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.
Comments on Proposed Class VI UIC Rules 

Docket ID No. EPA-HQ-OW-2008-0390 

Prepared by: 

Philip W. Papadeas, PG 

Sandia Technologies, LLC 

6731 Theall Road 

Houston, TX 77066 

Tel: 832 286-0471 

Phil.Papadeas@sandiatech.com

General Comments 

Sandia Technologies, LLC provides the following comments to U.S. EPA regarding the 

proposed Class VI UIC regulations, which in our judgment offer an excellent basis for 

regulating Geologic Sequestration projects and their anticipated large injectate volumes. 

The foundation of these rules has been derived from EPA’s highly successful Class I, 

Class II and Class V programs, which have a proven record of protecting groundwater 

and the near surface environment while managing large volumes of industrial aqueous 

waste. There are considerable areas in the rules which are vague in meaning and intent 

within portions of the proposed regulations. 

A sub-category of wells may be considered for pure long-term disposal, without having 

to consider recovery of the injectate, and later purification, etc. The direct line from stack 

gas to geologic reservoir should be considered as the total injectate, and if adequate well 

and surface materials are present then there should be no problem to dispose of the 

scrubber effluent, or gases direct into suitable geologic formations. 

For long term disposal, or storage, well tubular requirements should be robust and 

manage potential impurities in the injection stream, with no limitations so long as proper 

injection pressures and well materials are sufficiently followed during operations. 

Well Conversion 

An operator can potentially use a Class I permit to inject CO2, H2S, and NO2 and utilize 

an established program which is considered more stringent and successful to not 

endanger USDWs or the public. 

For Class I well operators who might want to convert an abandoned injection well to a 

Class VI well, should have an easier path to such due to the more stringent permit and 

diligence performed to obtain regulatory approval and permits. Historical operations 

have not endangered USDWs, therefore there is a direct connection to a ‘grandfather’ 

approach. 

For grandfathering of Class II wells to Class VI designation, in my judgment Class II 

wells are not constructed very stringently since they are typically converted oil and gas 

Sandia Technologies, LLC 1 December 24, 2008 
wells which have outlived their useful lives in hydrocarbon production. Cement bond in 

the annulus and isolation is typically not as good as Class I wells where continuous 

cement bond must be present allowing for 

Geologic Characterization 

EPA should allow an applicant to drill a site stratigraphic test well, convertible later to a 

Class VI injection well. All information should be provided, and utilized for modeling 

the reservoir, with conservative model inputs and predictions for determining future 

operations. 

§146.82 

Re: Collection of detailed geologic data. 

The collection of this data is the operator’s burden, and should be built on accumulation 

of all known geologic material in the area. Sandia believes this information is valuable 

for modeling, site characterization and geologic profile of the injection-confinement 

system. If none is present, then the operator must demonstrate via stratigraphic test or an 

information well all pertinent formation cores, not only of proposed permeable injection 

intervals, but overlying buffer intervals, confining zone cores, and formations that will 

act as hydraulic seals. 

One proposed approach is for the Agency to make the first Permitted injection well 

conditional, collecting the required data and providing this to the EPA under an adjusted 

permit to demonstrate that the data matches conservative assumptions used in reservoir 

and geologic modeling. The follow-up wells should collect in-fill well data on 

geomechanics and confirm data obtained from the first well. Reduced data collection 

should be employed for all subsequent wells on the site, since adequate will exit from 

these early wells for the storage operator and EPA to make a detailed assessment of the 

capability of the site. 

This idea is similar to many approaches on ‘greenfield’ sites followed via Class I well 

Permitting by EPA. A secondary approach is for the operator to include this data 

acquisition into their project costs for stratigraphic test data, cores, logs, pressures, 

reservoir testing to demonstrate the suitability of the injection and confining horizons. 

The burden 

§146.82 (d) (2) 

Re: Faults transmissive or sealing? 

Whether faults are transmissive or sealing in the injection interval, or zone is immaterial, 

if the reservoir and injection interval can pass modeling scenarios using conservative 

assumptions successfully preventing fluid migration to the USDW, then these operational 

considerations should be used as the key threshold and benchmark for EPA’s geological 

evaluation. Class I operators are required to model both scenarios if data is not known or 

exists and this similar approach should be followed. 

§146.82 (h) (i, j) 

Sandia Technologies, LLC 2 December 24, 2008 
Re: Compatibility testing should be performed from cores and either native or 

synthesized formation fluid and injectate to determine and demonstrate potential 

reactivity of the injectate with formations, tubular materials, and other waste or injectate 

mixtures. This is presently performed for all Class I hazardous wastes, and should be 

employed as a one-time initial testing program for new well operations and injection 

constituents, composition and properties. 

§146.83 (a)(2) 

Re: Confining Zone free of transmissive faults 

This remains very difficult to prove or demonstrate in the subsurface unless detailed 

seismic and geologic data exists in the area to define such. One suggested approach may 

involve including a secondary buffer confining zone, as a redundancy to the first 

confining zone. The key may also be if there is connection from the Injection Zone to the 

Confining Zone, then additional modeling or reduction in injection rate/pressure and 

more of a margin of safety built in unless more detailed geological modeling 

demonstrates the lack of transmissive faulting. 

§146.87 (f) 

Re: 30-day testing notification 

The requirements for 30-day notification should remain as such, the nature of drilling, 

workover, and testing is such that notification will not cover all testing. EPA or Agency 

notification of testing requirements, representative can witness the testing or be sent the 

data electronically with a summary for review, evaluation and concurrence. 

§146.88 (a)(e) 

Re: Fracture Pressure 

Fracture pressure determination should be key to EPA’s rules, via geophysical 

measurements, physical rock cores sampling and determination, and openhole logs. 

There are sufficient tools and methods present to evaluate the Confining Zone and 

Injection interval fracture gradients and determine an appropriate operating range with 

safeguards present for operation pressure and injection rate. 

Downhole shut off systems or valves are considered necessary for Class I wells which 

operate with large volumes and in some cases greater pressures. The Agency should not 

specify the type of tubular and well operations system. 

§146.90 (f) 

Re: Pressure Falloff testing of at least once every 5 years. 

This is of concern, since annual pressure tests are required for Class I operators, then why 

is the EPA diluting this requirement. As a consultant, I believe that for the first 5 years of 

established operation on the well, it should be installed as an annual requirement for 

Pressure Falloff testing, and thereafter, the operator can request from the Agency for once 

per 5-years. The behavior of buoyant carbon dioxide suggests more testing and 

monitoring and not less than Class I wells which have more safeguards present during 

operations. 

Sandia Technologies, LLC 3 December 24, 2008 
§146.90 (g) 

Re: Monitoring saline intervals above the Confining Zone. 

This monitoring approach may provide risk to USDWs, if monitor wells are drilled and 

installed, and adds significant burden, cost to the operator and uncertainties to the 

geologic system. One key question is however, what if no permeable intervals are present 

to monitor? Does one monitor saline intervals, or shallow fresh water wells? The UIC 

program has worked well for many years with a stringent continuous cemented wellbore, 

and no migration of fluid as determined from annual testing, and operational pressure 

monitoring of the injection interval. 

Close monitoring of injection pressure, and annual pressure falloff data will supercede a 

dedicated monitor well where pressure anomalies may exist due to pressure or some 

distant fluid injection or withdrawal in the shallow subsurface. In areas of depleted 

reservoirs or drawn down aquifers the pressure effects monitoring may not indicate 

anything significant. 

Calibrated reservoir and flow and containment models can predict the current and future 

pressure front as a result of the injectate. As with Class I modeling, a proper formation 

pressure gradient is required to assess a baseline, which can determine all future storage 

capacity of the reservoir in the subsurface. By bounding the injectate via conservative 

assumptions offers the best chance to define the pressure front, and assess how large the 

potential area of review may be necessary. 

The CO2 plume is likely to be highly variable in saturation and depends on the distance, 

location and depth considerations as well as original salinity and residual hydrocarbon 

saturation. Seismic and or vertical seismic profiling may offer the best approach to 

identifying where the highest saturation is present. Pressure remains the better indicator, 

distance from the wellbore. 

§146.93 (a)(4)(b)(1) 

Re:Monitoring for 50 years 

How is the operator going to monitor for 50 years, when their facility is closed, bankrupt, 

or remains insolvent, while other sites adjacent and in direct influence may remain active 

and operational? This time is not work-able, and should be consistent with EPA’s best 

analog, the 30-year post-closure rule from UIC Class I wells. Monitoring should 

continue only to the point when pressure dissipates to below minimum driving force 

pressures required to move fluid to a USDW. 

50-year monitoring is severe, and has no basis in other EPA operational considerations. 

No site continuity would be present, well operational records lost, and personnel retired 

with expertise dissipated. 

Sandia Technologies, LLC 4 December 24, 2008 
Letter ID: 0238 

Commenter: Philip Papadeas 

Organization: Sandia Technologies, LLC 

Letter ID: 0238 Comment ID: 23343 Letter Lines: 30 to 38 

Comment Code: 1410 1.2.1 Comments in support of EPA/rulemaking 

Comment: Sandia Technologies, LLC provides the following comments to U.S. EPA regarding 

the proposed Class VI UIC regulations, which in our judgment offer an excellent 

basis for regulating Geologic Sequestration projects and their anticipated large 

injectate volumes. The foundation of these rules has been derived from EPA’s 

highly successful Class I, Class II and Class V programs, which have a proven 

record of protecting groundwater and the near surface environment while managing 

large volumes of industrial aqueous waste. There are considerable areas in the 

rules which are vague in meaning and intent within portions of the proposed 

regulations. 

Individual Response: EPA agrees that the UIC Program, under the authority of the SDWA, 

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

regulation tailors the UIC requirements to address the unique issues associated with large-scale 

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

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

subsurface geologic formations. 

Letter ID: 0238 Comment ID: 23344 Letter Lines: 40 to 45 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

Comment: A sub-category of wells may be considered for pure long-term disposal, without 

having to consider recovery of the injectate, and later purification, etc. The 

direct line from stack gas to geologic reservoir should be considered as the 

total injectate, and if adequate well and surface materials are present then 

there should be no problem to dispose of the scrubber effluent, or gases direct 

into suitable geologic formations. 

Individual Response: The GS rule does not set generic purity standards for CO2 injectate 

streams (e.g., a percent CO2). Instead, the GS rule addresses the quality and quantity of 

impurities by requiring owners or operators to submit information on the source of the CO2 and 

its physical and chemical properties. Specifically, the GS rule requires the owner or operator to 

submit data about the site, including an analysis of the chemical and physical characteristics of 

the CO2 stream, as required at §146.82(a)(7)(iv), and information on the compatibility of the 

CO2 stream with fluids in the injection zone and minerals in both the injection and the confining 

zones and the materials used to construct the well, per §146.82(c)(3). This information can help 

the Director determine the potential for geochemical reactions between the injectate (CO2) and 

1
the host geologic formations, which could result in the plugging of pore spaces or the dissolution 

of formation minerals. 

EPA clarifies that the GS rule applies only to wells injecting CO2 for the purpose of long-term 

storage. 

Letter ID: 0238 Comment ID: 23345 Letter Lines: 47 to 50 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: For long term disposal, or storage, well tubular requirements should be robust 

and manage potential impurities in the injection stream, with no limitations so 

long as proper injection pressures and well materials are sufficiently followed 

during operations. 

Individual Response: EPA agrees that tubular materials in Class VI wells must be suitable for 

handling the CO2 stream. The final GS rule at §146.86(c)(1), requires that tubing materials used 

in Class VI wells meet or exceed standards developed by the American Petroleum Institute, 

ASTM International, or comparable standards acceptable to the Director. This requirement 

invokes the expertise of these bodies without the added burden of a certification program. The 

GS rule, at §146.86(c)(3)(ii), also requires the Director to consider the characteristics of the CO2 

stream (i.e., chemical content, corrosiveness, temperature, and density) and formation fluids in 

approving the construction of a Class VI well. 

Letter ID: 0238 Comment ID: 23346 Letter Lines: 52 to 62 

Comment Code: 2062 1.5.3.1 Grandfathering construction of Class I wells (seeking comment) 

Comment: Well Conversion 

An operator can potentially use a Class I permit to inject CO2, H2S, and NO2 and 

utilize an established program which is considered more stringent and successful 

to not endanger USDWs or the public. 

For Class I well operators who might want to convert an abandoned injection well 

to a Class VI well, should have an easier path to such due to the more stringent 

permit and diligence performed to obtain regulatory approval and permits. 

Historical operations have not endangered USDWs, therefore there is a direct 

connection to a ‘grandfather’ approach. 

Individual Response: EPA agrees that many Class I wells are designed and constructed to 

withstand exposure to CO2. The final GS rule provides for the construction of these wells to be 

grandfathered per §146.81(c), provided the owner or operator can demonstrate to the Director 

that the wells were engineered and constructed to meet the requirements at §146.86(a) and 

2
ensure protection of USDWs, in lieu of requirements at §146.86(b) and §146.87(a). However, 

EPA clarifies that only the construction requirements are grandfathered and that all other Class 

VI requirements (reporting, monitoring, mechnical integrity testing, etc.) must be met following 

a determination under §146.81(c). 

Letter ID: 0238 Comment ID: 23347 Letter Lines: 64 to 69 

Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment: For grandfathering of Class II wells to Class VI designation, in my judgment 

Class II wells are not constructed very stringently since they are typically 

converted oil and gas wells which have outlived their useful lives in 

hydrocarbon production. Cement bond in the annulus and isolation is typically 

not as good as Class I wells where continuous cement bond must be present 

allowing for 

Individual Response: EPA agrees that a cautious approach to grandfathering is appropriate, 

particularly given that the converted well will be used for a substantially different process, which 

involves increased reservoir pressures associated with large volumes of stored CO2 and the 

corrosivity of CO2 in the presence of water. The final GS rule provides for the construction of 

these wells to be grandfathered (per 146.81(c)). 

The final GS rule provides that the construction of these wells be grandfathered per §146.81(c), 

provided the owner or operator can demonstrate to the Director that the wells were engineered 

and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu 

of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction 

requirements are grandfathered and that all other Class VI requirements (reporting, monitoring, 

mechnical integrity testing, etc.) must be met following a determination under §146.81(c). 

Letter ID: 0238 Comment ID: 23348 Letter Lines: 71 to 76 

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

Comment: Geologic Characterization 

EPA should allow an applicant to drill a site stratigraphic test well, 

convertible later to a Class VI injection well. All information should be 

provided, and utilized for modeling the reservoir, with conservative model 

inputs and predictions for determining future operations. 

Individual Response: EPA anticipates that test wells will be drilled to support geologic site 

characterization of the proposed GS sites and can be used to collect subsurface samples, e.g. for 

laboratory determination of capillary pressure, and take other necessary measurements. 

EPA believes that the requirements for geologic site characterization (at §146.82), AoR 

3
evaluation (§146.84), and testing of the well during drilling (§146.87) are appropriate to ensure 

that permitting authorities have the necessary information to evaluate whether a specific site will 

allow safe injection of CO2. 

Letter ID: 0238 Comment ID: 23349 Letter Lines: 78 to 103 

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment: §146.82 

Re: Collection of detailed geologic data. 

The collection of this data is the operator’s burden, and should be built on 

accumulation of all known geologic material in the area. Sandia believes this 

information is valuable for modeling, site characterization and geologic profile 

of the injection- confinement system. If none is present, then the operator 

must demonstrate via stratigraphic test or an information well all pertinent 

formation cores, not only of proposed permeable injection intervals, but 

overlying buffer intervals, confining zone cores, and formations that will act 

as hydraulic seals. 

One proposed approach is for the Agency to make the first Permitted injection 

well conditional, collecting the required data and providing this to the EPA 

under an adjusted permit to demonstrate that the data matches conservative 

assumptions used in reservoir and geologic modeling. The follow-up wells should 

collect in-fill well data on geomechanics and confirm data obtained from the 

first well. Reduced data collection should be employed for all subsequent wells 

on the site, since adequate will exit from these early wells for the storage 

operator and EPA to make a detailed assessment of the capability of the site. 

This idea is similar to many approaches on ‘greenfield’ sites followed via Class 

I well Permitting by EPA. A secondary approach is for the operator to include 

this data acquisition into their project costs for stratigraphic test data, 

cores, logs, pressures, reservoir testing to demonstrate the suitability of the 

injection and confining horizons. The burden 

Individual Response: EPA agrees and believes that the extensive requirements for geologic site 

characterization (at §146.82), AoR evaluation (§146.84), and testing of the well during drilling 

(§146.87) are appropriate to ensure that permitting authorities have the necessary information to 

evaluate whether a specific site will allow safe injection of CO2. EPA adds that submittal and 

review of monitoring data (as required at §146.90) and the AoR reevaluation process 

(§146.84(e)) will provide an opportunity for an ongoing review of the site and a dialogue 

between the Director and the owner or operator to ensure that the project is being operated in a 

manner that protects USDWs from endangerment. 

4
EPA acknowledges that early pilot projects may focus on gathering data to inform GS 

technology. However, EPA believes that a detailed geological site characterization of every GS 

site (as required under §146.82) is essential to evaluating the presence and adequacy of the 

various geologic features necessary to receive and confine injected CO2 for GS. The 

requirements for geologic site characterization are based on a long standing UIC regulatory 

framework developed to address specific risks to USDWs posed by injection. The Class VI GS 

requirements are tailored so that they are appropriate for the unique nature of injecting large 

volumes of CO2 into a variety of geological formations for long-term storage. EPA adds that, if 

data on a formation or site collected in connection with an earlier project can support a geologic 

characterization, the Director has discretion to accept this data, provided it is sufficient to 

demonstrate site suitability. 

Letter ID: 0238 Comment ID: 23350 Letter Lines: 105 to 114 

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

Comment: §146.82 (d) (2) 

Re: Faults transmissive or sealing? 

Whether faults are transmissive or sealing in the injection interval, or zone is 

immaterial, if the reservoir and injection interval can pass modeling scenarios 

using conservative assumptions successfully preventing fluid migration to the 

USDW, then these operational considerations should be used as the key threshold 

and benchmark for EPA’s geological evaluation. Class I operators are required to 

model both scenarios if data is not known or exists and this similar approach 

should be followed. 

Individual Response: The Agency believes that the requirement at §146.83(a)(2) that the 

confining zone to be free of transmissive faults or fractures is appropriate for Class VI wells and 

is necessary to ensure containment of the injectate and that requiring the confining zone to be 

free of transmissive faults maximizes protection of USDWs from endangerment. EPA clarifies 

that geological data collected during site characterization, including information on faults, will 

be used as inputs for AoR modeling. Modeling results, in concert with other site characterization 

information, will be used to determine if a site is appropriate for GS and will ensure protection of 

USDWs from endangerment. 

Letter ID: 0238 Comment ID: 23351 Letter Lines: 116 to 122 

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

Comment Code: 3860 2.3.3 Well component degradation 

Comment: §146.82 (h) (i, j) 

Re: Compatibility testing should be performed from cores and either native or 

synthesized formation fluid and injectate to determine and demonstrate potential 

5
reactivity of the injectate with formations, tubular materials, and other waste 

or injectate mixtures. This is presently performed for all Class I hazardous 

wastes, and should be employed as a one-time initial testing program for new 

well operations and injection constituents, composition and properties. 

Individual Response: EPA has revised subpart §146.82 so that the final regulation specifies 

separate requirements for information to be submitted with the permit application and before 

well construction is approved (at §146.82(a)) and information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

Letter ID: 0238 Comment ID: 23352 Letter Lines: 124 to 133 

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: §146.83 (a)(2) 

Re: Confining Zone free of transmissive faults 

This remains very difficult to prove or demonstrate in the subsurface unless 

detailed seismic and geologic data exists in the area to define such. One 

suggested approach may involve including a secondary buffer confining zone, as a 

redundancy to the first confining zone. The key may also be if there is 

connection from the Injection Zone to the Confining Zone, then additional 

modeling or reduction in injection rate/pressure and more of a margin of safety 

built in unless more detailed geological modeling demonstrates the lack of 

transmissive faulting. 

Individual Response: EPA acknowledges that some smaller fractures may not be detectable 

during the site characterization process. Other requirements for GS injection wells and sites can 

mitigate the potential impacts of unidentified fractures. These include limitations on injection 

pressures to avoid propagation of existing fractures in the confining zone (§146.88(a)), collection 

and assessments of CO2 monitoring data at the site, and AoR reevaluations (§146.84(e)) to 

assess possible CO2 movement through high-permeability regions (i.e., faults and/or fractures) 

not detected in the initial site characterization. 

Letter ID: 0238 Comment ID: 23353 Letter Lines: 135 to 141 

Comment Code: 3866 2.3.3.3 Logging and testing requirements (40 CFR 146.87) 

Comment: §146.87 (f) 

Re: 30-day testing notification 

The requirements for 30-day notification should remain as such, the nature of 

drilling, workover, and testing is such that notification will not cover all 

testing. EPA or Agency notification of testing requirements, representative can 

witness the testing or be sent the data electronically with a summary for 

review, evaluation and concurrence. 

6
Individual Response: EPA acknowledges the comment; the final rule retains this provision. 

Letter ID: 0238 Comment ID: 23354 Letter Lines: 143 to 149 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: §146.88 (a)(e) 

Re: Fracture Pressure 

Fracture pressure determination should be key to EPA’s rules, via geophysical 

measurements, physical rock cores sampling and determination, and openhole logs. 

There are sufficient tools and methods present to evaluate the Confining Zone 

and Injection interval fracture gradients and determine an appropriate operating 

range with safeguards present for operation pressure and injection rate. 

Individual Response: EPA agrees it is important to accurately determine fracture pressure in 

setting permit limits for Class VI wells. The injection pressure limit for each GS project will be 

based on site-specific conditions and will be informed by data on the injection zone. During 

injection, the pressure in the injection zone must not exceed 90 percent of the fracture pressure of 

the injection zone, as specified at §146.88(a). The fracture pressure (and, therefore, the injection 

pressure) are based on site-specific geologic and geomechanical data collected during the site 

characterization process required at §146.82. Tests are available and have been used by injection 

well operators, e.g., Class I operators, to measure fracture pressure. Examples include the steprate test, in-situ stress tests, and a combination of a long spaced sonic log with laboratory 

measurement of the mechanical properties of cores. To meet the GS requirements, the permitting 

authority must set the injection pressure limit at no more than 90 percent of this value. 

The Director will also review geologic, hydrogeologic, and geomechanical information 

submitted by the owner or operator in setting permit conditions. If, based on this information, a 

lower pressure limitation is appropriate, the Director has the authority to set a lower limit in the 

operating permit. EPA clarifies that fracturing of the confining zone during injection and/or 

stimulation is also prohibited at §146.88(a). 

EPA is developing guidance on site characterization for GS projects to assist owners or operators 

in meeting the requirements of §146.82 and to assist directors in evaluating permit applications. 

The guidance will describe recommended approaches for characterizing the regional geology and 

hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA is also developing guidance for 

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. The guidance will be available on EPA's web site, at 

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

Letter ID: 0238 Comment ID: 23355 Letter Lines: 151 to 153 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

7
Comment: Downhole shut off systems or valves are considered necessary for Class I wells 

which operate with large volumes and in some cases greater pressures. The 

Agency should not specify the type of tubular and well operations system. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. However, the Agency believes that offshore Class VI wells present unique 

construction and operational conditions, including isolation from shorelines and the need to 

construct wells through the water column and the subsurface, which may delay response time in 

the event of well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of 

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA 

believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent 

subsurface fluid movement and ensure protection of USDWs. 

Letter ID: 0238 Comment ID: 23356 Letter Lines: 155 to 163 

Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment) 

Comment: §146.90 (f) 

Re: Pressure Falloff testing of at least once every 5 years. 

This is of concern, since annual pressure tests are required for Class I 

operators, then why is the EPA diluting this requirement. As a consultant, I 

believe that for the first 5 years of established operation on the well, it 

should be installed as an annual requirement for Pressure Falloff testing, and 

thereafter, the operator can request from the Agency for once per 5-years. The 

behavior of buoyant carbon dioxide suggests more testing and monitoring and not 

less than Class I wells which have more safeguards present during operations. 

Individual Response: EPA believes that a frequency of at least once every five years, as 

specified at §146.90(f), is an appropriate interval for pressure fall-off testing (particularly given 

the suite of tests operators will perform on the well and the site). EPA clarifies that the Director 

may require more frequent pressure fall-off tests at a specific project, if necessary based on sitespecific circumstances. Pressure fall-off tests may be conducted in conjunction with other well 

performance tests (i.e., mechanical integrity testing) to ensure safe and effective operations. All 

monitoring data collected, including information from pressure fall-off tests, will be incorporated 

in AoR reevaluations, at least every five years. 

Letter ID: 0238 Comment ID: 23357 Letter Lines: 165 to 194 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

8
Comment: §146.90 (g) 

Re: Monitoring saline intervals above the Confining Zone. 

This monitoring approach may provide risk to USDWs, if monitor wells are drilled 

and installed, and adds significant burden, cost to the operator and 

uncertainties to the geologic system. One key question is however, what if no 

permeable intervals are present to monitor? Does one monitor saline intervals, 

or shallow fresh water wells? The UIC program has worked well for many years 

with a stringent continuous cemented wellbore, and no migration of fluid as 

determined from annual testing, and operational pressure monitoring of the 

injection interval. 

Close monitoring of injection pressure, and annual pressure falloff data will 

supercede a dedicated monitor well where pressure anomalies may exist due to 

pressure or some distant fluid injection or withdrawal in the shallow 

subsurface. In areas of depleted reservoirs or drawn down aquifers the pressure 

effects monitoring may not indicate anything significant. 

Calibrated reservoir and flow and containment models can predict the current and 

future pressure front as a result of the injectate. As with Class I modeling, a 

proper formation pressure gradient is required to assess a baseline, which can 

determine all future storage capacity of the reservoir in the subsurface. By 

bounding the injectate via conservative assumptions offers the best chance to 

define the pressure front, and assess how large the potential area of review may 

be necessary. 

The CO2 plume is likely to be highly variable in saturation and depends on the 

distance, location and depth considerations as well as original salinity and 

residual hydrocarbon saturation. Seismic and or vertical seismic profiling may 

offer the best approach to identifying where the highest saturation is present. 

Pressure remains the better indicator, distance from the wellbore. 

Individual Response: EPA agrees that good site selection, modeling, and management are 

crucial elements of a successful GS project, but disagrees that this is an effective substitute for 

rigorous site monitoring. EPA disagrees that pressure fall-off tests are an appropriate substitute 

for monitoring pressure changes in the injection zone. Pressure fall-off tests provide information 

in the vicinity of the injection well(s) and measure pressure conditions within the injection zone. 

Direct monitoring of pressure changes in the injection zone can provide advance warning of 

movement of CO2 or brine that might ultimately endanger a USDW. 

The Agency recognizes that while there are similarities between injection of wastes for disposal 

(Class I) and GS (Class VI), there are significant differences as well. Important unique 

considerations for GS include the buoyancy of CO2, its corrosivity when in contact with water, 

its low viscosity (i.e., high mobility), and the very large injection volumes that are anticipated. 

There is also a degree of uncertainty regarding the behavior of large volumes of CO2 in the 

subsurface after injection. Given these characteristics of anticipated GS projects, EPA believes 

9
that plume and pressure front monitoring at §146.90(g) are justified to provide early warning of 

any unforeseen fluid movement that might endanger USDWs. 

The final rule (at §146.90(g)) requires owners or operators to perform monitoring to track the 

extent of the CO2 plume and pressure front. The owner or operator must use direct methods to 

monitor for pressure changes in the injection zone. Indirect methods (e.g., seismic, electrical, 

gravity, or electromagnetic surveys and/or down-hole CO2 detection tools) are also required 

unless the Director determines, based on site-specific geology, that such methods are not 

appropriate. 

EPA believes that pressure monitoring is necessary and for this reason, all GS well owners or 

operators must monitor pressure in the injection zone using direct methods (§146.90(g)(1)) to 

track the development and movement of the pressure front and CO2 plume. Monitoring can also 

identify needed remedial actions, provide inputs for AoR reevaluation modeling, evaluate 

predictions of plume movement, and target additional geochemical and surface monitoring 

needs. 

Letter ID: 0238 Comment ID: 23358 Letter Lines: 196 to 202 

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

Comment: §146.93 (a)(4)(b)(1) 

Re:Monitoring for 50 years 

How is the operator going to monitor for 50 years, when their facility is 

closed, bankrupt, or remains insolvent, while other sites adjacent and in direct 

influence may remain active and operational? This time is not work-able, and 

should be consistent with EPA’s best analog, the 30-year post-closure rule from 

UIC Class I wells. Monitoring should continue only to the point when pressure 

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

excessive. EPA proposed a default post-injection site care timeframe of 50 years based on a 

review of research studies, industry reports, and existing environmental programs. This analysis 

was included in an EPA-prepared background document that is available in the federal docket, 

titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determination 

of Area-of-Review and Potential Risk to Underground Sources of Drinking Water." EPA 

assessed various default timeframes based on additional review of research studies and 

evaluation of public comments. While numerous commenters suggested that EPA shorten the 

monitoring timeframe, none of the commenters provided sufficient data or other evidence to 

warrant a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by 

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

circumstances (e.g., little development of mineral trapping of CO2) under which the potential 

risks of endangering USDWs will likely not decline within these timeframes. EPA believes that a 

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

period and available data do not support a different timeframe. Furthermore, EPA believes that a 

50-year default post-injection site care timeframe, as required at §146.93(b)(1), is not overly 

burdensome, does not exaggerate the risks associated with GS, is consistent with other 

10
environmental programs, and sufficiently protects USDWs from endangerment. 

EPA acknowledges the concerns of some commenters that there will be circumstances where it 

can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk 

of endangerment to USDWs. For this reason, the final GS regulation includes a provision that the 

Director may, at his/her discretion, shorten the post-injection site care timeframe if the owner or 

operator can demonstrate that the GS project does not pose a risk to USDWs, as specified in 

§146.93(b)(2). Such a demonstration will be site-specific, and based on pressure monitoring and 

USDW impacts. 

To the comment expressing concern about financial responsibility, EPA recognizes that there are 

challenges associated with assuring funding for activities that will occur far in the future. 

However, the Agency believes that in order to protect USDWs from endangerment under the 

SDWA operators must demonstrate under §146.85 that financial resources are available to plug 

the injection well and provide post-injection site care at the point in time that the first CO2 is 

injected.. EPA is developing guidance on financial responsibility to assist owners or operators in 

evaluating the requirements of §146.85 and to assist Directors in evaluating financial 

responsibility demonstrations. The guidance describes the types of financial mechanisms that 

operators may choose to use when evaluating the financial responsibility requirements for GS 

wells and it will also include a section on how to estimate costs to support accurate financial 

responsibility demonstrations. http://www.epa.gov/safewater/uic/wells_sequestration.htm. 

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. 

Letter ID: 0238 Comment ID: 23359 Letter Lines: 202 to 204 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: UIC Class I wells. Monitoring should continue only to the point when pressure 

dissipates to below minimum driving force pressures required to move fluid to a 

USDW. 

Individual Response: EPA agrees that determinations about when post-injection site monitoring 

may be discontinued will be based on pressure observations. However, EPA clarifies that the 

non-endangerment demonstration should address more than changes in pressure; for example, 

fluid movement within the subsurface must also be considered. EPA expects that the Director 

would consider the types of information the commenter describes in determining whether the 

plume and pressure front no longer pose a risk of endangerment to USDWs and post-injection 

site care monitoring may be discontinued. 

Under the combined fixed timeframe and performance standard approach for Class VI wells, the 

post-injection site care timeframe may be reduced by the Director if the owner or operator can 

demonstrate that the remaining pressure front and plume no longer pose a risk of endangerment 

11
to USDWs. The non-endangerment finding is left to the discretion of the Director, based on sitespecific information such as plume movement, pressure decay, and the location of potential 

leakage pathways. 

EPA adds that the final GS rule at §146.93(c), also allows the Director to approve an alternative 

post-injection site care timeframe where an owner or operator can demonstrate during the 

permitting process that an alternative post-injection site care timeframe, other than the 50 year 

default, is appropriate and ensures non-endangerment of USDWs. 

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

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

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; perform 

post-injection monitoring; demonstrate the appropriateness of an alternative post-injection site 

care time frame; demonstrate non endangerment; and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0238 Comment ID: 23360 Letter Lines: 206 to 208 

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

Comment: 50-year monitoring is severe, and has no basis in other EPA operational 

considerations. No site continuity would be present, well operational records 

lost, and personnel retired with expertise dissipated. 

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

excessive and clarifies that the record supports EPA’s final approach. EPA proposed a default 

post-injection site care timeframe of 50 years based on a review of research studies, industry 

reports, and existing environmental programs. This analysis was included in an EPA-prepared 

background document that is available in the federal docket, titled "Computational Modeling of 

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

Risk to Underground Sources of Drinking Water." EPA assessed various default timeframes 

based on additional review of research studies and evaluation of public comments. While 

numerous commenters suggested that EPA shorten the monitoring timeframe, none of the 

commenters provided sufficient data or other evidence to warrant a change in the proposed 

timeframe. While the 10- or 30-year timeframe suggested by some of these commenters may be 

within the timeframe suggested in some studies, there are circumstances (e.g., little development 

of mineral trapping of CO2) under which the potential risks of endangering USDWs will likely 

not decline within these timeframes. EPA believes that a 50 year post-injection site care 

timeframe represents a reasonable and protective monitoring period and available data do not 

support a different timeframe. Furthermore, EPA believes that a 50-year default post-injection 

site care timeframe, as required at §146.93(b)(1), is not overly burdensome, does not exaggerate 

the risks associated with GS, is consistent with other environmental programs, and sufficiently 

protects USDWs from endangerment. 

12
13

EPA acknowledges that there will be circumstances where it can be demonstrated in less than 50 

years that the plume and pressure front no longer pose a risk of endangerment to USDWs. For 

this reason, the final GS regulation includes a provision that the Director may, at his/her 

discretion, shorten the post-injection site care timeframe if the owner or operator can 

demonstrate that the GS project does not pose a risk to USDWs, as specified in §146.93(b)(2). 

Such a demonstration will be site-specific, and based on pressure monitoring and USDW 

impacts. 

EPA disagrees that a 50 year post-injection site care period would contribute to lack of site 

continuity or loss of operational records or staff expertise. EPA understands that changes in staff 

or ownership occur associated with all injection operations that operate over timeframes of 

several years or decades, and believes that owners and operators granted UIC permits have a 

responsibility to maintain continuity in expertise and data associated with the project.