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 B ALTIMORE P IKE  L ITTLESTOWN

, P ENNSYLVANIA 17340 USA

T EL : 717

- 359

- 0014  F AX : 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 2 4 , 2008

Subject: Comments on Federal Requirements Under the Underground Injection

Con trol (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 Internati o nal, LLC. AmericanEnergySecurit y .org is dedicated to educat ing 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

embr aces 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 ef

ficiencies and sensible conservation have roles to play as well.

U n n ecessary government policies and regulations , like the subject EPA rule, can continue to deny the United States the energy security it needs to prosper.

CO 2 Enhanced Oil Recovery (EOR) i s 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 CO 2 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

.A. J. M AYER I NTERNATIONAL , LLC Page 2 Enhanced oil recovery offers the potential to vastly expand domestic crude oil reserves and production, while simultaneously providing a positive answer to CO 2 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 CO 2 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 produ ction.

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 t hat an additional 3.0 million daily barrels per day of American crude can be produced using CO 2, ultimately increasing domestic oil output by more than 50%. As an indicator of this potential, CO 2 EOR has already stimulated rising oil production in Mississ ippi and Wyoming, where adequate,

low cost sources of CO 2 have been available to support growth. Unfortunately, there are

substantial CO 2 shortages in most U.S. oil basins that constrain the growth of CO 2 EOR

. The prospect of capturing and utilizing addi tional 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 m ature oil fields

, facilitat ing a rapid increase in domestic production from

stranded oil (as described below) , and substantial economic and n ational s ecurity benefits

.A. J. M AYER I NTERNATIONAL , LLC Page 3 The United States has Vast EOR Potential that is Geographically Diverse

In term s of resource base, the U.S. CO 2 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 CO 2 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 beneat h 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 ). CO 2 injection (tertiary recovery) into R OZs 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 billio ns of barrels, offering the potential to significantly increase the

88+ billion barrel CO 2 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 CO 2 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 potenti al of about 1.4 million barrels per day. In contrast, U.S. CO 2 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 “s inks” for billions of tons of CO 2

.

The graphic below (Figure 2) is a simplified diagram of the CO 2 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 C O 2 dense phase. The compressed CO 2 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 CO 2 injection well is typically surrounded by a number of production wells organized in a “pattern”. Any CO 2 produced with the oil is separated and re

injected. The CO 2 that is not recycled is effectively trapped within the formation in dead

- end

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

the CO 2 is permanently sequestered underground

.

In current practices, the amount of CO 2 injected to mobilize oil is carefully controlled

due to the cost of the CO 2

. The yield of a CO 2 EOR project typically varies from two to four barrels of oil produced from every ton of CO 2 purchased. CO 2 EOR has not seen wider application because of the high project capital costs, historically low oil prices, and limited supplies o f low cost, pure CO 2 . But in today’s high oil price environment, the main constraint is a shortage of CO 2 . Enhanced oil recovery operators are currently paying between $10 and $30 per ton for CO 2 , when they can find it. The market is there. The challen ge is to provide

incentives for more CO 2 generators to capture their carbon dioxide streams, and developers to

build CO 2 pipelines from CO 2 sources to the oil and methane fields that need it. Today’sA. J. M AYER I NTERNATIONAL , LLC Page 4 suppl ies of CO 2 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 CO 2 Injection

Other emer ging 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 CO 2 . These and other

technol ogies promise to create additional markets for CO 2 but require more research and development efforts to reach commercial viability. In contrast, CO 2 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, stimul ate 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 CO 2 , to enhance natural gas, algae growth for biofuels, etc. Conversely, t he current focus on the passive, costly sequestration of CO 2 in deep saline formations will increase the price of all U.S. energy products and thus impose a significant

burden on our ec onomy and our society.

Commercial sequestration will enable the next generation of domestic energy production. CO 2 occurs naturally in the subsurface and it is no stranger to geologists who attempt to understand fluid migration and subsurface accumulation s. The fact that CO 2 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 excellen t 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.A. J. M AYER I NTERNATIONAL , LLC Page 5 GENERAL COMMENTS AND CONCERNS ABOUT THE PROPOSED UIC RULE

1

. It is strongly recommended that th e EPA promote and encourage, not block and erect barriers to, geosequestration of CO 2 for both productive and non

- productive uses of

CO 2 .

EPA’s stated goals for this proposal are to protect Underground Sources of Drinking Water (USDWs) while promoting car bon 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 CO 2 geologic sequestration and creates barriers to rapid technology de velopment and commercial scale deployment projects that will greatly benefit American (as noted in the preceding narrative)

.

2

. W e 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

otherw ise 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 CO 2 to be sequestered following injection for EOR

. Many CO 2 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 CO 2 injected for enhance d recovery is not ultimately sequestered upon cessation of injection and production activity.

5 . The Proposed Rule incorrectly implies that CO 2 is a waste.

The EPA states that it has not classified CO 2 as a waste or a commodity. However, by using

the w aste injection well requirements (Class I) as the framework for the new Class VI requirements, the Proposed Rule implies that the CO 2 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 CO 2 injection.

The Proposal Rule implies that when the purpose of the injection switches from enhanced recovery to sequestration, the risks to USDWs are si gnificantly magnified. W ith appropriate site selection, construction, monitoring, and testing, the risks of CO 2 geologic sequestration would be comparable to the risks of current activities such as natural gas storage and enhanced recovery of oil.

EPA beg ins with the framework of Class I non

- hazardous industrial waste injection well requirements and adds additional layers of redundant requirements to prevent or detect theA. J. M AYER I NTERNATIONAL , LLC Page 6 escape of CO 2 from the injection zone. EPA apparently believes that the Class II prog ram 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 CO 2 in association with enhanced recovery of oil or natural gas (with appropriate and necessary additional requirements to address any CO 2 issues).

2

. Any Class VI injection well program might be appl ied to injection wells used to sequester CO 2 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 conside r site

- specific characteristics and knowledge gained from the

extensive CO 2 history and the ongoing demonstration and pilot projects.

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

utilization of EOR , Enhanced Gas Recov ery (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 CO 2 is sequestered rather than the prescript ive 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 char acteristics 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 geograp hically and geologically diverse sites for CO 2 injection in non

- trapping (oil/gas) applications.

[This Space Left Blank Intentionally]A. J. M AYER I NTERNATIONAL , LLC Page 7 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, P ennsylvania 17340

Tel: 717

- 359

- 0 0 14

Email: jamesmayer@americanene rgysecurity.orgU.S. Department of Energy • Office of Fossil Energy • Office of Oil and Natural Gas

February 2006 

# Project Facts

Recovering “Stranded Oil” Can Substa ntially 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 i ndicate significant potential for increasing domestic oil supplies. This could result from applying carbon dioxide enhanced oil recovery (CO 2 -EOR) technology to recover nearly 89 billion barrels of additional oil from cu rrently “stranded” oil resour ces in ten regions of the United States. The reports summarize the results of basin-oriented CO 2 -EOR assessments prepared by

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

CO 2 -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 reservoi rs in basins/areas. ** Remaining oil in pl ace, in all reservoirs in basins/areas.
Source: Advanced Resources International

According to the Oil and Gas Journal, CO 2 –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 CO 2 -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 cont ribution of this technology for recovering crude oil from mature domestic oil fields. In addition, the reports assess the performance of CO 2 -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 es timated 390 billion barrels of already discovered oil
resources in the ten basins studied. Such “stranded oi l” provides a substantial target for EOR technology, representing about two-thirds of the region’s original o il in-place in discovered, producing fields. The ten assessments evaluated 1,5 81 large oil reservoirs to identify those that screen favorably for CO 2 -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 t en regions demonstrated that nearly 89 billion barrels of additional oil are technically recover able with today’s state-of-the art CO 2 -EOR technology. Advanced EOR technologies could significantly incr ease this oil recovery potential.

Overcoming the barriers to the wider use of CO 2 -EOR technologies may entail:

3⁄4 Bringing state-of-the-art CO 2 -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
CO 2 -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 CO 2 -EOR

3⁄4 Establishing low-cost, reliable “EOR-ready” CO 2 supplies from both natural and industrial sources. In the near-term, this could include high-concentration CO 2 emissions from refinery hydrogen plants, gas processing facilities and other industrial sources. In the longer-term, this could include capturing low
CO 2 concentration emissions from electric power generation plants and other sources.

Together, these “basin-oriented strategies” could hel p 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 lo cal 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) 528-8420U.S. Department of Energy • Office of Fossi l Energy • Office of Oil and Natural Gas

February 2006 

# Project Facts

Production of “Stranded Oil” in th e 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 establis hed. 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 CO 2 enhanced oil recovery (CO 2 -EOR) technologies. These thick residual oil zones exist where nature has already wa terflooded 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 CO 2 -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 t he technical feasibility of recovering oil from the transition and residual oil zones. It then reviews the results of three on-going CO 2 -EOR projects to examine the commercial merits of CO 2 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 Fr om 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. Howe ver, much larger “stranded” oil targets exist in residual oil zones of non-capillary origin. These thic ker 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 hydr odynamics on the tilt of the oil-water contact of an oil reservoir leading to the oil trapped in the ROZ.

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

February 2006 Current ROZ Field Projects. Three residual oil zone CO 2 -EOR projects are underway in the Permian Basin of West Texas. They are: Occidental’s Tran sition 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 avail able 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 avail able 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. T he oil in-place in the TZ/ROZ is estimated at 30.7 billion barrels, with 11.9 billion barrels potentially technica lly 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 technica lly recoverable.

3⁄4 Big Horn Basin. The report identifies 13 oil re servoirs that hold 4.4 billion barrels of oil in-place in the
TZ/ROZ of which 1.1 billion barrels is potentially technica lly recoverable.

Next Steps. Obtaining sufficient reservoir data for defin ing the ultimate size and productivity of the TZ/ROZ will be challenging. However, there will be great value from undertaking th is 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. Ul timately, field-by-field a nalyses will be necessary and will require considerable effort to fully establish t he 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. Copi es 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

2Letter 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 regula tions, 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, s ponsored by the Atlant a 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 dependen ce on imported oil and natural gas. The harmful economic and national security im pacts 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 endangermen t. 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 pur pose 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 potentia l 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 r ecent 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.

1Crude 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 an d other liquid by-pr oducts). Leading experts estimate that an additional 3.0 million daily barrels per day of American crude can be produced using CO 2, ultimately increasing domestic oil output by more than 50%. As an indicator of this potential, CO 2 EOR has already stimulated rising oil production in Mississ ippi and Wyoming, where adequate, low

cost sources of CO2 have been available to support growth. Un fortunately, there are substantial CO2 shortages in most U.S. oil basins that constrain the growth of CO2 EOR. The prospect of capturing a nd utilizing additiona l and substantial low cost CO2 supplies from the gasification of American coal, petroleum coke, municipal solid waste, and biomass re presents the ultimate economic and environmental leveraging of our st rategic domestic energy resources. Gasification clearly offers a "next genera tion" in energy effi ciency, emissions control, and fuel and chemical product manufacturing flexibility. Gasification plants can be configured to make one or a portfolio of tran sportation fuels, chemicals, fertilizers, natural gas subs titutes, 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 domes tic production from stranded oil (as described below), and subs tantial economic and nationa l 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 Poten tial 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. [S EE EPA-HQ-OW-2008-0390-0230.PDF FOR FACT SHEETS] In addition, experts are currently assessing another tr emendous CO2 EOR target--a new class of virg in oil resources being refe rred 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 wate r 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 bil lions of barrels, offering the potential to significantly increase the 88+ billi on barrel CO2 EOR reserve base (see the

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

2residual oil zone projects ar e already in production in the U.S., including an operation at the Hess Seminole Field and one at Occidental Pe troleum’s Wasson

field - both in West Texas. Other fields with substantial ROZ resources await CO2 availability for exploitation. The tota l EOR prize is believed to total or exceed 100 billion barrels of oil, includi ng 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 produc tion 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 la rge markets and geologic sequestration

"sinks" for billions of tons of CO2.

The graphic below (Figure 2) is a simplifie d diagram of the CO2 EOR process. In commercial operations carbon dioxide is transported under pressure to the project area by pipeline in what the indus try refers to as the CO2 dense phase. The compressed CO2 is then sent undergr ound 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 num ber 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 th e CO2 is permanently sequestered underground.

In current practices, the am ount of CO2 injected to m obilize oil is carefully

controlled due to the cost of the CO2. Th e 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 genera tors to capture th eir carbon dioxide streams, and developers to build CO2 pi pelines 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 produc tion, 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

3worth mentioning. These include the enhan ced production of natural gas, coalbed methane, and agricultural products (including algae fo r fuel production) with CO2. These and other technologies promise to create additional markets for CO2 but require more research and developmen t 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 excell ent foundation from

which to advance American Energy Security, stimulate a nd grow the economy, and protect the environment. This can and should be followed by the rapid development and deployment of other producti ve 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 t hus 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 s ubsurface 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 consid ered by recognized pe troleum engineers and geologist to be excellent final re sting place for CO2. These traps have already demonstrated the ability to ho ld 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 indus tries, with tailored requirements that address the unique nature of CO2 injection for GS.

The Agency clarifies that the final GS rule doe s not require owners or operators to use GS technologies, nor does it impact business as us ual for Class II owners or operators that are injecting CO2 to enhance production of oil or ga s. 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 le tter for further details. For additional information on EPA's final regulato ry approach, please see the final rule and preamble, including the discussion of the repermitt ing of Class II EOR wells for GS, as well as the rulemaking docket.

4Letter 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 ris k, don't stigmatize CO2

Comment: GENERAL COMMENTS AND CONCERNS ABOUT THE PROPOSED UIC

RULE

1. It is strongly recommended that the EP A 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 ar e to protect Underground Sources of Drinking Water (USDWs) while promoting car bon capture and storage. The proposed regulations would succeed in protecting US DWs, but would fails to promote carbon capture and storage. The Proposed Rule ove restimates 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 a ddress the unique nature of full-scale CO2 GS, including th e volumes of CO2 being anticipat ed for long-term storage, the buoyant nature of the injectate, its mobility within subsurf ace geologic formations, and its corrosivity in the presence of water.

EPA believes that the creation of a new inject ion well class (VI) under th e 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 ag rees that the UIC Program, under the authority of the SDWA, provides a strong fr amework for regulating injection of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the unique i ssues associated with large-scale GS including large injection volumes, the relative buoya ncy 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 c ould 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.

5Individual Response: EPA acknowledges the comment. Pleas e see the remainder of EPA's responses to this comment lette r and TxCCSA’s comment letter fo r further details. For additional information on EPA's final regulatory approach, pl ease 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 certain ly prevent some small and middle-size companies from undertaking otherwise successful and benefi cial CO2 injection projects because of the significant financial burden imposed.

Individual Response: EPA disagrees that a post-injection si te care timeframe of 50 years is excessive for most Class VI wells. EPA proposed a default post-injection s ite 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 "Computationa l Modeling of Underground Injection of Carbon

Dioxide for Determination of Area-of-Review a nd Potential Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes based on additional review of research studies and evaluation of public commen ts. While numerous commenters suggested that EPA shorten the monitoring timeframe, none of the commenters provided suffi cient 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 endange ring USDWs will likely no t decline within these timeframes and available data, including da ta submitted by commenters, do not support a different default timeframe. However, EPA r ecognizes that alternative timeframes may be appropriate under limited, specific circumstances.

For this reason, the GS rule offers owners or op erators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengthen the PISC timeframe during the post-injecti on period based on site-specific da ta, 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 ensu res non-endangerment of USDWs pursuant to requirements at §146.93(c).

EPA believes however, that to ensure USDW protection from enda ngerment, a default timeframe for post-injection site care will be necessary in al l but a limited number of cases. This default 50 year post-injection site care ti meframe represents a reasonable and protective monitoring period based on a review of research studies, industr y reports, and existing environmental programs, and evaluation of public comments.

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

6adjust 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 ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-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 th e 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 Flexibil ity 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 in jection 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 injecti on in EOR plays.

EPA does not consider CO2 to be sequest ered following injection for EOR. Many CO2 sequestration projects will be associated with oil and gas operations. However the Proposed Rule states that se questration begins onl y after enhanced recovery of oil or gas has stopped. The implication is that the CO2 injected for enhanced recovery is not ultimately se questered 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 site s used for ER may be suitable for GS and may be among the first GS sites. Furthermore, EPA r ecognizes that some portion of CO2 injected for purposes of EOR is sequestered. However, the Agen cy believes that the nature and risks of CO2 injection for the primary purpose of long term stor age pose different risks than injection for the primary purpose of ER, and theref ore has developed new Class VI regulations to address these unique risks. For example, the volume of CO2 anticip ated to be injected for long term storage is significantly greater than for ER operations. Reser voir pressure conditions will also be different, with Class VI injection opera tions 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 re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2.

7The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal Class II operations while allowing for site-specific flexibility.

EPA is developing guidance on transitioning perm its 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 change s in risk to USDWs from projects, and how the Director may determine whether a project should be regulated within th e Class II or Class VI UIC program. This guidance will be available on EPA’s website at http://water.epa.gov/type/groundwat er/uic/wells_sequest ration.cfm. For more information, please

see the discussion on transition of Class II well s 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 im plies that CO2 is a waste.

The EPA states that it has not classi fied 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 requiremen ts, the Proposed Rule implies that the CO2 is a waste. The Proposed Rule ha s 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 natu re of the injectate, its corrosivity in the presence of water, and its mobility w ithin subsurface geologic formations.

In addition, although the requirement s were based on the existing regulatory framework for deep wells, including Class I wells, the GS rule does not address the stat us of CO2 as a pollutant or commodity. EPA based many of the GS requireme nts on the Class I regulations because, like Class VI wells, Class I wells are typically deep and involve waste stream s 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 de termined 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 peri odically monitor their injectate throughout injecti on operations under §146.90(a).

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

Comment Code: 1680 1.3.8 Don't overstate ris k, 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, th e risks to USDWs are significantly magnified. With appropriate site se lection, constructi on, monitoring, and testing, the risks of CO2 geologic seques tration would be comparable to the

risks of current activities such as natura l gas storage and enhanced recovery of

oil.

EPA begins with the framework of Class I non-hazardous industrial waste injection well requirements and adds additi onal layers of redundant requirements to prevent or detect the escape of CO2 fr om 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 recognize s that injecting large volumes of CO2 for GS poses unique challenges that, if not properly managed, could endanger drinking water s ources and have other adverse impacts. However, with proper site sele ction, the final, tailored, Class VI requirements address the large volumes of CO2 injected, its bu oyancy, potential corrosivity in the presence of water, and potential impurities in the CO2 stream. In addition, EP A 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 th e primary purpose of long-term storage is sufficiently different from Class II ER operations and warrants tailor ed 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 wi ll also be different, with Cla ss VI injection operations involving large volumes of CO2 and likely having higher pressures within th eir 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 (p erformance-based standards)

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

UIC regulations developed by EPA must perm it or provide consideration of varying geologic, hydrological, or hi storical conditions in di fferent States and in different areas within a State. The Propos ed Rule does not allow State directors to use their expertise and knowledge to account for these varying conditions.

9Individual Response: EPA agrees that permitting decisions for GS wells should be based on site-specific factors. The GS ru le requires owners or operators to submit, and Directors to consider, extensive site-specific data, specified at §146.82, to demons trate that a site is suitable for GS. Additionally, many of the permit require ments for GS wells are established through individualized site-specific pl ans for AoR and corrective actio n, 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 speci fic criteria to be met by the owner or operator and areas of

Directorial discretion and consider ations 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 prov iding 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, Trib es, and Territories can develop requirements for Class VI and submit primacy applications (unde r 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 in jection for EOR/EGR as Class II/ dividing line between Class II and Class VI (seeking comment)

Comment: SPECIFIC RECOMMENDATIONS FOR IM PROVEMENTS IN THE UIC RULE

1. EPA should create a subclass within the Class II well classification for operators who plan to sequester CO2 in asso ciation with enhanced recovery of oil or natural gas (with appropriate and n ecessary 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 forma tions 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-te rm storage should be regulated under Class II requirements. The Agency believes that the natu re 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 regul ations 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 EO R projects, which may lead to fluid movement that endangers a USDW.

10EPA clarifies that the final Cla ss VI regulations require that any owner or operator injecting CO2 for the primary purpose of long term storage ob tain 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 auth ority 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 fina l regulation provides a set of tec hnical factors for the Director to evaluate in making this determination, at §144.19. EPA believes that th is 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 transiti on of Class II wells in the pr eamble 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 (p erformance-based standards)

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

Comment: 3. EPA should begin with a Class II inject ion well framework to assure that the rules are flexible enough to consider site-specific char acteristics 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 di sagrees 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 th at 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 ri sks deep injection may pose to USDWs and was tailored sp ecifically to addre ss 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 re quire that any owner or operato r injecting CO2 for the primary purpose of long term storage obtain a Class VI pe rmit with some special consideration for the fact that they are transitioning from a well not or iginally designed to meet Class VI requirements. The Director has the authority to determine at wh at point a Class VI permit is required for those projects that are transitioning from the primar y purpose of EOR to long term storage of CO2. The final regulation provides a set of technical factors for the Direct or to evaluate in making this determination, at §144.19. EPA believes that this approach provides su fficient protection of

USDWs when there is an increased risk to USDWs as compared to traditi onal 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 impor tant 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 th e final rule, many of the permit requirements

11must be established through site -specific plans (e.g., AOR and corre ctive action plan, testing and monitoring plan, etc.) developed by the owne r or operator and appr oved by the Director. Consequently EPA expects that owners or opera tors will consult with the Director as they develop, implement, and update these plans. Ad ditionally, 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-injecti on site care period or appr ove an alternative postinjection site care timeframe as part of th e permitting process under §146.93, allow the use of alternate methods for mechanical integrity testing under §146.89, or gr ant 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 Recove ry (EGR) and Enhanced Coalbed Methane Recovery (ECBM) formations for storage.

Individual Response: EPA clarifies that the GS rule does not categorically prec lude 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 Cla ss VI siting, well cons truction and operation, monitoring and testing, and post-inj ection site care and site closur e 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 a nd meets all of the requirements of the GS rule, the project may be permitted as a Class VI well.

EPA acknowledges that site-suitabil ity 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 ensuri ng USDW protection from endangerment, as described by commenters citing th e process of enhanced methane recovery. The final GS rule does not preclude injection into unmineable co al seams provided owne rs or operators can demonstrate that GS can be performed in a ma nner 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, we ll construction, operation, monitoring, post-injec tion site care and site cl osure 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 fre quency (seeking comment)

12Comment: 5. EPA should provide more flexibility in operational requir ements including allowing an EOR/EGR/ECBM operator to demons trate that CO2 is sequestered rather than the prescriptive 10-year default pe riod for reevaluation of the area of

review.

Individual Response: EPA clarifies that the AoR reeval uation 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 operationa l data will inform the AoR reevaluation and changes to the calculated AoR may necessitate ch anges to the testing an d monitoring plan—EPA believes that periodic monitoring, including grou nd 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 fo r 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 appropria te AoR reevaluation freque ncy, and adds that the owner or operator's AoR and corrective action pl an 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-ba sed requirements for Closure and Post Closure Care. The duration of post-injecti on 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 year s, with Director's di scretion to shorten or lengthen this timeframe, combined with a site-s pecific Director’s disc retion to create an alternative PISC time frame, ensu res that USDWs are protected. The GS rule offers owners or operators flexibility regarding th e duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or lengt hen the PISC timeframe during the PISC period based on sitespecific data, pursuant to require ments at §146.93(b); or (2) afford ing the Director discretion to allow a Class VI well owner or operator to demo nstrate, based on substa ntial 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 car e 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

13sites where GS is anticipated to occur, to ac commodate site-specific circumstances and various geologic conditions, and addre sses commenters’ concerns, wh ile ensuring USDW protection. Both approaches will utilize si te-specific data, and be based on pressure monitoring and USDW impacts. EPA is developing guidance to as sist owners or oper ators 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 propo sed well plugging plans a nd 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 monitori ng wells, perform post-in jection monitoring, demonstrate the appropriateness of an alternative post-injection site care time frame, demonstrate non-endangerment, and perfor m 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 qua lifying GS sites is appropriate. Instead, the GS rule focuses on evaluating the su itability 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 (und er §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 belie ves that it is important for the Director to have as much site-specific information as possi ble 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 select ion process, would not be permitted.

14