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Planned GS Projects and EPA’s Role

Research and development (R&D) on GS over the next several years will involve two phases of 

projects. CO2 GS wells constructed and operated as part of either phase may qualify as Class V 

“experimental technology” wells provided they meet the definition of that term found at 40 Code 

of Federal Regulations (CFR) 146.3 (“a technology which has not been proven feasible under the 

conditions in which it is being tested”). While injection of fluids, including CO2 into the 

subsurface, e.g., for enhanced oil recovery (EOR) and enhanced gas recovery (EGR), is a longstanding practice, injection of CO2 for GS is an experimental application of this existing 

technology. 

The first phase – the “validation” phase – is slated to begin in the next year or two and will 

provide in situ tests of GS technology by injecting low volumes of CO2. The validation phase 

projects include 25 field tests where CO2 will be injected and its fate and transport will be 

monitored. Attachment 2 lists the Regional Partnerships, who have GS projects supported by the 

U.S. Department of Energy (DOE). To get up-to-date information on the progress being made 

by the DOE Regional Partnerships, please visit the web sites referenced in the attachment. 

Deployment phase projects (the second phase) would follow, beginning around 2009. Drawing 

on the knowledge gained in the validation phase, these projects will involve higher volumes of 

CO2. Full, commercial-scale deployment of GS technology is expected to commence around 

2012, following the collection of sufficient data to inform a scientifically-sound management 

framework. 

EPA anticipates that pilot projects will have a variety of objectives, including testing the 

effectiveness of various well materials and injection practices, assessing the usefulness of 

geophysical survey and monitoring techniques, testing failure scenarios, and/or validating 

models of the fate and transport of CO2 in the subsurface. As they review permit applications, 

UIC Directors should keep in mind that a primary goal of the pilot projects is to collect data to 

support a scientifically-based framework for managing GS projects. Because the results of pilot 

experimental projects would benefit all future CO2 injection operations, EPA strongly 

encourages gathering and sharing of data through the permitting process for pilot projects. 

Several topics merit further evaluation through research and demonstration projects. These 

include the following topics: 

 Potential impacts of CO2 injection on ground water and USDWs; 

 Potential impacts of CO2 injection on human health and the environment; 

 Integrity of CO2 injection wells and other wells in the area of review; 

 Fluid displacement and pressure impacts; 

 Remediation technologies; 

 Land surface deformation; 

 Potential for large-scale CO2 releases; 

 Measurement, monitoring, and verification tools applicable to GS of CO2; 

 Potential impacts of CO2 injection on geologic media (reservoir and seals); and 

 Geochemical and geomechanical effects. 
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Research and demonstration projects focused on the above topics will provide useful information 

for developing a framework for commercial-scale CO2 injection projects. To further this research 

goal, Directors should exercise reasonable and appropriate flexibility in evaluating permit 

applications and writing permit conditions that will allow well owners or operators3 to achieve 

their project objectives. 

While flexibility is important, the Safe Drinking Water Act (SDWA) focuses on the protection of 

USDWs and public health, and no project should be designed or operated in a way that 

endangers USDWs or the health of persons. If the project goal is to test failure scenarios, it is 

important that the project incorporate appropriate protections to safeguard USDWs and public 

health (e.g., proper casing and tubing materials, sufficient logging to ensure well integrity, and 

adequate monitoring to detect movement of CO2). Well owners or operators should specify the 

objectives of the project and identify the data to be gathered; they should also demonstrate that 

the project meets the non-endangerment standard under the UIC Program (i.e., protection of 

USDWs). 

An important goal of the pilot projects is to gather, evaluate, and share data on appropriate 

technologies and approaches for CO2 injection to ultimately support national goals for addressing 

climate change. 

Here are some important features of the CO2 pilot phase: 

$ Transitional nature of the pilot phase - Over the next several years, EPA 

anticipates pilot CO2 injection projects will be put into operation across the United 

States. This guidance and the Class V experimental technology well permits will 

bridge the gap between pilot and commercial-scale projects. EPA plans to evaluate 

options for permitting commercial-scale projects in the near future. Through this 

guidance, EPA encourages a case-by-case approach to permitting pilot projects to 

facilitate gathering the data needed to support decisions about future requirements for 

commercial-scale operations. On the basis of the data collected, the Agency may 

consider developing regulations tailored specifically for CO2 injection. Development 

of such regulations would be a transparent and open process, and broad public and 

industry participation would be encouraged. 

$ Scale of the pilot projects - Initially, we expect the project permit applications to 

request authorization to inject very small volumes of CO2 relative to commercialscale projects. The relatively small volumes of CO2 injected in these initial pilot 

projects should minimize any potential for adverse effects on USDWs and public 

health due to the movement or leakage of CO2. As relevant siting, construction, and 

operational data from these smaller pilot projects is gathered and analyzed, EPA 

anticipates that Regional and State Directors will receive applications for larger 

 

3

 “Owner or operator” means the owner or operator of any facility or activity subject to regulation under the UIC 

Program. [40 CFR 144.3] 
 

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operations, with the goal of furthering our understanding of how to mitigate any risks 

posed by commercial-scale operations. 

$ Generation of data - Permitting requirements for commercial-scale CO2 injection 

projects will need to be based on sound science. The goal of the pilot projects is to 

generate data that will enhance our understanding of the fate and movement of, and 

risks associated with, injected CO2. The knowledge and data gained from these pilot 

projects will allow the development of an effective approach to manage injection of 

CO2, if needed, at the commercial scale. 

$ Communication - EPA encourages well owners or operators to share with the 

Director data collected throughout the siting, construction, and operation of the 

injection wells; operators may request protection of any confidential information that 

is submitted. In turn, Regional Direct Implementation Program Directors are 

expected to, and State Directors are encouraged to, share permit applications and 

other information related to permit issuance with EPA Headquarters. 

Because of the complexities involved in successfully and safely achieving the goals of a pilot 

project, States and Regions may want to pool their resources and form multidisciplinary teams to 

process the pilot applications and collect/analyze the data. These teams could consist of: 

o Geologists 

o Reservoir Engineers 

o Geophysicists 

o Geochemists 

o Hydrologists 

o Statisticians 

o Remote Sensing Scientists 

o Modellers 

o Atmospheric Scientists 

o Biologists/Ecologists 

Potential Impacts/Risk Associated with Geologic Sequestration 

There may be risks to human health and safety from CCS technology implementation. Direct 

exposure to elevated levels of CO2 can cause both chronic and acute health effects depending on 

the concentration and duration of exposure. Additionally, injected CO2 and any impurities it 

may contain have the potential to endanger USDWs or adversely affect human health. 

Therefore, the injectate for pilot projects should be characterized prior to permit issuance. 

Furthermore, displacement of native fluids and chemical constituents, movement of possibly 

hazardous impurities in injected fluids, and potential leaching and mobilization of naturally 

occurring metals and minerals in the injection and confining formations associated with CO2

injection may potentially endanger USDWs, if not properly managed. It is up to the Director to 

determine, on a case-by-case basis, whether endangerment of USDWs could occur as a result of 

the proposed injection. Authorities should make these determinations based on their knowledge 

of the specific geology in their States. In addition, we encourage permitting authorities to seek 
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UIC Program expertise, and request additional data on CO2 injection from the owners or 

operators where appropriate and available. 

Geologic Sequestration Authority Under the Safe Drinking Water Act

The UIC Program under the SDWA regulates injection of fluids, including solids, semi-solids, 

liquids, and gases (e.g., CO2) to protect USDWs. The UIC regulations address the siting, 

construction, operation, and closure of wells that inject a wide variety of fluids, including those 

that are considered commodities or wastes. The natural gas exemption under the UIC 

regulations is not applicable to GS because, while CO2 is a naturally occurring gas, the exclusion 

applies only to “natural gas as it is commonly defined” (e.g., gaseous hydrocarbons), and “not to 

other injections of matter in a gaseous state” (See House of Representatives Report 96-1348, 

reprinted in 1980 U.S. Code Congressional and Administrative News 6080). 

The UIC Program defines five classes of underground injection wells; at least three of these are 

potential classifications for CO2 injection: 

$ Class I wells are deep, technically sophisticated wells that dispose of waste below the 

lowermost USDW. The UIC regulations define three subcategories of Class I wells 

based on the fluids they inject, including wells used by generators of hazardous waste 

or hazardous waste management facilities, other industrial and municipal disposal 

wells, and radioactive waste disposal wells. Owners or operators of Class I hazardous 

waste disposal wells typically model the behavior of wastes in the subsurface to 

demonstrate long-term storage (i.e., 10,000 years). The large volumes of treated 

wastewater injected via Class I municipal disposal wells may provide some insight 

into the potential challenges presented by the large-scale injection of CO2. 

$ Class II wells are used by the oil and gas industry for a variety of waste fluid disposal, 

enhanced recovery, and hydrocarbon storage needs. CO2 is currently being injected 

for enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Class II 

programs’ decades of experience with injecting CO2 and knowledge of oil and gas 

reservoirs are useful to those working on GS efforts. 

$ Class V experimental technology wells are intended to demonstrate unproven but 

promising technologies. EPA’s rationale for allowing the use of Class V 

experimental technology wells is to encourage innovation. In other words, under 

EPA’s regulations an injection well that is being used to demonstrate a developing 

technology may be subject to more flexible, yet fully protective, technical standards 

than those designed for commercially operating facilities. The designation as a Class 

V experimental technology well is generally considered only while the technology is 

experimental in nature. [See Attachment 1: Appropriate Classification and 

Regulatory Treatment of Experimental Technologies (Ground Water Program 

Guidance No. 28); May 31, 1983 for additional information.] 

EPA has determined that the Class V experimental technology well subclass provides the best 

mechanism for authorizing pilot GS projects. This guidance has been developed to assist UIC 
 

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Program Directors in permitting CO2 injection wells as Class V experimental technology wells. 

Depending on the specific circumstances, for purposes of the pilot projects addressed in this 

guidance, permitting CO2 injection into deep saline formations, depleted hydrocarbon reservoirs, 

or basalt formations through Class V experimental technology wells may be appropriate. In 

addition, depending on the particular facts, CO2 injection wells of pilot GS projects that involve 

methane-depleted coalbeds, depleting natural CO2 formations, and non-commercial gas fields 

(due to low BTU or productivity) may be appropriate for permitting as Class V experimental 

technology wells. 

CO2 injection for EOR or EGR operations is a long-established technology, and these wells may 

continue to be permitted as Class II wells, and Class II permitting requirements would apply. 

However, if the injection of CO2 through those wells is not associated with the enhanced 

recovery of oil or gas, these operations would then be considered for re-permitting as Class V 

experimental technology wells. In other words, although CO2 injection for EOR and EGR is a 

proven technology, CO2 injection for long-term storage is still experimental and under 

development at this time. While there are similarities between CO2 injection for the purposes of 

oil and gas extraction and for GS, there are important differences as well. For example, CO2

injection for GS will eventually involve much greater volumes of CO2, which will be stored for 

very long periods of time. Owners or operators should be made aware that Class II EOR and 

EGR projects that transition to GS (either as pilot-phase Class V experimental projects or longterm commercial scale operations) may be subject to siting, well construction, or monitoring 

standards that could be different from those specified for a Class II well. 

Additionally, wells with dual completions (e.g., where CO2 is injected into one reservoir to 

produce oil and into another for GS) could be subject to permitting requirements under both 

Class II and Class V. Coordination will be essential where more than one permitting authority is 

involved (e.g., in States where Class II and Class V wells are overseen by different agencies); 

memoranda of agreement (MOAs) or memoranda of understanding (MOUs) between the 

authorities may be needed. Proactive communication about dual permitting requirements to 

owners or operators is important. 

Purpose of this Guidance

This guidance applies to GS projects that are to be permitted as Class V experimental technology 

wells (based on available information from the pilot projects planned by DOE’s Regional 

Partnerships and other GS projects developed for the purpose of increasing understanding of 

issues related to CO2 injection). It provides suggested guidelines for permitting and operating 

near-term pilot GS projects prior to commercial-scale implementation of GS. This guidance is 

intended to address only pilot GS projects (i.e., the limited number of experimental projects 

anticipated to be brought online in advance of commercial-scale operations over the next several 

years). Owners or operators should be made aware of this, so that they may submit permit 

applications in a timely manner that allows them to meet pilot project goals. 

Class V experimental technology permitting may be appropriate, as an interim measure, for CO2 

GS injection wells of a “pilot” or “demonstration” nature, regardless of the volumes injected. 

EPA’s regulations at 40 CFR 146.3 state that, “experimental technology means a technology 
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which has not been proven feasible under the conditions in which it is being tested.” Such wells, 

which are anticipated to come on-line in the near term, will be drilled and operated to test various 

technologies and assumptions related to the safe and effective GS of CO2. At some point in the 

future, EPA expects that the technology surrounding CO2 injection for GS purposes will no 

longer be considered “experimental.” By that time, EPA would expect to have made a decision 

on a management strategy to address CO2 injection for commercial scale GS. Until then, EPA 

recommends that States or Regions review applications to construct and operate appropriately 

designed and operated “pilot” and “demonstration” CO2 GS wells to determine whether they 

may be permitted as Class V experimental technology wells. 

Proper operation of injection wells for GS projects is required under the SDWA to safeguard 

USDWs and protect public health. In addition, comprehensive oversight of CO2 injection will 

build public confidence in an emerging technology that may ultimately be deployed at a large 

scale across the United States. Furthermore, a consistent oversight framework will allow 

Directors to permit pilot GS projects in an efficient and consistent manner, thus reducing 

unknowns and possible confusion among the pilot-project owners or operators, regulating 

entities, and the general public. EPA has begun evaluating and formulating a process for making 

decisions about commercial-scale GS projects and such a process may include specific 

regulatory options and technical requirements. 

This guidance assumes that adequate permitting procedures and enforcement authority are in 

place at the State and EPA Regional levels. Although there are no Federal requirements written 

specifically for Class V experimental technology wells, there are applicable requirements for 

Class V wells generally (see 40 CFR 144.12, 144.24 to 144.27, and 40 CFR 144.79 - .89). 

Among other things, Class V well owners or operators, including owners or operators of Class V 

experimental technology wells, must submit information to the Director regarding the nature of 

their injection operations (40 CFR 144.26). This Guidance identifies additional information that 

the Director may decide to request. UIC Program Directors are encouraged to request additional 

information, as needed for writing adequate permits, (40 CFR 144.27) and to require that the 

owner or operator obtain a permit (40 CFR 144.12 (c)). Federal UIC permitting requirements at 

40 CFR Parts 144 and 146 should be thoroughly considered and implemented. Permit issuers 

should follow the requirements for public participation (40 CFR Part 124), which are an 

important part of promoting public confidence in CO2 injection and an open decision-making 

process. 

Guidance for Setting Permit Requirements

Injection wells used for GS pilot projects may be permitted as Class V experimental technology 

wells if all applicable SDWA and UIC permitting requirements are met. For those pilot GS 

projects that inject CO2 into depleting oil and gas reservoirs to enhance the recovery of oil or 

natural gas, permitting as Class II EOR and EGR wells may be appropriate, as long as oil and gas 

are being recovered (40 CFR 144.6(b)(2)). 

Any Class V experimental permit issued to a pilot project should remain in effect for as long as 

necessary to cover the estimated timetable of the goals of the project. On an as-needed basis, 
 

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Class V GS pilot project permits can be modified to extend the timetables or alter the goals of an 

evolving project, as long as State or Federal limits on permit duration are not exceeded. 

The sections below present factors that Directors may wish to consider as they evaluate permit 

applications. Because the pilot projects will have a variety of experimental endpoints, the factors 

presented are not an exhaustive list, and may not necessarily be relevant to all projects. 

Considerations for the Appropriateness of Injection Sites 

The appropriateness of injection sites selected for pilot CO2 injection will depend on the goals of 

the project. Possible experimental goals may include testing the effectiveness of various 

geologic formations in receiving or trapping CO2 (e.g., short-term and long-term relations 

between trapping mechanisms, structural and stratigraphic considerations, and formation impacts 

such as solubility and mineralization); failure scenario testing; or testing or validating the 

accuracy of models in certain geologic conditions. In general, to prevent endangerment of 

USDWs, an adequate receiving and confining system for a CO2 injection site should consist of: 

$ A receiving zone of sufficient depth,4 areal extent, thickness, porosity, and 

permeability; 

$ A trapping mechanism that is free of major non-sealing faults; 

$ A confining system of sufficient regional thickness and competency; and 

$ A secondary containment system which could include buffer aquifers and/or thick, 

impermeable confining rock layers. 

A site that is deemed to be appropriate for pilot CO2 injection may not necessarily meet future 

requirements for commercial-scale operations. Therefore, owners or operators intending to 

eventually expand their pilot projects to commercial-scale operations should understand that 

additional UIC requirements may apply to the project after conversion to commercial operation. 

Below are factors that EPA recommends Directors consider when assessing the appropriateness 

of proposed pilot CO2 injection sites: 

$ Some leakage of CO2 from the injection zone may occur, and in fact may be the 

experimental goal of certain research projects that are designed to test monitoring 

methods. However, in no case should leakage endanger USDWs or the health of 

persons. 

$ Potential reactions between injected CO2 and the rocks and fluids in the injection 

zone may impact injectivity. Permeability may be reduced (by chemical precipitates 

blocking pore throats or coal swelling) or increased (if matrix minerals dissolve). 

 

4

 To be stored above supercritical pressure, CO2 should be injected at least 800 meters (2,625 feet) below the land 

surface. 
 Page 9

Other types of reactions include gas release due to injectate-fluid reactions and 

selective adsorption and desorption reactions of the minerals in a reservoir. 

$ Pressures needed for injection of supercritical CO2 (i.e., 1,070 psi/ 73.8 bars) may 

impact receiving and confining formations, e.g., they may exceed the fracture 

pressure of some formations. 

$ Thermal effects (e.g., thermal shock) can affect receiving formations and cement. 

$ Vertically transmissive geologic features (e.g., faults or fractures), which may 

facilitate the upward movement of CO2, should be delineated. High-resolution 

surface and borehole geophysics may be useful for these delineations. 

$ If analytical or numerical models of CO2 containment or transport are run, testing and 

validation of such models are necessary. (This model testing will provide valuable 

information on the selection of proper time frames for the modeling of commercialscale projects. The modeled time frames may vary to reflect the project goals and 

objectives). 

$ The presence of underground voids and conduits, whether natural (e.g., karst) or 

artificial (e.g., mines and solution mining operations) may impact the appropriateness 

of a proposed injection site. 

Considerations for the Area of Review

Studies to determine the area of review (AoR) and test modeling/monitoring of CO2 movement 

can provide valuable data to guide commercial-scale efforts. Maps and data for the AoR study 

should incorporate accurate and reliable data to inform commercial-scale projects regarding 

movement of CO2 and potential pathways for CO2 in AoRs. While a fixed radius approach to 

determining the AoR may be appropriate for smaller pilot projects, it may not be appropriate for 

commercial-scale operations. Furthermore, given that the aim of pilot operations is to inform 

future decision-making, projects that test AoR study methods or identify which properties of CO2

injection impact the size of the AoR are encouraged. The items below present aspects of the 

AoR that are relevant to CO2 injection: 

$ It may be appropriate to base the size of the AoR on a zone of endangering pressure 

influence. CO2 pressure buildup predictions may require adaptations of the pressure 

buildup equations used for aqueous fluid injection, along with considerations of some 

of the following: 

3⁄4 Reservoir transmissibility 

3⁄4 Injection rate 

3⁄4 Duration of CO2 injection 

3⁄4 Total injection volume 

3⁄4 Boundary conditions (e.g., pinchout or sealing fault) 

3⁄4 Pressure-volume-temperature (PVT) behavior 

3⁄4 Injection depth 
 

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3⁄4 Relative permeability effects of CO2 injection into a brine-filled reservoir. 

• The maximum pressure buildup predicted at abandoned well locations may affect 

corrective action procedures. 

• Given the buoyancy of CO2, shallow wells in the buoyant plume area may also act as 

conduits for the upward migration of CO2. (All wells and natural conduits within the 

AoR, regardless of depth, are potential conduits for CO2 release). The volume of 

CO2 injected, formation dip, and reservoir mobility can also impact the buoyant 

plume movement. Any data gathering or modeling that can help determine the upper 

limit and lateral extent of CO2 plume movement in various geologic conditions 

should be encouraged. 

• Certain geologic reservoirs that are potentially advantageous for CO2 injection for 

geologic sequestration, such as depleted oil and gas reservoirs, are likely to be 

penetrated by active and abandoned wells. The Director may not have complete 

information on the location and condition of all abandoned wells. This has 

implications for successful CO2 GS at a particular site. 

3⁄4 The corrosive nature of CO2 may have implications for selecting appropriate 

corrective action procedures. For example, cement with proven additives may be 

preferred 

3⁄4 Older abandoned wells are likely to be constructed of traditional well materials 

and plugged with mud and cement, and may be susceptible to CO2 contamination 

or corrosion 

3⁄4 It may be useful to retain some “typical cement plugs” in a limited number of 

abandoned wells to collect data on cement performance 

Considerations for Injection Well Construction

EPA expects that the objective of certain pilot projects may be to test the interactions between 

various well materials or cements and CO2, and, therefore, wells for these projects should be 

constructed in accordance with the project goals. Construction materials, casing, and cement 

should be appropriate to the geologic environment, the properties of CO2, and the anticipated life 

of the project. Owners or operators should describe the project goals, the planned construction 

procedures, and how USDWs will be protected from endangerment in their applications. 

It is important that owners or operators be made aware that, if they intend to eventually convert a 

well used in a pilot project to a commercial-scale operation, the permit requirements for the 

commercial-scale project may be more stringent than those for the pilot project. This may 

impact decisions by owners or operators about construction materials or drilling methods. 

Additional monitoring may be warranted if there are concerns or uncertainties about the pilot 

project, or where failure scenarios are being tested. Regional Directors are expected to, and State 

Directors should, encourage owners and operators to submit any data gathered or lessons learned 

about the effectiveness of certain materials or processes that can be of use in the development of 
 Page 11

standards and requirements for commercial-scale projects. Some of the considerations for well 

construction include: 

$ Requirements for surface and long-string casing, packer, tubing, cement, and other 

construction materials should take into account the properties of CO2 and the 

subsurface formations. Where existing wells are being used, the Director should 

evaluate the adequacy of the existing well materials and cement. It is the owner or 

operator’s responsibility to demonstrate that the existing well materials and cement 

are adequate. 

$ Directors may find owners and operators using new, non-traditional technologies 

(e.g., coil tubing, fiberglass liners, expandable casing, potassium cements, cathodic 

protection, laser drilling, and horizontal and slant injections) for the construction of 

CO2 injection wells. It is the responsibility of the owner or operator to demonstrate 

how these technologies can ensure the protection of USDWs and public health from 

CO2 injection activities. 

$ Non-traditional stimulation methods may be used for CO2 injection projects. 

Depending on the project goals, some fracturing during stimulation may provide 

useful information. The Director should include appropriate permit conditions to 

ensure that fracturing of the confining zone does not endanger USDWs. It is 

important to note that fracturing may render the site unusable for long-term CO2

storage, however. The owner or operator should describe the proposed stimulation 

program, and notify the Director when stimulation will be performed. Detailed 

geophysical and well logs should be maintained, and the Director should be informed 

of the results and be able to access and view any data collected.

Considerations for Injection Well Operation and Monitoring Program 

Appropriate operating procedures for pilot projects may depend on the project goals. Owners or 

operators should demonstrate how the planned operating procedures meet the project goals and 

how USDWs will be protected. Monitoring parameters (e.g., injection pressure, volume, and 

rate) in the permit that help gather the data needed to understand the behavior and potential 

leakage of CO2 and impacts of CO2 injection on well materials and receiving formations are 

encouraged. Owners or operators should also be encouraged to share any data gathered or 

lessons learned during well operation with the Director. Appropriate emergency procedures 

(e.g., automatic shut-offs and contingency plans) should be incorporated into the operating 

permits. 

The following are considerations relevant to developing operating and monitoring plans for CO2

injection wells: 

$ CO2 reacts with water to form carbonic acid, which is corrosive. Impurities in the 

CO2 stream may also be a concern due to their potential impact on well materials or 

potential contamination of USDWs. Data on the occurrence of various chemical 

compounds in ground water can help identify these effects. 
 

 Page 12

$ Operating parameters for CO2 injection include: 

3⁄4 Maintaining records of: 

 Average and maximum injection rates and pressures 

 Daily and cumulative total injection volumes 

3⁄4 The nature of the annulus fluid (e.g., its compatibility with CO2) 

3⁄4 The purity of injected CO2 and the presence of any other pollutants (e.g., nitrogen 

oxides, sulfur oxides, and mercury) 

3⁄4 The temperature of the injected CO2 (for evaluation of thermal effects on well 

materials and integrity) 

3⁄4 Limitations on injection pressure based on the fracture pressure, if fracturing is 

prohibited for the pilot project (Due to the reduced static fluid pressures expected 

from CO2 injection, compensation for pump-induced injection pressures at the 

surface will be needed) 

$ Monitoring of pressure buildup and movement of fluids, both within and outside of 

the injection zone, is useful for understanding the movement and impacts of the CO2

plume. 

$ If failure scenarios are being tested, appropriate protective contingencies are 

encouraged, such as additional monitoring, or the use of food-grade CO2 (i.e., without 

impurities), because the behavior of co-constituents and their impacts are not well 

known. 

$ It may be the goal of certain pilot projects to monitor the movement of CO2 out of the 

injection zone to understand the fate and transport of supercritical CO2, or to compare 

actual movement to modeled predictions. The performance of sensitivity analyses to 

determine which operating parameters have the greatest effects on injectivity, 

containment, and storage capacity might be useful for future commercial-scale project 

designs and operations. 

$ The properties of CO2 that differ from liquid injectate may affect mechanical integrity 

testing requirements and frequencies. Innovative alternatives (subject to approval by 

the Director), and expanded/custom logging suites that may be appropriate for various 

well types, geologic conditions, etc., are encouraged. For example: 

3⁄4 Noise logs can detect gas flow, and other wireline logs, such as neutron-density 

logs and thermal decay time logs, may be useful in evaluating movement of CO2

out of the injection zone 

3⁄4 Temperature logs may detect temperature changes associated with degassing. 

3⁄4 Oxygen Activation (OA) logs or other geophysical logging tools may be used to 

assess the movement of fluids behind the pipe due to poor cement bonding or 

cement deterioration and channeling effects 

3⁄4 Cement evaluation logging, casing inspection logs, and coupon testing for 

corrosion can be used to evaluate well material integrity 
 Page 13

$ Monitoring plans that include collection of baseline ground water quality data will 

facilitate post-injection evaluations of the impacts of the injected CO2 and other 

constituents. 

Considerations for Site Closure

As with other injection operations, CO2 injection projects must be closed and abandoned in a 

manner that is protective of USDWs (40 CFR 144.12). If projects are designed to test failure 

scenarios, CO2 volumes must be low enough and protective measures must be put in place so 

that no endangerment of USDWs will result (40 CFR 144.12). In addition, most pilot projects are 

assumed to be small enough (low volumes and/or use of food-grade CO2) that remediation would 

not be an issue. However, this should be confirmed by the Director. 

For pilot projects, traditional financial assurance requirements for proper abandonment would 

generally apply. However, commercial-scale operations, including those that are converted from 

pilot projects, may have additional financial assurance requirements to ensure that issues arising 

from the larger CO2 plumes, the unique nature of CO2, and the long storage time frame are 

addressed. 

Guidance Implementation

This document provides guidance to EPA Regional and State and Tribal Directors exercising 

responsibility under the SDWA concerning underground injection wells used for pilot CO2 GS 

projects. This document also provides information to the public and those responsible for the 

oversight of pilot CO2 injection projects, including Regional Carbon Sequestration Partnerships. 

It is designed to provide a timely and consistent framework to assist Regional and State Directors 

to permit pilot CO2 injection wells. This guidance does not, however, substitute for the SDWA 

or EPA’s UIC regulations; nor is it a regulation itself. Thus, it cannot change or impose legally 

binding requirements on EPA, States, or the regulated community, and may not apply to a 

particular situation based upon the circumstances. The use of non-mandatory words like 

“should,” “could,” “would,” “may,” “might,” “encourage,” “expect,” and “can,” in this guidance 

means solely that something is suggested or recommended, and not that it is legally required, or 

that the suggestion or recommendation imposes legally binding requirements, or that following 

the suggestion or recommendation necessarily creates an expectation of EPA approval. 

Collaboration and communication between Headquarters, Regional UIC Program staff, and 

Primacy States is critical to achieving pilot GS project goals. Regional Directors are expected to, 

and State Directors are encouraged to, share permit applications and other information related to 

permit issuance with EPA Headquarters to assist with the development of a management 

framework for commercial-scale GS projects. The purpose of EPA Headquarters’ involvement 

is to gather relevant and pertinent information for use in making decisions about commercialscale CO2 injection projects. Authority to access State UIC Program data is set forth in the 

Federal UIC regulations at 40 CFR 145.14(a) and can be used by EPA to request information 

from Program Directors. As with any other data gathering and management effort as part of UIC 

Program implementation, appropriate Confidential Business Information procedures must be 

followed (40 CFR 145.14(b)). 
 

 Page 14

Given the regional differences across the United States and to foster national consistency in 

issuing Class V experimental technology well permits for GS pilot projects, DI Program 

Directors are encouraged to submit initial permit applications and proposed permits to 

Headquarters staff. Based on the anticipated number of applications, EPA expects that the 

submission to Headquarters staff of one permit application and proposed permit per EPA Region 

is likely to be sufficient. State Directors are strongly encouraged to enter into formal 

arrangements, such as MOAs, with their Regional Directors to share data related to pilot project 

permit applications and issuances. 

Directors should make reasonable efforts to witness important field events throughout the life of 

the project. Directors should be notified in advance of drilling or completion activities so they 

have the opportunity to witness important events. 

Directors who are responsible for traditional Class V shallow wells are encouraged to consult 

deep well experts (e.g., Class I or Class II well Directors) to ensure that appropriate standards 

and requirements are applied to the pilot CO2 injection wells. EPA Headquarters can assist in 

identifying such experts. 

This guidance supplements the guidance: Appropriate Classification and Regulatory Treatment 

of Experimental Technologies (Ground Water Program Guidance No. 28); May 31, 1983. The 

specific guidance in that document continues to apply. (See Attachment 1) 

Contact Information for this Guidance

For further information, or questions relating to this guidance, please contact Lee Whitehurst, 

EPA Office of Ground Water and Drinking Water, Prevention Branch, at 202-564-3896 or 

Whitehurst.Lee@epa.gov. 

Contact information for UIC Program Directors can be found at: 

http://www.epa.gov/safewater/uic/states.html
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Attachment 1 

Appropriate Classification and Regulatory Treatment of Experimental Technologies (Ground 

Water Program Guidance No. 28); May 31, 1983 
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 Page 22

Attachment 2 

Summary Table of U.S. Department of Energy (DOE) 

Geologic Sequestration Regional Partnerships 
 Page 23

Name and Web site Area Covered Contact Person(s) 

Big Sky Regional Carbon 

Sequestration Partnership 

www.bigskyco2.org/

MT, WY, SD, ID, eastern WA, 

eastern OR

Susan Capalbo, Big Sky Principal Investigator, Office 

of VP for Research, Creativity and Technology. 406-

994-5619, scapalbo@montana.edu 

Pamela Tomski, Big Sky Outreach Director, 202-822-

6120 ext. 11, ptomski@erols.com

Midwest Geological Sequestration 

Consortium-Illinois Basin 

www.sequestration.org/ IL, KY, portions of IN Link to all project staff: 

http://www.sequestration.org/staff.htm

Midwest Regional Carbon 

Sequestration Partnership 

http://198.87.0.58/default.aspx

MD, MI, OH, PA, WV, and 

portions of IN, KY David Ball, balld@battelle.org

Plains CO2 Reduction Partnership 

www.undeerc.org/pcor/default.asp

ND, SD, MN, MT, WY, NE, IA, 

MO, WI, & Canadian provinces 

of Alberta, Manitoba, and 

Saskatchewan 

Link to all project staff: 

http://www.undeerc.org/pcor/contactus.asp

Southeast Regional Carbon 

Sequestration Partnership 

www.secarbon.org/

GA, FL, NC, SC, VA, TN, AL, 

TN, MS, AR, LA, southeast TX call 770.242.7712, or email sseb@sseb.org

Southwest Regional Partnership for 

Carbon Sequestration 

www.southwestcarbonpartnership.org/

NM, OK, KS, CO, UT, portions of 

TX, WY, AZ 

Brian McPherson - brian@nmt.edu 

New Mexico Institute of Mining and Technology, 

505.835.5834 

West Coast Regional Carbon 

Sequestration Partnership 

www.westcarb.org/

AK, CA, NV, British Columbia, 

and portions of AZ, OR, and WA 

Larry Myer, West Coast Regional Carbon 

Sequestration Partnership's technical director, 

Larry.Myer@ucop.edu.