March 2010

Economic Impact Analysis for the

Mandatory Reporting of

Greenhouse Gas Emissions

Subpart RR: Proposed Carbon

Dioxide Injection and Geologic

Sequestration Reporting Rule

Draft Report
CONTENTS

Section 1 Introduction and Background ................................................................................ 1-1

1.1 Mandatory Reporting Rule Background.............................................................. 1-1

1.2 Supplemental Proposal of Subpart RR: Geologic Sequestration......................... 1-2

1.3 Subpart RR Context............................................................................................. 1-5

Section 2 Regulatory Background ......................................................................................... 2-1

2.1 EPA’s Overall Rulemaking Approach................................................................. 2-1

2.2 Safe Water Drinking Act and UIC Regulations................................................... 2-2

2.3 Other Federal, State, and Agency Programs........................................................ 2-4

Section 3 Development of Subpart RR.................................................................................. 3-1

3.1 Rule Dimensions for Which Options Were Identified......................................... 3-1

3.2 Definition of Affected Entities............................................................................. 3-2

3.3 Selection of Reporting Threshold ........................................................................ 3-4

3.4 Selection of Data to Be Reported......................................................................... 3-6

3.5 Selection of proposed monitoring, reporting, and verification (MRV) plan

requirements and approval process.................................................................... 3-11

3.5.1 Selection of MRV Plan Option.............................................................. 3-11

3.5.2 Background on MRV Approaches......................................................... 3-13

3.6 Selected Option.................................................................................................. 3-14

3.7 Alternative Scenarios Evaluated........................................................................ 3-15

3.8 Data Quality....................................................................................................... 3-15

Section 4 Engineering Cost Analysis................................................................................... 4-17

4.1 Introduction........................................................................................................ 4-17

4.2 Overview of Cost Analysis................................................................................ 4-17

4.3 Baseline Reporting............................................................................................. 4-17

4.3.1 Introduction............................................................................................ 4-17
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4.3.2 Data Sources .......................................................................................... 4-19

4.3.3 Published Data on CO2 Sequestration Projects...................................... 4-19

4.3.4 Hydrogeologic Settings.......................................................................... 4-21

4.3.5 Formation Capacity................................................................................ 4-25

4.3.6 Geologic Sequestration Rule Activity Baseline..................................... 4-27

4.4 Reporting Costs.................................................................................................. 4-33

4.4.1 Introduction............................................................................................ 4-33

4.4.2 Cost Assumptions and Methodology..................................................... 4-33

4.4.3 Monitoring, Reporting, and Verification (MRV) Plan

Requirements and Approval Process..................................................... 4-35

4.5 Monitoring Technologies................................................................................... 4-38

4.5.1 Cost Scenarios........................................................................................ 4-43

4.6 Projecting and Discounting National Costs....................................................... 4-46

4.7 Other Recordkeeping and Reporting Costs........................................................ 4-50

4.8 Public Sector Burden ......................................................................................... 4-50

Section 5 Economic impact analysis.................................................................................... 5-51

5.1 Threshold Analysis ............................................................................................ 5-51

5.2 National Cost Estimates..................................................................................... 5-53

5.2.1 National Cost Estimates Under Alternative GS Facilities (ER opt

in) Outcomes.......................................................................................... 5-54

5.2.2 National Cost Estimates Under Alternative GS Facilities

(Commercial Saline) Outcomes............................................................. 5-55

5.3 Economic Impact Analysis................................................................................ 5-55

5.3.1 Revenue Estimate for a Representative Commercial ER Operation ..... 5-55

5.3.2 Sales Test Results .................................................................................. 5-56

5.4 Assessing Economic Impacts on Small Entities................................................ 5-56

5.4.1 Identify Affected Sectors and Entities................................................... 5-56

5.4.2 Develop Small Entity Economic Impact Measures............................... 5-57

5.4.3 Results of Screening Analysis ............................................................... 5-57

5.5 Characterization of Benefits of Subpart RR of the Mandatory Reporting

Rule.................................................................................................................... 5-58
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Section 6 Statutory and Executive Order Reviews.............................................................. 6-60

6.1 Executive Order 12866: Regulatory Planning and Review............................... 6-60

6.2 Paperwork Reduction Act.................................................................................. 6-60

6.3 Regulatory Flexibility Act ................................................................................. 6-62

6.3.1 Identify Affected Sectors and Entities................................................... 6-62

6.3.2 Develop Small Entity Economic Impact Measures............................... 6-63

6.3.3 Results of Screening Analysis ............................................................... 6-63

6.4 Unfunded Mandates Reform Act....................................................................... 6-64

6.5 Executive Order 13132: Federalism .................................................................. 6-64

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal

Governments...................................................................................................... 6-65

6.7 Executive Order 13045: Protection of Children from Environmental

Health and Safety Risks..................................................................................... 6-65

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

Distribution, or Use ........................................................................................... 6-66

6.9 National Technology Transfer Advancement Act ............................................. 6-66

6.10 Executive Order 12898: Federal Actions to Address Environmental Justice

in Minority Populations and Low-Income Populations..................................... 6-67

Section 7 Conclusions............................................................................................................ 7-1

7.1 Summary of Selected Regulatory Alternative ..................................................... 7-1

7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program......... 7-2

7.2.1 Alternative Scenarios Considered............................................................ 7-2

Section 8 References.............................................................................................................. 8-1
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LIST OF TABLES

Table 4-1. Comparison of ICF Assessment of U.S. Sequestration Potential with Published

Estimates................................................................................................................. 4-26

Table 4-2. Summary of ICF Sequestration Capacity Assessment ............................................. 4-27

Table 4-3. Pro-forma Project Characteristics (ER Scenario: No Additional ER opt In ).......... 4-29

Table 4-4. Pro-forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In) 4-30

Table 4-5. Pro-forma Project Characteristics (ER Scenario: Anthropogenic plus One-half Other

ER Opt In)............................................................................................................... 4-31

Table 4-6. Major Sources of Geologic Sequestration Cost Information ................................... 4-35

Table 4-7. Unit Cost of Relevant Continuous and Periodic Monitoring Technologies............ 4-36

Table 4-8. Unit Cost of Relevant Episodic Monitoring Technologies (That may be employed

after a subsurface leak is detected)......................................................................... 4-38

Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative ............. 4-44

Table 4-10. Summary of Cost Impacts: Activity Baseline with No Additional ER Opt In...... 4-47

Table 4-11. Summary of Cost Impacts: Activity Baseline from only Anthropogenic

ER Opt In.............................................................................................................. 4-48

Table 4-12. Summary of Cost Impacts: Activity Baseline from Anthropogenic CO2 plus Onehalf of Other ER Opt In ..........................................................................................4-49

Table 5-1 CO2 Injection Facilities: Effect of Injection Threshold on Reported Amount of CO2

Injected and Number of Facilities Required to Report........................................... 5-52

Table 5-2. National Annualized Mandatory Reporting Costs Estimates: Subpart RR............ 5-53

Table 5-3. Annualized Mandatory Reporting Costs per Project (2008$): Subpart RR ............ 5-53

Table 5-4. National Annualized Mandatory Reporting Costs Estimates (2008): All

Anthropogenic CO2 Projects................................................................................... 5-54

Table 5-5. National Annualized Mandatory Reporting Costs Estimates (2008$): All

Anthropogenic 50 Percent of Other CO2 Projects.................................................. 5-54

Table 5-6. Estimated Annual Revenue for a Representative Commercial ER Field Operation

(2008)......................................................................................................................5-55

Table 5-7. Sales Tests for Representative Commercial ER Field Operations..........................5-56
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SECTION 1

INTRODUCTION AND BACKGROUND

1.1 Mandatory Reporting Rule Background

On December 26, 2007, President Bush signed the fiscal year Consolidated

Appropriations Act authorizing funding for EPA to issue a rule requiring the mandatory

reporting of greenhouse gas (GHG) emissions (Consolidated Appropriations Act, 2008, Pub. L.

No.110-161, 121 Stat 1844, 2128 (2008)). An accompanying joint explanatory statement

directed EPA to "use its existing authority under the Clean Air Act" to develop a mandatory

GHG reporting rule.

The Proposed Mandatory Reporting of Greenhouse Gases Rule was signed on March 10,

2009, by Administrator Lisa Jackson; and EPA published a proposed rule requiring mandatory

reporting of GHG emissions in April 2009. 74 FR 16448 (April 10, 2009). After a 60 day

comment period, two public hearings, and meeting with over 4,000 additional people in over 150

groups via Webinars, conferences, individual meetings, and other forms of outreach EPA issued

a final rule on October 30, 2009. 74 FR 56260. The Mandatory Reporting of Greenhouse Gases

Rule requires reporting of GHGs and supply from all sectors of the economy, including fossil

fuel suppliers, industrial gas suppliers, and direct emitters of GHGs. The rule does not require the

control of greenhouse gases; rather the rule requires specific source categories that are above

certain threshold levels to monitor and report those emissions.

The final Mandatory Reporting of Greenhouse Gases Rule covers the major GHGs that

are directly emitted by anthropogenic activities. These include carbon dioxide (CO2), methane

(CH4), nitrous oxide (N2O), hydroflourocarbons (HFCs), perfluorocarbons (PFCs), sulfur

hexafluoride (SF6), and other specified fluorinated compounds (e.g., hydroflouroethers (HFEs))

used in boutique applications such as electronics and anesthetics. 1

The final rule contains 31 subparts, each requiring reporting from a defined source

category. In order to meet the reporting time, quality assurance, and verification requirements of

the rule, EPA is establishing a facility-to-EPA electronic reporting system to facilitate collection

of data under this rule. All facilities that are covered under this rule as reporters will use this

data system to submit required data.

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These gases influence the climate system by trapping in the atmosphere heat that would otherwise escape to space.

Additional information about GHGs, climate change, and climate science, and other related issues, can be found

at EPA’s climate change web site at http://www.epa.gov/climatechange/.
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1.2 Supplemental Proposal of Subpart RR: CO2 Injection and Geologic Sequestration

Today, EPA is proposing to amend the Mandatory Reporting of Greenhouse Gases

Program at 40 CFR part 98 to add reporting requirements covering facilities that conduct

injection and geologic sequestration (GS) of CO2.

EPA is proposing a tiered approach for reporting requirements under this subpart. The

first tier of proposed regulations would establish a set of reporting requirements that would cover

all facilities that inject CO2 underground. All facilities would be required to report the amount of

CO2 transferred onsite from offsite sources, the source of the CO2 (if known), and the amount of

CO2 injected underground.

The second tier of reporting requirements would apply to GS facilities. GS facilities

would be required to calculate the amount of CO2 sequestered by subtracting total CO2 emissions

from the quantity of CO2 injected in the reporting year. The emitted quantity would include the

amount of the injected CO2 that leaked from the subsurface to the surface (if any), CO2 produced

with oil or natural gas where ER operations are conducted at the GS facility, and fugitive or

vented CO2 emissions from surface equipment.

EPA considered several options for monitoring, reporting and verification (MRV) of

potential CO2 leakage2 at GS sites: do not require a MRV plan, require a universal MRV plan

that applies to all GS sites, or require a site-specific MRV plan. EPA is proposing to require

monitoring according to a site-specific MRV plan, but is seeking comment on all of the options

considered. While the risk of leakage at a well-selected and well-managed GS site is expected to

be low, the Agency considers it important for all facilities conducting GS to demonstrate that

they have met MRV standards.

Data on CO2 injection and GS are critical to informing Clean Air Act (CAA) GHG

policies. This data would provide information and transparency on the amount of CO2 injected

and geologically sequestered in the United States and, in combination with other subparts of the

MRR, would enable EPA to track the flow of CO2 across a CCS system. In addition, this

information would enable EPA to monitor the growth and efficacy of GS (and therefore CCS) as

a GHG mitigation technology over time and to evaluate relevant policy options. For example,

EPA would be able to track whether incentives or regulations are needed to encourage faster or

further GS project development. EPA would also be able to track whether ER sites are

transitioning to GS and consider whether incentives or regulations are needed. Where ER

2

 Leakage in this proposed rule is defined as the movement of CO2 from the injection zone to the surface (for

example to the atmosphere, indoor air, oceans or surface water).
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facilities are reporting GS, EPA would be able to evaluate ER as a potentially non-emissive end

use. In combination with other subparts of the MRR, EPA would be able to reconcile this data

with CO2 supplied (subpart PP) in order to better understand the quantity of CO2 supplied to

emissive and non-emissive end uses.

In developing this proposal, EPA considered overlap between this program and other

programs. In July 2008, EPA proposed to amend its UIC program to establish a new class of

injection well for GS projects (73 FR 43492 (July 25, 2008)). Today’s proposal provides a

pathway for CO2 injection facilities to report to EPA as GS facilities under the CAA, regardless

of their UIC permit classification. Under this proposal, any facility sequestering CO2

underground can choose to report as a GS facility for purposes of this proposed rule.

Since subpart RR is an amendment to the MRR, the general provisions of that rule (40

CFR part 98, subpart A) apply to today’s rule unless a provision is superseded by this subpart

that applies uniquely to facilities that inject CO2 or that conduct GS. The general provisions

address the following topics: the purpose and scope (40 CFR 98.1); who must report (40 CFR

98.2); the general monitoring, reporting, recordkeeping and verification requirement (40 CFR

98.3); the authorization and responsibilities of the designated authority (40 CFR 98.4); how a

report is submitted (40 CFR 98.5); definitions (40 CFR 98.6); the standardized methods

incorporated by reference (40 CFR 98.7); the compliance and enforcement provisions (40 CFR

98.8); and the mailing addresses (40 CFR 98.9).

In a separate rulemaking package that should shortly follow this proposal, EPA will be

issuing minor harmonizing changes to the general provisions for the MRR (40 CFR part 98,

subpart A) to accommodate the addition of the proposed CO2 injection and geologic

sequestration subpart. The changes affect paragraphs on rule applicability, schedule, definitions,

and incorporation by reference.

In particular, EPA is proposing to revise 40 CFR 98.2(a) to add CO2 injection and

geologic sequestration facilities to the list of source categories that must report starting with

calendar year 2011. EPA also is proposing to restructure 40 CFR 98.2(a) to move the lists of

source categories from the text into tables. The table format improves clarity and facilitates the

addition of source categories that were not included in calendar year 2010 reporting and begin

reporting in future years. Because all CO2 injection and geologic sequestration facilities (as

defined in proposed 40 CFR part 98, subpart RR) would be subject to the proposed rule, this

source category would be added to the table of “all-in” source categories referenced from 40

CFR 98.2(a)(1). The introductory text of 40 CFR 98.2(a)(1) and a few other sentences
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throughout 40 CFR part 98, subpart A that reference “subparts C through JJ” would be reworded

to accommodate proposed new subparts such as RR that are outside of this range of letters.

These rewordings either refer to the source category tables or otherwise correct the range of

subparts referenced, as appropriate. In addition, EPA is proposing to amend 40 CFR 98.2 (1) to

accommodate a mechanism that would allow CO2 injection and GS facilities to cease reporting.

EPA is proposing to amend 40 CFR 98.2(a) so that the MRR applies to facilities located

on or under the Outer Continental Shelf. These revisions are necessary to ensure that any CO2

injection or GS facilities located on or under the Outer Continental Shelf of the United States

would be required to report under this rule. In addition, EPA is proposing revisions to the

definition of United States to clarify that the United States includes the territorial seas. Other

facilities located offshore of the United States covered by the MRR program at 40 CFR part 98

would also be affected by this change in the definition of United States. For example, EPA is

intending to revise the MRR requirements to add a new subpart, subpart W, to address petroleum

and natural gas systems. Finally, in addition to the change to the definition of United States,

EPA is adding a definition of “Outer Continental Shelf.” This definition is drawn from the

definition in the U.S. Code. Together, these changes make clear that the MRR applies to

facilities on land, in the territorial seas, or on or under the Outer Continental Shelf, of the United

States, and that otherwise meet the applicability criteria of the rule.

EPA is proposing to revise 40 CFR 98.3(b), which establishes the schedule for annual

reporting. The text in 40 CFR 98.3(b)(1) and (b)(2) indicate that existing facilities subject to the

rule must submit an annual GHG report for calendar year 2010. When proposed subpart RR is

added, facilities will become subject to the reporting rule due to CO2 injection or geologic

sequestration, and their first annual GHG report would cover calendar year 2011 rather than

2010. Therefore, EPA is proposing to modify the text of 40 CFR 98.3(b) to allow reporting to

start in different years, as appropriate. EPA also is proposing to remove and reserve 40 CFR

98.3(b)(1). It would no longer be accurate, and it would not be needed because 40 CFR 98.2(a)

would indicate the first reporting year for source categories added to the rule and the requirement

for facilities to report in each subsequent year is already contained in 40 CFR 98.2(i).

EPA is proposing to amend 40 CFR 98.6 to add definitions for terms used in the

proposed subpart. EPA also is proposing to amend 40 CFR 98.7 (incorporation by reference) to

include standard methods used in proposed subpart RR.
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1.3 Subpart RR Context

Subpart PP requires the reporting of CO2 supplied to the economy. Subpart PP applies to

all facilities with CO2 production wells, facilities with production process units that capture and

supply CO2 for commercial applications or that capture and maintain custody of a CO2 stream to

sequester or otherwise inject it underground, and to importers and exporters of bulk CO2. During

the public comment period on the rule, EPA received many comments on subpart PP that CO2

injected underground should be considered when estimating emissions from the CO2 supply

industry.

Some commenters specified that some of the CO2 supplied for the purposes of enhanced

oil and gas recovery (ER) is additionally sequestered rather than emitted and characterized ER

operations as “closed systems” rather than emissive. Other commenters stated that including

reporting requirements for geologically sequestered CO2 would fill a critical gap in the reporting

system. EPA agrees that ER is a potentially non-emissive end use and that GS data reporting

from ER sites can assist EPA in quantifying the amount of CO2 that is permanently and securely

geologically sequestered. In addition, EPA agrees that GS reporting requirements would provide

information and transparency on the amount of CO2 injected and geologically sequestered in the

United States.

 Although CCS is occurring now on a relatively small scale, it could play a larger role in

mitigating GHG emissions from a wide variety of stationary sources. According to the Inventory

of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007, stationary sources contributed 67

percent of the total CO2 emissions from fossil fuel combustion in 2007.3 These sources represent

a wide variety of sectors amenable to CO2 capture: electric power plants (existing and new),

natural gas processing facilities, petroleum refineries, iron & steel foundries, ethylene plants,

hydrogen production facilities, ammonia refineries, ethanol production facilities, ethylene oxide

plants, and cement kilns. Furthermore, 95 percent of the 500 largest stationary sources are

within 50 miles of a candidate CO2 reservoir4. Estimated GS capacity in the United States is

over 3,500 Gigatons CO2 (GtCO2) (13,000 Gigatons CO2 at the high end),5 although the actual

capacity may be lower once site-specific technical and economic considerations are addressed.

3 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007, Draft Report, EPA 430-R-09-

004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html.

4 Dooley, JJ, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH Kim, EL Malone. 2006. "Carbon Dioxide

Capture and Geologic Storage: A Key Component of a Global Energy Technology Strategy to Address Climate

Change." Joint Global Change Research Institute, Battelle Pacific Northwest Division. PNWD-3602.

5

 DOE. 2008. Carbon Sequestration Atlas of the United States and Canada (Atlas II). Available at:

http://www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasII/.
1-6

Even if only a fraction of that geologic capacity is used, CCS is poised to play a sizeable role in

mitigating U.S. GHG emissions.

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

commercially available today and will be more widely demonstrated over the next 10 to 15

years.6 The oil and natural gas industry in the United States has over 35 years of experience in

transporting and injecting CO2 into the deep subsurface for the purposes of enhancing oil and

natural gas production. This experience provides a strong foundation for the injection and

monitoring technologies that will be needed for commercial-scale CCS. U.S. experience with

ER combined with the experience of four end-to-end commercial CCS projects7 and ongoing

research, demonstration, and deployment programs throughout the world, are building

confidence that transportation and sequestration of large volumes of CO2 can be achieved.

6 Dooley, JJ, CL Davidson, RT Dahowski. 2009. "An Assessment of the Commercial Availability of Carbon

Dioxide Capture and Storage Technologies as of June 2009." Joint Global Change Research Institute. Pacific

Northwest National Laboratory. PNNL-18520.

7

 These projects are: Sleipner (Norwegian North Sea)- 1 Mt CO2/yr injected since 1996; Weyburn (Canada)- 1 Mt

CO2/yr injected since 2000; In Salah (Algeria)- 1.2 Mt CO2/yr injected since 2004; and Snohvite (Norwegian

Barents Sea)- 0.7 Mt CO2/yr injected since 2008.
2-1

SECTION 2

REGULATORY BACKGROUND

The intent of the MRR is to collect accurate and timely GHG data that can be used to

inform future policies. Although the mandatory GHG rule is unique, EPA carefully considered

other federal and state programs during development of the rule. The reporting program will

supplement rather than duplicate other U.S. government GHG programs. We outline EPA’s

overall rulemaking approach, sources considered, and summarize our review of GHG monitoring

protocols for each source category used by federal, state, regional, and international voluntary

and mandatory GHG programs, and our review of state mandatory GHG rules below. The

remainder of the section provides an overview of related existing programs and discusses their

relevance in the development of Subpart RR.

2.1 EPA’s Overall Rulemaking Approach

The mandatory reporting program will provide comprehensive and accurate data which

will inform future climate change policies. Potential future climate policies include research and

development initiatives, economic incentives, new or expanded voluntary programs, adaptation

strategies, emission standards, a carbon tax, or a cap-and-trade program. Because we do not

know at this time the specific policies that will be adopted, the data reported through the

mandatory reporting system should be of sufficient quality to support a range of approaches.

Also, consistent with the Appropriations Amendment, the reporting rule covers a broad range of

sectors of the economy.

To these ends, we identified the following goals of the mandatory reporting system:

 Obtain data that is of sufficient quality that it can be used to support a range of future

climate change policies and regulations.

 Balance the rule coverage to maximize the amount of emissions reported while

excluding small emitters.

 Create reporting requirements that are consistent with existing GHG reporting

programs by using existing GHG emission estimation and reporting methodologies to

reduce reporting burden, where feasible.
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This section presents the current regulatory context for Subpart RR and illustrates the

anticipated role of the current proposal within the framework of the existing

mandatory and voluntary programs.

2.2 Statutory Authority

EPA is proposing this rule under the existing authority provided in CAA section 114. As

noted in the Mandatory Reporting of GHG Rule, CAA section 114 provides EPA with broad

authority to require information mandated by this rule because such data will inform and are

relevant to EPA’s carrying out a wide variety of CAA provisions (74 FR at 66264). Under CAA

section 114(a)(1), the Administrator may require emissions sources, persons subject to the CAA,

or persons whom the Administrator believes may have necessary information to monitor and

report emissions and provide such other information as the Administrator requests for the

purposes of carrying out the provisions in the CAA (except for a provision of title II with respect

to motor vehicles).

As discussed in greater detail in the response to comments for the final Mandatory

Reporting of GHG Rule, the CAA provides EPA with broad authority to require the

comprehensive and accurate information mandated in this rule because such data will inform,

and are relevant to, EPA’s analyses of various CAA provisions.

The information from CO2 injection and GS facilities will allow EPA to make wellinformed decisions about whether and how to use the CAA to regulate these facilities and

encourage voluntary reductions.

2.2 Safe Water Drinking Act and UIC Regulations

EPA’s UIC program was established in the 1970s to prevent endangerment of

underground sources of drinking water (USDWs) from injection of various fluids, including CO2

for ER, oil field fluids, water stored for drinking water supplies, and municipal and industrial

waste. The UIC program, which is authorized by Part C of the Safe Drinking Water Act

(SDWA) (42 U.S.C. 300h et seq.), is designed to prevent the movement of such fluid into

USDWs by addressing the potential pathways through which injected fluids can migrate and

potentially endanger USDWs.

When EPA initially promulgated its UIC program regulations, the Agency defined five

classes of injection wells at 40 CFR 144.6, based on similarities in the fluids injected,

construction, injection depth, design, and operating techniques. Wells injecting industrial non-
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hazardous liquids, municipal wastewaters or hazardous wastes beneath the lowermost USDW are

categorized as Class I. Those injecting fluids in connection with conventional oil or natural gas

production, enhanced oil and gas production, and the storage of hydrocarbons which are liquid at

standard temperature and pressure are categorized as Class II. Class III wells inject fluids

associated with the extraction of minerals, and those categorized as Class IV inject hazardous or

radioactive wastes into or above USDWs. Class IV injection wells are banned unless authorized

under an approved Federal or State ground water remediation project. Class V includes all

injection wells that are not included in Classes I–IV. This well class provides for Class V

experimental technology wells including those permitted as GS pilot projects.8

In 2008, EPA proposed to amend the UIC program to establish a new class of injection

well — Class VI — to cover the underground injection of CO2 for the purpose of GS, or longterm storage of CO2 (73 FR 43492 (July 25, 2008)). The proposed requirements would tailor

existing components of the UIC program to address the unique nature of GS projects so as to

ensure that the injection of large volumes of CO2 in a variety of geologic formations for the

purposes of long term storage would not endanger USDWs. The UIC Class VI proposal does not

require any facilities to capture and/or sequester CO2; rather the proposed requirements, if

finalized, would protect USDWs under the SDWA. The SDWA does not provide authority to

develop regulations for all areas related to GS such as capture or transport. As outlined in the

UIC Class VI proposal, injection wells used for injecting CO2 for the purposes of ER would

continue to be regulated and permitted as Class II as long as any production is occurring.

Facilities regulated under the UIC program are required to collect and report data, with

minimum requirements for the collection and reporting of data established at the federal level.

Where states are given primacy over the UIC program, the data collected under the UIC program

varies. Data currently collected under a state-issued UIC permit is submitted to states while,

under today’s subpart RR proposal, reporters will be submitting data directly to EPA. The

Agency believes that state, local, and tribal input is valuable in ensuring that the subpart RR

reporting requirements appropriately build on the UIC program requirements.

 Today’s proposal builds on the UIC program requirements for monitoring with the

additional goals of verifying the amount of CO2 sequestered and collecting data on CO2 surface

emissions from GS facilities. EPA is proposing that a facility’s UIC permit may be used to

demonstrate that certain MRV plan requirements have been fulfilled.

8

 See EPA UIC Guidance #83. Available at: http://www.epa.gov/safewater/uic/wells_sequestration.html
2-4

In the Agency’s August 2009 Notice of Data Availability supplementing the UIC Class

VI proposal, EPA noted that it was evaluating the need for a more comprehensive regulatory

framework for GS. The Agency acknowledges that regulatory clarity is essential for enabling

GS to move forward in a manner that protects human health and the environment. EPA is

coordinating GS requirements across relevant statutory or other programs in order to minimize

redundancy and increase clarity for stakeholders.

The proposed UIC Class VI rule is a separate rulemaking action; the comment period for

that rulemaking closed on December 24, 2008. EPA will not be accepting or responding to

comments on the proposed UIC Class VI rule through today's proposal unless related to a

specific issue raised by this action.

2.3 Other Federal, State, and Agency Programs

The Department of Energy (DOE) Energy Information Administration implements a

voluntary GHG reporting program under section 1605(b) of the Energy Policy Act of 1992,

which directed DOE to issue guidelines establishing a voluntary greenhouse gas reporting

program (42 U.S.C. 13385(b)). Under the Energy Information Administration’s “1605(b)

program,” reporters can choose to prepare an entity-wide GHG inventory and identify specific

GHG reductions made by the entity.9 Reporting tools were revised and published in 2009 to

assist entities in preparing a preliminary estimate of emissions. The 2007 updated 1605(b)

guidance outlines a voluntary process to report data on CO2 sequestration. Currently, no CO2

injection or sequestration entity has reported under the 1605(b) program per the 2007 guidelines.

According to the Energy Information Administration website, the first reporting cycle under the

revised Voluntary Reporting of Greenhouse Gases Program has not been completed as of

January 15, 2010. The Energy Information Administration anticipates issuing an annual report

and public use database for data reported through 2008 by early 2010.10 The 1605(b) guidance

requires the implementation of a site-specific monitoring plan, but this plan is not evaluated by

DOE to determine whether the plan will provide for appropriate monitoring. Four prescriptive

monitoring scenarios are offered with grades ranging from “A” to “C”, any of which would be

acceptable for compliance with the 1605(b) program. Furthermore, although the 1605(b)

guidance cites the importance of reporting CO2 leakage should it occur, the guidance does not

include a discussion of, procedures for, or methodologies for using monitoring technologies and

9

 Under the 1605(b) program an “entity” is defined as “the whole or part of any business, institution, organization or

household that is recognized as an entity under any U.S. Federal, State or local law that applies to it; is located, at

least in part, in the U.S.; and whose operations affect U.S. greenhouse gas emissions.”

(http://www.pi.energy.gov/enhancingGHGregistry/)

10 http://www.eia.doe.gov/oiaf/1605/data_reports.html
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techniques to quantify the leakage. As a result of this, and the fact that reporting is voluntary,

the 1605(b) program would not meet the data needs of this proposed rule.

The Internal Revenue Service (IRS) made public IRS Notice 2009-83 Credit for Carbon

Dioxide Sequestration under section 45Q on its Web site on October 8, 2009.11 The notice

provides procedures for the allocation of credits for CO2 sequestration under section 45Q of the

Internal Revenue Code. Section 45Q was enacted by section 115 of the Energy Improvement

and Extension Act of 2008, (October 3, 2008) and was amended by section 1131 of the

American Recovery and Reinvestment Act of 2009 (February 17, 2009). To claim this credit, a

taxpayer must follow general monitoring and verification principles, calculate CO2 sequestered

in the fiscal year using a mass-balance equation, and report to IRS the amount of qualified CO2

sequestered in the fiscal year. Seventy-five million metric tons of qualified CO2 can be taken

into account for this credit. The IRS included a provision in the notice to supersede its

monitoring and verification procedures and requirements with procedures and requirements

finalized by EPA in future GS rulemaking such as the UIC Class VI proposal and this proposed

rule.

EPA has concluded for a number of reasons that the IRS data would not meet the needs

outlined in this proposed rule. First, the IRS reporting requirement will expire after 75 million

metric tons of CO2 is reported as sequestered to IRS, at which point the data collection will end.

Second, the level of reporting and transparency would not meet the verification needs of this

proposed rule. GS facilities only report the quantity of CO2 sequestered to IRS. The data used to

calculate sequestration and the specific monitoring procedures followed will only be reviewed by

IRS staff in the case of an audit. Given the variability in geology and other conditions at GS

facilities, EPA believes that the monitoring approach at each GS facility must be reviewed on a

case-by-case basis to ensure that it is appropriate for the site-specific geologic and operational

conditions. Third, the IRS does not outline procedures or provide a mechanism for quantifying

and reporting any CO2 leakage that may occur as is necessary for this proposed rule.

EPA notes that the United States submits an inventory of GHG emissions that accounts

for CCS to the Secretariat of the United Nations Framework Convention on Climate Change

(UNFCCC) each year. The UNFCCC, ratified by the United States in 1992, establishes an

overall framework for intergovernmental efforts to tackle the challenge posed by climate change.

The United States has submitted the Inventory of U.S. Greenhouse Gas Emissions and Sinks

(Inventory) to the United Nations every year since 1993. The annual Inventory is consistent with

11 Available at: http://www.irs.gov/irb/2009-44_IRB/ar11.html.
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national inventory data submitted by other UNFCCC parties, and uses internationally accepted

methods for its emission estimates. For more information about the Inventory, please refer to the

following web site: http://www.epa.gov/climatechange/emissions/usinventoryreport.htm

The United States currently follows the 199612 Intergovernmental Panel of Climate

Change (IPCC) guidelines in preparing its Inventory, as supplemented by IPCC Good Practice

Guidance (GPG) from 200013 and 200314. Since these guidelines do not provide information on

the accounting of GS, EPA addressed CO2 usage in the 2007 Inventory by accepting some

general, top-down assumptions about the end-use of supplied CO2. First, EPA collected CO2

production data for natural CO2 domes and estimated for each dome the amount of CO2 used for

ER operations and the amount of CO2 used for non-ER operations. EPA assumed that the

percentage of naturally produced CO2 used for non-ER operations (e.g. food processing,

chemical production) was all emitted to the atmosphere. The percentage used for ER operations

was assumed to be sequestered. Second, EPA collected data from industry on anthropogenic

CO2 emitted from natural gas processing and ammonia plants and accounted it as emitted,

regardless of whether the CO2 was captured or not.

The IPCC published new inventory guidelines in 200615, which directly address

accounting for GS and include methodologies for the estimation of emissions from capture,

transport, injection, and GS of CO2. The guidelines are based on the principle that the CCS

system should be accounted for in a complete and consistent manner across the entire Inventory.

The approach accounts for CO2 produced from natural CO2 domes and captured at industrial

facilities as well as emissions from capture, transport, and use. For GS specifically, the IPCC

guidelines outline a Tier 3 methodology16 for estimating and reporting emissions based on sitespecific evaluations of each storage site. EPA believes that the GS monitoring, reporting, and

verification requirements of this proposed rule are consistent with the 2006 IPCC guidelines.

12 IPCC, 1996. “Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories.” National Greenhouse

Gas Inventories Programme. Available: http://www.ipcc-nggip.iges.or.jp/public/gl/invs1.html.

13 IPCC. 2000. “Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories.”

National Greehouse Gas Inventories Programme. Available at: http://www.ipccnggip.iges.or.jp/public/gp/english/.

14 IPCC. 2003. “Good Practice Guidance for Land Use, Land-Use Change, and Forestry.” National Greenhouse Gas

Inventories Programme. Available at: http://www.ipcc-nggip.iges.or.jp/public/gpglulucf/gpglulucf.html.

15 2006 IPCC Guidelines for National Greenhouse Gas Inventories: Volume 2 – Energy. Chapter 5 Carbon Dioxide

Transport, Injection, and Geological Storage. Available at: http://www.ipccnggip.iges.or.jp/public/2006gl/index.htm.

16 Tier 3 methods include either detailed emission models or measurements and data at individual plant level where

appropriate.
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In considering how to design this proposal, EPA also took into account the monitoring

requirements adopted in other countries, in particular other UNFCCC member countries that

have already taken steps towards collecting information for CCS to meet the 2006 IPCC

guidelines. The Directive of the European Parliament and of the Council on the geological

storage of carbon dioxide (Commission decision 2007/589/EC) establishes a legal framework for

the environmentally safe geological storage of CO2. It requires European Council (EC) member

states to ensure that each GS site operator will carry out monitoring of the injection facilities, the

storage complex (including the CO2 plume), and, where appropriate, the surrounding

environment for detection of any significant migration or leakage of CO2 or any significant

adverse effect on the surrounding environment.
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SECTION 3

DEVELOPMENT OF SUBPART RR

Since EPA is proposing that Subpart RR be added to the existing Mandatory Reporting of

Greenhouse Gases Program established under 40 CFR 98, we propose that the provisions of 98.1

through 98.6 apply to today’s rule unless we describe and provide a rationale for an alternative

provision in today’s rule. This section describes the development process underlying the

proposal of Subpart RR.

3.1 Rule Dimensions for Which Options Were Identified

Possible designs for subpart RR GHG reporting were developed by evaluating options

across the following dimensions:

1. Affected Entities

The targeted entities under the Subpart RR source category include:

(1) CO2 injection facilities, defined as a well or a group of wells that inject CO2 into the

subsurface or sub-seabed geologic formations. This definition would encompass both onshore

and offshore facilities.

(2) GS facilities, defined as facilities injecting CO2 for the purpose of long-term

containment in subsurface geologic formations.

2. Thresholds

Upon reviewing the results of a detailed threshold analysis, EPA is proposing that all

facilities that meet the definition of this source category must report the data outlined below at no

threshold.

3. Data to be reported

All injection facilities must annually report the following:

(a) Mass of CO2 injected.

(b) Mass CO2 transferred onsite from offsite

(c) Source of CO2, if known.
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In addition, all GS facilities must annually report the following:

(1) Mass of CO2 produced, if any.

(2) Mass of CO2 sequestered in the subsurface geologic formation.

(3) Mass of CO2 emitted from subsurface leaks, if any.

4. Monitoring, reporting, and verification (MRV) plan requirements

In order to ensure accurate and efficient data reporting, each GS facility must

develop a site-specific MRV plan consistent with EPA guidelines.

These dimensions are discussed in more detail below.

3.2 Definition of Affected Entities

1. CO2 Injection Facility

EPA is proposing that the CO2 injection facility be defined broadly to cover a well or a

group of wells that inject CO2 into the subsurface or sub-seabed geologic formations. This

definition would encompass both onshore and offshore facilities.

EPA is proposing a broad definition of CO2 injection facility to ensure complete

reporting of basic information regarding the quantity of CO2 transferred onsite, the source of the

CO2 if known, and the amount injected. The broad definition also provides reporters with

flexibility either to report this basic information on a well by well basis or to group wells in an

area for reporting purposes. Given the proposed threshold and applicability for CO2 injection

facilities, a more specific definition addressing the aggregation of groups of wells in an area is

not necessary.

 2. GS Facility

EPA is proposing facilities injecting CO2 for the purpose of long-term containment in

subsurface geologic formations would meet the definition of GS in this proposed rule and would

report additional information. EPA is proposing that facilities that inject CO2 for ER would not

be GS facilities unless they inject CO2 for the purpose of long-term containment in subsurface

geologic formations and choose to submit and gain EPA approval of an MRV plan.
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To comply with the specific reporting requirements detailed in the preamble, the reporter

would need to identify the sources and surface equipment making up the GS facility. However,

EPA recognizes that defining the extent of a GS facility source may be difficult. For example,

there may be a number of injection wells in an oilfield under common ownership or common

control of which only a subset would be considered GS facilities. In that example, the question

of whether and how to aggregate various wells arises. In addition, the area of review associated

with a GS facility may extend for a distance beyond the injection point, and widely separated

wells may be injecting into the same pore space. Because EPA is seeking data on the amount of

CO2 sequestered by these facilities and because EPA is proposing an all-in threshold for these

facilities, EPA is proposing a narrow definition of GS facility to simplify the reporting

requirements associated with emissions from combustion and surface equipment. For purposes

of this reporting rule, EPA is proposing to define a GS facility to include all structures associated

with the injection of CO2 located between the points of CO2 transfer onsite from offsite and the

injection well (or wells). A GS facility that injects CO2 to enhance the recovery of oil or natural

gas will also include all structures associated with production located between the production

wells and the separators.

Although EPA is proposing a narrow definition of GS facility, the proposed rule would

require GS facilities to monitor over a spatial area that will almost certainly extend beyond the

boundaries of the facility, as defined here. Given that a main focus of this proposal is to obtain

information regarding the efficacy of GS, EPA anticipates that the MRV plans for GS facilities

will need to require monitoring over a broad area. This is discussed in the preamble to this rule.

EPA is proposing to exempt research and development (R&D) as defined at 40 CFR Part

98.6 from subpart RR, consistent with the approach taken in subparts C through QQ of the MRR.

EPA is also proposing that, for the purposes of GS facility requirements under subpart RR,

research and development means those projects receiving Federal funding to research practices

and monitoring techniques that will enable safe and effective long-term containment of a

gaseous, liquid, or supercritical CO2 stream in subsurface geologic formations that are neither

demonstration nor commercial projects. R&D projects would not be required to submit an MRV

plan under subpart RR.

3. Other CO2 End-Users

In developing this proposed rule, EPA considered requiring reporting from various other

end-users of the CO2 that is produced and supplied to the economy. EPA considered but is not

proposing requiring reporting from these other end-users; EPA has concluded that collecting
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information pursuant to subpart PP on CO2 supplied to the economy will provide EPA with the

necessary data on emissive volumes while minimizing the number of facilities impacted by this

rule.

3.3 Selection of Reporting Threshold

To determine the appropriate threshold for reporting under subpart RR, EPA considered

both a threshold based on the amount of CO2 emitted and a threshold based on the amount of

CO2 injected underground. EPA concluded that an emissions-based threshold would be

problematic because of the lack of data on the incidence and scale of surface emissions and

leakage from injection and GS of facilities. EPA accordingly analyzed injection facilities based

on the quantity of CO2 injected underground and considered whether an injection threshold

should apply. EPA evaluated a no threshold option (i.e., all facilities that inject CO2 would be

required to report), 1,000 metric tons per year, 10,000 metric tons per year, 25,000 metric tons

per year, and 100,000 metric tons per year per facility of CO2 injected.

To establish a count of CO2 injection facilities, EPA relied on data reported in the Oil and

Gas Journal (O&GJ) Enhanced Oil Recovery Survey published in April 2008 (Volume 106,

Issue 15). EPA compiled all the projects listed for miscible and immiscible CO2 floods1 reported

in the O&GJ survey. A total of 105 active ER projects were reported. In some cases multiple

projects were conducted by the same company in an oil field. For the purposes of this analysis,

EPA grouped these reported projects by field and by owner or operator to align with typical

industry practices for reporting project information to state oil and gas commissions. This

computation results in eighty facilities for the facility count.

The O&GJ survey does not provide the specific volume of CO2 used in each of the active

ER projects. To calculate the estimated volume of CO2 injected at each ER project, EPA took

the total amount of CO2 used daily for ER, as reported by the U.S. EPA in the Draft 1990 – 2007

Inventory of U.S. Greenhouse Gas Emissions and Sinks,2 apportioned it to each ER project

according to an average value for the fractional production of oil attributed to ER using CO2 as

presented in the O&GJ survey, and normalized the amount of CO2 injection on an annual basis.

The results of the threshold analysis are presented in the preamble to this rule. For further

1A miscible CO2 flood injects CO2 as a liquid at high pressure to completely mix with oil and make it flow more

easily. An immiscible CO2 flood uses lower pressures of CO2 to swell the oil and provide additional gas pressure

to move the oil.

2

 U.S. EPA Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-2007,

 Draft Report, EPA 430-R-09-004. Available at:

http://epa.gov/climatechange/emissions/usinventoryreport.html
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information on the assumptions underlying the threshold analysis, please refer to the general

technical support document (TSD) for this proposal.1

The results of this analysis showed that nearly all injection data can be collected from

roughly half of operating facilities at an injection threshold of 100,000 metric tons/yr of CO2

injected. EPA considered establishing an injection threshold of 100,000 metric tons/yr of CO2

injected. However, a low CO2 injection or production quantity in one year is not a reliable

prediction of the quantity that may be injected in the following year or in a year of full-scale

operation. For example, six of the eighty facilities reported zero or near zero production and

therefore did not exceed the 1,000 metric tons threshold. However, these six facilities may inject

over this threshold in the following year. In addition, more than 40 of the 105 projects in this

analysis were described in the OG&J survey as “just started” or pilot projects, indicating that

they may not be at fully operational levels of CO2 injection. Given the variability of CO2

injection rates, EPA is proposing that all facilities report irrespective of injection or production

quantities in the reporting year.

EPA is proposing that all CO2 injection facilities would be required to report the

minimum information in subpart RR (quantity of CO2 injected, quantity of CO2 transferred

onsite from offsite, and source of the CO2 if known) at no threshold. An all-in reporting

threshold would allow the Agency to comprehensively track all CO2 supply (as reported in

Suppliers of CO2, subpart PP) that is injected underground. This approach is consistent with the

all-in requirements in the MRR for suppliers of petroleum, natural gas, and coal-to-liquid

products (subparts LL, MM, and NN), producers of industrial gases (subpart OO), and suppliers

of CO2 (subpart PP). It was reasonable to require all of the facilities in these source categories to

report because it would result in the most comprehensive accounting possible, simplify the rule,

and permit facilities to quickly determine whether or not they must report; the same rationale

applies for this source category proposed today. Furthermore, it would create a uniform burden

for all covered facilities, ensuring a level playing field in, and preventing fragmentation of, the

ER sector. EPA has estimated the cost for CO2 injection facilities to comply with the minimum

reporting requirements in this proposed rule and has determined that the burden would be small,

given the equipment and data collection efforts already in place at ER projects.

 Under this action, EPA is proposing that the subset of CO2 injection facilities that are

conducting GS (i.e. a GS facility) must report to EPA a second tier of data. EPA considered

whether a threshold should apply to this second tier of data given that it would place a reporting

1

 Subpart RR General TSD (see docket ID No. EPA-HQ-OAR-2009-0926)
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burden on GS facilities. However, EPA could not perform an analysis on GS facilities based on

emissions without data on actual or expected GS facility emissions. EPA also could not perform

a threshold analysis based on injection due to the uncertainty around predictions of injection

quantities for potential GS facilities. In addition, it is difficult to predict how many injection

facilities would choose to report GS. Therefore, EPA is proposing to exempt GS R&D projects

but otherwise require all GS facilities to comply with the GS monitoring, reporting, and

verification requirements of subpart RR, and that they report fugitive, vented, and combustion

emissions from surface equipment (under subpart W, RR, or C, as applicable). An all-in

threshold will allow EPA to work with the early-movers of this nascent industry and to

strengthen EPA’s understanding of GS.

3.4 Selection of Data to Be Reported

This section describes the data that injection facilities and GS facilities must report under

subpart RR. The first tier of reporting requirements described is for all facilities that inject CO2

underground. The second tier of reporting requirements described is for GS facilities only.

The first tier has three proposed reporting requirements. First, EPA is proposing that all

CO2 injection facilities report the mass of CO2 injected. This would be determined by the mass

flow or volumetric flow and CO2 concentration of the CO2 stream injected. Facilities must use

mass flow meters to accurately measure the mass of the CO2 injected or volumetric flow meters

to accurately measure the volumetric flow of the CO2 injected. To minimize the purchase and

installation of new equipment, facilities subject to the UIC program would be allowed to

measure the mass or volume of CO2 injected with the flow meters installed for purposes of

compliance with their UIC permits. EPA accordingly is proposing two methodologies for

making these calculations, depending on whether the facility is using a volumetric or a mass flow

meter. EPA is proposing this approach so that facilities can comply with these reporting

requirements regardless of the type of flow meter already installed. In the case of a facility using

a volumetric flow meter, EPA assumes that the facility can determine operating temperature and

pressure, which would allow for the volumetric flow of CO2 to be converted from operating

conditions to standard conditions and, using a density value for CO2 at standard conditions and

the measured concentration of CO2 in the flow, determine the mass of CO2.

Facilities would measure the CO2 concentration by sampling and testing the injected

stream at the flow meter. With this approach, the flow and the concentration would be measured

at the same point in the system for maximized data accuracy. Accordingly, if the flow meter

were installed at the compressor(s), then the concentration would be measured at the
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compressor(s). If the flow meter were installed at the well(s), then the concentration would be

measured at the well(s). EPA recognizes that a facility with tens or hundreds of injection wells,

all of which have flow meters already installed at the wellheads, may face a significant burden in

testing concentration at each of those flow meters.

Second, EPA is proposing that all CO2 injection facilities report the mass of the flow

transferred onsite from offsite to verify the mass of CO2 reported as injected. This would be

determined by the mass flow or volumetric flow and CO2 concentration of the flow transferred

onsite from offsite. A subset of CO2 injection facilities – facilities conducting ER – inject a

combination of new CO2 transferred onsite from offsite and old CO2 recycled from the operation.

Therefore, EPA would use reported data on CO2 transferred onsite from offsite to estimate the

amount of CO2 recycled from ER operations.

EPA is proposing that all CO2 injection facilities monitor the CO2 concentrations and

mass flow or volumetric flow quarterly. The purpose of these measurements is to account for

fluctuations in the CO2 concentration over the reporting year.

Third, EPA is proposing that all CO2 injection facilities would report the source

contracted to supply the CO2, if known. EPA would seek information on whether the CO2 was

contracted from a natural source (i.e. produced from a natural CO2 dome) or an industrial source.

If an industrial source, EPA would seek information on the type of source if known (captured at

a power plant, pulp and paper mill, ethanol plant, natural gas processing facility, or other type of

industrial source). This would allow EPA to track the movement of CO2 through a CCS system

and any shift toward anthropogenic CO2 supply sources. Pipelines that carry CO2 to the CO2

injection facility may contain a mix of CO2 from various sources. EPA recognizes that facilities

may not know the source of CO2 that they purchase. Accordingly, EPA would require the data

to be reported only if known.

EPA recognizes that at this time the source of CO2 injected underground is

predominantly CO2 produced from natural CO2 domes. It is possible that GS using naturally

sourced CO2 may not qualify as a GHG mitigation action because the purpose of GS is to isolate

CO2 that would otherwise have been emitted to the atmosphere. Under this proposed rule,

however, GS facilities must report annual CO2 sequestered regardless of the source.

For this proposed rule, EPA also considered, but is not proposing, that a CO2 injection

facility be required to report only the CO2 injection data it collects under its current UIC permit

(under any class) or relevant permit in the case of a facility that is outside SDWA jurisdiction.
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Although this would impose the lowest burden on the reporter since no new data would need to

be collected, EPA would not receive complete data on the mass of CO2 injected. While

collection of injection volume is a minimum monitoring requirement for all UIC well classes,

CO2 concentration data are not. Furthermore, facilities are not required to report CO2 transferred

onsite from offsite sources or the source of CO2 under any UIC permit class.

EPA is proposing that GS facilities would report a second tier of data in subpart RR.

These reporting requirements include the amount of leakage of CO2 to the surface (if any), the

amount of CO2 in produced oil or gas (for GS facilities conducting active ER operations), the

amount of fugitive and vented CO2 emissions from surface equipment, and the total annual

amount of CO2 sequestered using a mass balance equation. In this equation, the sum of the CO2

emissions listed above would be subtracted from the amount of CO2 injected to equal the amount

of CO2 sequestered. These four reporting requirements are described in more detail below.

GS facilities must report CO2 leakage, if any occurs from the subsurface geologic

formation to the surface. EPA is not proposing specific procedures or methodologies for

detecting or quantifying CO2 leakage. However, each GS facility would be required to develop

and implement a site-specific approach to monitoring, detecting, and quantifying CO2 leakage

based on requirements that are outlined in detail in the preamble to this rule.

First, EPA is proposing that GS facilities that are actively producing oil or gas would be

required to report the quantity of CO2 produced out of the subsurface with produced oil or

natural gas. This would be done by measuring at each separator the volumetric flow or mass

flow and the concentration of a CO2 stream. These GS facilities would also report CO2 that

remains in the oil or gas after separation.

Second, unless already reported in the petroleum and natural gas system subpart, subpart

W, EPA is proposing that all GS facilities would be required to report fugitive and vented CO2

emissions from surface components located within the facility for which procedures and

methodologies are provided in subpart W. This could include pump blow-downs and fugitive

emissions from valves, flanges, and compressors. EPA seeks these data to better understand the

volume of fugitive and vented GHG emissions at GS facilities as compared to the volume of CO2

sequestered. This information is an important indicator of the effectiveness of GS as a GHG

mitigation technology. In addition, fugitive and vented CO2 emissions will need to be included

in the mass balance calculation of GS if they occur downstream of the CO2 injection flow meter

or (if applicable for ER projects) upstream of the production flow meter. This proposed rule

does not impose a general requirement for all CO2 injection facilities to report fugitive and
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vented CO2 emissions from surface components since facilities that are not sequestering CO2

would not report GS.

Lastly, EPA is proposing that GS facilities use a mass balance equation to calculate and

report CO2 sequestered in the subsurface geologic formation in the reporting year. This reported

data point would be valuable for EPA as the Agency tracks CO2 across a CCS system and will

provide EPA with information on the performance of GS projects over time. Alternatively, EPA

could approximate CO2 sequestered in the subsurface without proposing additional reporting

requirements for GS facilities, by using data already reported on CO2 transferred from offsite and

CO2 injected. EPA considered but did not propose this approach because it does not account for

potential leakage from the subsurface and does not properly account for CO2 fugitive or vented

emissions from surface equipment during post-production, processing, transport, or compression.

Given the importance of GS as a GHG mitigation technology, EPA seeks to achieve an accurate

reporting of GS.

EPA recommends that CO2 injection and GS facilities review subparts C and PP and

proposed subpart W. Subpart C provides GHG calculation procedures and reporting

requirements for stationary fuel combustion devices that combust solid, liquid, or gaseous fuel.

CO2 injection and GS facilities should pay close attention to compressors and pumps located

within the facility boundary. Subpart PP provides procedures for calculating and reporting

quantities of CO2 supplied to the economy. The Subpart W proposal covers petroleum and

natural gas systems by defining eight types of facilities and providing calculation procedures and

reporting requirements for the GHG emissions of specific equipment that may be located in those

facilities. CO2 injection and GS facilities should review in particular the definitions of onshore

and offshore petroleum and natural gas production facilities.

EPA is proposing that if an injection facility is not conducting GS, it would determine

applicability to other subparts of the rule separately from applicability to subpart RR. This is

similar to the approach taken by reporters of upstream petroleum products supply, natural gas

supply, natural gas liquids supply, and carbon dioxide supply (reporters in subparts MM, NN,

and PP). For example, an injection facility not characterized as a GS facility would not

automatically trigger reporting under subpart C by this proposal, but would make a separate

applicability determination under subpart C. A GS facility would automatically trigger

applicability under other subparts of the rule. This is similar to the approach taken by reporters

of downstream emissions in the rest of the MRR. For example, the GS facility would report

under subpart C the emissions from combustion sources located within the facility boundary,

such as compressors.
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In selecting data to be reported under today’s proposal, EPA compared reporting

requirements under today’s subpart RR proposal with reporting under the UIC Class VI proposal.

EPA found two data elements with potential overlap. The first area of potential overlap is the

reporting of the amount (flow rate) of injected CO2. The UIC Class VI and subpart RR proposals

differ in the measurement unit and collection/reporting frequency. EPA determined that

reporting of the amount (flow rate) of injected CO2 was necessary in order to harmonize the data

with other subparts of the MRR. To ensure that data needs are harmonized between the MRR

and the UIC program requirements and to reduce burden, and because this data under a stateissued UIC permit is currently submitted to states while, under today’s subpart RR proposal,

reporters will be submitting data directly to EPA.

The second area of potential overlap relates to monitoring plans. Although both the UIC

Class VI proposal and today’s subpart RR proposal have monitoring plan requirements, the UIC

Class VI proposal is focused on protection of USDWs, while today’s subpart RR proposal is

focused on air emissions. Potential differences include baseline data and detection and

measurement of CO2 leakage to the surface. Recognizing that air monitoring under the UIC

Class VI proposal is at the discretion of the UIC director, EPA notes that a UIC Class VI permit

may fulfill requirements under today’s proposal.

EPA considered whether a GS facility should also report methane (CH4) leakage

emissions from the subsurface. CH4 emissions from the subsurface may occur at oil and natural

gas reservoirs or ECBM sites. The cases in which leakage of CH4 could occur at these sites may

be similar to the potential for CO2 leakage. CH4 leakage could potentially occur through

improperly sealed wells, open faults, and other pathways that have also been identified as

potential CO2 leakage pathways. However, CH4 is present as a gas, and thus may be more

upwardly mobile than CO2 which is injected as a supercritical fluid. Therefore, the potential for

leakage of methane at depleted oil and gas or ECBM sites may be greater than for CO2.

EPA is proposing to focus on CO2 emissions. EPA recognizes the potential for CH4

leakage from the subsurface at facilities conducting GS in oil and gas reservoirs or coal seams

and therefore seeks comment on whether to require reporting on CH4 leakage. If the potential

for CH4 leakage exists, the GS reporter could include in the MRV plan a monitoring strategy to

detect and quantify potential CH4 leakage. CH4 fugitive and vented emissions from surface

equipment are covered under the proposed oil and gas subpart, subpart W.

Under subparts C through QQ of the MRR, adjacent or contiguous equipment in actual

physical contact under common ownership or common control constitute a facility (see Section
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98.6 of the MRR). In the case of petroleum and natural gas systems and GS, equipment are not

necessarily in physical contact with one another in the conventional sense of the term. Subparts

W and RR are each proposing interpretations of what would constitute a facility. As a result, a

GS facility conducting ER may apply one facility boundary for reporting under subpart W and a

different facility boundary for reporting under subpart RR. EPA acknowledges that this may

present a challenge for submitting annual reports, depending on how the data system is designed.

A CO2 injection or GS operation would submit an annual report to EPA according to the

proposed definition of facility.

EPA also recognizes that, in the case of an ER operation conducting GS, the combustion

emissions from equipment within the GS facility would be included in both annual reports.

Though this approach results in duplicative reporting, EPA has concluded that to analyze the

efficacy of GS as a GHG mitigation tool, EPA needs to collect information on combustion

emissions from GS facility equipment at only the GS facility level rather than aggregated with

emissions from additional equipment.

3.5 Selection of proposed monitoring, reporting, and verification (MRV) plan

requirements and approval process

3.5.1 Selection of MRV Plan Option

EPA considered three alternatives for monitoring, reporting and verification of potential

CO2 leakage at GS sites: do not require an MRV plan, require a universal MRV plan that applies

to all GS sites, or require a site-specific MRV plan. The three alternatives vary in stringency and

specificity as described below. EPA outlines the advantages and disadvantages of each

alternative and seeks comment on each alternative, as well as any alternatives not discussed.

Under the first alternative, EPA would allow GS facilities to report the amount of CO2

sequestered without requiring an MRV plan. Under this alternative, the Agency would rely on

published information and existing studies to assume that injected CO2 remains sequestered and

would assume these results can be generalized to all GS projects. This alternative would impose

the least burden on reporters. EPA notes that international guidelines on information collection

and reporting efforts do not support this approach. Furthermore, EPA did not propose this

approach because of the limited empirical data and the variability in geology and other

conditions among GS facilities.

The second alternative that EPA considered was a one-size-fits-all MRV plan approach

under which the Agency would prescribe specific monitoring technologies and quantification

methods for GS facilities. The advantage of this approach is that all GS facilities would use the
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same monitoring technologies and methods. The disadvantage of this approach is that the

geology and other conditions at potential GS facilities will vary from site to site and a one-sizefits all approach may not provide the most effective monitoring strategy for all facilities. EPA

notes that international guidelines on information collection and reporting efforts do not support

this approach. In addition, since the monitoring and testing plans implemented under the UIC

program are necessarily site-specific in nature, it would be difficult to prescribe a one-size-fitsall MRV plan that would complement and build upon the UIC program. This alternative would

likely be the least cost effective and most burdensome approach for reporters.

The third alternative, and the alternative that EPA is proposing, is that GS facilities be

required to develop a site-specific MRV plan and submit it to EPA for approval. Facilities

would report CO2 injection until the final MRV plan has been approved. Once a final MRV plan

has been approved by EPA, GS facilities would implement the plan, including the reporting of

the amount of CO2 that has been sequestered. The advantage of this approach is that it provides

a flexible and cost-effective option for reporters and complements monitoring requirements

under the proposed UIC Class VI rule. EPA recognizes that the rigorous proposed UIC Class VI

requirements will provide the foundation for the safe sequestration of CO2 and should serve to

reduce the risk of CO2 leakage to the atmosphere when finalized. An adequate MRV plan would

be tailored to site-specific conditions and be designed for each stage of the GS project. In

addition, the MRV plan would allow for modification or adaptation of the plan based on

monitoring results. Although the risk of leakage at an appropriately selected and managed GS

facility may be low, the MRV plan would ensure that if leakage occurs, the GS reporter would

have an approved methodology for measuring the emitted CO2. If leakage occurs, the MRV plan

would also provide a process for revising the MRV plan if necessary.

It is important to recognize that this proposed rule is a data collection and monitoring

proposal which does not directly address the potential human health and welfare, ground or

surface water, ecosystem or geosphere impacts of GS. Therefore, the proposed rule does not

address these potential impacts from CO2 leakage (e.g. requiring remediation or mitigation) as

this is outside the scope of this proposal.

EPA is proposing that each submitted MRV plan must include at a minimum the four

requirements described below:

Step 1 – Assessment of Risk of Leakage: All potential pathways that may result in CO2

leakage have been identified and characterized and the risk of CO2 leakage at each pathway has

been evaluated;
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Step 2 – Strategy for Detecting and Quantifying CO2 Leakage to Surface: Potential

pathways will be monitored according to the risk of CO2 leakage to ensure that any leakage to

the surface will be detected and that leakage to the surface, should it occur, will be quantified

according to a specified methodology;

Step 3 - Strategy for Establishing Pre-Injection Environmental Baselines: Environmental

baselines against which the monitoring results will be evaluated have been established at

potential leakage pathways; and

Step 4 - Tailor Mass Balance Equation: Site-specific variables have been considered and

developed for the mass balance equation provided in the regulatory text to calculate the amount

of CO2 sequestered.

Details regarding MRV requirements are provided by EPA in the preamble to this rule.

EPA also developed a monitoring plan technical support document that describes characteristics

of a robust monitoring plan.1

3.5.2 Background on MRV Approaches

EPA has identified published studies and/or guidelines on monitoring programs that

identify and quantify CO2 leakage from GS facilities.2 While the science of quantifying CO2

leakage from GS facilities is evolving, it is generally recognized that, when properly planned and

implemented, monitoring methods will be effective at detecting leakages.3,4

Though the methodologies for detecting and quantifying leakage of CO2 from GS

facilities have not been standardized, EPA has concluded that a GS facility would be able to

propose a site-specific plan for leak detection and quantification under this rule based on the

current availability of monitoring technologies. A wide range of techniques for monitoring

1 Monitoring Plans for Geologic Sequestration TSD (see docket ID No. EPA-HQ-OAR-2009-0926)

2 Arts, R, O Eiken, A Chadwick, P Zweigel, L van der Meer, B Zinszner. 2004. “Monitoring of CO2 injected at

Sleipner using time-lapse seismic data.” Energy 29: 1383-1392; Wilson, M. and M. Monea (Eds.). 2004. “IEA

GHG CO2 Weyburn CO2 Monitoring and Storage Project,” Seventh International Conference on Greenhouse

Gas Control Technologies, Vol. 3; Klusman, RW. 2003. “Rate Measurements and Detection of Gas

Microseepage to the Atmosphere from an Enhanced Recovery Sequestration Project, Rangely, Colorado, USA,”

Applied Geochemistry, 18, 1825-1838; IPCC. 2006. “2006 IPCC Guidelines for Greenhouse Gas Inventories.”

Intergovernmental Panel on Climate Change, Simon Eggleston, ed.

 http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html; DOE/NETL. 2009. “Best Practices for Monitoring,

Verification, and Accounting for CO2 Stored in Deep Geologic Formations.” U.S. Department of Energy,

National Energy Technology Laboratory.

3

 Benson, SM. 2006. “Monitoring Carbon Dioxide Sequestration in Deep Geological Formations for Inventory

Verification and Carbon Credits.” Society of Petroleum Engineers Paper 102833.

4

 FutureGen Alliance. 2006. “Mattoon Site Environmental Information Volume.” December 2006.
3-14

sequestration of CO2 have been used for a number of years in other applications, including oil

and natural gas production, natural gas storage, disposal of liquid and hazardous waste in deep

geologic formations, groundwater monitoring, and ecosystem research.1 Some monitoring

techniques such as seismic monitoring can detect the presence and location of CO2 in the

subsurface, including both vertical and lateral spread, although the accuracy of seismic

monitoring for quantifying the amount of CO2 may be more limited than other approaches.

Other techniques, such as soil gas monitors or eddy covariance techniques, can detect, within a

certain limit, leakage of CO2 from the confining system. Many of these technologies have

excellent sensitivity, and have been shown to be able to detect relatively low concentrations of

CO2 above background levels. The minimum leakage rate detectable is a function of parameters

such as the volume of CO2 making its way to the surface, the size of the leak area, and the

sensitivity of the monitoring device.

Descriptions of the various monitoring technologies that could be deployed at a GS

facility can be found in the general TSD to this proposal2. Additional information on GS

monitoring technologies can also be found in the IPCC Guidelines for National Greenhouse Gas

Inventories (2006), the API/IPECA Inventory Guidelines for CCS (2007), Department of Energy

MVA Best Practices Manual (2009), and the International Energy Agency GHG R&D

Programme monitoring tool website (www.co2captureandstorage.info/co2monitoringtool).

3.6 Selected Option

The selected approach is tiered. First, a set of reporting requirements is proposed to

cover all facilities that inject CO2 underground regardless of the purpose of injection. A subset

of facilities that inject CO2 and conduct geologic sequestration (GS) have additional

requirements and include developing and implementing a Monitoring, Reporting, and

Verification (MRV) plan which, once approved by EPA, would be used to verify injected CO2 as

sequestered and to quantify emissions in the event that injected CO2 leaks, or is suspected of

leaking, to the surface.

Since the geology and conditions at each GS facility will vary widely, EPA proposes a

case-by-case MRV plan approval process. EPA will evaluate each MRV plan to ensure that the

GS facility has an appropriate strategy in place to effectively quantify geologically sequestered

1

 Benson, S and L Myer. 2002. “Monitoring to Ensure Safe and Effective Geological Sequestration of Carbon

Dioxide.” Lawrence Berkeley Laboratory, Berkeley, California; Benson, SM. 2002. "Geologic Sequestration of

Carbon Dioxide." The Carbon Dioxide Dilemma, Promising Technologies and Policies, Proceedings of a

Symposium, National Academy of Engineering, April 23-24, 2002, Washington, D.C., pp. 29-39.

2

Subpart RR General TSD (see docket ID No. EPA-HQ-OAR-2009-0926)
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CO2. EPA will evaluate the adequacy of the methodologies proposed to detect and quantify

leakage, including whether the chosen monitoring technologies are suitable for the type of

leakage pathway and for the type of risk evaluated at that pathway.

Although MRV plan approval would be an inherently EPA function, the Agency is

considering approaches and processes to streamline and facilitate external technical input in the

development of specific evaluation criteria or guidelines, particularly at the outset of the

program. EPA recognizes that an adaptive approach to the GS portion of this proposal will be

necessary to take advantage of the experience gained in developing and implementing MRV

plans and in complying with the proposed UIC Class VI requirements. EPA expects to update

the guidelines and requirements of an MRV plan over time as technologies, methodologies, and

scientific understanding of GS evolve; and the Agency believes that the site-specific nature of

the MRV plan enables the proposed approach to adapt and improve over time.

3.7 Alternative Scenarios Evaluated

Given uncertainties related to project adoption and the costs of the reporting program.

EPA currently considered two other costs scenarios (one requires higher levels of monitoring and

the other requires lower levels of monitoring relative to the reference cost scenario) in order to

assess a range of cost estimates and economic impacts on affected entities. The monitoring

options vary by which monitoring devices would be used at a GS site and how often sampling

and measurement would take place. Second, it is currently unknown how many projects

conducting ER would choose to meet the definition of a GS facility and submit an MRV plan.

As a result, three potential scenarios of the quantity of facilities that would convert have been

considered in the economic impact analysis to represent low, medium, and high outcomes.

Finally, EPA considered two additional scenarios of the quantity of saline formation GS project

outcomes in the economic impact analysis to represent lower and higher outcomes.

3.8 Data Quality

For this analysis, EPA gathered existing data from EPA, industry trade associations,

states, and publicly available data sources (e.g., labor rates from the Bureau of Labor Statistics

[BLS]) to characterize the processes, sources, sectors, facilities, and companies/entities affected.

Costs were estimated based on the data collected and engineering analysis and models provided

by EPA and its contractors. EPA staff and contractors provided engineering expertise,

knowledge of existing facility conditions and activities (e.g., typical labor hours required for

developing QA plans and performing CO2 stream sampling), and an estimate of incremental

activities required to comply with the rule.
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The most important elements affecting the data quality for this analysis include the

number of affected facilities in the source category, the site by site variability of GS sites,

process inputs and outputs (especially for monitoring procedures that involve a carbon mass

balance), and the measurements that are already being made for reasons not associated with the

rule (to allow only the incremental costs to be estimated). The background information was

supplemented from numerous sources, including industry surveys from the U.S. Census Bureau,

trade associations, and operating permits, for example. Information on measurements that are

already made (and thus would not be associated with the rule) was obtained from discussions

with industry representatives, knowledge gained from previous site visits, and other sources. The

data collected to characterize the facilities in this source category are judged to be of good

quality and the best that is publicly available.Other elements affecting the quality of the data

include estimates of labor hours to perform specific activities, cost of labor, and cost of

monitoring equipment. Estimates of labor hours were based on previous analyses of the costs of

monitoring, reporting, and recordkeeping for other rules; information from the industry

characterization on the number of units or process inputs and outputs to be monitored and

engineering judgment. Labor costs were taken from the BLS and adjusted to account for

overhead. Monitoring costs were generally based on cost algorithms or approaches that had been

previously developed, reviewed, accepted as adequate, and used specifically to estimate the costs

associated with various types of measurements and monitoring. The data quality associated with

these elements of the cost analysis is analogous to the quality of data used in the development of

numerous other Information Collection Requests for the different industrial source categories.
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SECTION 4

ENGINEERING COST ANALYSIS

4.1 Introduction

Using available industry and EPA data to characterize conditions at affected sources,

EPA estimated the costs of complying with this proposed rule. Incremental monitoring,

recordkeeping, and reporting activities were then identified for each type of facility, and the

associated costs were estimated.

4.2 Overview of Cost Analysis

The costs of complying with the rule will vary from one facility to another, depending on

the nature of the CO2 injection activities (GS or non-GS), the MRV plan selected, existing

monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor

costs for performing the monitoring, recordkeeping, and reporting activities necessary to comply

with the rule, as well as capital costs related to the implementation of monitoring activities

outlined in the MRV plan for GS sites. All costs referred to in this section are reported in 2008

dollars.

We first provide a general overview of baseline reporting and GS activities. This is

followed by detail on the cost components associated with this information collection; labor

costs (i.e., the cost of labor by facility staff to meet the information collection requirements of

the rule); and capital and operating and maintenance costs (e.g., the cost of purchasing and

installing monitoring equipment or contractor costs associated with providing the required

information).

4.3 Baseline Reporting

4.3.1 Introduction

The Environmental Protection Agency is developing a set of proposed regulatory

alternatives for reporting of CO2 injection and GS. These rules can affect the number and type of

monitoring equipment installed at the sites and the type and frequency of tests and surveys

conducted at the sites. In creating new EPA regulations, a unit cost analysis and the total cost

impact of each of the proposed regulations is required by federal law. This provides a basis for a

full evaluation of the incremental costs of the proposed rule. The purpose of this section is to

present the “activity baseline,” which describes the number and types of injection and GS sites

that could be subject to the rule and the volume of CO2 injections that would be expected.
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Through the practice of geological sequestration, CO2 can potentially be sequestered in

underground formations worldwide for thousands of years. Although commercial geologic

sequestration of CO2 has not yet begun in the U.S., several projects such as Sleipner in the North

Sea, In Salah in Algeria, and Weyburn in Alberta have achieved success in recent years. CO2 at

these sites is being sequestered, and technologies to monitor the process have proved effective.

In the U.S., the Department of Energy is supporting approximately 25 sequestration pilot projects

around the country. DOE also has plans to start a number of relatively large scale pilot projects

within coming years.

Geologic sequestration in the U.S. will likely occur in a range of different geologic

settings including: saline reservoirs, oil and gas reservoirs, coal seams, and others. For purposes

of this economic analysis, the costs of specific aspects of geologic sequestration were specified

on the basis of cost per well, per square mile, per sample, or other basis for each project. In

addition, “type cases” were developed for each reservoir type including, in some instances, two

sizes of injection projects for pilot and commercial-size project scales. These include the typical

parameters (e.g. number of monitoring wells and average well depth) for each type of project,

allowing for estimation of total cost per project. In the cost analysis that appears in Chapter 5, a

base case is created assuming relevant monitoring costs are only that which is required under the

UIC rules. Then three regulatory alternatives for reporting from geologic sequestration sites are

evaluated in terms of technologies and practices and their costs.
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4.3.2 Data Sources

In order to evaluate the total costs in the U.S. of the proposed regulations, it is necessary

to establish an activity baseline forecast of the sequestration activity to which the proposed

regulation applies. The appropriate forecast for this analysis is the level of GS activity that

would be expected even in the absence of future climate change legislation. While climate

change legislation is currently being debated in Congress, no legislation has been enacted. Even

in the absence of national climate legislation, sequestration activity in the U.S. is planned

including:

 Research and Development (R&D) projects,

 FutureGen Sequestration Site, and

 Commercial Sequestration Projects Related to State and Regional Incentive

Programs (in part, funded by DOE)

4.3.3 Published Data on CO2 Sequestration Projects

4.3.3.1 Planned R&D Projects

The Department of Energy has funded an extensive research effort into geologic

sequestration in the U.S. The project is a collaborative effort with seven regional partnerships.

The research effort is managed by the National Energy Technology Laboratory in Morgantown,

West Virginia. The program has two major components: Core R&D and Demonstration and

Deployment.

According to DOE, the goal is to “develop by 2012 systems that will achieve 90%

capture of CO2 at less than a 10 percent increase in the cost of energy services and retain 99

percent sequestration permanence.”

26

The field component of the sequestration research is being carried out by seven regional

partnerships. These partnerships were formed in 2003 and represent consortia of private industry

and government agencies. This effort is tasked with determining the most suitable technologies,

regulations, and infrastructure needs for capture and sequestration.

There are three phases to the work being carried out by the partnerships:

 Characterization (2003-2005)

26 Direct Carbon Sequestration: Capturing and Storing Carbon Dioxide, Congressional Research Service, report

RL33801, September, 2007.
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 Validation (2005-2009)

 Deployment (2009-2017)

The Characterization Phase involved the geologic analysis that resulted in the

development of a National Carbon Sequestration Database and Geographic Information System

(NATCARB). The Validation Phase is currently active and involves such activities as

validation of reservoir simulation methods, data collection for capacity and injectivity, and

demonstration of monitoring technologies. Also being researched are well completion methods,

operations, and abandonment approaches.

The Deployment Stage involves the construction and operation of 8 significant

sequestration projects. These projects are consistent with the Energy Independence and Security

Act of 2007 (EISA), under Title VII, Sec. 702, which requires DOE to conduct at least 7 large

scale sequestration field tests greater than one million tons of CO2 each. These tests are designed

to fully evaluate the potential for commercial scale operations in a range of geological settings.

The tests are planned to have an injection period of up to four, followed by a lengthy monitoring

period. This phase is designed to evaluate the practical aspects of large scale injection over a

prolonged period of time.

A great deal of progress has been made in the areas of site characterization and

monitoring. The next major phase of the DOE research effort is to provide funding support for a

number of commercial scale sequestration operations with injections of up to one million tons

per year.

Sequestration Related to State and Regional Incentive Programs

A number of states or regions have adopted or plan to adopt regulations to address carbon

dioxide and/or greenhouse gas emissions. Most allow for regulated sources of emissions to meet

compliance requirements through the use of offsets. Although geologic sequestration goals or

criteria may not be specified in each case, the potential exists for sequestration activities to

become an accepted and more prevalent way of meeting greenhouse gas reductions.

The programs or state legislation initiatives are generally in the early stages, and there is

considerable uncertainty in terms of which projects will proceed, and on what schedule. ICF has

researched the CSLF (Carbon Sequestration Leadership Forum) online database and the MIT

online database in our analysis of non-DOE projects. It should be noted, that in these databases,
4-21

there are several projects for which startup date and/ or planned injection volumes are not

specified.

Laboratory Research

Over the past several years, DOE and the regional partnerships have carried out an effort

to assess and characterize the CO2 sequestration capacity and potential of the U.S. This effort

has resulted in the publication of a large amount of information on potential by geologic setting

and basin or state. A large amount of GIS data has also been compiled on the geology of

sequestration potential.

In 2008, DOE published the most recent version of the NATCARB (National Carbon)

Atlas. 27 This publication contains maps and data tables documenting their assessment of

sequestration potential in the U.S. Much of the data behind the NATCARB atlas are either

available in GIS form or will eventually be made available.

4.3.4 Hydrogeologic Settings

Geologic sequestration may take place in a number of settings and lithologies. These

include:

 Non-basalt saline reservoirs

 Depleted gas fields

 Depleted and abandoned oil fields

 Enhanced oil recovery (ER)

 Enhanced coalbed methane recovery

For the purposes of analyzing the GS rule, we will focus on the settings that are most

likely affected by the rule, which includes saline reservoirs and oil and gas fields.

4.3.4.1 Non-Basalt Saline Reservoirs

Most significant sedimentary basins in the U.S. contain regionally significant saline

formations that are potential sequestration reservoirs. These are typically sandstone lithologies

with good porosity, containing formation waters of greater than 10,000 mg/L total dissolved

27 Carbon Sequestration Atlas of the United States and Canada, 2008, U.S. Department of Energy, National Energy

Technology Laboratory, Morgantown, WV.
4-22

solids. Salinity may be as high as several times that of seawater. Thus, the water is unsuitable

for drinking or agriculture. Saline reservoirs dominate the assessed potential of the U.S. and

worldwide. In addition, because of their wide geographic distribution in the U.S., saline

reservoirs are often in close proximity to CO2 sources, minimizing pipeline transport distance.

Saline reservoirs represent the vast majority of U.S. sequestration potential (approximately 89

percent of total U.S. capacity). 28 It is very likely that saline reservoirs will play a prominent role

in future geologic sequestration.

Sequestration in saline reservoirs has been shown to be effective. The Sleipner field in

the North Sea is the first commercial-scale saline reservoir project. Carbon dioxide is separated

from the gas stream and re-injected into a reservoir at about 800 meters depth. The rate of

injection is 2,700 tons per day or about one million tons per year. 29 It is anticipated that about

20 million tons will eventually be stored. At Sleipner, the plume has been monitored effectively.

30

DOE has extensively studied saline reservoirs for sequestration. Projects include the Frio

Brine pilot in the Texas Gulf Coast and the Mount Simon Sandstone in the Illinois Basin. 31 The

Mount Simon is known to have excellent sequestration potential because of its regional thickness

and reservoir characteristics, and because it has been used extensively for natural gas

sequestration in the Midwest.

4.3.4.2 Depleted Gas Fields and Oil Fields

Depleted gas and oil fields can be excellent candidates for CO2 sequestration. These

represent known structures that have trapped hydrocarbons over geologic time, thus proving the

presence of an effective structure and seal above the reservoir. These fields have also been

extensively studied, there is a large amount of well log and other data available, and the field

infrastructure is already in place. This infrastructure could in some cases be utilized in

sequestration. A potentially problematic aspect of using depleted fields for sequestration is the

28 2007 ICF assessment developed using DOE Atlas volumes and supplementing in several categories.

29 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A.

Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.

30 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A.

Meyer (eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.

31 Carbon Capture and Storage: A Regulatory Framework for States – Summary of Recommendations,, by Kevin

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.
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presence of a large number of existing wellbores, which can provide leakage pathways.

Typically, oil fields are developed with a closer spacing than gas fields, resulting in a larger

number of existing wells per unit area than in gas fields.

The In Salah Field in Algeria was the world’s first project in which CO2 is injected at

commercial scale into a gas reservoir. However, in this case, the gas is injected downdip in an

actively producing gas reservoir. This differs from an abandoned gas reservoir scenario in which

the gas field is no longer producing.

4.3.4.3 Enhanced Recovery of Oil and Gas

Under certain reservoir and fluid conditions, CO2 can be injected into an oil reservoir in a

process called miscible CO2 enhanced oil recovery. The effect of the CO2 is to mobilize the oil

so that it can move more readily to the production wells. As the oil is produced, part of the

injected CO2 is produced with the oil. This CO2 is then separated and re-injected.

In the U.S. most CO2 ER projects are located in the Permian Basin of West Texas, where

projects have been in place for several decades. The source of most of the CO2 is natural CO2

from several fields in Colorado and New Mexico. 32 Some of the injected CO2 is from gas

processing or other sources. The current volume of CO2 injected for CO2 ER is about 2.2 billion

cubic feet per day.

In 2005, CO2 ER operations produced approximately 237,000 barrels of oil per day in the

U.S. About 180,000 barrels per day of that occurred in West Texas, with most of the rest

produced in the Rockies, Mid-Continent, and Gulf Coast. 33

The development of CO2 ER projects has resulted in a great deal of knowledge about the

process and injection well and other technologies have matured and are well understood. In

addition, it is estimated that more than 3,500 miles of high pressure (>1,300 psi) CO2 pipelines

have been built to accommodate these operations. 34

At the Weyburn Field in Saskatchewan, CO2 from the Dakota Gasification Facility in

North Dakota is injected into an oil reservoir for ER and monitoring of CO2 sequestration. Over

32 The Economics of CO2 Storage, Gemma Heddle, Howard Herzog, and Michael Klett, Laboratory for Energy and

the Environment, Massachusetts Institute of Technology, August, 2003.

33 Oil and Gas Journal, April 17, 2006.

34 Carbon Capture and Storage: A Regulatory Framework for States – Summary of Recommendations,, by Kevin

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.
4-24

the 25 year life of this project, it is expected that about 18 million tons of CO2 will be

sequestered.

4.3.4.4 Enhanced Coalbed Methane Recovery

CO2 can potentially be sequestered in coalbeds through the process of adsorption. CO2

injected as a gas into a coal bed will adsorb onto the molecular structure and be sequestered.

Methane is naturally adsorbed onto coalbeds and coalbed methane now represents a

significant percentage of U.S. natural gas production. Major coalbed methane production areas

include the San Juan Basin of northwestern New Mexico and southwestern Colorado, the Powder

River Basin of eastern Wyoming, and the Warrior Basin in Alabama.

The concept of enhanced coalbed methane recovery is based upon the fact that coalbeds

have a greater affinity for CO2 than methane. Thus, when CO2 is injected into the seam, methane

is liberated and the CO2 is retained. This additional methane represents enhanced gas recovery.

Depending upon depth and other factors, coalbeds may be mineable or unmineable.

Because the process of mining the coal would release any stored CO2, only unmineable coals are

assessed as representing permanent CO2 sequestration. 35

4.3.4.5 Other Hydrogeologic Settings

Basalt flows such as those of the Columbia River Basalts in the Pacific West, are

believed to have the potential for permanent CO2 sequestration. The sequestration process is

geochemical trapping, in which the CO2 reacts with silicates in the basalt to form carbonate

minerals. 36 While research is being carried out on basalt, it is considered unlikely that any

commercial scale sequestration will occur in the foreseeable future due to the unconventional

geology and likely difficulty in monitoring.

The potential to sequester CO2 in organic shale formations is based upon the same

concept as that of coal beds. CO2 will adsorb onto the organic material, displacing methane.

Gas shales have recently emerged as a major current and future source of gas production in the

U.S. These include the Barnett Shale in the Fort Worth Basin, the Fayetteville and Woodford

35 Carbon Capture and Storage: A Regulatory Framework for States – Summary of Recommendations,, by Kevin

Bliss, Interstate Oil and Gas Compact Commission, January, 2005.

36 IPCC, 2005: IPCC Special Report on Carbon Dioxide Capture and Storage, by Working Group III of the

Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer

(eds.)], Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442 pp.
4-25

Shales in the Arkoma Basin, and the Appalachian Devonian Shale. These Devonian and

Mississippian age organic shale formations represent tremendously large volumes of rock. To

date little research has been done on enhanced gas recovery with organic shales. However,

should it prove technically feasible, the U.S. could become one of the major areas worldwide for

this type of sequestration.

4.3.5 Formation Capacity

4.3.5.1 Current DOE Assessment of Sequestration Potential

Through the regional sequestration partnerships, DOE has developed a new national

assessment of sequestration potential. The current assessment is summarized in Table 4-3, in the

column titled “2008 NATCARB.” As evaluated by ICF, the DOE Lower-48 total is 8,179

gigatonnes (Gt) of CO2. The range of uncertainy is 3,508 to 12,850 Gt. Most of the assessment

is attributed to saline reservoirs). This assessment is much larger than the prior assessments

also shown on the table.

4.3.5.2 ICF Assessment of Sequestration Potential

ICF has also developed a sequestration potential assessment by reservoir type. The

results of this assessment are summarized in Table 4-1. The Lower-48 assessed total is 3,375 Gt.

The assessment includes estimates from DOE, and estimates for resources not convered by DOE.

We have included a rough assessment of the Gulf of Mexico, as well as an estimate of shale gas

sequestration potential. The ICF assessment can be broken out by state or region, and geologic

category.

Table 4-2 presents the ICF Lower-48 assessment by region. Sequestration capacity

associated with depleted oil and gas fields occurs where there has been significant production,

including Appalachia, the Gulf Coast, Mid-Continent, and Rockies. Saline reservoir potential

occurs in many areas of the country. Coalbed methane potential is concentrated in the large

coalbed methane production areas such as New Mexico and Wyoming, while shale gas potential

is associated with some of the new shale gas basins that have emerged over the past decade.
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4-1. Comparison of ICF Assessment of U.S. Sequestration Potential with Published Estimates

Lower 48 Only Aug 2007 ICF 2008 2008 2008 2007 2006 2006 2005

ICF Lower-48 NATCARB NATCARB NATCARB NATCARB NATCARB Batelle IEA

Low High Mid

Category Gt CO2 % Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2 Gt CO2

Depleted Oil and Gas Fields

Depleted Oil Reservoirs with EOR Potential 17 0.5% 7 12 0 1

Depleted Conventional Oil Fields 60 1.8% 13 0 1 11

Depleted Gas Fields 50 1.5% 9 35 35

subtotal 126 3.7% 138 138 138 82 29 47 46

Coal and Coalbed Methane

Enhanced CBM 20 0.6% 17 0 1

Deep Unmineable Coal Seams 32 0.9% 11 30 60

subtotal 52 1.5% 73 94 84 86 28 30 60

Shale Formations 107 3.2% 0 0 0 0 45 0 1 0 1

Deep Saline Formations

Onshore 1,187 2,130 7,950 5,040 1,907 6,595 2,730 2,730

Offshore 1,803 4 1,167 4,668 2,918 4 242 3 0 1 900

subtotal 2,990 88.6% 3,297 12,618 7,958 2,149 6,595 3,630 2,730

Onshore Saline-Filled Basalt 100 3.0% 84 100 240 0

Lower-48 Total 3,375 100.0% 3,508 12,850 8,179 2,401 6,797 3,947 2,836

Alaska 84 84

U.S. 8,263 2,485

Notes:

1 No covereage in assessment. 3 Atlantic Offshore Only

2 Represents only a partial assessment of US. 4 GOM, Pacific and Atlantic Offshore
4-27

Table 4-2. Summary of ICF Sequestration Capacity Assessment

Gigatonnes of CO2 Storage

Depleted Depleted

Region (Markal Region Name) EOR Oil Fields Gas Fields Coals Shale Saline Basalt Total

California (California) 1.2 8.0 1.8 0.0 0.0 161.1 0.0 172.2

Eastern Gulf Coast (East South Central) 0.2 1.1 1.3 1.9 28.0 103.2 0.0 135.6

Gulf of Mexico 1.5 5.5 8.4 0.0 0.0 800.0 0.0 815.3

Midwest (East North Central) 0.3 1.3 0.2 3.3 12.7 167.1 0.0 184.9

Northern Midcontinent (West North Central) 0.7 5.9 2.1 0.2 0.0 57.8 0.0 66.7

Northern Rockies (Mountain 1) 0.7 4.6 2.5 17.7 0.0 665.6 33.3 724.4

New England (New England) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Northeast (Middle Atlantic) 0.0 0.3 0.6 0.1 12.0 9.0 0.0 22.0

Pacific NW (Pacific; Lower 48 Onshore Part) 0.0 0.0 0.0 2.3 0.0 53.0 66.6 121.9

Pacific Offshore (Pacific; L48 Offshore) 0.0 1.2 0.0 0.0 0.0 100.0 0.0 101.3

Southern Rockies (Mountain 2) 1.4 3.3 6.0 19.6 0.0 36.5 0.0 66.8

Southeast (South Atlantic) 0.1 0.2 0.7 0.9 19.0 378.0 0.0 398.9

Texas and S. Midcontinent (West S. Central) 10.4 28.0 26.1 5.7 35.0 459.5 0.0 564.6

Total 16.5 59.5 49.7 51.6 106.7 2,990.6 99.9 3,374.6

Offshore (Gulf, Atlantic, Pacific) 1.5 6.7 8.4 0.0 0.0 1,186.6 0.0 1,203.3

Onshore 15.1 52.8 41.2 51.6 106.7 1,804.0 99.9 2,171.3

4.3.6 Geologic Sequestration Rule Activity Baseline

Based upon the above information on what is anticipated for R&D projects, FutureGen,

and state programs, an activity baseline forecast of sequestration activity has been developed.

Because of the uncertainty in which existing ER project might come under subpart RR, three

scenarios have been created and are shown as Table 4-5 to 4-7. The first scenario assumes that

no existing CO2 ER projects choose to report as GS facilities. The second scenario assumes that

all CO2 ER projects from anthropogenic sources (7 million metric tons per year coming primarily

from natural gas processing plants) choose to report as GS facilities. The third scenario assumes

that all projects from anthropogenic CO2 sources plus one-half of the remaining CO2 flood

projects choose to report as GS facilities. This third scenario adds up to 23.4 million metric tons

per year injected of new (i.e., ignoring recycled volumes) CO2.

The most comprehensive source of information on US ER projects is the annual survey

conducted by the Oil and Gas Journal. The 105 projects listed in the Oil and Gas Journal 2007

ER survey were grouped by CO2 source type – natural or anthropogenic. CO2 use was allocated

to the projects supplied by each source based on oil production. Anthropogenic sources were

well defined for ER projects in Michigan (Antrim Gas Processing Plant), Wyoming/Colorado
4-28

(LaBarge/Shute Creek Gas Processing Plant), central Oklahoma (Enid Fertilizer Plant) and

Kansas (US Energy Partners, Russell Kansas Ethanol Plant) from geographic proximity and

information in published literature. Natural CO2 production from the Jackson Dome in

Mississippi was allocated to the 15 projects in Mississippi and Louisiana based on geographic

proximity and information in published literature. Anthropogenic CO2 from the Val Verde Gas

Plant in Texas is mixed with CO2 from natural sources and distributed to several fields in the

Permian Basin so there was not a clear delineation of which projects were served by

anthropogenic gas from the Val Verde plant. To estimate the number of facilities served by Val

Verde, the total CO2 use in the Permian Basin from natural sources and Val Verde production

was summed and the percent of Val Verde production was prorated among the 66 projects in the

Permian Basin. Val Verde CO2 production represents 5.4 % of the total CO2 used in the Permian

Basin, therefore, the equivalent of approximately 4 projects in the Permian Basin are estimated to

use anthropogenic CO2 from Val Verde. For this analysis 2007 CO2 production data for natural

and anthropogenic sources was taken from the (1990-2007) Inventory of U.S. Greenhouse Gas

Emissions and Sinks, and totaled 2.1 bcf/day which differs from the published DOE estimate of

2.6 bcf/day used in the threshold analysis.

Based on the number of projects active in 2007 (latest data available), anthropogenic

sources provide approximately 18% of the mass of CO2 used in ER projects in the US, and

represent approximately 27 % of the CO2 ER projects. These projects result in the additional

production of more than 13 million barrels of oil annually. If only ER projects supplied by

anthropogenic sources opted into the reporting program approximately 28 projects would be

included. If all the ER projects supplied by anthropogenic sources, and half of the projects using

natural sources opted into the reporting program approximately 67 projects would report,

representing 1.2 bcf/day (23.4 million metric tons per year) or 59% of all CO2 ER use.
4-29

Table 4-3. Pro-forma Project Characteristics (ER Scenario: No Additional ER Opt In)

 Baseline Forecast, # of

Projects & Total Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Type

Number

of Projects

Operating

in 2012

Metric Tons

CO2 Injected

per Year

Project

Count

Monitoring

Wells/

Project

Monitoring

Well Depth

Ft

Footage all

monitoring

wells

Square

Miles/

Project

Producing

Oil or Gas

Wells/

Project

Project

Life

Metric Tons

CO2

Injected per

Year /

Project

Known R&D ER 1 1,100,000 1 18 5,700 102,600 17.6 144 7 1,100,000

Known R&D Saline 6 2,720,000 1 3 8,000 24,000 1.7 0 7 750,557

Future R&D Saline 2 1,500,000 1 3 8,000 24,000 1.7 0 7 750,557

Known Commercial

CO2 Injection Facilities

(No GS) 5 3,300,000 1 8 5,700 45,600 8.0 64 20 500,000

Known Commercial

Saline 0 0 1 12 8,000 96,000 11.6 0 20 1,842,885

GS Facilities (ER opt

in) 0 0 1 8 5,700 45,600 8.0 64 20 500,000
4-30

Table 4-4. Pro-forma Project Characteristics (ER Scenario: Anthropogenic ER Only Opt In)

 Baseline Forecast, # of

Projects & Total Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Type

Number

of Projects

Operating

in 2012

Metric Tons

CO2 Injected

per Year

Project

Count

Monitoring

Wells/

Project

Monitoring

Well Depth

Ft

Footage all

monitoring

wells

Square

Miles/

Project

Producing

Oil or Gas

Wells/

Project

Project

Life

Metric Tons

CO2

Injected per

Year /

Project

Known R&D ER 1 1,100,000 1 18 5,700 102,600 17.6 144 7 1,100,000

Known R&D Saline 6 2,720,000 1 3 8,000 24,000 1.7 0 7 750,557

Future R&D Saline 2 1,500,000 1 3 8,000 24,000 1.7 0 7 750,557

Known Commercial

CO2 Injection Facilities

(No GS) 5 3,300,000 1 8 5,700 45,600 8.0 64 20 500,000

Known Commercial

Saline 0 0 1 12 8,000 96,000 11.6 0 20 1,842,885

GS Facilities (ER opt

in) 16 6,972,040 1 8 5,700 45,600 8.0 64 20 500,000
4-31

Table 4-5. Pro-forma Project Characteristics (ER Scenario: Anthropogenic plus One-half Other ER Opt In)

 Baseline Forecast, # of

Projects & Total Volumes Per Project Averages for Economic Analysis (taken from ICF's UIC Class VI work)

Type

Number

of Projects

Operating

in 2012

Metric Tons

CO2 Injected

per Year

Project

Count

Monitoring

Wells/

Project

Monitoring

Well Depth

Ft

Footage all

monitoring

wells

Square

Miles/

Project

Producing

Oil or Gas

Wells/

Project

Project

Life

Metric Tons

CO2

Injected per

Year /

Project

Known R&D ER 1 1,100,000 1 18 5,700 102,600 17.6 144 7 1,100,000

Known R&D Saline 6 2,720,000 1 3 8,000 24,000 1.7 0 7 750,557

Future R&D Saline 2 1,500,000 1 3 8,000 24,000 1.7 0 7 750,557

Known Commercial

CO2 Injection Facilities

(No GS) 5 3,300,000 1 8 5,700 45,600 8.0 64 20 500,000

Known Commercial

Saline 0 0 1 12 8,000 96,000 11.6 0 20 1,842,885

GS Facilities (ER opt

in) 48 23,543,741 1 8 5,700 45,600 8.0 64 20 500,000
4-32

4.3.6.1 Sources of Uncertainty

The activity baseline forecast of sequestration activity represents our best estimate of

what will likely occur in the absence of national climate change legislation. As with any

forecast, there are sources of uncertainty. Categories of uncertainty include:

 Number and timing of R&D projects and number of years of injection

 Number and timing of FutureGen projects and number of years of injection

 Number and timing of State Incentive projects and number of years of injection

 Average injection rates

 Number of ER projects that will be covered

Of the three categories of project, the least uncertainty is associated with the R&D

projects. These projects have been funded and are expected to proceed at close to the

announced schedule.

The DOE FutureGen project site has been chosen (Illinois) but there is still uncertainty

about timing and injection volumes.

Given the number of state and regional initiatives underway it is very likely that projects

related to state incentives will be initiated. As discussed previously, there are a number of

projects for which either timing or injection volumes were not provided and were estimated by

ICF.

The largest uncertainty over the timeframe of the activity baseline is what may occur at

the national level in terms of climate change legislation. However, any costs associated with

potential future national climate policy cannot be attributed to this subpart currently under

consideration. The activity baseline presented in this document is expressly for the purpose of

evaluating the costs of the subpart RR proposal under existing climate change policies.
4-33

4.4 Reporting Costs

4.4.1 Introduction

The purpose of this section is to present the unit cost estimates for the equipment and

services that might be required to comply with the CO2 Injection and GS Reporting rule and the

total incremental annual cost of compliance. A base case is created assuming relevant monitoring

costs are only that which is required under the UIC rules. Then three regulatory alternatives for

reporting from geologic sequestration sites are evaluated in terms required technologies and

practices and their costs.

4.4.2 Cost Assumptions and Methodology

The costs reported here include capital and operating and maintenance (O&M) including

labor costs. They are based on hypothetical or pro-forma sites for various types of projects such

as saline formation R&D GS projects, saline formation commercial GS projects, and ER GS

projects. The geologic and engineering assumption for these pro-forma projects are the same as

used by the EPA Office of Water in the proposed Federal Requirements under the Underground

Injection Control Program for Carbon Dioxide Geologic Sequestration Wells, or the UIC Class

VI proposal for CO2 injection wells37 for CO2 injection wells. The Office of Water is currently

updating the cost analysis used for the UIC Class VI proposal in preparation for the final rule.

Once that data has been updated and made available, this cost analysis will be updated

accordingly. The costs represent price levels in mid 2009, are presented in 2008 dollars. There

were very steep increases in the costs of equipment, materials and labor used in the construction

of all types of energy infrastructure including power plants, pipelines and oil and gas wells from

2004 through 2008. With the drop of oil and natural gas prices in the Fall of 2008 and the

general economic decline around the world the costs of equipment, materials and labor have

moderated somewhat.

4.4.2.1 Primary Data Sources for Costs

Table 4-8 summarizes the major data sources for costs used by EPA in the analysis

geologic sequestration costs. A wide range of cost data is available from industry survey

publications for costs typically incurred in oil and gas drilling and production operations. This

includes drilling and completion costs by region and depth interval, equipment and operating

37 The UIC rulemaking that would create a Class VI well class for injection of CO2 for the purposes of GS was

proposed July 25, 2008. (73 FR 43492)
4-34

costs, and pipeline costs. Data are available for both the U.S. and Canada. 38 39 40 41The cost of

drilling and equipping wells represents a large component of sequestration costs. The costs of

additional equipment or material specifications for CO2 injection wells are based in part upon

various sources for corrosion resistant materials and specific well components. Cost estimates for

seismic data acquisition are also available from industry publications and presentations.

Labor rates are obtained from the U.S. Bureau of Labor Statistics and from surveys of oil

and gas professional performed by the American Association of Petroleum Geologists (AAPG)

and the Society of Petroleum Engineers (SPE). The number of hours required to carry out the

various characterization or monitoring activities are ICF estimates that have been reviewed by

the EPA workgroup.

No comprehensive source has been identified that provides detailed summaries of the full

range of sequestration project cost components. Estimates of the costs of monitoring equipment,

the number of stations required, and the cost of ongoing monitoring are based upon analysis of

available literature and recent presentations by government and academic research groups and

quotations from vendors. Some specific monitoring costs were obtained at a recent industry

meeting sponsored by the Groundwater Protection Council.

42

38 Joint Association Survey of Drilling Costs, American Petroleum Institute, Washington, DC.

http://www.api.org/statistics/accessapi/api-reports.cfm

39 PSAC Well Cost Study – 2008, Petroleum Services Association of Canada, October 30, 2007.

40 Oil and Gas Lease Equipment and Operating Costs, U.S. Energy Information Administration, 2006,

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/cost_indices_equipment_production/current/costs

tudy.html

41 Oil and Gas Journal Pipeline Cost Survey, Oil and Gas Journal Magazine, September 3, 2007.

42 Ground Water Protection Council Meeting, New Orleans, LA, January, 16, 2008.
4-35

Table 4-6. Major Sources of Geologic Sequestration Cost Information

Source Cost Categories

API Joint Association Survey of Drilling Costs Drilling costs in the U.S. for oil, gas, and dry holes by depth interval

EIA Oil and Gas Lease Equipment and Operating Cost Survey Surface equipment costs, annual operating costs, pump costs

Pipeline Prime Mover and Compressor Costs (FERC) Pumps

2008 Petroleum Services of Canada Well Cost Study (PSAC) Drilling costs, plugging costs, logging costs

Oil and Gas Journal Report on Pipeline and Cost Data

Reported to FERC Pipeline costs per inch-mile

Land Rig Newsletter Onshore rig day rates/ well cost algorithms

New Orleans Sequestration Technology Meeting, January, 2008 Monitor station costs in several categories; seismic costs

FutureGen Sequestration Site Submittals Monitoring station layout/number of stations

Preston Pipe Report Casing and tubing costs

Hourly Labor Rates U.S. Bureau of Labor Statistics

Selected Presentations and Papers (see below) Sensor costs, monitoring costs, number of stations, seismic costs

Significant Papers and Presentations With Cost Data

Benson, "Monitoring Protocols and Life Cycle Costs for Geologic Storage of Carbon Dioxide", Sept., 2004

IEA Greenhouse Gas Programme Report PH4/29, "Overview of Monitoring Requirements for Geologic Storage Projects, Nov., 2004.

Hoversten, "Investigation of Novel Geophysical Techniques for Monitoring CO2 Movement During Sequestration," Oct., 2003.

Dahowski, et al, " The Costs of Applying Carbon Dioxide Capture and Geologic Storage Technologies to Two Hypothetical

Coal to Liquids Production Configurations: A Preliminary Estimation," Pacific NW National Laboratory, September, 2007.

The assumed capital costs and the annual operating cost of the various monitoring

technologies whose application might be affected by the GS Reporting rule are shown in Table

4-9 and 4-10. The capital costs are annualized using a capital recovery factor of 0.186 for

projects lasting 7 years and 0.094 for projects lasting 20 years. The annual O&M costs are added

to the annualized capital costs to determine total annual direct costs. To this is added a 20

percent overhead and general and administrative cost factor to obtain total annual costs. These

are then divided by the amount assumed to be injected each year in the pro-forma project to

arrive at total costs per metric ton of CO2 injected. These per-ton costs are then used to estimate

total annual costs for the level of injection expected in the activity baseline.

4.4.3 Monitoring, Reporting, and Verification (MRV) Plan Requirements and Approval

Process

There are two types of sites that will report under Subpart RR, injection facilities and a

subset of injection facilities conducting GS (i.e. GS facilities). All sites will incur the periodic

sampling and testing costs, however only GS facilities will incur the monitoring plan related
4-36

costs. EPA proposes that GS facilities must develop an MRV plan, submit it to EPA for

approval, and implement it once approved by EPA to report the amount of CO2 that has been

sequestered. EPA is proposing that each submitted MRV plan must include at a minimum the

four requirements described below.

Step 1 – Assessment of Risk of Leakage: All potential pathways that may result in CO2

leakage have been identified and characterized and the risk of CO2 leakage at each pathway has

been evaluated;

Step 2 – Strategy for Detecting and Quantifying CO2 Leakage to Surface: Potential

pathways will be monitored according to the risk of CO2 leakage to ensure that any leakage to

the surface will be detected and that leakage to the surface, should it occur, will be quantified

according to a specified methodology;

Step 3 - Strategy for Establishing Pre-Injection Environmental Baselines: Environmental

baselines against which the monitoring results will be evaluated have been established at

potential leakage pathways; and

Step 4 - Tailor Mass Balance Equation: Site-specific variables have been considered and

developed for the mass balance equation provided in the regulatory text to calculate the amount

of CO2 sequestered.

Table 4-7. Unit Cost of Relevant Continuous and Periodic Monitoring Technologies

Item

Capital Cost to

Establish

Environmental Baseline

Capital Cost for

Construction and

Equipment Operating Cost

Deep Monitoring Wells

(into or right above

injection zone)

$200 lab fee per sample

plus $1,000 to collect. 4

samples per well is

$4,800 per well.

$20,000 + $5,000/well for

design, $10,000 per well for

surface disturbance, $165-

$200 per foot to build,

$20,000 for equipment

Annual O&M costs are

$25,000 + $3/ft per well per

year

CO2 Flow Meters on

Producing Oil and Gas

Wells

NA $10,000/ oil well Annual O&M costs are

$500 per well per year

CO2 Flow & Gas

Composition Meters on

Producing Oil and Gas

Wells

NA $50,000/ oil well Annual O&M costs are

$2,500 per well per year

Periodic Sampling and

Testing of Injected

Fluid

NA 12 hours @$107.23/hr =

$1,286 for plan

$200 lab fee per sample

plus $270 to collect.

Estimation of Fugitive

Emission from Surface

Facilities

NA

40 hours @$107.23/hr =

$4,289 for planning and initial

inventory of facilities

24 hours @$107.23/hr =

$2,574 for annual

calculations
4-37

Item

Capital Cost to

Establish

Environmental Baseline

Capital Cost for

Construction and

Equipment Operating Cost

Periodic Seismic

Surveys

Seismic survey baseline

established as part of site

characterization. No

extra cost for monitoring.

No construction costs, but

planning and quality

assurance costs would add

$25,000 per project.

$100,000 per square mile

Periodic Digital Color

Infrared Orthoimagery

(CIR) or Hyperspectral

Imaging to detect

changes to vegetation.

Initial survey before

injection commences

would establish baseline.

No construction costs, but

planning and quality

assurance costs would add

$10,000 per square mile.

Airborne survey costs $250

per linear mile. Assuming

interline spacing of 200-

250 feet, a square mile

would take about 25

passes and cost $6,250.

Plus mobilization costs of

$5,000 per site.

Periodic airborne

survey to detect

surface leaks. Works

best where vegetation

is sparse.

NA

No construction costs, but

planning and quality

assurance costs would add

$10,000 per square mile.

Airborne survey costs $250

per linear mile. Assuming

interline spacing of 200-

250 feet, a square mile

would take about 25

passes and cost $6,250.

Plus mobilization costs of

$5,000 per site.

Eddy covariance

measurement from

permanent towers to

detect surface leaks.

Establishing baseline is

$35,000 per station.

40 hours @$107.23/hr =

$4,289 for plan plus

$70,000/monitoring site.

$10,000 per station per

year

Soil zone monitoring

(sampling gas from

accumulation

chambers)

Initial survey before

injection commences

would establish baseline.

40 hours @$107.23/hr =

$4,289 for plan plus

$6,000/monitoring site

$200 lab fee per sample

plus $100 to collect.

Vadose zone

monitoring wells to

sample gas above

water table.

Initial survey before

injection commences

would establish baseline.

40 hours @$107.23/hr =

$4,289 for plan plus

$8,000/monitoring site

$200 lab fee per sample

plus $100 to collect.

 Monitoring wells for

samples from water

table.

Initial survey before

injection commences

would establish baseline.

40 hours @$107.23/hr =

$4,289 for plan plus

$80,000/monitoring site

$200 lab fee per sample

plus $1,000 to collect.
4-38

Table 4-8. Unit Cost of Relevant Episodic Monitoring Technologies (That may be

employed after a subsurface leak is detected)

Detection

Method

Method of

Quantification

Estimate of Unit Cost

for Leak Quantification

Cost per

Episode

Probability

of Detection

Method

Deployment

Additional

Annual

Cost per

Project for

Leak

Quantifica

tion

Surface leak

detected by air,

soil or water

table monitoring.

Detailed

seismic survey

plus reservoir

simulation to

estimate leak

volume at

subsurface to

help calibrate

leak volume

into

atmosphere

$100,00 per square

mile per survey. Leak

volume estimation

process 160 hours

@$110.62/hr.

$117,698 1.0% $1,177

Surface leak

detected by air,

soil or water

table monitoring

Tenting of area

to estimate leak

volume

Assume 30 minutes

per tent survey

location by two

technicians @$100/hr

each plus mobilization

costs of $5,000. If 640

locations are surveyed

(one per acre), cost is

$69,000 per square

mile. Leak volume

estimation process 80

hours @$110.62/hr.

$77,849 1.0% $778

Total per

Year

2.0% $1,955

Note: Assumes survey for leak occurs over one square mile area in each episode.

Project's area is 10 square miles.

4.5 Monitoring Technologies

Deep Monitoring Wells

Deep monitoring wells are typically drilled to monitor the deepest permeable zone above

the caprock. Downhole instrumentation can be used to monitor pressure, temperature, and

conductivity/salinity. Alternatively, U-tube devices can be used to retrieve pressurized samples

for laboratory testing. Other types of monitoring from wells include micro-seismic, cross-well

resistivity, and vertical seismic profiling.
4-39

CO2 Flow Meters on Producing Oil and Gas Wells

Meters, probably located after the wellhead separator, that continuously measure the

pressure, temperature and flow rate of the gas from a well. The composition of the gas is

analyzed periodically using a gas chromatograph to determine percent CO2 concentration. The

mass of CO2 passing through the wellhead can then be calculated from the measured quantities.

CO2 Flow and Gas Composition Meters on Producing Oil and Gas Wells

Meters, probably located after the wellhead separator, that continuously measure the

pressure, temperature, flow rate and chemical composition of the gas from a well. The mass of

CO2 passing through the wellhead can then be calculated from the measured quantities. This

differs from the item directly above in that the chemical composition of the gas is being

measured automatically by the meter itself rather through periodically obtaining a sample and

sending it to lab for analysis.

Periodic Sampling and Testing of Injected Fluid

All injection and GS facilities will incur periodic sampling and testing costs. To estimate

the costs, we have applied similar assumptions that were used in Subpart OO for sampling and

testing of industrial gases. For example, we have assumed that it takes 12 labor hours to contact

an onsite laboratory or offsite vendor and develop a plan; to collect and send the sample to an

onsite or offsite laboratory; and to provide data invoice if sent offsite. Furthermore, we have

assumed that it costs approximately $500 per sample to collect and conduct the test of chemical

composition. In addition to these costs, GS facilities will additionally incur the costs described in

this rule.

Seismic Surveys

Seismic data acquisition involves the generation and detection of sound waves to

evaluation conditions in the subsurface. Periodic acquisition of seismic data can be used to

detect subsurface CO2 movement within and outside of the reservoir.

Digital Color Infrared Ortho-imagery and Hyper-spectral Imaging

Digital color ortho-imagery and hyper-spectral imaging are airborne remote sensing

technologies that are used to detect changes in vegetation resulting from CO2 leaks.

Hyperspectral sensors look at objects using electromagnetic spectrum. The object is to detect a
4-40

specific spectral signature that is known to result from CO2 uptake. The advantage of these

methods is that they can efficiently cover a large surface area.

Airborne Survey (LIDAR)

LIDAR (Light Detection and Ranging) involves the transmission of light from an

instrument to a target and the recording of the reflected light to determine some property of the

target. Differential Absorption LIDAR (DIAL) uses two wavelengths of laser to measure CO2.

The wavelengths used are specific to CO2. One wavelength is selected to correspond to a CO2

spectral absorption line, while the other is a non-absorbing wavelength. The difference in

intensity of the two return signals is a measure of concentration.

Airborne Survey (CO2 Detectors)

CO2 detectors are commercially available for short closed-path and short open-path

(point) measurements and long open-path (radial line) measurements. Similar detectors have

been integrated into stationary, mobile, and airborne monitoring packages that are commonly

used in combination with high-resolution global positioning system (GPS) to detect and quantify

methane leaks in areas with road access. While these packages have not been widely tested for

CO2, various types of CO2 monitors are commercially available and could be used in these

applications. Such monitoring techniques are likely the leading candidates for monitoring plan

applications because of their low cost and high reliability. The technologies include infrared gas

analyzers (IRGAs, including Fourier transform infrared (FTIR) and non-dispersive infrared

(NDIR) analyzers), tunable diode lasers (TDLs), cavity ring down techniques, and others. The

sample path can range from 10 cm to 1 km, by reflecting a laser beam off retro-reflecting

mirrors. These devices measure the gas concentration, and, when packaged with measurements

of wind speed and wind direction, they measure the total gas flow.

Eddy Covariance

Eddy Covariance is a technique whereby high frequency measurements of atmospheric

CO2 concentration at a height above the ground are made by an infra-red gas analyzer along with

measurements of micro-meteorological variables such as wind velocity, direction, humidity, and

temperature. Integration of these data allows derivation of the net CO2 flux over the upwind

footprint, typically square meters to square kilometers in area.

Soil Zone Monitoring with Accumulation Chamber (AC)
4-41

Surface CO2 flux is measured using an accumulation chamber. The chamber is made of

stainless steel with an open bottom and is placed at the sampling location. It may be placed

either directly on the ground or on a collar installed in the ground surface. The air is circulated

through the AC and measured with and infra-red gas analyzer.

Vadose Zone Monitoring

The vadose zone is the relatively shallow zone beneath the soil zone that is not saturated

with groundwater. Small diameter probes are installed in the zone and samples are taken. The

CO2 concentration of air samples taken in this zone can be measured by and infrared gas

analyzer.

Monitoring Wells for Water Table Sampling

Shallow monitoring wells may be used to measure the properties of ground water. Such

wells are typically no deeper than several hundred feet.

Estimating Leak Volumes after a Leak is Detected

The monitoring program for GS facilities may detect subsurface leaks and it will be

necessary to estimate the volume of leaks to the surface to comply with the reporting

requirements of this rule. Each site operator will have to devise suitable techniques taking into

account the geology of the sites, the location and nature of the potential leaks and the

performance characteristics of available monitoring and measurement technologies.

It is expected that these estimates may include engineering estimates as well as some

direct measurement and may have a wide margin of uncertainty. It is expected that site

characterization and screening will lead to selection of sites that are suitable for long-term

sequestration and that incidences of leaks to the surface may be infrequent at well-selected and

well-managed sites. The cost estimates presented here for subsurface leak quantification assume

a two percent chance in one year that any given site will have to implement the leak

quantification strategy described in the site’s MRV plan. There are no operating statistics for

CO2 GS from which to draw any citable conclusions on how often leaks to the surface may be

detected, therefore a very conservative estimate was used in order to estimate the potential cost.
4-42

If the leak is detected in the subsurface (possibly by anomalous pressure readings in a

monitoring well) the leak volume may be estimated to help calibrate a leak volume to the

surface. Quantification is presumed to be done using engineering calculations supplemented,

when technically feasible, by direct observation/measurement using, for example, a 3-D seismic

survey over the area of the suspected leak. The seismic survey might be able to detect the

location, size and density of the CO2 plume formed by the leak in one or more containment zones

located above the injection zone. The volume of the leak also might be estimated using a

reservoir simulation model of the containment zone calibrated to the pressure readings of the

monitoring wells surrounding the location of the leak. In other words, different volumes of leaks

would be tested in the reservoir simulator to find which leak volume most closely matches the

pressure history observed in the surrounding monitoring wells.

Leaks may also be detected at or near the surface by air, soil gas and water table

monitoring devices. It is possible that some of the monitoring devices, such as eddy covariance,

could themselves be used to estimate leak volumes. Another possible way of estimating the

volume of a leak at the surface is to place a tent over the area of the leak. The tent would be

sealed at the ground by weights or spikes and a calibrated volume of gas such as nitrogen would

be introduced into the tent and allowed to escape through a chimney at the top of the tent. By

measuring the concentration of CO2 in the gases leaving the chimney it is possible to measure the

amount of CO2 leaving the ground in the area of the tent. The tent would have to be moved to

many locations and the process repeated to get a representative sample over the entire area of the

leak. It also would be necessary to correct the readings for natural CO2 fluxes into and out of the

soil.

Many of the leak detection methods for onshore GS sites can be applied to sub-seabed

sites. These include monitoring of the injection well and monitoring of the subsurface CO2

plume: active seismic, passive seismic, sensors in deep monitoring wells, and reservoir

modeling. Though there will be differences in monitoring approaches at sub-seabed GS sites for

leak detection and quantification, the cost estimates are assumed to be comparable.

Labor Rates

The cost of labor for many of the cost items in Table 4-9 and 4-10 and for General and

Administrative Costs are based on Society of Petroleum Engineers (SPE) 2008 annual salary

survey.

43 The average salary for a petroleum reservoir engineer with 15 years of experience is

43 For SPE survey of petroleum engineers see http://www.spe.org/spesite/spe/spe/career/salary_survey/08SalarySurveyHighlights.pdf
4-43

$143,800. Applying a 1.6 fringe and overhead factor yields an hourly burdened labor cost of

$110.62 per hour.

The unit costs values shown in Table 4-9 and 4-10 reflect the cost of goods and services

that would be purchased by the entity which owns the GS facility. That entity would have

additional General and Administrative Costs (G&A) on top of those direct costs for goods and

services. These G&A cost are assumed to 20 percent of the direct costs.

4.5.1 Cost Scenarios

There are three regulatory alternatives (low, medium [or reference], and high) presented

in Table 4-11 in terms of which monitoring devices would be used at a GS facility and how often

sampling and measurement would take place. Because each GS facility will have unique

characteristics that may result in the selection of different monitoring techniques, the application

of the monitoring devices are indicated as percents of sites that would be expected to use each

device or technique. Also shown in Table 5-4 are the portions of facilities that expected to be

required to use the device or technique under the UIC Class VI permits and under UIC Class II

permits. The cost impacts of the Rule RR are estimated as the monitoring and measurement

requirements above and beyond the UIC Class II requirements. 44

44 For the purposes of this proposed rule, costs incremental to Class II requirements were estimated for ER projects

conducting GS and costs incremental to the proposed Class VI requirements were estimated for all other GS

projects.
4-44

Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative

Saline, Abandoned Oil & Gas Fields: Starting

Point is UIC Class VI Requirements

ER plus GS: Starting Point is UIC Class II

Requirements

Under

UIC

Class VI

Lowest

Level RR

Alternative

Middle

Level RR

Alternative

Highest

Level RR

Alternative

Under

UIC

Class

II

Lowest

Level RR

Alternative

Middle

Level RR

Alternative

Highest

Level RR

Alternative

Fraction

Projects 100% 100% 100% 100% 0% 100% 100% 100%

Deep

Monitoring

Wells (into or

right above

injection

zone)

Frequency

(months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous

Fraction

Projects 0% 0% 0% 0% 0% 100% 100% 100%

CO2 Flow

Meters on

Producing Oil

and Gas

Wells

Frequency

(months) Continuous Continuous Continuous

Fraction

Projects 0% 0% 0% 0% 0% 0% 0% 0%

CO2 Flow &

Gas

Composition

Meters on

Producing Oil

and Gas

Wells

Frequency

(months) Continuous Continuous Continuous

Fraction

Projects

Periodic 100% 100% 100% 100% 100% 100% 100% 100%

Sampling and

Testing of

Injected Fluid

Frequency

(months) 3 3 3 3 3 3 3 3

Fraction

Projects 0% 0% 100% 100% 0% 0% 0% 0%

Estimation of

Fugitive

Emission

from Surface

Facilities

Frequency

(months) 12 12 12 12 12 12 12 12

Fraction

Projects Periodic 25% 25% 25% 25% 0% 25% 25% 25%

Seismic

Surveys Frequency

(months) 60 60 60 60 60 60 60 60

Fraction

Projects 0% 0% 50% 50% 0% 0% 50% 50%

Periodic

Digital Color

Infrared

Orthoimagery

(CIR) or

Hyperspectral

Imaging to

detect

changes to

vegetation.

Frequency

(months) 12 12 12 12 12 12 12 12
4-45

Table 4-9. Assumptions for Application of Technologies by Regulatory Alternative

(continued)

Saline, Abandoned Oil & Gas Fields: Starting

Point is UIC Class VI Requirements

ER plus GS: Starting Point is UIC Class II

Requirements

Under

UIC

Class VI

Lowest

Level RR

Alternative

Middle

Level RR

Alternative

Highest

Level RR

Alternative

Under

UIC

Class II

Lowest

Level RR

Alternative

Middle

Level RR

Alternative

Highest

Level RR

Alternative

Fraction

Projects 0% 0% 50% 50% 0% 0% 50% 50%

Periodic

LIDAR

airborne

survey to

detect

surface

leaks. Works

best where

vegetation is

sparse.

Frequency

(months) 12 12 12 12 12 12 12 12

Fraction

Projects 25% 25% 25% 100% 0% 25% 25% 100%

Eddy

covariance

measurement

from

permanent

towers to

detect

surface

leaks.

Frequency

(months) Continuous Continuous Continuous Continuous Continuous Continuous Continuous Continuous

Fraction

Projects 0% 0% 100% 100% 0% 0% 100% 100%

Soil zone

monitoring

(sampling

gas from

accumulation

chambers)

Frequency

(months) 12 12 12 3 12 12 12 3

Fraction

Projects 0% 0% 100% 100% 0% 0% 100% 100%

Vadose zone

monitoring

wells to

sample gas

above water

table.

Frequency

(months) 12 12 12 3 12 12 12 3

Fraction

Projects

 Monitoring 0% 0% 100% 100% 0% 0% 100% 100%

wells for

samples from

water table.

Frequency

(months) 12 12 12 3 12 12 12 3
4-46

4.6 Projecting and Discounting National Costs

The cost per project is computed by applying the cost algorithms (Table 4-5 and 4-8) to

the “pro-forma” characteristics assume for each type of project (Tables 4-3 to 4-5), “Pro-form

Project Characteristics.” The results for cost per project appear in the left-hand side of Table 4-

10 for the no additional ER opt in activity baseline scenario. Table 4-11 shows the results for the

anthropogenic ER opt in only activity scenario. Table 4-12 shows the results for the

anthropogenic plus one half of other ER opt in activity scenario.
4-47

Table 4-10. Summary of Cost Impacts: Activity Baseline with No Additional ER Opt In

Environmental Baseline Periodic Monitoring

Type

Capital

Costs

Annualized

Capital

Costs Capital Cost

Annual

Operating

Cost

Annualized Capital

and Contractor

Costs

Annual

Episodic

Monitoring

Costs

Overhead and

G&A

Total Annual

Costs

Per Project

Known R&D ER $0 $0 $1,286 $1,880 $2,119 $0 $424 $2,542

Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043

Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043

Known Commercial CO2 Injection

Facilities (No GS) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $0 $444,041 $2,664,244

Under

UIC Class

VI or II

GS Facilities (ER opt in) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known R&D ER $77,000 $14,288 $19,276,372 $941,680 $4,518,473 $3,442 $907,240 $5,443,443

Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390

Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390

Known Commercial CO2 Injection

Facilities (No GS) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $2,268 $444,494 $2,666,966

Low

GS Facilities (ER opt in) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known R&D ER $166,180 $30,835 $21,333,231 $1,088,360 $5,046,810 $3,442 $1,016,217 $6,097,304

Known R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514

Future R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514

Known Commercial CO2 Injection

Facilities (No GS) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known Commercial Saline $110,380 $10,419 $17,812,801 $763,334 $2,444,736 $2,268 $491,485 $2,948,909

Reference

GS Facilities (ER opt in) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known R&D ER $397,180 $73,698 $21,823,538 $1,249,400 $5,298,828 $3,442 $1,075,193 $6,451,161

Known R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694

Future R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694

Known Commercial CO2 Injection

Facilities (No GS) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381

Known Commercial Saline $262,630 $24,790 $18,135,958 $869,474 $2,581,380 $2,268 $521,688 $3,130,127

High

GS Facilities (ER opt in) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381
4-48

Table 4-11. Summary of Cost Impacts: Activity Baseline from only Anthropogenic ER Opt In

Environmental Baseline Periodic Monitoring

Type

Capital

Costs

Annualized

Capital

Costs Capital Cost

Annual

Operating

Cost

Annualized Capital

and Contractor

Costs

Annual

Episodic

Monitoring

Costs

Overhead and

G&A

Total Annual

Costs

Per Project

Known R&D ER $0 $0 $1,286 $1,880 $2,119 $0 $424 $2,542

Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043

Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043

Known Commercial CO2 Injection

Facilities (No GS) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $0 $444,041 $2,664,244

Under

UIC Class

VI or II

GS Facilities (ER opt in) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known R&D ER $77,000 $14,288 $19,276,372 $941,680 $4,518,473 $3,442 $907,240 $5,443,443

Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390

Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390

Known Commercial CO2 Injection

Facilities (No GS) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $2,268 $444,494 $2,666,966

Low

GS Facilities (ER opt in) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known R&D ER $166,180 $30,835 $21,333,231 $1,088,360 $5,046,810 $3,442 $1,016,217 $6,097,304

Known R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514

Future R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514

Known Commercial CO2 Injection

Facilities (No GS) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known Commercial Saline $110,380 $10,419 $17,812,801 $763,334 $2,444,736 $2,268 $491,485 $2,948,909

Reference

GS Facilities (ER opt in) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known R&D ER $397,180 $73,698 $21,823,538 $1,249,400 $5,298,828 $3,442 $1,075,193 $6,451,161

Known R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694

Future R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694

Known Commercial CO2 Injection

Facilities (No GS) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381

Known Commercial Saline $262,630 $24,790 $18,135,958 $869,474 $2,581,380 $2,268 $521,688 $3,130,127

High

GS Facilities (ER opt in) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381
4-49

Table 4-12. Summary of Cost Impacts: Activity Baseline from Anthropogenic CO2 plus One-half of Other ER Opt In

Environmental Baseline Periodic Monitoring

Type

Capital

Costs

Annualized

Capital

Costs Capital Cost

Annual

Operating

Cost

Annualized Capital

and Contractor

Costs

Annual

Episodic

Monitoring

Costs

Overhead and

G&A

Total Annual

Costs

Per Project

Known R&D ER $0 $0 $1,286 $1,880 $2,119 $0 $424 $2,542

Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043

Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $0 $185,174 $1,111,043

Known Commercial CO2 Injection

Facilities (No GS) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $0 $444,041 $2,664,244

Under

UIC Class

VI or II

GS Facilities (ER opt in) $0 $0 $1,286 $1,880 $2,001 $0 $400 $2,402

Known R&D ER $77,000 $14,288 $19,276,372 $941,680 $4,518,473 $3,442 $907,240 $5,443,443

Known R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390

Future R&D Saline $7,438 $1,380 $4,122,722 $159,505 $924,489 $1,955 $185,565 $1,113,390

Known Commercial CO2 Injection

Facilities (No GS) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known Commercial Saline $50,750 $4,790 $16,452,855 $662,380 $2,215,413 $2,268 $444,494 $2,666,966

Low

GS Facilities (ER opt in) $35,000 $3,304 $8,584,225 $420,680 $1,230,970 $1,955 $247,246 $1,483,475

Known R&D ER $166,180 $30,835 $21,333,231 $1,088,360 $5,046,810 $3,442 $1,016,217 $6,097,304

Known R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514

Future R&D Saline $18,310 $3,397 $4,325,685 $180,764 $983,409 $1,955 $197,752 $1,186,514

Known Commercial CO2 Injection

Facilities (No GS) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known Commercial Saline $110,380 $10,419 $17,812,801 $763,334 $2,444,736 $2,268 $491,485 $2,948,909

Reference

GS Facilities (ER opt in) $76,900 $7,259 $9,519,161 $490,080 $1,388,621 $1,955 $279,567 $1,677,403

Known R&D ER $397,180 $73,698 $21,823,538 $1,249,400 $5,298,828 $3,442 $1,075,193 $6,451,161

Known R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694

Future R&D Saline $40,623 $7,538 $4,373,045 $196,319 $1,007,751 $1,955 $203,449 $1,220,694

Known Commercial CO2 Injection

Facilities (No GS) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381

Known Commercial Saline $262,630 $24,790 $18,135,958 $869,474 $2,581,380 $2,268 $521,688 $3,130,127

High

GS Facilities (ER opt in) $181,900 $17,170 $9,742,028 $563,280 $1,482,859 $1,955 $300,397 $1,802,381
4-50

4.7 Other Recordkeeping and Reporting Costs

Additional recordkeeping ($1,700 per entity) and reporting ($500) costs per field were

also added to each project type.

4.8 Public Sector Burden

EPA estimates the public sector burden to be $344,000 per year; $55,000 per year is for

verification activities, and remaining costs are for program implementation and developing and

maintaining the data collection system. Program implementation activities include, but are not

limited to, evaluating monitoring plans, developing guidance and training materials to assist the

regulated community, responding to inquires from affected facilities on monitoring and

applicability requirements, and developing tools to assist in determining applicability.
5-51

SECTION 5

ECONOMIC IMPACT ANALYSIS

EPA prepares an EIA to provide decision makers with a measure of the social costs of

using resources to comply with a program (EPA, 2000). As noted in EPA’s (2000) Guidelines

for Preparing Economic Analyses, several tools are available to estimate social costs and range

from simple direct compliance cost methods to the development of a more complex market

analysis that estimates market changes (e.g., price and consumption) and economic welfare

changes (e.g., changes in consumer and producer surplus). Given data limitations and the size

scope of the proposed rule, EPA has used the direct compliance cost method as a measure of

social costs45.

5.1 Threshold Analysis

EPA considered both a threshold based on the amount of CO2 emitted and a threshold

based on the amount of CO2 injected underground. EPA concluded that an emissions-based

threshold would be problematic because of the lack of data on the incidence and scale of surface

emissions and leakage from injection and GS of facilities. EPA accordingly analyzed injection

facilities based on the quantity of CO2 injected underground and considered whether an injection

threshold should apply. EPA evaluated a no threshold option (i.e., all facilities that inject CO2

would be required to report), 1,000 metric tons per year, 10,000 metric tons per year, 25,000

metric tons per year, and 100,000 metric tons per year per facility of CO2 injected. The results of

the threshold analysis are presented below in Table 5-1. For further information on the

assumptions underlying the threshold analysis, please refer to the general technical support

document (TSD) for this proposal.46

45 See pages 124 and 125 (EPA, 2000).

46 Subpart RR General TSD (see docket ID No. EPA-HQ-OAR-2009-0926)
5-52

Table 5-1 CO2 Injection Facilities: Effect of Injection Threshold on Reported Amount of

CO2 Injected and Number of Facilities Required to Report

Amount of CO2

Injected

Number of

Facilities Threshold Level

(metric tons/yr of

CO2 injected)

Total National

(metric tons/yr

of CO2

injected)

Total

Number

of U.S.

Facilities

Metric

tons/yr of

CO2

Injected

Percent

Covered Number PercentCovered

All In 40,111,639 80 40,111,639 100.0% 80 100.0%

1,000 40,111,639 80 40,111,115 100.0% 74 92.5%

10,000 40,111,639 80 40,099,065 100.0% 71 88.8%

25,000 40,111,639 80 40,005,238 100.0% 65 81.3%

100,000 40,111,639 80 39,065,039 97.4% 48 60.0%

EPA is proposing that all CO2 injection facilities would be required to report the

minimum information in subpart RR (quantity of CO2 injected, quantity of CO2 transferred

onsite from offsite, and source of the CO2 if known) at no threshold. An all-in reporting

threshold would allow the Agency to comprehensively track all CO2 supply (as reported in

Suppliers of CO2, subpart PP) that is injected underground. This approach is consistent with the

all-in requirements in the MRR for suppliers of petroleum, natural gas, and coal-to-liquid

products (subparts LL, MM, and NN), producers of industrial gases (subpart OO), and suppliers

of CO2 (subpart PP). It was reasonable to require all of the facilities in these source categories to

report because it would result in the most comprehensive accounting possible, simplify the rule,

and permit facilities to quickly determine whether or not they must report; the same rationale

applies for this source category proposed today. Furthermore, it would create a uniform burden

for all covered facilities, ensuring a level playing field in, and preventing fragmentation of, the

ER sector. EPA has estimated the cost for CO2 injection facilities to comply with the minimum

reporting requirements in this proposed rule and has determined that the burden would be small,

given the equipment and data collection efforts already in place at ER projects.

Under this action, EPA is proposing that the subset of CO2 injection facilities that are

conducting GS (i.e. a GS facility) must report to EPA a second tier of data. EPA considered

whether a threshold should apply to this second tier of data given that it would place a reporting

burden on GS facilities. However, EPA could not perform an analysis on GS facilities based on

emissions without data on actual or expected GS facility emissions. EPA also could not perform

a threshold analysis based on injection due to the uncertainty around predictions of injection

quantities for potential GS facilities. In addition, it is difficult to predict how many injection
5-53

facilities would choose to report GS. Therefore, EPA is proposing to exempt GS R&D projects

but otherwise require all GS facilities to comply with the GS monitoring, reporting, and

verification requirements of subpart RR, and that they report fugitive, vented, and combustion

emissions from surface equipment (under subpart W, RR, or C, as applicable). An all-in

threshold will allow EPA to work with the early-movers of this nascent industry and to

strengthen EPA’s understanding of GS.

5.2 National Cost Estimates

The total annualized costs incurred under the rule by these entities would be

approximately $713,000 (in 2008$). This includes a public sector burden estimate of $344,000

for program implementation and verification activities. The typical annual cost for a CO2

injection facility with no GS is $4,000 per year.

Table 5-2. National Annualized Mandatory Reporting Costs Estimates: Subpart RR

Type Number

Metric Tons

CO2 Injected

per Year

Total Annual Cost

(thousand, 2008$)

R&D 9 5,320,000 $37

CO2 Injection Facilities (No GS)a80 36,815,442 $332

Private Sector, Total All Projects 89 45,435,442 $369

Private Sector, Average ($/ton) $0.01

Public Sector, Total $344

National Total $713

a

Includes Class II ER projects

Given uncertainties related to project adoption and the costs of the reporting program,

EPA also considered two other private costs scenarios (one higher and one lower than the

reference cost scenario) in order to assess a range of economic impacts on affected entities

(Table 5-3).

Table 5-3. Annualized Mandatory Reporting Costs per Project (2008$): Subpart RR

Average

Alternative Cost Scenarios

Type

Reference

($1,000)

Low

($1,000)

High

($1,000)

GS Facilities (commercial saline) $289 $7 $470

GS Facilities (ER opt in) $1,679 $1,485 $1,804

CO2 Injection Facilities (No GS)a$4 $4 $4

a

Includes Class II ER projects
5-54

5.2.1 National Cost Estimates Under Alternative GS Facilities (ER opt in) Outcomes

 Currently, the number of ER operations that would choose to report as GS Facilities (ER

opt in) is unknown and EPA could not identify any information or analysis to estimate this

quantity. As a result, two additional scenarios of the have been considered to represent medium

and high outcomes. As shown in Tables 5-4, national cost estimate is $24 million under the

medium ER opt in outcome. As shown in Tables 5-5, national cost estimate is $79 million under

the high ER opt in outcome.

Table 5-4. National Annualized Mandatory Reporting Costs Estimates (2008): All

Anthropogenic CO2 Projects

Type Number

Metric Tons

CO2 Injected

per Year

Total Annual Cost

(thousand, 2008$)

R&D 9 5,320,000 $37

GS Facilities (ER opt in) 16 6,972,040 $23,423

CO2 Injection Facilities (No GS)a64 33,143,402 $266

Private Sector, Total All Projects 89 45,435,442 $23,726

Private Sector, Average ($/ton) $0.52

Public Sector, Total $344

National Total $24,069

a

Includes Class II ER projects

Table 5-5. National Annualized Mandatory Reporting Costs Estimates (2008$): All

Anthropogenic 50 Percent of Other CO2 Projects

Type Number

Metric Tons

CO2 Injected

per Year

Total Annual Cost

(thousand, 2008$)

R&D 9 5,320,000 $37

GS Facilities (ER opt in) 48 23,543,741 $79,071

CO2 Injection Facilities (No GS)a32 16,571,701 $133

Private Sector, Total All Projects 89 45,435,442 $79,241

Private Sector, Average ($/ton) $1.74

Public Sector, Total $344

National Total $79,585

a

Includes Class II ER projects
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5.2.2 National Cost Estimates Under Alternative GS Facilities (Commercial Saline)

Outcomes

EPA considered two additional scenarios of the number of large scale saline aquifer GS

(commercial saline) project deployment over the next 25 years: low (3 projects), medium (6

projects), and high (9 projects). The medium scenario is based on large scale saline project

deployment projected in the cost analysis prepared for the UIC Class VI rule proposed on July

25, 2008 (73 FR 43492 ). The national cost estimates estimate increase $867,000 under the low

outcome; $1.7 million under the medium outcome, and $2.6 million under the high outcome.

5.3 Economic Impact Analysis

EPA assessed how the regulatory program may influence the profitability of companies

by comparing the monitoring program costs to total sales (i.e., a “sales” test). Given limited data

on commercial geological sequestration operations, EPA restricted the analysis to ER operations.

As shown in Table 5-2, ER activities account for approximately 90 percent of the project

population. To do this, we divided the average annualized mandatory reporting costs per field by

the estimated revenue for a representative field.

Sales Test Ratio= Average Cost (Table 5-3)/Estimated revenue (Table 5-6)

5.3.1 Revenue Estimate for a Representative Commercial ER Operation

EPA obtained national production statistics from the latest Department of Energy report

about CO2 ER Technologies (DOE, 2009). Data suggest a typical operation produces

approximately 776,000 barrels of oil per year. Using the DOE choice of an average long-term

price of oil ($70), EPA estimated total revenue of $54.3 million per year. To enhance the

transparency of the calculation, we provide data, sources, and methods in Table 5-6.

Table 5-6. Estimated Annual Revenue for a Representative Commercial ER Field

Operation (2008)

Label Variable Value Source and Calculation Method

A Barrels Per Day 250,000 DOE, 2009 p: 19

B Barrels per year 77,562,500 A × 0.85 × 365

C Population 100 DOE, 2009 p: 19

D Average Barrels per year 775,625 B / C

E Price per barrel $70 DOE, 2009 p: 2

F

Total Revenue

 ($ milliion) $54 D× E

Source: EPA calculations using data from DOE (2009). Storing CO2 and Producing Domestic Crude Oil with Next Generation

CO2-ER Technology, accessed October 28, 2009.
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5.3.2 Sales Test Results

As shown in Table 5-7 sales test ratios are between 3.1 to 3.3 percent for GS facilities (ER

opt in). In contrast, CO2 injection facilities (no GS, which includes Class II ER operations) sales

test ratios are below 0.01 percent.

Table 5-7. Sales Tests for Representative Commercial ER Field Operations

Cost-to-Sales Ratios (CSRs)

Alternative Cost Scenarios

Type Reference Low High

GS Facilities (ER opt in) 3.1% 2.7% 3.3%

CO2 Injection Facilities (No GS)a<0.01% <0.01% <0.01%

a

Includes Class II ER operations

5.4 Assessing Economic Impacts on Small Entities

The first step in this assessment was to determine whether the rule will have a significant

impact on a substantial number of small entities (SISNOSE). To make this determination, EPA

used a screening analysis that allows us to indicate whether EPA can certify the rule as not

having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

 selecting and describing the measures and economic impact thresholds used in the

analysis, and

 determining SISNOSE certification category.

5.4.1 Identify Affected Sectors and Entities

For the purposes of assessing the impacts of the rule on small entities, we defined a small

entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 121.201; (2) a

small governmental jurisdiction that is a government of a city, county, town, school district, or

special district with a population of less than 50,000; or (3) a small organization that is any notfor-profit enterprise that is independently owned and operated and is not dominant in its field.

For the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small

entity is defined as a small business as defined by the Small Business Administration’s

regulations at 13 CFR 121.201; according to these size standards, ultimate parent companies
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owning oil and gas extraction operations (NAICS 211) are categorized as small if the total

number of employees at the firm is fewer than 500.

The Oil & Gas Journal publishes a list of companies owning active U.S. CO2 ER projects

in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases

suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees.

EPA continues to collect other information about corporate structures of these 9 companies to

assess whether these companies are owned by larger parent companies.

5.4.2 Develop Small Entity Economic Impact Measures

The sales test examined the average total annualized mandatory reporting costs per ER

field to a representative measure of revenue. Details are provided in section 5.3.

5.4.3 Results of Screening Analysis

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will

not have a significant economic impact on a substantial number of small entities.

After considering the economic impact of the rule on small entities, EPA has concluded

that this action will not have a significant economic impact on a substantial number of small

entities. Currently EPA believes small ER operations will most likely be CO2 injection facilities

(no GS), including Class II ER projects. The average ratio of annualized reporting program costs

to revenues of a typical ER operation likely owned by representative small enterprises is less

than 1%.

Although this rule will not have a significant economic impact on a substantial number of

small entities, EPA nonetheless took several steps to reduce the impact of this rule on small

entities. For example, EPA is proposing monitoring and reporting requirements that build off of

the UIC program. In addition, EPA is proposing equipment and methods that may already be in

use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting

instead of more frequent reporting.

In addition to the public hearing that EPA plans to hold, EPA has an open door policy,

similar to the outreach conducted during the development of the proposed and final Mandatory

GHG Reporting Rule. Details of these meetings are available in the docket (EPA-HQ-OAR2009-0926).
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5.5 Characterization of Benefits of Subpart RR of the Mandatory Reporting Rule

EPA examined the potential benefits of the Carbon Dioxide Injection and Geologic

Sequestration Reporting Rule. EPA’s previous analysis of the GHG reporting rule discussed the

benefits of a reporting system with respect to policy making relevance, transparency issues, and

market efficiency. Instead of a quantitative analysis of the benefits, EPA conducted a systematic

literature review of existing studies including government, consulting, and scholarly reports.

A mandatory reporting system will benefit the public by increased transparency of

facility GHG data. Transparent, public data on GHGs allows for accountability of polluters to

the public stakeholders who bear the cost of the pollution. Citizens, community groups, and

labor unions have made use of data from Pollutant Release and Transfer Registers to negotiate

directly with polluters to lower emissions, circumventing greater government regulation.

Publicly available emissions data also will allow individuals to alter their consumption habits

based on the GHG emissions of producers.

The greatest benefit of mandatory reporting of GHGs to government will be realized in

developing future GHG policies. For example, in the EU’s Emissions Trading System, a lack of

accurate monitoring at the facility level before establishing CO2 allowance permits resulted in

allocation of permits for emissions levels an average of 15 percent above actual levels in every

country except the United Kingdom.

Benefits to industry of GHG monitoring include the value of having independent,

verifiable data to present to the public to demonstrate appropriate environmental stewardship,

and a better understanding of their emission levels and sources to identify opportunities to reduce

emissions. Such monitoring allows for inclusion of standardized GHG data into environmental

management systems, providing the necessary information to achieve and disseminate their

environmental achievements.

Standardization will also be a benefit to industry, once facilities invest in the institutional

knowledge and systems to report GHG data, the cost of monitoring should fall and the accuracy

of the accounting should improve. A standardized reporting program will also allow for

facilities to benchmark themselves against similar facilities to understand better their relative

standing within their industry.

Data on CO2 injection and GS are critical to informing CAA GHG policies. This data

would provide information and transparency on the amount of CO2 injected and geologically

sequestered in the United States and, in combination with other subparts of the MRR, would
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enable EPA to track the flow of CO2 across a CCS system. In addition, this information would

enable EPA to monitor the growth and efficacy of GS (and therefore CCS) as a GHG mitigation

technology over time and to evaluate relevant policy options. For example, EPA would be able

to track whether incentives or regulations are needed to encourage faster or further GS project

development. EPA would also be able to track whether ER sites are reporting GS and consider

whether incentives or regulations are needed. Where ER facilities are reporting GS, EPA would

be able to evaluate ER as a potentially non-emissive end use. In combination with subpart PP,

EPA would be able to reconcile this data with CO2 supplied in order to better understand the

quantity of CO2 supplied to emissive and non-emissive end uses.
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SECTION 6

STATUTORY AND EXECUTIVE ORDER REVIEWS

This section describes EPA’s compliance with several applicable executive orders and

statutes during the development of the proposed Carbon Dioxide Injection and Geologic

Sequestration Reporting Rule, subpart RR under Track II of the GHG reporting rule.

6.1 Executive Order 12866: Regulatory Planning and Review

Under Section 3(f)(1) of Executive Order 12866 (58 FR 51735, October 4, 1993), this

proposed action is not by itself an “economically significant regulatory action” because it is

unlikely to have an annual economic effect of less than $100 million. EPA’s cost analysis,

presented in Section 4 of the Economic Impact Analysis (EIA), estimates that for the minimum

reporting under the recommended regulatory option, the total annualized cost of the rule will be

approximately 713,000 (in 2008$) during the first year of the program and $713,000 in

subsequent years (344,000 of programmatic costs to the Agency). This proposed action adds

Subpart RR to the mandatory GHG reporting rule, which was a significant regulatory action.

Thus, EPA has chosen to analyze the impacts of Subpart RR as if it were significant. EPA

submitted this proposed action to the Office of Management and Budget (OMB) for review

under Executive Order 12866, and any changes made in response to OMB recommendations

have been documented in the docket for this proposed action.

In addition, EPA prepared this EIA, including an analysis of the potential costs associated

with this action. In this report, EPA has identified the regulatory options considered, their costs,

the emissions that would likely be reported under each option, and explained the selection of the

option chosen for the rule. The costs of the rule are reported in Section 4, and the economic

impacts and qualitative benefits assessment are reported in Section 5. Overall, EPA has

concluded that the costs of the Carbon Dioxide Injection and Geologic Sequestration Reporting

Rule are outweighed by the potential benefits of more comprehensive information about CO2

injection.

6.2 Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for

approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act,

44 U.S.C. 3501 et seq. The Information Collection Request (ICR) document prepared by EPA

has been assigned EPA ICR number 2372.01

EPA has identified the following goals of the mandatory GHG reporting system:
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 Obtain data that is of sufficient quality that it can be used to analyze and inform

the development of a range of future climate change policies and potential

regulations.

 Balance the rule’s coverage to maximize the amount of emissions reported while

excluding small emitters.

 Create reporting requirements that are, to the extent possible and appropriate,

consistent with existing GHG reporting programs in order to reduce reporting burden

for all parties involved.

The information from CO2 injection and geologic sequestration facilities will allow EPA

to make well-informed decisions about whether and how to use the CAA to regulate these

facilities and encourage voluntary reductions. Because EPA does not yet know the specific

policies that will be adopted, the data reported through the mandatory reporting system should be

of sufficient quality to inform policy and program development. Also, consistent with the

Appropriations Act, the reporting rule covers a broad range of sectors of the economy.

This information collection is mandatory and will be carried out under CAA Sections

114. Information identified and marked as Confidential Business Information (CBI) will not be

disclosed except in accordance with procedures set forth in 40 CFR Part 2. However, emissions

information collected under CAA Sections 114 generally cannot be claimed as CBI and will be

made public.47

The projected average ICR cost and respondent burden is $0.8 million and 4,510 hours

per year. The estimated average annual burden per response is 6.8 hours; the frequency of

response is annual for all respondents that must comply with the rule’s reporting requirements,

except for electricity-generating units that are already required to report quarterly under 40 CFR

Part 75 (ARP); and the estimated average number of likely respondents per year is 89. The cost

burden to respondents resulting from the collection of information includes the total capital and

start-up cost annualized over the equipment’s expected useful life (averaging $0.1 million per

year) a total operation and maintenance component (averaging $0.3 million per year), and a labor

cost component (averaging $0.3 million per year). Burden is defined at 5 CFR Part 1320.3(b).

These cost numbers differ from those shown elsewhere in the EIA because ICR costs

represent the average cost over the first three years of the rule, but costs are reported elsewhere

47 Although CBI determinations are usually made on a case-by-case basis, EPA has issued guidance in an earlier

Federal Register notice on what constitutes emissions data that cannot be considered CBI (956 FR 7042 – 7043,

February 21, 1991). As discussed in Section II.R of the preamble to the rule, EPA will be initiating a separate

notice and comment process to make CBI determinations for the data collected under this proposed rulemaking.
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in the EIA for the first year of the rule. Also, the total cost estimate of the rule in the EIA

includes the cost to the Agency to administer the program. The ICR differentiates between

respondent burden and cost to the Agency.

An agency may not conduct or sponsor, and a person is not required to respond to, a

collection of information unless it displays a currently valid OMB control number. The OMB

control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR Part 9. When this ICR is

approved by OMB, the Agency will publish a technical amendment to 40 CFR part 9 in the

Federal Register to display the OMB control number for the approved information collection

requirements contained in the final rule.

6.3 Regulatory Flexibility Act

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will

not have a significant economic impact on a substantial number of small entities. Small entities

include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.

The first step in this assessment was to determine whether the rule will have a significant

impact on a substantial number of small entities (SISNOSE). To make this determination, EPA

used a screening analysis that allows us to indicate whether EPA can certify the rule as not

having a SISNOSE. The elements of this analysis included

 identifying affected sectors and entities,

 selecting and describing the measures and economic impact thresholds used in the

analysis, and

 determining SISNOSE certification category.

6.3.1 Identify Affected Sectors and Entities

For the purposes of assessing the impacts of the rule on small entities, we defined a small

entity as (1) a small business, as defined by SBA’s regulations at 13 CFR Part 121.201; (2) a

small governmental jurisdiction that is a government of a city, county, town, school district, or

special district with a population of less than 50,000; or (3) a small organization that is any notfor-profit enterprise that is independently owned and operated and is not dominant in its field.

For the Carbon Dioxide Injection and Geologic Sequestration Reporting Rule, small

entity is defined as a small business as defined by the Small Business Administration’s

regulations at 13 CFR 121.201; according to these size standards, ultimate parent companies
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owning oil and gas extraction operations (NAICS 211) are categorized as small if the total

number of employees at the firm is fewer than 500.

The Oil & Gas Journal publishes a list of companies owning active U.S. CO2 ER projects

in 2008 (OGJ, 2008). EPA’s initial review of publicly available sales and employment databases

suggest up to 9 of the 23 companies listed in the OGJ survey have fewer than 500 employees.

EPA continues to collect other information about corporate structures of these 9 companies to

assess whether these companies are owned by larger parent companies.

6.3.2 Develop Small Entity Economic Impact Measures

These sales test examined the average total annualized mandatory reporting costs per ER

field to a representative measure of revenue. Details are provided in section 5.3.

6.3.3 Results of Screening Analysis

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will

not have a significant economic impact on a substantial number of small entities.

After considering the economic impact of the rule on small entities, EPA has concluded

that this action will not have a significant economic impact on a substantial number of small

entities. Currently EPA believes small ER operations will most likely be CO2 injection facilities

(no GS), including Class II ER projects. As shown in Table 5-7, the average ratio of annualized

reporting program costs to revenues of a typical ER operation likely owned by model small

enterprises was less than 1%.

Although this rule will not have a significant economic impact on a substantial number of

small entities, EPA nonetheless took several steps to reduce the impact of this rule on small

entities. For example, EPA is proposing monitoring and reporting requirements that build off of

the UIC program. In addition, EPA is proposing equipment and methods that may already be in

use by a facility for compliance with its UIC permit. Also, EPA is requiring annual reporting

instead of more frequent reporting.

In addition to the public hearing that EPA plans to hold, EPA has an open door policy,

similar to the outreach conducted during the development of the proposed and final Mandatory

GHG Reporting Rule. Details of these meetings are available in the docket (EPA-HQ-OAR2008-0508).
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6.4 Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), P.L. 104-4, establishes

requirements for federal agencies to assess the effects of their regulatory actions on state, local,

and tribal governments and the private sector. Under Section 202 of the UMRA, EPA generally

must prepare a written statement, including a cost-benefit analysis, for final rules with “federal

mandates” that may result in expenditures to state, local, and tribal governments, in the

aggregate, or to the private sector, of $100 million or more in any one year.

This proposed rule does not contain a Federal mandate that may result in expenditures of

$100 million or more for State, local, and tribal governments, in the aggregate, or the private

sector in any one year. Overall, EPA estimates that the total annualized costs of this proposed

rule are approximately $713,000 per year. Thus, this proposed rule is not subject to the

requirements of sections 202 or 205 of UMRA.

This proposed rule is also not subject to the requirements of section 203 of UMRA

because it contains no regulatory requirements that might significantly or uniquely affect small

governments. Facilities subject to the proposed rule include facilities that inject CO2 for

enhanced recovery of crude oil, and those that sequester CO2. None of the facilities currently

known to undertake these activities are owned by small governments.

6.5 Executive Order 13132: Federalism

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires

EPA to develop an accountable process to ensure “meaningful and timely input by state and local

officials in the development of regulatory policies that have federalism implications.” “Policies

that have federalism implications” is defined in the executive order to include regulations that

have “substantial direct effects on the states, on the relationship between the national government

and the states, or on the distribution of power and responsibilities among the various levels of

government.”

This proposed rule does not have federalism implications. It will not have substantial

direct effects on the states, on the relationship between the national government and the states, or

on the distribution of power and responsibilities among the various levels of government, as

specified in Executive Order 13132.

This regulation applies to public- or private-sector facilities that inject GHG

underground. Few government facilities would be affected. This regulation also does not limit
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the power of states or localities to collect GHG data and/or regulate GHG emissions. Thus,

Executive Order 13132 does not apply to this proposed rule.

In the spirit of Executive Order 13132, and consistent with EPA policy to promote

communications between EPA and State and local governments, EPA specifically solicits

comment on this proposed action from State and local officials.

6.6 Executive Order 13175: Consultation and Coordination with Indian Tribal

Governments

Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal

Governments” (59 FR 22951, November 6, 2000), requires EPA to develop an accountable

process to ensure “meaningful and timely input by tribal officials in the development of

regulatory policies that have tribal implications.”

This proposed rule is not expected to have tribal implications, as specified in Executive

Order 13175. This regulation applies to facilities that facilities that inject GHG underground.

Few facilities expected to be affected by the rule are likely to be owned by tribal governments.

Thus, Executive Order 13175 does not apply to this proposed rule.

Although Executive Order 13175 does not apply to this proposed rule, EPA sought

opportunities to provide information to tribal governments and representatives during

development of the MRR rule. In consultation with EPA’s American Indian Environment Office,

EPA’s outreach plan for the MRR included tribes. For a complete list of tribal contacts, see the

“Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,” in

the Docket for this proposed rulemaking (EPA-HQ-OAR-2008-0508-055). In addition to the

consultation activities supporting the MRR, EPA continues to provide information to tribal

governments and representatives during development of the Track II rules such as this proposed

rulemaking. EPA specifically solicits additional comment on this proposed action from tribal

officials.

6.7 Executive Order 13045: Protection of Children from Environmental Health and

Safety Risks

EPA interprets Executive Order 13045 (62 F.R. 19885, April 23, 1997) as applying only

to those regulatory actions that concern health or safety risks, such that the analysis required

under Section 5-501 of the executive order has the potential to influence the regulation. This

action is not subject to Executive Order 13045 because it does not establish an environmental

standard intended to mitigate health or safety risks.
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6.8 Executive Order 13211: Actions that Significantly Affect Energy Supply,

Distribution, or Use

This proposed rule is not a “significant energy action” as defined in Executive Order

13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect

on the supply, distribution, or use of energy. Further, we have concluded that this proposed rule

is not likely to have any adverse energy effects.

This proposal relates to monitoring, reporting, and recordkeeping at facilities that directly

inject CO2 for enhanced recovery of oil or geologic sequestration; it does not adversely affect

energy supply, distribution or use. Therefore, we conclude that this proposed rule is not likely to

have any adverse effects on energy supply, distribution, or use.

6.9 National Technology Transfer Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act of 1995

(NTTAA), Public Law No. 104-113 (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, with explanations when the Agency decides not to use available and

applicable voluntary consensus standards.

This proposed rulemaking involves technical standards. EPA proposes to use voluntary

consensus standards from six different voluntary consensus standards bodies: American Society

for Testing and Material (ASTM), American Society of Mechanical Engineers (ASME),

International Organization for Standardization (ISO), Gas Processors Association (GPA),

American Gas Association (AGA), and American Petroleum Institute (API). These voluntary

consensus standards will help facilities monitor, report, and keep records of GHG emissions

associated with their CO2 injection and geologic sequestration activities. No new test methods

were developed for this proposed rule. Instead, from existing rules for source categories and

voluntary GHG programs, EPA identified existing means of monitoring, reporting, and keeping

records. The existing methods (voluntary consensus standards) include a broad range of

measurement techniques, methods to measure gas or liquid flow, and methods to gauge and

measure petroleum and petroleum products. The test methods are incorporated by reference into

the rule and are available as specified in Section 98.6 of subpart A.
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By incorporating voluntary consensus standards into this proposed rule, EPA is both

meeting the requirements of the NTTAA and presenting multiple options and flexibility for

complying with the proposed rule. EPA welcomes comments on this aspect of the proposed

rulemaking and, specifically, invites the public to identify potentially-applicable voluntary

consensus standards and to explain why such standards should be used in this proposed

regulation.

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

Minority Populations and Low-Income Populations

Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive

policy on environmental justice. Its main provision directs federal agencies, to the greatest extent

practicable and permitted by law, to make environmental justice part of their mission by

identifying and addressing, as appropriate, disproportionately high and adverse human health or

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States.

EPA has determined that this proposed rule will not have disproportionately high and

adverse human health or environmental effects on minority or low-income populations because it

does not affect the level of protection provided to human health or the environment. This

proposed rule does not affect the level of protection provided to human health or the

environment because it is a rule addressing information collection and reporting procedures.
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SECTION 7

CONCLUSIONS

EPA is proposing to add Subpart RR to the existing Mandatory Reporting of Greenhouse

Gases Program established under 40 CFR 98 to track the fate of CO2 injected underground and

confirm CO2 sequestration volumes. The proposed approach is tiered. First, a set of reporting

requirements is proposed to cover facilities that inject CO2 underground regardless of the

purpose of injection. Second, a subset of facilities that inject CO2 and conduct geologic

sequestration (GS) are subject to an additional set of requirements.

7.1 Summary of Selected Regulatory Alternative

EPA is proposing that all CO2 injection facilities would be required to report the

minimum information in subpart RR (quantity of CO2 injected, quantity of CO2 transferred

onsite from offsite, and source of the CO2 if known) at no threshold. An all-in reporting

threshold would allow the Agency to comprehensively track all CO2 supply (as reported in

Suppliers of CO2, subpart PP) that is injected underground. This approach is consistent with the

all-in requirements in the MRR for suppliers of petroleum, natural gas, and coal-to-liquid

products (subparts LL, MM, and NN), producers of industrial gases (subpart OO), and suppliers

of CO2 (subpart PP). It was reasonable to require all of the facilities in these source categories to

report because it would result in the most comprehensive accounting possible, simplify the rule,

and permit facilities to quickly determine whether or not they must report; the same rationale

applies for this source category proposed today. Furthermore, it would create a uniform burden

for all covered facilities, ensuring a level playing field in, and preventing fragmentation of, the

ER sector. EPA has estimated the cost for CO2 injection facilities to comply with the minimum

reporting requirements in this proposed rule and has determined that the burden would be small,

given the equipment and data collection efforts already in place at ER projects.

Under this action, EPA is proposing that the subset of CO2 injection facilities that are

conducting GS (i.e. a GS facility) must report to EPA a second tier of data. EPA considered

whether a threshold should apply to this second tier of data given that it would place a reporting

burden on GS facilities. However, EPA could not perform an analysis on GS facilities based on

emissions without data on actual or expected GS facility emissions. EPA also could not perform

a threshold analysis based on injection due to the uncertainty around predictions of injection

quantities for potential GS facilities. In addition, it is difficult to predict how many injection

facilities would choose to report GS. Therefore, EPA is proposing to exempt GS R&D projects

but otherwise require all GS facilities to comply with the GS monitoring, reporting, and
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verification requirements of subpart RR, and that they report fugitive, vented, and combustion

emissions from surface equipment (under subpart W, RR, or C, as applicable). An all-in

threshold will allow EPA to work with the early-movers of this nascent industry and to

strengthen EPA’s understanding of GS.

7.2 Estimated Costs and Impacts of the Mandatory GHG Reporting Program

Under the rule, EPA estimates that 89 fields would be covered by the rule, injecting

approximately 40 MtCO2 per year. The total annualized costs incurred under the rule by these

entities would be approximately $713,000 (in 2008$). This includes a public sector burden

estimate of $344,000 for program implementation and verification activities. These costs are

distributed to several economic sectors and represent approximately 0.0001% of 2008 gross

domestic product; overall, EPA does not believe the rule will have a significant macroeconomic

impact on the national economy or on small entities within those sectors.

7.2.1 Alternative Scenarios Considered

7.2.1.1 GS Facilities (ER opt in) Outcomes

Currently, the number of GS Facilities (ER opt in) is unknown and EPA could not

identify any information or analysis to estimate this quantity. As a result, two additional

scenarios of the have been considered to represent medium and high outcomes. As shown in

Tables 5-4, national cost estimate is $24 million under the medium ER opt in outcome. As shown

in Tables 5-5, national cost estimate is $79 million under the high ER opt in outcome.

7.2.1.2 GS Facilities (Commercial Saline) Outcomes

EPA considered two additional scenarios of the quantity of commercial saline project

outcomes: low (3 projects), medium (6 projects), and high (9 projects). The national cost

estimates estimate increase $867,000 under the low outcome; $1.7 million under the medium

outcome, and $2.6 million under the high outcome.
8-1

SECTION 8

REFERENCES

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8-2

U.S. Department of Energy, National Energy Technology Laboratory website, www.netl.doe.gov

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