# 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 Pr omulgating 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 Re gulatory 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 Di scounting 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 fo r 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 Pluggi ng 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 Incremen tal 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 a nd 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: Regulator y 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 Childre n from Environmental Health Risks and Safety Risks........................................................................................................ . 6-5 6.9 Executive Order 13211: Actions that Si gnificantly 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 CO 2 

# ...................................................2-13 Exhibit 3.1 Schedule of Baseline Project Deployment by Formation Type and Project Size ................................................................................................3-7 Exhibit 3.2 Project Characteristic s 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 Sta ndard Occupational Classification (SOC) and Government Schedule Codes- 2008$......................................................5-5 Exhibit 5.2 Project Characteristic s By Formation Type and Size ....................................5-8 Exhibit 5.3 Owner and Operator Burden and Unit Cost Estimates for Geologic Site Characterization (2008$) ........................................................................5-10 Exhibit 5.4 Owner and Operator Co st 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$) .............................................................................5-12 Exhibit 5.6 Owner and Operator Cost Estimates for AoR and Corrective Action – Annualized Values Usi ng a 3% and 7% Discount Rate ($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 Es timates for Injection Well Construction – Annualized Values Using a 3% and 7% Discount Rate ($Millions, 2008$) .........................................................................................5-16 Exhibit 5.9 Owner and Operator Burd en and Unit Cost Estimates for Well Operation (2008$)..........................................................................................5-18 Exhibit 5.10 Owner and Operator Cost Estimates for Well Operation – Annualized Values Using a 3% and 7% Di scount Rate ($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 Bu rden and Unit Cost Estimates for Monitoring (2008$)........................................................................................5-23 Exhibit 5.14 Owner and Operator Cost Estimates for Monitoring – Annualized Values Using a 3% and 7% Di scount Rate ($Millions, 2008$).....................5-26 Exhibit 5.15 Owner and Operator Burd en and Unit Cost Estimates for Well Plugging and PISC (2008$) ...........................................................................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$)..................................................................5-38 Exhibit 5.23 Total and Incremental Rule Costs by Regulatory A lternative and Rule Component – Annualized Values Using a 3% and 7% Discount Rate ($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$) .........................................................................................5-45 Exhibit 5.25 Total and Incremental Ru le Costs Based on 50% Increased Labor Rate - Annualized Values Using a 3% Discount Rate ($Millions, 2008$)....5-45 Exhibit 5.26 Total and Incremental Rule Costs, Change in Cost from Primary Analysis Resulting from 25% Increa se/Decrease in Monitoring Wells – Annualized Values Using a 3% Discount Rate ($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 Associati on 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 CO 2 

# 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 Indus try 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 a nd potential benefits of the new Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 

# ) Geologic Sequestration (G S) 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 im pact of rules that have an annual effect on the economy of over $100 million and make that anal ysis available to the public in conjunction with publication of the final rule. EPA has chos en 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 alternativ es and the reduction in risk re lative 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 CO 2 

# for the purposes of long-term storage (also known as GS). The final rule creates a new class of inje ction well, Class VI, and sets minimum technical criteria for the purposes of protecting undergro und sources of drinking water (USDWs). The elements of the GS Rule are based on the existing Underground In jection Control (UIC) regulatory framework with modifications to addre ss the unique nature of GS in the anticipation of its eventual use to reduce CO 2 

# emissions to the atmosphere.

An outline of the organization of this Cost An alysis is provided below. The remainder of this chapter summarizes the techni cal, 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 authorit y 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 alternat ive 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 hydroge ologic settings available for GS and potential CO 2 

# storage capacity. It also provi des 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 quanti fied assessment of risk becau se GS is a new technology and the results from research on the po tential 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 a lternatives considered. A qualitative discussion of the potential economic benefits of the final rule is also presented.

• Chapter 5 presents an estimate of the cost s of implementing the final rule to owners and operators and primacy agencies. The costs of the other regulator y alternatives that were considered are compared.

• Chapter 6 discusses the effect s of the GS rule on different segments of the population and considers the executive orders and re quirements 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 a nd 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 include s 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 spread sheets that are output from the cost model for each of the regulatory alternativ es 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 Regula tory Issues Addressed by the GS Rule

The Agency has developed a final rule that has tailored the ex isting UIC regulatory framework to address the unique nature of CO 2 

# injection for GS for the purposes of protecting USDWs. The rule contains tailored re quirements 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 (P ISC) and Site Closure,

8. Financial Responsibility, and

9. Emergency and Remedial Response.

1.1.1 Description of the Issue

Geologic sequestration is th e process of injecting CO 2 

# captured from an emissions source (e.g., a power plant or industrial fa cility) into deep subsurface rock formations for long-term storage to reduce CO 2 

# emissions to the atmosphere. To inject captured CO 2 

# , the CO 2 

# is typically converted from a gaseous state to a supercritical state. The CO 2 

# 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 reser voirs) via an injection well.

Many of the injection and monitoring technol ogies 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, th ese technologies have yet to be widely demonstrated at the larger scale needed for GS. It is expected th at GS projects will inject large volumes of CO 2 

# . CO 2 

# in the subsurface is buoyant and is highly mobile. While CO 2 

# itself is not a drinking water contaminant, CO 2 

# 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 well s are not properly sited, operated and monitored. The GS Rule provides minimum requirements to protect US DWs 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 Pa rtnerships (RSCPs) program. In recent years, several experimental pilot or demonstration proj ects 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 eith er Class V experime ntal technology wells 2 

# , Class I industrial non-hazardous wa ste injection wells (the baseline scen ario for this cost analysis), or Class II injection wells (where the CO 2 

# injection is associated with oil or gas recovery). Following promulgation of the GS Rule, proj ects whose primary purpose is to inject CO 2 

# 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 esti mate 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 CO 2 

# 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 CO 2 

# emissions from a variety of stationary sources. For example, 95 percent of the 500 larg est stationary sources are located within 50 miles of a candidate GS rese rvoir (Dooley et al., 2006).

While predictions about large-sc ale availability and the rate of GS deployment are subject to considerable uncertainty, EPA analysis of C ongressional climate chan ge 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 co st 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), EP A conducted sensitivity analyses reflecting projections under certain curr ent 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 pr ojects deployed. These analyses are comparable to analyses performed to support the Regulatory Impact Analysis for Mandatory Reporting of Greenhouse Gases: Injection and Geologic Seques tration of CO2 Rule (Subpart RR) 3



# .

1.1.2 Public Health Concern to Be Addressed

The injection of CO 2 

# , if not properly managed, could e ndanger USDWs because the large injection volumes expected, the relative buoyancy of CO 2 

# and its potential mobility within subsurface geologic formations, combined with the corrosive nature of CO 2 

# in the presence of water, could mobilize contaminants from the surrounding formations and decrease pH of the groundwater. In addition, larg e injection volumes could push saline ground water into fresh
water sources.

Such changes to ground water quality coul d 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 treat ment is prohibitive). The GS rule will protect USDWs by requiring that approp riate measures related to proper siting, injection well construction and operation, monito ring 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 CO 2 

## 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 protecti on 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 issu e regulations for State 4 

# 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 su ch injection may result in the presence in underground water which suppl ies or can reasonabl y be expected to supply any public water system of any cont aminant, 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 promulga ted 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, Tr ibe 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 wa ter 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 histori cal conditions in diffe rent 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 s ubstance that flows or moves whether in a semisolid, liquid, slud ge, 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: CO 2 

# 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. CO 2 

# 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 Progr am regulations, it defi ned five classes of injection wells based on similariti es in the fluids injected, cons truction, injection depth, design, and operating techniques. This categorization ensures that wells with common design and operating techniques are required to meet appropriate performance cr iteria and is described in the following paragraph.

Class I wells, which inject hazardous wa stes, industrial non-hazardous liquids, or municipal wastewaters beneath the lowermost US DW, are technically sophisticated and subject to stringent construction and ope ration standards. Class II wells inject fluids (including CO 2 

# ) associated with oil and gas production. Class III wells inject fluids a ssociated with solution mining of minerals. Class IV wells inject hazar dous or radioactive wastes into or above USDWs. 6 

# Class V includes all injection wells that ar e not included in Classe s 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. Cl ass V wells include GS experimental technology wells used for GS pilot projects.

Currently, almost all existing CO 2 

# 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 CO 2 

# has been injected via Class II wells for enhanced oil and gas recovery (ER). In ER operations, CO 2 

# 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 w ith injection, includ ing injection of CO 2 

# for the purposes of oil and gas production, with oi l and gas reservoir dynamics, and with injection well construction. Although the majority of CO 2 

# 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 infr astructure 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 CO 2 

# 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: Usi ng the Class V Experimental Technology Well Classification for Pilo t 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 CO 2 

# injection projects of an experimental nature that are designed to assess the efficacy of CO 2 

# 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 CO 2 

# into deep subsurface formations for long-term storage.



# 1.3 Economic Rationale

This section addresses the economic rationa le for choosing a regulatory approach to govern GS and thus protect public drinking wate r supplies (i.e., by protecting USDWs) rather than nonregulatory alternatives. Although the fina l 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 ru le because it is not economically significant, EPA is providing the rationale below.

EO 12866 states the following:

[E]ach agency shall identif y the problem that it inte nds to address (including, where applicable, the failures of the priv ate 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 B udget (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 inta ngible 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 affect ed public water systems and private well users. These market failures work separately and togeth er to distort the workings of a free market. Furthermore, the promulgation of a regulation that limits CO 2 

# 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 mark et failure, resulting from the nature of the affected resources. In this case, there are two resources that will be potentially affected by injection of CO 2 

# under the final rule—the aquifers th at serve as USDWs and the underground formations that can sequester CO 2 

# . Under the SDWA, EPA protects USDWs for public use and establishes a regulatory structur e (the UIC Program) to preven t potential contamination that supersedes property rights/ownership issues. B ecause the UIC Program focuses specifically on protection of USDWs, there exists less regulatory history in de fining 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 pote ntial side effects from the operation of GS wells (i.e., contamination of USDWs or other underground formations due to improper siting, construction, operation, or closur e) 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 protect ion of USDWs provided by the Class VI regulation, which ta ilors protective measures to th e risks posed by GS projects.

The second market failure results from an asymmetry in information held by GS well owners and operators versus pot entially affected public water system and private well users. There are an estimated 105,249 smalle r public water systems in the Unit ed States out of a total of153,530 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 rura l communities operate private wells. All of these systems and individuals would be at a disa dvantage in trying to maintain a quality water supply if they were not informed of the potenti al risks that a GS proj ect in their community might pose to their current or future potential wa ter 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 affecte d, i.e., those who are curr ent 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. Th e Federal regulations reduce the high information and transaction costs by acting on be half of consumers in balanci ng 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 di stort the workings of a free market and are the basis for governme ntal intervention. Congress acknowledged these market conditions when it established a Federa l regulatory approach to protecting USDWs under SDWA.

# 2. Consideration of Regu latory Alternatives

2.1 Introduction

The United States Environmental Protection Ag ency (EPA) is finalizing minimum Federal Requirements under the Safe Drinking Water Act (S DWA) for underground injection of carbon dioxide (CO 2 

# ) for the purposes of Geologic Sequestration (GS Rule). The GS Rule was developed to ensure consistency in permitting underground injection of CO 2 

# at geologic sequestrati on (GS) operations across the U.S. and provide requirements to prevent en dangerment of underground sources of drinking water (USDWs) in anticipation of the ev entual use of GS to reduce CO 2 

# emissions to the atmosphere. This cost analysis has been informed by Federal and non- Federal entities to determine how best to tailor existing underground injec tion requirements for CO 2 

# for GS (described in Sec tion 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 nationwid e. EPA has taken a number of steps to inform the GS rule including: conducting research; conducting stak eholder coordination and outreach (including technical works hops); issuing a proposed rulemaki ng and soliciting and reviewing public comment; and publishing a Notice of Data Avai lability (NODA) for comment to seek additional input on the rulemaking.

The following workshops were held to identify t echnical, 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 th eir experience with and use of subsurface and near-surface monitoring techniques. The presen tations were followed by “round table” breakout discussions where participants discussed the availa bility and utility of various monitoring techniques that may be applicable to GS projects.

• Geologic Setting and Area of Revi ew 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 consis ted of three presentation sessions, during which industry and government experts de scribed current research on: s ubsurface 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 O il & 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 In tegrity 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 includ ed technical presentation s on current research by industry, academia, and government agencies on experi mental research in the U.S. and Canada into wellbore integrity and CO 2 

# -cement interactions, modeling, the im pact of wellbore integrity on GS site selection, and industry research on well construction.

• State Regulators’ Workshop on Geologic Sequestration of CO 2


# . 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 a nd formulate the questions related to CO 2 

# injection that EPA would need to answer in its rulemaking pr ocess. In sessions led by the National Energy Technology Laboratory (NETL), expert s presented the status of Department of Energy (DOE) research projects on AoR studies, injection well management, and MMV.

• International Symposium on Site Characterization for CO 2 

# Geologic Storage. Participants at this symposium, held in Berkeley, CA on Marc h 20-22, 2006, discussed various aspects of characterization and se lection of potential CO 2 

# storage sites. The symposium emphasized advances in process understanding, developm ent of measurement methods, identi fication of key site features and parameters, site characteriza tion strategies, and case studies. The presenta tions and discussions addressed: site characterization methods; regional-sc ale site selection; site characterization case studies; leakage from storage formations, includi ng pathways, effects, and implications for site characterization; fundamental pro cesses and technical issues rela ted to site characterization; screening and characterization tools; and regulatory and social issues.

• Risk Assessment for Geologic CO 2 

# Storage Workshop. Following the GWPC fall meeting in Portland, Oregon, State and EPA experts on GS, gr ound water and underground injection, and health and environmental effects of CO 2 

# 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 inj ection and long-term storage of CO 2 

# . 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 fo r 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 reservoi r 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 CO 2 

# storage. They also discu ssed the role of models and reservoir simulation in supporting risk assessmen t and risk communication for GS sites. The workshop informed EPA about ways that geologic m odels and reservoir simulation might be applied during key stages in th e life cycle of a CO 2 

# storage reservoir, from site selection and characterization through injection operations and pos t-injection verification of CO 2 

# containment.

Throughout the rulemaking process, the Agency conduc ted public workshops and public hearings, consultations with specific groups, and EPA representati ves attended meetings to explain the GS rulemaking effort to interested pub lic and stakeholder groups.

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

# EPA held public meetings to discuss EPA’s ru lemaking approach, and consulted with other stakeholder groups including non-gove rnmental 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 Inst itute’s Carbon Capture and Storage (CCS) working group.

Agency Activities Conducted for Proposed Rulemaking

On July 25, 2008, EPA published the proposed “Fed eral Requirements Under the Underground Injection Control (UIC) Progr am for Carbon Dioxide (CO 2 

# ) Geologic Sequestration (GS) Wells” (73 FR 43492). The Agency proposed a new class of injection we ll (Class VI), along with technical criteria for permitting GS wells that tailored the existing UIC regulatory framework to address the unique nature of CO 2 

# injection for GS.

During the public comment period, the Agency he ld 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 repres enting non-governmental organizations, academia, industry, and other organizations. At the hearings, 29 people submitted oral comments. Transcripts of the public hearings are in th e 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 propose d 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, includi ng preliminary field data from the DOE-sponsored Regional Carbon Sequestration Partne rship (RCSP) projects. The Noti ce presented the results of GSrelated studies conducted by the Lawrence Berkeley National Laboratory (LBNL) concerning both GS projects and modeling to predict th e potential impacts on ground water from GS activities (discussed in section II.C.2 of today’s publica tion). The NODA also presented an alternative to address public comments and concerns about the proposed inje ction depth requirement s for Class VI wells.

Following publication of the NODA and Request fo r Comment, EPA initiated a 45-day public comment period, which closed on October 15, 2 009. 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 hear ing. 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 a ddress the unique technical and administrative considerations posed by the GS of CO 2 

# . These four RAs are described in subs equent sections and in Exhibit 2.1.

2.3.1 Regulatory Alternative 1

Under this first alternative, GS wells would n eed to be sited, construc ted, operated, maintained, monitored, and closed in a manner that protects US DWs. RA1 would apply th e performance standard under 40 Code of Federal Regulations (CFR) 144.12(a) that prohibits fluid m ovement 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 acco mpany 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 th e 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 stak eholders advocated a flexible approach for certain elements of a GS regulation, none advocated complete fl exibility in the GS rule. If this alternative were adopted, EPA would need to develop numerous techni cal guidances to assist permitting authorities and to help injection well owners and operators unde rstand and interpret the performance standards.

2.3.2 Regulatory Alternative 2

This RA is similar to the “basic” UIC Program re gulatory standards for injection associated with oil and gas recovery, modified to address the poten tial impacts to USDWs from the injection of large volumes of potentially corrosive CO 2 

# . The GS-specific components of this RA include the use of corrosion-resistant construction materials and surface at mospheric or soil gas monitoring. This RA also gives permitting authorities flexibility to interpret cer tain elements in their permit requirements. For the purpose of this analysis, EPA assumed that operat ors 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 CO 2 

# , 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 ar eal 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 ge ology 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 a nd confining system by pr oviding geological data, including geological names and lit hologic descriptions of the form ations, and information on their thickness and depth. Owners or opera tors 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 operato rs would define the AoR for the GS project based on a calculated radius or by modeli ng. The use of models is encouraged, but would not be required. Within the defined AoR, owners or op erators 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, construc tion, 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 CO 2 

# or associated fluids; and employ co rrective 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 betw een USDWs. This mirrors the curr ent Class II requirements; however this RA includes additional components to address the unique nature of CO 2 

# 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 CO 2 

# and any impurities at the antic ipated 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 CO 2 

# 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 inj ect 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 CO 2 

# injection and will evaluate the following components: the integrity of the upper and lower confining units; the suitability of the inje ction zone; the potential capacity of the geologic formation to sequester CO 2 

# ; community needs, demands, and suppl y from drinking wa ter sources; and any other applicable considerations or information requested by the director.

Injection Well Operation: Under this RA, CO 2 

# injection for GS should be conducted such that the pressure during injection does not initiate new fractures or pr opagate existing fractures in the confining zone adjacent to the USDWs. Higher ope rating 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 pack er) 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 demonstr ate internal MI by continuously monitoring injection pressure, flow ra te, injected volumes, and pressure on the annulus between the tubing and the long-stri ng casing. This RA does not stipul ate specific testing methods for external MITs; rather, flexibility is provided to owners and operators and permitting authorities to propose and approve methods that ar e appropriate to the specific proj ect. A variety of testing methods are available and a flexible a pproach would allow owners and operators to adopt new testing technologies that ar e appropriate to CO 2 

# injection if they become availa ble. Under this RA, MITs would be conducted at a frequency determined by the permitting authority.

Monitoring: Under this RA, GS well owners and operato rs would monitor the nature of injected fluids at a frequency sufficient to yi eld data representative of their ch aracteristics, as determined by the permitting authority. Owners and operators would repor t annually on the characteristics of injection fluids, injection pressure, flow ra te, temperature, volume and annular pressure, and on the results of MITs.

Injection Well Pluggi ng and Post-Injection Site Care (PISC): When injection through a well is concluded, the injection well would be plugged in a way that ensures th at 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 manne r 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 CO 2 

# movement is limited to intende d 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 th e 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 techni cal standards that mirror the stringent deep-well requirements for disposal of non-ha zardous industrial wastes, with some additional requirements to account for the unique nature of CO 2 

# injection for GS. It is more st ringent and prescriptive than RA2. The paragraphs below describe the specific elements of this alternative, hi ghlighting the differences between RA2 and RA3.

Site Characterization: Under this RA, in addition to an ad equate 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 additiona l 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 conf ining 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 adve rse effects associated with CO 2 

# 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 el iminate sites with potential seis mic risks. Additionally, under RA3, owners and operators characterize the overburden and subsurface structures, and provide data on subsurface porosity and permeability and geomechani cal information, e.g., on fractures, stress, rock strength, and formation fluids.

Operators and operators also submit data on geoc hemistry within the injection zone and above the confining zone, including USDWs; th is 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 CO 2 

# movement.

AoR and Corrective Action : Under this RA, owners and operato rs of GS wells determine, in three dimensions, the extent of the AoR based on com putational modeling that accounts for the physical and chemical properties of all phases of the injected CO 2 

# stream, CO 2 

# 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. Addition ally, owners and operators iden tify 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 th erefore need corrective ac tion, and apply corrective action using materials compatible w ith the carbon dioxide stream and other appropriate methods. At the Director’s discretion, owners and operators have the option to phase-in corr ective action and focus on those wells in the portion of the AoR that would be intersected by the CO 2 

# plume or pressure front over the early years of th e 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 th e owner or operator would determine the initial AoR, what corrective action w ill be performed up front and what will be phased in, and a plan for periodic reevaluati on of the AoR (at least every 5 years) to inco rporate monitoring and operational data to verify that the CO 2 

# 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 we ll’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 in ject below the lowermost USDW, except in the limited number of cases wher e operators apply for and receive a permit for a waiver of this requirement. Waiver applications will demonstrate that USDWs above and below the

Cost Analysis for the 2-7 November 2010 Final GS Rule

# injection zone will not be endangered as a result of CO 2 

# injection and will evaluate the following components: the integrity of the uppe r and lower confining units; the suit ability of the injection zone; the potential capacity of the geol ogic formation to sequester CO 2 

# ; community needs, demands, and supply from drinking water sources; and any other applicab le considerations or information requested by the director.

Under RA3, the long string casing and cement wo uld 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 develo ped by API or American Society for Testing and Materials (ASTM) International and can withstand the corrosive nature of the injected CO 2 

# and any impurities throughout the life of the project. Cements would be required to be compatible with the CO 2, 

# and the adequacy of the cement would be verified us ing the best available t echnologies. During drilling and construction, the owner or operato r run logs, surveys, and tests to determine or verify the properties of subsurface formations to assure confor mance with the construction requirements.

Injection Well Operation: Under this RA, the CO 2 

# injection pressure will not be permitted to exceed 90 percent of the fracture pressure of the inje ction zone, and injection would not be allowed to initiate new fractures, propagate existing fractu res, 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-o ff systems (e.g., automatic shut-off check valves) for onshore wells or, other mechanical devices that provide equi valent protection; and alarms and automatic down-hole shut-off systems for we lls located offshore but within State territorial waters, designed to alert the operator and shut-in th e well when operating parameters such as annulus pressure, injection rate, or other parameters dive rge 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, re voked 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 tr acer 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 in jection pressure, rates, and volumes, as well as the pressure on the annul us. Owners and operators also monitor the well materials for signs of corrosion. Operators woul d submit semi-annual opera ting 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 we lls develop and implement a plan to perform testing and monitoring to protect US DWs by tracking the position of the CO 2 

# plume and pressure front; monitoring for geochemical changes in subsurface form ations; and if directed, monitoring at the surface for evidence that CO 2 

# may have leaked to USDWs.

Cost Analysis for the 2-8 November 2010 Final GS Rule

# Owners and operators conduct a pressu re fall-off test at least once ev ery five years. The owner or operator also track the subsurface extent of the CO 2 

# 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 CO 2 

# 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 a nd operators report twice per ye ar, rather than annually, on all required monitoring.

Injection Well Pl ugging and PISC: Under this RA, owners and operators submit, gain approval for, and implement a well plugging plan. To plug inj ection 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 an d implement a plan for PISC and site closure and submit the plan as part of the permit applicati on. For at least 50 years (unl ess 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 si te to show the position of the CO 2 

# plume and pressure front and to demonstrate that USDWs are not being endangered. After 50 years, owners and operators perform a non-endangerment demons tration that the CO 2 

# plume and pressure front ha ve 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 ope rators demonstrate and maintain financial responsibility and resources for pl ugging the injection well, correc tive action, remediation, providing post-injection site monitoring a nd closure (accounting for inflation) and emergency and remedial response. The requirement to maintain adequate fi nancial 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 fi nancial instruments include: trust funds, surety bonds, letters of credit, escrow accounts and insura nce. The owner or operator must maintain such financial responsibility and resources until (1) The Director receives and appr oves 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 opera tors develop, implement and periodically update a plan that describes actions to be taken to address events that may cause endangerment to USDWs during the cons truction, 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 Dire ctor 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 prot ect USDWs from the injection of large volumes of CO 2 

# . This alternative is the most prescriptive; it pr ovides the most regulatory certainty and consistency (and therefore the least flexibility). Many compone nts of this RA equal or exceed the activities performed by owners and operators of Class I hazar dous 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 th at will impede vertical fluid movement, allow for pressu re dissipation, and provi de 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 Cl ass 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 ot her alternatives. In addition to th e 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 l east one stratigraphi c 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-CO 2 

# 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 desc ribing the process by whic h they would define the AoR, apply corrective action, and peri odically reevaluate the AoR. As with RA3, owners and operators would define the AoR using computational models of the injected CO 2 

# stream, CO 2 

# plume and the associated pressure front that are based on informati on collected as part of th e site characterization as well as anticipated operating data . This RA would also specify that the models predict the CO 2 

# plume movement over 10,000 years.

As with RA3, owners and operato rs 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 othe r appropriate corre ctive action methods. As in RA3, owners and operators would, at the Director’s discretion, have the opt ion to phase in corrective action. This RA would specify that the AoR reevaluati on be performed at least once every 5 years.

Injection Well Construction: As with RA3, this RA would speci fy 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 pres criptive. For example, this RA would require the use of specialized, corrosion-resistant ma terials such as latex cement, me tal 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 f eet above the uppermost perforati on. Owners and operators would have to construct injection wells to inject below the lowermost USDW, and at a sufficient depth so the CO 2 

# would remain in a supercritical state (to poten tially avoid MI concerns associated with CO 2 

# phase changes). As with RA3, during drilling and constructi on, the owner or operator would run logs, surveys, and tests to determine or verify th e properties of subsurface formations to assure conformance with the construction requirements.

Injection Well Operation: Under this RA, injection should be c onducted such that pressure in the injection zone does not exceed 90 percent of the fract ure pressure in any porti on of the area defined by the anticipated pressure front, or th e capillary entry pressure at any point in the lower-most portion of the primary confinement system. As with RAs 2 a nd 3, injection may not initiate new fractures, propagate existing fractures, or cause fluid movement into USDWs.

RA4 contains one additional element th at is specific to injection of CO 2 

# for GS. Owners and operators would, at the Director’s discretion, be required to add an odor ant or a tracer to the injected CO 2 

# 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 we lls would demonstrate that their wells have internal and external MI. The sole difference is that this RA would re quire 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 deve lop and implement plans for monitoring geochemical changes in the subsurfa ce, monitoring their injectate, tracking the CO 2 

# plume and pressure front, and conducting surface atmospheric or soil gas CO 2 

# monitoring). This RA also requires that a pressure fall -off test be conducted annually.

This RA differs from RA3 in that it would prescr ibe the use of certain sophisticated technologies, which exceed the detail prescribed in the existing regul ations. For example, it specifies that the network of monitoring wells used for ge ochemical monitoring should be c onstructed, using best available technologies, of corrosion-resistan t materials that could withsta nd extended contact with the CO 2 

# 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 ga s monitoring would be expanded to include monitoring at all artif icial 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, operato rs or operators would report m onthly on the characteristics of injection fluids, injection pressure , flow rate, temperature, volume and annular pressure, and on the results of MITs, and ground water a nd atmospheric/soil gas monitoring.

Injection Well Pl ugging and PISC: Under this RA, owners and operators would develop and implement well plugging and PISC and site clos ure 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 require d under RA3. This RA differs from RA3 in that the post-injection monitoring period would be ove r a period of 100 years (also followed by a non-endangerment demonstration).

Financial Responsibility: The financial responsibili ty requirements under this RA are the same as under RA3, i.e., the owners and operators would de monstrate financial responsibility for plugging the well, corrective action, remediati on, providing post-injection monitori ng, and emergency and remedial response, accounting for inflation.

Emergency and Remedial Response: The requirements for deve loping and implementing an emergency and remedial response plan to address move ment 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 com ponents of each RA of the GS rule.Cost Analysis for the 2-13November 2010Final GS RuleExhibit 2.1 Comparison of Alternatives for GS of CO2REGULATORY ALTERNATIVE 1REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Site CharacterizationGS wells must be sited in a mannerthat protects USDWs from endangerment.A geologic system comprised of:•A receiving zone of sufficient arealextent, thickness, porosity, andpermeability;•A containment mechanism that isfree of transmissive faults or fractures; and•A confining zone of sufficient arealextent and integrity to contain allinjected fluid to allow injection atproposed 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 oftransmissive faults or fractures;•A confining zone of sufficient areal extent andintegrity to contain all injected fluid to allow injection at proposed rates and volumes without initiating or propagating fractures in theconfining zone; and•At the Director’s discretion, additional zonesthat will impede vertical fluid movement, allowfor pressure dissipation, are free of faults andfractures, and provide additional opportunitiesfor monitoring, mitigation, and remediation.A geologic system comprised of:•A injection zone of sufficient depth,areal extent, thickness, porosity, andpermeability;•A containment mechanism that is freeof transmissive faults or fractures;•A primary confining system of sufficient areal extent and integrity to contain all injected fluid to allow injectionat proposed rates and volumes withoutinitiating or propagating fractures in theconfining zone; and•Additional zones that will impede vertical fluid movement, allow for pressuredissipation, are free of faults and fractures, and provide additional opportunities for monitoring, mitigation, andremediation.Provide geological data on the injectionzone and confining zone, including:•Lithologic description.•Geological name.•Thickness and depth.Provide information on thegeologic structure of theproposed site, including:•Maps and cross sections of local geologicstructure;•Identification of faults and fractures in theconfining zone and determination that theywould not interfere with containment;•At the Director’s discretion, identification offaults and fractures in additional zones anddetermination that theywould not interferewith containment;•Eliminate sites with potential seismic risks.Provide information on the geologic structure of the proposed site, including:•Maps and cross sections of local geologic structure.•Identification of faults and fractures inthe primary confining system and determination that they would not interfere with containment.•Identification of faults and fractures inadditional zones and determinationthat they would not interfere with containment.•Information on seismic history and thepresence/depth of seismic sources.Cost Analysis for the 2-14November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Provide a map of the injection well andthe applicable AoR.Characterize the geologic structure and hydrogeologic properties of the proposed storage siteand overlying formations based on:•Data on the areal extent, thickness, capacity,porosity, and permeability of the receivingformations, the confining zones and, at theDirector’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 crosssections illustrating regional geology.Characterize the geologic structure and hydrogeologic propertiesof the proposed storage site and overlying formations based on:•Data on the areal extent, thickness,capacity, porosity, and permeability ofthe receiving formations, the primaryconfining system, and additional confining and containment zones, including any geology/facies changes, basedon geologic cores, outcrop data, 3-dimensional seismic surveys, and welllogs.•In areas with insufficient data, the drilling of at least one stratigraphic testwell in the area is encouraged to determine site specific petrophysical parameters of the injection and confiningformations.•Geomechanical information on fractures, stress, rock strength, and in situfluid pressures within the primary confining system and additional confiningand containment zones.•Geologic and topographic maps andcross sections illustrating regional geology.Provide the geologic name and depthto bottom of all USDWs that may beaffected by the injection.Provide geochemical information on subsurfaceaquifers, including all USDWs:•Baseline geochemistry.•Maps and cross sections of USDWs.Provide geochemical information on subsurface aquifers, including all USDWs:•Baseline geochemical data on waterrock-CO2geochemistry and mineralreactions.•Maps and cross sections of USDWs.Conduct baseline geochemical monitoring withinthe injection system andabove the confining system before injection commences.Conduct baseline geochemical monitoringwithin the injection system and above theconfining systems before injection commences.Cost Analysis for the 2-15November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVEREGULATORY ALTERNREGULATORY ALTERNAT2ATIVE 3IVE 4Provide information on the AoR:•Maps and cross sections of theAoR.•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 theDirector’s discretion, into any additionalzones, including structures that are intendedfor human occupancy using publicly availabledata..•List and associated data (well type and construction, date drilled,location, depth, plugging record, and anyother information required by the Director) for all wells into theconfining zones.Provide information on the AoR:•Maps and cross sections of the AoR.•List and maps of penetrations into theinjection zone and additional confiningand containment zones includingstructures that are intended for humanoccupancy using publicly available data.•List and associated data (well type andconstruction, date drilled, location,depth, plugging record, and any otherinformation required by the Director)for all wells into the injection zone, discretionary confining and containmentzones.Provide information on proposed:•Testing and Monitoring Plan•Injection well plugging plan•PISC and site closure plan•Emergency and remedial plan; andAny other information requested by theDirectorProvide 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 andfailures•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 DirectorProvide information on proposed:•Operating data•Formation testing program•Stimulation program•Injection procedure•Surface and subsurface well construction(including schematic)•Contingency plan to address well shutins and failures•Testing and Monitoring Plan•Injection well construction procedures•FR responsibility demonstration•Injection well plugging plan•PISC and site closure plan•Emergency and remedial plan; andAny other information requested by the DirectorCost Analysis for the 2-16November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVEREGULATORY ALTERNATIVE 43Provide, 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 CO2streamwith formation fluids and minerals in the injection and confining zones and with proposedwell construction materials•Modeled AoR•Status of corrective action on wells in the AoR;and,Any other information required by the Director.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 CO2stream with formation fluids and mineralsin the injection and confining zones andwith proposed well construction materials•Modeled AoR•Status of corrective action on wells in theAoR; and,•Any other information required by theDirector.AoR Study and Corrective ActionThe 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 chemicalproperties of all phases of the injected CO2stream,CO2plume, and pressure front for an appropriatetimeframe to ensure there is no longer a threat toUSDWs based on proposed injection rates andvolumes. Models must be based on site specificinformation, geologic information collected to characterize the injection zone, confining zones, andadditional zones, as well as anticipated operatingdata.The AoR is delineated using computationalmodeling that accounts for the physical andchemical properties of all phases of the injected CO2stream, CO2plume, and pressurefront for 10,000 years based on proposedinjection rates and volumes. Models must bebased on site specific information, geologicinformation collected to characterize the injection zone, confining zones, and additionalzones, as well as anticipated operating data.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 ofthe minimum fixed frequency) the AoR will bereevaluated taking into account: changes insite operation; when monitoring data differsfrom modeling results; and, considerations formaintaining site access; and•Corresponds with the CO2plume and pressurefrontandindicates whether corrective actionwill performed up-front or on a phased-in basis; how corrective action will be adjusted if theAoR changes; and how site access will beguaranteed for future corrective action.As a part of the permit application, the owner/operator develops and submits an AoRand corrective action plan for Director approval that:•Requires the reevaluation of the AoR ata minimum of every five years;•Describes how and when the AoR will bereevaluated taking into account: changesin site operation; when monitoring datadiffers from modeling results; and, considerations for maintaining site access;and•Corresponds with the CO2plume andpressure frontandindicates whether corrective action will performed up-front oron a phased-in basis; how corrective action will be adjusted if the AoR changes;and how site access will be guaranteedfor future corrective action.Cost Analysis for the 2-17November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Identify all artificial penetrations (including active and abandoned wells andmines) in the AoR that penetrate theconfining zone. Provide: a description ofeach well's type, construction, datedrilled, location, depth, record of plugging and/or completion, and any additional information the Director may require.Identify all artificial penetrations (including activeand abandoned wells and mines) in the AoR thatpenetrate the confining t zones (and at the Director’s discretion any additional zones) and pose anendangerment to USDWs. Provide: a description ofeach well's type, construction, date drilled, location,depth, record of plugging and/or completion, andany additional information the Director may require.Identify all artificial penetrations (includingactive and abandoned wells and mines) inthe AoR that penetrate the primary confiningsystem and additional confining and containment zones, and pose an endangerment toUSDWs. Provide: a description of each well'stype, construction, date drilled, location,depth, record of plugging and/or completion,and any additional information the Directormay require.Determine if they have been plugged ina manner that prevents the movementof CO2or associated fluids, and identifythose that need corrective action.Determine if they have been plugged in a mannerthat prevents the movement of CO2or associatedfluids based on reliable, recent plugging records,and identify those that need corrective action.Determine if they have been plugged in amanner that prevents the movement of CO2or associated fluids based on reliable, recentplugging records, and identify those that needcorrective action.Conduct corrective action for the entireAoR prior to injection, remediatingthose wells in the AoR that pose a riskto USDWs using appropriate correctiveaction methods determined by the permitting authorityCorrective action will be conducted up-front or on aphased-in basis as per the AoR and correctiveaction plan (and if approved by the director). Thisincludes, remediating those wells in the AoR thatpose a risk to USDWs using materials compatiblewith the CO2stream and other appropriate corrective action methods.Corrective action will be conducted up-frontor on a phased-in basis as per the AoR andcorrective action plan (and if approved by thedirector). This includes, remediating thosewells in the AoR that pose a risk to USDWsusing materials compatible with the CO2stream and other appropriate corrective action methods.Injection Well ConstructionGS wells must be constructed in amanner that protects USDWs fromendangerment.The well must be cased and cementedto prevent movement of fluids into orbetween USDWs.Provide to the Director for approval of casing andcementing program:Depth to injection zone; injection, external, internalpressure and axial loading; hole size; size andgrade of casing strings; information about CO2stream (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: (inaddition to information above)Depth of setting; annular pressure; injection rate;casing size; and tubing tensile, burst, and collapsestrengths.Provide to the Director for approval of casingand cementing program:Depth to injection zone; injection, external,internal pressure and axial loading; hole size;size and grade of casing strings; informationabout CO2stream (corrosiveness, quantity,composition, temperature) and formationfluids; down-hole temperatures; lithology ofinjection and confining zones; type/grade ofcement.Cost Analysis for the 2-18November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Injection must be below the lowermost USDW, except in the limitednumber of cases in which a waiverapplication is approved. (See RA3for waiver application requirements.)Injection must be below the lowermostUSDW, except in the limited number ofcases in which a waiver application isapproved. (See RA3 for waiver application requirements.)Surface casing should be set through the base ofthe lowermost USDW and cemented to the surfacethrough the use of a single or multiple strings ofcasing and cement. Injection must be below thelowermost USDW, except in the limited number ofcases in which a waiver application is approved.Owners/operators seeking a waiver to inject belowthe lowermost USDW must submit to the Director asupplemental report that demonstrates USDWs willnot be endangered as a result of CO2injection.Before being granted a waiver, owners/operatorswould have to evaluate the following componentsas they relate to their GS projects:•the integrity of the upper and lower confiningunits;•the suitability of the injection zone;•the potential capacity of the geologic formationto sequester CO2;•community needs, demands, and supply fromdrinking water sources; and•any other applicable considerations or information requested by the Director.The director will give public notice that a waiverapplication has been submitted. The supplementalreport 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 fluidmovement and pressure buildup outside of theinjection zone; and, thatthe confining units arefree of transmissive faults and fractures.•Using computational modeling, show thatUSDWs above and below the injection zonewill not be endangered as a result of fluidmovement.•Well design and construction, in conjunctionwith the waiver, will ensure isolation of the injectate.•Monitoring and testing and any additionalplans will be tailored to the GS project to ensure protection of USDWs above and belowthe injection zone.Surface casing drilled below the USDW shallbe set 100 feet below the lowest USDW andcemented to the surface.Injection must be below the lowermostUSDW and the CO2must remain in a supercritical state to avoidMI concerns associatedwith phase change.Cost Analysis for the 2-19November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4The integrity and location of the cementmust be verified using technology capable of radially evaluating cementquality, 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 sufficientnumber of centralizers, must extend to the injectionzone and must be cemented by circulating cementto the surface in one or more stages. The integrityand location of the cement must be verified usingthe best available technology capable of radiallyevaluating cement quality and identifying the location of channels to ensure that USDWs are notendangered.At least one long-string casing, using a sufficient number of centralizers, must extend tothe injection zone and must be cemented bycirculating cement to the surface in one ormore stages. The integrity and location of thecement must be verified using the best available technology capable of radially evaluatingcement quality and identifying the location ofchannels to ensure that USDWs are not endangered.Casing, tubing, and packer should beadequate to withstand the corrosivenature of the injected CO2and any impurities at the anticipated pressure,temperature and otheroperational conditions and meet API standards.Casing, tubing, and packer should be adequate towithstand the corrosive nature of the injected CO2and any impurities at the anticipated pressure,temperature and other operational conditions andmeet API standards.Use specialized, corrosion-resistant materialssuch as metal alloy casing and specializedtubing that can withstand the corrosive natureof the injected CO2and any impurities at theanticipated pressure, temperature and otheroperational conditions and must meet APIstandards using best available technologies.Inject through tubing and packer that is set at adepth opposite a cemented interval of the longstring casing at a depth approved of by the Director.Inject through tubing and packer that is set ata depth opposite a cemented interval of thelong-string casing and set no more than 100feet above the uppermost perforation or openhole for the CO2storage reservoir.Use corrosion resistant cements inzones where cement-CO2contact islikely 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 withstandextended contact with injected CO2and associatedimpurities throughout the life of the project.Use specialized corrosion-resistant latex cement that can withstand extended contactwith injected CO2and associated impuritiesthroughout the life of the project.Cost Analysis for the 2-20November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY AREGULATORY ALTERNATIVE 3LTERNATIVE 4Logging, 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 toconducting first test and notification of anychanges 30 days prior to next test.•A report prepared by a knowledgeable loganalyst that includes an interpretation of alllogs and tests conducted to determine or verifydepth, 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:Beforesurface casing installation: resistivity, sp,and caliper logs; andAftercasing is set and cemented: cement bondand variable density log to evaluate cement qualityradially;Beforelong-string casing installation: resistivity,spontaneous potential,porosity, caliper, gammaray, fracture finder, and any other logs required byDirector; andAfterlong-string casing is set and cemented: cement bond and variable density log, and a temperature log; andA series of MIT logs which may include pressuretest, tracer survey, temperature or noise log, casing inspection log and any other tests required byDirector.Submit to the Director:•A schedule of all logging, sampling, andtesting activities to be completed 30 daysprior to conducting first test and notification of any changes 30 days prior to nexttest.•A report prepared by a knowledgeablelog analyst that includes an interpretationof all logs and tests conducted to determine or verify depth, thickness, porosity,permeability, and lithology of, and formation fluid salinity of, all relevant geologicformations.Logs and tests must include:•Deviation checks•Other logs as required by Director atvarious intervals, including:Beforesurface casing installation: resistivity,sp, and caliper logs; andAftercasing is set and cemented: cementbond and variable density log;Beforelong-string casing installation: resistivity, spontaneous potential, porosity, caliper,gamma ray, fracture finder, and any otherlogs required by Director; andAfterlong-string casing is set and cemented:cement bond and variable density log, and atemperature log; andA series of MIT logs which may include pressure test, tracer survey, temperature or noiselog, casing inspection log if required by Director and any other tests required by Director.Take whole cores and sidewall cores in the injection zone and confining systems and formation fluidsamples from the injection zone(s) and submit tothe 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 submit to Director, whole cores andsidewall cores in the injection zone and confining systems and formation fluid samples ofthe injection zone; and any other or comparable information required and approved of byDirector.Cost Analysis for the 2-21November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Record fluid temperature, pH, conductivity, reservoir pressure, and static fluid level of the injectionzone(s).Record fluid temperature, pH, conductivity,reservoir pressure, and static fluid level of theinjection zone.Determine or calculate injection and confining zonefracture pressure; physical and chemical characteristics of the injection zone, confining zone, andinjection zone formation fluids.Determine or calculate injection and confiningzone fracture pressure; physical and chemical characteristics of the injection zone, confining zone, and injection zone formation fluids.Perform a pump test or injectivity test prior to operation to verify hydrogeologic characteristics ofthe injection zone.Perform a pump test or injectivity test prior tooperation to verify hydrogeologic characteristics of the injection zone.Injection Well OperationGS wells must be operated in amanner that protects USDWs fromendangerment.Injection should be conducted such thatthe pressure during injection does notinitiate new fractures or propagate existing fractures in the confining zoneadjacent to the USDWs.Higher operating pressures may beallowed if approved by the permittingauthority.Injection should be conducted such that pressurein the injection zone does not exceed 90 percent ofthe fracture pressure of the injection zone in anyportion of the area definedby the anticipated pressure front. Injection may notinitiate new fractures,propagate existing fractures in the injection zone,or cause fluid movement into USDWs; and, annulus pressure should exceed operating injectionpressure unless otherwise specified by the Director.Injection should be conducted such thatpressure in the injection zone does not exceed 90 percent of the fracture pressure ofthe injection zone in any portion of the areadefined by the anticipated pressure front, orthe capillary entry pressure at any point in thelower most portion of the primary confiningsystem. Injection may not initiate new fractures, propagate existing fractures, or causefluid movement into USDWs; and, annuluspressure should exceed operating injectionpressure unless otherwise specified by theDirector.Owners and operators are be required to equip thewell with alarms and down-hole shut-off systems orother safety devices (e.g., check valves) approvedby the Director, designed to alert the owner or operator and shut-in the well when operating parameters such as annulus pressure, injection rate, orother parameters diverge beyond permitted rangesand/or gradients specified in the permit.Equip with down-hole safety shutoff valvesthat engage when any operating parametersdiverge beyond permitted ranges or a drop inannulus pressure is detected.At the director’s discretion, add an odorant ora tracer to the injected CO2to facilitate earlydetection of leaks or movement outside of theintended injection zone in order to preventendangerment of USDWs.If a shutdown (i.e. down-hole or at the surface) istriggered, cease injection;investigate and identifycause of shutdown; determine if CO2has leakedinto unintended zones; notify Director; restore anddemonstrate MI to Director; notify Director wheninjection will resume.If a down-hole shutdown is triggered, ceaseinjection; investigate and identify cause ofshutdown; determine if CO2has leaked intounintended zones; notify Director; restore anddemonstrate MI to Director; notify Directorwhen injection will resume.Cost Analysis for the 2-22November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4MITGS wells must be monitored in amanner that protects USDWs fromendangerment.Demonstrate internal MI by monitoringinjection pressure, flow rate, injectedvolumes, and pressure on the annulusas specified by the permitting authority.Demonstrate internal MI by continuously monitoring injection pressure, flowrate, injected volumes,and pressure on the annulus between the tubingand the long-string casing.Demonstrate internal MI by continuouslymonitoring injection pressure, flow rate, injected volumes, and pressure on the annulusbetween the tubing and the long-string casing.Demonstrate external MI, i.e., there isno significant fluid movement into aUSDW 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 verticalchannels adjacent to the injection well bore using atracer survey of the bottom-hole cement (using aCO2-soluble tracer or a suitable alternative method(e.g., Oxygen Activation Log (OAL)), a temperatureor noise logs or other tests suitable to wells injecting liquid/super critical CO2fluids as approved bythe permitting authority), or if required by the director a casing inspection log; or, another suitablemethod required and/or approved by the Director atleast once per year.Demonstrate external MI, i.e., there is nosignificant fluid movement into a USDWthrough vertical channels adjacent to the injection well bore using a tracer survey of thebottom-hole cement (using a CO2-solubletracer or a suitable alternative method (e.g.,OAL), a temperature or noise logs or othertests suitable to wells injecting liquid/supercritical CO2fluids as approved by the permitting authority), or if required by the director acasing inspection log; or, another suitablemethod required and/or approved by the Director at least twice per year.Report within 30 days(or with the next reportingperiod, whichever is later) the results of periodic MItests, other tests required by the Director, or wellworkovers.Report within 30 days (or with the next reporting period, whichever is later) the results ofperiodic MI tests, other tests required by theDirector, or well workovers.MonitoringAs a part of the permit application, develop andsubmit a testing and monitoring plan for Directorapproval.As a part of the permit application, developand submit a testing and monitoring plan forDirector approval.GS wells must be monitored in amanner that protects USDWs fromendangerment.Monitor the nature of injected fluids at afrequency sufficient to yield data representative of their characteristics.Monitor the nature of injected fluids at a frequencysufficient to yield data representative of their characteristics.Monitor the nature of injected fluids at a frequency sufficient to yield data representativeof their characteristics and to demonstratetheir compatibility with the well materials.Monitor injection wells for loss of mass, thickness,cracking, pitting and other signs of corrosion on aquarterly basis to ensure that the well componentsmaintain integrity using coupons, routing CO2through a loop in the well, or an alternative methodapproved by the Director.Monitor injection wells for loss of mass, thickness, cracking, pitting and other signs of corrosion on a quarterly basis to ensure that thewell components maintain integrity usingcoupons, routing CO2through a loop in thewell, or an alternative method approved bythe Director.Conduct a pressure fall-off test at least once every5 years.Conduct a pressure fall-off test at least onceper year.Cost Analysis for the 2-23November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Track the subsurface extent of the CO2plume andpressure front using pressure and temperaturegauges, resistivity logs, and other monitoring toolsor using geophysical techniques (e.g., seismic,electrical, gravity, or electromagnetic surveys)and/or other down-hole CO2detection tools or other methods as determined by the director.Track the subsurface extent of the CO2plume and pressure front using pressure andtemperature gauges, resistivity logs, and other monitoring tools and using geophysicaltechniques (e.g., seismic, electrical, gravity,or electromagnetic surveys) and other downhole CO2detection tools as determined bythe director.Monitor geochemical changes above the confiningzone (and at the Director’s discretion any additionalzones). The number of monitoring wells should bebased on site-specific information and may be afunction of CO2injection rate and volume, geology,the presence of artificial penetrations, or other factors.Monitor geochemical changes above the confining zone and additional confining and containment zones using best available technologies. Develop a monitoring well strategy;the number of monitoring wells should bebased on site-specific information and maybe a function of CO2injection rate and volume, geology, the presence of artificial penetrations, or other factors; wells should be constructed of corrosion-resistant materials.At the Director’s discretion and as part of the permit application, develop and implement a plan forsurface air monitoring and/or soil gas monitoring todetect leakage of CO2in the AoR to ensure thatCO2and any other contaminants moving with theCO2have not migrated through USDWs.Develop and implement a plan for surface airmonitoring and/or soil gas monitoring to detect leakage of CO2in the AoR, at all artificialpenetrations within the AoR, and at othersensitive areas, e.g., in buildings and manmade surface structures that are intended forhuman occupancy to ensure that CO2andany other contaminants moving with the CO2have not migrated through USDWs.Report annually on the characteristicsof injection fluids, injection pressure,flow rate, temperature, volume and annular pressure, and on the results ofMITs.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 ofevents that exceed operating parameters for annulus or injection pressures and any events that trigger a shutdown and response taken; monthly volume of CO2stream injected; and results of allmonitoring. Report on MIT results within 30 days oftesting, except in the cases where MIT or other testindicates a problem with the operations, whichwould be reported within 24 hours. Reports mustbe submitted to an electronic EPA system. Records on operational data are kept for 10 yearsafter collection and certain other data are kept until10 years after site closure.Report monthly on the characteristics of injection fluids and any changes from proposedoperating data; injection pressure, flow rate,temperature, volume and annular pressure; adescription of events that exceed operatingparameters for annulus or injection pressuresand any events that trigger a shutdown andresponse taken; monthly volume of CO2stream injected; and results of all monitoring.Report on MIT results within 30 days of testing, except in the cases where MIT or othertest indicates a problem with the operations,which would be reported within 24 hours.Reports must be submitted to an electronicEPA system. Records on operational dataare kept for 10 years after collection and certain other data are kept until 10 years aftersite closure.Cost Analysis for the 2-24November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Well Plugging, PISC and Site ClosureAs a part of the permit application, develop and submit a well plugging planfor Director approval.As a part of the permit application, develop andsubmit a well plugging plan for Director approvalwhich includes: appropriate test methods to determine bottom-hole reservoir pressure and MIT to beused; type and number of plugs; location/placement of each plug; type of CO2compatible material to be used in plugging; and the methodof plug placement.As a part of the permit application, developand submit a well plugging plan for Directorapproval which includes: appropriate testmethods to determine bottom-hole reservoirpressure and MIT to be used; type and number of plugs; location/placement of each plug;type of CO2compatible material to be used inplugging; and the method of plug placement.GS wells must be closed in a manner that protects USDWs from endangerment.Ensure that the well isin a state of stat-ic equilibrium with mud equalized priorto placement of the plugs (or as required by the permitting authority).Flush the well with a buffer fluid and determinebottom-hole reservoir pressure prior to well plug-ging.Flush the well with a buffer fluid and deter-mine bottom-hole reservoir pressure prior towell plugging.Perform an MIT prior to plugging the well to ensurethe integrity of that portionof the long-string casingand cement that will be left in the ground afterplugging.Perform an MIT prior to plugging the well toensure the integrity of that portion of the longstring casing and cement that will be left inthe ground after plugging.Plug the well with cement in a mannerthat will not allow the movement of fluids either into or between USDWs (oras required by the permitting authority),placing the cement plugs in a mannerspecified by the Director.Notify the Director at least 60 days before pluggingthe 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 Director at least 60 days beforeplugging the well, submitting any revisions tothe well plugging plan for Director approval;and, plug the injection well per the approvedwell plugging plan.Within 60 days after plugging or at the time of thenext quarterly report (whichever is less), owner/operator must submita certified plugging reportto the Director. The owner or operator shall retainthe well plugging report for ten years following siteclosure.Within 60 days after plugging or at the time ofthe next quarterly report (whichever is less),owner/operator must submit a certified plugging report to the Director.Cost Analysis for the 2-25November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4As a part of the permit application, develop and submit a plan for Directorapproval to address PISC and site closure requirements and monitoring, for10 years after project closure.As a part of the permit application, develop andsubmit a plan for Director approval to addressPISC (and monitoring) and closure requirements,for 50 years after cessation of injection.The plan should include the:Pressure differential between pre-injection andpost-injection pressuresin the injection zonePredicted position of the CO2plume and pressure frontA description of post-injection monitoring (location, methods, and frequency)A proposed schedule for submitting monitoringresults to the Director.Upon cessation of injection, the plan should be reapproved by the Director, amended or original.The default PISC period is50 years; data submitted as part of the permitapplication, or collectedduring PISC and submitted to the Director can beused to request a shorter PISC period, subject toDirector approval. At theend of the PISC period, anon-endangerment demonstration will be performed and the director will determine if furthermonitoring is necessary.As a part of the permit application, developand submit a plan for Director approval toaddress PISC (and monitoring) and closurerequirements, for 100 years after cessation ofinjection.The plan should include the:Pressure differential between preinjection and post-injection pressures inthe injection zonePredicted position of the CO2plume andpressure frontA 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 shouldbe re-approved by the Director, amended ororiginal.After 100 years (or before or after with Director approval), a non-endangerment demonstration will be performed and the director willdetermine if further monitoring is necessary.Conductpost-injectsite monitoring perthe Director-approved plan to confirmthat CO2movement is limited to intended zonesConduct post-injection site monitoring per the Director-approved plan (which may include pressurefall-off test; seismic monitoring, if appropriate; monitoring in and above the injection zone and theUSDW) to confirm that CO2movement is limited tointended zones.Conduct post-injection site monitoring per theDirector-approved plan (which may includepressure fall-off test; seismic monitoring, ifappropriate; monitoring in and above the injection zone and the USDW) to confirm thatCO2movement is limited to intended zones.After site-closure is authorized by the Director, plugall monitoring wells in a manner that will preventendangerment of USDWs.After site-closure is authorized by the Director, plug all monitoring wells in a manner thatwill prevent endangerment of USDWs.Submit a site closure report to the Director within90 days, that must be retained for ten years, thatincludes: documentation of (all) well plugging;submission of a survey plat to specified parties;documentation of notification to parties that mayhave authority over future drilling activities in theAoR; records reflecting CO2characteristicsSubmit a site closure report to the Directorwithin 90 days that includes: documentationof (all) well plugging; submission of a surveyplat to specified parties; documentation ofnotification to partiesthat may have authorityover future drilling activities in the AoR; records reflecting CO2characteristicsRecord a notation on the deed to the facility property indicating that the land was used for GS; nameof authority with which survey plat was filed; injection volume, zones, and duration.Record a notation on the deed to the facilityproperty indicating that the land was used forGS; name of authority with which survey platwas filed; injection volume, zones, and duration.Cost Analysis for the 2-26November 2010Final GS RuleREGULATORY ALTERNATIVE 1 REGULATORY ALTERNATIVE 2REGULATORY ALTERNATIVE 3REGULATORY ALTERNATIVE 4Retain for 10 years following site closure, and, afterthree years deliver to the Director, records of thenature, composition,and volume of the CO2stream.Retain for 3 years following site closure, and,after three years deliver to the Director, records of the nature, composition, and volumeof the CO2stream.Financial ResponsibilityProvide through a performance bond, orother appropriate means, the resourcesnecessary plug the well.Demonstrate and maintain financial responsibilityand resources for plugging the well, corrective action, remediation and providing post-injection sitemonitoring and closure, accounting for inflation.Demonstrate and maintain financial responsibility for plugging the well, corrective action,remediation and providing post-injection sitemonitoring and closure, accounting for inflation.Emergency and Remedial ResponseAs a part of the permit application, develop andsubmit an emergency and remedial response planfor Director approval that describes actions to betaken to address movement of injection or formation fluids that may endanger USDWs. Therequirement to maintain and implement anapproved plan is directly enforceable regardless ofwhether the requirementis a condition of thepermit.As a part of the permit application, developand submit an emergency and remedial response plan for Director approval that describes actions to be taken to addressmovement of injection or formation fluids thatmay endanger USDWs.If evidence shows potential endangerment ofUSDWs, the owner or operator should cease injection; notify the Director;investigate and identifyCO2release; implement the emergency and remedial response plan;And, prior to re-commencing injection, demonstrateto the Director non-endangerment to USDWs.If evidence shows potential endangerment ofUSDWs, the owner or operator should, ceaseinjection; notify the Director; investigate andidentify CO2release; implement the plan;implement the emergency and remedial response plan;And, prior to re-commencing injection, demonstrate to the Director non-endangerment toUSDWs.Notify the Director and obtain approval for wellworkovers.Notify the Director and obtain approval forwell workovers.Periodically review the emergency and remedialresponse plan at least once every five years. Anyamendments to the emergency and remedial response plan must be approved by the Director andshall 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 fo r 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 spec ifically to GS and includes re quirements 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 Di rector’s discretion wher ever appropriate. RA4 provides the most reduction in ri sks and overall costs because it pr escribes 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 USDW s. 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 (CO 2 

# ) geologic sequestration (GS) projects that form the baseline incorporated into the GS Ru le Cost Analysis including their hydrogeologic characteristics and other project ch aracteristics affecting the costs of the rule. It presents the data sources for the baseline information and an overv iew of the uncertainty associated with these data. The United States Environmental Pr otection Agency (EPA) has estimated the characteristics for a representative group of proj ects that are expected to deploy under existing legislation over the 50-year pe riod of analysis of the GS Rule. This chapter summarizes the information relevant to the cost analysis presen ted 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 vari ous types and distribution of hydrogeologic settings identified as po tential receiving formations for CO 2 

# injected for the purpose of GS in the U.S.

• Section 3.4 introduces the group of GS projects c onstituting the baseline by size of project and type of receiving formation, and pr esents characteristics for each type of project.

• Section 3.5 identifies the sources of uncer tainty 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, indu stry, and academia, pilot project data and laboratory data from efforts by DOE in conjunction with seven CO 2 

# GS Regional Carbon Sequestration Partnerships (RCSPs). Thes e 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 govern ment representatives) have assessed and characterized the potential CO 2 

# 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 ge ologic basin or State, often pr oviding the data in geographic information system (GIS) format. The NATCARB Atlas also presents information on the research conducted regarding va rious potential receiving formati ons, and includes an estimated total U.S. CO 2 

# GS capacity of approximately 3,500 gigat ons (Gt) although th e actual capacity may be lower once site-specific technical a nd economic considerati ons are addressed.

## Cost Analysis for the 3-2 November 2010 Final GS Rule 

# To estimate non-DOE large-scale projects, EP A consulted sources including the Carbon Sequestration Leadership Forum (CSLF) Carbon Capture and Storage Demonstration Database (updated June, 2009), which EPA downloaded 1 

# 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 w ith the Characterization Phase, in which the National Energy Technology Laboratory (NETL) in Morgantown, WestVirginia and the seven regional partnerships conducted the geologic analysis that resulted in the NATCARB Atlas described above. During the Validation Ph ase (2005-2009), field re searchers conducted validation tests of re servoir simulation methods, data co llection methods for capacity and injectivity, and the performance of monitoring technologies. The partnerships are also field testing approaches to well completion methods, ope rations, and site closur e, with a variety of objectives including:

• 

# Testing the effectiveness of various we ll materials and injection practices;

• 

# Validating models of the fate and transport of CO 2 

# in the subsurface;

• 

# Developing a thorough understandin g of the geology, hydrogeology, and geochemistry at potential GS sites;

• 

# Assessing the usefulness of geophysical survey and monito ring techniques;

• 

# Testing failure scenarios;

• 

# Developing experience necessary fo r deployment of large-scale CO 2 

# 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 pa rtnerships are conducting large volume carbon storage tests to demonstrate that large-scale CO 2 

# 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 CO 2 

## per year injection volume was used to determine those projects lik ely 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, f unding estimates and discussions with members of the regional partnerships to deve lop the projected baseline invent ory 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 th e Lawrence Berkeley National Laboratory (LBNL) to study and evaluate the physiochemical processes of CO 2 

# injection and to explore any potential impacts on ground water aquifers and drinking water sour ces. Current research includes the following:

• 

# Modeling potential impacts of CO 2 

# injection on ground water aquifers and drinking water sources;

• 

# Assessing potential changes in regional gr ound water flow, including displacement of pre-existing saline water or hydrocarbons that could im pact underground sources of drinking water (USDWs) or other resources; and

• 

# Integrating laboratory, field and modeling effo rts with the objectiv e of evaluating the potential consequences of CO 2 

# 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. Informati on gained from this research will be used to evaluate potential risks and develop safeguard s to protect USDWs from endangerment. As described in the preamble to the final GS Rule, EP A 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 form ations across the U.S. that may serve as targets for long-term GS repres ent a significant range of storag e potential, geographic location, and technical and economic merits, which could all affect the potential costs of GS. The variables that define the hydrogeol ogic setting include the type a nd 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 va riables 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 numb er of monitoring wells; and maximum injection rates, volumes, and pressures. The geographic lo cation of the potential in jection zones can also determine the feasibility of injection pr ojects depending on the location of the CO 2 

# source. Although the costs of CO 2 

# 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 compos e 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 desi gned to ensure protection of USDWs through proper siting, well construction, operation, monitori ng, and post-injection site care (PISC) at all sites selected for GS irrespect ive 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 CO 2


# . 3



# Saline Formations

Saline formations are deep and geographically extensive water-saturated rock layers with a high total dissolved solids (T DS) content (i.e., over 10,000 ppm TD S). 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 CO 2 

# stationary sources, which has the po tential to substantially lower CO 2 

# transportation costs. However, because they ar e currently of limited economic value (i.e., they are not used as drinking water s ources or contain any mineral res ources), 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 furthe r 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 o il and gas reservoirs to improve production efficiency. Injection of CO 2 

# is one of several ER techni ques 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. In jection 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 du e to the amount of research needed for oil and gas exploration, and account fo r between 1.1 to 3.8 percent of the potential storage capacity in the U.S. (DOE, 2008). The volumes of CO 2 

# to be injected and left behind in the formation for the purpose of GS would be much greater than traditionally seen in CO 2 

# enhanced oil and gas recovery operations. Geographic distribution of o il and gas reservoirs corresponds to areas that have b een drilled for oil and gas in th e past including Appalachia, the Gulf Coast, Mid-Continen t, and the Rockies.

Unmineable Coal Seams

CO 2 

# may be injected into coal seams to displ ace methane that adsorbs onto the surface of the coal, provided injection does not enda nger USDWs; such formations account for approximately 1.4 – 4.4 percent of the potenti al U.S. storage capacity (DOE, 2008). DOE estimates that for every molecule of methane displaced in enhanced coal bed methane (ECBM)

3 

## CO 2 

## 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 CO 2 

# molecules are adsorbed. (DOE OF E, 2007) This process allows the methane to be captured and produced for eco nomic purposes. Coalbed methane potential is concentrated in the areas of New Mexico a nd Wyoming. There are currently no large-scale CO 2 

# ECBM projects, but DOE reports that initia l field studies have demonstrated that CO 2 

# ECBM and GS into coal seams is technically feasible.

Other Formation Types

Other types of formations such as basalts, or ganic rich shales, and abandoned mines also could potentially serve as CO 2 

# reservoirs, provided injecti on 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 fo rmations, oil and gas reservoirs, and unmineable coal seams for GS. Research is ongoing in these formations a nd their viability as sequestration sites has not been proven. Therefore, EPA expects that CO 2 

# 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. CO 2 

# storage potential by type of injection formation. This estimate extrapolates from prior NATCARB estimates into the previously excluded geographic areas of the Un ited States to yield a total U. S. estimate of 3,374 Gt. Deep saline formations account for the largest estimated potential CO 2 

# 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 guide lines 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 requirement s for GS wells, EPA anticipates that GS wells would be permitted as Class V experimental t echnology wells, in accordance with UIC Program Guidance #83. This class of wells affords the UI C primacy agency discretion to issue permits that meet site-specific conditions for experiment al 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 goa ls 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) determ inations) can have a significant impact on the amount of USDW protection unde r 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 construc tion, 40 years of injection, and 9 years of post-closure monitoring which concludes the timeframe of an alysis. For pilot projects, this analysis captures the entire 15 year period, including 1 year of construction, 4 years of injec tion, 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 wher e 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. Th ese 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 addi tion, 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 CO 2 

# 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 pr oject 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

Y ea r

Notes: 1) Numbers may not add due to rounding. 2) Estimates represent modeled paramet ers, 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 peri od 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 ou tside 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 characteristic s 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. Howeve r, characteristics such as stor age 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 CO 2 

# 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 1 6 4

1 0 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 (mi 2 

## ) 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 41 7 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 Zone 1 

## 1.0 5.8 8.7 2.1 3.1 Number of Monitoring Wells into Injection Zone 1 

## 1.0 5.8 8.7 2.1 3.1 Depth of Monitoring Wells 2 

## (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 4 0 4 0 1 0 Source: Appendix A Type of Project Saline

ER Characteristic 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 we lls; 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 assume d 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 tran sition 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 es timated 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 r equired 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 climat e 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 CO 2 

# , the number of injection wells, the volume of CO 2 

# to be injected, and th e length of the injection period, all of which are incorporated into the ba seline estimate for the GS Rule Cost Analysis. Some parameters, such as the number of projects and the length of the in jection period, represent direct multipliers used to develop costs in this analysis. For example, a doubling of the number of projects (all else being equa l) 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 influe nce injection rates, the need ed areal extent of the CO 2 

# injection zone, and the size of the AoR, which in turn influe nces 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 baseli ne estimates presented in this chapter as reasonable and representative of the current i ndustry status. Depending on how many of these projects actually deploy during th e 50-year period of analysis and the associated characteristics of those projects, the baseline estimates used in this Cost Analysis ma y result in an over- or underestimate of GS Rule costs. Detailed discussi on 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) consider ed during the development of the Federal Requirements under the Safe Drinking Water Ac t (SDWA) for undergro und injection of carbon dioxide (CO 2 

# ) for the purposes of Geologic Sequestra tion (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 prov ides a level of USDW pr otection that corresponds to the stringency of the requirements of that alte rnative. This chapter uses a qualitative approach to examine the risk tradeoffs between compliance with existing requirements, (i.e., the regulatory baseline) and the four regulator y alternatives considered.

The regulatory baseline, for the purpose of this analysis, consists of Agency estimates of the decisions regarding GS projects permitting aut horities and owners and operators would have made under current Underground Injection Control (UIC) Program regulations. The Agency assumes that, absent a GS rule, permitting author ities would issue permits with conditions that are similar in stringency to those for Class I indu strial waste disposal well s. A review of permits issued to early pilot projects indicates that this is the case. Current permits require that these projects have siting, constructi on, operating (i.e., injection be low the lowermost USDW), and monitoring and testing requirements that matc h 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 qualita tive consideration of reduction in risks to USDWs under each alternative relative to the baseline scenario i ndicates that risks are reduced the most under RA4, the mo st prescriptive of the altern atives, and least under RA1 and RA2. While this analysis show s that both RA3 and RA4 signifi cantly 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 Enviro nmental 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 CO 2 

# injection volumes associated with GS, the buoyant and mobile natu re 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 appropr iate for wells injecting CO 2 

# for GS. 1 

# Because GS is still in the early phases of deployment, qua ntitative correlations be tween GS project components, such as site characteristics or operati ng parameters, and the incidence of migration of fluid away from the injection site or leakage from the borehole are not available. This limite d 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 an alysis with regard to the probability of contamination. However, considerable work has been done to qualitatively assess the vulnerabilities in various geologi c 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 protectio n 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 unde rstanding of the nature of the risk from GS.

The current assumptions are that: 1) CO 2 

# injection could cause the movement of brine or brackish water into a USDW, thereby requiring furt her treatment of that water to meet drinking water requirements; and 2) the presence of CO 2 

# 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 quantifie d, 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 re lative 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 re quirements (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 c onsidered relative to the existing (baseline) conditions. The term “baseline” in this chapter refe rs to risks as they exist unde r 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 wh en comparing the regulatory alternatives to the baseline, and not the magnitude of any such change . A discussion of risk ch ange 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 thei r 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 betagged and tested. Conduct postinjection monitoring to confirm that CO 2 

## 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, owne rs and operators of GS wells would need to demonstrate that the injection site is in an area with geol ogic formations that can receive and confine the injected fluids below USDWs such that these fluids remain isolated in or der to ensure protection of USDWs from endangerment. Owne rs and operators must provide maps and cross sections of local geologic structure, USDWs, and the Ao R and characterize the overburden using data on size, capacity, porosity, and permeability and ge omechanical information on fractures, stress, rock strength, and in situ fluid pressures w ithin the cap rock and storage reservoir.

Compared to this baseline, RA1 increases ri sk because the performance standard that wells be sited in a manner that protects USDW s from endangerment is su bject 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 charact erizing the site as th oroughly as described in the baseline, which could potential ly result in injection at a si te with fewer of the protective safeguards that are necessary, gi ven the unique nature of the CO 2 

# 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 ba seline. 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 ar e more stringent and specific than the baseline. Under these alternatives the owners a nd 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, so me 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 a dditional opportunities for monitoring, mitigation, and remediation. Characterizing these layers woul d 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 CO 2 

# injection for GS, such as: requirements for structural and hydrogeologic da ta, seismic history, geomechanical data, and identification and evaluation of faults and fr actures. Additionally, RA4 would require owners and operators to further characterize the ove rburden using geologic cores, outcrop data, 3- dimensional seismic surveys, and well logs and, at the Director’s discre tion, drill a stratigraphic test well to provide more deta iled 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 RA s 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-hazar dous regulations, the AoR for a GS site would be either a 1⁄4 mile radius around the injection well or woul d 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, constr uction, depth, and plugging, and identify which wells require corrective action. Wells in the AoR that pose a risk to USDWs must be addressed using appropr iate 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 th is 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 de fine the AoR based on a calculated fixed radius or by modeling. Assuming that some owne rs 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 penetratio ns; determine, based on publicly available data, whether abandoned wells have been plugged in a manner that prevents the movement of CO 2 

# or associated fluids from the stor age reservoir; and employ correctiv e action at those wells that pose a risk to USDWs using appropriate methods de termined 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 requ iring 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 CO 2 

# . This type of modeling is the most accurate tool available for predicting the migration of the CO 2 

# plume and associated pressure front in the subsurface until the plume movement ceases and pr essures 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.) A dditionally, the use of computational models improves predictions of the extent and direction of the CO 2 

# plume and pressure front to allow better targeting of corrective action and monitori ng. Because using a fixed radius would underrepresent the size and shape of th e large volumes of injected CO 2 

# , the requirement to delineate the AoR using computational modeling decreases ri sk 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 CO 2


# . As in RA2, RA3 and RA4 would require owne rs and operators to identify all well penetrations in the AoR, determine if they ha ve been plugged in a manner that prevents fluid movement, and apply corrective ac tion to those wells as needed. RA3 and RA4 are more specific in that they require that correc tive action be performed using mate rials that are compatible with CO 2 

# , therefore reducing risk of degrading existin g well materials that come in contact with injected CO 2 

# . 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 acco unt 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 CO 2 

# plume is moving as predicted or provide an opportunity to adjust the injection operation, mo nitoring, or corrective action to address changes in the predicted AoR and therefore w ould reduce risk rela tive 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 pr event movement of fluids into USDWs. RA1, with no explicit technical standa rds, 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 impl emented, wells could poten tially be constructed without the appropriate materials and methods that specifically ad dress the risks associated with CO 2 

# injection and risk under RA1 increases from baseline.

RA2, RA3, and RA4 would address risk by e xplicitly requiring that GS wells be constructed and cemented with cas ing, tubing, and packer that meet API or ASTM International standards and are compatible with CO 2 

# . Each RA provides increasing specificity. RA 2 allows the Director’s discretion to approve well materials and desi gn. RA3 specifies the use of cemented surface casing (base of the lowermos t 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. Additiona lly, RA3 also allows the use of horizontal well drilling techniques for GS wells wh ich 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, wh ich address the unique characteristics of CO 2 

# in the presence of water and are demonstrated to reduce the chances of compromising well integrity, are therefore expected to de crease risk relative to the baseline.

## Cost Analysis for the 4-7 November 2010 Final GS Rule 

# EPA assumes in the analysis that under RA 1 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 dir ectly address the presen ce of USDWs above and below the injection zone will result in a minima l increase in risk for RAs 1-3 relative to the baseline.

RA4 would require that in all cases, oper ators inject below the lowermost USDW, as under the baseline scenario. This would apply in most cases to RA3, how ever, as for RA1 and RA2, owners and operators would have the opti on 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 inject ion into the lowermost USDW would result in impractical or technically inf easible well construction. The exp licit formal waiver application process and additional permit conditions that dir ectly address the presen ce of USDWs above and below the injection zone will result in a minimal in crease in risk for RA3 relative to the baseline. In these limited circumstances owners and operato rs 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 owne rs and operators the option of injecting above the lowermost USDW via the waiver process, th ere is an incremental risk increase relative to comple te prohibition of the practice as under the baseline and RA4.

4.2.4 Injection Well Operation

Under current regulations, in jection must be conducted su ch 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 in jection 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 porti on of the cases, appropria te injection pressure limitations may not be employed, suggesting an incr ease in risk for RA1 from the baseline. RA2 has similar requirements as the baseline but allows for higher injection pre ssure 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 owne rs 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 ex tent that these limitations reduce the chance of initiating new fractures or propaga ting existing fractures in the inje ction zone, they decrease risk relative to the baseline.

RA4 additionally requires that the de pth be sufficient to retain the CO 2 

# in a supercritical state; this can help reduce pot ential MI concerns associated with phase changes and decreases risk relative to baseline.

RA3 and RA4 also require th at injection wells are equi pped with down-hole shut-off systems or other safety mechanisms, e.g., check va lves, 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 a llows for director’s discretion unless wells are located in offshore territorial State waters 2 

# 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 a ny 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, decr easing risk relative to the baseline.

Additionally, RA4 allows the Dire ctor to require that an odoran t or a tracer be introduced to the injected CO 2 

# to facilitate early detection of leak s or movement outside of the intended injection zone in order to pr event endangerment of USDWs. To the extent that odorants or tracers are detected and result in modifications to the injection operati on 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 we ll operation requirements.

4.2.5 Mechanical Integrity Testing

Under the baseline, GS well owners and operato rs 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 CO 2 

# -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 sp ecify mechanical integrity testing (MIT) types and frequencies that are less pr otective than baseline requireme nts. Therefore, under RA1 there is a potential increase in the relative ri sk to the baseline for MIT requirements.

RA2 does not specify a testing frequency; ra ther, it provides flexibility to permitting authorities to specify MIT methods and testing frequencies that are appr opriate to the specific project. As such, the Agency assumes that Director s may choose a testing interval of more than 5 years which could potentially allow MI problem s to go undetected for longer periods of time; therefore, RA2 potentially increases risk from baseline.

Under RA3 and RA4, owners and operator s must demonstrate internal MI by continuously monitoring injection pressure, flow rate, injected volumes, and pressure on the annulus between the tubing and the long stri ng casing. Continuous monitoring can provide

2 

## Requirements specific to ocean injection wells in the Fe deral 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 CO 2 

# . This requirement would directly address the unique nature of CO 2 

# injection for GS and therefor e is expected to decrease risk from baseline.

Under RA3 and RA4, owners and operators mu st demonstrate external MI using an approved tracer survey such as an oxygen-activ ation log or temperatur e or noise logs. The Director also has the discretion to require a cas ing inspection log to de termine the presence or absence of any casing corrosion. The external MI T 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 wate r monitoring within the AoR (a t the Director’s discretion); and report quarterly on these resu lts 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 m onitoring 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 mon itor the nature of injected fluids at a frequency sufficient to yield data representative of their char acteristics. Owners and operators would report annually on the char acteristics 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 CO 2 

# or other fluids.

Under RA3, owners and operators would deve lop, implement, and periodically review a plan for conducting testing and moni toring that is tailored to the site. This RA includes additional monitoring, including injectate monitoring; corrosion monitori ng of the well’s tubular, mechanical and cement components; pressure fall-off testing; CO 2 

# plume and pressure front tracking; and ground water quali ty 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 mo nitoring plan and these monitoring requirements are tailored to the risks associated wi th injection of large volumes of CO 2 

# and to the specific aspects of the site and operational conditions, RA 3 is expected to mitigate more risk than the baseline requirements.

RA4 includes all of the monito ring requirements in RA3, with additional specificity on some elements. In addition to corrosion mon itoring, owners and opera tors would need to

## Cost Analysis for the 4-10 November 2010 Final GS Rule 

# demonstrate compatibility of well materials to the injected CO 2 

# . 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-re sistant materials. It requires that the surface air and soil gas monitoring regime include all arti ficial penetrations within the AoR and other sensitive areas, e.g., in buildings and manmade surface structur es that are intended for human occupancy. Finally, under RA4, owners and operators woul d submit monitoring reports every month. With additional monitoring requirements that are tailore d 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-Injectio n Site Care (PISC), and Site Closure

At the conclusion of injection of CO 2 

# for GS, the injection well must be plugged in a way that ensures that it would not se rve 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 operato rs would also conduct post-injection monitoring to confirm that the CO 2 

# movement is limited to intended zones.

RA1 has no specific requirements with resp ect to plugging and post-injection monitoring and therefore increases risk relative to the ba seline. 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 taggi ng and testing all plugs. This RA also would require owners and operators to conduc t post-injection monitoring for 10 years per a Director-approved plan. Th e inclusion of specific PI SC requirements that CO 2 

# movement be monitored following injection activ ities to ensure that it is lim ited 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 reserv oir pressure, perform a final external MIT, and plug the well in a manner using approved methods that will pr event the movement of fluid that may endanger USDWs. Additionally, these RAs require owners a nd operators to develop and implement a plan to conduct PISC monitoring, (which may include pressure monitoring; geophysical monitoring, if appropriate; and geochemical monitoring in an d above the injection zone and the USDW) to confirm that CO 2 

# movement is limited to intended z ones. The sole difference between the alternatives is the time frame: 50 years for RA3 (the Director ha s 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 po int, closure of the site is authorized.

The requirements in RA3 and RA4 for PISC mon itoring for extended time frames that are tailored to site-specific conditi ons 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 de monstrate that they have the resources necessary to plug and abandon the injection well throu gh 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 activiti es, suggests an increase in risk relative to the baseline. RA2 w ould require the operator to pr ovide 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 demonstr ate and maintain financial responsibility for not only plugging the injection well, but also for all needed correctiv e action, emergency and remedial response, and PISC and closure. Owners and operators would need to adjust the cost estimates for these activities peri odically to account for inflation and other conditions that may affect costs. RA3 and RA4 mitigate more risk rela tive 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 activitie s, 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 endangeri ng USDWs. Although injection well owners and operators are required to cease injection and take nece ssary actions if they discover evidence of USDW endangerment, the Class I no n-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 an d 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 construc tion, operation and PISC periods of a GS project. In the even t that there is evidence that the CO 2 

# or pressure front is endangering USDWs, the operator would cease inj ection, take necessary steps to identify and characterize the extent of any release, and impl ement the emergency and remedial response plan. By providing a means to address a release of CO 2 

# 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 EP A 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 m odifications 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 modifi cation of existing requir ements) to ensure the safe injection and sequestering of CO 2 

# , 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 th ere 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 chan ge in the direction of risk based on consideration of each regulatory al ternative 1 – 4 relative to the ba seline 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 relati ve 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 resp onse. Thus, EPA estimates an overall increase in risk relative to the baseline for RA1.

Under RA2, EPA estimates that risk will incr ease for four of the eleven programmatic components of the GS rule (geologic charac terization, injection we ll operation, MIT, and monitoring); that it will decrease in three ca tegories (AoR /correctiv e action, well construction, and well plugging/PISC); and that it will not change from the baseline relative to four categories (financial responsibility, emergency and remedi al response, injection depth waivers, and the adaptive rulemaking process). Although this a lternative generally has many of the same requirements as the baseline, RA2 allows the Dir ector 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 importan ce of the AoR/corrective action and construction components (which decrease risk relative to the base line), it is expected th at the overall resulting change in risk will be a slight decr ease in comparison to the baseline.

Both RA3 and RA4 uniformly decrease risk ac ross all regulatory components, indicating an overall decrease in ri sk under both regulatory alternatives. Th is is primarily attributed to the additional specificity in each of these alternatives th at are tailored to address the unique nature of GS. However, in many instances the requirement s under RA4 are more prescriptive or specify better technologies than under RA3; this results in the potential fo r 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 protecti ons provided to affected entities that are not directly addressed under the authority of the UIC Program as pres cribed under the SDWA, which is limited to protection of USDWs. These ancill ary protections apply to categor ies such as human health and welfare, the atmosphere, ecological receptors, su rface water, and the physical environment. Risk to these entities from GS is not well understood; however, to the ex tent 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 opera tions and after injection has ceased. These ancillary benefits are summarized below a nd 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 contaminat ed by materials that are mobilized from the soil/rock matrix. These measures include mon itoring requirements and appropriate operational thresholds that decrease the potential for large scale CO 2 

# leaks. As CO 2 

# is an asphyxiant, humans can experience adverse health effects at elevated CO 2 

# concentrations (Raschi et al., 1997), and extremely high concentrations (a bove 30 percent) can result in fatality. Although the likelihood of CO 2 

# 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 CO 2 

# 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 CO 2 

# and brine below USDWs. The GS Rule may also mitigate potential risk to forest s and other flora by protecting it from the harmful effects of exposure to elevated CO 2 

# 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 ancilla ry 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 su rface water is contaminated by CO 2 

# , brine, or mobilized contaminants. It also mitigates risk to subsurf ace resources such as oil and gas reservoirs, which could be affected by pressure from CO 2 

# plumes.

Surface Water

Through geologic siting and well construction st andards that prevent fluid movement in the subsurface and monitoring standards that w ould provide early warnin g of leakage out of intended zones, the GS Rule mitigates potential ri sk of contamination of surface water from GS

## Cost Analysis for the 4-14 November 2010 Final GS Rule 

# operations. Specifically, the GS Rule mitigates th e risk of water quality degradation that is associated with CO 2 

# contamination, including: increased salinity, increased acidity, and mobilization of metals and impurities. It also mitigates the risk that pressure from CO 2 

# 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 CO 2 

# 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 he alth effects associated with CO 2 

# exposure. Acidification of surface water due to CO 2 

# contamination could kill species sens itive 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. CO 2 

# 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 CO 2 

# migrating to USDWs will mitigate the risk of sequestered CO 2 

# escaping to the atmosphere, helping to ensure that the benefits of reduced CO 2 

# emissions to the atmosphere with regard to climate change are maintained. The well plugging and PISC require ments in the GS Rule further reduce the potential for leakage of CO 2 

# into the atmosphere and ensure effective long-term storage.

Additionally, plants relyi ng on a water source that is impacted by injected CO 2 

# may be intolerant of the pH change or high concentrations of CO 2, 

# which can inhibit root respiration and hinder oxygen uptake and plant growth. In the case of CO 2 

# contamination of plant life, animal species depending on these plants would also suffe r detrimental health effects. The extensive geologic siting process, well cons truction, and monitoring requirements associated with the GS Rule mitigate these potential risks by guarding against CO 2 

# leakage.

Physical Environment

Uplift and induced seismic activity as a result of subsurface pressure changes associated with injecting large volumes of CO 2 

# could have significant financ ial ramifications as well as negative effects on human health. Subsurface pr essure changes that exceed a formation’s geomechanical strength could cau se fracturing or reactivate fau lts 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 transm issive faults and fractures, and the seismic history of the site; injection pressure limitations; and monitoring of the CO 2 

# plume and pressure changes.

Social Cost of Carbon

The GS rule has many requirements that help ensure that CO 2 

# is not being lost from GS sites to the atmosphere. They in clude pressure integrity requirements for injection wells, various types of CO 2 

# detection and monitoring requirements, re medial action requirements, and required

## Cost Analysis for the 4-15 November 2010 Final GS Rule 

# minimum criteria for GS sites. These require ments provide assuran ce that sequestered CO 2 

# remains underground, which in turn provide benef its in terms of avoided emissions from GS sites. In other words, if CO 2 

# leaked out of a given GS site, a net reduction in emissions would not be realized. Therefore, en suring that sequestered CO 2 

# remains underground has a net benefit. The cost to society of CO 2 

# emissions (and thus the value of avoided emissions) can be measured in dollars using an emerging metric called the So cial 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 CO 2 

# emissions and reflect underlying assumptions about the growth of emissions a nd changes in socio-economic trajectories. In February 2010, an interagency working group pub lished SCC estimates for use in regulatory impact analyses of government regulations.

The interagency group selected four CO 2 

# SCC estimates for use in regulatory analyses. For 2010, these estimates are $5, $21, $35, and $65 (i n 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. Th e central value is the average SCC across models at the 3 percent discount rate. For purpos es of capturing the uncertainties involved in regul atory impact analysis, the inte ragency group emphasized the importance and value of considering the full rang e. These SCC estimates also grow over time. For instance, the central value increases to $24 per ton of CO 2 

# in 2015 and $26 per ton of CO 2 

# in 2020.

Due to the fact that this final rule does not require owners or operators to mitigate climate impacts through geologi c sequestration of CO 2 

# , the benefits (which can be measured using SCC) associated with geologic sequestration may be bette r ascribed to regulations that require and/or provide incentives for geologic sequestration. Ho wever, without the re quirements of the GS Rule, a regulatory framework would not be in place to help ensure that CO 2 

# is not being lost from GS sites to the atmosphere. Therefore, a sm all (but unquantified) porti on 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 quantita tive 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 consider ed in this analysis represent increasing levels of regulatory ce rtainty that are assumed to corre late 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 author ities. 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 UI C Program suggests that in those areas where discretion is allowed there are distinct differences in interp retation among permitting authorities nationally. The magnitude and impact of such diff erences is difficult to predict for the GS rule, but EPA believes its general interp retation of a decrease in pote ntial 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 na tional costs of the Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 

# ) Geologic Sequestration (GS) Wells (the GS Rule), as well as a brief qualita tive 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 Prot ection 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 ar e particular to injection of CO 2 

# for the purposes of long-term storage. The GS Rule defines a new class of injection well (Class VI), along with technica l criteria that tailor the ex isting UIC Program regulatory framework to address the unique nature of CO 2 

# injection for long-term st orage in anticipation of the eventual use of GS to reduce CO 2 

# emissions to the atmosphere. Technical components of the GS Rule include geologic site characterizati on; area of review (AoR ) and corrective action; injection well construction; injection well opera tion; 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 Co st Analysis are representative of costs that EPA expects owners and operators and pe rmitting 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 Analys is makes assumptions about the number of monitoring wells to be construc ted although, in reality, the owners and operators and Director will determine this requirement on a site speci fic 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 pred icted how the Directors will appl y this latitude for the purpose of estimating costs. EPA considered the variou s hydrogeologic conditions that might prevail in baseline projects and the level of stringency in pr otective 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 (Regulat ory Alternative 3, or RA3); how ever, assumptions and cost estimates for the baseline (RA 0) and the othe r three RAs considered (RAs 1, 2, and 4) are presented in the exhibits in this chapter. Increm ental costs with respect to the baseline are shown for the selected RA as well as the other al ternatives considered during the regulatory development process. In addition, some exhibits in clude cost elements that apply to at least one alternative but not to the selected alternative, RA3. Furthermore, so me exhibits include costs that correspond to activities that th e 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 CO 2 

# 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 va riety of implementation and oversight activities such as training, data system updates, primacy applications, permit reviews and approvals (including waiver application revi ew), consultations, and report reviews (i.e., monitoring results), as well as all associ ated recordkeeping.

EPA estimated owner and operator costs fo r the technical rule components using equipment price lists and quotes, wage rates fr om government sources (e.g., Bureau of Labor Statistics (BLS)) and industry sources, stakehol der input, and information developed for similar analyses (e.g., the UIC Program Information Co llection 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 me thodology and compliance assumptions used to estimate national costs for the GS Rule.

• Section 5.3 describes the methodology for projec ting costs over a 50-year period according to the GS Rule compliance schedul e, estimating the present value of each cost, and annualizing each cost over this period.

• Section 5.4 describes the methodology for developi ng 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 pr ojects 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 compon ents: characteristic profiles for the five types of projects that represent the 29 1 

# projects of the cost analys is baseline; unit costs for each compliance activity; a site selection factor to account for the cost of geologic site characterization of sites th at turn out to be unusable 2 

# ; an ER Applicability factor to account for how costs apply differently to tr ansitioning GS projects (project s converting from existing Class II enhanced recovery (ER) operations to long- term storage operations ) compared to saline projects; an application factor 3 

# and a schedule specific to each RA for each compliance activity; calculation of the costs for each compliance ac tivity 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 main tenance (O&M) expenditures).

The five project type profiles contain char acteristics 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 inj ection zone (IZ) and the primary containment formation are deepest in sa line formations, and shallower in oil and gas reservoirs. Additionally, limited projects with an approved waiver to inje ct between USDWs are likely to be shallower than those with inje ction zones below the lowermost USDW. Other characteristics vary by the GS pr oject 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 transi tion to a Class VI project for the primary purpose of long-term storage is 10 years (after 20 y ears of Class II ER). The assumptions used in developing the GS Rule baseline are described in Chapter 3 (B aseline 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 ty pe profiles and by the f actors appropriate for a given project type (RA applicati on factor, site selection factor, enhanced recovery application factor) to produce a project leve l cost (as opposed to a rule level cost) for each compliance activity. Descriptions of the unit costs, application factors, an d algorithms developed in this analysis are provided in Appendix B, and the detailed derivation a nd sources of the unit costs are presented in the Geologic CO 2 

# Sequestration Technology and Cost Analysis (EPA, 2010a).

The model then multiplies the project level cost for each compliance activity by the corresponding number of respondent s 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 s ite 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 determin ed to be suitable for GS. Put another way, an operator will on average have to characterize four sites to find one suitabl e one. For ER projects, the s ite 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 fo r 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 e ach of the 50 years in the analysis period. The model calculates these annual estimates in nondiscounted do llars 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-ye ar period of analysis by rule component and further by cost type: one-time, capital, and O&M expenditures.

Lastly, the model compares the baseline regul atory scenario (RA0) to each of the RAs (RA1 – RA4) to derive the incremental costs attr ibuted to the GS Rule. The regulatory baseline, for the purpose of this analysis, consists of EPA estimates of the decision s regarding GS projects that permitting authorities as we ll as owners and operators woul d 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 st ringency to those for Cl ass I industrial waste disposal wells. A review of permits issued to early pilot-scale proj ects indicates that this is the case. Current permits require that these proj ects have siting, cons truction, operating (i.e., injection below the lowermost USDW), and mon itoring 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 requireme nts of Class I non-hazardous wells.

5.2.1 Labor Rates

For costing purposes, EPA estimated the la bor needs and hourly labor rates for two occupations: geoscientists and mining and geolog ical 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 year s 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 hourl y 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 Fe deral employee pay scales issued by the U.S. Office of Personnel and Management 7 

# (OPM) and was multiplied by 1.6 for a loaded rate of $50.14.

4 

## http://www. aapg. org/expl orer/salarysurvey. cfm
5 

## Society for Petroleum Engineers Annu al Membership Salary Survey High light Report. Prepared by Western Management Group. September 2008. p. 12 http://www. spe. org/spe-site/s pe/spe/career/salary_survey/08S alarySurveyHighlights. pdf
6 

## Occupational Employment and Wages, 2008. Table 1. Nati onal 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 Ge neral Schedule Increase, Eff ective 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 participat e in the UIC Program will have primacy for Class VI wells. EPA based this estimate on the numbe r of States with existing Class II programs because of the likelihood that oil and gas reservoi rs 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 operati ng. Federal and Primacy Agency costs are provided in Section 5.4.11.

Exhibit 5.1 Loaded Labor Rates by Stan dard 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 durin g 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 maintena nce and periodic replacement of such items. EPA estimates that G&A costs for the elec tric power generation, mining, and petroleum industries are 20% on average for a ll 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 compone nt and by cost type include G&A costs. Permitting authority costs associated with G&A ar e 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 charac terization of the geologic formati ons 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 (dep ending 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-ye ar instead of a 25-y ear time period, as is normally performed for EPA drinking water regula tions. EPA elected to increase the analysis period to better reflect the lifecycl e 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 cost s for the 50-year analys is 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 ove r a 50-year time horizon based on the schedule for each compliance activity.

• Calculate total present valu e 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 a bove 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 co sts used to derive pr oject 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) regulato ry 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 fi rst 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 Ch apter 3 as a starting point for analysis of owners and operators of GS wells that are su bject to each rule com ponent and associated compliance activities. Exhibit 5.2 presents data from the characteristic profile s of the five project types, which are referenced thr oughout this section, and summari zes 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 capaci ty, 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 1 6 4

1 0 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 (mi 2 

## ) 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 41 7 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 Zone 1 

## 1.0 5.8 8.7 2.1 3.1 Number of Monitoring Wells into Injection Zone 1 

## 1.0 5.8 8.7 2.1 3.1 Depth of Monitoring Wells 2 

## (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 4 0 4 0 1 0

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 we lls; 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 assume d 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 tran sition 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 es timated 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 r equired 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 de scription of the compliance activities and associated costs for permitting authorities. An im portant distinction to note about the figures presented in Section 5.4 is that th ey provide both total and increm ental 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 regulator y requirements beyond those currently practiced by owners and operators of GS wells under exis ting UIC regulations fo r Class I non-hazardous wells.

5.4.1 Rule Implementation and Annual Administration

All owners and operators of GS wells subjec t to the GS Rule will incur one-time costs that include time for staff to become familiar wi th 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 pr esented in Section 5.2.1 are used along with estimates of labor hours to generate implementa tion costs for all owners and operators. Based on previous experience with rule implementation, EP A estimates that each owner and operator will require a total of 80 hours to read and understa nd 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 (s ee 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 characteri zation is to determine whether a site is suitable and safe for injecti on and sequestration. The characte rization process includes site evaluation and tests to support perm it applications. It also involves the development of a baseline for the conditions (pressure, temperature, CO 2 

# flux, etc.) in the AoR to allow long-term monitoring to be successful. Geologic site charac terization is designed to provide the geologic and hydrologic data needed to design the subs urface 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 charac terized will be suitable for GS; therefore a site selection success factor has been applied to th e geologic site characte rization unit costs to account for this extra cost. For saline projects, the analysis assumes th at 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 characteri zed 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 cost s. 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 Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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 $ 19,697,002 $ 310,826 $ 616,490 $ RA3 2,758,863 $ 14,531,099 $ 29,545,503 $ 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 $ 20 5
, 800 $ 411
, 60 0 $ 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. N/A $6,434

$104,000/ square mile N/A Conduct 3D seismic survey to identify faults and fractures in primary and secondar y 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

s y stems.

$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 ( earth q uake ) histor y . 6 0

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 whic h 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). $25,736Provide information on water-rockCO2 geochemistry and mineral reactions. $107.23

Develop list of penetrations into injection zone within AoR (from well histor y data bases )

. $25,736 $10,300/ site

N/

A $1,287/ square mile Provide geochemical information and maps/cross section on subsurface

a q uifers. $107.23 List names and depth of all potentially affected Underground Sources of Drinkin g Water ( USDWs )

. N/ A

$107.23 Obtain geomechanical information on fractures, stress, rock strength, in situ fluid p ressures ( 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 histor y 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

s y stem, etc. $107.23 240 Develop list of water wells within AoR ( from p ublic 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 Geolog ic Site Characterization

Annualized costs for owners and operators unde r 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 mode ls will account for the physical and chemical properties of all phases of the injected CO 2 

# and the associated pressure front and will be based on information collected on site during geologic si te 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 condu its for the escape of injected CO 2 

# or formation fluids into overlying units or USDWs. In the case of salin e 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 i nvolve the removal of existing plugs and casing strings, and recompleting the we ll. This may involve the use of CO 2 

# resistant cements in portions of the well.

It is assumed that each well owner and operato r 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 re curring intervals as the AoR is re-evaluated and potentially expanded or where phased corrective action is al lowed. (The recurring cost for updating the AoR using computational models of CO 2 

# fluid flows is included in th e 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 un it costs are presented in Appe ndix 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 Cost 1 Regulatory Alternative Project Cost Pilot Project -

Saline Project Cost Large Project

- Saline P ro j ec t C os t 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

surve y

.

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 s y stem. 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 6 hours/well $110.62 $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 whic h 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 hor izontal drilling and multi-stage fracturing in shale formations, high tech stimulation and co mpletion methods in tight gas reservoirs, and directional and deepwater wells offshore. Many ER projects using CO 2 

# are now active, especially in the Permian Basin of West Texa s, and technologies have been developed to complete, produce, and maintain injection a nd production wells using this medium for long periods of time.

The design of a GS injection well is similar to that of a conventiona l gas injection well or a gas storage well, with the ex ception that much of the down-hol e equipment must be upgraded for high pressure and corrosion resistance (IPCC, 2005). Upgrades include special casing and tubing, safety valves, cements, and blowout prev enters. GS well owners and operators must construct their injection wells using materials and cements that are compatible with the CO 2 

# stream and/or other fluids with which they may come into contact. EPA assumes in this analysis that under RA1 and RA2 owners a nd operators would inject belo w 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 subsurf ace or pore space use. While subsurface and pore space rights are an expense that is outside the au thority 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 (bas eline 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 include s several volumes of ge ologic data, maps and cross sections, schematics, monitoring and testin g 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 CO 2 

# Sequestration Technology and Cost Analysis (EPA, 2010a) describes all of the documenta tion included in the permit application. Facility construction permits will also be neces sary for air emissions and water use incurred during construction. Also in cluded in this item is the develo pment of a corrosion control program for the well. Owners and operators are assumed to in cur this cost in Year 1 of the project, before well construction begins.

Owners and operators will need to install m onitoring 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 equipm ent 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 veri fy 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 monitori ng wells into the injection zone, the Agency assumes one monitoring well per four square mi les. EPA assumes monitoring wells into the injection zone will also be used to sample a bove the injection zone (see Exhibit 5.2 for the required number of wells in the pro forma of each project type for the sel ected alternative, RA3). As is the case with injection we lls, costs for monitoring wells are well established in the industry. Capital costs for monitoring wells will be incurre d in Year 1 of each pr oject, as the wells are being constructed.

Owners and operators will also need to build onsite pipelines to conduct the CO 2 

# from the distribution piping to the injecti on well. The basis for these cost s is well understood because they are used in the oil and gas indus try. It is estimated that the av erage saline formation GS project site will need to install 48 inch-miles of pipelin e, and the average oil a nd gas reservoir project will need to install 59 inch-miles of pipeline. CO 2 

# 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; th ey 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 un it costs are presented in Appendi x 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 Cost 1 Regulatory Alternative Project Cost Pilot Project - Saline Project Cost Large Project

- Saline P ro j ect C ost 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 tubin g . N / A

Cement well from surface through base of lowermost USDW and throu g hout in j ection zone. N/A Com p liance Activit y Conduct front-end engineering and design (general and injection wells), pre-op logging, sampling, and testing. Includes baseline p ressure 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 p a y ment to landowner. N/A N/A $20,700/inj ection well

Pum p s. N/A N/A N/A N/A

Standard injection well cost (from look u p 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 dischar g e p ermits.

$1.15/foot (length)- inch(diame

ter ) $103,400/s ite $20,700/sq

. mile N/A N/ A

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 in j ected/we $20,700/w

ell site $1,550/HP of p um p

N/

A

Wellhead and Control E q ui p ment. 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 RuleLabor Cost ($/hour) Labor Burden (hours) Labor Cost ($) Non-labor unit Cost 1 Regulatory Alternative Project Cost Pilot Project - Saline Project Cost Large Project

- Saline P ro j ect C ost 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 Ru le cost model, which are also presented in Appendix C of the Cost Analysis. Source: GS Cost Model Com p liance Activit y $83,000/in ch (diameter)

-

mile ( len g th ) All elements of p i p eline costs. N/A N/A N/ A

(E) As described in Section 5.2, application factors represent t he Agency's best estimate of the percentage of projects to whic h 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 operato rs under the injectio n well construction component for the baseline and RAs 1- 4 are presented in Exhibit 5.8.

Exhibit 5.8 Owner and Operator Cost Es timates 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 cost s for operating the inje ction and monitoring wells beginning in Year 2 of th e project and will continue to in cur these costs th roughout the life of the injection period. Throughout injection, owners and operators will need to monitor injection rates, pressures, and volumes to assu re that the well is ope rating within permitted parameters and does not fracture the injecti on zone. Other operating costs include regular maintenance of the well, electric costs for the pu mps, land leases, insurance, providing reports to regulators, and contributions to a long-term monitoring, insura nce, and remediation fund in proportion to the amount of CO 2 

# injected. EPA assumes that under RA1, RA2, and RA3, owners and operators would inject below the lowerm ost 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 al so install down-hole devices (automatic shut-offs, check valves, or other, the se lection of which is site specific and subject to the Director’s discretion) that allow the well to be shut-in or injecti on stopped if conditions become unsafe or well integrity fails. Down- hole devices are required for all offshore wells located in State Territorial waters. Most dow n-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 We ll 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 Cost 1 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. E q ui p ment 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

e q ui p ment.

N/A N/A $5.20/acre In j ection well O&M.

Pay rent for land use and rights-ofwa y

. $664 6 hours/ well

$0.03/$1 CAPEX

N/A $0.05/ton of CO2 in j ected N/A N/A $10,400/well

$0.066/KWh

N/A

N/A

$0.10/unit CO2 in j ected Develop a corrosion monitoring and p revention p ro g ram.

N/A N/A $15,500/well Corrosion monitoring: analysis of injectate stream and measurement of corrosion of well material cou p ons.

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/sam p le

$77,500/ injection well $3.10/foot (depth)/ in j ection 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 whic h 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 in j ected fluid.

Repair and replace wells and

e q ui p ment. Pro p ert y 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 ar e 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, fl ow rate, injected volumes, and pressure on the annulus between the tubing and the long string ca sing. GS owners and operators will need to install monitoring equipment on each well to mon itor these parameters. Costs for installing the monitoring equipment are accounted for under the injection well construc tion rule component, but because this equipment is used to monitor both well operation and integrity, equipment costs are accounted for under the monitoring ru le component (see Section 5.4.7).

Owners and operators will demonstrate external mech anical integrity at least once per year using a tracer survey of the bottom-hole cement (using a CO 2 

# -soluble tracer or a suitable alternative method (e.g., Oxygen Activation Log (OAL)), a temper ature or noise logs or other tests suitable to wells injecting liquid/super critical CO 2 

# fluids as approved by the permitting authority), or if required by the director a casi ng 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 begi nning 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 un it costs are presented in Appendi x 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 Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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 isoto p e. N/A

N/A N/A

Conduct p ressure fall-off test. N/A $2,070/ injection

well N/A

N/A N/A N/A $2,070/ injectionwel l $4/foot ( de p th ) N/A Internal Mechanical integrity p ressure test.

N/A N/A N/A N/A

Casin g ins p ection lo g

.

Conduct a tracer survey of the bottom-hole cement using a CO2-soluble isoto p e. N/A $2,070/ injection

well

N/A N/A N/A

N/A $2,070/ injection

well $4/foot ( de p th )

N/A $2,070/ injection

well $4/foot ( de p th ) N/A $5,200/ injection

well N/A

$5,200/ injection

well 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). 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 lo g at least annuall y

.

$2,070/ injection

well Conduct p ressure fall-off test.



# 5.4.6.1 Annualized Costs for M echanical 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% Disc ount 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 CO 2 

# remains safely sequestered in the injection zone and will not endanger USDWs, owners and operators will impl ement 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 ti me feedback for assessing parameters of the injection process, provide early warni ngs of failure, and verify that the CO 2 

# plume is behaving as expected.

Under the GS Rule, owners and operators must monitor the nature of the injectate and continuously monitor injection pr essure, 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 CO 2 

# plume and pressure front; this can be done by monitoring pr essure 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 CO 2 

# detection tools). Owners and operators must also conduct a pressure fall-off test at l east 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 operat ors to monitor ground water quality and geochemical changes above the confining zone us ing a network of monito ring wells and to track changes relative to baseline geoc hemical data. For oil and gas re servoirs, owners and operators will need to install U-tu be 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 monitori ng component. For the purposes of this analysis, monitoring equipment has been categorized into subsurf ace equipment (installed in wells) and surface equipment. Monitoring wells may have permanen tly installed down-hole equipment to measure pressure, temperature, resistivit y, salinity, pH, pressure, and temper ature. 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 CO 2 

# flux from the surface will require installation of monitoring equi pment. Surface or near-surface monitoring equipment installation costs (if this monitoring is required by the Directo r) will be incurred in Year 1 of each project.

Additionally, the GS Rule re quires that owners and opera tors update the AoR using computational (complex) modeling of the CO 2 

# fluid flow at minimum every 5 years. EPA also assumes that owners and opera tors under RA0-RA3 would deve lop a 100-year forecast and under the more stringent RA4 would develop a 1 0,000-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 un it 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 Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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 $ RA 4 10,400 $ 60,518 $ 90,776 $ 21,712 $ 32,568 $ N/A 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 p eriodic in situ sam p lin g usin g Check valve (Director discretion to require down-hole shut-off valve, but expected to be check valves in all but the most exce p tional cases )

. N/A

Standard monitoring well stopping above the confining zone (used look up table). Standard monitoring wells for ER p ro j ects sto p below the

S a li n it y, CO2

, t racer, e t c. monitoring equipment for wells drilling into the injection zone (portion of equipment may be at surface such as for periodic in situ sam p lin g usin g U-tubes; N/A N/A

Pressure, temperature, and resistivity gauges and related equipment for monitoring wells drilling into the injection zone ( a pp lication factor reflects Obtain rights-of-way for surface uses (monitoring sites )

. Obtain rights-of-way for surface uses (monitoring wells drillin g into in j ection zone ) . N/A N/A Develop geochemical baseline for injection zones and confining zone. Assumes 4

sam p les p er in j ection 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 monitorin g . N / A

Conduct front-end engineering and design for monitoring wells stopping above the confinin g 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 $200/sam p le N/A N/A

N/A $35,000/station

N/A N/A

N/A $5,000/ monitorin g well

$10,000/ monitorin g well

$100-$130/foot (depth) down to

9,000 feet $20,000/site

$5,000/ monitorin g well

$5,000/air monitoring station site

$15,000/site $2/foot ( de p th )

$10,000/ monitorin g well

$100-$130/foot (depth) down to

9,000 feet

$10,000/ monitorin g well

$10,000/ monitorin g well

$10,000/ monitorin g well

$10,000/ monitorin g well N/A Standard monitoring well drilled into the injection zone (used look up table; applies to RA3-4 onl y)

. Pressure, temperature, and resistivity gauges and related equipment for monitoring wells stopping above the injection

zone ( a pp lication 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 RuleCompliance Activity Labor Cost ($/hour) Labor Burden (hours) Labor Cost ($) Non-labor unit Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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/

sam p le

N/A $107.23

N/A 40

Monitoring well O&M for wells drillin g into the in j ection zone. Develop a monitoring and testing plan, an emergency response plan, a post-injection site care and site closure plan and im p lement monitorin g 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 in j ection zone. Conduct periodic monitoring of groundwater quality and g eochemistr y

.

Surface microseismic detection equipment: geophone arrays in monitoring wells.

Monitoring well O&M for wells stopping above the injection

zone. 0.5 hr/sam p le

N/A

N/A N/A $110.62

N/A $55.31/sampl

e

N/A $30,000/ monitoring well

$18/foot ( de p th )

N/A $80,000/site

$200/sam p le $4,289

$10,619.52/sa

m p le N/A

N/A N/A

55 N/A

40 N/A

Develop plan and implement soil zone monitorin g

. Develop plan and implement LIDAR airborne survey to detect surface leaks. Works best where vegetation is

s p arse. Costs are for p lannin g N/A N/A Develop plan and implement Eddy Covariance air monitorin g

. Develop plan and implement Digital Color Infrared Orthoimagery (CIR) or Hyperspectral Imaging to detect chan g es to ve g etation. ER only. U-tube for sensing oil movement away from bottom of formation. Applies to 1 of every 4 monitoring wells drilled into the in j ection zone.

$107.23 $107.23

$8,000/site

$25,000/ monitoring well $3/foot ( de p th )

$5,000/ site $6,250/ square mile $25,000/ monitoring well $3/foot ( de p th ) $10,000/square mile

$50,000/ monitorin g site

N/A Annual cost of air and soil

surve y s: Edd y 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 chan g es to ve g etation. $10,000/square mile $75,000/ monitorin g site

$107.23 40

N/A

$4,289

$5,898

N/A

$12,400/

sam p le

$10,000/ station N/A

$6,000/site $4,289



## Cost Analysis for the 5-24 November 2010 Final GS RuleCompliance Activity Labor Cost ($/hour) Labor Burden (hours) Labor Cost ($) Non-labor unit Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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 g atherin g activities. Annual reports to regulators and recordkeeping for all data g atherin g activities. 44 $110.62 180 hours/ project site +

70 or 90 hours/well N/A N/A

N/A Annual cost of passive seismic

e q ui p ment.

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 s p arse.

Annual cost of air and soil

surve y s: soil zone monitorin g

.

Annual cost of air and soil surveys: monitoring wells for g as sam p les from water table.

Periodic seismic surve y s: 3D. Annual cost of air and soil surveys: vadose zone monitoring wells to sample g as above water table. $5,000/ site $6,250/ square mile

N/A N/A N/A

$19,911.60 per project site + $9,956

p er well $300/sam p le

$1,200/sam p le

$10,500/ station $300/sam p le N/A N/A

N/A

$1,217 $104,000/

s q uare 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 whic h 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 recordkee p in g

. $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 fl uid 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 move ment of fluid that may endanger USDWs. EPA assumes that injection wells will be plugged 1 y ear after completion of the injection phase.

Following injection, owners and operators must perform PISC to show the position of the CO 2 

# plume and pressure front and ensure that they will no longer pose an endangerment to USDWs. Under RAs 0-2, PISC must be performe d for at least 10 years. For RA3 the default PISC period is 50 years; data submitted as pa rt 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 co st 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 su rveys, and air and soil tests, along with an updated demonstration of the financ ial 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 unt il the end of the post-injectio n 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 CO 2 

# 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 Di rector authorizes closur e of the site, closure activities would include pluggi ng 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 operato r 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 Cost 1 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 p lume has stabilized )

.

Post-injection air and soil

surve y s. Document plugging and closureprocess (well plugging, postinjection plans, notification of intent to close, and post closure

re p ort )

. Perform a mechanical integrity test prior to plugging to evaluate integrity of casing and cement to remain in g round. 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 ( in j ection wells )

.

Post-closure O&M for monitoring wells stopping above injection zone (continues until p lume has stabilized )

. Plug monitoring wells drillin g 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

( de p th ) N/A Flush wells with a buffer fluid before p lu gg in g

.

$10,400/ monitoring well $5,200/ monitoring

station

$110.62 Remove surface equipment and structures; restore vegetation (monitoring well stopping above in j ection zone )

.

N/A Remove surface equipment and structures; restore vegetation (monitoring wells drilling into in j ection zone )

. N/A

N/A $25,000/ monitoring well $3/foot (depth)/ monitorin g well

$25,900/ in j ection well N/A

N/A $25,900/ monitoring well

$3.10/foot (depth)/ monitorin g well N/A N/A

N/A $10,400/ monitorin g well N/A 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/ monitorin g well

$24,900/ in j ection well

$2,070/ injection well $4.15/foot

( de p th )

$12,400/ monitorin g well



## Cost Analysis for the 5-27 November 2010 Final GS RuleCompliance Activity Labor Cost ($/hour) Labor Burden (hours) Labor Cost ($) Non-labor unit Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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 $ 2,462,125 $ 1,243,304 $ 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 monitorin g re p orts to re g ulators. N/ A Post-in j ection seismic surve y

.

(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 $110.62 40 N/ A N/

A $104,000/

s q uare mile



# 5.4.8.1 Annualized Costs for Well Plu gging 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 opera tors have no requirement to demonstrate financial responsibility; under RA2 and the baseline (RA0) the owner and operator would provide financial assurance through a pe rformance bond, or other appropria te 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 demonstr ate 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 operato rs will post a performance bond and periodically re-evaluate the costs during the injection and PISC phases of the project. Financia l 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 prio r to deployment. All GS well owners and operators are required to demons trate 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

Cost 1 Regulatory Alternative Project Cost Pilot Project

-

Saline Project Cost Large Project - Saline P ro j ec t C os t 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 t he Agency's best estimate of the percentage of projects to whic h 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 enda ngerment of USDWs, the owner and operator will be required to cease inje ction, investigate and identify the release, and implement the emergency and remedial response plan. Some incidents could require replacement of well equipment, or remedi ation or removal of the CO 2 

# . A percentage of the capital costs for well operation for each project is as sumed 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 cost s 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, presente d in Section 5.4.5. In a ddition, emergency and remedial response plans must be re viewed at least every five year s, 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 descrip tion of the permitting authority’s oversight responsibilities for the GS Rule, organized by ru le 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 administra tive costs while implementing the GS Rule. These implementation costs are not directly requir ed 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 n eed 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 tr ack 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 wi ll also need to modify or develop data management systems. Finally, th e 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 perm itting authority will need to expend resources for ongoing administrative activities. On an annua l basis, the permitting authority will provide technical assistance to well owne rs 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 CO 2 

# , 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 a nd 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-sub mitted AoR modeling results and the status of corrective action in Year 1 and the AoR reeval uations and modified AoR and corrective action plans that owners and operators periodically subm it over the course of th e injection project.

5.4.11.4 Injection Well Construction

Permitting authority activities associated w ith 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 pr operly designed to with stand injection of large volumes of CO 2


# . As they review information on the geology of the site, the AoR, and construction procedures described above, the permitting author ity will also review the other components of the permit application, including proposed monitoring plans, c ontingency 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 lowe rmost USDW. In the case of Stat es with primacy, such waivers will be reviewed at both the State and Federal level.

This cost analysis assumes that the permitti ng authority will review permit applications and associated materials in Year 1 of the proj ect, 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 authoriti es may visit the project site and witness the MITs. (The burden associated with review ing MIT reports is captured under monitoring, below).

5.4.11.7 Monitoring

EPA assumes that the permitting authority wi ll incur burden associated with reviewing the annual, semi-annual, quarterly, or monthly monitoring reports submitted by well owners and operators, including inject ate monitoring results, plume track ing data, ground water monitoring, MIT results, or other testing pe rformed 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 report s beginning in Year 2 of each project.

5.4.11.8 Well Plugging and PISC

Permitting authority costs related to well plugg ing and PISC requirements include review and approval of the initial plans submitted with pe rmit 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 di scretion, 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 rela ted to review of post-injection monitoring reports. Permitting au thorities will also review non-endangerment demonstrations following post-injection monitoring; this analysis includes such costs only as incurred within the 50-y ear 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 fina ncial assurance demonstrations provided by GS well owners and operators with their pe rmit applications and any updated estimates submitted.

5.4.11.10 Emergency and Remedial Response Plans

The permitting authority will re view emergency and remedial response plans submitted by owners and operators along w ith other attachments to the permit application, which is included in the costs for reviewing permit applic ations. In addition, the permitting authority may need to respond to incidences where there is evidence of CO 2 

# 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 Bu rden 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 Cost 2
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 $ RA4 4 111 $ 88 $ 199 $ $49.44 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 RuleState Labor Cost ($/hour) Federal Labor Cost ($/hour) Regulatory Alternative One-time labor burden (hrs) State Cost Federal Cost Weighted Project Cost 2
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 $50.14 $49.44

$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 RuleState Labor Cost ($/hour) Federal Labor Cost ($/hour) Regulatory Alternative One-time labor burden (hrs) State Cost Federal Cost Weighted Project Cost 2
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 to gether. As described in Section 5.2, application factors rep resent 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 altern ative 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 headqua rters offices to review. (2) Weighted permitting authority cost based on assumption of 56% of states currently active in the UIC program obtaining prima cy 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

$50.14 $49.44



# Exhibit 5.20 Permitting Authority Cost Estimates – Annualized Values Using a 3% and 7% Discount Rate ($Millions, 2008$)

State Federal Total St ate 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 ope ration of GS wells under the GS Rule will be passed on, in whole or in part, to consum ers. However, the impact on any individual household is expected to be very minor. Quantif ication of exact househol d costs is not possible due to the representative nature of the costi ng estimates. The representative project estimates used in this cost analysis are not connected to specific industry prof iles that would include numbers and distributions of customers that co uld be used in househol d cost calculations. However, assumptions about the broader industry profile (i.e., types a nd characteristics of projects) can be used to qualitative ly evaluate costs. In particular, the 29 proj ects estimated to be subject to the requirements of the GS Rule as pa rt of this Cost Analysis are assumed to be sponsored by the energy sector. Because of th e current government focus on the energy sector, there are many factors that will work to mitig ate costs that are passed on to consumers.

As the major producers of CO 2 

# , it is expected that large energy producers such as coal fired power plants will sponsor th e majority of GS projects and th erefore incur most of the costs of sequestration. Because of thei r roles as energy suppliers, thes e 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 househol d cost increases. These potential increases may be further minimized depending on the regional or local regulatory stru ctures 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 a ddition, many of the projects esti mated 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., pric e limits or supports) will still be borne by consumers but most likely as part of a much la rger tax base, especially for national programs. Overall, these considerations imply that any hous ehold costs resulting from the GS Rule will be minimal.



# 5.6 Comparison of Annualized Incrementa l Costs for All Regula tory Alternatives Considered

Exhibit 5.21 below summarizes the incremen tal costs of the GS Rule for each RA considered during the rule development proces s. Estimates represent those costs that EPA expects owners and operators and permitting author ities to incur for the 29 estimated baseline projects during the 50-year period of analysis.

Relative to the baseline regulatory scenario 10 

# , Alternatives 1 through 4 have increasing incremental costs that range from $4.8 m illion to $48.1 million in annualized 2008$ (using a 3 percent discount rate). The in cremental cost for the GS Ru le (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 proj ect site geology and iden tification 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 th an those at 7%, and vi ce versa. EPA notes that when calculating annualized costs, there is an inflection point wher e 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 aver age of 5-10 years, while the annualization is applied over 25 ye ars. Whereas the values discount ed using a 3 percent discount rate are higher than the same cost stream di scounted using 7 percent, the annualization step moves the results in the other di rection, i.e., towards the condit ion 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 fa vor of a larger 3 percen t 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 s ubject 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 

### Discount Rate Regulatory 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 compone nt 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., afte r subtracting baseline costs) are associated with mon itoring. For RA 1 - 3, well operation is the second most significant incremental rule cost (for RA4, MIT is the second most significant increm ental rule costs at 3% discounting, and Geologic Site Ch aracterization at 7% discount rate). Monitoring represents a range from 44% to 77% of to tal 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 th e 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 mitiga tion of the risk to USDWs related to GS.

Exhibit 5.23 Total and Incremental Rule Costs by Regulatory Al ternative 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 p eriod 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 disc ount 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 quali fiers. 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 conditi ons with the overall conditions under each of the alternatives, or 2) comparisons of speci fic regulatory component s (i.e., geologic site characterization) that could be used to compare the baseline and all alternatives. Currently, the risk of contamination of USDW s from GS activities has not b een 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 cu rrent 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 addre ss the unique nature of injection of CO 2 

# for the purposes of GS. RA4 has more stringent standards and greater costs compared to the final Rule, but EPA believe s that RA4 requirements are beyond what is necessary to provide adequate risk reduction to USDWs. RA1 a nd RA2 provide lower costs than RA3 but at increased levels of risk to USDW s. Although RA4 has more stringent requirements, EPA does not believe that the in creased requirements and the incr eased costs are necessary to provide protection to USDWs. Therefore EPA be lieves that RA3 is the best alternative.



# 5.8 Other Economic Measures

The lack of a quantitative risk assessment prevents the us e of other economic measures, specifically, a break-even analysis and measures of cost effec tiveness 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 inst ance 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 wate r to usable quality or the cost of developing an alternative source of dr inking water in some cases. There is most likely a very low probability of such a failure being attri butable 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 resulti ng in activity that caus es contamination of a USDW.

## Cost Analysis for the 5-41 November 2010 Final GS Rule 

# Should the GS Rule somehow impede GS depl oyment, 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 w ith practicability and econom ic considerations and believes the probability of such impedance is ve ry 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. EP A 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 be lieves the GS Rule will not impede deployment of GS projects.

5.9.2 Uncertainties in Cost Estimates

As described in the Geologic CO 2 

# Sequestration Technology and Cost Analysis (EPA, 2010a) developed in support of this Cost Analys is, 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 estimat ed 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 Ch apter 3 of this Cost Analysis. If limits on emissions of greenhouse gases were imposed, GS would allow the Un ited States to continue to use fossil fuels to a larger extent than otherw ise 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 projec ts 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 Geol ogical Engineers (present ed in Section 5.2.1 of this Cost Analysis) were signifi cantly underestimated. If a rapid in crease in demand for this labor occurred under future climate change legisla tion and outpaced the deve lopment 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 uncer tainty in labor costs is not considered to contribute significantly to the uncerta inty in this cost analysis.

Third, EPA assumes that the number of monitori ng wells per project is correlated to the size of the site, which is the AoR. As shown in Exhibit 5.2, the representati ve 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 w ith 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, tw o that are drilled into the IZ and two above the IZ. In the limited ci rcumstances where injection depth waivers are approved, sites are assumed to have 50% more m onitoring wells than those estimated above. For the purpose of estimating national costs, how ever, EPA recognizes th at 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 signifi cant in the overall uncer tainty of the Cost Analysis.

Additional uncertainties correspond more dire ctly to specific assumptions made in constructing the cost model. If the assumptions for such items are incorrect, there may be significant cost implications outsi de of the general price level un certainties 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 fo r new projects from scratch, modeling costs may increase by four to five times.

• It is assumed that partially corrosion resist ant cement can be used for injection well construction. If GS well owners and opera tors have to utili ze corrosion resistant alloys, construction costs can increase significantly.

• Assumptions made for several cost components and subcomponents are based on industry averages. However, the actual cost s of several cost components such as finding wells in AoR, land use and rights, a nd remediation of failu res can vary widely based on site specific characte ristics. 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 CO 2 

# 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 conv entional drilling and completi on practices and geophysical techniques used in exploration and deve lopment for oil and gas. Some equipment costs, i.e., pipeline, are we ll known in the industry but vary based on market forces affecting supply and demand for materials and labor.

• Owners and operators would, if directed, de velop and implement a plan for surface air monitoring and/or soil gas moni toring to detect leakage of CO 2 

# to ensure that CO 2 

# and any other contaminants moving with the CO 2 

# 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 co sts 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 assumpti ons in the cost analysis. These analyses include:

1) Considering 5 and 54 projects as the lo wer and upper bound number of projects deployed;

2) An increase of 50% in indus try labor rates used; and

3) A 25% increase and decrease in m onitoring wells per project site.

To address the uncertainty inhere nt in projecting the GS baseli ne, sensitivity analyses that further explore the implications of alternativ e climate policy scenarios have been performed. These analyses are comparable to analyses perf ormed to support the Regulatory Impact Analysis for Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of CO 2 

# 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 high lighted in the presidential memorandum establishing the CCS Task Force a nd an EPA legislative analysis model of deployment under the American Power Act, respec tively. As shown in Exhibit 5.24a, assuming 5 pilot saline projects are implemented during the period of analysis result s in annualized RA 3 incremental rule costs that are approxim ately $2.3 million. And, as shown in Exhibit 5.24b, assuming 54 large saline projec ts are implemented during the pe riod of analysis results in annualized RA 3 incremental rule costs that ar e approximately $235 million. Consideration of an increase in projects based on climate change legi slation 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 anal ysis 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 cost s are embedded in project costs, this sensitivity analysis underestimates the extent of increase that a 50% labor incr ease would induce. The Geologic CO 2 

# 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 ow ners and operators under the GS Rule (RA3) will construct and operate a certain ratio of m onitoring wells per project site area depending on project type (see Exhibit 5.2 for th e 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 CO 2 

## 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 CO 2 

# and its plume. Because the actual number that will be necessary for a given project site is uncertain, EPA tested th e sensitivity of cost estimates to the number of monitoring wells by applying a 25 percent decrease and increase of monito ring wells per project site area to the original assumptions for each pr oject 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 re sults 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 form ation type and project scale. To be commensurate with the treatment (annualization) of costs, the injected volumes are disc ounted, 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 ex planation of the annualiz ation). The results indicate that the pilot-scale saline projects, which must adhere to the same level of pr otectiveness 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 CO 2 

# sequestered (147% more with 3% discounting and 77% more with 7% discounti ng) than large-scal e saline projects.

The results for each sensitivity analysis calc ulated 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,

$2008 1 

### Cost, 2008$ Increase or Decrease,

$2008 1 

### Cost, 2008$ Increase or Decrease,

$2008 1 

### Cost, 2008$ Increase or Decrease,

$2008 1



### 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 $ (7 8.5) 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,

$2008 1 

### Cost, 2008$ Increase or Decrease,

$2008 1 

### Cost, 2008$ Increase or Decrease,

$2008 1 

### Cost, 2008$ Increase or Decrease,

$2008 1



### 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 % Chan g e Capital Costs % Chan g e O&M Costs % Chan g e Total % Chan g e RA0 10.1 $ 2% 15.5 $ 0% 44.9$ 0% 70.6 $ 1% RA1 8.1 $ 2% 16.7 $ 0% 50.6$ 0% 75.4 $ 1% RA1 Incremental (2.1) $ 0% 1.2 $ 0% 5.6$ 1% 4.8 $ 1% RA2 11.5 $ 2% 17.5 $ 0% 56.2$ 1% 85.2 $ 1% RA2 Incremental 1.3 $ 1% 2.0 $ 0% 11.3 $ 1% 14.7 $ 1% RA3 16.9 $ 2% 21.5 $ 0% 70.8$ 1% 109.2 $ 1% RA3 Incremental 6.7 $ 1% 6.0 $ 0% 25.9 $ 2% 38.6 $ 2% RA4 19.9 $ 2% 20.9 $ 0% 78.6$ 1% 119.4 $ 1% RA4 Incremental 9.7 $ 2% 5.4 $ 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/De crease in Monitoring Wells - Annualized Values Using a 3% Discount Ra te ($Millions, 2008$)

One-Time

Costs % Change Capital Costs % Change O&M Costs % Change Total % Change

RA0 10.0 $ 0% 15.5 $ 0% 44.8$ 0% 70.2$ 0% RA3 16.6 $ 0% 21.5 $ 0% 70.2 $ 0% 108.3 $ 0% RA3 Incremental 6.6 $ 0% 6.0 $ 0% 25.4$ 0% 38.1$ 0% RA0 9.9 $ -1% 15.3 $ -1% 44.0 $ -2% 69.2 $ -2% RA3 16.3 $ -2% 20.1 $ -6% 65.8 $ -6% 102.2 $ -6% RA3 Incremental 6.4 $ -4% 4.8 $ -20% 21.8 $ -14% 33.0 $ -13% RA0 10.0 $ 1% 15.7 $ 1% 45.6$ 2% 71.3$ 2% RA3 16.9 $ 2% 22.9 $ 6% 74.6 $ 6% 114.4 $ 6% RA3 Incremental 6.9 $ 4% 7.2 $ 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 comparabi lity to annualized costs.

2 

### Injected volumes are discounted to the first year of the analysis and annualized over 25 years at 7% discounting for comparabi lity 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 ($MM) A nnualized Incremental Rule Cost Per Metric Tonne ($) 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, Unite d States Environmental Protection Agency (EPA) is required to address the direct and in direct burdens that the Federal Requirements under the Underground Injection Control (UIC) Program for Carbon Dioxide (CO 2 

# ) Geologic Sequestration (GS) Wells (GS Rule) may place on certain types of governments, business, and populations. This chapter presents the analys es performed by EPA in accordance with the following 12 Federal mandates:

1. Executive Order 12866: Regulator y 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 Fa irness Act (SBREFA) of 1996.

4. Unfunded Mandates Reform Act (UMRA) of 1995.

5. Executive Order 13132 (Federalism).

6. Executive Order 13175 (Consultation and Coordina tion with Indian Tribal Governments).

7. Executive Order 13045 (Protection of Children from Environmental Health Risks and Safety Risks).

8. Executive Order 13211 (Actions Concerning Re gulations 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 A ddress 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 object ives that the rule is intended to achieve (refer to Chapter 2 for more informati on regarding the objectives of the rule). Others are designed to assess the financial and health effects of the rule on ce rtain 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: Regu latory Planning and Review

Under Executive Order (EO) 12866 (58 FR 51735, October 4, 1993), this action is a "significant regulatory action” b ecause it is anticipated to raise novel legal and policy issues, as it is creating a new class of UIC wells to regulate CO 2 

# injection for a new purpose. Accordingly, EPA submitted this action to the Office of Mana gement 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 enfo rceable until OMB approves them.

The information collected as a result of th is 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 a llows 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 manda tory under the Safe Drinking Water Act (SDWA). (42 U.S.C. 300h et seq. ).

For the first three year s after publication of the final ru le in the Federal Register, the major information requirements apply to a to tal 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 (baselin e) 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 incremen tal 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 manda tory under SDWA (42 U.S.C. 3501 et seq. ). Details on the calculation of the rule information collection bu rden and costs can be found in the ICR (USEPA, 2010b) and Chapter 5 of this Cost Analysis. A summar y 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

A nnual 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, a nd 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 ar e listed in 40 CFR part 9. In addition, EPA is amending the table in 40 CFR part 9 of curre ntly approved OMB contro l numbers for various regulations to list the regulatory citations for th e 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 agen cy certifies that the rule will not have a significant economic impact on a substa ntial number of small entities. Small entities include small businesses, small organizati ons, 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) regula tions at 13 CFR 121.201; (2) a sm all governmental jurisdiction that is a government of a city, c ounty, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any "not-f or-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 generati on, transmission, and/or distributi on 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 NAIC S code 324110, as specified for government procurement purposes, a firm must have fe wer than 1,500 employees and less than 125,000 barrels per calendar day in tota l Operable Atmospheric Crude O il Distillation capacity. Capacity would include owned or leased facilities as well as facilities under a proc essing agreement or an arrangement such as an exchange agreem ent 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 woul d only be undertaken by a small entity if GS were in its interest compared to other alterna tives it may have. The purpose of the GS regulation is to ensure that, where deployed, GS is conduc ted 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 e xpected that small entities would not elect to sequester CO 2 

# via injection wells, and t hus the rule will not have any impact on them. In summary, EPA certifies that the GS Rule will no t 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 th e private sector in any one year. The total annual increm ental costs estimated for the imp lementation of this rule are well under $100 million, resulting in expenditure s for the entity groupings required under an UMRA analysis that also fall far below the $100 m illion 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 requi rements of section 203 of UMRA because it contains no regulatory requirements that might signi ficantly or uniquely affect small governments. Government responsibilities for ove rsight 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 implicat ions, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal gov ernment provides the funds necessary to pay the direct compliance costs incurred by State and loca l governments, or EPA consults with State and local officials early in the process of devel oping 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 c onsulted with representatives of State and local governments early in the process of devel oping the proposed action to permit them to have meaningful and timely input into its developm ent. Representatives included the National Governors’ Association, the Na tional Conference of State Legi slatures, 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, a nd 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, N ovember 9, 2000) EPA may not issue a regulation that has Tribal implications, that impos es substantial direct compliance costs, and that is not required by statute, unless the Federal gov ernment provides the funds necessary to pay the direct compliance costs incurred by Tribal governments, or EPA c onsults with Tribal officials early in the process of developi ng the proposed regulation and deve lops a tribal summary impact
statement.

EPA has concluded that this action may have tr ibal implications. However, it will neither impose substantial direct compliance costs on tribal governments, nor preempt Tribal law. Indian Tribes may voluntarily apply for primary enfo rcement responsibility to regulate the UIC Program in lands under their jurisdiction (See se ction 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 th erefore protects all populations from adverse health effects related to potential USDW contamination.

EPA consulted with tribal officials early in the process of developi ng 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 rule making. 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 C onsultation 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 re quire or provide incentive for firms to engage in GS, however, it does prot ect USDWs from potential negative impacts from GS of CO 2 

# should a firm decide to undertake such a pr oject. Health and risk assessments related to GS of CO 2 

# 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 sugg ested), 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 secti on II of the Preamble for more details on this research.



# 6.9 Executive Order 13211: Actions th at Significantly Affect Energy Supply, Distribution, or Use

This rule is not a “significant energy ac tion” as defined in EO 13211 (66 FR 28355, May 22, 2001), because it is not likely to have a signif icant adverse effect on the supply, distribution, or use of energy. In absence of climate change legislation, baseline assu mptions developed with the Department of Energy (DOE) for this rulema king indicate that only approximately 1% of the existing CO 2 

# emissions will be sequestered (approximately 1.0 billion metric tons) over the period of analysis. Furthermore, the higher degr ee of regulatory certain ty and clarity in the permitting process may, in fact, have a positive effect on the energy sector.

Specifically, if climate change legisl ation that imposes caps or taxes on CO 2 

# emissions is passed in the future, energy generation firms and other CO 2 

# producing industries will have an economic incentive to reduce emissions, and this rule will provide regu latory certainty in determining how to maximize operations (for ex ample, by increasing pr oduction 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 investme nt 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 regulat ed community; it is also intended to encourage innovation in analytical technol ogy and improved data quality. EPA is not precluding the use of any method, whether it constitute s a voluntary consensus standard or not, as long as it meets the performance criteria specified.



# 6.11 Executive Order 12898: Federal Actions to Addre ss Environmental Justice in Minority Populations an d Low-Income Populations

EO 12898 (59 FR 7629, Feb. 16, 1994) establishes Federal executive policy on environmental justice. Its main provision dir ects 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, disp roportionately high and adverse human health or environmental effects of their programs, policie s, 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 mi nority or low-income populations because it increases the level of environmental protection for all affected populations.

Existing electric power generati on plants that burn fossil fuel s 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 Stor age (CCS) will be built. EPA is developing guidance for UI C Directors that places emphasi s on considering the potential impact of any GS permits on communities (suc h as minority and low income populations) when evaluating Class VI injection well permit applica tions, as well as provide s suggestions and tools for targeted outreach to ensure more meaningful public input and partic ipation from the most affected communities during the permit evaluation and approval process.

This rule does not require that GS be undert aken; but does require that if it is undertaken, owners and operators will conduc t the activity in such a way as to protect USDWs from endangerment caused by CO 2 

# . Additionally, this rule will ensure that all areas of the United States are subject to the same minimum Federa l 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 Ge ologic Sequestration of Carbon Dioxide (USEPA, 2010c).

## Cost Analysis for the 7-1 November 2010 Final GS Rule 

# 7. References

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## Cost Analysis for the 7-2 November 2010 Final GS Rule 

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