This comment letter response contains two parts:   

(1) The original submittal from the commenter.

(2) A data base printout of EPA’s response to each point raised by the commenter.

Notes about the response letters:

• The response letters were generated by a data base used to track the content of all public

comment submittals and ensure that the Agency responds to each. Each comment letter

was assigned a Letter ID that corresponds to the last four digits of the docket number of the

original comment (as posted on www.regulations.gov).

• Each response letter includes: comment text; an EPA‐assigned comment code; and an

individual response. These are described and explained below.  

• The data base contains Comment text from the letters submitted by commenters.  

Many hard copy letters were scanned into electronic format for inclusion in the data

base. As a result, there may be some typographical errors attributable to optical

character recognition issues.  However, all original submittals were reviewed in the

process of drafting responses to ensure that the comment content was understood and

appropriately addressed.

• The content of each comment letter was divided into topic areas and assigned a unique

Comment ID.  Additionally, one or more Comment Codes (i.e., unique topic area ID) was

assigned to each discrete point raised by a commenter. This information was added to

the data base. To inform final rulemaking decisions, all comments and information

received on a given topic were reviewed by technical experts in each rule area (e.g., on

construction requirements).  

• Following decisions on the final rule requirements, Individual responses were drafted

by topic area to ensure completeness and consistency of the responses with the final

rule and other responses to similar comments.  Each discrete point made by a

commenter was given a unique response.

• Upon completion of comment responses, all information was entered into the data base.

Each letter response is a compilation of each comment and its individual response,

compiled in the order of the original comment letter.  As a result of this process, there is

repetition in the response text.  The Agency believes this approach ensures completeness

and attention to each comment letter that was submitted.   

• All comments in a topic area were reviewed, evaluated, and responded to concurrently.  

Responses on each topic area are compiled and are also available in the rulemaking docket.
6672 BALTIMORE PIKE  LITTLESTOWN, PENNSYLVANIA 17340 USA

TEL: 717-359-0014  FAX: 717-359-0220

Water Docket

Environmental Protection Agency

Mailcode: 2822T

1200 Pennsylvania Ave., NW

Washington, DC 20460

Filed via website: http://www.regulations.gov

December 24, 2008

Subject: Comments on Federal Requirements Under the Underground Injection

Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration

(GS) Wells; Proposed Rule

Docket ID No. EPA–HQ–OW–2008–0390

(73 Fed. Reg. 43492 (July 25, 2008))

From: AmericanEnergySecurity.org, an initiative of A. J. Mayer International, LLC

These comments are filed on behalf of the American Energy Security initiative (see

www.AmericanEnergySecurity.org) , a web-based initiative of A. J. Mayer International,

LLC. AmericanEnergySecurity.org is dedicated to educating American citizens, businesses,

and policy makers about America's energy crisis and the tremendous challenges and

opportunities ahead.

The American Energy Security initiative endorses a comprehensive energy policy that

embraces our full portfolio of diverse and abundant energy resource, resulting in American

energy security and independence.

Through aggressive efforts to produce more low cost, clean electricity, heat, and liquid and

gaseous fuels from America's tremendous domestic resources, we can create millions of jobs,

decrease our trade and budget deficits, provide affordable energy to American families and

businesses, and restore economic vitality, opportunity, and prosperity to this great nation.

Increased energy efficiencies and sensible conservation have roles to play as well.

Unnecessary government policies and regulations, like the subject EPA rule, can continue to

deny the United States the energy security it needs to prosper.

CO2 Enhanced Oil Recovery (EOR) is Key to U.S. Energy Security and Independence

The American Energy Security Study, sponsored by the Atlanta based regional energy

compact, Southern States Energy Board (www.SSEB.org and www.AmericanEnerySecurity.org )

identified CO2 EOR as a key to U.S. energy security and independence.

EPA’s proposed rule for UIC of CO2, if not changed dramatically, could undermine the

potential for increased domestic production of crude oil and methane, leading to an

increase in our dependence on imported oil and natural gas. The harmful economic and

national security impacts of dependence on energy imports cannot be understated.
Page 2 A. J. MAYER INTERNATIONAL, LLC

Enhanced oil recovery offers the potential to vastly expand domestic crude oil reserves

and production, while simultaneously providing a positive answer to CO2 emissions based on

a commercial, value added sequestration solution. Carbon dioxide injection into mature oil

fields is a proven oil recovery method that has been safely and successfully utilized for 35

years. In fact CO2 EOR was growing in the U.S. even before the recent crude oil price runup, when oil was selling for $20 per barrel. The technique now accounts for about 4% of U.S.

oil production.

Crude oil production has been declining in the U.S. since the early 1970’s (see Figure

1 below). Current production is about 5.2 million barrels per day (excluding natural gas

condensates and other liquid by-products). Leading experts estimate that an additional 3.0

million daily barrels per day of American crude can be produced using CO2, ultimately

increasing domestic oil output by more than 50%. As an indicator of this potential, CO2 EOR

has already stimulated rising oil production in Mississippi and Wyoming, where adequate,

low cost sources of CO2 have been available to support growth. Unfortunately, there are

substantial CO2 shortages in most U.S. oil basins that constrain the growth of CO2 EOR. The

prospect of capturing and utilizing additional and substantial low cost CO2 supplies from

the gasification of American coal, petroleum coke, municipal solid waste, and biomass

represents the ultimate economic and environmental leveraging of our strategic domestic

energy resources. Gasification clearly offers a “next generation” in energy efficiency,

emissions control, and fuel and chemical product manufacturing flexibility. Gasification

plants can be configured to make one or a portfolio of transportation fuels, chemicals,

fertilizers, natural gas substitutes, and electricity, while at the same time capturing a large

percentage of CO2 generated by the processes. These large new CO2 product streams

represent a valuable commodity that can be utilized to restore the vitality of many of

America’s mature oil fields, facilitating a rapid increase in domestic production from

stranded oil (as described below), and substantial economic and national security benefits.
Page 3 A. J. MAYER INTERNATIONAL, LLC

The United States has Vast EOR Potential that is Geographically Diverse

In terms of resource base, the U.S. CO2 EOR “prize” is tremendous, with technically

recoverable reserves estimated at more than 88 billion additional barrels of oil from declining

oil fields (see the attached Department of Energy fact sheet) in ten major basins. In

addition, experts are currently assessing another tremendous CO2 EOR target—a new class of

virgin oil resources being referred to as “residual oil zones” or “transition zones.” Residual

oil zones (“ROZs”) are untapped oil-bearing geologic units beneath some main pay zones

from which the easy oil has been displaced by natural underground water movement over the

geological past (a process analogous to oil industry water flooding, also know as secondary

recovery). CO2 injection (tertiary recovery) into ROZs is a promising method to mobilize

enough of the remaining “stranded oil” to justify development of a number of these

formations.

Although somewhat difficult to quantify at this early stage, residual oil zone resources

are believed to be in the billions of barrels, offering the potential to significantly increase the

88+ billion barrel CO2 EOR reserve base (see the attached DOE fact sheet for more details).

Several very significant commercial residual oil zone projects are already in production in the

U.S., including an operation at the Hess Seminole Field and one at Occidental Petroleum’s

Wasson field – both in West Texas. Other fields with substantial ROZ resources await CO2

availability for exploitation. The total EOR prize is believed to total or exceed 100 billion

barrels of oil, including existing commercial oil reservoirs and new residual oil zones.

For comparative purposes, ANWR represents approximately 10.4 billion barrels of

technically recoverable oil, with an estimated production potential of about 1.4 million barrels

per day. In contrast, U.S. CO2 EOR offers the potential to add almost three times the daily

production of ANWR, and 10+ times the oil reserves, while at the same time creating very

large markets and geologic sequestration “sinks” for billions of tons of CO2.

The graphic below (Figure 2) is a simplified diagram of the CO2 EOR process. In

commercial operations carbon dioxide is transported under pressure to the project area by

pipeline in what the industry refers to as the CO2 dense phase. The compressed CO2 is then

sent underground into a targeted underground oil “pay zone” through injector wells where it

acts as a solvent reducing the oil viscosity and surface tension, thus freeing the oil to be

“swept” to production wells. A CO2 injection well is typically surrounded by a number of

production wells organized in a “pattern”. Any CO2 produced with the oil is separated and reinjected. The CO2 that is not recycled is effectively trapped within the formation in dead-end

pores and channels. When the EOR project is complete all wells are plugged with cement and

the CO2 is permanently sequestered underground.

In current practices, the amount of CO2 injected to mobilize oil is carefully controlled

due to the cost of the CO2. The yield of a CO2 EOR project typically varies from two to four

barrels of oil produced from every ton of CO2 purchased. CO2 EOR has not seen wider

application because of the high project capital costs, historically low oil prices, and limited

supplies of low cost, pure CO2. But in today’s high oil price environment, the main constraint

is a shortage of CO2. Enhanced oil recovery operators are currently paying between $10 and

$30 per ton for CO2, when they can find it. The market is there. The challenge is to provide

incentives for more CO2 generators to capture their carbon dioxide streams, and developers to

build CO2 pipelines from CO2 sources to the oil and methane fields that need it. Today’s
Page 4 A. J. MAYER INTERNATIONAL, LLC

supplies of CO2 are a combination of naturally occurring deposits tapped by underground

wells and man made (“anthropgenic”) sources captured from some natural gas processing,

coal gasification, ethanol production, and other operations.

Figure 2: Enhanced Oil Recovery Process with CO2 Injection

Other emerging carbon dioxide application/sequestration technologies are also worth

mentioning. These include the enhanced production of natural gas, coalbed methane, and

agricultural products (including algae for fuel production) with CO2. These and other

technologies promise to create additional markets for CO2 but require more research and

development efforts to reach commercial viability. In contrast, CO2 Enhanced Oil Recovery

is already commercial and can be quickly expanded.

Rapid expansion of Enhanced Oil Recovery provides an excellent foundation from

which to advance American Energy Security, stimulate and grow the economy, and protect

the environment. This can and should be followed by the rapid development and deployment

of other productive uses of CO2, to enhance natural gas, algae growth for biofuels, etc.

Conversely, the current focus on the passive, costly sequestration of CO2 in deep saline

formations will increase the price of all U.S. energy products and thus impose a significant

burden on our economy and our society.

Commercial sequestration will enable the next generation of domestic energy

production. CO2 occurs naturally in the subsurface and it is no stranger to geologists who

attempt to understand fluid migration and subsurface accumulations. The fact that CO2 can be

trapped in subsurface formations for geologic times is known and accepted; and we will

undoubtedly find more of these locations. Oil and gas “traps” are considered by recognized

petroleum engineers and geologist to be excellent final resting place for CO2. These traps

have already demonstrated the ability to hold oil and gas safely undergroud for hundreds of

millions of years.
Page 5 A. J. MAYER INTERNATIONAL, LLC

GENERAL COMMENTS AND CONCERNS ABOUT THE PROPOSED UIC RULE

1. It is strongly recommended that the EPA promote and encourage, not block and erect

barriers to, geosequestration of CO2 for both productive and non-productive uses of

CO2.

EPA’s stated goals for this proposal are to protect Underground Sources of Drinking Water

(USDWs) while promoting carbon capture and storage. The proposed regulations would

succeed in protecting USDWs, but would fails to promote carbon capture and storage. The

Proposed Rule overestimates the risks of CO2 geologic sequestration and creates barriers to

rapid technology development and commercial scale deployment projects that will greatly

benefit American (as noted in the preceding narrative).

2. We generally agree with and endorse the Texas Carbon Capture and Storage

Association (TxCCSA) comments to the Proposed Rule.

3. The proposed 50-year post-injection site care timeframe discriminates against

smaller operators. The extraordinarily long-term obligation this provision creates will

almost certainly prevent some small and middle-size companies from undertaking

otherwise successful and beneficial CO2 injection projects because of the significant

financial burden imposed.

4. The Proposed Rule does not recognize the benefits of injection in EOR plays.

EPA does not consider CO2 to be sequestered following injection for EOR. Many CO2

sequestration projects will be associated with oil and gas operations. However the Proposed

Rule states that sequestration begins only after enhanced recovery of oil or gas has stopped.

The implication is that the CO2 injected for enhanced recovery is not ultimately sequestered

upon cessation of injection and production activity.

5. The Proposed Rule incorrectly implies that CO2 is a waste.

The EPA states that it has not classified CO2 as a waste or a commodity. However, by using

the waste injection well requirements (Class I) as the framework for the new Class VI

requirements, the Proposed Rule implies that the CO2 is a waste. The Proposed Rule has

proposed requirements for Class VI injection wells that are more severe than those for wells

used for the injection of hazardous waste.

6. The Proposed Rule overestimates the risks of CO2 injection.

The Proposal Rule implies that when the purpose of the injection switches from enhanced

recovery to sequestration, the risks to USDWs are significantly magnified. With appropriate

site selection, construction, monitoring, and testing, the risks of CO2 geologic sequestration

would be comparable to the risks of current activities such as natural gas storage and

enhanced recovery of oil.

EPA begins with the framework of Class I non-hazardous industrial waste injection well

requirements and adds additional layers of redundant requirements to prevent or detect the
Page 6 A. J. MAYER INTERNATIONAL, LLC

escape of CO2 from the injection zone. EPA apparently believes that the Class II program is

not sufficiently protective.

7. The Proposed Rule precludes a meaningful role for States.

UIC regulations developed by EPA must permit or provide consideration of varying geologic,

hydrological, or historical conditions in different States and in different areas within a State.

The Proposed Rule does not allow State directors to use their expertise and knowledge to

account for these varying conditions.

SPECIFIC RECOMMENDATIONS FOR IMPROVEMENTS IN THE UIC RULE

1. EPA should create a subclass within the Class II well classification for operators who

plan to sequester CO2 in association with enhanced recovery of oil or natural gas (with

appropriate and necessary additional requirements to address any CO2 issues).

2. Any Class VI injection well program might be applied to injection wells used to

sequester CO2 in formations that are non-productive, such as deep saline formations.

3. EPA should begin with a Class II injection well framework to assure that the rules are

flexible enough to consider site-specific characteristics and knowledge gained from the

extensive CO2 history and the ongoing demonstration and pilot projects.

4. EPA should provide flexibility in the siting requirements including promoting

utilization of EOR, Enhanced Gas Recovery (EGR) and Enhanced Coalbed Methane

Recovery (ECBM) formations for storage.

5. EPA should provide more flexibility in operational requirements including allowing

an EOR/EGR/ECBM operator to demonstrate that CO2 is sequestered rather than the

prescriptive 10-year default period for reevaluation of the area of review.

6. EPA should provide for performance-based requirements for Closure and Post

Closure Care. The duration of post-injection site care should be determined by specific

conditions and characteristics of the site, and monitoring of the pressure to determine the

point at which the injection zone pressure is such that USDWs cannot be impacted.

7. EPA should provide for a system for qualifying sequestration sites, including

qualifying geographically and geologically diverse sites for CO2 injection in non-trapping

(oil/gas) applications.

[This Space Left Blank Intentionally]
Page 7 A. J. MAYER INTERNATIONAL, LLC

If you have any questions, please don’t hesitate to call. Thank you for the opportunity

to comment.

Sincerely and respectfully,

A. James Mayer

President

A. J. Mayer International, LLC

6672 Baltimore Pike

Littlestown, Pennsylvania 17340

Tel: 717-359-0014

Email: jamesmayer@americanenergysecurity.org
U.S. Department of Energy • Office of Fossil Energy • Office of Oil and Natural Gas 

February 2006 

Project Facts

Recovering “Stranded Oil” Can Substantially Add to U.S. Oil Supplies 

Ten Reports Examine Basin-Oriented Strategies 

For Increasing Domestic Oil Production

A series of reports -- four new, three updated and three previously released – prepared for the U.S. 

Department of Energy (DOE) Office of Fossil Energy indicate significant potential for increasing domestic oil 

supplies. This could result from applying carbon dioxide enhanced oil recovery (CO2-EOR) technology to 

recover nearly 89 billion barrels of additional oil from currently “stranded” oil resources in ten regions of the 

United States. The reports summarize the results of basin-oriented CO2-EOR assessments prepared by 

Advanced Resources International for the Fossil Energy Office of Oil and Natural Gas. 

 

CO2-EOR Technically Recoverable Resource Potential 

All Reservoirs (Ten Basins/Areas Assessed) 

Basin/Area 

No. Large 

Reservoirs 

Assessed

OOIP* 

(Billion Barrels)

ROIP** 

(Billion Barrels) 

Technically 

Recoverable 

(Billion Barrels) 

Alaska 34 67.3 45.0 12.4 

California 172 83.3 57.3 5.2 

Gulf Coast 239 44.4 27.5 6.9 

Mid-Continent 222 89.6 65.6 11.8 

Illinois and Michigan 154 17.8 11.5 1.5 

Permian 207 95.4 61.7 20.8 

Rocky Mountains 162 33.6 22.6 4.2 

Texas: East and Central 199 109 73.6 17.3 

Williston 93 13.2 9.4 2.7 

Louisiana Offshore 99 28.1 15.7 5.9 

Total 1,581 581.7 390.0 88.7

* Original oil in place, in all reservoirs in basins/areas. ** Remaining oil in place, in all reservoirs in basins/areas. 

 Source: Advanced Resources International 

According to the Oil and Gas Journal, CO2–EOR is the fastest growing form of enhanced oil recovery in the 

United States, producing an estimated 206,000 barrels per day in 2004, mostly in the Permian Basin of 

West Texas and New Mexico, representing 4 percent of the Nation’s crude oil production. This experience, 

plus the innovative CO2-EOR project at the Weyburn field in Saskatchewan, Canada, could lead the way in 

helping to overcome the risks and economic barriers to applying this technology to recover “stranded oil” in 

other basins. 

The reports reveal the potential for expanding the contribution of this technology for recovering crude oil 

from mature domestic oil fields. In addition, the reports assess the performance of CO2-EOR projects 

conducted in these regions during the past 30 years, reviewing both successful and unsuccessful efforts. 

 

Traditional oil recovery methods will leave behind an estimated 390 billion barrels of already discovered oil 

resources in the ten basins studied. Such “stranded oil” provides a substantial target for EOR technology, 

representing about two-thirds of the region’s original oil in-place in discovered, producing fields. The ten 

assessments evaluated 1,581 large oil reservoirs to identify those that screen favorably for CO2-EOR. 
U.S. Department of Energy • Office of Fossil Energy • Office of Oil and Natural Gas 

February 2006 

Extrapolating this sample to all reservoirs in the ten regions demonstrated that nearly 89 billion barrels of 

additional oil are technically recoverable with today’s state-of-the art CO2-EOR technology. Advanced EOR 

technologies could significantly increase this oil recovery potential. 

Overcoming the barriers to the wider use of CO2-EOR technologies may entail: 

3⁄4 Bringing state-of-the-art CO2-EOR technology 

to oil fields in regions where it is currently not yet 

applied. 

3⁄4 Lowering the risks inherent in applying new 

technology to complex oil reservoirs, by conducting 

research, pilot tests and field demonstrations of 

CO2-EOR in geologically challenging oil fields. 

3⁄4 Providing a package of “risk mitigating” actions, such 

as state production tax incentives, federal investment 

tax credits, and royalty relief, to reduce potential oil 

price and market risks and to improve the economic 

competitiveness of pursuing this domestic oil 

resource. 

U.S. Basins/Regions Studied for Future Potential for CO2-EOR 

3⁄4 Establishing low-cost, reliable “EOR-ready” CO2 supplies from both natural and industrial sources. In 

the near-term, this could include high-concentration CO2 emissions from refinery hydrogen plants, gas 

processing facilities and other industrial sources. In the longer-term, this could include capturing low 

CO2 concentration emissions from electric power generation plants and other sources. 

Together, these “basin-oriented strategies” could help revitalize state economies, increase federal and 

state revenues, and enable additional domestic oil to be recovered. The potential benefits are substantial. 

Eighty-nine billion barrels of additional domestic oil recovery, at $40 per barrel, could yield: 

3⁄4 A reduction in the Nation’s trade deficit of over $3.6 trillion through reduced oil imports. 

3⁄4 Enhanced national energy security from an additional 2 to 3 million barrels per day of domestic oil 

production by 2020. 

3⁄4 Over 200,000 high-paying domestic jobs from the direct and indirect economic effects of increased 

domestic oil production. 

3⁄4 Over $800 billion of additional federal, state and local revenues from royalties, production, and 

corporate income taxes. 

Further information 

Copies of the basin assessments are available at www.fossil.energy.gov. For information about DOE Oil 

and Natural Gas Program research on emerging EOR technologies, see www.netl.doe.gov. 

Contact Points 

Art Hartstein 

DOE Fossil Energy 

Office of Oil and Natural Gas 

(202) 586-5600

Vello Kuuskraa 

Advanced Resources 

International 

(703) 528-8420

Michael Godec 

Advanced Resources 

International 

(703) 528-8420

 

 
U.S. Department of Energy • Office of Fossil Energy • Office of Oil and Natural Gas 

February 2006 

 Project Facts 

Production of “Stranded Oil” in the Residual Oil Zone Could Add 

New Domestic Oil Resources 

Background. The presence of an oil bearing transition zone (TZ) beneath the traditionally defined base 

(oil-water contact) of an oil reservoir is well established. What is now clear, and as documented by this 

series of five reports, is that, in certain geologic and hydrodynamic conditions, an additional residual oil 

zone (ROZ) exists below this transition zone. This lower zone may be extensive, thick and filled with 

residual oil that may be recoverable using CO2 enhanced oil recovery (CO2-EOR) technologies. These 

thick residual oil zones exist where nature has already waterflooded the lower portion of an oil reservoir. 

Past investigations of the origins and presence of these naturally-formed residual oil zones have been 

hampered by two limitations: a general lack of interest in these intervals, as they may add little additional 

oil during primary and secondary production; and clear preference for avoiding drilling into these residual 

oil transition zones to reduce the production of water. 

Topics Addressed by These Reports. The advent of advanced tertiary oil production technology now 

enables previously waterflooded oil zones (with low oil saturations) to be further exploited, particularly 

using CO2-EOR technologies. The residual oil saturation and reservoir properties in naturally-created 

residual oil transition zones are like those in the waterflooded intervals of the main pay zone. As such, 

new interest is emerging to better understand the nature, size and recoverability of this “stranded oil” 

resource. To facilitate and further support this new interest in the ROZ, the Fossil Energy Office of Oil 

and Natural Gas has issued a series of reports: 

1) The first report, Stranded Oil in the Residual Oil Zone, discusses the origin of residual oil zones 

of abnormal thicknesses, beyond those formed by capillary pressure. 

2) The second report, Assessing Technical and Economic Recovery of Oil Resources in 

Residual Oil Zones, applies reservoir simulation to study the technical feasibility of recovering oil 

from the transition and residual oil zones. It then reviews the results of three on-going CO2-EOR 

projects to examine the commercial merits of CO2 flooding in residual oil zones. 

3) The third, fourth and fifth reports, Technical Oil Recovery Potential From Residual Oil Zones: 

Permian Basin, Technical Oil Recovery Potential From Residual Oil Zones: Williston Basin, 

and Technical Oil Recovery Potential From Residual Oil Zones: Big Horn Basin, document 

the sizable, previously unaccounted-for oil resource within three domestic oil basins -- Permian, 

Williston and Big Horn. 

Origins of Abnormally Thick ROZs. All reservoirs have oil-to-water transition zones, of varying 

thicknesses, that owe their origin to capillary forces. These forces cause gradational changes in the oil 

and water saturations beneath the main pay zone. However, much larger “stranded” oil targets exist in 

residual oil zones of non-capillary origin. These thicker and more extensive residual oil zones stem from 

the displacement of oil previously trapped in an oil reservoir, such as those documented in the thick ROZ 

intervals observed at the Wasson Field (Denver Unit) and the Seminole Field (San Andres Unit). The first 

report describes the affects of basin tectonics and hydrodynamics on the tilt of the oil-water contact of an 

oil reservoir leading to the oil trapped in the ROZ. 

1 
U.S. Department of Energy • Office of Fossil Energy • Office of Oil and Natural Gas 

February 2006 

Current ROZ Field Projects. Three residual oil zone CO2-EOR projects are underway in the Permian 

Basin of West Texas. They are: Occidental’s Transition Zone project in the Denver Unit of the Wasson 

Field; Amerada Hess’ Residual Oil Zone pilot in the San Andres Unit of the Seminole Field; and 

Occidental’s Main Pay and Transition Zone project in the Bennett Ranch Unit of the Wasson Field. 

Preliminary Estimates of ROZ Size and Recovery Potential. Given the data and information on tilted 

oil-water contacts and supporting reservoir data available for the Permian, Williston and Big Horn Basins, 

initial efforts have been undertaken to develop a methodology and a first order estimate of the size of the 

“stranded oil” target in the ROZ. 

These reports used tilted oil-water contacts as the key attribute for identifying settings with potentially 

thick ROZs. Fortunately, oil-water contact contouring is a basic input for efficient exploitation of an oil 

field, and these data exist for most major oil fields and are often filed in the public records of state 

regulatory agencies. Based on this currently available data, initial estimates of the ROZ size and 

potential are provided for three basins: 

3⁄4 Permian Basin. The report identifies 56 oil reservoirs, in five Permian Basin oil plays, that may 

contain significant volumes of TZ/ROZ resources. The oil in-place in the TZ/ROZ is estimated at 30.7 

billion barrels, with 11.9 billion barrels potentially technically recoverable. 

3⁄4 Williston Basin. The report identifies 20 oil reservoirs that hold 6.8 billion barrels of oil in-place in the 

TZ/ROZ, of which 3.3 billion barrels is potentially technically recoverable. 

3⁄4 Big Horn Basin. The report identifies 13 oil reservoirs that hold 4.4 billion barrels of oil in-place in the 

TZ/ROZ of which 1.1 billion barrels is potentially technically recoverable. 

Next Steps. Obtaining sufficient reservoir data for defining the ultimate size and productivity of the 

TZ/ROZ will be challenging. However, there will be great value from undertaking this task, as it will add 

previously undocumented domestic oil to the Nation’s resource base. The next step would be conducting 

a series of additional regional and basin studies. Ultimately, field-by-field analyses will be necessary and 

will require considerable effort to fully establish the size and economic potential of this new, previously 

undocumented oil resource. 

Further information 

This resource assessment was prepared by Advanced Resources International for the U.S. Department 

of Energy Office of Fossil Energy. Copies of the assessment are available at www.fossil.energy.gov. For 

information about DOE Oil and Natural Gas Program research on emerging EOR technologies, see 

www.netl.doe.gov. 

Contact Points 

Art Hartstein 

DOE Fossil Energy 

Office of Oil and Natural Gas 

(202) 586-5600

L. Stephen Melzer 

Melzer Consulting 

(432) 682-7664 

Vello Kuuskraa 

Advanced Resources 

International 

(703) 528-8420 

George Koperna 

Advanced Resources 

International 

(703) 528-8420 

2 
Letter ID: 0230 

Commenter: A. James Mayer 

Organization: A. J. Mayer International on behalf of the American Energy Security Initiative 

Letter ID: 0230 Comment ID: 21870 Letter Lines: 52 to 66 

Comment Code: 1450 1.2.2.1 Oppose the GS rulemaking 

Comment: Unnecessary government policies and regulations, like the subject EPA rule, can 

continue to deny the United States the energy security it needs to prosper. 

CO2 Enhanced Oil Recovery (EOR) is Key to U.S. Energy Security and Independence 

The American Energy Security Study, sponsored by the Atlanta based regional 

energy compact, Southern States Energy Board (www.SSEB.org and 

www.AmericanEnerySecurity.org ) identified CO2 EOR as a key to U.S. energy 

security and independence. 

EPA’s proposed rule for UIC of CO2, if not changed dramatically, could undermine 

the potential for increased domestic production of crude oil and methane, 

leading to an increase in our dependence on imported oil and natural gas. The 

harmful economic and national security impacts of dependence on energy imports 

cannot be understated. 

Individual Response: In response to comments that the GS rule could impede technology or 

undermine the potential for increased domestic production of crude oil and methane, EPA 

stresses that the purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in 

a manner that protects USDWs from endangerment. Consequently, these comments are outside 

the scope of the rulemaking. EPA adds that this rulemaking is not intended to promote oil or 

natural gas production or to address U.S. dependence on imported oil and natural gas. EPA 

clarifies that wells injecting CO2 for the purpose of ER are regulated as Class II wells. 

Letter ID: 0230 Comment ID: 21871 Letter Lines: 68 to 193 

Comment Code: 1000 1. General and Administrative Comments 

Comment: Enhanced oil recovery offers the potential to vastly expand domestic crude oil 

reserves and production, while simultaneously providing a positive answer to CO2 

emissions based on a commercial, value added sequestration solution. Carbon 

dioxide injection into mature oil fields is a proven oil recovery method that 

has been safely and successfully utilized for 35 years. In fact CO2 EOR was 

growing in the U.S. even before the recent crude oil price run-up, when oil was 

selling for $20 per barrel. The technique now accounts for about 4% of U.S. oil 

production. 

1
Crude oil production has been declining in the U.S. since the early 1970’s (see 

Figure 1 below). Current production is about 5.2 million barrels per day 

(excluding natural gas condensates and other liquid by-products). Leading 

experts estimate that an additional 3.0 million daily barrels per day of 

American crude can be produced using CO2, ultimately increasing domestic oil 

output by more than 50%. As an indicator of this potential, CO2 EOR has already 

stimulated rising oil production in Mississippi and Wyoming, where adequate, low 

cost sources of CO2 have been available to support growth. Unfortunately, there 

are substantial CO2 shortages in most U.S. oil basins that constrain the growth 

of CO2 EOR. The prospect of capturing and utilizing additional and substantial 

low cost CO2 supplies from the gasification of American coal, petroleum coke, 

municipal solid waste, and biomass represents the ultimate economic and 

environmental leveraging of our strategic domestic energy resources. 

Gasification clearly offers a "next generation" in energy efficiency, emissions 

control, and fuel and chemical product manufacturing flexibility. Gasification 

plants can be configured to make one or a portfolio of transportation fuels, 

chemicals, fertilizers, natural gas substitutes, and electricity, while at the 

same time capturing a large percentage of CO2 generated by the processes. These 

large new CO2 product streams represent a valuable commodity that can be 

utilized to restore the vitality of many of America’s mature oil fields, 

facilitating a rapid increase in domestic production from stranded oil (as 

described below), and substantial economic and national security benefits. 

Figure 1: US Oil Production Has Been Declining Since 1970 

[see PDF Docket ID EPA-HQ-OW-2008-0390-0230] 

The United States has Vast EOR Potential that is Geographically Diverse 

In terms of resource base, the U.S. CO2 EOR "prize" is tremendous, with 

technically recoverable reserves estimated at more than 88 billion additional 

barrels of oil from declining oil fields (see the attached Department of Energy 

fact sheet) in ten major basins. [SEE EPA-HQ-OW-2008-0390-0230.PDF FOR FACT 

SHEETS] In addition, experts are currently assessing another tremendous CO2 EOR 

target--a new class of virgin oil resources being referred to as "residual oil 

zones" or "transition zones." Residual oil zones ("ROZs") are untapped oilbearing geologic units beneath some main pay zones from which the easy oil has 

been displaced by natural underground water movement over the geological past (a 

process analogous to oil industry water flooding, also know as secondary 

recovery). CO2 injection (tertiary recovery) into ROZs is a promising method to 

mobilize enough of the remaining "stranded oil" to justify development of a 

number of these formations. 

Although somewhat difficult to quantify at this early stage, residual oil zone 

resources are believed to be in the billions of barrels, offering the potential 

to significantly increase the 88+ billion barrel CO2 EOR reserve base (see the 

attached DOE fact sheet for more details). Several very significant commercial 

2
residual oil zone projects are already in production in the U.S., including an 

operation at the Hess Seminole Field and one at Occidental Petroleum’s Wasson 

field - both in West Texas. Other fields with substantial ROZ resources await 

CO2 availability for exploitation. The total EOR prize is believed to total or 

exceed 100 billion barrels of oil, including existing commercial oil reservoirs 

and new residual oil zones. 

For comparative purposes, ANWR represents approximately 10.4 billion barrels of 

technically recoverable oil, with an estimated production potential of about 1.4 

million barrels per day. In contrast, U.S. CO2 EOR offers the potential to add 

almost three times the daily production of ANWR, and 10+ times the oil reserves, 

while at the same time creating very large markets and geologic sequestration 

"sinks" for billions of tons of CO2. 

The graphic below (Figure 2) is a simplified diagram of the CO2 EOR process. In 

commercial operations carbon dioxide is transported under pressure to the 

project area by pipeline in what the industry refers to as the CO2 dense phase. 

The compressed CO2 is then sent underground into a targeted underground oil "pay 

zone" through injector wells where it acts as a solvent reducing the oil 

viscosity and surface tension, thus freeing the oil to be "swept" to production 

wells. A CO2 injection well is typically surrounded by a number of production 

wells organized in a "pattern". Any CO2 produced with the oil is separated and 

reinjected. The CO2 that is not recycled is effectively trapped within the 

formation in dead-end pores and channels. When the EOR project is complete all 

wells are plugged with cement and the CO2 is permanently sequestered 

underground. 

In current practices, the amount of CO2 injected to mobilize oil is carefully 

controlled due to the cost of the CO2. The yield of a CO2 EOR project typically 

varies from two to four barrels of oil produced from every ton of CO2 purchased. 

CO2 EOR has not seen wider application because of the high project capital 

costs, historically low oil prices, and limited supplies of low cost, pure CO2. 

But in today’s high oil price environment, the main constraint is a shortage of 

CO2. Enhanced oil recovery operators are currently paying between $10 and $30 

per ton for CO2, when they can find it. The market is there. The challenge is to 

provide incentives for more CO2 generators to capture their carbon dioxide 

streams, and developers to build CO2 pipelines from CO2 sources to the oil and 

methane fields that need it. Today’s supplies of CO2 are a combination of 

naturally occurring deposits tapped by underground wells and man made 

("anthropgenic") sources captured from some natural gas processing, coal 

gasification, ethanol production, and other operations. 

Figure 2: Enhanced Oil Recovery Process with CO2 Injection 

[see PDF Docket ID EPA-HQ-OW-2008-0390-0230] 

Other emerging carbon dioxide application/sequestration technologies are also 

3
worth mentioning. These include the enhanced production of natural gas, coalbed 

methane, and agricultural products (including algae for fuel production) with 

CO2. These and other technologies promise to create additional markets for CO2 

but require more research and development efforts to reach commercial viability. 

In contrast, CO2 Enhanced Oil Recovery is already commercial and can be quickly 

expanded. 

Rapid expansion of Enhanced Oil Recovery provides an excellent foundation from 

which to advance American Energy Security, stimulate and grow the economy, and 

protect the environment. This can and should be followed by the rapid 

development and deployment of other productive uses of CO2, to enhance natural 

gas, algae growth for biofuels, etc. Conversely, the current focus on the 

passive, costly sequestration of CO2 in deep saline formations will increase the 

price of all U.S. energy products and thus impose a significant burden on our 

economy and our society. 

Commercial sequestration will enable the next generation of domestic energy 

production. CO2 occurs naturally in the subsurface and it is no stranger to 

geologists who attempt to understand fluid migration and subsurface 

accumulations. The fact that CO2 can be trapped in subsurface formations for 

geologic times is known and accepted; and we will undoubtedly find more of these 

locations. Oil and gas "traps" are considered by recognized petroleum engineers 

and geologist to be excellent final resting place for CO2. These traps have 

already demonstrated the ability to hold oil and gas safely undergroud for 

hundreds of millions of years. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of EOR. The GS rulemaking builds upon existing experience and 

knowledge about safe injection practices in EOR and other injection industries, with tailored 

requirements that address the unique nature of CO2 injection for GS. 

The Agency clarifies that the final GS rule does not require owners or operators to use GS 

technologies, nor does it impact business as usual for Class II owners or operators that are 

injecting CO2 to enhance production of oil or gas. Those owners or operators that choose to 

transition from enhanced recovery to GS may do so, provided they meet the requirements for 

Class VI wells. EPA adds that the intent of the GS rule is not to address the deployment of GS or 

the use of CO2 for ER. Rather, the purpose of the GS regulation is to ensure consistency in 

permitting underground injection of CO2 at GS operations across the United States and provide 

requirements to prevent endangerment of USDWs in anticipation of the eventual use of GS to 

reduce CO2 emissions. 

Please see the remainder of EPA's responses to this comment letter for further details. For 

additional information on EPA's final regulatory approach, please see the final rule and 

preamble, including the discussion of the repermitting of Class II EOR wells for GS, as well as 

the rulemaking docket. 

4
Letter ID: 0230 Comment ID: 21872 Letter Lines: 195 to 207 

Comment Code: 1450 1.2.2.1 Oppose the GS rulemaking 

Comment Code: 1680 1.3.8 Don't overstate risk, don't stigmatize CO2 

Comment: GENERAL COMMENTS AND CONCERNS ABOUT THE PROPOSED UIC 

RULE 

1. It is strongly recommended that the EPA promote and encourage, not block and 

erect barriers to, geosequestration of CO2 for both productive and nonproductive uses of CO2. 

EPA’s stated goals for this proposal are to protect Underground Sources of 

Drinking Water (USDWs) while promoting carbon capture and storage. The proposed 

regulations would succeed in protecting USDWs, but would fails to promote carbon 

capture and storage. The Proposed Rule overestimates the risks of CO2 geologic 

sequestration and creates barriers to rapid technology development and 

commercial scale deployment projects that will greatly benefit American (as 

noted in the preceding narrative). 

Individual Response: EPA disagrees that the requirements in the GS rule overstate the risk 

associated with GS. The requirements for Class VI wells are tailored to address the unique nature 

of full-scale CO2 GS, including the volumes of CO2 being anticipated for long-term storage, the 

buoyant nature of the injectate, its mobility within subsurface geologic formations, and its 

corrosivity in the presence of water. 

EPA believes that the creation of a new injection well class (VI) under the existing UIC Program 

is necessary to enable deployment of GS as a climate change mitigation technology in a manner 

that protects USDWs from endangerment. EPA agrees that the UIC Program, under the authority 

of the SDWA, provides a strong framework for regulating injection of CO2 for GS and adds that 

the GS regulation tailors the UIC requirements to address the unique issues associated with 

large-scale GS including large injection volumes, the relative buoyancy of CO2, its corrosivity in 

the presence of water, the potential presence of impurities in captured CO2, and its mobility 

within subsurface geologic formations. 

In response to comments that the GS rule could impede technology, EPA stresses that the 

purpose of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that 

protects USDWs from endangerment. 

Letter ID: 0230 Comment ID: 21873 Letter Lines: 209 to 210 

Comment Code: 1000 1. General and Administrative Comments 

Comment: 2. We generally agree with and endorse the Texas Carbon Capture and Storage 

Association (TxCCSA) comments to the Proposed Rule. 

5
Individual Response: EPA acknowledges the comment. Please see the remainder of EPA's 

responses to this comment letter and TxCCSA’s comment letter for further details. For additional 

information on EPA's final regulatory approach, please see the final rule and preamble, as well as 

the rulemaking docket. 

Letter ID: 0230 Comment ID: 21874 Letter Lines: 212 to 216 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: 3. The proposed 50-year post-injection site care timeframe discriminates against 

smaller operators. The extraordinarily long-term obligation this provision 

creates will almost certainly prevent some small and middle-size companies from 

undertaking otherwise successful and beneficial CO2 injection projects because 

of the significant financial burden imposed. 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive for most Class VI wells. EPA proposed a default post-injection site care timeframe of 

50 years based on a review of research studies, industry reports, and existing environmental 

programs. This analysis was included in an EPA-prepared background document that is available 

in the federal docket, titled "Computational Modeling of Underground Injection of Carbon 

Dioxide for Determination of Area-of-Review and Potential Risk to Underground Sources of 

Drinking Water." EPA assessed various default timeframes based on additional review of 

research studies and evaluation of public comments. While numerous commenters suggested that 

EPA shorten the monitoring timeframe, none of the commenters provided sufficient data or other 

evidence to warrant a change in the proposed timeframe. While the 10- or 30-year timeframe 

suggested by some of these commenters may be within the timeframe suggested in some studies, 

EPA believes that the potential risks of endangering USDWs will likely not decline within these 

timeframes and available data, including data submitted by commenters, do not support a 

different default timeframe. However, EPA recognizes that alternative timeframes may be 

appropriate under limited, specific circumstances. 

For this reason, the GS rule offers owners or operators flexibility regarding the duration of the 

PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC 

timeframe during the post-injection period based on site-specific data, pursuant to requirements 

at §146.93(b); or (2) affording the Director discretion to allow a Class VI well owner or operator 

to demonstrate, during the permitting process based on substantial data, that an alternative PISC 

timeframe may be appropriate if it ensures non-endangerment of USDWs pursuant to 

requirements at §146.93(c). 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 50 

year post-injection site care timeframe represents a reasonable and protective monitoring period 

based on a review of research studies, industry reports, and existing environmental programs, 

and evaluation of public comments. 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

6
adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA adds that the purpose of the GS rule is not to incentivize the use of GS; rather, the purpose 

of the GS rule is to ensure that, where GS is deployed, it is conducted in a manner that protects 

USDWs from endangerment, regardless of the size of the project. EPA adds that as part of the 

rulemaking process, the Agency has evaluated the impacts of the GS rule on small entities and 

determined that it will not have a significant economic impact on a substantial number of small 

entities. See the discussion of the Regulatory Flexibility Act in the preamble to the final GS rule. 

Letter ID: 0230 Comment ID: 21875 Letter Lines: 218 to 225 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: 4. The Proposed Rule does not recognize the benefits of injection in EOR plays. 

EPA does not consider CO2 to be sequestered following injection for EOR. Many 

CO2 sequestration projects will be associated with oil and gas operations. 

However the Proposed Rule states that sequestration begins only after enhanced 

recovery of oil or gas has stopped. The implication is that the CO2 injected for 

enhanced recovery is not ultimately sequestered upon cessation of injection and 

production activity. 

Individual Response: EPA recognizes that the oil and gas industry has decades of experience 

injecting CO2 for the purpose of ER, and that sites used for ER may be suitable for GS and may 

be among the first GS sites. Furthermore, EPA recognizes that some portion of CO2 injected for 

purposes of EOR is sequestered. However, the Agency believes that the nature and risks of CO2 

injection for the primary purpose of long term storage pose different risks than injection for the 

primary purpose of ER, and therefore has developed new Class VI regulations to address these 

unique risks. For example, the volume of CO2 anticipated to be injected for long term storage is 

significantly greater than for ER operations. Reservoir pressure conditions will also be different, 

with Class VI injection operations involving large volumes of CO2 and likely having higher 

pressures within their storage formations than Class II ER projects, which may lead to fluid 

movement that endangers a USDW. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

7
The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

EPA is developing guidance on transitioning permits from Class II to Class VI. The guidance 

will assist Directors in determining whether an injection project should be transitioned from 

Class II where the primary purpose is oil and gas production to Class VI where the primary 

purpose is long-term storage of large volumes of CO2. The guidance describes recommended 

methods the Director may use to evaluate changes in risk to USDWs from projects, and how the 

Director may determine whether a project should be regulated within the Class II or Class VI 

UIC program. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. For more information, please 

see the discussion on transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0230 Comment ID: 21882 Letter Lines: 227 to 234 

Comment Code: 1480 1.2.2.2.2 CO2 is not a pollutant 

Comment: 5. The Proposed Rule incorrectly implies that CO2 is a waste. 

The EPA states that it has not classified CO2 as a waste or a commodity. 

However, by using the waste injection well requirements (Class I) as the 

framework for the new Class VI requirements, the Proposed Rule implies that the 

CO2 is a waste. The Proposed Rule has proposed requirements for Class VI 

injection wells that are more severe than those for wells used for the injection 

of hazardous waste. 

Individual Response: EPA disagrees that the requirements in the GS rule overstate the risk 

associated with GS or imply that CO2 is a waste. The requirements for Class VI wells are 

tailored to address the unique nature of full-scale CO2 GS, including the injection volumes 

anticipated for long-term storage, the buoyant nature of the injectate, its corrosivity in the 

presence of water, and its mobility within subsurface geologic formations. 

In addition, although the requirements were based on the existing regulatory framework for deep 

wells, including Class I wells, the GS rule does not address the status of CO2 as a pollutant or 

commodity. EPA based many of the GS requirements on the Class I regulations because, like 

Class VI wells, Class I wells are typically deep and involve waste streams that, if not properly 

managed, can harm the well and lead to contamination. 

Under §146.82(a)(7), owners or operators of GS wells must characterize their CO2 stream as part 

of their permit application. If the injectate is determined to meet the definition of a hazardous 

waste under RCRA, and as defined in 40 CFR Part 261, the stringent UIC Class I hazardous 

waste requirements for injection of hazardous waste apply. Thus, injection of corrosive CO2 into 

Class VI wells is prohibited. In addition, owners or operators must periodically monitor their 

injectate throughout injection operations under §146.90(a). 

8
Letter ID: 0230 Comment ID: 21883 Letter Lines: 236 to 248 

Comment Code: 1680 1.3.8 Don't overstate risk, don't stigmatize CO2 

Comment: 6. The Proposed Rule overestimates the risks of CO2 injection. 

The Proposal Rule implies that when the purpose of the injection switches from 

enhanced recovery to sequestration, the risks to USDWs are significantly 

magnified. With appropriate site selection, construction, monitoring, and 

testing, the risks of CO2 geologic sequestration would be comparable to the 

risks of current activities such as natural gas storage and enhanced recovery of 

oil. 

EPA begins with the framework of Class I non-hazardous industrial waste 

injection well requirements and adds additional layers of redundant requirements 

to prevent or detect the escape of CO2 from the injection zone. EPA apparently 

believes that the Class II program is not sufficiently protective. 

Individual Response: EPA disagrees that the GS regulation overstates or overestimates the risk 

of CO2 injection. EPA recognizes that injecting large volumes of CO2 for GS poses unique 

challenges that, if not properly managed, could endanger drinking water sources and have other 

adverse impacts. However, with proper site selection, the final, tailored, Class VI requirements 

address the large volumes of CO2 injected, its buoyancy, potential corrosivity in the presence of 

water, and potential impurities in the CO2 stream. In addition, EPA expects the tailored 

permitting, siting, construction, operation, monitoring, and post-injection site care requirements 

in the GS rule to prevent leakage from injection formations and protect USDWs. 

EPA believes that injection for the primary purpose of long-term storage is sufficiently different 

from Class II ER operations and warrants tailored requirements. For example, the volume of 

CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II wells. 

Reservoir pressure conditions will also be different, with Class VI injection operations involving 

large volumes of CO2 and likely having higher pressures within their storage formations than 

Class II ER projects. 

Letter ID: 0230 Comment ID: 21884 Letter Lines: 250 to 255 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment: 7. The Proposed Rule precludes a meaningful role for States. 

UIC regulations developed by EPA must permit or provide consideration of varying 

geologic, hydrological, or historical conditions in different States and in 

different areas within a State. The Proposed Rule does not allow State directors 

to use their expertise and knowledge to account for these varying conditions. 

9
Individual Response: EPA agrees that permitting decisions for GS wells should be based on 

site-specific factors. The GS rule requires owners or operators to submit, and Directors to 

consider, extensive site-specific data, specified at §146.82, to demonstrate that a site is suitable 

for GS. Additionally, many of the permit requirements for GS wells are established through 

individualized site-specific plans for AoR and corrective action, testing and monitoring, and 

injection well plugging and post-injection site care and site closure. EPA adds that the final GS 

rule includes a balance of specific criteria to be met by the owner or operator and areas of 

Directorial discretion and considerations for how that discretion would be exercised. The Agency 

believes this balance allows for GS projects to be designed and permitted to address the unique, 

site-specific aspects of each project, while providing consistency in permitting across the U.S. 

In response to the comment that States with primacy be able to develop “performance-based 

standards,” the Agency clarifies that States, Tribes, and Territories can develop requirements for 

Class VI and submit primacy applications (under Section 1422 of the SDWA) for review and 

approval by EPA as long as the requirements are as stringent as or more stringent than the 

Federal minimum requirements. 

Letter ID: 0230 Comment ID: 21885 Letter Lines: 257 to 266 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: SPECIFIC RECOMMENDATIONS FOR IMPROVEMENTS IN THE UIC RULE 

1. EPA should create a subclass within the Class II well classification for 

operators who plan to sequester CO2 in association with enhanced recovery of oil 

or natural gas (with appropriate and necessary additional requirements to 

address any CO2 issues). 

2. Any Class VI injection well program might be applied to injection wells used 

to sequester CO2 in formations that are non-productive, such as deep saline 

formations. 

Individual Response: The final rule does not designate a subclass under the Class II well 

classification. EPA agrees that injection of CO2 for the primary purpose of enhancing oil and gas 

recovery should remain under the Class II Program. However, the Agency disagrees that wells 

injecting CO2 for the primary purpose of long-term storage should be regulated under Class II 

requirements. The Agency believes that the nature and risks of CO2 injection for the primary 

purpose of long-term storage pose different risks than injection for the primary purpose of EOR, 

and therefore has developed new Class VI regulations to address these unique risks. For 

example, the volume of CO2 anticipated to be injected for long-term storage is significantly 

greater than for EOR operations. Reservoir pressure conditions will also be different, with Class 

VI injection operations involving large volumes of CO2 and likely having higher pressures 

within their storage formations than Class II EOR projects, which may lead to fluid movement 

that endangers a USDW. 

10
EPA clarifies that the final Class VI regulations require that any owner or operator injecting CO2 

for the primary purpose of long term storage obtain a Class VI permit with some special 

consideration for the fact that they are transitioning from a well not originally designed to meet 

Class VI requirements. The Director has the authority to determine at what point a Class VI 

permit is required for those projects that are transitioning from the primary purpose of EOR to 

long term storage of CO2. The final regulation provides a set of technical factors for the Director 

to evaluate in making this determination, at §144.19. EPA believes that this approach provides 

sufficient protection of USDWs when there is an increased risk to USDWs as compared to 

traditional Class II operations while allowing for site-specific flexibility. For more information, 

please see the discussion on transition of Class II wells in the preamble to the final GS rule. 

Letter ID: 0230 Comment ID: 21886 Letter Lines: 268 to 271 

Comment Code: 1250 1.1.1.4 Flexibility is needed (performance-based standards) 

Comment Code: 2000 1.5 Need for a New Class of Injection Well 

Comment: 3. EPA should begin with a Class II injection well framework to assure that the 

rules are flexible enough to consider site-specific characteristics and 

knowledge gained from the extensive CO2 history and the ongoing demonstration 

and pilot projects. 

Individual Response: EPA agrees that owners and operators of Class II wells have experience 

that will be helpful in implementing the Class VI requirements, but EPA disagrees that the risks 

posed by long-term storage of CO2 for GS can be addressed under existing UIC requirements, 

such as those for Class II wells. EPA believes that there are significant differences between how 

projects are operated, as well as the risks posed by these different injection activities. The new 

tailored approach of the GS rule was designed to address the general risks deep injection may 

pose to USDWs and was tailored specifically to address the risks posed by long-term storage of 

CO2 (i.e., very large volumes, very long time-periods, and reservoir pressure conditions). 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. For more information, please see the discussion on 

transition of Class II wells in the preamble to the final GS rule. 

Furthermore, EPA agrees that flexibility is important for regulating GS activities. EPA has taken 

a regulatory approach which promotes USDW protection, incorporates flexibility or the 

discretion of the permitting authority when appropriate, seeks to limit burden on owners or 

operators and permitting agencies, and provides a foundation for national consistency in 

permitting of GS projects. For example, under the final rule, many of the permit requirements 

11
must be established through site-specific plans (e.g., AOR and corrective action plan, testing and 

monitoring plan, etc.) developed by the owner or operator and approved by the Director. 

Consequently EPA expects that owners or operators will consult with the Director as they 

develop, implement, and update these plans. Additionally, the Director has the discretion to 

approve alternatives to the requirements in some cases. For example, the Director may in certain 

situations modify the length of the post-injection site care period or approve an alternative postinjection site care timeframe as part of the permitting process under §146.93, allow the use of 

alternate methods for mechanical integrity testing under §146.89, or grant waivers from the 

requirement to inject below the lowermost USDW under §146.95. 

Letter ID: 0230 Comment ID: 21887 Letter Lines: 273 to 275 

Comment Code: 2100 1.6 Target Geologic Formations for GS 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment: 4. EPA should provide flexibility in the siting requirements including promoting 

utilization of EOR, Enhanced Gas Recovery (EGR) and Enhanced Coalbed Methane 

Recovery (ECBM) formations for storage. 

Individual Response: EPA clarifies that the GS rule does not categorically preclude injection of 

CO2 into any non-USDW formation types. The purpose of the GS rule is to ensure protection of 

USDWs from endangerment, and the rule requires that owners or operators demonstrate that 

wells are sited in suitable systems with geologic formations to receive and confine injected CO2, 

required at §146.83 of the GS rule. The Class VI siting, well construction and operation, 

monitoring and testing, and post-injection site care and site closure requirements are designed to 

ensure that injected CO2 remains within the target formation. If an owner or operator can 

demonstrate to the Director's satisfaction that GS in coal seams, basalts, salt domes, or shales can 

be accomplished in a manner that protects USDWs and meets all of the requirements of the GS 

rule, the project may be permitted as a Class VI well. 

EPA acknowledges that site-suitability for GS is dependent on a number of factors and that many 

formation types may be suitable for GS. EPA agrees that GS into unmineable coal seams has the 

potential to allow sequestration while ensuring USDW protection from endangerment, as 

described by commenters citing the process of enhanced methane recovery. The final GS rule 

does not preclude injection into unmineable coal seams provided owners or operators can 

demonstrate that GS can be performed in a manner that protects USDWs from endangerment. 

The Agency clarifies that owners or operators of Class VI wells used for injecting CO2 into 

unmineable coal seams are subject to the same site characterization, well construction, operation, 

monitoring, post-injection site care and site closure requirements that are required of projects 

injecting into other formation types. 

Letter ID: 0230 Comment ID: 21888 Letter Lines: 277 to 280 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

12
Comment: 5. EPA should provide more flexibility in operational requirements including 

allowing an EOR/EGR/ECBM operator to demonstrate that CO2 is sequestered rather 

than the prescriptive 10-year default period for reevaluation of the area of 

review. 

Individual Response: EPA clarifies that the AoR reevaluation required at §146.84(e) is not 

intended to serve as a replacement for monitoring of the site or demonstrating containment. 

While the two are linked—monitoring and operational data will inform the AoR reevaluation and 

changes to the calculated AoR may necessitate changes to the testing and monitoring plan—EPA 

believes that periodic monitoring, including ground water sampling and plume and pressure front 

tracking, are necessary to ensure that CO2 is not endangering USDWs. 

EPA is retaining the approach of setting a minimum fixed frequency for reevaluating the AoR 

but has, based on commenters' input, changed the frequency from 10 years to at least every 5 

years, as specified in §146.84(e). EPA agrees with commenters that site-specific information is 

an important factor in determining an appropriate AoR reevaluation frequency, and adds that the 

owner or operator's AoR and corrective action plan must describe the minimum fixed frequency 

for reevaluating the AoR and the site-specific conditions on which this frequency is based. 

Letter ID: 0230 Comment ID: 21889 Letter Lines: 282 to 286 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: 6. EPA should provide for performance-based requirements for Closure and Post 

Closure Care. The duration of post-injection site care should be determined by 

specific conditions and characteristics of the site, and monitoring of the 

pressure to determine the point at which the injection zone pressure is such 

that USDWs cannot be impacted. 

Individual Response: The PISC requirements in the final GS rule, as specified in §146.93(b), 

incorporate a combination of a fixed timeframe and a performance standard approach. EPA 

believes that a default PISC timeframe of 50 years, with Director's discretion to shorten or 

lengthen this timeframe, combined with a site-specific Director’s discretion to create an 

alternative PISC time frame, ensures that USDWs are protected. The GS rule offers owners or 

operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director 

discretion to shorten or lengthen the PISC timeframe during the PISC period based on sitespecific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to 

allow a Class VI well owner or operator to demonstrate, based on substantial data during the 

permitting process, that an alternative PISC timeframe may be appropriate if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

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sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA is developing guidance to assist owners or operators in evaluating the well plugging, postinjection site care, and site closure requirements of 146.92 and 146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes how an owner or 

operator should plug injection and monitoring wells, perform post-injection monitoring, 

demonstrate the appropriateness of an alternative post-injection site care time frame, demonstrate 

non-endangerment, and perform site closure activities. 

Letter ID: 0230 Comment ID: 21890 Letter Lines: 288 to 290 

Comment Code: 3110 2.1.1 Proposed siting requirements (i.e., injection/confining zones, 

trapping mechanism) 

Comment: 7. EPA should provide for a system for qualifying sequestration sites, including 

qualifying geographically and geologically diverse sites for CO2 injection in 

non-trapping (oil/gas) applications. 

Individual Response: EPA disagrees that a system for qualifying GS sites is appropriate. 

Instead, the GS rule focuses on evaluating the suitability of each site based on site-specific 

geological and operational data. EPA believes that requiring appropriate, site-specific, site 

characterization by the owner or operator (under §146.82) and providing an appropriate degree 

of flexibility to the Director to evaluate site-specific geologic data will afford the greatest 

protection of USDWs from endangerment. EPA believes that it is important for the Director to 

have as much site-specific information as possible in order to make an informed decision to 

permit injection for GS at a specific site. This approach allows the permit writer to establish 

requirements considering varying site conditions, eliminating the need for tiered requirements. 

GS in areas that may pose risks to USDWs, as assessed and identified by the owner or operator 

and the Director during the site selection process, would not be permitted. 

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