 902,520

RA2 $ 337,410 $ 380,880 $ 380,880 $ 945,990 $ 902,520

RA3 $ 337,410 $ 380,880 $ 380,880 $ 945,990 $ 902,520

RA4 $ 337,410 $ 380,880 $ 380,880 $ 945,990 $ 902,520

 RA0 $ 62,100 $ 82,800 $ 82,800 $ 175,950 $ 165,600

RA1 $ 62,100 $ 82,800 $ 82,800 $ 175,950 $ 165,600

RA2 $ 62,100 $ 82,800 $ 82,800 $ 175,950 $ 165,600

RA3 $ 62,100 $ 82,800 $ 82,800 $ 175,950 $ 165,600

RA4 $ 62,100 $ 82,800 $ 82,800 $ 175,950 $ 165,600

RA0 $ 31,548 $ 774,624 $ 792,878 $ 208,433 $ 205,508

RA1 $ 31,548 $ 774,624 $ 792,878 $ 208,433 $ 205,508

RA2 $ 31,548 $ 774,624 $ 792,878 $ 208,433 $ 205,508

RA3 $ 31,548 $ 774,624 $ 792,878 $ 208,433 $ 205,508

RA4 $ 31,548 $ 774,624 $ 792,878 $ 208,433 $ 205,508

RA0 $ 123,023 $ 585,213 $ 596,566 $ 276,259 $ 273,834

RA1 $ 123,023 $ 585,213 $ 596,566 $ 276,259 $ 273,834

RA2 $ 123,023 $ 585,213 $ 596,566 $ 276,259 $ 273,834

RA3 $ 123,023 $ 585,213 $ 596,566 $ 276,259 $ 273,834

RA4 $ 123,023 $ 585,213 $ 596,566 $ 276,259 $ 273,834

 RA0 $ 39,020 $ 45,020 $ 135,060 $ 75,020 $ 219,060

RA1 $ 39,020 $ 45,020 $ 135,060 $ 75,020 $ 219,060

RA2 $ 39,020 $ 45,020 $ 135,060 $ 75,020 $ 219,060

RA3 $ 39,020 $ 45,020 $ 135,060 $ 75,020 $ 219,060

RA4 $ 39,020 $ 45,020 $ 135,060 $ 75,020 $ 219,060

RA0 $ 7,189,653 $ 9,586,205 $ 4,647,171 $ 2,406,404 $ 1,332,265

RA1 7,189,653 $ $ 9,586,205 $ 4,647,171 $ 2,406,404 $ 1,332,265

RA2 7,189,653 $ $ 9,586,205 $ 4,647,171 $ 2,406,404 $ 1,332,265

RA3 7,189,653 $ $ 9,586,205 $ 4,647,171 $ 2,406,404 $ 1,332,265

RA4 7,189,653 $ $ 9,586,205 $ 4,647,171 $ 2,406,404 $ 1,332,265

RA0 $ 175,950 $ 234,600 $ 138,000 $ 453,560 $ 251,106

RA1 $ 43,988 $ 58,650 $ 34,500 $ 113,390 $ 62,776

RA2 $ 175,950 $ 234,600 $ 138,000 $ 453,560 $ 251,106

RA3 $ 175,950 $ 234,600 $ 138,000 $ 453,560 $ 251,106

RA4 $ 175,950 $ 234,600 $ 138,000 $ 453,560 $ 251,106

RA0 $ - $ - $ - $ - $ -

RA1 $ - $ - $ - $ - $ -

RA2 $ 481,913 $ 642,550 $ 814,500 $ - $ -

RA3 $ 481,913 $ 642,550 $ 814,500 $ - $ -

RA4 $ 718,875 $ 958,500 $ 1,215,000 $ - $ -

RA0 $ 27,900 $ 37,200 $ 120,000 $ - $ -

RA1 $ 27,900 $ 37,200 $ 120,000 $ - $ -

RA2 $ 27,900 $ 37,200 $ 120,000 $ - $ -

RA3 $ 111,600 $ 148,800 $ 480,000 $ - $ -

RA4 $ 111,600 $ 148,800 $ 480,000 $ - $ -

RA0 $ 6,975 $ 9,300 $ 30,000 $ - $ -

RA1 $ 6,975 $ 9,300 $ 30,000 $ - $ -

RA2 $ 27,900 $ 37,200 $ 120,000 $ - $ -

RA3 $ 27,900 $ 37,200 $ 120,000 $ - $ -

RA4 $ 27,900 $ 37,200 $ 120,000 $ - $ -

RA0 $ - $ - $ - $ - $ -

RA1 $ - $ - $ - $ - $ -

RA2 $ - $ - $ - $ - $ -

RA3 $ - $ - $ - $ - $ -

RA4 $ - $ - $ - $ - $ -

RA0 $ 512,071 $ 1,187,640 $ 1,187,640 $ 1,316,124 $ 1,215,072

RA1 $ 512,071 $ 1,187,640 $ 1,187,640 $ 1,316,124 $ 1,215,072

RA2 $ 512,071 $ 1,187,640 $ 1,187,640 $ 1,316,124 $ 1,215,072

RA3 $ 512,071 $ 1,187,640 $ 1,187,640 $ 1,316,124 $ 1,215,072

RA4 $ 512,071 $ 1,187,640 $ 1,187,640 $ 1,316,124 $ 1,215,072

RA0 $ 86,508 $ 166,379 $ 166,379 $ 273,515 $ 253,383

RA1 $ 86,508 $ 166,379 $ 166,379 $ 273,515 $ 253,383

RA2 $ 86,508 $ 166,379 $ 166,379 $ 273,515 $ 253,383

RA3 $ 86,508 $ 166,379 $ 166,379 $ 273,515 $ 253,383

RA4 $ 86,508 $ 166,379 $ 166,379 $ 273,515 $ 253,383

Corrosion resistant casing: low 

alloy for RA2 and RA3, high alloy 

for RA4.

RA 2 & 3: 

$1.81/foot 

(length) - 

inch 

(diameter)

adds 25% 

to total 

cementing 

cost

$1.20/foot 

(length) - 

inch 

(diameter)

Use CO2-resistant cement. N/A N/A

N/A

Corrosion resistant tubing. N/A

Cement well from surface through 

base of lowermost USDW and 

throughout injection zone. N/A

Compliance Activity

Conduct front-end engineering and 

design (general and injection 

wells), pre-op logging, sampling, 

and testing. Includes baseline 

pressure fall-off test.

$207,000/s

ite

$43,470/inj

ection well

Obtain rights-of-way for surface 

uses (equipment, injection wells). 

Pipeline rights-of-way are included 

in pipeline costs. Half of cost is 

legal fees for developer, other half 

is payment to landowner. N/A N/A

$20,700/inj

ection well

Pumps. N/A N/A

N/A N/A

Standard injection well cost (from 

look up table).

Lease rights for subsurface (pore 

space) use. Additional injection 

fees are included under O&M 

costs. N/A N/A

N/A

N/A

Land use, air emissions, water 

discharge permits.

$1.15/foot 

(length)- 

inch(diame

ter)

$103,400/s

ite 

$20,700/sq

N/A N/A . mile

N/A N/A

N/A

Injection pressure limited to 90% 

of fracture pressure of injection 

formation. N/A N/A

$520*(maxi

mum tons 

per day 

injected/we

$20,700/w

ell site

$1,550/HP 

of pump

N/A

Wellhead and Control Equipment. N/A

$52/acre

$10,400/sit

e

$6,000/inje

ction well

$220-

$290/foot 

(depth) 

down to 

9,000 feet

N/A

N/A

UIC permit filing, including 

preparation of attachments and 

required plans (see T&C 

Document for detail).

N/A

N/A

N/A N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

 

Cost Analysis for the 5-15 November 2010 

Final GS Rule
Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project - 

Saline

Project Cost 

Large Project -

Saline

Project Cost 

Large 

Waivered 

Project - 

Saline

Project Cost 

Large Project -

ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ 671,497 $ 4,004,349 $ 4,051,254 $ 4,929,421 $ 4,763,220

RA1 $ 671,497 $ 4,004,349 $ 4,051,254 $ 4,929,421 $ 4,763,220

RA2 $ 671,497 $ 4,004,349 $ 4,051,254 $ 4,929,421 $ 4,763,220

RA3 $ 671,497 $ 4,004,349 $ 4,051,254 $ 4,929,421 $ 4,763,220

RA4 $ 671,497 $ 4,004,349 $ 4,051,254 $ 4,929,421 $ 4,763,220

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

Source: GS Cost Model

Compliance Activity

$83,000/in

ch 

(diameter) -

mile 

All elements of pipeline costs. N/A N/A N/A (length)

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which each project 

under a given alternative is expected to engage in the activity (see Section 5.2).

5.4.4.1 Annualized Costs for Injection Well Construction 

Annualized costs for owners and operators under the injection well construction 

component for the baseline and RAs 1- 4 are presented in Exhibit 5.8. 

Exhibit 5.8 Owner and Operator Cost Estimates for Injection Well Construction – 

Annualized Values Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

Baseline $ 16.17 $ 17.04

RA1 $ 16.53 $ 17.45

Incremental RA1 $ 0.36 $ 0.40

RA2 $ 17.28 $ 18.29

Incremental RA2 $ 1.12 $ 1.25

RA3 $ 17.37 $ 18.40

Incremental RA3 $ 1.20 $ 1.36

RA4 $ 16.89 $ 17.95

Incremental RA4 $ 0.72 $ 0.91

Regulatory Alternative 

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.5 Injection Well Operation 

Owners and operators will incur annual costs for operating the injection and monitoring 

wells beginning in Year 2 of the project and will continue to incur these costs throughout the life 

of the injection period. Throughout injection, owners and operators will need to monitor 

injection rates, pressures, and volumes to assure that the well is operating within permitted 

parameters and does not fracture the injection zone. Other operating costs include regular 

maintenance of the well, electric costs for the pumps, land leases, insurance, providing reports to 

regulators, and contributions to a long-term monitoring, insurance, and remediation fund in 

proportion to the amount of CO2 injected. EPA assumes that under RA1, RA2, and RA3, owners 

and operators would inject below the lowermost USDW, except for in limited cases when a 

waiver of this requirement was approved. This is discussed further in Chapter 4, Section 4.2.4. 

Cost Analysis for the 5-16 November 2010 

Final GS Rule
Cost Analysis for the 5-17 November 2010 

Final GS Rule

 At the director’s discretion, owners and operators must also install down-hole devices 

(automatic shut-offs, check valves, or other, the selection of which is site specific and subject to 

the Director’s discretion) that allow the well to be shut-in or injection stopped if conditions 

become unsafe or well integrity fails. Down-hole devices are required for all offshore wells 

located in State Territorial waters. Most down-hole monitoring costs will be capital costs and 

will be incurred in Year 1 of each project. This equipment, which is co-installed with monitoring 

devices, is accounted for under Section 5.4.7, Monitoring. 

Exhibit 5.9 presents the owner and operator burden and costs for the baseline, the GS 

Rule, and each RA considered for Injection Well Operation unit costs. The detailed calculations 

used to develop unit costs are presented in Appendix C of the Cost Analysis. 

 

 
Exhibit 5.9 Owner and Operator Burden and Unit Cost Estimates for Well 

Operation (2008$) 

Compliance Activity

Labor Cost

($/hour)

Labor 

Burden 

(hours)

Labor Cost 

($)

 Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project - 

Saline

Project Cost 

Large Project 

- Saline

Project Cost 

Large 

Waivered 

Project - 

Saline

Project Cost 

Large Project 

- ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ 664 $ 664 $ 664 $ 664 $ 664

RA1 $ 664 $ 664 $ 664 $ 664 $ 664

RA2 $ 1,327 $ 1,327 $ 1,327 $ 1,327 $ 1,327

RA3 $ 2,655 $ 2,655 $ 2,655 $ 2,655 $ 2,655

RA4 $ 2,655 $ 2,655 $ 2,655 $ 2,655 $ 2,655

RA0 $ 1,417 $ 1,889 $ 1,889 $ 8,027 $ 7,555

RA1 $ 1,417 $ 1,889 $ 1,889 $ 8,027 $ 7,555

RA2 $ 2,833 $ 3,777 $ 3,777 $ 16,054 $ 15,110

RA3 $ 5,666 $ 7,555 $ 7,555 $ 32,109 $ 30,220

RA4 $ 5,666 $ 7,555 $ 7,555 $ 32,109 $ 30,220

 RA0 $ 46,500 $ 62,000 $ 62,000 $ 263,500 $ 248,000

RA1 $ 46,500 $ 62,000 $ 62,000 $ 263,500 $ 248,000

RA2 $ 46,500 $ 62,000 $ 62,000 $ 263,500 $ 248,000

RA3 $ 46,500 $ 62,000 $ 62,000 $ 263,500 $ 248,000

RA4 $ 46,500 $ 62,000 $ 62,000 $ 263,500 $ 248,000

RA0 $ - -$ $ - $ - -$ 

RA1 $ - -$ $ - $ - -$ 

RA2 $ 7,800 $ 10,400 $ 10,400 $ 44,200 $ 41,600

RA3 $ 7,800 $ 10,400 $ 10,400 $ 44,200 $ 41,600

RA4 $ 15,600 $ 20,800 $ 20,800 $ 88,400 $ 83,200

RA0 $ 142,666 $ 350,296 $ 350,296 $ 305,713 $ 280,236

RA1 142,666 $ $ 350,296 $ 350,296 $ 305,713 $ 280,236

RA2 142,666 $ $ 350,296 $ 350,296 $ 305,713 $ 280,236

RA3 142,666 $ $ 350,296 $ 350,296 $ 305,713 $ 280,236

RA4 142,666 $ $ 350,296 $ 350,296 $ 305,713 $ 280,236

 RA0 $ 311,550 $ 415,400 $ 372,000 $ 1,623,160 $ 1,409,224

RA1 311,550 $ $ 415,400 $ 372,000 $ 1,623,160 $ 1,409,224

RA2 311,550 $ $ 415,400 $ 372,000 $ 1,623,160 $ 1,409,224

RA3 311,550 $ $ 415,400 $ 372,000 $ 1,623,160 $ 1,409,224

RA4 311,550 $ $ 415,400 $ 372,000 $ 1,623,160 $ 1,409,224

RA0 $ 3,155 $ 77,462 $ 79,288 $ 27,791 $ 27,401

RA1 $ 3,155 $ 77,462 $ 79,288 $ 27,791 $ 27,401

RA2 $ 3,155 $ 77,462 $ 79,288 $ 27,791 $ 27,401

RA3 $ 3,155 $ 77,462 $ 79,288 $ 27,791 $ 27,401

RA4 $ 3,155 $ 77,462 $ 79,288 $ 27,791 $ 27,401

 RA0 $ 270,200 $ 663,439 $ 663,439 $ 579,001 $ 530,751

RA1 270,200 $ $ 663,439 $ 663,439 $ 579,001 $ 530,751

RA2 270,200 $ $ 663,439 $ 663,439 $ 579,001 $ 530,751

RA3 270,200 $ $ 663,439 $ 663,439 $ 579,001 $ 530,751

RA4 270,200 $ $ 663,439 $ 663,439 $ 579,001 $ 530,751

 RA0 $ 265,328 $ 502,925 $ 384,826 $ 296,776 $ 253,389

RA1 265,174 $ $ 541,926 $ 454,403 $ 294,084 $ 259,864

RA2 284,452 $ $ 567,630 $ 485,012 $ 305,856 $ 266,988

RA3 328,058 $ $ 765,830 $ 638,672 $ 347,748 $ 306,313

RA4 335,824 $ $ 777,616 $ 652,994 $ 350,045 $ 308,521

RA0 $ - -$ $ - $ - -$ 

RA1 $ - -$ $ - $ - -$ 

RA2 $ 9,382 $ 23,036 $ 23,036 $ 20,104 $ 18,429

RA3 $ 9,382 $ 23,036 $ 23,036 $ 20,104 $ 18,429

RA4 $ 18,764 $ 46,072 $ 46,072 $ 40,208 $ 36,858

RA0 $ - -$ $ - $ - -$ 

RA1 $ - -$ $ - $ - -$ 

RA2 $ - -$ $ - $ - -$ 

RA3 $ - -$ $ - $ - -$ 

RA4 $ - -$ $ - $ - -$ 

 RA0 $ 88,443 $ 167,642 $ 128,275 $ 98,925 $ 84,463

RA1 $ 88,391 $ 180,642 $ 151,468 $ 98,028 $ 86,621

RA2 $ 94,817 $ 189,210 $ 161,671 $ 101,952 $ 88,996

RA3 109,353 $ $ 255,277 $ 212,891 $ 115,916 $ 102,104

RA4 111,941 $ $ 259,205 $ 217,665 $ 116,682 $ 102,840

RA0 $ 33,166 $ 6,287 $ 4,810 $ 14,839 $ 12,669

RA1 $ 33,147 $ 6,774 $ 5,680 $ 14,704 $ 12,993

RA2 $ 33,779 $ 6,741 $ 5,760 $ 14,528 $ 12,682

RA3 $ 32,806 $ 7,658 $ 6,387 $ 13,910 $ 12,253

RA4 $ 31,484 $ 7,290 $ 6,122 $ 13,127 $ 11,570

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

Equipment to add tracers.

N/A

N/A N/A N/A

N/A

N/A N/A

N/A N/A

Electricity cost for pumps and 

equipment.

N/A N/A $5.20/acre 

Injection well O&M.

Pay rent for land use and rights-ofway.

6 hours/ well $664

 $0.03/$1 

CAPEX 

N/A

$0.05/ton of 

CO2 injected 

N/A

N/A $10,400/well 

$0.066/KWh 

N/A

N/A

 $0.10/unit 

CO2 injected 

Develop a corrosion monitoring and 

prevention program.

N/A N/A $15,500/well 

Corrosion monitoring: analysis of 

injectate stream and measurement of 

corrosion of well material coupons.

Continuous measurement / monitoring 

equipment: injected volumes, 

pressure, flow rates and annulus 

pressure.

$110.62

$2,655

N/A

1.5% of total 

capital costs 

$110.62 24 N/A 

 $25/ well

$300/sample 

 $77,500/ 

injection well

$3.10/foot 

(depth)/ 

injection well 

 1% of initial 

well and 

equipment 

cost 

N/A

$0.36/metric 

ton 

N/A

N/A

N/A

N/A

N/A N/A

N/A N/A

N/A N/A

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which each project under 

a given alternative is expected to engage in the activity (see Section 5.2).

Pore space use costs.

General failure of containment at site: 

cost to remove and relocate the CO2.

Tracers in injected fluid.

Repair and replace wells and 

equipment.

Property Taxes & Insurance.

N/A N/A

N/A

Contribution to Long-term Monitoring, 

Insurance, and Remediation Fund.

Cost Analysis for the 5-18 November 2010 

Final GS Rule
5.4.5.1 Annualized Costs for Injection Well Operation 

Annualized costs for owners and operators under the well operation rule component for 

the baseline and RA 1- 4 are presented in Exhibit 5.10. 

Exhibit 5.10 Owner and Operator Cost Estimates for Well Operation – Annualized 

Values Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

Baseline $ 41.81 $ 28.23

RA1 $ 44.62 $ 30.17

Incremental RA1 $ 2.81 $ 1.94

RA2 $ 45.87 $ 31.03

Incremental RA2 $ 4.06 $ 2.80

RA3 $ 50.27 $ 34.16

Incremental RA3 $ 8.46 $ 5.92

RA4 $ 48.51 $ 32.99

Incremental RA4 $ 6.70 $ 4.75

Regulatory Alternative 

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.6 Mechanical Integrity Testing 

Under the GS Rule, owners and operators must demonstrate internal mechanical integrity 

by continuously monitoring injection pressure, flow rate, injected volumes, and pressure on the 

annulus between the tubing and the long string casing. GS owners and operators will need to 

install monitoring equipment on each well to monitor these parameters. Costs for installing the 

monitoring equipment are accounted for under the injection well construction rule component, 

but because this equipment is used to monitor both well operation and integrity, equipment costs 

are accounted for under the monitoring rule component (see Section 5.4.7). 

Owners and operators will demonstrate external mechanical integrity at least once per year using 

a tracer survey of the bottom-hole cement (using a CO2 -soluble tracer or a suitable alternative 

method (e.g., Oxygen Activation Log (OAL)), a temperature or noise logs or other tests suitable 

to wells injecting liquid/super critical CO2 fluids as approved by the permitting authority), or if 

required by the director a casing inspection log; or, another suitable method required and/or 

approved by the Director. Owners and operators will perform an initial external MIT after 

completion of well construction and prior to beginning operation in Year 2, and at least once per 

year throughout the life of the well. Exhibit 5.11 presents the owner and operator burden and 

costs for the baseline, the GS Rule, and each RA considered for MIT unit costs. The detailed 

calculations used to develop unit costs are presented in Appendix C of the Cost Analysis. 

Cost Analysis for the 5-19 November 2010 

Final GS Rule
Exhibit 5.11 Owner and Operator Burden and Unit Cost Estimates for Conducting 

MIT (2008$) 

Compliance Activity

Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ 6,210 $ 8,280 $ 8,280 $ 35,190 $ 33,120

RA1 $ 6,210 $ 8,280 $ 8,280 $ 35,190 $ 33,120

RA2 $ 6,210 $ 8,280 $ 8,280 $ 35,190 $ 33,120

RA3 $ 6,210 $ 8,280 $ 8,280 $ 35,190 $ 33,120

RA4 $ - $ - $ - -$ -$ 

RA0 $ - $ - $ - -$ 259,661 $ 

RA1 $ - $ - $ - -$ 259,661 $ 

RA2 $ - $ - $ - -$ 259,661 $ 

RA3 $ 28,009 $ 37,345 $ 22,820 $ 111,095 $ 259,661

RA4 112,035 $ $ 149,380 $ 91,280 $ 444,380 $ 259,661

RA0 $ 3,900 $ 5,200 $ 7,800 $ 22,100 $ 31,200

RA1 $ 3,900 $ 5,200 $ 7,800 $ 22,100 $ 31,200

RA2 $ 3,900 $ 5,200 $ 7,800 $ 22,100 $ 31,200

RA3 $ 7,800 $ 10,400 $ 15,600 $ 44,200 $ 62,400

RA4 $ - $ - $ - -$ -$ 

RA0 $ - $ - $ - -$ $ -

RA1 $ - $ - $ - -$ -$ 

RA2 $ - $ - $ - -$ -$ 

RA3 $ - $ - $ - -$ -$ 

RA4 $ 7,800 $ 10,400 $ 15,600 $ 44,200 $ 62,400

RA0 $ - $ - $ - -$ -$ 

RA1 $ - $ - $ - -$ -$ 

RA2 $ - $ - $ - -$ -$ 

RA3 $ 56,018 $ 74,690 $ 68,460 $ 222,190 $ 194,746

RA4 $ - $ - $ - -$ -$ 

RA0 $ - $ - $ - -$ -$ 

RA1 $ - $ - $ - -$ -$ 

RA2 $ - $ - $ - -$ -$ 

RA3 $ - $ - $ - -$ -$ 

RA4 $ 56,018 $ 74,690 $ 68,460 $ 222,190 $ 194,746

RA0 $ 3,105 $ 4,140 $ 6,210 $ 17,595 $ 24,840

RA1 $ 3,105 $ 4,140 $ 6,210 $ 17,595 $ 24,840

RA2 $ 3,105 $ 4,140 $ 6,210 $ 17,595 $ 24,840

RA3 $ 6,210 $ 8,280 $ 12,420 $ 35,190 $ 49,680

RA4 $ - $ - $ - -$ -$ 

RA0 $ - $ - $ - -$ -$ 

RA1 $ - $ - $ - -$ -$ 

RA2 $ - $ - $ - -$ -$ 

RA3 $ - $ - $ - -$ -$ 

RA4 $ 6,210 $ 8,280 $ 8,280 $ 35,190 $ 33,120

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

Conduct a tracer survey of the 

bottom-hole cement using a 

CO2-soluble isotope. N/A

N/A

N/A

Conduct pressure fall-off test. N/A

 $2,070/ 

injection 

well 

N/A

N/A N/A

N/A

 $2,070/ 

injectionwel

l

$4/foot 

N/A (depth)

Internal Mechanical integrity 

pressure test.

N/A N/A

N/A N/A

Casing inspection log. 

Conduct a tracer survey of the 

bottom-hole cement using a 

CO2-soluble isotope.

N/A

 $2,070/ 

injection 

well 

N/A N/A

N/A

N/A

 $2,070/ 

injection 

well

$4/foot 

(depth)

N/A

 $2,070/ 

injection 

well

$4/foot 

(depth)

N/A

 $5,200/ 

injection 

well 

N/A

 $5,200/ 

injection 

N/A well 

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which 

each project under a given alternative is expected to engage in the activity (see Section 5.2).

N/A N/A

External mechanical integrity 

tests to detect flow adjacent to 

well using temperature or 

noise log at least every 6 

months.

External mechanical integrity 

tests to detect flow adjacent to 

well using temperature or 

noise log at least annually.

 $2,070/ 

injection 

well 

Conduct pressure fall-off test.

5.4.6.1 Annualized Costs for Mechanical Integrity Testing 

Annualized costs for owners and operators under the MIT rule component for the 

baseline and RA 1- 4 are presented in Exhibit 5.12. 

Cost Analysis for the 5-20 November 2010 

Final GS Rule
Exhibit 5.12 Owner and Operator Cost Estimates for MIT – Annualized Values 

Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

Baseline $ 0.15 $ 0.09

RA1 $ 0.22 $ 0.13

Incremental RA1 $ 0.07 $ 0.04

RA2 $ 0.22 $ 0.13

Incremental RA2 $ 0.07 $ 0.04

RA3 $ 2.73 $ 1.71

Incremental RA3 $ 2.57 $ 1.62

RA4 $ 8.87 $ 5.64

Incremental RA4 $ 8.72 $ 5.54

Regulatory Alternative 

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.7 Monitoring 

To ensure that the CO2 remains safely sequestered in the injection zone and will not 

endanger USDWs, owners and operators will implement an extensive monitoring program. The 

monitoring program will be necessary to: supply the information that provides for an ongoing 

assessment of risk to USDWs, provide real time feedback for assessing parameters of the 

injection process, provide early warnings of failure, and verify that the CO2 plume is behaving as 

expected. 

Under the GS Rule, owners and operators must monitor the nature of the injectate and 

continuously monitor injection pressure, rates, and volumes, as well as the pressure on the 

annulus. Owners and operators must also monitor the well materials for signs of corrosion; this is 

addressed in Section 5.4.5 (Well Operation). 

Owners and operators of GS wells must also track the position of the CO2 plume and 

pressure front; this can be done by monitoring pressure changes above and within the confining 

zone, and, if appropriate, by using geophysical techniques (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or other down-hole CO2 detection tools). Owners and operators 

must also conduct a pressure fall-off test at least once every five years for RA0– RA3, and every 

six months for RA4 (the cost of this test is included with MIT costs in Section 5.4.6). 

The GS Rule requires owners and operators to monitor ground water quality and 

geochemical changes above the confining zone using a network of monitoring wells and to track 

changes relative to baseline geochemical data. For oil and gas reservoirs, owners and operators 

will need to install U-tube sensors to detect oil movement in the bottom of the formation. Costs 

for installing the monitoring equipment and costs for the monitoring equipment itself are 

accounted for under this monitoring component. For the purposes of this analysis, monitoring 

equipment has been categorized into subsurface equipment (installed in wells) and surface 

equipment. Monitoring wells may have permanently installed down-hole equipment to measure 

pressure, temperature, resistivity, salinity, pH, pressure, and temperature. This equipment is used 

to monitor well operation and integrity. An additional cost for ER projects only is the installation 

and maintenance of a U-tube for sensing movement of oil away from the injection formation. 

Cost Analysis for the 5-21 November 2010 

Final GS Rule
Cost Analysis for the 5-22 November 2010 

Final GS Rule

Some surface monitoring technologies require specific equipment to be installed. Most 

surface monitoring costs will be non-equipment or labor costs to conduct the surveys and analyze 

the data. Seismic monitoring and monitoring of CO2 flux from the surface will require 

installation of monitoring equipment. Surface or near-surface monitoring equipment installation 

costs (if this monitoring is required by the Director) will be incurred in Year 1 of each project. 

Additionally, the GS Rule requires that owners and operators update the AoR using 

computational (complex) modeling of the CO2 fluid flow at minimum every 5 years. EPA also 

assumes that owners and operators under RA0-RA3 would develop a 100-year forecast and 

under the more stringent RA4 would develop a 10,000-year forecast. Owners and operators will 

also need to develop, review, and possibly revise their corrective action plans, monitoring and 

testing, well plugging, PISC and site closure, and emergency and remedial response plans as 

needed based on changes in the AoR. 

Exhibit 5.13 presents the owner and operator burden and costs for the baseline, the GS 

Rule, and each RA considered for monitoring unit costs. The detailed calculations used to 

develop unit costs are presented in Appendix C of the Cost Analysis. 
Exhibit 5.13 Owner and Operator Burden and Unit Cost Estimates for Monitoring 

(2008$) 

Compliance Activity

Labor Cost

($/hour)

Labor 

Burden 

(hours)

Labor Cost 

($)

 Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA 0 $ 621 $ 828 $ 1,242 $ 3,519 $ 4,968

RA 1 $ 621 $ 828 $ 1,242 $ 3,519 $ 4,968

RA 2 $ 1,242 $ 1,656 $ 2,484 $ 7,038 $ 9,936

RA 3 $ 2,484 $ 3,312 $ 4,968 $ 14,076 $ 19,872

RA 4 $ 2,484 $ 3,312 $ 4,968 $ 14,076 $ 19,872

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

 RA 0 $ 6,475 $ 20,304 $ 27,869 $ 10,603 $ 13,317

RA 1 $ 12,950 $ 40,609 $ 55,738 $ 21,206 $ 26,634

RA 2 $ 12,950 $ 40,609 $ 55,738 $ 21,206 $ 26,634

RA 3 $ 25,900 $ 50,959 $ 66,088 $ 31,556 $ 36,984

RA 4 $ 25,900 $ 50,959 $ 66,088 $ 31,556 $ 36,984

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ 5,200 $ 30,259 $ 45,388 $ 10,856 $ 16,284

RA 4 $ 5,200 $ 30,259 $ 45,388 $ 10,856 $ 16,284

RA 0 $ 2,600 $ 30,259 $ 45,388 $ 10,856 $ 16,284

RA 1 $ 5,200 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 2 $ 5,200 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 3 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 4 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ 90,776 - $ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 4 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

RA 0 $ 375 $ 500 $ 500 $ 2,125 $ 2,000

RA 1 $ 375 $ 500 $ 500 $ 2,125 $ 2,000

RA 2 $ 375 $ 500 $ 500 $ 2,125 $ 2,000

RA 3 $ 375 $ 500 $ 500 $ 2,125 $ 2,000

RA 4 $ 1,500 $ 2,000 $ 2,000 $ 8,500 $ 8,000

RA 0 $ 121,625 $ 1,415,472 $ 2,241,164 $ 218,156 $ 308,552

RA 1 243,250 $ $ 2,830,944 $ 4,482,328 $ 436,313 $ 617,103

RA 2 243,250 $ $ 2,830,944 $ 4,482,328 $ 436,313 $ 617,103

RA 3 486,501 $ $ 2,830,944 $ 4,482,328 $ 436,313 $ 617,103

RA 4 486,501 $ $ 2,830,944 $ 4,482,328 $ 436,313 $ 617,103

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 1,095,384 $ $ 6,374,033 $ 4,576,692 $ 1,303,421 $ 1,133,776

RA 4 1,095,384 $ $ 6,374,033 $ 4,576,692 $ 1,303,421 $ 1,133,776

RA 0 $ 2,600 $ 30,259 $ 90,776 $ 10,856 $ 32,568

RA 1 $ 5,200 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 2 $ 5,200 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 3 $ 10,400 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 4 $ 10,400 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 4 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA 0 $ 2,600 $ 30,259 $ 90,776 $ 10,856 $ 32,568

RA 1 $ 5,200 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 2 $ 5,200 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 3 $ 10,400 $ 60,518 $ 181,553 $ 21,712 $ 65,135

RA 4 $ 10,400 $ 60,518 $ 181,553 $ 21,712 $ 65,135

 RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

N/A RA 4 $ 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568

N/A

N/A

N/A

Salinity, CO2, tracer, etc. 

monitoring equipment for wells 

stopping above the injection 

zone (portion of equipment 

may be at surface such as for 

periodic in situ sampling using

Check valve (Director 

discretion to require down-hole 

shut-off valve, but expected to 

be check valves in all but the 

most exceptional cases).

N/A

Standard monitoring well 

stopping above the confining 

zone (used look up table). 

Standard monitoring wells for 

ER projects stop below the 

Salinity, CO2, tracer, etc. 

monitoring equipment for wells 

drilling into the injection zone 

(portion of equipment may be 

at surface such as for periodic 

in situ sampling using U-tubes; 

N/A

N/A

Pressure, temperature, and 

resistivity gauges and related 

equipment for monitoring wells 

drilling into the injection zone 

(application factor reflects 

Obtain rights-of-way for 

surface uses (monitoring 

sites).

Obtain rights-of-way for 

surface uses (monitoring wells 

drilling into injection zone). N/A N/A

Develop geochemical baseline 

for injection zones and 

confining zone. Assumes 4 

samples per injection well. N/A

Conduct front-end engineering 

and design for monitoring 

wells drilling into the injection 

zone.

N/A

N/A

Develop baseline of surface 

air CO2 flux for leakage 

monitoring. N/A

Conduct front-end engineering 

and design for monitoring 

wells stopping above the 

confining zone. N/A

Obtain rights-of-way for 

surface uses (monitoring wells 

stopping above confining 

zone).

N/A

N/A

N/A N/A

N/A

N/A N/A $200/sample

N/A $35,000/station

N/A

N/A

N/A

$5,000/ 

monitoring well

$10,000/ 

monitoring well

$100-$130/foot 

(depth) down to 

9,000 feet

$20,000/site

$5,000/ 

monitoring well

$5,000/air 

monitoring 

station site

$15,000/site

$2/foot (depth)

$10,000/ 

monitoring well

$100-$130/foot 

(depth) down to 

9,000 feet

$10,000/ 

monitoring well

$10,000/ 

monitoring well

$10,000/ 

monitoring well

$10,000/ 

monitoring well

N/A

Standard monitoring well 

drilled into the injection zone 

(used look up table; applies to 

RA3-4 only).

Pressure, temperature, and 

resistivity gauges and related 

equipment for monitoring wells 

stopping above the injection 

zone (application factor 

N/A N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Cost Analysis for the 5-23 November 2010 

Final GS Rule
Compliance Activity

Labor Cost

($/hour)

Labor 

Burden 

(hours)

Labor Cost 

($)

 Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - $ 10,550 - $ $ 30,485

RA 2 $ - $ - $ 10,550 - $ $ 30,485

RA 3 $ - $ - $ 44,050 - $ $ 127,286

RA 4 $ - $ - $ 44,050 - $ $ 127,286

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

RA 0 $ - $ - -$ -$ $ -

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - $ - $ - $ -

RA 0 $ 21,072 $ 21,072 $ 31,608 $ 21,072 $ 31,608

RA 1 $ 21,072 $ 21,072 $ 31,608 $ 21,072 $ 31,608

RA 2 $ 42,145 $ 42,145 $ 63,217 $ 42,145 $ 63,217

RA 3 $ 85,898 $ 85,898 $ 128,847 $ 85,898 $ 128,847

RA 4 $ 85,898 $ 85,898 $ 128,847 $ 85,898 $ 128,847

RA 0 $ 255 $ 2,971 $ 6,685 $ 1,066 $ 2,399

RA 1 $ 511 $ 3,227 $ 7,260 $ 1,321 $ 2,973

RA 2 $ 1,021 $ 6,453 $ 14,520 $ 2,643 $ 5,946

RA 3 $ 2,042 $ 11,885 $ 26,742 $ 4,264 $ 9,594

RA 4 $ 2,042 $ 11,885 $ 26,742 $ 4,264 $ 9,594

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ 13,000 $ 65,000 $ 65,000 $ 26,000 $ 26,000

RA 0 $ 9,963 $ 115,943 $ 177,297 $ 38,037 $ 56,114

RA 1 $ 19,925 $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA 2 $ 19,925 $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA 3 $ 39,850 $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA 4 $ 39,850 $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ 25,893 - $ -$ -$ -$ 

RA 2 $ 25,893 - $ -$ -$ -$ 

RA 3 $ 51,785 $ 301,336 $ 357,301 $ 91,445 $ 113,984

RA 4 $ 51,785 $ 301,336 $ 357,301 $ 91,445 $ 113,984

RA 0 $ - $ - $ - $ 2,500 $ 5,000

RA 1 $ - $ - $ - $ 6,627 $ 14,882

RA 2 $ - $ - $ - $ 6,627 $ 14,882

RA 3 $ - $ - $ 16,795 - $ $ 40,386

RA 4 $ - $ - $ 16,795 - $ $ 40,386

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

RA 0 $ - $ - -$ -$ -$ 

RA 1 $ - $ - -$ -$ -$ 

RA 2 $ - $ - -$ -$ -$ 

RA 3 $ - $ - -$ -$ -$ 

RA 4 $ - $ - -$ -$ -$ 

N/A

$110.62 

96 hours/ 

sample

N/A

$107.23

N/A

40

Monitoring well O&M for wells 

drilling into the injection zone.

Develop a monitoring and 

testing plan, an emergency 

response plan, a post-injection 

site care and site closure plan 

and implement monitoring

Develop plan and implement 

vadose zone monitoring wells 

to sample gas above water 

table.

ER only. U-tube O&M for 1 of 

4 monitoring wells drilled into 

the injection zone.

Conduct periodic monitoring of 

groundwater quality and 

geochemistry.

Surface microseismic 

detection equipment: 

geophone arrays in monitoring 

wells.

Monitoring well O&M for wells 

stopping above the injection 

zone.

0.5 hr/sample

N/A

N/A

N/A

$110.62

N/A

$55.31/sampl

e

N/A

$30,000/ 

monitoring well

$18/foot 

(depth)

N/A

$80,000/site

$200/sample

$4,289

$10,619.52/sa

mple

N/A

N/A

N/A

55

N/A

40

N/A

Develop plan and implement 

soil zone monitoring.

Develop plan and implement 

LIDAR airborne survey to 

detect surface leaks. Works 

best where vegetation is 

sparse. Costs are for planning N/A N/A

Develop plan and implement 

Eddy Covariance air 

monitoring.

Develop plan and implement 

Digital Color Infrared 

Orthoimagery (CIR) or 

Hyperspectral Imaging to 

detect changes to vegetation. 

ER only. U-tube for sensing oil 

movement away from bottom 

of formation. Applies to 1 of 

every 4 monitoring wells drilled 

into the injection zone.

$107.23

$107.23

$8,000/site

$25,000/ 

monitoring well

$3/foot (depth)

$5,000/ site

$6,250/ square 

mile

$25,000/ 

monitoring well

$3/foot (depth)

$10,000/square 

mile

$50,000/ 

monitoring site

N/A

Annual cost of air and soil 

surveys: Eddy Covariance.

N/A

N/A N/A

N/A

Annual cost of air and soil 

surveys: Digital Color Infrared 

Orthoimagery (CIR) or 

Hyperspectral Imaging to 

detect changes to vegetation.

$10,000/square 

mile

$75,000/ 

monitoring site

$107.23

40

N/A

$4,289

$5,898

N/A

$12,400/ 

sample

$10,000/ 

station

N/A

$4,289 $6,000/site

Cost Analysis for the 5-24 November 2010 

Final GS Rule
Compliance Activity

Labor Cost

($/hour)

Labor 

Burden 

(hours)

Labor Cost 

($)

 Non-labor 

unit Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ - $ - -$ -$ -$ 

RA4 $ - $ - -$ -$ -$ 

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ - $ - -$ -$ -$ 

RA4 $ - $ - -$ -$ -$ 

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ - $ - -$ -$ -$ 

RA4 $ - $ - -$ -$ -$ 

RA0 $ - $ - -$ -$ $ -

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ - $ - -$ -$ -$ 

RA4 $ - $ - -$ -$ -$ 

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ - $ - -$ -$ -$ 

RA4 $ 2,625 $ 13,125 $ 13,125 $ 5,250 $ 5,250

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 229,905 $ $ 1,210,925 $ 1,231,063 $ 621,652 $ 616,490

RA3 229,905 $ $ 1,210,925 $ 1,231,063 $ 621,652 $ 616,490

RA4 459,811 $ $ 2,421,850 $ 2,462,125 $ 1,243,304 $ 1,232,980

RA0 $ 10,288 $ 12,058 $ 18,087 $ 35,068 $ 49,947

RA1 $ 10,288 $ 12,058 $ 18,087 $ 35,068 $ 49,947

RA2 $ 10,288 $ 12,058 $ 18,087 $ 35,068 $ 49,947

RA3 $ 43,143 $ 50,887 $ 76,331 $ 151,555 $ 215,717

RA4 $ 49,781 $ 59,737 $ 89,605 $ 189,167 $ 268,816

RA0 $ - $ - -$ -$ -$ 

RA1 $ 4,867 $ 4,867 $ 4,867 $ 4,867 $ 4,867

RA2 $ 4,867 $ 4,867 $ 4,867 $ 4,867 $ 4,867

RA3 $ - $ - -$ -$ -$ 

RA4 $ - $ - -$ -$ -$ 

RA0 $ 1,079 $ 1,079 $ 1,079 $ 1,079 $ 1,079

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ 3,651 $ 3,651 $ 3,651 $ 3,651 $ 3,651

RA4 $ - $ - -$ -$ -$ 

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 $ - $ - -$ -$ -$ 

RA3 $ - $ - $ - -$ -$ 

RA4 $ 1,217 $ 1,217 $ 1,217 $ 1,217 $ 1,217

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

N/A

N/A

N/A

N/A

N/A N/A

N/A N/A

N/A

Semi-Annual (RA3) or 

quarterly (RA0) reports to 

regulators and recordkeeping 

for all data gathering activities.

Annual reports to regulators 

and recordkeeping for all data 

gathering activities. 44

$110.62 

180 hours/ 

project site + 

70 or 90 

hours/well

N/A

N/A

N/A

Annual cost of passive seismic 

equipment.

Complex modeling of fluid 

flows and migration (reservoir 

simulations) over 100 years 

(RA0-3) or 10,000 years 

(RA4). Includes AoR and 

Annual cost of air and soil 

surveys: LIDAR airborne 

survey to detect surface leaks. 

Works best where vegetation 

is sparse.

Annual cost of air and soil 

surveys: soil zone monitoring.

Annual cost of air and soil 

surveys: monitoring wells for 

gas samples from water table.

Periodic seismic surveys: 3D.

Annual cost of air and soil 

surveys: vadose zone 

monitoring wells to sample 

gas above water table.

$5,000/ site

$6,250/ square 

mile

N/A N/A

N/A

$19,911.60 

per project 

site + $9,956 

per well

$300/sample

$1,200/sample

$10,500/ 

station

N/A $300/sample

N/A

N/A

$1,217 

$104,000/ 

square mile

N/A

N/A

N/A

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which each project 

under a given alternative is expected to engage in the activity (see Section 5.2).

$4,867 

$3,651 

N/A

$110.62 11

Monthly reports to regulators 

and recordkeeping for all data 

gathering activities and 

recordkeeping.

$110.62 33

$110.62 

5.4.7.1 Annualized Costs for Monitoring 

Annualized costs for owners and operators under the monitoring rule component for the 

baseline and RAs 1- 4 are presented in Exhibit 5.14. 

Cost Analysis for the 5-25 November 2010 

Final GS Rule
Exhibit 5.14 Owner and Operator Cost Estimates for Monitoring – Annualized 

Values Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

Baseline $ 3.39 $ 2.90

RA1 $ 7.07 $ 6.08

Incremental RA1 $ 3.67 $ 3.19

RA2 $ 11.43 $ 8.96

Incremental RA2 $ 8.03 $ 6.07

RA3 $ 21.95 $ 18.65

Incremental RA3 $ 18.56 $ 15.76

RA4 $ 24.43 $ 20.06

Incremental RA4 $ 21.04 $ 17.16

Regulatory Alternative 

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.8 Well Plugging and Post-injection Site Care 

Following cessation of injection, owners and operators must plug injection wells to 

ensure that they do not become conduits for fluid movement. To do this, owners and operators 

will flush the well with a buffer fluid, perform a final external mechanical integrity test, and plug 

the well in a manner that will prevent the movement of fluid that may endanger USDWs. EPA 

assumes that injection wells will be plugged 1 year after completion of the injection phase. 

Following injection, owners and operators must perform PISC to show the position of the 

CO2 plume and pressure front and ensure that they will no longer pose an endangerment to 

USDWs. Under RAs 0-2, PISC must be performed for at least 10 years. For RA3 the default 

PISC period is 50 years; data submitted as part of the permit application, or collected during 

PISC and submitted to the Director can be used to request a shorter PISC period, subject to 

Director approval. Under RA4, PISC must be performed for 100 years (unless the Director 

approves a shorter time frame). However, this cost analysis considers only the costs that are 

incurred in the 50-year period of analysis from 2011 to 2060. PISC costs that are incurred in this 

period may include monitoring well O&M, seismic surveys, and air and soil tests, along with an 

updated demonstration of the financial capacity to plug the well. 

PISC monitoring costs are generally assumed to be incurred at 5-year intervals from the 

year the injection is stopped until the end of the post-injection monitoring period (50 years for 

RA3), a portion of which is captured in the 50 year period of this Cost Analysis. 

At the end of the PISC monitoring period, owners and operators must perform a nonendangerment demonstration showing that the CO2 plume and pressure front have stabilized and 

that no additional monitoring is needed to assure that the project does not pose an endangerment 

to USDWs. If, based on this demonstration, the Director authorizes closure of the site, closure 

activities would include plugging the monitoring wells, removing surface equipment, and 

restoring the land. 

 

Cost Analysis for the 5-26 November 2010 

Final GS Rule
 Exhibit 5.15 presents the owner and operator burden and costs for the baseline, the GS 

Rule, and each RA considered for Well Plugging and PISC unit costs. Detailed calculations used 

to develop unit costs are presented in Appendix C of the Cost Analysis. 

Exhibit 5.15 Owner and Operator Burden and Unit Cost Estimates for Well 

Plugging and PISC (2008$) 

Compliance Activity

Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

 Non-labor unit 

Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost 

Large 

Waivered 

Project - 

Saline

Project Cost 

Large Project 

- ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EF G H I J

RA0 $ 1,292 $ 1,723 $ 1,425 $ 6,345 $ 5,160

RA1 $ 1,292 $ 1,723 $ 1,425 $ 6,345 $ 5,160

RA2 $ 2,584 $ 3,445 $ 2,850 $ 12,691 $ 10,320

RA3 $ 5,168 $ 6,890 $ 5,700 $ 25,381 $ 20,640

RA4 $ 5,168 $ 6,890 $ 5,700 $ 25,381 $ 20,640

RA0 $ 56,025 $ 74,700 $ 74,700 $ 317,475 $ 298,800

RA1 56,025 $ $ 74,700 $ 74,700 $ 317,475 $ 298,800

RA2 56,025 $ $ 74,700 $ 74,700 $ 317,475 $ 298,800

RA3 74,700 $ $ 99,600 $ 99,600 $ 423,300 $ 398,400

RA4 74,700 $ $ 99,600 $ 99,600 $ 423,300 $ 398,400

RA0 $ 28,009 $ 37,345 $ 22,820 $ 111,095 $ 64,915

RA1 28,009 $ $ 37,345 $ 22,820 $ 111,095 $ 64,915

RA2 56,018 $ $ 74,690 $ 45,640 $ 222,190 $ 129,831

RA3 112,035 $ $ 149,380 $ 91,280 $ 444,380 $ 259,661

RA4 112,035 $ $ 149,380 $ 91,280 $ 444,380 $ 259,661

 RA0 $ 3,100 $ 36,078 $ 54,117 $ 12,944 $ 19,415

RA1 $ 6,200 $ 72,155 $ 108,233 $ 25,887 $ 38,831

RA2 $ 6,200 $ 72,155 $ 108,233 $ 25,887 $ 38,831

RA3 12,400 $ $ 72,155 $ 108,233 $ 25,887 $ 38,831

RA4 12,400 $ $ 72,155 $ 108,233 $ 25,887 $ 38,831

 RA0 $ - $ - -$ $ - $ -

RA1 $ - $ - -$ $ - $ -

RA2 $ - $ - -$ $ - $ -

RA3 12,400 $ $ 72,155 $ 108,233 $ 25,887 $ 38,831

RA4 12,400 $ $ 72,155 $ 108,233 $ 25,887 $ 38,831

RA0 $ 77,700 $ 103,600 $ 103,600 $ 440,300 $ 414,400

RA1 77,700 $ $ 103,600 $ 103,600 $ 440,300 $ 414,400

RA2 77,700 $ $ 103,600 $ 103,600 $ 440,300 $ 414,400

RA3 77,700 $ $ 103,600 $ 103,600 $ 440,300 $ 414,400

RA4 77,700 $ $ 103,600 $ 103,600 $ 440,300 $ 414,400

RA0 $ 2,600 $ 30,259 $ 45,388 $ 10,856 $ 16,284

RA1 $ 5,200 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA2 $ 5,200 $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA3 10,400 $ $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA4 10,400 $ $ 60,518 $ 90,776 $ 21,712 $ 32,568

 RA0 $ - $ - -$ $ - $ -

RA1 $ - $ - -$ $ - $ -

RA2 $ - $ - -$ $ - $ -

RA3 10,400 $ $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA4 10,400 $ $ 60,518 $ 90,776 $ 21,712 $ 32,568

RA0 $ 6,637 $ 6,637 $ 6,637 $ 6,637 $ 6,637

RA1 $ 6,637 $ 6,637 $ 6,637 $ 6,637 $ 6,637

RA2 $ 6,637 $ 6,637 $ 6,637 $ 6,637 $ 6,637

RA3 13,275 $ $ 13,275 $ 13,275 $ 13,275 $ 13,275

$13,275 RA4 13,275 $ $ 13,275 $ 13,275 $ 13,275 $ 13,275

 RA0 $ 9,963 $ 115,943 $ 177,297 $ 38,037 $ 56,114

RA1 19,925 $ $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA2 19,925 $ $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA3 39,850 $ $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA4 39,850 $ $ 231,887 $ 354,595 $ 76,075 $ 112,228

RA0 $ - $ - -$ $ - $ -

RA1 $ - $ - -$ $ - $ -

RA2 $ - $ - -$ $ - $ -

RA3 51,785 $ $ 301,336 $ 357,301 $ 91,445 $ 113,984

RA4 51,785 $ $ 301,336 $ 357,301 $ 91,445 $ 113,984

RA0 $ - $ - -$ $ - $ -

RA1 $ - $ - -$ $ - $ -

RA2 $ - $ - -$ $ - $ -

RA3 $ - $ - -$ $ - $ -

RA4 $ - $ - -$ $ - $ -

Post-closure O&M for 

monitoring wells drilling into 

injection zone (continues until 

plume has stabilized).

Post-injection air and soil 

surveys.

Document plugging and closure 

process (well plugging, postinjection plans, notification of 

intent to close, and post closure 

report).

Perform a mechanical integrity 

test prior to plugging to evaluate 

integrity of casing and cement to 

remain in ground.

Plug monitoring wells stopping 

above injection zone. Use one 

cement plug from the surface to 

the bottom of UDSWs, fill the 

remainder of the borehole with 

mud.

Remove surface equipment and 

structures; restore vegetation 

(injection wells).

Post-closure O&M for 

monitoring wells stopping above 

injection zone (continues until 

plume has stabilized).

Plug monitoring wells drilling into 

injection zone. Use one cement 

plug from the surface to the 

bottom of UDSWs, fill the 

remainder of the borehole with 

mud.

N/A N/A

$1,000/ injection 

well

$0.085/foot 

N/A (depth)

Flush wells with a buffer fluid 

before plugging.

$10,400/ 

monitoring well

$5,200/ 

monitoring 

station

$110.62

Remove surface equipment and 

structures; restore vegetation 

(monitoring well stopping above 

injection zone).

N/A

Remove surface equipment and 

structures; restore vegetation 

(monitoring wells drilling into 

injection zone).

N/A

N/A

$25,000/ 

monitoring well

$3/foot (depth)/ 

monitoring well

$25,900/ 

N/A injection well

N/A

$25,900/ 

monitoring well

$3.10/foot 

(depth)/ 

N/A monitoring well

N/A

N/A

$10,400/ 

N/A monitoring well

Plug injection wells. Use two 

cement plugs: one in producing 

formation and one for surface to 

bottom of USDWs, fill the 

remainder of the borehole with 

N/A

N/A

N/A

N/A

N/A N/A

N/A

N/A

N/A N/A

N/A

N/A N/A

N/A

120

N/A

N/A

N/A

N/A N/A $10,400/ station

N/A

N/A

N/A

$12,400/ 

monitoring well

 $24,900/ 

injection well 

$2,070/ injection 

well

$4.15/foot 

(depth)

$12,400/ 

monitoring well

Cost Analysis for the 5-27 November 2010 

Final GS Rule
Compliance Activity

Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

 Non-labor unit 

Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EF G H I J

RA0 $ - $ - $ - $ - -$ 

RA1 $ - $ - $ - $ - -$ 

RA2 $ - $ - $ - $ - -$ 

RA3 229,905 $ $ 1,210,925 $ 1,231,063 $ 621,652 $ 616,490

RA4 459,811 $ $ 2,421,850 $ 1,243,304 2,462,125 $ $ 1,232,980

 RA0 $ - $ - $ - $ - -$ 

RA1 $ - $ - $ - $ - -$ 

RA2 $ 4,425 $ 4,425 $ 4,425 $ 4,425 $ 4,425

RA3 $ 4,425 $ 4,425 $ 4,425 $ 4,425 $ 4,425

$4,425 RA4 $ 4,425 $ 4,425 $ 4,425 $ 4,425 $ 4,425

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

Periodic post-injection 

monitoring reports to regulators.

Post-injection seismic survey. N/A

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which 

each project under a given alternative is expected to engage in the activity (see Section 5.2).

$110.62 40 N/A

N/A N/A

$104,000/ 

square mile

5.4.8.1 Annualized Costs for Well Plugging and PISC 

Annualized costs for owners and operators under the well-plugging and PISC component 

of the GS Rule for the baseline and RA 1- 4 are presented in Exhibit 5.16. 

Exhibit 5.16 Owner and Operator Cost Estimates for Well Plugging and PISC – 

Annualized Values Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

Baseline $ 0.59 $ 0.24

RA1 $ 0.86 $ 0.33

Incremental RA1 $ 0.27 $ 0.09

RA2 $ 0.91 $ 0.35

Incremental RA2 $ 0.33 $ 0.12

RA3 $ 2.76 $ 1.01

Incremental RA3 $ 2.17 $ 0.77

RA4 $ 3.26 $ 1.18

Incremental RA4 $ 2.67 $ 0.95

Regulatory Alternative 

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.9 Financial Responsibility 

Under RA1 owners and operators have no requirement to demonstrate financial 

responsibility; under RA2 and the baseline (RA0) the owner and operator would provide 

financial assurance through a performance bond, or other appropriate means, of the resources 

necessary to plug the well. 

Cost Analysis for the 5-28 November 2010 

Final GS Rule
RA3 and RA4 require the owners and operators to demonstrate and maintain financial 

responsibility for not only plugging the injection well, but also for all needed corrective action, 

emergency and remedial response, and PISC and closure (accounting for inflation). EPA 

assumes that owners and operators will post a performance bond and periodically re-evaluate the 

costs during the injection and PISC phases of the project. Financial responsibility following the 

injection phase is assumed to be demonstrated by posting a second bond when the wells are 

plugged in addition to the first bond posted prior to deployment. All GS well owners and 

operators are required to demonstrate financial responsibility. Exhibit 5.15 presents the owner 

and operator burden and costs for the baseline, the GS Rule, and each RA considered for 

Financial Responsibility unit costs. 

Exhibit 5.17 Owner and Operator Burden and Unit Cost Estimates for Financial 

Responsibility (2008$)

Compliance Activity

Labor 

Cost

($/hour)

Labor 

Burden 

(hours)

Labor 

Cost ($)

 Nonlabor unit 

Cost1

Regulatory 

Alternative

Project Cost 

Pilot Project -

Saline

Project Cost 

Large 

Project - 

Saline

Project Cost

Large 

Waivered 

Project - 

Saline

Project Cost 

Large 

Project - ER

Project Cost 

Large 

Waivered 

Project - ER

A B C = B*A D EFGH I J

RA0 $ 885 $ 885 $ 885 $ 885 $ 885

RA1 $ 885 $ 885 $ 885 $ 885 $ 885

RA2 $ 885 $ 885 $ 885 $ 885 $ 885

RA3 $ 885 $ 885 $ 885 $ 885 $ 885

RA4 $ 885 $ 885 $ 885 $ 885 $ 885

RA0 $ - $ - -$ -$ -$ 

RA1 $ - $ - -$ -$ -$ 

RA2 $ 442 $ 442 $ 442 $ 442 $ 442

RA3 $ 442 $ 442 $ 442 $ 442 $ 442

RA4 $ 442 $ 442 $ 442 $ 442 $ 442

Source: GS Cost Model

Notes:

(1) Some cost components include labor burden that is not explicitly shown here.

Sources:

(A) Owner and operator labor cost from Exhibit 5.1.

(B), (D) Owner and operator burden and non-labor unit cost estimates reflect EPA's best professional judgment.

(F)-(J) Nondiscounted Project level cost estimates from final GS Rule cost model, which are also presented in Appendix C of the Cost Analysis.

Performance bond or demonstrate 

financial ability (accounting for 

inflation) for post-injection monitoring 

and remediation. $110.62 4 N/A 

Performance bond or demonstrate 

financial ability (accounting for 

inflation) to close site.

$442

$885

(E) As described in Section 5.2, application factors represent the Agency's best estimate of the percentage of projects to which a given activity is expected to apply, or the extent to which 

each project under a given alternative is expected to engage in the activity (see Section 5.2).

$110.62 8 N/A 

5.4.9.1 Annualized Costs for Financial Responsibility 

Annualized costs for owners and operators under the financial responsibility rule 

component for the baseline and RA 1- 4 are presented in Exhibit 5.18 (unlike the other 

annualized cost tables, Exhibit 5.18 is in 2008 dollars, not millions of 2008 dollars). 

Cost Analysis for the 5-29 November 2010 

Final GS Rule
Exhibit 5.18 Owner and Operator Cost Estimates for Financial Responsibility – 

Annualized Values Using a 3% and 7% Discount Rate (2008$) 

3% 7%

Baseline $ 549 $ 257

RA1 $ 574 $ 267

Incremental RA1 $ 26 $ 9

RA2 $ 1,118 $ 809

Incremental RA2 $ 569 $ 552

RA3 $ 1,118 $ 809

Incremental RA3 $ 569 $ 552

RA4 $ 1,066 $ 775

Incremental RA4 $ 518 $ 518

Regulatory Alternative 

Discount Rate

Source: Appendix C, Exhibit C.67/C.68

5.4.10 Emergency and Remedial Response Plans 

GS well owners and operators must develop and implement an emergency and remedial 

response plan that describes actions to be taken to address movement of injection or formation 

fluids that may endanger USDWs. If there is evidence of potential endangerment of USDWs, the 

owner and operator will be required to cease injection, investigate and identify the release, and 

implement the emergency and remedial response plan. Some incidents could require replacement 

of well equipment, or remediation or removal of the CO2. A percentage of the capital costs for 

well operation for each project is assumed to be contributed annually to a fund to account for the 

possible need for well remediation during operation. 

Emergency and remedial response plans must be submitted as an attachment to the UIC 

Program permit application; as such these costs are included along with the permit application 

fee, as described in Section 5.4.4. Implementation of the plan is included in the cost items 

associated with well remediation, presented in Section 5.4.5. In addition, emergency and 

remedial response plans must be reviewed at least every five years, usually in association with 

AoR reevaluation. Costs for any necessary plan revision are included in the costs for AoR 

modeling in Section 5.4.3. 

Annualized costs for owners and operators under the emergency and remedial response 

rule component for the baseline and RAs 1- 4 are included in the costs presented in Exhibits 5.6, 

5.8, and 5.10. 

5.4.11 Permitting Authority Costs 

The following subsections provide a description of the permitting authority’s oversight 

responsibilities for the GS Rule, organized by rule component. Exhibits 5.19 and 5.20 at the end 

of this section provide project level and annualized cost estimates for the permitting authority, 

respectively. 

 

Cost Analysis for the 5-30 November 2010 

Final GS Rule
Cost Analysis for the 5-31 November 2010 

Final GS Rule

5.4.11.1 Rule Implementation and Annual Administration 

The permitting authority will incur administrative costs while implementing the GS Rule. 

These implementation costs are not directly required by specific provisions of GS Rule RAs but 

will be necessary for the permitting authority to ensure that the provisions of the GS Rule are 

properly carried out. The permitting authority will need to allocate time for their staff to establish 

and then maintain the programs necessary to comply with the GS Rule, including developing 

and/or modifying data management systems to track new required owner and operator reports to 

the permitting authority. Permitting authority staff at the State level will need to prepare primacy 

applications, which will be reviewed and approved by EPA. To manage data submitted by 

owners and operators, the permitting authority will also need to modify or develop data 

management systems. Finally, the permitting authority will need to provide technical assistance 

when owners and operators request help in implementing the GS Rule. 

In addition to these one-time costs, the permitting authority will need to expend resources 

for ongoing administrative activities. On an annual basis, the permitting authority will provide 

technical assistance to well owners and operators and to their own staff as needed. Exhibit 5.19 

lists these annual activities with their respective costs and burden. 

5.4.11.2 Geologic Site Characterization 

The permitting authority will incur costs associated with reviewing geological data 

submitted by owners and operators to determine whether a proposed site is suitable for injection 

of large volumes of CO2, such as maps and cross sections, geomechanical data, structural data, 

and seismic data. The permitting authority will review the owners and operators’ site data 

beginning in Year 1 of the project. 

5.4.11.3 Area of Review and Corrective Action 

The permitting authority costs associated with AoR and Corrective Action requirements 

include review of the owner and operator’s proposed AoR and corrective action, which will be 

submitted in compliance with §146.84. The permitting authority will review one plan per GS site 

as they are received from owners and operators during the compliance period. The permitting 

authority will also review owner- and operator-submitted AoR modeling results and the status of 

corrective action in Year 1 and the AoR reevaluations and modified AoR and corrective action 

plans that owners and operators periodically submit over the course of the injection project. 

5.4.11.4 Injection Well Construction 

Permitting authority activities associated with the well construction requirements of the 

GS Rule include review of owner- and operator-submitted construction schematics and 

procedures to assure that the injection well is properly designed to withstand injection of large 

volumes of CO2. 

As they review information on the geology of the site, the AoR, and construction 

procedures described above, the permitting authority will also review the other components of 

the permit application, including proposed monitoring plans, contingency plans, well plugging 

and PISC and site closure plans, and financial responsibility information. Additionally, in limited 
Cost Analysis for the 5-32 November 2010 

Final GS Rule

cases, the permitting authority will also need to review applications for waivers that allow a 

project to inject above the lowermost USDW. In the case of States with primacy, such waivers 

will be reviewed at both the State and Federal level. 

This cost analysis assumes that the permitting authority will review permit applications 

and associated materials in Year 1 of the project, and for some cost items (e.g., AoR evaluations 

and financial responsibility determinations) will review updates to the material periodically, or in 

specific project phases such as prior to plugging of the well for updated PISC and site closure 

plans. 

5.4.11.5 Injection Well Operation 

The permitting authority will not incur any cost or burden associated with operation of 

injection wells. 

5.4.11.6 Mechanical Integrity Testing 

At the Director’s discretion, permitting authorities may visit the project site and witness 

the MITs. (The burden associated with reviewing MIT reports is captured under monitoring, 

below). 

5.4.11.7 Monitoring 

EPA assumes that the permitting authority will incur burden associated with reviewing 

the annual, semi-annual, quarterly, or monthly monitoring reports submitted by well owners and 

operators, including injectate monitoring results, plume tracking data, ground water monitoring, 

MIT results, or other testing performed since the last report. Although reports may occur at 

different frequencies, the cost of reviewing them is considered on an annual basis. The 

permitting authority will review monitoring reports beginning in Year 2 of each project. 

5.4.11.8 Well Plugging and PISC 

 

Permitting authority costs related to well plugging and PISC requirements include review 

and approval of the initial plans submitted with permit applications (which are estimated to occur 

in Year 1) and reviewing periodic updates to plans (which will occur periodically throughout the 

injection phase). 

 Permitting authorities will also review owners and operators’ notification of intent to plug 

their wells and final updates to the closure plan; and reports documenting the well plugging 

process. The permitting authority may, at its discretion, witness the well plugging process or 

post-plugging MITs. This Cost Analysis does not include costs for this discretionary item. 

During the PISC period, the permitting authority will incur costs related to review of 

post-injection monitoring reports. Permitting authorities will also review non-endangerment 

demonstrations following post-injection monitoring; this analysis includes such costs only as 

incurred within the 50-year period of analysis. 
Cost Analysis for the 5-33 November 2010 

Final GS Rule

5.4.11.9 Financial Responsibility 

The permitting authority must review the financial assurance demonstrations provided by 

GS well owners and operators with their permit applications and any updated estimates 

submitted. 

5.4.11.10 Emergency and Remedial Response Plans 

The permitting authority will review emergency and remedial response plans submitted 

by owners and operators along with other attachments to the permit application, which is 

included in the costs for reviewing permit applications. In addition, the permitting authority may 

need to respond to incidences where there is evidence of CO2 leakage or other endangerment to 

USDWs; this cost incurrence is subject to a high degree of uncertainty and is not included in this 

analysis. 
Exhibit 5.19 Permitting Authority Burden and Unit Cost Estimates (2008$) 

State 

Labor 

Cost

($/hour)

Federal 

Labor 

Cost

($/hour)

Regulatory 

Alternative

One-time 

labor burden 

(hrs) State Cost

Federal 

Cost

Weighted 

Project 

Cost2

A B C D E=A*C*0.56 F=B*C*0.44 G=E+F

RA0 0 - $ $ - -$ 

RA1 12 $ 593 $ - $ 593

RA2 12 $ 593 $ - $ 593

RA3 12 $ 593 $ - $ 593

RA4 12 $ 593 $ - $ 593

RA0 4160 $ 208,599 - $ $ 208,599

RA1 4160 $ 208,599 - $ $ 208,599

RA2 4160 $ 208,599 - $ $ 208,599

RA3 4160 $ 208,599 - $ $ 208,599

RA4 4160 $ 208,599 - $ $ 208,599

RA0 40 $ 1,110 $ 880 $ 1,990

RA1 40 $ 1,110 $ 880 $ 1,990

RA2 40 $ 1,110 $ 880 $ 1,990

 RA3 40 $ 1,110 $ 880 $ 1,990

 RA4 40 $ 1,110 $ 880 $ 1,990

 RA0 0 - $ $ - -$ 

 RA1 80 $ 2,220 $ 1,759 $ 3,980

 RA2 80 $ 2,220 $ 1,759 $ 3,980

 RA3 80 $ 2,220 $ 1,759 $ 3,980

 RA4 0 - $ $ - $ -

 RA0 0 - $ $ - -$ 

 RA1 80 $ 2,252 - $ $ 2,252

 RA2 80 $ 2,252 - $ $ 2,252

 RA3 80 $ 2,252 - $ $ 2,252

RA4 0 - $ $ - -$ 

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 0 - $ $ - -$ 

RA1 0 - $ $ - -$ 

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 0 - $ $ - -$ 

RA1 0 - $ $ - -$ 

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

 RA2 4 $ 111 $ 88 $ 199

 RA3 4 $ 111 $ 88 $ 199

 RA4 4 $ 111 $ 88 $ 199

 RA0 4 $ 111 $ 88 $ 199

 RA1 4 $ 111 $ 88 $ 199

 RA2 4 $ 111 $ 88 $ 199

 RA3 4 $ 111 $ 88 $ 199

 RA4 4 $ 111 $ 88 $ 199

 RA0 4 $ 111 $ 88 $ 199

 RA1 4 $ 111 $ 88 $ 199

 RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

$49.44 RA4 4 $ 111 $ 88 $ 199

Review financial assurance of capacity to provide 

post-closure care. $49.44

$49.44

Second review of proposed post-closure care plan 

required by §146.93(a).

Review information required in § 146.82(c)1 prior 

to issuing permit.

Review financial assurance of capacity to properly 

close, plug, and abandon well.

Administration (Staff Training, Rule 

Implementation). $49.44

$49.44

Permitting Authority: review waiver applications. $49.44

$50.14

Federal Systems Updates. $49.44

Review proposed remedial response plan 

required by §146.94(b).

Compliance Activity

Second review of proposed closure plan required 

by §146.92(b).

$50.14

$50.14

$50.14

$50.14

Review information required in general UIC permit 

(Includes initial review of closure and post-closure 

plans). $49.44

$50.14

$49.44 $50.14

$50.14

$49.44

Review emergency response plan required by 

§146.94(a).

Federal level: review waiver applications for those 

originally reviewed by State/Tribe/Territory having 

primacy.

$50.14

$49.44 $50.14

$49.44

$50.14

$50.14

Cost Analysis for the 5-34 November 2010 

Final GS Rule
State 

Labor 

Cost

($/hour)

Federal 

Labor 

Cost

($/hour)

Regulatory 

Alternative

One-time 

labor burden 

(hrs) State Cost

Federal 

Cost

Weighted 

Project 

Cost2

A B C D E=A*C*0.56 F=B*C*0.44 G=E+F

RA0 1 2 $ 8 $ 22 $ 50

RA1 1 2 $ 8 $ 22 $ 50

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 1 2 $ 8 $ 22 $ 50

RA1 1 2 $ 8 $ 22 $ 50

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 1 2 $ 8 $ 22 $ 50

RA1 1 2 $ 8 $ 22 $ 50

RA2 1 2 $ 8 $ 22 $ 50

 RA3 3 8 $ 3 $ 66 $ 149

 RA4 4 $ 111 $ 88 $ 199

 RA0 1 2 $ 8 $ 22 $ 50

 RA1 1 2 $ 8 $ 22 $ 50

 RA2 1 2 $ 8 $ 22 $ 50

 RA3 3 8 $ 3 $ 66 $ 149

 RA4 4 $ 111 $ 88 $ 199

 RA0 4 $ 111 $ 88 $ 199

 RA1 4 $ 111 $ 88 $ 199

 RA2 4 $ 111 $ 88 $ 199

 RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 4 $ 111 $ 88 $ 199

RA1 4 $ 111 $ 88 $ 199

 RA2 4 $ 111 $ 88 $ 199

 RA3 4 $ 111 $ 88 $ 199

 RA4 4 $ 111 $ 88 $ 199

 RA0 4 $ 111 $ 88 $ 199

 RA1 4 $ 111 $ 88 $ 199

 RA2 4 $ 111 $ 88 $ 199

 RA3 4 $ 111 $ 88 $ 199

 RA4 4 $ 111 $ 88 $ 199

 RA0 12 $ 333 $ 264 $ 597

 RA1 12 $ 333 $ 264 $ 597

 RA2 12 $ 333 $ 264 $ 597

RA3 24 $ 666 $ 528 $ 1,194

RA4 24 $ 666 $ 528 $ 1,194

Review proposed injection procedure.

Review plans (including maps) for meeting 

monitoring requirements.

Analyze the pressure decay and the transient 

pressures recorded by owner/operator pursuant to 

§146.90(e) and determine whether the injection 

activity has conformed with predicted 

values[§ 146.92(e)(1)].5 

Review contingency plans.

Review of the information described in § 146.82(c) 

prior to granting approval for plugging and 

abandonment of a well.1

Review information required under § 146.86(b)(1) 

to determine and specify casing and cementing 

requirements.2

Review construction procedures.

$49.44

$49.44

Review the corrective action proposed to be taken 

under §146.84 for wells within the area of review 

which penetrate the injection zone but are not 

properly completed or plugged.

Review schematics of proposed wells.

$49.44

Review information required under § 146.86(c)(2) 

to determine and specify tubing and packer 

requirements.3 $50.14

Compliance Activity

$50.14

$50.14

$49.44 $50.14

$49.44 $50.14

$50.14

$50.14

$49.44

$49.44

$50.14

Evaluate mechanical integrity based on 

monitoring tests conducted since the last such 

evaluation and other mechanical integrity data. $49.44 $50.14

Witness logging and testing. $49.44

$49.44 $50.14

$50.14

$50.14

$49.44

$49.44

Cost Analysis for the 5-35 November 2010 

Final GS Rule
State 

Labor 

Cost

($/hour)

Federal 

Labor 

Cost

($/hour)

Regulatory 

Alternative

One-time 

labor burden 

(hrs) State Cost

Federal 

Cost

Weighted 

Project 

Cost2

A B C D E=A*C*0.56 F=B*C*0.44 G=E+F

RA0 0 - $ $ - -$ 

RA1 4 $ 111 $ 88 $ 199

RA2 4 $ 111 $ 88 $ 199

RA3 0 - $ $ - -$ 

RA4 0 - $ $ - -$ 

RA0 4 9 $ 7 $ 77 $ 174

 RA1 0 - $ $ - -$ 

 RA2 0 - $ $ - -$ 

 RA3 4 $ 111 $ 88 $ 199

 RA4 0 - $ $ - -$ 

 RA0 0 - $ $ - -$ 

 RA1 0 - $ $ - -$ 

 RA2 0 - $ $ - -$ 

RA3 0 - $ $ - -$ 

RA4 12 $ 338 $ 268 $ 605

RA0 0 - $ $ - -$ 

RA1 1 2 $ 8 $ 22 $ 50

RA2 1 2 $ 8 $ 22 $ 50

RA3 0 - $ $ - -$ 

RA4 0 - $ $ - $ -

RA0 4 $ 111 $ 88 $ 199

RA1 2 5 $ 6 $ 44 $ 99

RA2 2 5 $ 6 $ 44 $ 99

RA3 4 $ 111 $ 88 $ 199

RA4 4 $ 111 $ 88 $ 199

RA0 0 / 0 $ - $ - -$ 

 RA1 1040 / 90 51,418 $ $ 4,513 $ 55,931

 RA2 1040 / 90 51,418 $ $ 4,513 $ 55,931

 RA3 1040 / 90 51,418 $ $ 4,513 $ 55,931

 RA4 1040 / 90 51,418 $ $ 4,513 $ 55,931

Source: GS Cost Model

Notes:

Sources:

(A), (B) Permitting authority labor rate from Section 5.2.1.

(C) Burden and unit cost estimates reflect EPA's best professional judgment.

(E), (F) Nondiscounted Project level cost estimates from GS Rule Cost Model.

Review of each project's annual reports submitted 

by all operators of Class VI wells [§ 146.91]1 and 

recordkeeping.

(D) Alternatives having the same application factor are grouped together. As described in Section 5.2, application factors represent the Agency's best estimate of the 

percentage of projects to which a given activity is expected to apply, or the extent to which each project under a given alternative is expected to engage in the activity (see 

Section 5.2).

(1) The project cost is independent of the project siting or size and constant across the various project types.

Prepare / Review primacy applications. $49.44 $50.14

(3) Preparation of primacy applications is estimated to require 1040 hours by states, and 90 hours for EPA regional and headquarters offices to review.

(2) Weighted permitting authority cost based on assumption of 56% of states currently active in the UIC program obtaining primacy for proposed Class VI wells (Section 

5.2.1).

Review AoR modeling update (complex model). $49.44

Review AoR modeling update (simple model).

$50.14

$49.44 $50.14

$50.14

$50.14

Review of each project's semi-annual (RA3) or 

quarterly (RA0) reports submitted by all operators 

of Class VI wells [§ 146.91]2 and recordkeeping. $49.44

Review of each project's monthly reports 

submitted by all operators of Class VI wells 

[§ 146.91]3 and recordkeeping. $49.44

Compliance Activity

$49.44 $50.14

Exhibit 5.20 Permitting Authority Cost Estimates – Annualized Values Using a 3% 

and 7% Discount Rate ($Millions, 2008$) 

State Federal Total State Federal Total

Baseline $0.00 $0.32 $0.32 $0.00 $0.27 $0.27

RA1 $0.10 $0.33 $0.43 $0.15 $0.28 $0.43

Incremental RA1 $0.10 $0.01 $0.11 $0.14 $0.01 $0.16

RA2 $0.10 $0.33 $0.43 $0.15 $0.28 $0.43

Incremental RA2 $0.10 $0.01 $0.11 $0.14 $0.01 $0.16

RA3 $0.10 $0.33 $0.43 $0.15 $0.28 $0.43

Incremental RA3 $0.10 $0.01 $0.11 $0.14 $0.01 $0.16

RA4 $0.10 $0.33 $0.44 $0.15 $0.29 $0.44

Incremental RA4 $0.10 $0.01 $0.11 $0.15 $0.02 $0.16

Source: Appendix C, Exhibit C.67/C.68

Regulatory 

Alternative 3% 7%

Cost Analysis for the 5-36 November 2010 

Final GS Rule
Cost Analysis for the 5-37 November 2010 

Final GS Rule

 

5.5 Estimated Costs to Households 

EPA assumes that the increased costs for operation of GS wells under the GS Rule will 

be passed on, in whole or in part, to consumers. However, the impact on any individual 

household is expected to be very minor. Quantification of exact household costs is not possible 

due to the representative nature of the costing estimates. The representative project estimates 

used in this cost analysis are not connected to specific industry profiles that would include 

numbers and distributions of customers that could be used in household cost calculations. 

However, assumptions about the broader industry profile (i.e., types and characteristics of 

projects) can be used to qualitatively evaluate costs. In particular, the 29 projects estimated to be 

subject to the requirements of the GS Rule as part of this Cost Analysis are assumed to be 

sponsored by the energy sector. Because of the current government focus on the energy sector, 

there are many factors that will work to mitigate costs that are passed on to consumers. 

As the major producers of CO2, it is expected that large energy producers such as coal 

fired power plants will sponsor the majority of GS projects and therefore incur most of the costs 

of sequestration. Because of their roles as energy suppliers, these types of producers would be 

able to spread any cost increases across very large numbers of consumers. This is the major 

factor that works to minimize individual household cost increases. These potential increases may 

be further minimized depending on the regional or local regulatory structures in place. Energy 

prices are capped or subsidized in some areas based on the level of deregulation and resulting 

policies that are in place. In addition, many of the projects estimated as part of the project 

baseline are pilot-scale and as such may be subject to significant subsidies under various 

government programs to promote climate change mitigation technologies. The actual funding of 

these and other government programs (i.e., price limits or supports) will still be borne by 

consumers but most likely as part of a much larger tax base, especially for national programs. 

Overall, these considerations imply that any household costs resulting from the GS Rule will be 

minimal. 

5.6 Comparison of Annualized Incremental Costs for All Regulatory Alternatives 

 Considered 

Exhibit 5.21 below summarizes the incremental costs of the GS Rule for each RA 

considered during the rule development process. Estimates represent those costs that EPA 

expects owners and operators and permitting authorities to incur for the 29 estimated baseline 

projects during the 50-year period of analysis. 

 Relative to the baseline regulatory scenario10, Alternatives 1 through 4 have increasing 

incremental costs that range from $4.8 million to $48.1 million in annualized 2008$ (using a 3 

percent discount rate). The incremental cost for the GS Rule (RA3) is approximately $38.1 

million (using a 3 percent discount rate). 

10 As explained in the introductory paragraph of Chapter 4 of this Cost Analysis, the baseline regulatory scenario 

consists of Class I regulations for non-hazardous wells. 
Exhibit 5.21 Incremental Rule Costs for All Regulatory Alternatives Considered – 

Annualized Values Using a 3% and 7% Discount Rate ($Millions, 2008$) 

3% 7%

RA1 Incremental $ 4.8 $ 2.6

RA2 Incremental $ 14.5 $ 11.4

RA3 Incremental $ 38.1 $ 31.7

RA4 Incremental $ 48.1 $ 39.5

Source: Appendix C, Exhibit C.74/C.75

Regulatory Alternative

Discount Rate

5.6.1 Costs Summed by Type of Expenditure 

 

As shown in Exhibit 5.22, operations and maintenance expenditures represent 

approximately 67% of the total incremental cost of the GS Rule (at 3% discounting). One-time 

costs, such as initial mapping of the project site geology and identification of existing 

penetrations in the projected AoR are approximately 17%. Capital expenditures represent the 

smallest portion of total cost at approximately 16%. 

Sometimes costs annualized at 3% are higher than those at 7%, and vice versa. EPA notes 

that when calculating annualized costs, there is an inflection point where the annualization step 

can compensate for the difference in present values after the initial discounting step. The capital 

costs occur predominantly early in the analysis period; as a result, the discounting step for 

several of these cost items is only discounting at an average of 5-10 years, while the 

annualization is applied over 25 years. Whereas the values discounted using a 3 percent discount 

rate are higher than the same cost stream discounted using 7 percent, the annualization step 

moves the results in the other direction, i.e., towards the condition of the 7-percent discounted 

values being greater than the 3-percent values. In some cases the annualization step can more 

than compensate for the original difference in favor of a larger 3 percent present value and result 

in 7 percent annualized estimates greater than those using 3 percent. For O&M costs, which 

occur throughout the period of analysis and therefore are not subject to as great an annualization 

effect, the reverse generally can be seen; the annualized estimates are mostly greater based on a 

3% discount rate as compared to a 7% discount rate. 

 

Exhibit 5.22 Incremental Rule Costs – Annualized Values Using a 3% and 7% 

Discount Rate ($Millions, 2008$) 

3% 7% 3% 7% 3% 7% 3% 7%

RA1 Incremental $ (2.1) $ (2.8) 1.2$ 1.5$ 5.6$ 4.0$ 4.8$ $ 2.6

RA2 Incremental $ 1.3 1.4$ 2.0$ $ 2.3 $ 11.2 $ 7.7 $ 14.5 $ 11.4

RA3 Incremental $ 6.6 7.0$ 6.0$ $ 7.0 $ 25.4 17.7$ 38.1$ $ 31.7

RA4 Incremental $ 9.5 $ 10.7 5.4$ $ 6.4 $ 33.1 22.3$ 48.1$ $ 39.5

Source: Appendix C, Exhibit C.74/C.75

Regulatory Discount Rate 

Alternative

Discount Rate Discount Rate 

One-Time Capital O&M Total

Discount Rate 

Cost Analysis for the 5-38 November 2010 

Final GS Rule
5.6.2 Costs Summed by Rule Component 

Exhibit 5.23 provides a summary by rule component of the annualized costs (at discount 

rates of 3 and 7 percent) for each RA considered during the rule development process. It includes 

estimates of total and incremental costs that EPA expects owners and operators and permitting 

authorities to incur for the 29 estimated baseline projects over the 50-year period of analysis. 

For RA 1 - 4, the most significant incremental rule costs (i.e., after subtracting baseline 

costs) are associated with monitoring. For RA 1 - 3, well operation is the second most significant 

incremental rule cost (for RA4, MIT is the second most significant incremental rule costs at 3% 

discounting, and Geologic Site Characterization at 7% discount rate). Monitoring represents a 

range from 44% to 77% of total incremental rule costs at three percent discounting. Well 

operation costs represent a range from 14% to 59% at 3 percent discounting. 

The estimated cost for the GS Rule is the incremental cost for RA3 (approximately $38.1 

million at 3% discount rate), which lies between the least costly and most costly RAs. The 

selection of RA3 for the final Rule is consistent with the results of the comparison of incremental 

costs and anticipated benefits of the rule, as discussed in Section 5.7, which also discusses these 

incremental costs as they relate to mitigation of the risk to USDWs related to GS. 

Exhibit 5.23 Total and Incremental Rule Costs by Regulatory Alternative and Rule 

Component – Annualized Values Using a 3% and 7% Discount Rate ($Millions, 

2008$) 

Regulatory 

Alternative/ 

Discount Rate

Geologic Site 

Characterization Monitoring

Injection Well 

Construction Area of Review Well Operation MIT

Well Plugging 

& Post 

Injection Site 

Care

Financial 

Responsibility

Permitting 

Authority 

Costs TOTAL

Baseline 

3% $ 6.7 $ 3.4 $ 16.2 $ 1.1 $ 41.8 $ 0.2 $ 0.6 $ 0.0 $ 0.3 $ 70.2

7% $ 8.3 $ 2.9 $ 17.0 $ 1.0 $ 28.2 $ 0.1 $ 0.2 $ 0.0 $ 0.3 $ 58.1

RA1

3% $ 4.1 $ 7.1 $ 16.5 $ 1.1 $ 44.6 $ 0.2 $ 0.9 $ 0.0 $ 0.4 $ 75.0

7% $ 5.1 $ 6.1 $ 17.4 $ 1.0 $ 30.2 $ 0.1 $ 0.3 $ 0.0 $ 0.4 $ 60.8

Incremental RA1

3% $ (2.6) $ 3.7 $ 0.4 $ 0.1 $ 2.8 $ 0.1 $ 0.3 $ 0.0 $ 0.1 $ 4.8

7% $ (3.2) $ 3.2 $ 0.4 $ 0.1 $ 1.9 $ 0.0 $ 0.1 $ 0.0 $ 0.2 $ 2.6

RA2

3% $ 7.4 $ 11.4 $ 17.3 $ 1.1 $ 45.9 $ 0.2 $ 0.9 $ 0.0 $ 0.4 $ 84.7

7% $ 9.2 $ 9.0 $ 18.3 $ 1.0 $ 31.0 $ 0.1 $ 0.4 $ 0.0 $ 0.4 $ 69.5

Incremental RA2

3% $ 0.7 $ 8.0 $ 1.1 $ 0.1 $ 4.1 $ 0.1 $ 0.3 $ 0.0 $ 0.1 $ 14.5

7% $ 0.9 $ 6.1 $ 1.2 $ 0.1 $ 2.8 $ 0.0 $ 0.1 $ 0.0 $ 0.2 $ 11.4

RA3

3% $ 11.3 $ 22.0 $ 17.4 $ 1.5 $ 50.3 $ 2.7 $ 2.8 $ 0.0 $ 0.4 $ 108.3

7% $ 14.1 $ 18.7 $ 18.4 $ 1.3 $ 34.2 $ 1.7 $ 1.0 $ 0.0 $ 0.4 $ 89.8

Incremental RA3

3% $ 4.6 $ 18.6 $ 1.2 $ 0.4 $ 8.5 $ 2.6 $ 2.2 $ 0.0 $ 0.1 $ 38.1

7% $ 5.7 $ 15.8 $ 1.4 $ 0.3 $ 5.9 $ 1.6 $ 0.8 $ 0.0 $ 0.2 $ 31.7

RA4

3% $ 14.3 $ 24.4 $ 16.9 $ 1.5 $ 48.5 $ 8.9 $ 3.3 $ 0.0 $ 0.4 $ 118.3

7% $ 17.9 $ 20.1 $ 18.0 $ 1.5 $ 33.0 $ 5.6 $ 1.2 $ 0.0 $ 0.4 $ 97.6

Incremental RA4

3% $ 7.6 $ 21.0 $ 0.7 $ 0.5 $ 6.7 $ 8.7 $ 2.7 $ 0.0 $ 0.1 $ 48.1

7% $ 9.5 $ 17.2 $ 0.9 $ 0.5 $ 4.8 $ 5.5 $ 0.9 $ 0.0 $ 0.2 $ 39.5

Notes:

Source: Appendix C, Exhibit C.67/C.68

1) With the exception of the two pilot saline projects in the baseline, the GS Rule Cost Model does not capture the full PISC period for projects under the baseline and RA3, and because these 

costs mostly occur near (or after) the end of the 50 year period of analysis they are also significantly influenced by the discount rate.

2) Costs related to demonstration of Financial Responsibility are less than $100,000 in annualized terms.

3) Detail may not add due to rounding.

Cost Analysis for the 5-39 November 2010 

Final GS Rule
Cost Analysis for the 5-40 November 2010 

Final GS Rule

5.7 Comparison of Costs and Benefits 

EPA is limited by the purpose, quality, and quantity of data available in developing 

meaningful benefits analyses. In the absence of additional statistical analyses, only general 

observations of the data can be made with qualifiers. A quantitative comparison of risk between 

the alternatives considered for the final Rule would require robust data that would support: 1) 

direct comparisons of the overall baseline conditions with the overall conditions under each of 

the alternatives, or 2) comparisons of specific regulatory components (i.e., geologic site 

characterization) that could be used to compare the baseline and all alternatives. Currently, the 

risk of contamination of USDWs from GS activities has not been directly measured for any 

injection parameters or site characteristics. Thus, costs can only be compared to the qualitative 

relative risks discussed in Ch. 4. 

Compared to the baseline condition of the current UIC Program regulations, RA3 offers 

significantly greater protection to USDWs because that RA (the final Rule) is tailored 

specifically to GS and includes requirements necessary to prevent endangerment via migration of 

fluids into USDWs; existing well classes I – V do not specifically address the unique nature of 

injection of CO2 for the purposes of GS. RA4 has more stringent standards and greater costs 

compared to the final Rule, but EPA believes that RA4 requirements are beyond what is 

necessary to provide adequate risk reduction to USDWs. RA1 and RA2 provide lower costs than 

RA3 but at increased levels of risk to USDWs. Although RA4 has more stringent requirements, 

EPA does not believe that the increased requirements and the increased costs are necessary to 

provide protection to USDWs. Therefore EPA believes that RA3 is the best alternative. 

5.8 Other Economic Measures 

The lack of a quantitative risk assessment prevents the use of other economic measures, 

specifically, a break-even analysis and measures of cost effectiveness based on the value of 

changes in health conditions. 

5.9 Non-quantified Costs and Uncertainties in Cost Estimates 

5.9.1 Non-quantified Costs 

The purpose of the GS Rule is to mitigate any risk introduced by GS activities to the 

quality, and indirectly volume, of current and potential future USDWs. The requirements of the 

GS Rule are specifically designed to mitigate such risks and to provide some redundancy in these 

protections. However, should there be an instance of failure to protect a USDW through 

inappropriate implementation of the GS Rule or GS deployment in a way not consistent with the 

GS Rule; the cost to society would be either the cost of returning the water to usable quality or 

the cost of developing an alternative source of drinking water in some cases. There is most likely 

a very low probability of such a failure being attributable to the GS Rule itself; this would entail 

the GS Rule being non-implementable or not readily comprehensible for proper implementation, 

and then either of these circumstances resulting in activity that causes contamination of a 

USDW. 
Cost Analysis for the 5-41 November 2010 

Final GS Rule

Should the GS Rule somehow impede GS deployment, then the opportunity costs of not 

capturing the benefits associated with GS could be attributed to the GS Rule; however, EPA has 

tried to develop a rule that balances risk with practicability and economic considerations and 

believes the probability of such impedance is very low. The GS Rule should serve to bolster 

public confidence in GS by establishing requirements that manage risks to human health and the 

environment through protection of USDWs. EPA expects the GS Rule to enhance public 

acceptance of GS technology and provide national consistency and regulatory certainty to 

owners and operators of GS wells. Thus, EPA believes the GS Rule will not impede deployment 

of GS projects. 

5.9.2 Uncertainties in Cost Estimates 

 As described in the Geologic CO2 Sequestration Technology and Cost Analysis (EPA, 

2010a) developed in support of this Cost Analysis, many assumptions in the model include 

uncertainty; the general areas of uncertainty include the project characteristics of the five pro 

forma projects, the unit costs of technology, the frequency of each compliance activity 

appropriate for each given project site, estimates of labor burden and hourly wage rates, and 

changes in costs over time (caused by market forces or improved technology, for example). 

EPA considered in particular the uncertainty in three basic assumptions used in the Cost 

Analysis: 1) the estimated number of projects that will be affected by the GS Rule; 2) the labor 

rates applied; and 3) the estimated number of monitoring wells to be constructed per project to 

adequately monitor in a given geologic setting. 

Under the current baseline assumption there will be 29 projects affected by the GS rule in 

the 50-year analysis period, as described in Chapter 3 of this Cost Analysis. If limits on 

emissions of greenhouse gases were imposed, GS would allow the United States to continue to 

use fossil fuels to a larger extent than otherwise possible; with the widespread occurrence of 

saline formations across the United States, GS could be deployed nationwide under such a 

scenario. Therefore, the number of projects that will deploy from 2011 through 2060 may be 

significantly underestimated in this analysis if legislation that provides an incentive for GS 

should be enacted. Alternatively, should the public have a negative perception to GS 

deployment, the number of projects could be overestimated. 

Second, this analysis considered how the Cost Analysis results would change if the labor 

rates used for Geoscientists and Mining and Geological Engineers (presented in Section 5.2.1 of 

this Cost Analysis) were significantly underestimated. If a rapid increase in demand for this labor 

occurred under future climate change legislation and outpaced the development of an equal 

supply of such labor, some period of increased labor costs would be expected. However, a rapid 

wide scale increase in deployment is not expected, according to the Joint Global Change 

Research Institute (Dooley, 2010), therefore the uncertainty in labor costs is not considered to 

contribute significantly to the uncertainty in this cost analysis. 

Third, EPA assumes that the number of monitoring wells per project is correlated to the 

size of the site, which is the AoR. As shown in Exhibit 5.2, the representative pilot-scale saline 

project site is assumed to be approximately one square mile and under the selected alternative 

(RA3) is assumed to have two monitoring wells, one that is drilled into the injection zone (IZ) 

and one above the IZ. For the representative large-scale saline project, the site is assumed to be 
Cost Analysis for the 5-42 November 2010 

Final GS Rule

approximately 23 square miles with 12 monitoring wells, six that are drilled into the injection 

zone and six above the IZ. For the representative transitioning Class II ER project, the site is 

assumed to be approximately 8 square miles with four monitoring wells, two that are drilled into 

the IZ and two above the IZ. In the limited circumstances where injection depth waivers are 

approved, sites are assumed to have 50% more monitoring wells than those estimated above. For 

the purpose of estimating national costs, however, EPA recognizes that more or fewer 

monitoring wells may be appropriate depending on project site characteristics. Because the 

monitoring wells and associated costs represent a significant component of the Cost Analysis, 

EPA acknowledges that this factor may be significant in the overall uncertainty of the Cost 

Analysis. 

Additional uncertainties correspond more directly to specific assumptions made in 

constructing the cost model. If the assumptions for such items are incorrect, there may be 

significant cost implications outside of the general price level uncertainties discussed above. The 

most prominent examples of these are: 

• It is assumed that all projects have access to an existing fluid flow model that can be 

customized for the project by updating input parameters. If GS well owners and 

operators have to develop such a model for new projects from scratch, modeling costs 

may increase by four to five times. 

• It is assumed that partially corrosion resistant cement can be used for injection well 

construction. If GS well owners and operators have to utilize corrosion resistant 

alloys, construction costs can increase significantly. 

• Assumptions made for several cost components and subcomponents are based on 

industry averages. However, the actual costs of several cost components such as 

finding wells in AoR, land use and rights, and remediation of failures can vary widely 

based on site specific characteristics. To the degree that EPA’s assumptions about the 

“representative” projects differs from cost factors of those that eventually deploy, 

costs for such rule components could be significantly over- or underestimated. 

• As detailed in Section 5.0 of the Geologic CO2 Sequestration Technology and Cost 

Analysis (EPA, 2010a), underlying trends in equipments costs will have an impact on 

costs incurred by owners and operators after the GS Rule is promulgated. Generally 

speaking, the unit costs for which there is greater certainty are those directly or 

indirectly related to conventional drilling and completion practices and geophysical 

techniques used in exploration and development for oil and gas. Some equipment 

costs, i.e., pipeline, are well known in the industry but vary based on market forces 

affecting supply and demand for materials and labor. 

• Owners and operators would, if directed, develop and implement a plan for surface 

air monitoring and/or soil gas monitoring to detect leakage of CO2 to ensure that CO2

and any other contaminants moving with the CO2 have not migrated through USDWs. 

Costs associated with air monitoring are accounted for under the Mandatory 

Reporting Rule of Greenhouse Gases - Subpart RR (MRR). However, in the event 

that additional air monitoring is needed for GS wells (beyond what is required under 

MRR), the GS Rule monitoring costs could be under-estimated. 
Cost Analysis for the 5-43 November 2010 

Final GS Rule

 

Based on the considerations discussed above, EPA conducted sensitivity analyses to 

evaluate the potential impacts of changes in certain key assumptions in the cost analysis. These 

analyses include: 

1) Considering 5 and 54 projects as the lower and upper bound number of projects 

deployed; 

2) An increase of 50% in industry labor rates used; and 

3) A 25% increase and decrease in monitoring wells per project site. 

To address the uncertainty inherent in projecting the GS baseline, sensitivity analyses that 

further explore the implications of alternative climate policy scenarios have been performed. 

These analyses are comparable to analyses performed to support the Regulatory Impact Analysis 

for Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of CO2

Rule (Subpart RR).11 The sensitivity analyses consider 5 and 54 projects as the lower and upper 

bound project numbers to be consistent with the Subpart RR analysis. The sensitivity analysis 

numbers (5 and 54 projects) are based on projected deployment highlighted in the presidential 

memorandum establishing the CCS Task Force and an EPA legislative analysis model of 

deployment under the American Power Act, respectively. As shown in Exhibit 5.24a, assuming 

5 pilot saline projects are implemented during the period of analysis results in annualized RA 3 

incremental rule costs that are approximately $2.3 million. And, as shown in Exhibit 5.24b, 

assuming 54 large saline projects are implemented during the period of analysis results in 

annualized RA 3 incremental rule costs that are approximately $235 million. Consideration of an 

increase in projects based on climate change legislation could result in a significant increase in 

rule costs. 

In considering the sensitivity of analysis results to changes in labor rates, EPA found that 

a 50% increase in industry labor rates results in annualized incremental rule costs of $38.6 

million based on a 3 percent discount rate, or approximately a 1% increase in costs from the 

primary analysis. An important caveat to this analysis is that it captures the increase for only 

those project costs for which a distinct labor component has been defined; for those that have a 

labor component embedded in the cost, that cost has not been increased by this sensitivity 

analysis. Therefore, to the degree that labor costs are embedded in project costs, this sensitivity 

analysis underestimates the extent of increase that a 50% labor increase would induce. The 

Geologic CO2 Sequestration Technology and Cost Analysis (EPA, 2010a) provides detail on how 

individual compliance and business-as-usual (baseline) activities are defined for costing 

purposes, and a brief text description accompanies each unit cost algorithm in the matrix 

presented in Appendix B to this Cost Analysis. 

In this Cost Analysis EPA assumes that owners and operators under the GS Rule (RA3) 

will construct and operate a certain ratio of monitoring wells per project site area depending on 

project type (see Exhibit 5.2 for the pro forma types used in this analysis) to conduct necessary 

11 Simultaneous development of the Mandatory Reporting of Greenhouse Gases: Injection and Geologic 

Sequestration of CO2 Rule (Subpart RR) and the GS Rule was coordinated by EPA. As a part of the coordinated rule 

making efforts, EPA developed these sensitivity analyses to ensure consistency of requirements and costs between 

the two rules.
monitoring of the injected CO2 and its plume. Because the actual number that will be necessary 

for a given project site is uncertain, EPA tested the sensitivity of cost estimates to the number of 

monitoring wells by applying a 25 percent decrease and increase of monitoring wells per project 

site area to the original assumptions for each project type. This change results in annualized 

incremental rule costs of approximately $33.0 million and $43.1 million, or a 13 percent 

decrease or increase from the primary analysis results of $38.1 million at a 3% discount rate (as 

shown in Exhibit 5.26). 

An additional analysis EPA performed was a calculation of the rule costs for the baseline 

29 projects on the basis of formation type and project scale. To be commensurate with the 

treatment (annualization) of costs, the injected volumes are discounted, that is, put in present 

value terms for the amount injected over 50 years, and then annualized over the first 25 years of 

the analysis period (see Section 5.3 for further explanation of the annualization). The results 

indicate that the pilot-scale saline projects, which must adhere to the same level of protectiveness 

as the large-scale projects, don’t achieve the same economies of scale as the large-scale projects: 

pilot-scale saline projects cost significantly more per ton CO2 sequestered (147% more with 3% 

discounting and 77% more with 7% discounting) than large-scale saline projects. 

The results for each sensitivity analysis calculated using 3 and 7 percent discount rates 

are presented in Appendix C of the Cost Analysis. 

Exhibit 5.24a Total and Incremental Rule Costs by Cost Type, Assuming 5 Pilot 

Saline Projects are Implemented During the Period of Analysis ($Millions, 2008$) 

Cost, 2008$

Increase or 

Decrease, 

$20081

Cost, 2008$

Increase or 

Decrease, 

$20081

Cost, 2008$

Increase or 

Decrease, 

$20081

Cost, 2008$

Increase or 

Decrease, 

$20081

 RA0 $ 1.0 $ (8.9) $ 3.0 $ (12.5) $ 1.8 $ (43.0) $ 5.8 $ (64.4)

 RA1 $ 0.8 $ (7.1) $ 3.0 $ (13.8) $ 1.8 $ (48.6) $ 5.6 $ (69.4)

 RA1 Incremental $ (0.2) $ 1.9 $ (0.0) $ (1.2) $ 0.0 $ (5.6) $ (0.2) $ (4.9)

 RA2 $ 1.2 $ (10.1) $ 3.2 $ (14.3) $ 1.9 $ (54.1) $ 6.2 $ (78.5)

 RA2 Incremental $ 0.1 $ (1.2) $ 0.2 $ (1.8) $ 0.1 $ (11.1) $ 0.4 $ (14.1)

 RA3 $ 2.0 $ (14.6) $ 3.6 $ (17.9) $ 2.5 $ (67.7) $ 8.1 $ (100.2)

 RA3 Incremental $ 0.9 $ (5.7) $ 0.6 $ (5.4) $ 0.7 $ (24.7) $ 2.3 $ (35.8)

 RA4 $ 2.6 $ (16.9) $ 3.7 $ (17.2) $ 3.2 $ (74.7) $ 9.5 $ (108.8)

 RA4 Incremental $ 1.6 $ (8.0) $ 0.7 $ (4.7) $ 1.4 $ (31.7) $ 3.7 $ (44.4)

 RA0 $ 1.5 $ (9.8) $ 4.3 $ (12.2) $ 2.2 $ (28.2) $ 7.9 $ (50.2)

 RA1 $ 1.2 $ (7.2) $ 4.3 $ (13.7) $ 2.2 $ (32.2) $ 7.6 $ (53.1)

 RA1 Incremental $ (0.3) $ 2.5 $ (0.0) $ (1.5) $ 0.0 $ (4.0) $ (0.3) $ (2.9)

 RA2 $ 1.7 $ (10.9) $ 4.6 $ (14.2) $ 2.3 $ (35.8) $ 8.5 $ (61.0)

 RA2 Incremental $ 0.2 $ (1.2) $ 0.3 $ (2.0) $ 0.1 $ (7.6) $ 0.6 $ (10.8)

 RA3 $ 2.6 $ (15.6) $ 5.2 $ (18.3) $ 3.0 $ (45.1) $ 10.7 $ (79.0)

 RA3 Incremental $ 1.1 $ (5.9) $ 0.9 $ (6.1) $ 0.8 $ (16.8) $ 2.8 $ (28.8)

 RA4 $ 3.3 $ (18.6) $ 5.3 $ (17.6) $ 3.6 $ (49.2) $ 12.2 $ (85.4)

 RA4 Incremental $ 1.9 $ (8.9) $ 1.0 $ (5.4) $ 1.4 $ (20.9) $ 4.3 $ (35.2)

1

 As compared to GS Rule deployment schedule of 29 projects.

Source: Appendix C, Exhibit C.81

Total Costs

3 Percent Discount Rate

 7 Percent Discount Rate 

Regulatory 

Alternative

One-Time Costs Capital Costs O&M Costs

Cost Analysis for the 5-44 November 2010 

Final GS Rule
Exhibit 5.24b Total and Incremental Rule Costs by Cost Type, Assuming 54 Large 

Saline Projects are Implemented During the Period of Analysis ($Millions, 2008$) 

Cost, 2008$

Increase or 

Decrease, 

$20081

Cost, 2008$

Increase or 

Decrease, 

$20081

Cost, 2008$

Increase or 

Decrease, 

$20081

Cost, 2008$

Increase or 

Decrease, 

$20081

 RA0 $ 64 $ 54 $ 98 $ 82 $ 300 $ 255 $ 462 $ 391 

 RA1 $ 42 $ 34 $ 104 $ 87 $ 325 $ 274 $ 471 $ 396 

 RA1 Incremental $ (23) $ (21) $ 6 $ 5 $ 25 $ 20 $ 9 $ 4 

 RA2 $ 65 $ 54 $ 108 $ 91 $ 362 $ 306 $ 535 $ 451 

 RA2 Incremental $ 1 $ (0) $ 10 $ 8 $ 62 $ 51 $ 74 $ 59 

 RA3 $ 94 $ 78 $ 140 $ 118 $ 462 $ 392 $ 696 $ 588 

 RA3 Incremental $ 30 $ 23 $ 42 $ 36 $ 162 $ 137 $ 235 $ 196 

 RA4 $ 126 $ 106 $ 142 $ 121 $ 521 $ 443 $ 788 $ 670 

 RA4 Incremental $ 61 $ 52 $ 44 $ 39 $ 222 $ 188 $ 327 $ 279 

 RA0 $ 72 $ 61 $ 111 $ 94 $ 201 $ 171 $ 384 $ 326 

 RA1 $ 46 $ 38 $ 118 $ 100 $ 219 $ 184 $ 383 $ 322 

 RA1 Incremental $ (26) $ (23) $ 7 $ 6 $ 18 $ 14 $ (1) $ (4)

 RA2 $ 73 $ 60 $ 123 $ 104 $ 242 $ 204 $ 438 $ 368 

 RA2 Incremental $ 1 $ (1) $ 12 $ 10 $ 41 $ 33 $ 54 $ 42 

 RA3 $ 105 $ 87 $ 159 $ 135 $ 312 $ 263 $ 575 $ 485 

 RA3 Incremental $ 33 $ 26 $ 48 $ 41 $ 111 $ 93 $ 191 $ 159 

 RA4 $ 140 $ 118 $ 161 $ 138 $ 350 $ 297 $ 651 $ 553 

 RA4 Incremental $ 68 $ 57 $ 50 $ 44 $ 149 $ 126 $ 267 $ 227 

1

 As compared to GS Rule deployment schedule of 29 projects.

Source: Appendix C, Exhibit C.82

3 Percent Discount Rate

 7 Percent Discount Rate 

Regulatory 

Alternative

One-Time Costs Capital Costs O&M Costs Total Costs

Exhibit 5.25 Total and Incremental Rule Costs Based on 50% Increased Labor 

Rate - Annualized Values Using a 3% Discount Rate ($Millions, 2008$) 

Regulatory 

Alternative

One-Time 

Costs 

% 

Change 

Capital 

Costs

% 

Change 

O&M 

Costs

% 

Change 

Total % 

Change 

RA0 $ 2% 15.5 10.1 $ 0% 44.9$ 0% 70.6 $ 1%

RA1 $ 2% 16.7 8.1 $ 0% 50.6$ 0% 75.4 $ 1%

RA1 Incremental $ 0% 1.2 (2.1) $ 0% 5.6$ 1% 4.8 $ 1%

RA2 $ 2% 17.5 11.5 $ 0% 56.2$ 1% 85.2 $ 1%

RA2 Incremental $ 1% 2.0 1.3 $ 0% 11.3 $ 1% 14.7 $ 1%

RA3 $ 2% 21.5 16.9 $ 0% 70.8$ 1% 109.2 $ 1%

RA3 Incremental $ 1% 6.0 6.7 $ 0% 25.9 $ 2% 38.6 $ 2%

RA4 $ 2% 20.9 19.9 $ 0% 78.6$ 1% 119.4 $ 1%

RA4 Incremental $ 2% 5.4 9.7 $ 0% 33.7 $ 2% 48.8 $ 1%

% change shows difference between primary analysis and model run using 50% increased labor rate.

Source: Appendix C, Exhibit C.82

Cost Analysis for the 5-45 November 2010 

Final GS Rule
Exhibit 5.26 Total and Incremental Rule Costs, Change in Cost from Primary 

Analysis Resulting from 25% Increase/Decrease in Monitoring Wells - Annualized 

Values Using a 3% Discount Rate ($Millions, 2008$) 

One-Time 

Costs 

% 

Change

Capital 

Costs

% 

Change

O&M 

Costs

% 

Change Total % 

Change

RA0 $ 0% 15.5 10.0 $ 0% 44.8$ 0% 70.2$ 0%

RA3 $ 0% 21.5 16.6 $ 0% 70.2 $ 0% 108.3 $ 0%

RA3 Incremental $ 0% 6.0 6.6 $ 0% 25.4$ 0% 38.1$ 0%

RA0 $ -1% 15.3 9.9 $ -1% 44.0 $ -2% 69.2 $ -2%

RA3 $ -2% 20.1 16.3 $ -6% 65.8 $ -6% 102.2 $ -6%

RA3 Incremental $ -4% 4.8 6.4 $ -20% 21.8 $ -14% 33.0 $ -13%

RA0 $ 1% 15.7 10.0 $ 1% 45.6$ 2% 71.3$ 2%

RA3 $ 2% 22.9 16.9 $ 6% 74.6 $ 6% 114.4 $ 6%

RA3 Incremental $ 4% 7.2 6.9 $ 20% 29.0 $ 14% 43.1 $ 13%

Source: Appendix C, Exhibit C.84

Regulatory Alternative

Primary 

Analysis 

Assumption 

25% 

decrease

25% 

increase

Exhibit 5.27 Annualized Rule Costs By Project Type Per Metric Tonne and Per 

Project (2008$) 

3% 7% 3% 7% 3% 7%

Pilot Saline 268,360 17,992,359 2.0 0.8 0.8 3.11 2.73 0.42 0.40

Large Saline 20,197,218 18,962,247 9.4 25.4 22.8 1.26 1.54 2.70 2.42

Large Saline Waivered 1,122,068 969,888 0.5 4.6 4.4 4.13 5.41 8.87 8.51

ER 5,553,462 18,962,247 13.7 5.8 2.9 1.04 1.00 0.42 0.21

ER Waivered 282,815 969,888 0.8 1.4 0.8 5.04 5.26 1.88 1.03

All Formations 27,423,922 18,962,247 26.4 38.1 31.8 1.39 1.67 1.44 1.20

Source: Appendix C, Exhibit C.77

1

 Injected volumes are discounted to the first year of the analysis and annualized over 25 years at 3% discounting for comparability to 

annualized costs.

2

 Injected volumes are discounted to the first year of the analysis and annualized over 25 years at 7% discounting for comparability to 

annualized costs.

Metric 

Tonnes of 

CO2 Injected 

(7%)2

Note: It is estimated that 25 - 26 of the 29 baseline projects (depending on the RA) will successfully deploy over the 50 year period of analysis. Annualized 

rule cost per project is based on the number of successfully deployed projects. 

Project Type

Metric 

Tonnes of 

CO2 Injected 

(3%)1 

No. of 

Projects 

Deployed

Annualized 

Incremental Cost by 

Project Type ($MM)

Annualized 

Incremental Rule 

Cost Per Metric 

Tonne ($)

Annualized 

Incremental Rule 

Cost Per Project 

($MM)

Cost Analysis for the 5-46 November 2010 

Final GS Rule
 

Cost Analysis for the 6-1 November 2010 

Final GS Rule 

6. Economic Impact Analysis 

6.1 Introduction 

 As part of the rulemaking process, United States Environmental Protection Agency 

(EPA) is required to address the direct and indirect burdens that the Federal Requirements under 

the Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic 

Sequestration (GS) Wells (GS Rule) may place on certain types of governments, business, and 

populations. This chapter presents the analyses performed by EPA in accordance with the 

following 12 Federal mandates: 

1. Executive Order 12866: Regulatory Planning and Review. 

2. Paperwork Reduction Act (PRA) (a separate Information Collection Request (ICR) 

document contains the complete analysis). 

3. The Regulatory Flexibility Act (RFA) of 1980, as amended by the Small Business 

Regulatory Enforcement Fairness Act (SBREFA) of 1996. 

4. Unfunded Mandates Reform Act (UMRA) of 1995. 

5. Executive Order 13132 (Federalism). 

6. Executive Order 13175 (Consultation and Coordination with Indian Tribal Governments). 

7. Executive Order 13045 (Protection of Children from Environmental Health Risks and 

 Safety Risks). 

8. Executive Order 13211 (Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution, or Use). 

9. National Technology Transfer and Advancement Act (NTTAA) of 1995. 

10. Executive Order 12898 (Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations). 

Many of the requirements and EOs listed above call for an explanation of why the rule is 

necessary, the statutory authority for the rule, and the primary objectives that the rule is intended 

to achieve (refer to Chapter 2 for more information regarding the objectives of the rule). Others 

are designed to assess the financial and health effects of the rule on certain subpopulations such 

as low-income, minority, and tribal populations. 
 

Cost Analysis for the 6-2 November 2010 

Final GS Rule 

6.2 Executive Order 12866: Regulatory Planning and Review 

Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a 

"significant regulatory action” because it is anticipated to raise novel legal and policy issues, as it 

is creating a new class of UIC wells to regulate CO2 injection for a new purpose. Accordingly, 

EPA submitted this action to the Office of Management and Budget (OMB) for review under EO 

12866 and any changes made in response to OMB recommendations have been documented in 

the docket for this action. 

6.3 Paperwork Reduction Act 

The information collection requirements in this rule will be submitted for approval to the 

OMB under the Paperwork Reduction Act (PRA), 44 U.S.C. 3501 et seq. The information 

collection requirements are not enforceable until OMB approves them. 

The information collected as a result of this rule will allow EPA and State permitting 

authorities to review geologic information about a proposed injection project to evaluate its 

suitability for safe and effective GS. It also allows the Agency to fulfill the requirements of the 

UIC Program to verify throughout the life of the injection project that protective requirements 

are in place and that Underground Sources of Drinking Water (USDWs) are protected. The 

collection requirements are mandatory under the Safe Drinking Water Act (SDWA). (42 U.S.C. 

300h et seq.). 

For the first three years after publication of the final rule in the Federal Register, the 

major information requirements apply to a total of 38 respondents, for an average of 12.6 

respondents per year. The total incremental burden (for owners and operators, permitting 

authorities, and the Agency) associated with the change in moving from the information 

requirements of the UIC Program for Class I non-hazardous wells (baseline) to the selected 

alternative under the GS Rule over the three years covered by the ICR is 53,740 hours, for an 

average of 17,913 hours per year. The total incremental cost over the three-year clearance period 

is $36.9 million, for an average of $12.3 million per year (simple average over three years). The 

average burden hours per response (i.e., the amount of time needed for each activity that requires 

a collection of information) is 423 hours; the average cost per response is $290,695. The 

collection requirements are mandatory under SDWA (42 U.S.C. 3501 et seq.). Details on the 

calculation of the rule information collection burden and costs can be found in the ICR (USEPA, 

2010b) and Chapter 5 of this Cost Analysis. A summary of the burden and costs of the collection 

is presented in Exhibit 6-1 below.
 

Exhibit 6-1 Average Annual Net Change Burden and Costs for the GS ICR 

Annual Labor 

Cost

Annual 

Capital Cost

Annual O&M 

Cost

Total Annual 

Cost

Owners or 

Operators 1.0 1,549 $ 204,574 $ 5,827,027 $ 5,454,346 $ 11,485,946 6.9

Permitting 

Authorities 10.7 11,241 $ 555,763 $ - $ - $ 555,763 23.6 

Agency 1.0 5,123 $ 256,880 $ - $ - $ 256,880 11.7 

Total 12.6 17,913 $ 1,017,217 $ 5,827,027 $ 5,454,346 $ 12,298,589 42.3 

Source: 

Information Collection Request for the Geologic Sequestration Rule (USEPA, 2010b).

Notes:

1) Detail may not add exactly to total due to independent rounding.

2) “Annual Burden Hours” reflects an annual average for all project types over the 3-year ICR period.

Annual 

Responses

Respondent 

Type

Annual 

Respondents

Annual 

Burden Hours

Cost

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. In addition, EPA is 

amending the table in 40 CFR part 9 of currently approved OMB control numbers for various 

regulations to list the regulatory citations for the information requirements contained in this final 

rule. 

6.4 Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedures Act or any other statute unless the agency certifies that the rule will 

not have a significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small organizations, and small governmental jurisdictions. 

The RFA provides default definitions for each type of small entity. Small entities are 

defined under the RFA as: (1) a small business as defined by the Small Business 

Administration’s (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction 

that is a government of a city, county, town, school district or special district with a population of 

less than 50,000; and (3) a small organization that is any "not-for-profit enterprise which is 

independently owned and operated and is not dominant in its field.” 

For the purpose of assessing the impacts of the GS Rule on small entities, would include 

the following (1) For electric power plants under North American Industry Classification 

System (NAICS) codes 221111, 221112, 221113, 221119, 221121, 221122, a firm that is 

primarily engaged in the generation, transmission, and/or distribution of electric energy for sale 

and its total electric output for the preceding fiscal year did not exceed 4 million megawatt hours; 

(2) For petroleum refineries under NAICS code 324110, as specified for government 

procurement purposes, a firm must have fewer than 1,500 employees and less than 125,000 

barrels per calendar day in total Operable Atmospheric Crude Oil Distillation capacity. Capacity 

would include owned or leased facilities as well as facilities under a processing agreement or an 

arrangement such as an exchange agreement or a throughput. See 73 FR 43492 (July 2008). 

 

Cost Analysis for the 6-3 November 2010 

Final GS Rule 
 

Cost Analysis for the 6-4 November 2010 

Final GS Rule 

However, GS is a voluntary action that would only be undertaken by a small entity if GS 

were in its interest compared to other alternatives it may have. The purpose of the GS regulation 

is to ensure that, where deployed, GS is conducted in a manner that protects USDWs from 

endangerment. GS is a technologically complex activity, the cost of which is anticipated to be 

prohibitive to small entities. Therefore, it is expected that small entities would not elect to 

sequester CO2 via injection wells, and thus the rule will not have any impact on them. In 

summary, EPA certifies that the GS Rule will not generate a significant economic impact on a 

substantial number of small entities. 

6.5 Unfunded Mandates Reform Act (UMRA) 

This rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any 

one year. The total annual incremental costs estimated for the implementation of this rule are 

well under $100 million, resulting in expenditures for the entity groupings required under an 

UMRA analysis that also fall far below the $100 million per year threshold. Thus, this rule is not 

subject to the requirements of sections 202 or 205 of UMRA. 

 This rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments. 

Government responsibilities for oversight and implementation of this rule reside with State or 

Federal agencies and not with small governments. 

6.6 Executive Order 13132: Federalism 

 Under section 6(b) of EO 13132 (64 FR 43255, August 10, 1999), EPA may not issue an 

action that has federalism implications, that imposes substantial direct compliance costs, and that 

is not required by statute, unless the Federal government provides the funds necessary to pay the 

direct compliance costs incurred by State and local governments, or EPA consults with State and 

local officials early in the process of developing the proposed action. In addition, under section 

6(c) of EO 13132, EPA may not issue an action that has federalism implications and that 

preempts State law, unless the Agency consults with State and local officials early in the process 

of developing the proposed action. 

 

 EPA has concluded that this action may have federalism implications. It will change the 

UIC Program, and increase the stringency of regulation of GS projects (which would otherwise 

have been permitted under UIC as Class I wells). This rule will not impose substantial direct 

compliance costs on State or Local governments, nor does EPA anticipate that it will preempt 

State law. Thus, the requirements of sections 6(b) and 6(c) of the EO do not apply to this action. 

 Consistent with EPA policy, EPA nonetheless consulted with representatives of State and 

local governments early in the process of developing the proposed action to permit them to have 

meaningful and timely input into its development. Representatives included the National 

Governors’ Association, the National Conference of State Legislatures, the Council of State 

Governments, the National League of Cities, the US Conference of Mayors, the National 
 

Cost Analysis for the 6-5 November 2010 

Final GS Rule 

Association of Counties, the International City/County Management Association, the National 

Association of Towns and Townships, and the County Executives of America. 

6.7 Executive Order 13175: Consultation and Coordination with Indian Tribal 

 Governments 

Subject to the EO 13175 (65 FR 67249, November 9, 2000) EPA may not issue a 

regulation that has Tribal implications, that imposes substantial direct compliance costs, and that 

is not required by statute, unless the Federal government provides the funds necessary to pay the 

direct compliance costs incurred by Tribal governments, or EPA consults with Tribal officials 

early in the process of developing the proposed regulation and develops a tribal summary impact 

statement. 

EPA has concluded that this action may have tribal implications. However, it will neither 

impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. Indian 

Tribes may voluntarily apply for primary enforcement responsibility to regulate the UIC 

Program in lands under their jurisdiction (See section II.G of the Preamble for more details on 

Primacy). Currently, two Tribes have received primacy for the UIC Program under section 1425 

of SDWA since the publication of the proposed rule. EPA is responsible for implementing the 

UIC Program in the event that States or Tribes do not seek primary enforcement responsibility. 

EPA clarifies that regardless of whether Tribes have UIC Program primacy, the rule protects 

USDWs from contamination and therefore protects all populations from adverse health effects 

related to potential USDW contamination. 

EPA consulted with tribal officials early in the process of developing this regulation to 

permit them to have meaningful and timely input into its development. A summary of the tribal 

consultation calls are included in the docket for the GS rulemaking. See section II of the 

Preamble for more information on the details of the tribal consultation process. 

As required by section 7(a), EPA’s Tribal Consultation Official has certified that the 

requirements of the (EO) have been met in a meaningful and timely manner. A copy of the 

certification is included in the docket for this action. 

6.8 Executive Order 13045: Protection of Children from Environmental Health 

 Risks and Safety Risks 

This action is not subject to EO 13045 (62 FR 19885, April 23, 1997) because the 

Agency does not believe the environmental health risks or safety risks addressed by this action 

present a disproportionate risk to children. Today’s rule does not require or provide incentive for 

firms to engage in GS, however, it does protect USDWs from potential negative impacts from 

GS of CO2 should a firm decide to undertake such a project. Health and risk assessments related 

to GS of CO2 and its effects on humans and the environment are presented in the Vulnerability 

Evaluation Framework for Geologic Sequestration of Carbon Dioxide (USEPA, 2010c). 

Additionally, EPA notes that it is funding and monitoring research related to the potential for 

USDW contamination associated with GS projects. Much of this research focuses on potential 

exceedances of drinking water standards (as suggested), which were developed by EPA and take 
 

Cost Analysis for the 6-6 November 2010 

Final GS Rule 

into account impacts on children. Please see section II of the Preamble for more details on this 

research. 

6.9 Executive Order 13211: Actions that Significantly Affect Energy Supply, 

 Distribution, or Use 

This rule is not a “significant energy action” as defined in EO 13211 (66 FR 28355, May 

22, 2001), because it is not likely to have a significant adverse effect on the supply, distribution, 

or use of energy. In absence of climate change legislation, baseline assumptions developed with 

the Department of Energy (DOE) for this rulemaking indicate that only approximately 1% of the 

existing CO2 emissions will be sequestered (approximately 1.0 billion metric tons) over the 

period of analysis. Furthermore, the higher degree of regulatory certainty and clarity in the 

permitting process may, in fact, have a positive effect on the energy sector. 

 Specifically, if climate change legislation that imposes caps or taxes on CO2 emissions is 

passed in the future, energy generation firms and other CO2 producing industries will have an 

economic incentive to reduce emissions, and this rule will provide regulatory certainty in 

determining how to maximize operations (for example, by increasing production while staying 

within the emissions cap or avoiding some carbon taxes). The rule may allow some firms to 

extend the life of their existing capital investment in plant machinery or plant processes. 

 

6.10 National Technology Transfer and Advancement Act 

 Section 12(d) of the NTTAA, Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus standards in its regulatory activities unless to do so 

would be inconsistent with applicable law or otherwise impractical. Voluntary consensus 

standards are technical standards (e.g., materials specifications, test methods, sampling 

procedures, and business practices) that are developed or adopted by voluntary consensus 

standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when 

the Agency decides not to use available and applicable voluntary consensus standards. 

This rulemaking involves environmental monitoring or measurement. Consistent with the 

Agency’s Performance Based Measurement System (“PBMS”), EPA has decided not to require 

the use of specific, prescribed analytic methods. Rather, the rule will allow the use of any 

method that meets the prescribed performance criteria. The PBMS approach is intended to be 

more flexible and cost-effective for the regulated community; it is also intended to encourage 

innovation in analytical technology and improved data quality. EPA is not precluding the use of 

any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the 

performance criteria specified. 

6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in 

 Minority Populations and Low-Income Populations 

EO 12898 (59 FR 7629, Feb. 16, 1994) establishes Federal executive policy on 

environmental justice. Its main provision directs Federal agencies, to the greatest extent 
 

Cost Analysis for the 6-7 November 2010 

Final GS Rule 

practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States. 

EPA has determined that this final rule will not have disproportionately high and adverse 

human health or environmental effects on minority or low-income populations because it 

increases the level of environmental protection for all affected populations. 

Existing electric power generation plants that burn fossil fuels may be more prevalent in 

areas with higher percentages of people who are minorities or have lower incomes on average, 

but it is hard to predict where new plants with Carbon Capture and Storage (CCS) will be built. 

EPA is developing guidance for UIC Directors that places emphasis on considering the potential 

impact of any GS permits on communities (such as minority and low income populations) when 

evaluating Class VI injection well permit applications, as well as provides suggestions and tools 

for targeted outreach to ensure more meaningful public input and participation from the most 

affected communities during the permit evaluation and approval process. 

This rule does not require that GS be undertaken; but does require that if it is undertaken, 

owners and operators will conduct the activity in such a way as to protect USDWs from 

endangerment caused by CO2. Additionally, this rule will ensure that all areas of the United 

States are subject to the same minimum Federal requirements for protection of USDWs from 

endangerment from GS. Additional detail regarding the potential risk of the rule is presented in 

the Vulnerability Evaluation Framework for Geologic Sequestration of Carbon Dioxide

(USEPA, 2010c). 
Cost Analysis for the 7-1 November 2010 

Final GS Rule 

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Arizona. 2006. Executive Order 2006-13. http://www.governor.state.az.us/ 

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Florida Executive Orders related to climate change: 

http://www.dep.state.fl.us/climatechange/eo.htm 

 

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in Geological Media: Analysis of Well Distribution in Mature Sedimentary Basins. 

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California. 

Gibbs, J. F., J. H. Healy, C. B. Raleigh, and J. Coakley. 1973. Seismicity in the Rangeley, 

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Experience from Underground Gas Storage and Enhanced Oil Recovery. Alberta 

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Muds and Mudstones: Physical and Fluid Flow Properties. In: Geol. Sci. Special 

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Project Summary Report 2000-2004. 
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http://www.illinois.gov/gov/execorders/2006_11.htm 

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Jaffe, P. R. and S. Wang. 2003. Potential Effect of CO2-releases from Deep Reservoirs on the 

Quality of Fresh-water Aquifers. Proceedings, 6th International Conference on 

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