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.
I offer my comments regarding proposed sequestration well rule offer by EPA on 25 July 

2008 at 73 FR 43491-43541.

I have five concerns with sequestration of CO2.

A: CO2 SEQUESTRATION IS NOT NECESSARY TO STOP GLOBAL WARMING

1. DOE compared the 2008 estimated CO2 emissions from anthropogenic 

sources with naturally occurring emissions, Fig 1. Based on the graph data, it 

is difficult to believe sequestering the anthropogenic releases will change 

anything. 

2. The only accurate means of measuring the changing Global Temperature 

is via satellite. Since 2001 the satellite measurements show a decrease of 

0.1°C per year, while the CO2 continues to increase..

3. The IPPC computer simulation of climate change predicts an “Atmospheric 

Hotspot” layer about 10 Km above the earth’s surface as CO2 increases. Try 

as we have, the weather balloons have never recorded such a raise in 

temperature. This casts doubt on the validity of the IPPC Model and the need 

for CO2 sequestration.

B: EPA STATES THE NECESSARY MATERIALS FOR THE COMPLETION OF 

SEQUESTRATION INJECTION WELLS ARE NOT CURRENTLY AVAILABLE.

1. CO2 when mixed with water forms carbonic acid.

2. Well casing, valves, packer slips and connectors are typically manufactured 

from carbon steel.

3. Carbon steel is highly corrosive when in contact with carbonic acid.

4. Stainless steel 404 is attacked by carbonic acid.

5. EPA suggests using stainless steel 316 for well heads on the basis on one

Enhanced Oil Recovery injection well. 

6. Cameron reports manufacturing only one SS 316 wellhead and Cameron does 

not know the fate of the one 316 wellhead.
7. My personal contact with the project consulting engineer for the well used by 

EPA resulted in no response regarding the corrosion resistance of SS 316.

8. EPA say in the proposed rule, “Not to worry” the Petroleum Industry will 

develop the need materials. This is the same industry EPA disparages. EPA in 

the proposed rule requires the completion materials to be corrosion restraint. I 

wish it was that easy.

9. Completion tubulars are held in place by Portland cement. 

10. Portland cement is highly susceptible to Carbonic Acid attack.

11. EPA says, based on a Halliburton ad, safe cement is available.

12. Halliburton says they have tested corrosion resistant cement in the 

laboratory, under accelerated conditions for 12 months using weight loss as the 

criteria of satisfaction. When asked if weight loss is a satisfactory criterion the 

laboratory cement chemist said “We don’t know.” EPA is relying on premature 

data.

13. Sequestration of CO2 is forever. A 12 month test against a questionable 

criterion appears unsafe.

14. Any existing wells penetrating the injection zone is subject to failure.

15. EPA has approved Sequestration wells as Class I and/or Class II wells, even 

though adequate materials are not available.

C: WITHOUT TECHNICAL SUPPORT, EPA REQUIREs 50 YEARS OF 

MONITORING EXECPT BY SAYING MORE MONITORING IS EXPENSIVE.

1. Sequestration of CO2 is forever, or we don’t need capture the CO2 in the 

first place. If the CO2 escapes the Earth the World population is doomed, in 

accordance with the IPPC theory. 

2. EPA provides no justification for selecting 50 years, in fact the proposed 

rule states the economic contractor was told to develop the cost on the basis 

of 25 years.

3. It is unclear if the cost is based on 25 or 50 years.
D. EPA RULE DOES NOT IMPOSE ANY TECHNICAL QULIFICATIONS ON THE 

EPA PERMIT REVIEWER.

1. CO2 is injected in a supercritical phase, e.g., 2200± psia.

2. CO2 is buoyant and becomes a gas as the pressure decreases. 

3. CO2 sequestration looks like a money making scheme, so speculators will be 

attracted. 

4. EPA likens CO2 sequestration wells (Class VI wells) to Class II Enhanced 

oil/gas well, water injector wells and Class I hazardous waste disposal wells.

4. Class II well injected liquids are not corrosive. Special care is exercised to 

make injected water O2 free to avoid corrosion. 

5. Class I injected fluids are blended to avoid corrosion. 

6. Class II Enhanced oil recovery CO2 injection wells reservoirs are produced 

until abandonment, which lower the pressure to about the original pressure, 

Unlike Class II wells, sequestration well will be abandoned at the maximum 

injection pressure.

7. CO2 sequestration will attract many speculators, because of fast money during 

injection, but the speculators will fade away during the monitoring phase.

8. Speculators will write a good proposal without the technical expertise to 

conduct the drilling, completion and injection safely. Unqualified/untrained EPA 

reviewers will have difficulty recognizing a sound proposal from an unsatisfactory 

proposal. So unsafe projects will be approved.

9. Speculators will go out of business in 50 years, assuming they remain in 

business after the money making inject is completed.

10. EPA makes no provision in the rules for qualified EPA personnel to correct 

problem left by the speculators.

11. EPA says the Regional Administrators have the authority to make technical 

decisions.

12. Regional Administrators typically are not technically trained

13. I requested under a FOI letter, the number of Permit writer/reviewers who 

were graduate engineers. EPA refuse to respond by saying such information 

was protected by the privacy laws.
14. At a minimum the proposed rule needs to require the EPA permit 

writer/reviewer be a Professional Engineer who stamps ever permit 

demonstrating the competency of the well project design and the Regional 

Administrator must be a graduate engineer..

15. EPA require a P.E. stamp SPCC Plans, a Plan of no real consequence, but, 

now, allows an EPA employee, who has not demonstrated competency to 

review and approve a massive vessel operating at 2200 psia.

E. EPA PROVIDES IN THE PROPOSED RULE NO MEANS OF ASSURING 

CORRECTIVE ACCTION WILL BE TAKEN BY THE SEQUESTRATION PROJECT 

OWNER.

1 EPA discusses in the proposed rule the difficulty of corrective action in the 

event of a project problem, but does not come to a resolution.

2. There is no assurance major oil and gas companies will operate the Class VI 

wells, since experienced engineers are needed to produce oil and gas for the 

nation.

2. EPA discusses using the Interstate Oil and Gas Compact Commission 

(IOGCC) idea of charging each Class VI well operator a per ton injection fee to 

be use in the case of an emergency, but what fee should be charged? EPA had 

no answer.

3. In Canada 4.6 percent of the sequestration wells leak. The chance of an CO2 

leak appears real.

4. If a leak occurs under a home and the residents are asphyxiated, and the 

project owner has gone bankrupt, who is responsible?

5. EPA suggest they are in contact with a Federal Agency regarding funding for 

emergencies, but reading the references provided by EPA, the reader finds no 

reference to sequestration well funding. The reference is to transportation, 

perhaps transportation of CO2 by pipeline, but even that is not clear.

Based on my reading, the proposed EPA rule is not ready for promulgation. The 

proposal should be withdrawn. 

Regards
G. H, Holliday, PhD, P.E., BCEE 

P.O. Box 2508 

Bellaire, TX 77402 
Figure 1. 2008 Estimated United States CO2 

Emissions for 2008 
Letter ID: 0127 

Commenter: George Holliday, PhD, PE, BCEE 

Organization: Holliday Environmental Services, Inc. 

Letter ID: 0127 Comment ID: 23052 Letter Lines: 20 to 33 

Comment Code: 1280 1.1.2.1 General comments on climate change/ global warming 

Comment: A: CO2 SEQUESTRATION IS NOT NECESSARY TO STOP GLOBAL 

WARMING 

1. DOE compared the 2008 estimated CO2 emissions from anthropogenic sources with 

naturally occurring emissions, Fig 1. Based on the graph data, it is difficult 

to believe sequestering the anthropogenic releases will change anything. 2. The 

only accurate means of measuring the changing Global Temperature is via 

satellite. Since 2001 the satellite measurements show a decrease of 0.1°C per 

year, while the CO2 continues to increase.. 

3. The IPPC computer simulation of climate change predicts an "Atmospheric 

Hotspot" layer about 10 Km above the earth’s surface as CO2 increases. Try as we 

have, the weather balloons have never recorded such a raise in temperature. This 

casts doubt on the validity of the IPPC Model and the need for CO2 

sequestration. 

Individual Response: EPA notes that mitigating and modeling climate change is outside the 

scope of the Class VI GS rulemaking. EPA clarifies that the purpose of the Class VI GS rule 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. 

Letter ID: 0127 Comment ID: 23053 Letter Lines: 35 to 59 

Comment Code: 3862 2.3.3.1 Use of corrosion-resistant construction materials (seeking 

comment) 

Comment: B: EPA STATES THE NECESSARY MATERIALS FOR THE COMPLETION OF 

SEQUESTRATION 

INJECTION WELLS ARE NOT CURRENTLY AVAILABLE. 

1. CO2 when mixed with water forms carbonic acid. 

2. Well casing, valves, packer slips and connectors are typically manufactured 

from carbon steel. 

3. Carbon steel is highly corrosive when in contact with carbonic acid. 

1
4. Stainless steel 404 is attacked by carbonic acid. 

5. EPA suggests using stainless steel 316 for well heads on the basis on one 

Enhanced Oil Recovery injection well. 

6. Cameron reports manufacturing only one SS 316 wellhead and Cameron does not 

know the fate of the one 316 wellhead. 

7. My personal contact with the project consulting engineer for the well used by 

EPA resulted in no response regarding the corrosion resistance of SS 316. 

8. EPA say in the proposed rule, “Not to worry” the Petroleum Industry will 

develop the need materials. This is the same industry EPA disparages. EPA in the 

proposed rule requires the completion materials to be corrosion restraint. I 

wish it was that easy. 

Individual Response: EPA disagrees that corrosion-resistant materials and cement do not exist 

and the research literature describes several types of cements that have been used under corrosive 

conditions. 

EPA clarifies that Grade 316 stainless steel is not a specified material. It is discussed in the 

preamble to the proposed rule as an example of materials that have been used successfully in 

similar situations. The determination of the best material to use is left for the Director to approve 

based upon case-specific information as provided under §146.86(b)(1). 

EPA is developing guidance on the construction of Class VI wells. This guidance will be 

available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0127 Comment ID: 23054 Letter Lines: 61 to 74 

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: 9. Completion tubulars are held in place by Portland cement. 

10. Portland cement is highly susceptible to Carbonic Acid attack. 

11. EPA says, based on a Halliburton ad, safe cement is available. 

12. Halliburton says they have tested corrosion resistant cement in the 

laboratory, under accelerated conditions for 12 months using weight loss as the 

criteria of satisfaction. When asked if weight loss is a satisfactory criterion 

the laboratory cement chemist said “We don’t know.” EPA is relying on premature 

data. 

2
13. Sequestration of CO2 is forever. A 12 month test against a questionable 

criterion appears unsafe. 

Individual Response: EPA disagrees that corrosion-resistant materials and cement do not exist. 

Industry experience of many decades in corrosive down-hole situations such as acid gas injection 

and production of natural gas with carbon dioxide and hydrogen sulfide impurities shows that 

materials are available that can resist corrosive environments. Meyer (2007) lists several types of 

cements that have been used under such corrosive conditions. EPA acknowledges that studies 

have likely not been performed to prove a 50-year life span for corrosion-resistant materials. 

However, there are two studies of wells that were exposed to CO2 for approximately 30 years by 

Carey et al. (2007) and Crow et al. (2008). Although these studies are limited in the number of 

well material samples and the number of wells examined, the casing and cement sampled 

indicate fairly good condition (i.e., fairly significant corrosion resistance) of well materials 

installed three decades ago. The best available corrosion-resistant materials suited for each GS 

project will be determined by the Director. 

EPA acknowledges that there is limited data on this subject, and believes that providing multiple 

barriers of protection is the most appropriate approach to protecting USDWs from 

endangerment. The Agency plans to, every six years, collect and review project data on early GS 

projects as well as industry innovations on cementing including the development of CO2-

resistant epoxy cements to determine whether the appropriate amount and types of information 

and appropriate documentation are being collected, and to determine if modifications to the 

requirements are appropriate or necessary. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0127 Comment ID: 23055 Letter Lines: 76 to 79 

Comment Code: 3860 2.3.3 Well component degradation 

Comment: 14. Any existing wells penetrating the injection zone is subject to failure. 

15. EPA has approved Sequestration wells as Class I and/or Class II wells, even 

though adequate materials are not available. 

Individual Response: EPA acknowledges that any injection well can potentially fail. It is for 

this reason that the GS rule contains multiple, tailored requirements for the siting, operation, 

MIT, monitoring, reporting, plugging, and post-injection site care and site closure of Class VI 

wells to protect USDWs from endangerment. 

EPA believes that adequate materials that are appropriate for CO2 injection for GS exist. EPA 

believes that the requirement at §146.86(b)(1) that materials must meet or exceed standards 

developed by the American Petroleum Institute, ASTM International, or comparable standards 

3
acceptable to the Director invokes the expertise of these bodies without the added burden of a 

certification program. EPA is developing guidance on the construction of Class VI wells. This 

guidance will be available on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA clarifies that all wells 

used for CO2 injection for the purpose of GS must meet requirements in the final GS rule. 

Letter ID: 0127 Comment ID: 23056 Letter Lines: 81 to 92 

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

Comment Code: 6210 3.2.1 Comments on the timeframe of the costing analysis (seeking 

comment) 

Comment: C: WITHOUT TECHNICAL SUPPORT, EPA REQUIREs 50 YEARS OF 

MONITORING EXECPT BY 

SAYING MORE MONITORING IS EXPENSIVE. 

1. Sequestration of CO2 is forever, or we don’t need capture the CO2 in the 

first place. If the CO2 escapes the Earth the World population is doomed, in 

accordance with the IPPC theory. 

2. EPA provides no justification for selecting 50 years, in fact the proposed 

rule states the economic contractor was told to develop the cost on the basis of 

25 years. 

3. It is unclear if the cost is based on 25 or 50 years. 

Individual Response: EPA disagrees that the monitoring timeframe was selected based on cost. 

In determining the post-injection site care-timeframe for the proposed regulation, EPA reviewed 

industry reports, existing environmental programs, and initial GS research studies. EPA provided 

a synthesis of pertinent results from GS modeling studies in the preamble to the proposed 

regulation. Further explanation of this analysis was included in an EPA-prepared background 

document that is available in the federal docket for the GS rule, titled "Computational Modeling 

of Underground Injection of Carbon Dioxide for Determination of Area-of-Review and Potential 

Risk to Underground Sources of Drinking Water." Based on review of these studies, modeling 

results indicate that the CO2 plume stabilization may occur on the timeframe of 10-100 years 

after the cessation of injection. EPA believes that a 50-year default post-injection site care 

timeframe is a reasonable midpoint for most GS projects and available data, including data 

submitted by commenters, do not support a different default timeframe, and has retained this in 

the final regulation. 

However, EPA recognizes that there may be sites where the 50 year post injection site care 

timeframe may be either not appropriate or more burdensome than necessary based on sitespecific conditions. 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 

4
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 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 

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. 

Letter ID: 0127 Comment ID: 23057 Letter Lines: 94 to 147 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: D. EPA RULE DOES NOT IMPOSE ANY TECHNICAL QULIFICATIONS ON 

THE EPA PERMIT 

REVIEWER. 

1. CO2 is injected in a supercritical phase, e.g., 2200± psia. 

2. CO2 is buoyant and becomes a gas as the pressure decreases. 

3. CO2 sequestration looks like a money making scheme, so speculators will be 

attracted. 

4. EPA likens CO2 sequestration wells (Class VI wells) to Class II Enhanced 

oil/gas well, water injector wells and Class I hazardous waste disposal wells. 

4. Class II well injected liquids are not corrosive. Special care is exercised 

to make injected water O2 free to avoid corrosion. 

5. Class I injected fluids are blended to avoid corrosion. 

6. Class II Enhanced oil recovery CO2 injection wells reservoirs are produced 

until abandonment, which lower the pressure to about the original pressure, 

Unlike Class II wells, sequestration well will be abandoned at the maximum 

injection pressure. 

7. CO2 sequestration will attract many speculators, because of fast money during 

injection, but the speculators will fade away during the monitoring phase. 

8. Speculators will write a good proposal without the technical expertise to 

5
conduct the drilling, completion and injection safely. Unqualified/untrained EPA 

reviewers will have difficulty recognizing a sound proposal from an 

unsatisfactory proposal. So unsafe projects will be approved. 

9. Speculators will go out of business in 50 years, assuming they remain in 

business after the money making inject is completed. 

10. EPA makes no provision in the rules for qualified EPA personnel to correct 

problem left by the speculators. 

11. EPA says the Regional Administrators have the authority to make technical 

decisions. 

12. Regional Administrators typically are not technically trained 

13. I requested under a FOI letter, the number of Permit writer/reviewers who 

were graduate engineers. EPA refuse to respond by saying such information was 

protected by the privacy laws. 

14. At a minimum the proposed rule needs to require the EPA permit 

writer/reviewer be a Professional Engineer who stamps ever permit demonstrating 

the competency of the well project design and the Regional Administrator must be 

a graduate engineer.. 

15. EPA require a P.E. stamp SPCC Plans, a Plan of no real consequence, but, 

now, allows an EPA employee, who has not demonstrated competency to review and 

approve a massive vessel operating at 2200 psia. 

Individual Response: EPA disagrees that the people designing and regulating wells lack 

technical training for effective oversight of Class VI wells. Most permitting authority staff have 

years of experience with the current UIC injection well classes and have relevant specialties in 

geology, engineering, and related disciplines. Injection well owners and operators represent 

industries with decades of experience injecting a variety of fluids, including CO2. Regarding 

UIC requirements for staff qualifications, EPA clarifies that only the Class I hazardous waste 

injection well regulations at §§144.14(c)(9) and 144.63 (i) require that a professional engineer 

certify closure of the well. 

Letter ID: 0127 Comment ID: 23058 Letter Lines: 149 to 172 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

Comment: E. EPA PROVIDES IN THE PROPOSED RULE NO MEANS OF ASSURING 

CORRECTIVE ACCTION 

WILL BE TAKEN BY THE SEQUESTRATION PROJECT OWNER. 

1 EPA discusses in the proposed rule the difficulty of corrective action in the 

6
event of a project problem, but does not come to a resolution. 

2. There is no assurance major oil and gas companies will operate the Class VI 

wells, since experienced engineers are needed to produce oil and gas for the 

nation. 

2. EPA discusses using the Interstate Oil and Gas Compact Commission (IOGCC) 

idea of charging each Class VI well operator a per ton injection fee to be use 

in the case of an emergency, but what fee should be charged? EPA had no answer. 

3. In Canada 4.6 percent of the sequestration wells leak. The chance of an CO2 

leak appears real. 

4. If a leak occurs under a home and the residents are asphyxiated, and the 

project owner has gone bankrupt, who is responsible? 

5. EPA suggest they are in contact with a Federal Agency regarding funding for 

emergencies, but reading the references provided by EPA, the reader finds no 

reference to sequestration well funding. The reference is to transportation, 

perhaps transportation of CO2 by pipeline, but even that is not clear. 

Individual Response: EPA expects the emergency and remedial response requirements at 

§146.94 will encourage owners or operators to plan (during the permitting phase of a GS project) 

for any actions that would be necessary in the unlikely event of a GS project-related emergency 

and ensure that operators know what entities and individuals must be notified and what actions 

must be taken to expeditiously mitigate any emergency situations. 

EPA clarifies that, if the owner or operator obtains evidence that USDWs may be endangered or 

that leakage is occurring, he or she must cease injection, take all steps reasonably necessary to 

identify and characterize any release, notify the Director, and implement the approved 

emergency and remedial response plan (§146.94(b)). Failure to respond to any evidence of 

USDW endangerment would be considered a violation of the UIC permit and would be subject 

to applicable civil, criminal, or administrative penalties. 

In response to the comment about funding for emergency actions or damage if the owner or 

operator were to go bankrupt, EPA clarifies that §146.85 requires owners or operators to 

demonstrate and maintain financial responsibility for performing any necessary remedial actions 

associated with the requirements at §146.94, including the actions outlined in their GS projectspecific emergency and remedial response plan. 

Letter ID: 0127 Comment ID: 23059 Letter Lines: 174 to 175 

Comment Code: 1450 1.2.2.1 Oppose the GS rulemaking 

Comment: Based on my reading, the proposed EPA rule is not ready for promulgation. The 

7
proposal should be withdrawn. 

Individual Response: EPA believes that the creation of a new injection well class (VI) under the 

existing UIC Program is necessary to enable the use of GS as a climate change mitigation 

technology in a manner that protects USDWs from endangerment. EPA believes 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. EPA adds that the final 

GS rule includes a variety of changes from the proposed rule that enhance and clarify the 

requirements and address public comments on the proposed rule. 

Letter ID: 0127 Comment ID: 23966 Letter Lines: 112 to 115 

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: 6. Class II Enhanced oil recovery CO2 injection wells reservoirs are produced 

until abandonment, which lower the pressure to about the original pressure, 

Unlike Class II wells, sequestration well will be abandoned at the maximum 

injection pressure. 

Individual Response: EPA agrees that the nature and risks associated with CO2 injection for 

long term storage are different from Class II CO2 injection for ER, and that tailored requirements 

for GS wells are appropriate and necessary to protect USDWs from endangerment. For this 

reason, the Agency tailored UIC requirements for Class VI wells that address the general risks 

deep injection may pose to USDWs and specifically address the unique nature of CO2 GS (i.e., 

very large volumes, very long time-periods, and reservoir pressure conditions). 

EPA adds that, while at the time that injection operations cease, pressures will be high (or at 

maximum), owners or operators of Class VI wells will be required to perform extensive postinjection site care and monitoring until pressures decline to the point that USDWs are not 

endangered as required under §146.93. See the discussion of post-injection site care in the 

preamble to the final rule for additional information. 

8