Office of Water (4606M) EPA 816-P-13-004 December 2013

Geologic Sequestration of Carbon 

Dioxide

Draft Underground Injection Control 

(UIC) Program Guidance on 

Transitioning Class II Wells to Class VI 

Wells
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells i

Disclaimer

The Federal Requirements Under the Underground Injection Control Program for Carbon 

Dioxide Geologic Sequestration Wells (75 FR 77230, December 10, 2010), known as the Class 

VI Rule, establishes a new class of injection well (Class VI). 

The Safe Drinking Water Act (SDWA) provisions and U.S. Environmental Protection Agency 

(EPA) regulations cited in this document contain legally-binding requirements. In several 

chapters, this guidance document makes suggestions and offers alternatives that go beyond the 

minimum requirements indicated by the Class VI Rule. This is intended to provide information 

and suggestions that may be helpful for implementation efforts. Such suggestions are prefaced by 

“may” or “should” and are to be considered advisory. They are not required elements of the rule. 

Therefore, this document does not substitute for those provisions or regulations, nor is it a 

regulation itself, so it does not impose legally-binding requirements on EPA, states, or the 

regulated community. The recommendations herein may not be applicable to each and every 

situation. 

EPA and state decision makers retain the discretion to adopt approaches on a case-by-case basis 

that differ from this guidance where appropriate. Any decisions regarding a particular facility 

will be made based on the applicable statutes and regulations. Mention of trade names or 

commercial products does not constitute endorsement or recommendation for use. EPA is taking 

an adaptive rulemaking approach to regulating Class VI injection wells and the agency will 

continue to evaluate ongoing research and demonstration projects and gather other relevant 

information as needed to refine the rule. Consequently, this guidance may change in the future 

without a formal notice and comment period.

While EPA has made every effort to ensure the accuracy of the discussion in this document, the 

obligations of the regulated community are determined by statutes, regulations or other legally 

binding requirements. In the event of a conflict between the discussion in this document and any 

statute or regulation, this document would not be controlling.

Note that this document only addresses issues covered by EPA’s authorities under the SDWA. 

Other EPA authorities, such as Clean Air Act (CAA) requirements to report carbon dioxide 

injection activities under the Greenhouse Gas Mandatory Reporting Rule (GHG MRR), are not 

within the scope of this document.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells ii

Executive Summary

The Federal Requirements Under the Underground Injection Control (UIC) Program for 

Carbon Dioxide Geologic Sequestration Wells are now codified in the U.S. Code of Federal 

Regulations [40 CFR 146.81 et seq.]. These requirements are often collectively referred to as the 

Class VI Rule. The Class VI Rule establishes a new class of injection well, Class VI, and sets 

minimum federal technical criteria for Class VI injection wells that are protective of 

underground sources of drinking water (USDWs). EPA developed the Class VI Rule to ensure 

that USDWs are sufficiently protected during all phases of geologic sequestration (GS)

operations. The Class VI requirements are built upon the existing UIC regulatory framework and 

tailored to the unique nature of GS. This guidance is part of a series of technical guidance 

documents that EPA is developing to support owners or operators of Class VI wells and the UIC 

Program permitting authorities in the implementation of the Class VI Rule. The Class VI Rule 

and related documents are available at 

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

Carbon dioxide is currently injected into some oil and gas reservoirs for the purpose of 

enhancing the recovery of oil and gas. Injection wells used for enhanced oil recovery (EOR) and 

enhanced gas recovery (EGR)—collectively referred to as enhanced recovery or ER wells—are 

regulated as Class II wells under the UIC Program. EPA anticipates, however, that carbon 

dioxide injection for the purpose of GS may also occur in depleting or depleted oil and gas 

reservoirs. The Agency believes that if the business model for a well or group of wells changes 

from an ER-focused activity to one that maximizes carbon dioxide injection volumes and 

permanent storage, then the risk of endangerment to USDWs is likely to increase and such wells 

may need to be re-permitted as Class VI wells [75 FR 77230, 77244, December 10, 2010].

This Draft Underground Injection Control (UIC) Program Guidance on Transitioning Class II 

Wells to Class VI Wells provides information regarding the transition of a Class II well to a Class 

VI well. This information includes the factors specified in the Class VI Rule at 40 CFR 144.19

that inform when re-permitting must occur. This guidance also provides information regarding 

Class VI regulations that may be of interest to owners or operators of Class II wells and Class II 

UIC Program Directors. 

Owners or operators of Class II wells that are injecting carbon dioxide for the primary purpose of 

long-term storage into an oil or gas reservoir must apply for and obtain a Class VI permit where 

there is an increased risk to USDWs compared to traditional Class II operations using carbon 

dioxide [40 CFR 144.19(a)]. EPA recognizes that there may be some carbon dioxide trapped in 

the subsurface at ER operations; however, if the Class VI UIC Program Director has determined 

that there is no increased risk to USDWs, then these operations would continue to be permitted 

under the Class II requirements. EPA has identified factors for owners or operators and Class VI 

UIC Program Directors to consider when determining if risks to USDWs have increased [40 

CFR 144.19(b)]. No single factor should be relied on to make a determination of injection 

purpose and potential risk. Rather, all available factors should be considered in determining the 

appropriate well class for a carbon dioxide injection well in an oil or gas reservoir.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells iii

Once a determination has been made that a Class VI permit is needed to continue injection, a 

number of requirements must be fulfilled, both at the time of re-permitting and during future 

operations. The owner or operator must demonstrate that the proposed injection well is 

appropriately constructed and operable as a Class VI well and will not endanger USDWs [40 

CFR 146.81(c)]. The Class VI Rule describes the requirements that must be met in order to 

grandfather existing Class II wells to Class VI wells, including a demonstration that the wells 

meet the requirements at 40 CFR 146.86(a). This guidance document describes a number of 

requirements an owner or operator must follow including well construction and operation, GS 

site testing and monitoring, post-injection site care (PISC) and emergency and remedial 

response, among other requirements. In addition, a Class VI well owner or operator must adhere 

to more comprehensive operating requirements than those required for Class II wells, as 

specified at 40 CFR 146.88. Mechanical integrity testing requirements for Class VI wells at 40 

CFR 146.89 are more rigorous than those for Class II wells. Some testing and monitoring 

procedures are unique to Class VI wells, such as plume and pressure front tracking [40 CFR 

146.90(g)]. PISC [40 CFR 146.93] and emergency and remedial response [40 CFR 146.94]

requirements are also unique to Class VI wells. These combined requirements provide protection 

for USDWs and are tailored to the longer timeframes and greater injection volumes expected at 

GS operations.

Under the Class VI Rule, new aquifer exemptions will not be granted for Class VI wells.

However, some Class II wells currently operate with aquifer exemptions; as a result, when these 

Class II wells are re-permitted for GS, the Class VI Rule allows owners or operators to request 

an expansion of the areal extent of a previously existing aquifer exemption [40 CFR 144.7(d)].

To do this, the owner or operator must define the new expanded area for the aquifer exemption, 

per 40 CFR 144.7, and show that the new area meets the criteria for exempted aquifers given at 

40 CFR 146.4. These criteria serve to ensure that the exempted area is not used as a drinking 

water source and is not likely to be used as a drinking water source in the future. This guidance 

document outlines the process by which this expansion may be requested, evaluated, approved or 

disapproved. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells iv 

Table of Contents

1 Introduction ...................................................................................................................... 1

1.1 Comparison of Class II and Class VI UIC Regulations .................................................. 2

1.2 Re-permitting of Class II Wells ....................................................................................... 5

1.3 Organization of this Guidance Document ....................................................................... 7

2 Background on Enhanced Oil and Gas Recovery in the U.S........................................... 9

2.1 Carbon Dioxide Enhanced Recovery Operating Practices ............................................ 11

2.2 Potential Risks to USDWs from EOR ........................................................................... 12

2.3 Phases of a Hypothetical EOR Project Transitioning to a GS project ........................... 14

3 Factors for Identifying the Need for a Class VI Permit ................................................. 16

3.1 Reservoir Pressure, Injection Rate and Production Rate [40 CFR 144.19(b)(1-4)] ...... 18

3.2 Suitability of Class II Area of Review Delineation [40 CFR 144.19(b)(5)].................. 26

3.3 Quality of Abandoned Well Plugs [40 CFR 144.19(b)(6)] ........................................... 27

3.4 Anticipated Plan for Recovery of Injected Carbon Dioxide at Cessation of Injection for 

ER [40 CFR 144.19(b)(7)] ............................................................................................. 28

3.5 Source and Properties of Injected Carbon Dioxide [40 CFR 144.19(b)(8)] .................. 29

3.6 Additional Factors Determined by the UIC Program Director [40 CFR 144.19(b)(9)] 30

4 UIC Requirements for Wells Transitioning from the Class II to the Class VI Program 31

4.1 Class II ER Well Construction and Corrosion ............................................................... 31

4.2 Meeting the Well Construction and Logging Requirements for Class VI Wells .......... 31

4.2.1 Construction and Logging Requirements and Considerations for Wells 

Transitioning from Class II to Class VI ................................................................. 33

4.2.2 Considerations for Demonstrating that Transitioning from a Class II to a Class VI 

Injection Well is Appropriate .................................................................................. 35

4.3 Non-Construction Related Permit Requirements .......................................................... 39

4.3.1 Injection Well Operation ......................................................................................... 39

4.3.2 Mechanical Integrity ............................................................................................... 40

4.3.3 Testing and Monitoring ........................................................................................... 41

4.3.4 Reporting ................................................................................................................. 42

4.3.5 Injection Well Plugging .......................................................................................... 43

4.3.6 Post-Injection Site Care and Site Closure ............................................................... 44

4.3.7 Emergency and Remedial Response ....................................................................... 44

4.4 Area Permits .................................................................................................................. 45

5 Transitioning Wells and Aquifer Exemptions ............................................................... 47

5.1 Aquifer Exemptions and GS Projects ............................................................................ 47

5.2 Applying to Expand the Areal Extent of an Aquifer Exemption ................................... 48

5.3 Evaluating Requests for Aquifer Exemption Expansions.............................................. 53

6 References ...................................................................................................................... 55

Appendix I. Detailed Comparison of Class II and Class VI Regulations .................................. A-1
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells v 

List of Figures

Figure 1. Graphs of Oil Production Rates during Primary Production, Waterflooding and ER with Carbon 

Dioxide (i.e., Carbon Dioxide Flooding) for (a) the SACROC Unit and (b) Denver Unit in the Permian 

Basin, Texas. ............................................................................................................................................... 10

Figure 2. Number of Active Carbon Dioxide EOR Projects per State (as of 2008) and DOE Anticipated 

Regions for GS in Oil and Gas Reservoirs. ................................................................................................ 11

Figure 3. Schematic of an EOR Project Showing Carbon Dioxide Injection, Production of Mixed Fluids, 

Separation and Carbon Dioxide Recycling (a) and a Water-Alternating-Gas Scenario (b). ....................... 14

Figure 4. Phases of a Hypothetical Oil Production Project that Transitions to ER and Eventually GS, 

Illustrating Relative Risk. ........................................................................................................................... 15

Figure 5. Hypothetical Carbon Dioxide Injection Project Schematic. ........................................................ 21

Figure 6. Predicted Change in Injection Zone Pressure with Injection and Extraction at the Abandoned 

Well. ............................................................................................................................................................ 23

Figure 7. Graph of Predicted Change in Reservoir Pressure for Scenario 2 (see Box 1), with a Decrease in 

Reservoir Production Rate at 360 Days. ..................................................................................................... 26

Table 

Table 1. Comparison of Requirements for Class II and Class VI Wells. ...................................................... 3
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells vi

Acronyms and Abbreviations 

AoR Area of Review

API American Petroleum Institute

ASTM American Society for Testing and Materials

BOPD Barrels of Oil per Day

CFR Code of Federal Regulations

DOE United States Department of Energy

EGR Enhanced Gas Recovery

EIA Energy Information Administration

EOR Enhanced Oil Recovery

EPA United States Environmental Protection Agency

EPRI Electrical Power Research Institute

ER Enhanced Recovery

FR Federal Register

GS Geologic Sequestration

mg/L Milligram per Liter

MI Mechanical Integrity

MIT Mechanical Integrity Test

MPa Megapascals

NETL National Energy Technology Laboratory

OGJ Oil and Gas Journal

pH Potential for Hydrogen Ion Concentration

PDFs Probability Density Functions 

PISC Post-Injection Site Care

PRA Probabilistic Risk Assessment

psig Pounds per Square Inch Gauge

SACROC Scurry Area Canyon Reef Operators Committee

SDWA Safe Drinking Water Act

SDWIS Safe Drinking Water Information System

TDS Total Dissolved Solids

UIC Underground Injection Control

USDW Underground Source of Drinking Water

USGS United States Geological Survey

WAG Water Alternating Gas
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells vii

Definitions 

Key to definition sources:

1: 40 CFR 144.3.

2: Class VI Rule Preamble.

3: This definition was drafted for the purposes of this document.

4: 40 CFR 146.81(d).

5: EPA’s UIC website (http://water.epa.gov/type/groundwater/uic/glossary.cfm). 

6: 40 CFR 144.6(f) and 144.80(f)

Administrator means the Administrator of the United States Environmental Protection Agency, 

or an authorized representative. 1

Annulus means the space between the well casing and the wall of the borehole; the space 

between concentric strings of casing; the space between casing and tubing. 2

Aquifer exemption refers to a special exemption that removes an aquifer or part of an aquifer 

from SDWA protection when certain requirements (at 40 CFR 146.4) are met to demonstrate that 

the exempted aquifer does not currently serve as a source of drinking water and has no real 

potential to be used as a drinking water source in the future.

3

Area of Review (AoR) means the region surrounding the geologic sequestration project where 

USDWs may be endangered by the injection activity. The area of review is delineated using 

computational modeling that accounts for the physical and chemical properties of all phases of 

the injected carbon dioxide stream and displaced fluids, and is based on available site 

characterization, monitoring, and operational data as set forth in 40 CFR 146.84. 4

Brine refers to water that has a quantity of salt, especially sodium chloride, dissolved in it. Large 

quantities of brine are often produced along with oil and gas.

5

Carbon dioxide plume means the extent underground, in three dimensions, of an injected 

carbon dioxide stream.4

Carbon dioxide stream means carbon dioxide that has been captured from an emission source 

(e.g., a power plant), plus incidental associated substances derived from the source materials and 

the capture process, and any substances added to the stream to enable or improve the injection 

process. This subpart [subpart H of 40 CFR 146] does not apply to any carbon dioxide stream 

that meets the definition of a hazardous waste as defined by RCRA under 40 CFR part 261.4

Casing means pipe material placed inside a drilled hole to prevent the hole from collapsing. The 

two types of casing in most injection wells are (1) surface casing, the outer-most casing that 

extends from the surface to the base of the lowermost USDW and (2) long string casing, which 

extends from the surface to or through the injection zone.2

Cement means material used to support and seal the well casing to the rock formations exposed 

in the borehole. Cement also protects the casing from corrosion and prevents movement of 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells viii

injectate up the borehole. The composition of the cement may vary based on the well type and 

purpose; cement may contain latex, mineral blends, or epoxy.2

Class I wells means technologically sophisticated wells that inject wastes into deep, isolated 

rock formations below the lowermost USDW. Class I wells may inject hazardous waste, nonhazardous industrial waste, or municipal wastewater.5

Class II wells means wells that inject brines and other fluids associated with oil and gas 

production, or storage of hydrocarbons. Class II well types include salt water disposal wells, 

enhanced recovery wells, and hydrocarbon storage wells.5

Class III wells means wells that inject fluids associated with solution mining of minerals. 

Mining practices that use Class III wells include, but are not limited to, salt solution mining, in

situ leaching of uranium, and sulfur mining using the Frasch process.5

Class V wells means wells not included in Classes I to IV and Class VI. Class V wells inject 

non-hazardous fluids into or above a USDW and are typically shallow, on-site disposal systems; 

however, this class also includes some deeper injection operations. There are approximately 20 

subtypes of Class V wells.5

Class VI wells means wells that are not experimental in nature that are used for geologic 

sequestration of carbon dioxide beneath the lowermost formation containing a USDW; or, wells 

used for geologic sequestration of carbon dioxide that have been granted a waiver of the 

injection depth requirements pursuant to requirements at 40 CFR 146.95; or, wells used for 

geologic sequestration of carbon dioxide that have received an expansion to the areal extent of an 

existing Class II enhanced oil recovery or enhanced gas recovery aquifer exemption pursuant to 

40 CFR 146.4 and 40 CFR 144.7(d).6

Computational model means a mathematical representation of the injection project and relevant 

features, including injection wells, site geology, and fluids present. For a GS project, site specific 

geologic information is used as input to a computational code, creating a computational model 

that provides predictions of subsurface conditions, fluid flow, and carbon dioxide plume and 

pressure front movement at that site. The computational model comprises all model input and 

predictions (i.e., output).3

Confining zone means a geologic formation, group of formations, or part of a formation 

stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. For Class 

VI wells operating under an injection depth waiver, confining zone means a geologic formation, 

group of formations, or part of a formation stratigraphically overlying and underlying the 

injection zone(s).4

Corrective action means the use of Director-approved methods to assure that wells within the 

area of review do not serve as conduits for the movement of fluids into underground sources of 

drinking water (USDWs).

4

Corrosive means having the ability to wear away a material by chemical action. Carbon dioxide 

mixed with water, for example, forms carbonic acid, which can corrode well materials.2
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells ix

Enhanced Gas Recovery (EGR) means the process of injecting a gas (i.e., carbon dioxide) into 

a gas-bearing formation to displace available gas to allow it to be produced.3

Enhanced Oil Recovery (EOR) means the process of injecting carbon dioxide into an oil 

reservoir to thin (decrease the viscosity of) extractable oil, which is then available for recovery.3

Enhanced Recovery means either enhanced oil recovery or enhanced gas recovery.3

Fluid means any material or substance which flows or moves whether in a semisolid, liquid, 

sludge, gas or other form or state.1

Formation or geological formation means a layer of rock that is made up of a certain type of 

rock or a combination of types.2

Geologic dome refers to a geologic formation that is round or oval in shape and resembles an 

inverted bowl. A geologic dome consists of an anticline that plunges in all directions.3

Geologic sequestration (GS) means the long-term containment of a gaseous, liquid or 

supercritical carbon dioxide stream in subsurface geologic formations. This term does not apply 

to carbon dioxide capture or transport.4

Geologic sequestration project means an injection well or wells used to emplace a carbon 

dioxide stream beneath the lowermost formation containing a USDW; or, wells used for geologic 

sequestration of carbon dioxide that have been granted a waiver of the injection depth 

requirements pursuant to requirements at 40 CFR 146.95; or, wells used for geologic 

sequestration of carbon dioxide that have received an expansion to the areal extent of an existing 

Class II enhanced oil recovery or enhanced gas recovery aquifer exemption pursuant to 40 CFR 

146.4 and 144.7(d). It includes the subsurface three-dimensional extent of the carbon dioxide 

plume, associated area of elevated pressure, and displaced fluids, as well as the surface area 

above that delineated region.4

Geophysical surveys refers to the use of geophysical techniques (e.g., seismic, electrical, 

gravity, or electromagnetic surveys or well logging methods such as gamma ray and spontaneous 

potential) to characterize subsurface rock formations.3

Heterogeneity refers to the spatial variability in the geologic structure and/or physical properties 

of the site.3

Injectate means the fluids injected. For the purposes of the Class VI Rule, this is also known as 

the carbon dioxide stream.2

Injection depth waivers refer to the provisions at 40 CFR 146.95 that allow owners or operators 

to seek a waiver from the Class VI injection depth requirements for GS to allow injection into 

non-USDW formations while ensuring that USDWs are protected from endangerment.3

Injection zone means a geologic formation, group of formations, or part of a formation that is of 

sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a 

well or wells associated with a geologic sequestration project.4
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells x

Injectivity refers to the efficiency of displacement of an injected fluid into porous rock, both 

within the rock (micro-displacement efficiency) as well as from the perspective of total pore 

space (sweep efficiency).3

Lithology means the description of rocks, based on color, mineral composition, and grain size.5

Logging means the measurement of physical properties in or around the well.3

Mechanical integrity (MI) means the absence of significant leakage within the injection tubing, 

casing, or packer (known as internal mechanical integrity), or outside of the casing (known as 

external mechanical integrity).2

Mechanical integrity test (MIT) refers to a test performed on a well to confirm that a well 

maintains internal and external mechanical integrity. MITs are a means of measuring the 

adequacy of the construction of an injection well and a way to detect problems within the well 

system.2

Miscible refers to a term used to describe phases that can be combined to form a homogenous 

mixture. Immiscible phases cannot be combined to form a homogenous mixture.3

Model means a representation or simulation of a phenomenon or process that is difficult to 

observe directly or that occurs over long time frames. Models that support GS can predict the 

flow of carbon dioxide within the subsurface, accounting for the properties and fluid content of 

the subsurface formations and the effects of injection parameters.2

Multiphase flow refers to flow in which two or more distinct phases are present (e.g., liquid, 

gas, supercritical fluid).3

Packer means a mechanical device that seals the outside of the tubing to the inside of the long 

string casing, isolating an annular space.2

Parameter means a mathematical variable used in governing equations, equations of state, and 

constitutive relationships. Parameters describe properties of the fluids present, porous media, and 

fluid sources and sinks (e.g., injection well). Examples of model parameters include intrinsic 

permeability, fluid viscosity, and fluid injection rate.3

Portland cement refers to a hydraulic cement made by reacting a pulverized calcium silicate 

hydrate material (C-S-H), which in turn is made by heating limestone and clay in a kiln, with 

water to create a calcium silicate hydrate and other reaction products.

3

Post-injection site care means appropriate monitoring and other actions (including corrective 

action) needed following cessation of injection to ensure that USDWs are not endangered, as 

required under 40 CFR 146.93.4

Pressure front means the zone of elevated pressure that is created by the injection of carbon 

dioxide into the subsurface. For [GS projects], the pressure front of a carbon dioxide plume 

refers to the zone where there is a pressure differential sufficient to cause the movement of 

injected fluids or formation fluids into a USDW.4
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells xi

Primacy (primary enforcement responsibility) means the authority to implement the UIC 

Program. To receive primacy, a state, territory, or tribe must demonstrate to EPA that its UIC 

program is at least as stringent as the federal standards; the state, territory, or tribal UIC 

requirements may be more stringent than the federal requirements. (For Class II, states must 

demonstrate that their programs are effective in preventing pollution of USDWs.) EPA may grant 

primacy for all or part of the UIC Program, e.g., for certain classes of injection wells.5

Site closure means the point/time, as determined by the Director following the requirements 

under 40 CFR 146.93, at which the owner or operator of a GS site is released from post-injection 

site care responsibilities.4

Supercritical fluid: A fluid above its critical temperature (31.1oC for carbon dioxide) and 

critical pressure (73.8 bar for carbon dioxide).5

Total dissolved solids (TDS) refers to the measurement, usually in mg/L, for the amount of all 

inorganic and organic substances suspended in liquid as molecules, ions, or granules. For 

injection operations, TDS typically refers to the saline (i.e., salt) content of water-saturated 

underground formations.2

Transmissive fault or fracture means a fault or fracture that has sufficient permeability and 

vertical extent to allow fluids to move between formations.4

Tubing refers to a small-diameter pipe installed inside the casing of a well. Tubing conducts 

injected fluids from the wellhead at the surface to the injection zone and protects the long string 

casing of a well from corrosion or damage by the injected fluids.

5

Underground Injection Control Program refers to the program EPA, or an approved state, is 

authorized to implement under the Safe Drinking Water Act (SDWA) that is responsible for 

regulating the underground injection of fluids by wells injection. This includes setting the federal 

minimum requirements for construction, operation, permitting, and closure of underground 

injection wells.3

Underground Injection Control Program (UIC Program) Director refers to the chief 

administrative officer of any state or tribal agency or EPA Region that has been delegated to 

operate an approved UIC program.5

Underground Source of Drinking Water (USDW) means an aquifer or its portion which 

supplies any public water system; or which contains a sufficient quantity of ground water to 

supply a public water system; and currently supplies drinking water for human consumption; or 

contains fewer than 10,000 mg/l total dissolved solids; and which is not an exempted aquifer.

1

Water alternating gas refers to an enhanced oil recovery technique used to increase oil yields 

from a reservoir that involves alternating between periods of water and gas (i.e., carbon dioxide) 

injection.3

Waterflooding refers to a secondary recovery technique using the injection of water.3
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells xii

Well bore refers to the hole that remains throughout a geologic (rock) formation after a well is 

drilled.3

Wireline refers to a wire or cable used to lower tools and instruments into a well.3

Workover refers to any maintenance activity performed on a well that involves ceasing injection

or production and removing the wellhead.3
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 1

1 Introduction

The Underground Injection Control (UIC) Program of the United States Environmental 

Protection Agency (EPA) is responsible for establishing regulations for the construction, 

operation, permitting and closure of injection wells through which fluids are placed underground.

EPA’s regulations, at Title 40 of the Code of Federal Regulations (CFR) Parts 144 through 148, 

establish six classes of injection wells, based on the type of injection activity and types of fluids 

injected. Class II injection wells (formally defined at 40 CFR 144.6) are wells into which fluids 

associated with oil and gas production are injected, including carbon dioxide injected for the 

purpose of enhanced recovery (ER). The EPA rule Federal Requirements Under the 

Underground Injection Control Program for Carbon Dioxide Geologic Sequestration Wells [40 

CFR 146.81 et seq.], referred to in this document as the Class VI Rule, created a new UIC 

injection well category, Class VI, specifically for the injection of carbon dioxide for the purpose 

of geologic sequestration (GS).

Carbon dioxide is currently injected into some oil and gas reservoirs for the purpose of 

increasing or enhancing the recovery of oil and gas. Injection wells used for enhanced oil 

recovery (EOR) or enhanced gas recovery (EGR) are collectively referred to as ER wells. ER 

wells have traditionally been regulated under the UIC Program as Class II wells. The Class VI 

Rule requires that owners or operators that are injecting carbon dioxide for the primary purpose 

of long-term storage into an oil and gas reservoir must apply for and obtain a Class VI GS permit 

when there is an increased risk of endangerment to underground sources of drinking water 

(USDWs) compared to Class II operations [40 CFR 144.19(a)].

EPA recognizes that it is very likely that some carbon dioxide will be trapped in the subsurface 

as part of ER operations; however, if there is no increased risk to USDWs, then these operations 

would continue to be permitted under Class II requirements. Traditional EOR projects are not 

affected by the Class VI rulemaking and will continue to be permitted under Class II

requirements. The Class VI Rule lists several factors that the UIC Program Director must 

consider to determine if risks to USDWs have increased and a Class VI permit is required [40 

CFR 144.19(b)].

This document is designed to provide guidance to injection well owners or operators and UIC 

Program Directors regarding when Class II operations must be re-permitted as Class VI wells. 

This document is part of a series of technical guidance documents intended to provide 

information and possible approaches for addressing various aspects of permitting and operating a 

Class VI injection well. The Class VI guidance documents are intended to complement each 

other and to assist owners or operators in preparing permit applications that satisfy the 

requirements of the Class VI Rule and are tailored to the characteristics of individual sites.

Cross-linkages between guidance documents are noted in the text where appropriate. These 

additional UIC Program GS guidance documents can be found at 

http://water.epa.gov/type/groundwater/uic/class6/gsguidedoc.cfm.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 2

1.1 Comparison of Class II and Class VI UIC Regulations

When an injection well operation transitions from a Class II to a Class VI well, the well owner or 

operator must comply with all Class VI requirements. There are, however, certain components of 

Class II well construction that may be grandfathered into the Class VI Program at the discretion 

of the Class VI UIC Program Director [40 CFR 146.81(c)]. While the Class II requirements are 

designed specifically to protect USDWs from injection activities conducted for ER and brine 

disposal, the Class VI Rule is designed to protect USDWs from carbon dioxide injection 

associated with GS projects. The Class VI requirements build on existing UIC requirements, 

including those for Class II, and are tailored for the unique circumstances of GS through 

additional requirements, such as post-injection site care (PISC).

The nature and risks of carbon dioxide injection for long-term storage into Class VI wells are 

different from those at Class II carbon dioxide injection wells used for EOR. For example, 

reservoir pressure conditions and injection rates and volumes will be different between Class II 

and Class VI. Additionally, the corrosivity of carbon dioxide in the presence of water 

necessitates additional protective measures that are not required of Class II owners or operators.

A summary comparison of Class II and Class VI requirements is provided in Table 1, and a more 

detailed comparison is provided in Appendix I. The Class VI requirements are more 

comprehensive and specific than the Class II requirements. For instance, the area of review 

(AoR) delineation requires sophisticated modeling for Class VI [40 CFR 146.84(c)(1)], whereas 

the AoR for Class II operations may be delineated using a fixed radius or a radial calculation, 

although an owner or operator may use more sophisticated modeling depending on the Class II 

operation [40 CFR 146.6]. Well construction standards are more specific for Class VI, and more 

frequent mechanical integrity (MI) testing of the Class VI wells is required [40 CFR 146.89 and 

40 CFR 146.90(e)]. Additionally, monitoring of ground water quality and tracking the fate of the 

injectate and induced pressure front are required under the Class VI Program [40 CFR 

146.90(d)], but not the Class II program. Post-injection monitoring is also required only under 

the Class VI Program [40 CFR 146.93(b)]. Multiple Class II wells within a single field may be 

permitted on a field-basis through the use of a single “area permit.” Area permits are not allowed 

for Class VI wells; instead, each Class VI well in a given field or site must be permitted 

individually [40 CFR 144.33(a)(5)].

The Class VI Program is implemented under Section 1422 of the Safe Drinking Water Act 

(SDWA), which mandates that states seeking primary enforcement responsibility (primacy) meet 

all minimum federal requirements for protection of USDWs by developing and implementing a 

UIC Program with requirements that meet the minimum federal requirements. Class II Programs, 

however may be implemented under Section 1422 or Section 1425 of the SDWA. Programs 

implemented under Section 1425 are required to demonstrate an effective Class II Program for 

preventing underground injection that endangers USDWs. (Class II Programs implemented 

under Section 1422 must have Class II regulations that are at least as stringent as the federal 

Class II regulations.) 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 3

The more comprehensive and specific requirements of the Class VI Program (as compared to the 

Class II Program requirements) reflect the unique potential risks posed to USDWs by GS. EPA 

anticipates that the injection pressures and injected carbon dioxide volumes will be greater for 

commercial-scale GS projects than for ER projects, resulting in larger project areas, increased 

project duration, and, therefore, a greater potential for risk of endangerment to USDWs.

Table 1. Comparison of Requirements for Class II and Class VI Wells.

Requirement 

Type

Class VI 

Regulatory 

Citations

Class II Requirements (Summary) 

and Regulatory Citations

Significant Differences between Class II and 

Class VI Requirements

Required 

Class VI 

permit 

information 

40 CFR 

146.82

Information is required on the 

local geology. The UIC Program 

Director may consider information 

including maps and cross sections 

of the regional geology, including 

the AoR; the planned formation 

testing program, construction, 

operating and monitoring 

procedures; and a demonstration 

of financial responsibility to close 

the well. (40 CFR 146.24)

Class VI regulations require information on 

baseline geochemistry and seismic history.

Class VI requirements include several 

project-specific plans not required for Class 

II (e.g., post-injection site care and site 

closure and comprehensive Emergency and 

Remedial Response Plans). 

Class VI requirements include periodic 

updates to certain plans.

Minimum 

criteria for 

siting 

40 CFR 

146.83

Demonstrate the presence of 

injection and confining zones. 

Confining zone must be free of 

known open faults or fractures 

within the AoR. (40 CFR 146.22)

Class VI regulations permit the UIC Program 

Director to require characterization of 

additional confining zones.

Area of 

review and 

corrective 

action 

40 CFR 

146.84

Define the AoR as a fixed radius of 

at least 1⁄4 mile or based on the 

zone of endangering influence

(calculate by a formula). (40 CFR 

146.6)

For new wells, identify status of 

corrective action on improperly 

completed or plugged wells in the 

AoR. (40 CFR 146.24(c)(6))

Class VI regulations require computational 

modeling for AoR and periodic reevaluation 

of the AoR and Corrective Action Plan. 

Class VI regulations require the use of 

carbon dioxide-compatible materials for 

corrective action.

Class VI regulations permit phased 

corrective action.

Financial 

responsibility 

40 CFR 

146.85

Demonstrate and maintain 

financial responsibility to close, 

plug, or abandon the well. (40 CFR 

146.24(a)(9))

Class VI regulations have requirements for 

financial responsibility to address corrective 

action, post-injection site care and site 

closure and emergency and remedial 

response. 

Class VI regulations have requirements for 

allowable instruments.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 4

Requirement 

Type

Class VI 

Regulatory 

Citations

Class II Requirements (Summary) 

and Regulatory Citations

Significant Differences between Class II and 

Class VI Requirements

Injection well 

construction 

40 CFR 

146.86

Wells must be constructed to 

prevent movement of fluids into 

or between USDWs. Casing and 

cementing must be designed for 

the life expectancy of the well. (40 

CFR 146.22) 

Class VI regulations specify the depths of 

casing strings and cementing to the 

surface*.

Class VI regulations require compatibility of 

well materials with fluids with which they 

would come into contact.

Logging, 

sampling and 

testing prior 

to injection 

well 

operation 

40 CFR 

146.87

Class II and Class VI regulations 

include similar requirements for 

logging, sampling and testing (40 

CFR 146.22 (f)). 

Class VI regulations require cores to be 

taken and a log analyst’s report to be 

submitted*.

Class VI regulations require tests to verify 

the hydrogeologic characteristics of the 

injection zone (e.g., pressure fall-off test and 

pump test or injectivity tests) *.

Class VI regulations require the owner or 

operator to provide the UIC Program 

Director the opportunity to witness all 

logging and testing for a Class VI well.

Injection well 

operating 

requirements 

40 CFR 

146.88

Injection between the outermost 

casing protecting USDWs and the 

well bore is prohibited. (40 CFR 

146.23(a)(2))

Injection pressures may not 

initiate or propagate fractures in 

the confining zone or cause 

injection or formation fluid 

movement into USDWs. (40 CFR 

146.23(a)(1))

Class VI regulations include a pressure 

limitation. 

Class VI regulations include a requirement to 

install continuous recording devices, alarms 

and surface or down-hole shut-off systems 

or other safety devices. 

Class VI regulations require specific 

procedures if a loss of mechanical integrity is 

discovered or a shutdown (i.e., down-hole or 

at the surface) is triggered.

Mechanical 

integrity 

testing

40 CFR 

146.89

Conduct internal and external 

MITs at least once every five 

years. (40 CFR 146.23(b)(3))

Class VI regulations require continuous 

monitoring to demonstrate internal 

mechanical integrity. 

Class VI regulations require annual external 

mechanical integrity testing. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 5

Requirement 

Type

Class VI 

Regulatory 

Citations

Class II Requirements (Summary) 

and Regulatory Citations

Significant Differences between Class II and 

Class VI Requirements

Testing and 

monitoring 

requirements 

40 CFR 

146.90

Monitor injected fluids. Observe 

injection pressure, flow rate and 

cumulative volume on a daily, 

weekly or monthly basis, 

depending on the type of 

operation. (40 CFR 146.23(b)(1-2))

Class VI regulations require:

• Continuously monitoring of injected 

fluids, injection pressure, flow rate and 

cumulative volume;

• Plume and pressure front tracking; 

• Surface air monitoring and soil 

monitoring, at the UIC Program 

Director’s discretion; and

• Corrosion monitoring and ground water 

quality monitoring.

Reporting 

requirements 

40 CFR 

146.91

Submit annual monitoring report. 

(40 CFR 146.23(c))

Class VI require:

• Semi-annual monitoring report;

• Electronic reporting; and

• Record-keeping.

Injection well 

plugging 

40 CFR 

146.92

Well must be plugged in a manner 

which will not allow the 

movement of fluids either into or 

between a USDW. (40 CFR

146.10(a)(1))

Class VI regulations require compatibility of 

the plugging material with fluids with which 

the plugs may be expected to come into 

contact. 

Class VI regulations specify pre-plugging 

activities, notice of intent to plug and a 

plugging report.

Post-injection 

site care and 

site closure 

40 CFR 

146.93

None. Class VI regulations require post-injection 

site care or monitoring; no such 

requirements exist for Class II.

Emergency 

and remedial 

response 

40 CFR 

146.94

Submit contingency plans to cope 

with well failures so as to prevent 

migration of fluids into a USDW.

(40 CFR 146.24(b)(4))

Class VI regulations address other potential 

risks in the AoR, such as risks from the 

pressure front.

*Pursuant to requirements at 40 CFR 146.81(c), owners or operators seeking to convert existing wells to Class VI 

geologic sequestration wells must demonstrate to the UIC Program Director that the wells were engineered and 

constructed to meet the requirements at 40 CFR 146.86(a) and ensure protection of USDWs, in lieu of 

requirements at 40 CFR 146.86(b) and 146.87(a). See Section 4 of this guidance for additional information on 

requirements for transitioning wells. 

1.2 Re-permitting of Class II Wells

As noted above, owners or operators of existing Class II injection wells that inject carbon 

dioxide into an oil or gas reservoir for the primary purpose of long-term storage of carbon 

dioxide must apply for and secure a Class VI permit when there is an increased risk to USDWs 

compared to Class II operations [40 CFR 144.19(a)]. The Class VI UIC Program Director must 

determine, based on review of information provided by the owner or operator and the factors at 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 6

40 CFR 144.19(b), when there is an increased risk to USDWs (see Section 3). EPA anticipates 

that such an evaluation may be initiated by an owner or operator, suggested by a Class II UIC 

Program Director based on an evaluation of the factors at 40 CFR 144.19, or may be requested 

by the Class VI Program Director as a result of periodic evaluations of information on wells in 

mature oil and gas fields in the context of the factors at 40 CFR 144.19. Several options are 

available to facilitate the request for and evaluation of site-specific information (e.g., monitoring

data) about Class II ER operations that is needed to evaluate the factors at 40 CFR 144.19(b):

• 40 CFR 144.17 provides either the Class II or Class VI UIC Program Director with the 

authority to require that a Class II owner or operator “conduct monitoring, and provide 

other information as is deemed necessary to determine whether the owner or operator has 

acted or is acting in compliance with Part C of the SDWA or its implementing 

regulations.” This could include requesting information needed to determine whether the 

injection may lead to an increased risk to USDWs relative to Class II operations.

• 40 CFR 144.51(h) requires permittees to provide “any information which the Director 

may request to...determine compliance with [a] permit.” This gives the Class II UIC 

Program Director the authority to include Class II permit provisions to gather information 

that may be needed in the future to determine whether the project meets the definition of 

a Class II well or whether re-permitting as a Class VI well is necessary.

• 40 CFR 144.52(a)(9) gives the Class II permit writer authority to “impose on a case-bycase basis such additional conditions as are necessary to prevent the migration of fluids 

into underground sources of drinking water.” This may include the Class II UIC Program 

Director requesting monitoring or other information needed to support an evaluation of 

the factors at 40 CFR 144.19(b) on behalf of the Class VI UIC Program Director. If the 

Class II owner or operator plans to eventually transition to GS, the Class II UIC Program 

Director may use authority at 40 CFR 144.52(a)(9) to guide the monitoring and reporting 

conditions of the Class II permit to allow collection of necessary information.

The review of site-specific information and evaluation of the factors at 40 CFR 144.19(b) by the 

Class VI UIC Program Director may take place in consultation with the Class II UIC Program 

Director and the owner or operator. Consultation and coordination between Class II and Class VI 

permitting authorities may be needed, particularly where they are with different organizations 

(e.g., where two different state agencies have Class II and Class VI primacy or where the state 

has Class II Program primacy and the Class VI Program is directly implemented by EPA) or 

when permitting of Class II and Class VI wells in a state is under different authorities (e.g., the 

state has primacy for Class II wells under SDWA Section 1425 and Class VI wells under SDWA 

Section 1422). EPA recommends that states work across agencies, with EPA regional staff and 

with owners or operators as appropriate to facilitate the transfer of relevant information about a 

site and ensure that all existing data about a site and an owner or operator are available to the 

Class VI permit writer.

Following a determination that the well must be re-permitted as a Class VI well, the owner or 

operator of a re-permitted injection well must meet all Class VI requirements. However, under 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 7

40 CFR 146.81(c), the UIC Program Director has the option to grandfather the construction of 

existing wells to be re-permitted as Class VI if the owner or operator demonstrates to the UIC 

Program Director that the wells were engineered and constructed to meet the requirements at 40 

CFR 146.86(a) and ensure protection of USDWs, in lieu of requirements at 40 CFR 146.86(b) 

and 146.87(a). See Section 4 of this document and the UIC Program Class VI Well Construction 

Guidance for additional information on grandfathering of Class II wells. Prior to the repermitting of an existing Class II well, the owner or operator must submit, and the UIC Program 

Director must consider, all of the permit information at 40 CFR 146.82(a) and (c). 

EPA recognizes that some GS project owners or operators may plan to eventually produce the 

injected carbon dioxide from the injection zone (e.g., to sell it for ER). However, these projects 

require a Class VI permit. The appropriate injection well class is based on the injection activity 

and its risk to USDWs, and a Class VI permit is needed to address the potential risk associated 

with high pressures that will exist in the subsurface during injection and in the early months or 

years of carbon dioxide withdrawal. Because the high injection rates and pressures associated 

with GS will cause movement of the carbon dioxide plume—even if the planned withdrawal 

would occur a few years after injection ceases—a Class VI permit (and the required operationaland post-injection phase monitoring) is needed to address potential risks of USDW 

endangerment. Injecting carbon dioxide under a Class VI permit will not preclude future 

withdrawal of the carbon dioxide.

Following re-permitting as a Class VI well, the owner or operator will be subject to all of the 

operational, testing and monitoring, reporting, injection well plugging and PISC and site closure 

requirements set forth in 40 CFR 146 Subpart H. For additional information on permitting Class 

VI wells, see the UIC Program Class VI Implementation Manual for State Directors.

1.3 Organization of this Guidance Document

The remaining sections of this guidance document are organized as follows:

• Section 2, Background on Enhanced Oil and Gas Recovery in the U.S., presents

background information on carbon dioxide ER operations, potential risks to USDWs, and 

the phases of a traditional ER project transitioning to GS. 

• Section 3, Factors for Identification of the Need for a Class VI Permit, describes the 

factors at 40 CFR 144.19 to be considered by owners or operators and the Class VI UIC 

Program Director when determining whether a Class VI permit is required for carbon 

dioxide injection wells currently permitted as Class II wells. These factors include: 

increase in reservoir pressure; increase in carbon dioxide injection rates; decrease in 

reservoir production rates; distance between injection zone and USDWs; suitability of 

Class II AoR delineation; quality of abandoned well plugs; anticipated recovery of 

injected carbon dioxide at cessation of injection; source and properties of injected carbon 

dioxide and possibly additional factors determined by the Class VI UIC Program 

Director.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 8

• Section 4, UIC Requirements for Wells Transitioning from Class II to Class VI, 

describes well construction for Class II wells and additional Class VI requirements that 

owners or operators must meet following a determination that a Class II ER project will 

transition to a Class VI GS project [40 CFR 146.86 and the construction-related 

requirements at 40 CFR 146.87(a)]. These additional requirements include well 

construction requirements as well as operating-phase requirements and individual well 

permitting requirements for Class VI wells. 

• Section 5, Transitioning Wells and Aquifer Exemptions, describes how owners or 

operators of Class II ER projects that currently operate under an aquifer exemption can 

apply to expand the areal extent of the aquifer exemption pursuant to the requirements of 

40 CFR 144.7(d). The relationship between aquifer exemptions and injection depth 

waivers for GS projects is also briefly discussed. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 9

2 Background on Enhanced Oil and Gas Recovery in the U.S.

ER, which includes both EOR and EGR, refers to the injection of fluids into a reservoir to 

increase oil and/or gas production efficiency. ER is typically conducted at a reservoir after 

production yields have decreased from primary production—during primary oil production, no 

fluids are injected into the reservoir to enhance production. Fluids commonly used for ER

include brine, fresh water, steam, nitrogen, alkali solutions, surfactant solutions, polymer 

solutions and supercritical carbon dioxide. EOR involves injecting carbon dioxide or another 

fluid into an oil reservoir to help mobilize the remaining oil and make it available for recovery; 

EGR refers to injecting a gas (e.g., carbon dioxide) into a gas-bearing formation to displace 

available gas to allow it to be produced. ER using supercritical carbon dioxide, sometimes also 

referred to as carbon dioxide flooding, has been successfully used at many production fields 

throughout the U.S. (and abroad) to increase recovery. For example, Figure 1 presents 

production data from two fields in the Permian Basin, Texas, showing increased oil production 

volumes following EOR with carbon dioxide.

Carbon dioxide EOR is the fastest-growing EOR technique in the U.S., producing 323,000 

barrels of oil per day (BOPD) in 2004. This comprises about 6.5 percent of U.S. crude oil 

production (OGJ, 2008; EIA, 2009). The vast majority of worldwide carbon dioxide EOR is 

conducted in oil reservoirs in the U.S. Permian Basin, which extends through southwest Texas 

and southeast New Mexico. The majority of these projects are located in Texas, and the 

remaining projects are located in Mississippi, Wyoming, Michigan, Oklahoma, New Mexico, 

Utah, Louisiana, Kansas and Colorado (see Figure 2). 

EPA believes many early GS projects may be sited in depleted, depleting, or active oil and gas 

reservoirs because these formations have been previously characterized for hydrocarbon 

recovery and likely already have suitable infrastructure (e.g., wells, pipelines, etc.). EPA expects

that these early projects will support meeting near-term greenhouse gas mitigation goals and 

advance CCS technology development. Additionally, oil and gas fields now considered to be 

“depleted” may resume operation because of increased availability and decreased cost of 

anthropogenic carbon dioxide (NETL, 2010). Current Department of Energy (DOE) projections 

of areas where GS may occur in oil and gas reservoirs are included in Figure 2. Anticipated 

regions of interest primarily include Louisiana, Texas, Oklahoma, Kansas, New Mexico, 

Colorado, Wyoming, California, Montana, North Dakota, West Virginia and Ohio.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 10 

(a)

(b)

Figure 1. Graphs of Oil Production Rates during Primary Production, Waterflooding and ER with 

Carbon Dioxide (i.e., Carbon Dioxide Flooding) for (a) the SACROC Unit and (b) Denver Unit in 

the Permian Basin, Texas. 

From: EPRI (1999).
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 11 

DOE Carbon Atlas projected 

regions of capacity in active 

and depleted reservoirs

Source: 2010 EOR 

Survey

Number of active CO2 EOR projects per State

1-5 11-15

6-10 >15 Figure 2. Number of Active Carbon Dioxide EOR Projects per State (as of 2008) and DOE 

Anticipated Regions for GS in Oil and Gas Reservoirs. 

From: DOE (2010).

2.1 Carbon Dioxide Enhanced Recovery Operating Practices

EOR with carbon dioxide increases the rate of production via miscible displacement, through 

which the mobility of the residual oil in the reservoir is increased. The improved recovery is due 

primarily to elimination of surface tension between supercritical carbon dioxide and the liquid 

phase hydrocarbon in the reservoir. Secondary effects of the miscible carbon dioxide-oil 

interaction include increase in the specific volume of the oil phase and a reduction in viscosity, 

both of which improve mobility of the oil phase relative to the water phase and result in an 

increase in recoverable hydrocarbon. ER can also occur through immiscible displacement, in 

which the carbon dioxide displaces the oil as an immiscible fluid. Immiscible displacement 

occurs at shallower depths and lower pressures than miscible displacement. Figure 3a presents a 

schematic of a generalized carbon dioxide EOR project. Carbon dioxide, provided either from a 

pipeline or other conveyance or stored on-site, is compressed to a supercritical state (if 

necessary) and injected into the oil-producing formation (i.e., injection zone). Production wells 

in the vicinity of the carbon dioxide injection well extract a fluid mixture that may contain 

injection fluids (e.g., carbon dioxide, water) and formation fluids (e.g., water, oil, solids and 

natural gas). A series of above-ground separators are then used to separate out the carbon 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 12 

dioxide, which is commonly recycled and re-injected. Oil, natural gas, solids and water are also 

separated out. Depending on the volume of carbon dioxide being added to the system, the 

separated water, which is normally a brine (high in salts), is handled in one of two ways: either 

(1) it is re-injected through a Class II well into the reservoir from which it was originally 

produced, or (2) it is injected into a Class II disposal well into another reservoir that is pressureisolated from the original reservoir of production. In the case of water-alternating-gas (WAG)

operations (Figure 3b), the separated water may be re-injected for EOR purposes through the 

same injection well system as the carbon dioxide. 

The carbon dioxide used for ER may come from natural geologic and/or anthropogenic sources. 

Representative compositions of carbon dioxide used for ER are given by Meyer (2007). 

Generally, the composition of carbon dioxide delivered to an ER site is greater than 95 percent 

carbon dioxide, with other constituents typically including nitrogen, methane and trace amounts 

of water. After mixing delivered carbon dioxide and recycled carbon dioxide, the injectate 

composition may vary from 92 percent to 97 percent carbon dioxide. Both the carbon dioxide 

delivered to the EOR or EGR site and the recycled carbon dioxide contain very low amounts of 

water vapor to control corrosion. Surface injection pressures for carbon dioxide injection in ER

wells are often greater than 2,000 pounds per square inch-gauge (psig) or 138 bars. The 

maximum injection pressure is determined by the lower of two pressures, either the fracture 

gradient of the injection formation or confining formation, multiplied by a safety factor of less 

than 1.0. The surface and bottom hole operating injection pressures are always maintained below 

this regulatory limit. The actual injection pressures are determined for each well by a technical 

and economic calculation taking into account reservoir pressure, surface temperature, reservoir 

temperature, injectate composition, injection rate, reservoir maturity and the regulatory limit. A 

second, separate safety factor is then utilized to establish a desired routine operating injection 

pressure and a higher safety shutdown limit, which is also below the regulatory limit. 

A primary challenge in EOR is preventing preferential flow, or channeling, of carbon dioxide 

through high-permeability lenses in the formation, which results in reduced reservoir sweep 

efficiency and excessive carbon dioxide cycling. To improve sweep efficiency, EOR fields are 

normally operated with WAG injection, where water and carbon dioxide injection are alternated 

cyclically (e.g., EPRI, 1999; Meyer, 2007; Jessen et al., 2005); see Figure 3b. Other options to 

maximize the efficiency and reservoir sweep of the EOR operation are the use of horizontal 

injection wells, the addition of chemical agents to increase viscosity and reduce viscous 

fingering, a significant increase in carbon dioxide injection volumes above normal injection rates 

and innovative well placement designs and targeting of specific zones (e.g., Jessen et al., 2005; 

ARI, 2006; Meyer, 2007). Carbon dioxide injection wells and oil production wells are sited in 

patterns frequently repeated throughout the site, designed to maximize oil recovery. 

2.2 Potential Risks to USDWs from EOR 

The injection of fluids, including carbon dioxide, underground poses potential risks to USDWs. 

In the context of the UIC Program, the term “risk” refers to the possibility for degradation of 

water quality in a USDW as it relates to the usability of that USDW as a drinking water source 

now or in the future. A USDW is considered to be “endangered” if an injection project has 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 13 

caused degradation of water quality. There are several ways in which such degradation might 

occur in a GS project:

• Migration of carbon dioxide into a USDW, which may change geochemical 

characteristics of the USDW, including decreased pH and consequent leaching of natural 

minerals to release contaminants (e.g., lead and arsenic) into the USDW; 

• Migration of drinking water contaminants transported in the injectate (e.g., hydrogen 

sulfide and mercury) into USDWs;

• Change in geochemistry of formation fluids that may cause leaching of drinking water 

contaminants (e.g., lead and arsenic), which may then migrate into the groundwater of 

USDWs, impairing drinking water quality; and/or 

• Induced migration of non-potable, saline formation fluids from the injection zone, or 

overlying zones, into a USDW. 

EPA designed the Class VI regulations to minimize risks to USDWs that may be posed by GS 

projects. If GS projects are properly operated in compliance with all Class VI regulations, EPA 

believes that risks to USDWs will be appropriately managed and USDWs will be protected. 

(a)
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 14 

(b) 

Figure 3. Schematic of an EOR Project Showing Carbon Dioxide Injection, Production of Mixed 

Fluids, Separation and Carbon Dioxide Recycling (a) and a Water-Alternating-Gas Scenario (b).

2.3 Phases of a Hypothetical EOR Project Transitioning to a GS project

As described above, EPA anticipates that for wells injecting carbon dioxide in oil and gas 

reservoirs for GS, there may be an increased risk to USDWs compared to traditional Class II 

operations. Figure 4 presents an example of a risk diagram showing relative risk over the 

different phases of a generic carbon dioxide project. During primary oil production, no fluids are 

injected into the reservoir to enhance production. The oil and/or gas production rate declines 

during primary production as the remaining oil in place is more difficult to access and remove. In 

the example field, first waterflooding and then EOR are employed to increase production rates. 

Although injection of carbon dioxide increases production efficiency initially, production rates 

decrease over time. (This trend is shown for actual oil production fields in Figure 1.) In this 

example, as the owner or operator transitions the primary purpose of his/her project from EOR to 

GS, there is an increased risk to USDWs when compared to the ER operations, and therefore, the 

owner or operator should obtain a Class VI permit. During GS, carbon dioxide injection rates 

increase and fluid production rates continue to decline. At the point when the reservoir has 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 15 

received the maximum practical volume of carbon dioxide, injection ceases. The Class VI GS 

project continues during PISC and eventually ends with site closure.

Figure 4. Phases of a Hypothetical Oil Production Project that Transitions to ER and Eventually 

GS, Illustrating Relative Risk. 

From: Benson (2007).
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 16 

3 Factors for Identifying the Need for a Class VI Permit

Owners or operators that are injecting carbon dioxide for the primary purpose of long-term 

storage into an oil and gas reservoir must apply for and obtain a Class VI permit when there is an 

increased risk to USDWs compared to Class II operations [40 CFR 144.19(a)]. 

This guidance document discusses the “primary purpose” of the injection only as it relates to and 

supports an identification within EPA’s UIC Program of the appropriate UIC well class under 

which a well injecting carbon dioxide must be permitted. The determination of primary purpose 

for the UIC well class evaluation may have little or no bearing on how the purpose of the well is 

defined for other regulatory programs or activities. 

The determination of the need for a Class VI permit is based on risk to USDWs. In the Class VI 

Rule, EPA identified several factors that indicate a change in project operations that may 

increase risks to USDWs. These factors are to be considered by owners or operators and Class 

VI UIC Program Directors

1

 when determining whether a Class VI permit is required for carbon 

dioxide injection in wells currently permitted as Class II wells. They may also be considered by 

owners or operators applying for a permit for a Class II well to inform business decisions prior to 

deciding whether to permit a well as a Class II or Class VI well. Considering these factors ahead 

of time may also ease the transition process at a later point in time. These factors are established 

in the Class VI Rule at 40 CFR 144.19(b), and include: 

• Increase in reservoir pressure; 

• Increase in carbon dioxide injection rates; 

• Decrease in reservoir production rates; 

• Distance between injection zone and USDWs; 

• Suitability of Class II AoR delineation; 

• Quality of abandoned well plugs; 

• Anticipated recovery of injected carbon dioxide at cessation of injection; 

• Source and properties of injected carbon dioxide; and

• Additional factors determined by the UIC Program Director.

EPA developed these factors to inform a determination regarding whether an increased risk to 

USDWs warrants re-permitting a project from Class II to Class VI. No single factor from this list 

should be independently relied upon to make determinations. Rather, all available factors should 

 

1 The decision to re-permit a Class II well as a Class VI well will benefit from consultation and coordination with 

the Class II UIC Program Director. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 17 

be considered in determining the appropriate well class for a carbon dioxide injection well in an 

oil and gas reservoir, to the extent possible given information available to the Class VI UIC 

Program Director. Specific factors are discussed in detail in this section. 

EPA recognizes that Class II wells may not necessarily transition to Class VI. This may be 

because an evaluation of the above factors results in a determination that a Class VI permit is not 

needed, either because the owner or operator determines that he/she does not want to proceed 

with or continue carbon dioxide injection and decides to plug the well, or because a 

determination is made that the Class II well was not sited or constructed in a manner that allows 

for safe, long-term storage of large volumes of carbon dioxide as a Class VI injector. 

EPA encourages owners or operators of ER operations considering a transition to GS to consult 

with both the Class II and the Class VI UIC Program Directors. Ongoing discussions between all

parties will promote communication regarding the appropriate permit for each project and if 

necessary facilitate the transition from Class II to Class VI. Additionally, this communication 

may clarify what additional project-specific information (e.g., production rates or any plan for 

recovery of injectate at the cessation of injection) the Class VI UIC Program Director will need 

that may not be regularly required of or submitted by Class II owners or operators for Class II 

ER projects. 

Although a formal risk assessment is not required by the Class VI Rule, owners or operators may 

choose to submit the results of a quantitative risk assessment to complement operational and 

monitoring data submitted to the Class VI UIC Program Director to inform the considerations at 

40 CFR 144.19. One approach to risk assessment is to evaluate features, events and processes 

(FEPs) of an engineered system that may affect the system’s behavior; this approach is used in 

assessing risks for various engineered systems and is discussed in the context of GS by the 

Carbon Sequestration Leadership Forum (CSLF, 2009). A database of FEPs can help in using 

this approach to identify issues for a system (e.g., http://www.quintessa.org/co2fepdb/). For 

owners or operators seeking to pursue a quantitative probabilistic risk assessment (PRA), the box 

on the next page provides some background on PRA methods and examples of methods that 

have been developed for and applied to GS. If a PRA is performed, EPA recommends that 

owners or operators submit information on their choice of method, information on their input 

data, including choice of probability density functions (PDFs) for input variables, and detailed 

information on output, including appropriate graphs and a narrative discussing the results along 

with any data submitted to the Class VI UIC Program Director.

The remaining sections describe each of the factors at 40 CFR 144.19(b) and provide guidance 

regarding how the Class VI UIC Program Director may evaluate them.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 18 

Probabilistic Risk Assessment

Probabilistic risk assessment (PRA) methods present a way to accommodate the uncertainty inherent in 

input variables for models evaluating risk (e.g., Nicot et al., 2006). This is especially important in geologic 

settings, which exhibit inherent variability in physical properties and may be prone to future seismic 

events with little predictability. PRAs attempt to capture the uncertainty associated with this variability 

through the use of probability density functions (PDFs). PDFs incorporate a statistical distribution that 

defines a range of reasonable values for a particular input parameter (i.e., intrinsic permeability) rather 

than a single “average” value (Deel et al., 2007). PDFs are defined by several statistical parameters, such 

as the median PDF value and variance. The choice of PDF for a particular parameter at a GS project 

should be based on available data regarding distribution of the parameter. A PRA may then be performed 

to estimate the probabilities of various risk exposure scenarios based on the assumed PDFs of the input 

variables.

In particular, a PRA may take advantage of required data on potential leakage pathways (e.g., faults and

well bores), formation properties (e.g., permeability and thickness) and formation fluids (e.g., pressure, 

velocity and salinity) to demonstrate how this information translates into the likelihood of USDW 

endangerment. If an owner or operator wishes to perform a risk assessment, EPA recommends that they 

consider the current state of the science on probabilistic methods that have been developed for and 

applied to GS. Below are three examples: 

• Walton et al. (2004) developed a statistical approach to GS performance and risk and applied it to 

the Weyburn project. Their model, CQUESTRA-2 (CQ-2) (LeNeveu et al., 2006), is a semi-analytical 

model that can be used for both probabilistic and deterministic simulations. A deterministic 

simulation does not incorporate randomness or variability in input variables; it uses discrete input 

values and yields a reproducible output. A probabilistic simulation incorporates uncertainty in input 

through the use of PDFs, as described above. The probabilistic aspect of CQ-2 is handled using a 

Monte-Carlo (repeated random sampling) simulation plug-in for Microsoft Excel. Variability is 

expressed in PDFs for porosity, permeability, Darcy flow velocity, well component degradation, 

leakage processes and other parameters. The model Monte Carlo simulator samples the input 

variables from their PDFs and the modeling process is applied iteratively. 

• Oldenburg et al. (2009) developed an approach termed the Certification Framework (CF). The CF 

uses deterministic models to obtain estimates of leakage from wells and faults. It uses a probabilistic 

approach to calculate the risk of carbon dioxide or brine reaching an environmental compartment 

(e.g., a USDW) via a fault or well by estimating: 1) the likelihood of the carbon dioxide reaching a 

leakage pathway and 2) the likelihood of the pathway intersecting the environmental compartment of 

concern. 

• The CO2-PEN model (Stauffer et al., 2006; NETL, 2011) is a system-level model, which 

incorporates a number of aspects of a GS system. It is built on GoldSim, a commercially available 

modeling software product. It can be used to coordinate subprograms handling a variety of physical 

and chemical models, including reservoir simulators. Variables can be passed into and out of the 

subprograms from the system-level model and CO2-PENS can use Monte-Carlo simulation to 

develop probabilistic representations of variables of interest. CO2-PENS has been linked to a 

number of programs, including reactive flow models such as FEHM, TOUGHREACT, and 

FLOTRAN, as well as PHREEQ-C for geochemical simulations (NETL, 2011). 

3.1 Reservoir Pressure, Injection Rate and Production Rate [40 CFR 144.19(b)(1-4)]

Reservoir pressure refers to the pressure of fluids within the oil and/or gas reservoir that 

constitutes the injection zone. During GS operations, injection zone pressure and carbon dioxide 

volumes will likely increase if carbon dioxide injection rates increase. Furthermore, the 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 19 

i f u i u i P , = P + ρ g ⋅(z − z ) [1] 

dissipation of reservoir pressure will decrease if fluid production from the reservoir decreases. 

Although pressure dissipation is likely and common in the early and middle stages of the 

productive life of a field, pressures may remain elevated even after carbon dioxide injection (and 

oil production) ceases. Owners or operators may also choose to maximize carbon dioxide storage 

by using “well pressure control,” a technique that effectively increases the pressure of the 

reservoir by decreasing production rates (e.g., Kovscek and Cakici, 2005). 

Elevated pressure great enough to cause fluid movement past the confining zone or through 

another potential leakage pathway poses a primary risk factor to USDWs from injection because 

it may result in unintended fluid migration that endangers USDWs. Thus, monitoring data on the 

fluid pressure within the injection zone is a direct measure of the risks posed to USDWs by the 

injection project. Reservoir pressure within the injection zone that is increased and sustained at

pressures greater than the routine operating pressure range of the ER project will stress the 

primary confining zone and well plugs to a greater degree than traditional ER (e.g., Klusman, 

2003). Furthermore, active and abandoned well bores are much more numerous at oil and gas 

fields than at other potential GS sites and may be potential leakage pathways (Celia et al., 2004). 

An AoR evaluation pursuant to the Class VI requirements at 40 CFR 146.84 is necessary to 

identify abandoned wells and perform corrective action in accordance with necessary standards 

to prohibit fluid leakage. 

Because of the possibility of elevated pressure, the Class VI UIC Program Director should also 

evaluate increased carbon dioxide injection and/or decreased hydrocarbon production rates in 

determining risks to USDWs, as listed at 40 CFR 144.19(b)(2-3), and discussed below. 

Increase in Reservoir Pressure [40 CFR 144.19(b)(1)] 

Reservoir pressure within the formation is measured from a well that is not injecting or 

withdrawing fluids for a period of at least several days prior to or at the time of measurement.

Pressure is measured by monitoring instruments known as pressure transducers, or gauges, which 

are discussed in detail in the UIC Program Class VI Well Testing and Monitoring Guidance. 

Pressure measurements can be compared to historical pressure levels and fluctuations to gain 

further understanding of the baseline conditions. Trends over time of significantly increasing 

pressure for extended duration, (i.e., greater than six months to one year), considered in 

conjunction with other factors listed in this section, indicate that a Class VI permit may be 

required. 

Specifically, increased pressures within the injection zone should be compared against the 

threshold pressure at which fluids are predicted to migrate from the injection zone to the 

lowermost USDW through a hypothetical open conduit. The pressure threshold within the 

injection zone that may cause fluid movement into a USDW (Pi,f) may be determined by the 

following equation: 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 20

Where Pu is the average fluid pressure within the lowermost USDW, ρi is the density of 

groundwater within the injection zone, g is a constant for the acceleration due to gravity, and zu

and zi are the elevations of the USDW and injection zone, respectively, relative to a common 

datum (e.g., mean sea level). A pressure increase within the injection zone greater than Pi,f

indicates that the risk to USDWs has increased. Importantly, Eq-1 is only valid in cases where 

the injection zone is not overpressured relative to the lowermost USDW. Reservoirs that have 

been previously subjected to ER operations will, in most cases, meet this assumption. Further 

discussion of threshold pressure calculations are provided in the UIC Program Class VI Well 

Area of Review Evaluation and Corrective Action Guidance. 

It should be noted that the hypothetical open conduit assumption is presented as a conservative 

scenario. In an appropriately sited GS project with suitable corrective action, there should not be 

direct communication between the injection zone and a USDW through an open conduit.

Alternative methods may be used to estimate the threshold pressure in overpressured formations. 

More detailed methods for assessment of the critical pressure may be used that account for 

salinity and temperature gradients (e.g., Nicot et al., 2006). Additional site-specific 

circumstances may influence the assumptions used in calculation of the critical threshold 

pressure, and the Class VI UIC Program Director may be consulted for evaluation of alternative 

assumptions and methodologies. An example of the anticipated increase in injection zone 

pressure with transition to GS is provided in Box 1. Reservoir pressure is commonly monitored 

during ER operations, but reporting (as a Class II well owner or operator) to the Class II UIC 

Program Director may not be required, as monitoring and reporting of reservoir pressure is not a 

Class II federal permit requirement [40 CFR 146.23]. However, pursuant to the requirements at

40 CFR 144.52(a)(9), the Class II UIC Program Director may request pressure data from Class II 

well owners or operators to evaluate risks to USDWs, especially in projects of dual purposes 

such as ER and GS. Additionally, on a project-specific basis, the Class VI UIC Program Director 

may request information pursuant to 40 CFR 144.17 to inform a transition decision. The amount, 

format and specific types of data requested are based on the UIC Program Director’s discretion

and project details.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 21 

Box 1: Example of Determining Pressure Changes

 

This section presents examples of pressure changes in a hypothetical formation. The 

graphs presented are hypothetical examples, displaying pressure changes as influenced by 

projected injection and production rates. For actual projects, projected pressure changes may 

be estimated via analytical, semi-analytical, or numerical modeling techniques based on 

available site data (see e.g., Zhou et al., 2008, Nicot et al., 2008; Nordbotten et al, 2004; 

Doughty et al., 2007). 

A simple hypothetical formation is presented in Figure 5. In this formation, a single 

large confining unit separates the injection zone and an overlying USDW. Initial hydraulic 

head (hint), before any injection or production, is 1,700 meters (m) in the injection zone and 

1,900 m in the USDW, corresponding to initial fluid pressures of 6.72 and 0.49 mega-Pascals 

(MPa), respectively. Initial pressures in the injection zone are great enough to force native 

fluids vertically upwards through a potential conduit (e.g., abandoned well bore) but not great 

enough to force fluid vertically upwards to the height of the USDW. 

USDW

Confining Unit

Injection Zone

Confining Unit

z = 0 m

z = 1000 m

z = 1800 m

z = 1900 m

z = 1030 m

z = 1950 m

hint = 1900m

hint = 1700m 400 m (1/4 mile) 10 m

note: not to scale

Pu = 0.49 MPa

Pi = 6.72 MPa

Figure 5. Hypothetical Carbon Dioxide Injection Project Schematic.

The perforated interval of the injection and production wells is depicted by dashed zones. 

The abandoned well is assumed to be uncased, and therefore open, along its entire depth.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 22 

Box 1, continued: Example of Determining Pressure Changes

Pressure (e.g., hydraulic head) in the injection zone is a function of injection and 

production rates, distance from injection and extraction wells, time after initiation of injection 

and production, as well as the aquifer properties of the injection zone. 

For the present example exercise, four injection/production scenarios are evaluated: 

• Scenario 1: Oil production without carbon dioxide injection. 

• Scenario 2: Oil production with low carbon dioxide injection. 

• Scenario 3: Oil production with high carbon dioxide injection. 

• Scenario 4: Carbon dioxide injection without oil production. 

Specific injection and extraction rates for each of these scenarios are presented in the 

following table: 

Injection Rate m3/d Production Rate m3/d

Scenario 1 0 3000 

Scenario 2 3000 3000 

Scenario 3 4000 1000 

Scenario 4 4000 0 

The scenarios are designed such that Scenario 1 is strictly oil production, and 

Scenario 4 is strictly GS, while Scenario 2 and Scenario 3 represent ER projects that are 

transitioning to GS and therefore must be evaluated for the necessity of a Class VI permit. In 

the example, injection zone pressure increases from Scenario 1 to Scenario 4.

When pressure in the injection zone increases such that hydraulic heads within the 

injection zone are greater than hydraulic heads in the lowermost USDW, fluids in the 

injection zone could potentially be pushed into the USDW via an artificial penetration, fault, 

or fracture system. The pressure threshold that defines risk of fluid flow from the injection 

zone to the lowermost USDW is calculated with Equation 1. For this example, the injection 

zone threshold pressure (Pi,f) is 8.68 MPa. Pressure increases will be greatest at the injection 

well and decrease exponentially as distance from the injection well (r) increases. In the 

example, it is assumed that adequate protections exist at the injection well to preclude fluid 

movement through or around the well bore, and the artificial penetration at a distance of 400 

meters (approximately 1/4 mile) from the injection well is the relevant measurement point for 

pressure increase.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 23 

Box 1, continued: Example of Determining Pressure Changes

2

3

4

5

6

7

8

9

10

0 100 200 300

Injection Zone Pressure, MPa

Time, d

Scenario 1

Scenario 2

Scenario 3

Scenario 4

Threshold Pressure Great

Enough to Cause Fluid

Movement into the USDW

Figure 6. Predicted Change in Injection Zone Pressure with Injection and Extraction at the 

Abandoned Well. 

Hypothetical values of pressure at the artificial penetration as a function of time for 

each of the four scenarios are presented in Figure 6. For Scenario 1, with production and no 

injection, injection zone pressure decreases, therefore decreasing risk of efflux of fluids out 

of the injection zone. For Scenario 2, injection and production rates are equal, and pressure 

in the injection zone remains nearly constant at levels only slightly above initial conditions. 

In Scenario 3, injection rates are greater than production rates, and injection zone pressure 

reaches the threshold level of 8.68 MPa at about 150 days. In Scenario 4, without any 

production, the threshold pressure is reached within 80 days after the start of injection. 

Therefore, for Scenarios 3 and 4, there is risk for efflux of native fluids into the overlying 

USDW, whereas for Scenarios 1 and 2 this is not the case. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 24

Increase in Carbon Dioxide Injection Rates [40 CFR 144.19(b)(2)]

As discussed above, increased carbon dioxide injection rates may be used to increase the volume 

of carbon dioxide sequestered. Such an increase may indicate an increased risk to USDWs 

compared to Class II operations. Increased carbon dioxide injection rates are one of the key 

determinants of reservoir pressure and also result in an increased volume of carbon dioxide in the 

subsurface. Injection rates have the greatest influence on reservoir pressure in the region nearest 

the well bore, with decreasing influence further from the injection well.

Carbon dioxide injection rates are measured with a flow metering device (see the UIC Program 

Class VI Well Testing and Monitoring Guidance). For evaluation as a criterion, injection rates 

should be considered from an individual well or on a project basis by manifold monitoring.

Monitoring of injection flow rates and pressures is required on at least a monthly basis for Class 

II ER wells [40 CFR 146.23]. Anticipated injection rates and pressures (average and daily 

maximum) are required information for authorization of a Class II permit [40 CFR 146.24].

Proposed injection rates and/or pressures are provided with the Class II permit application and 

are typically incorporated as operating conditions of the Class II permit. Any increase above 

those levels would be a violation of the Class II permit. When compared to historical data, 

injection rate increases for an extended time period may indicate increased risk to USDWs. 

Thresholds for the amount and duration of increase will be site-specific and based on historical 

operating records as well as the injection rate specified in the Class II permit. Taken in concert 

with other factors, injection rate increases may indicate the need for a Class VI permit.

Decrease in Reservoir Production Rates [40 CFR 144.19(b)(3)]

Owners or operators may elect to decrease reservoir production rates to maximize carbon dioxide 

storage. For example, produced fluids from EOR operations are typically a mixture of brine, 

hydrocarbons and carbon dioxide. As the efficiency of the EOR operation decreases over time, 

the amount of hydrocarbons in the produced fluids decreases. Production well pressure control 

has been described as a possible way to increase carbon dioxide storage at EOR facilities. This 

involves reduction of production rates when carbon dioxide levels in the produced fluid become 

high (Kovscek and Cakici, 2005).

Production rates may be measured with a flow metering device and may be evaluated on an 

individual well basis or from a manifold point for a group of production wells. Reservoir 

production rates are measured during ER operations, but reporting to the Class II UIC Program 

Director may not be required, as monitoring and reporting of reservoir pressure is not a Class II 

federal permit requirement. Thus, injection and production rates may be the best indicator of how 

reservoir pressure is changing. In cases where the Class VI UIC Program Director does not have 

access to reservoir production data, he/she may request these data from the Class II UIC Program 

Director or the owner or operator pursuant to requirements at 40 CFR 144.17.

When the sum of total fluid production (i.e., the total volume of brine, hydrocarbons and carbon

dioxide produced) is less than the total fluid injection for a significant period of time, there will 

be increased reservoir pressure, potentially increasing the risk to USDWs (see Box 2). The 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 25

amount of the pressure change will be based on several factors, as discussed above, including the 

change in injection and production volumes relative to the total pore volume of the storage 

reservoir/injection zone. If production rates decline significantly for an extended period of time 

(e.g., six months to one year) and reservoir injection rates are steady or increasing, this may 

indicate that a Class VI permit is required. Decisions regarding whether a Class VI permit is 

needed would be made considering the potential for decreasing production rates which leads to 

elevated pressure that may pose a risk to USDWs, along with other factors, including 

modification of operational parameters or other mitigation measures. 

Distance Between Injection Zone and USDWs [40 CFR 144.19(b)(4)]

The distance between the injection zone and the lowermost USDW is a primary determinant of 

the risk to USDWs posed by the injection operation. Increased distance between the injection 

zone and lowermost USDW allows for a larger pressure increase within the injection zone before 

USDWs might become endangered. This is demonstrated by Equation 1 (see page 14), which 

shows that as the term representing the distance between the injection zone and lowermost 

USDW (zu - zi) increases, the threshold pressure, that would result in possible fluid migration 

into a USDW through a hypothetical open conduit (Pi,f), increases. Similarly, if fluid leakage 

does occur through the confining zone, greater distance between the injection zone and 

lowermost USDW will allow for increased trapping of mobilized fluids before reaching the 

USDW. A greater vertical distance also increases the likelihood that there will be additional 

zones between the injection zone and the lowermost USDW that are available for monitoring.

In certain circumstances, the distance between the injection zone and the lowermost USDW may 

be adequate for the permitted Class II ER operation, but not necessarily adequate for a proposed 

GS project in the same location. If pressures within the injection zone increase beyond those 

allowed for the Class II operation, the possibility exists for greater vertical fluid migration and 

increased risks to USDWs. Furthermore, increased fluid injection rates may result in lateral fluid 

movement to areas where the distance between the injection zone and the lowermost USDW is 

not known.

The locations and depths of all USDWs are required information for a Class II permit application 

[40 CFR 146.24]. However, Class II requirements will likely not be sufficient for a carbon 

dioxide operation transitioning to GS if the distance to the lowermost USDW is small, allowing 

for the possibility of fluid leakage into the USDW. If the owner or operator or the Class VI UIC 

Program Director determines, from consideration of other factors, that a Class VI permit may 

eventually be required for the project, the distance between the injection zone and the lowermost 

USDW should be considered in determining when the Class VI permit is required. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 26 

Box 2: Example of Pressure Increase with Reduction in Production Rates 

 Reduction of fluid production rates, with steady or increasing carbon dioxide 

injection rates, will result in increased fluid pressure within the injection zone. For the 

simple hypothetical example shown in Box 1, Scenario 2, when injection and production 

rates are similar for the injection and extraction wells, reservoir pressure remains 

approximately constant. However, if production rates for Scenario 2 were to decrease, 

reservoir pressures are expected to increase. The change in reservoir pressure with a 

decrease in production rates from 3000 m3/d to 500 m3/d after 360 days was evaluated. As 

can be seen, in the hypothetical graph of pressure increase (Figure 7), at 700 days total, or 

340 days after reduction of the fluid production rate, pressure has increased above the 

threshold necessary for fluids to flow from the injection zone into the USDW at the 

abandoned well (8.68 MPa). 

2

3

4

5

6

7

8

9

10

0 200 400 600 800

Injection Zone Pressure, MPa

Time, d

Scenario 2 with decreasing

extraction rate at 360 days

Threshold Pressure Great

Enough to Cause Fluid

Movement into the USDW

Figure 7. Graph of Predicted Change in Reservoir Pressure for Scenario 2 (see Box 1), with a 

Decrease in Reservoir Production Rate at 360 Days. 

3.2 Suitability of Class II Area of Review Delineation [40 CFR 144.19(b)(5)] 

The AoR is the area around the injection well that may be affected by injection and that must be 

reviewed for the presence of artificial penetrations (i.e., wells) or other conduits for fluid 

movement. A key difference between Class II and Class VI requirements is the process for 

delineating the AoR (see Appendix I). The AoR for Class II wells is defined as either a fixed 

radius of 1/4 mile, or by a simple radial calculation based on the Theis formula [40 CFR 146.6]. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 27 

For Class VI wells, the AoR must be delineated using sophisticated computational modeling that 

accounts for multiphase flow of carbon dioxide and native fluids and takes into account any 

geologic heterogeneities, other discontinuities, data quality and their possible impact on model 

predictions [40 CFR 146.84]. A Class VI AoR may be much larger than that for a Class II well, 

and it may be non-circular. For more information regarding AoR delineation for Class VI wells, 

see the UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance. 

For a project transitioning from ER to GS, the original Class II AoR delineation may no longer 

be adequate. For example, elevated pressure and/or fluid migration may occur outside of the 

Class II delineated AoR. This is demonstrated by the hypothetical example provided in Box 1 

(on pages 21 to 23) and Box 2 (on page 26). The artificial penetration in this hypothetical 

example is located 1/4 mile (approximately 400 meters) from the injection well and could, 

therefore, be at the outermost boundary of a Class II AoR delineation. As shown in Figure 7, as 

operational parameters at the project change to more closely represent GS rather than ER, 

reservoir pressure at artificial penetrations in the AoR may increase to levels that may cause fluid 

movement into a USDW. In these cases, the AoR should be re-delineated to include any area that 

exhibits this elevated pressure. Under these circumstances, a Class VI permit may be required for 

continued injection well operation. 

Any monitoring data that indicate the presence of carbon dioxide or the pressure front (elevated 

pressure great enough to cause fluid movement into the lowermost USDW) beyond the Class II 

AoR is evidence that the AoR does not meet the Class VI requirements. Furthermore, relatively 

simple analytical modeling or more sophisticated computational modeling may be needed to 

estimate whether the Class II AoR delineation is adequate in comparison to AoR requirements 

under the Class VI Rule. EOR operations routinely use sophisticated computational modeling 

and uncertainty analysis to plan and evaluate the project, and this modeling may be used to 

assess the adequacy of the current AoR delineation.

Carbon dioxide plume and pressure front monitoring and modeling data are routinely collected 

and analyzed at ER operations as part of typical monitoring activities to ensure proper operation 

of the injection well. Reporting the results of this type of monitoring, though, is not required 

under Class II federal permit requirements. In cases where the Class VI UIC Program Director 

does not have access to these data, he/she may request these data from the Class II UIC Program 

Director or the owner or operator pursuant to requirements at 40 CFR 144.17. 

3.3 Quality of Abandoned Well Plugs [40 CFR 144.19(b)(6)] 

The quality of abandoned well plugs and well construction are key determinants of the risk to 

USDWs posed by the injection operation. To prevent fluid movement, abandoned wells should 

include a cement plug through the primary confining zone and/or across the injection zoneconfining zone contact. The cement plug should have sufficient integrity to contain separatephase carbon dioxide and elevated pressures. Abandoned wells should also have been 

constructed with an adequate quantity of cement that is sufficiently bonded to the casing to 

prevent the upward migration of fluids between the casing and the borehole. In the absence of an 

adequate plug across the confining zone, cross-migration may occur where fluids enter a 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 28 

permeable zone below the lowermost USDW and then migrate upward from that zone. Class VI 

regulations require that abandoned wells be plugged using methods designed to prevent the 

movement of fluid into or between USDWs, including use of materials compatible with the 

carbon dioxide stream [40 CFR 146.84(d)]. This could warrant the use of enhanced plugging 

techniques, including possibly the use of specialty cements. For further information regarding 

locating and assessing abandoned well plugs, see the UIC Program Class VI Well Area of 

Review Evaluation and Corrective Action Guidance. 

In approving a Class II permit application, the Class II UIC Program Director is required to 

consider the status of corrective action on wells within the AoR [40 CFR 146.24], including: (1) 

the type and number of plugs to be used; (2) the placement of each plug including the elevation 

of the top and bottom; (3) the type, grade and quantity of cement to be used; and (4) the method 

of emplacement of the plugs. This information should, therefore, be available to the Class VI 

UIC Program Director and may be provided in abandoned well plugging records and/or plug 

field testing. If the owner or operator or the Class VI UIC Program Director determine from 

consideration of other factors that the project may be transitioning to GS and a Class VI permit is 

required, the quality of abandoned well plugs should be considered. 

3.4 Anticipated Plan for Recovery of Injected Carbon Dioxide at Cessation of Injection 

for ER [40 CFR 144.19(b)(7)] 

For current ER operations, owners or operators may attempt to recover as much carbon dioxide 

from the subsurface as possible for recycling and use in future projects at other sites since carbon 

dioxide is currently a valuable commodity and an important investment at ER projects. Recovery 

of carbon dioxide, to the extent possible, at the end of an ER project incidentally decreases risk 

to USDWs because reservoir pressure is lowered and the carbon dioxide volume left in place 

decreases. However, owners or operators may plug and abandon an ER project without removing 

any carbon dioxide under Class II requirements. 

Because the objective of GS is to maximize carbon dioxide storage, owners or operators will 

typically leave the injected carbon dioxide in place after injection.2

 Therefore, fluid pressures in 

the injection zone will likely remain elevated above pre-injection levels for some period of time, 

and a large volume of carbon dioxide will remain in the subsurface. Separate phase carbon 

dioxide left in place poses a risk to USDWs because if the storage project has not been 

appropriately sited and operated, carbon dioxide may leak upward through leakage pathways 

(such as improperly abandoned wells or transmissive faults or fractures) due to buoyancy, or 

cause upward or downward movement of formation fluids due to elevated pressure. For example, 

modeling calculations indicate that accumulation of supercritical carbon dioxide at a thickness of 

 

2 Even if the owner or operator plans to produce some or all of the carbon dioxide eventually, a Class VI permit is 

required for GS projects where needed to address the potential risk to USDWs due to increased pore pressure 

associated with GS. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 29 

20 meters at the injection zone-confining zone interface is sufficient to cause leakage into 

microcracks or crevices in the confining zone as small as 2 microns in diameter (Saripalli and 

McGrail, 2002). Note that leakage into microcracks or crevices in the confining zone may not 

necessarily lead to endangerment of USDWs, as several processes may lead to attenuation of the 

carbon dioxide leakage above the injection zone/confining zone interface. 

Owners or operators are not required to submit an anticipated plan for recovery of carbon 

dioxide at the end of a project to the UIC Program Director since reporting of this information is 

not a Class II federal permit requirement [40 CFR 146.23]. However, in cases where the Class 

VI UIC Program Director does not have access to this data, he/she can request these data from 

the Class II UIC Program Director who may obtain them pursuant to 40 CFR 146.10(c), 144.12, 

or 144.52(b)(1) or from the owner or operator pursuant to requirements at 40 CFR 144.17. If the 

anticipated plan for the end of the project changes from recovery of carbon dioxide to 

maximizing carbon dioxide storage, this indicates that the primary purpose of the project is GS. 

Given this, risks to USDWs will remain after injection ceases, and therefore, post-injection 

monitoring and site care should be required. For these reasons, a Class VI permit may be 

required. 

3.5 Source and Properties of Injected Carbon Dioxide [40 CFR 144.19(b)(8)] 

As previously discussed, carbon dioxide used in ER projects may be anthropogenic in origin 

(e.g., from a natural gas processing plant, fertilizer production plant, or coal-fired power plant) or 

may come from natural underground geologic sources. Currently, the majority of carbon dioxide 

used in ER is from natural sources. The chemical composition of the carbon dioxide injectate, 

including the percent of carbon dioxide, depends on the source. Fluid properties (e.g., viscosity, 

density and potential acidity and corrosivity when mixed with water) and concomitant risks to 

USDWs are influenced by the chemical composition of the injectate. For example, sulfur dioxide 

may be an impurity in anthropogenic carbon dioxide streams from coal-fired power plants. 

Several studies have suggested that sulfur dioxide in the injected carbon dioxide stream may 

result in lower pH in the injection zone than if pure carbon dioxide is injected (Xu et al., 2007; 

Knauss et al., 2005). The lower pH may mobilize drinking water contaminants (e.g., arsenic or 

lead). If levels of drinking water contaminants within the injectate (such as mercury or hydrogen 

sulfide) increase with a change in carbon dioxide source, this may pose a risk to USDWs. 

The source of the injected fluid, along with an analysis of its chemical and physical 

characteristics, is required information that the Class II UIC Program Director considers for 

approval of a Class II permit application [40 CFR 146.24]. Furthermore, Class II owners or 

operators are required to report on the properties of the injectate at a time interval frequent 

enough to represent its characteristics [40 CFR 146.23]. Likewise, owners or operators must 

submit analyses of the carbon dioxide injectate when applying for a Class VI permit [40 CFR 

146.82(a)(7)(iv)] and are required to submit analyses of the injectate at an appropriate time 

interval [40 CFR 146.90(a)]. Thus, these data may be considered by the Class VI UIC Program 

Director to inform a re-permitting decision. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 30 

3.6 Additional Factors Determined by the UIC Program Director [40 CFR 

144.19(b)(9)] 

The Class VI UIC Program Director may specify additional factors that are tailored to the 

information available to him/her based on regional or state requirements and site-specific 

geologic and operational conditions. Examples of additional factors include, but are not limited 

to: 

• Migration of carbon dioxide into regions known to exhibit faults, fractures, or additional 

migration pathways; 

• Evidence of surface leakage of carbon dioxide or constituents mobilized by the injection 

process; and

• Increased risk of induced geomechanical activity, including fault slippage, due to 

increased injection rates and pressures. 

The Class VI UIC Program Director will and the Class II UIC Program Director is encouraged to 

evaluate the site-specific factors influencing risks to USDWs at a particular project to support 

appropriate permitting and inform re-permitting decisions. EPA encourages various permitting 

authorities to work across agencies and with owners or operators, as appropriate, to facilitate the 

transfer and evaluation of relevant information about a site and to ensure that all existing data are 

available to the Class VI permit writer. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 31 

4 UIC Requirements for Wells Transitioning from the Class II to 

the Class VI Program

Following a determination that there is an increased risk to USDWs from the injection project 

(see Section 3), owners or operators will need to apply for a Class VI permit. This section 

describes additional Class VI requirements that owners or operators must meet following a 

determination that a Class II ER project will transition to a Class VI GS project. Section 4.1 

briefly describes well construction requirements for Class II ER wells. Section 4.2 presents Class 

VI well construction requirements and identifies considerations that may be appropriate for the 

conversion of Class II wells to Class VI wells. Section 4.3 describes the operating-phase 

requirements that owners or operators must meet under a Class VI permit. Finally, Section 4.4 

discusses how owners or operators following the individual well permitting requirements for 

Class VI wells can achieve some of the efficiencies of area permits that are allowed under some 

other UIC well classes.

4.1 Class II ER Well Construction and Corrosion 

Owners or operators may drill Class II carbon dioxide injection wells as new wells, but it is very 

common to convert existing production or water injection wells into carbon dioxide injection 

wells. Carbon dioxide injection wells used for ER are constructed to meet the UIC Class II 

requirements, with a surface casing and production casing. Casing thicknesses are selected based 

on injection and production pressures, well depth and reservoir properties. Casings are usually 

constructed with carbon steel, and in deep (greater than 10,000 feet) high-pressure, hightemperature environments; high strength grades of well casing may be used. Corrosion resistant 

alloys are also used when necessary (Meyer, 2007). 

When carbon dioxide is mixed with water or impurities (e.g., nitrogen oxides, sulfur oxides, 

hydrogen sulfide), it can be corrosive to well materials and cements commonly used in well 

construction. Cements with a reduced Portland cement content are more resistant to corrosion 

caused by acids, such as carbonic acid, because they contain less calcium carbonate. Acid 

resistant cements can be formulated by adding fly ash, silica fume (microsilica), latex, epoxy or 

other substances. Limited results of field studies at EOR production fields (e.g., Carey et al., 

2007) show clear evidence of reactions between carbon dioxide and well cement. However, both 

laboratory research (e.g., Kutchko et al., 2007, 2009) and field studies suggest that wet carbon 

dioxide-induced alteration of cement does not necessarily result in degradation to the point 

where cement strength and permeability are substantially affected (Kutchko et al., 2007; Crow et 

al., 2009). 

4.2 Meeting the Well Construction and Logging Requirements for Class VI Wells 

In recognition that some Class II ER wells may have been built to Class VI standards or their 

equivalent, the Class VI Rule allows, on a case by case basis, grandfathering of components of 

previously permitted Class II wells at the discretion of the UIC Program Director [40 CFR 

146.81(c)]. Some Class II ER wells are built according to specifications appropriate for the 

injection of carbon dioxide for ER; in some cases, the wells may have been constructed in a 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 32 

manner to maintain MI when in contact with carbon dioxide for the purpose of GS. However, the 

UIC Program Director may determine that, based on construction specifications, the well has not 

been designed to maintain integrity for GS operations. For example, GS operations may employ 

greater injection pressures than ER operations. 

The Class VI Rule describes the requirements for owners or operators seeking to re-permit 

existing Class II wells to Class VI wells for the purpose of GS at 40 CFR 146.81(c). Owners or 

operators planning to convert existing Class II wells to Class VI wells must, per 40 CFR 

146.81(c), demonstrate to the Class VI UIC Program Director that the wells were engineered and 

constructed to meet the requirements at 40 CFR 146.86(a). The owner or operator must also 

demonstrate that the wells will ensure protection of USDWs in lieu of the requirements for 

casing and cementing of Class VI wells at 40 CFR 146.86(b) and the requirements for logging, 

sampling and testing prior to injection well operation at 40 CFR 146.87(a). For further 

information on well construction to meet these Class VI requirements, see the UIC Program 

Class VI Well Construction Guidance. If an owner or operator seeking to grandfather an existing 

Class II well to a Class VI well cannot make this demonstration, then re-permitting of the 

constructed well will not be allowed. The owner or operator may discuss with the Class VI UIC 

Program Director whether remedial activities will enable the well to meet Class VI requirements 

or if construction of a new Class VI well or selection of an alternative well for conversion is 

needed.

It is important to note that although the Class VI Rule provides for “grandfathering” the 

construction of Class II wells, Class II owners or operators transitioning to Class VI wells will 

need to apply for and obtain a Class VI permit in order to continue safe, appropriately permitted 

carbon dioxide injection [40 CFR 146.82(a)]. The sections below (4.2.1 and 4.2.2) focus on the 

requirements from 40 CFR 146.86 through 146.87, differentiating between the requirements that 

must be met by owners or operators of transitioning wells (40 CFR 146.86(a) and (c) and 40 

CFR 146.87(b) through (f)) and recommendations for consideration when transitioning (related 

to 40 CFR 146.86(b) and 146.87(a)). For additional information on the Class VI requirements, 

see the UIC Program Class VI Well Site Characterization Guidance, the UIC Program Class VI 

Well Area of Review Evaluation and Corrective Action Guidance; and the UIC Program Class 

VI Well Construction Guidance. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 33 

4.2.1 Construction and Logging Requirements and Considerations for Wells 

Transitioning from Class II to Class VI 

Owners or operators seeking to transition their wells 

from Class II to Class VI do not necessarily have to 

meet all the requirements for construction and 

logging as required at 40 CFR 146.86 and 146.87. 

Instead, they are required to meet a performance 

standard, demonstrating a well is adequately 

constructed to prevent endangerment of USDWs in 

lieu of specific requirements for well casing, 

cementing and logging. Only well construction can 

be “grandfathered;” owners or operators of wells 

transitioning from Class II to Class VI must meet all 

other requirements of the Class VI Rule. 

The following list briefly describes the Class VI 

requirements and how they apply to wells 

transitioning from Class II to Class VI or may be 

considered in re-permitting determinations: 

• Requirement: Class VI wells must be 

constructed to prevent fluid movement into 

or between USDWs or any other 

unauthorized zones (e.g., no fluid movement 

outside the injection zone) [40 CFR 

146.86(a)(1)]. This is the central construction 

requirement for Class VI wells and is the 

performance standard all wells transitioning 

to Class VI must meet. Class II wells that 

cannot meet this requirement cannot be repermitted as Class VI wells. 

• Requirement: Class VI wells must be 

constructed to allow all appropriate workover 

and testing equipment [40 CFR 146.86(a)(2)] 

and to allow monitoring of the annulus 

between the long string casing and the 

injection tubing [40 CFR 146.86(a)(3)]. The box to the right presents examples of 

equipment that may need to be used to satisfy Class VI requirements. All wells 

transitioning to Class VI must meet these requirements [40 CFR 146.86(a)]. 

CLASS VI WELL EQUIPMENT

Caliper Tools – Used for casing inspection.

Sonic Logging Tools – Used for cement 

testing.

Temperature and Pressure Sensors – Used 

for mechanical integrity tests and formation 

monitoring.

Seismic Imagers – Used for tracking the 

carbon dioxide plume.

Bridge Plugs or Portable Packers – Used to 

seal off portions of the well for pressure 

tests or repair work.

Radioactive Tracer Tools – Used for 

mechanical integrity tests.

Noise Logging Tools – Used for 

mechanical integrity tests.

Down-hole Fluid Samplers – Used for 

geochemical sampling.

Electromagnetic Survey Logger – Used for 

casing inspection.

Down-hole Cameras – Used for inspection 

of the well.

Ultrasonic Imaging Tools – Used for casing 

and cement inspection.

Gravimeters – Used for plume tracking.

Down-hole Safety Valves – Used to replace 

failed tubing deployed valves or to 

temporarily seal off the well.

• Requirement: Class VI wells must inject through tubing and a packer [40 CFR 

146.86(c)(2)] that are designed to be compatible with fluids they will contact or exceed 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 34

standards developed for such materials such as those developed by the American 

Petroleum Institute (API) or American Society for Testing and Materials (ASTM) [40 

CFR 146.86(c)(1)]. Wells transitioning to Class VI must meet this requirement. 

• Requirement: Class VI owners or operators must submit a report on whole or sidewall 

cores [40 CFR 146.87(b)]; record fluid temperature, pH, conductivity, reservoir pressure 

and static fluid level of the injection zone(s) [40 CFR 146.87(c)]; calculate the fracture 

pressure and other physical and chemical characteristics of the confining zone and 

injection zone [40 CFR 146.87(d)]; and conduct a pressure fall-off test; and a pump test 

or an injectivity test [40 CFR 146.87(e)]. All Class VI wells including those transitioning 

from Class II must meet this requirement, and previously conducted monitoring tests, 

while informative for historical comparison, may not be sufficient to satisfy Class VI 

permitting requirements. The owner or operator and the Class VI UIC Program Director 

should discuss the need for updating any of these tests as part of the discussions related to 

the Class VI permit application.

• Consideration: Class II wells transitioning to Class VI that have casing and cement that 

are appropriate for carbon dioxide injection and that will prevent endangerment of 

USDWs may be grandfathered. When assessing this, the Class VI UIC Program Directors 

may give consideration to: whether the wells have casing and cement that are compatible 

with the fluids and materials with which they will come into contact and are designed for 

the life of the well [similar to the requirements for new wells at 40 CFR 146.86(b)(1) and 

(5)]; the depth of the surface casing and how it is cemented to ensure protection of 

USDWs [as in 40 CFR 146.86(b)(2)]; and the depth of the long string casing and how it 

is cemented to ensure protection of USDWs [similar to 40 CFR 146.86(b)(3)]. 

• Consideration: Permit applicants for newly proposed but not yet constructed Class VI 

wells must perform comprehensive logging and testing to verify well construction and 

demonstrate MI of the well. Such logs and tests include: deviation checks on all wells 

constructed by enlarging a hole [40 CFR 146.87(a)(1)]; resistivity, spontaneous potential, 

caliper and cement bond logs before the well’s surface casing is completed [40 CFR 

146.87(a)(2)]; and resistivity, spontaneous potential, porosity, caliper, gamma ray, 

fracture finder log, cement bond and variable density log, and a temperature log before 

and upon completion of the well’s long string casing [40 CFR 146.87(a)(3)]. Class VI 

owners or operators must also perform both internal and external MITs [40 CFR 

146.87(a)(4)]. 

In lieu of the owner or operator of a well that is applying to transition from Class II to 

Class VI performing the tests outlined at 40 CFR 146.87(a) for the purpose of repermitting, EPA anticipates that the Class VI UIC Program Director may evaluate 

previous logs and tests run on the (Class II) well to determine that the well was 

constructed to achieve the goals of 40 CFR 146.86(a), has sufficient integrity to prevent 

fluid movement and that the formation is adequate to accept and contain carbon dioxide 

at the rate and volume anticipated to be injected at the GS project. If such information is 

not available to inform the Class VI UIC Program Director’s decision, it is within his or 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 35

her authority to request additional information to inform a final decision on whether repermitting is appropriate. 

4.2.2 Considerations for Demonstrating that Transitioning from a Class II to a Class 

VI Injection Well is Appropriate

To successfully re-permit a Class II well as a Class VI well, the key requirement regarding 

construction is to demonstrate to the Class VI UIC Program Director that the well, as constructed 

and completed, will prevent fluid movement into or between USDWs or into any unauthorized 

zones pursuant to requirements at 40 CFR 146.86(a)(1) under the conditions anticipated for GS. 

Specifically, an owner or operator will need to demonstrate that the well materials and cements 

will be able to withstand the down-hole operating conditions that are anticipated following 

transition to GS without developing leaks. Considerations for this demonstration include the 

potentially corrosive nature the carbon dioxide stream, formation fluids, or carbon dioxide-brine 

mixtures. Additionally, injection pressures may be higher for a GS project than for an ER 

project, and the owner or operator will need to demonstrate that the materials have adequate 

strength to withstand these elevated pressures. If the Class II well was constructed for injection 

of carbon dioxide for ER purposes, it may be sufficient to demonstrate to the Class VI UIC 

Program Director that such suitable materials were used and that these materials have not 

degraded as a result of past operations.

This will likely involve an ongoing discussion between the owner or operator and the Class VI 

UIC Program Director throughout the re-permitting process regarding applicable requirements. 

This section discusses requirements and considerations related to injection wells; for information 

pertaining to the construction of monitoring wells, see the UIC Program Class VI Well Testing 

and Monitoring Guidance.

The sections below present considerations that may aid an owner or operator in demonstrating to 

a Class VI UIC Program Director that a well is adequately constructed to prevent fluid 

movement. Essentially, in order to demonstrate that the construction is adequate, the owner or 

operator must demonstrate that the well has both internal and external MI and will be able to 

maintain MI throughout the life of the project to meet the requirements of 40 CFR 146.81(c). 

Materials Strength 

The owner or operator and the Class VI UIC Program Director will need to consider well 

material strength when evaluating the information submitted in compliance with requirements at 

40 CFR 146.86(c)(3). Additionally, the Class VI UIC Program Director, in confirming that the 

well is appropriately engineered and constructed to meet the requirements of 40 CFR 146.81(c),

will likely also consider the cement and casing material strength. 

The owner or operator can demonstrate adequate materials strength by providing computations 

showing calculated down-hole stresses on the casing, tubing, cement and packer. These 

calculated values can be compared with strength values for the materials in place. The strength of 

the materials used in the well construction will most likely have been submitted with the original 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 36

Class II permit application; although, the current condition of the well materials will be a more 

relevant consideration. A current pressure test at a pressure equal to or higher than the proposed 

injection pressure may help demonstrate sufficient material strength. If the records are missing 

from the original permit files, the Class VI UIC Program Director may request that they be 

resubmitted. 

The owner or operator can demonstrate that the well materials can maintain MI and are 

compatible with the carbon dioxide stream through direct testing of the materials with the 

proposed carbon dioxide stream or through detailed materials compatibility assessments using 

published literature showing that the materials will not corrode significantly in the presence of 

the carbon dioxide stream or carbon dioxide-rich brine. The UIC Program Class VI Well 

Construction Guidance has additional information and resources for determining the stress on

well components. 

Casing

While an owner or operator of a Class II well applying to transition to a Class VI well need not 

comply with the requirements at 40 CFR 146.86(b) as per 40 CFR 146.81(c), EPA encourages 

owners or operators to consider—and anticipates that Class VI UIC Program Directors will 

carefully evaluate—the placement of casing and materials of a well proposed for conversion. 

Such an assessment may include evaluating whether the casing is intact and the zones through 

which it is completed. When an owner or operator is selecting a Class II well for re-permitting as 

a Class VI well, the owner or operator may consider selecting a well where the long string casing 

extends to the top of the injection zone as such a well design provides optimal protection across 

multiple subsurface formations. Construction plans for the well (whether from the original Class 

II well permit application or more recent plans) showing the current design of the well may be 

referenced to provide the details of casing placement and demonstrate that the well is 

constructed to meet the requirements of 40 CFR 146.86(a). The casing diameter must be 

sufficiently large to permit any testing or logging equipment required by the Testing and 

Monitoring Plan and any workover equipment that might be anticipated [40 CFR 146.86(a)(2)]. 

The owner or operator will need to demonstrate that the casing has not corroded or been 

damaged to the extent that it cannot meet the requirements at 40 CFR 146.86 or can no longer 

maintain MI. Such a demonstration may be achieved by MITs and/or wireline logs and is 

discussed in more detail in the section on logging and testing below. 

Cement

Cement is essential for providing external MI by helping to prevent fluid migration along the 

well bore annulus. Part of the owner or operator’s demonstration that a well being considered for 

conversion to Class VI is constructed and completed to meet the requirements at 40 CFR 

146.86(a) includes an assessment of the appropriateness of the cement placement, type, 

compatibility and integrity. 

While newly constructed Class VI wells must be cemented to the surface [40 CFR 146.86(b)], 

there is some flexibility afforded owners or operators applying to re-permit existing Class II 

wells as Class VI wells. Specifically, wells re-permitted to Class VI may not need to meet the 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 37

requirement that their long string casing be cemented to the surface. Under such circumstances, 

EPA anticipates that the Class VI UIC Program Director would require the owner or operator to 

demonstrate that there is proper zonal isolation. In all cases, however, re-permitting is contingent 

upon a demonstration that the well meets the requirements at 40 CFR 146.86(a) to prevent the 

movement of fluids into or between USDWs or into any unauthorized zones. Cement logs can be 

used to show placement of the cement with respect to USDWs and other permeable formations 

and cement logs complemented by other MI logs can identify the position and integrity of well 

cement.

The UIC Program Director may evaluate whether a well has cement in the following locations: 

from the injection zone up through and to some distance above the base of the confining layer 

(some states require 500 feet for Class II wells); through any overpressured zones (zones that are 

overpressured relative to the normal geologic pressure gradient); and through any USDW. When 

identifying and selecting a well for transitioning to Class VI, the owner or operator may also 

consider whether the well was cemented through any active oil or gas formations and between 

permeable formations where pressure differences could cause fluid movement. Cementing in 

these zones is consistent with industry best operating practices.

The owner or operator should also provide information to the Class VI UIC Program Director to 

inform his or her assessment of the proposed well’s integrity. External MITs and logs (as 

discussed in the logging and testing section) can indicate cement integrity. If external MITs 

indicate channels or microannuli in the cement (i.e., flow behind pipe), an owner or operator may 

be able to repair them using cement squeezes. The UIC Program Class VI Well Area of Review 

Evaluation and Corrective Action Guidance includes details relevant to repairing faulty cement. 

(Note that, although well condition and remediation discussions in that guidance focus on 

abandoned wells, they are applicable to re-permitted wells.)

Tubing and Packer

Injection must occur through tubing and a packer to prevent migration of carbon dioxide up the 

annulus between the tubing and casing [40 CFR 146.86(c)(2)]. The tubing and packer should 

meet the material requirements discussed above and should be pressure tested prior to operation 

to the maximum injection pressures expected during the lifetime of the GS project. If the existing 

tubing and packer are missing or inadequate, they would need to be replaced. The tubing must 

also be installed in such a way that the annulus between the tubing and casing can be monitored 

[40 CFR 146.86(a)(3)]. The UIC Program Class VI Well Testing and Monitoring Guidance

provides more details on how to monitor the annular space between the tubing and casing. 

Logging, Sampling and Testing 

For owners or operators applying to convert a Class II well to Class VI, the logging, sampling 

and testing requirements at 40 CFR 146.87(a) are not required, per 40 CFR 146.81(c), provided 

the owner or operator demonstrates to the Class VI UIC Program Director’s satisfaction that the 

well is engineered and constructed to meet the requirements at 40 CFR 146.86(a). However, an 

owner or operator must meet the requirements of 40 CFR 146.87(b) through (f). The purpose of 

the suite of requirements at 40 CFR 146.87 is to ensure that sufficient information regarding both 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 38

the well and (geologic) formations the well intersects is available to the Class VI UIC Program 

Director to enable him/her to establish operational conditions, confirm USDW protection and 

authorize injection. 

To ensure that such information is available to inform a Class VI UIC Program Director’s 

evaluation of a well for re-permitting, EPA recommends that the owner or operator conduct and 

submit the results of internal and external MITs. However, the owner or operator and the UIC 

Program Director should discuss what logs and tests may need to be performed to ensure that the

transitioned well was engineered and constructed to meet the requirements at 40 CFR 146.86(a).

• Tests or logs to demonstrate internal MI – Although specific tests are not required for 

wells transitioning from Class II to Class VI, the owner or operator must demonstrate to 

the UIC Program Director that the well is designed to prevent fluid movement into 

USDWs in order to meet the requirements of 40 CFR 146.81(c). If recent mechanical 

integrity test results are available for a transitioning well, the Class VI UIC Program 

Director may choose to review them as evidence that the well has internal MI. Otherwise, 

the owner or operator may consider performing a caliper log, casing inspection log, or 

video log in order to demonstrate that the casing is intact. Options for demonstrating 

internal MI can include standard annulus pressure tests, ultrasonic imaging logs and 

tracer surveys.

• Tests or logs demonstrating external MI – As with internal MITs, specific external MI 

tests are not required for wells transitioning from Class II to Class VI, but the owner or 

operator must demonstrate to the UIC Program Director that the well is designed to 

prevent fluid movement into USDWs in order to meet the requirements of 40 CFR 

146.81(c). If recent mechanical integrity test results are available for a transitioning well

the Class VI UIC Program Director may choose to review them as evidence that the well 

has external MI. Temperature logs, oxygen activation logs and noise logs may aid in 

identifying any channeling in the cement. If channels or microannuli are detected through 

logging, drilling out the well and recementing may be necessary. Alternatively the UIC 

Program Director may determine that the well is not suitable for re-permitting. 

• Other logging and testing activities – An owner or operator applying to repermit a well as 

a Class VI well must comply with all requirements at 40 CFR 146.87(b) through (f). 

Information on complying with these requirements and discussions on the advantages and 

considerations for various logs and test can be found in the UIC Program Class VI Well 

Testing and Monitoring Guidance. Additionally, it should be noted that, in the event that 

an owner or operator conducts any logging or testing requested by the Class VI UIC 

Program Director to support re-permitting of a well, the owner or operator must provide 

the Class VI UIC Program Director with the opportunity to witness any such logging and 

testing [40 CFR 146.87(f)]. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 39

4.3 Non-Construction Related Permit Requirements

Following transition to Class VI, owners or operators will need to meet the requirements in the 

Class VI Rule throughout the lifetime of the GS project. While some required activities may 

have been included in a Class II permit, others are unique or more specific. The following 

sections describe the requirements that owners or operators must meet under a Class VI permit 

and how they may differ from the requirements of a Class II permit. See Appendix I for a 

detailed comparison of the Class II and Class VI requirements.

4.3.1 Injection Well Operation

Owners or operators of Class VI wells must comply with injection well operating requirements 

that are more comprehensive than those required under Class II permits. The Class VI Rule 

contains requirements at 40 CFR 146.88 for injection pressure limitations, use of automatic shutoff systems and annulus pressure requirements. These requirements are intended to ensure that 

injection of carbon dioxide does not endanger USDWs. Down-hole shutoff devices are required 

for offshore wells and may be required for onshore wells at the discretion of the Class VI UIC 

Program Director [40 CFR 146.88(e)(2)]. 

While all owners or operators must limit injection pressure such that injection may not initiate 

new fractures or propagate existing fractures, Class VI well owners or operators must meet the 

requirement that the injection pressure does not exceed 90 percent of the fracture pressure of the 

injection zone, except during stimulation [40 CFR 146.88(a)]. Because Class II permits might 

not contain conditions that reflect this requirement, owners or operators will need to be aware of 

this Class VI requirement and ensure that information needed to calculate fracture pressure and 

an appropriate injection pressure is incorporated into the Class VI permit application. It may be 

necessary to adjust injection operations accordingly following transition. 

Class II well owners or operators are not universally required to install continuous recording 

devices, alarms and automatic shut-off systems or other safety devices (although such practices 

may be considered best practices to ensure mitigation of any potential well component or 

operational problems). The Class VI Rule requires the installation and use of alarms and 

automatic surface shut-off systems for onshore injection wells and, at the discretion of the Class 

VI UIC Program Director, down-hole shut off systems may also be required [40 CFR 

146.88(e)(2)]. For offshore Class VI injection wells located within state territorial waters, alarms 

and automatic down-hole shut-off systems are required [40 CFR 146.88(e)(3)]. Although surface 

shut-off systems are not required for offshore wells, EPA recommends they be installed in 

addition to the required down-hole systems. Surface safety valves can be beneficial to protect 

against failures above the downhole valve and to provide a second barrier against loss of well 

control.

The owner or operator should provide information about what devices, if any, were previously 

installed on the well. Because the Class II well may be constructed without these devices, the 

Class VI UIC Program Director should consider whether the addition of these devices will 

interfere with well testing and monitoring required at 40 CFR 146.86(a)(2) and (3). If appropriate 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 40

retrofits to install the required equipment cannot be made or if they would interfere with 

operation of the well in a manner required under the Class VI regulations, then transition to a 

Class VI well is not an option.

Owners or operators of Class VI wells are subject to more specific requirements regarding 

maintaining a pressure on the annulus that exceeds the operating injection pressure [40 CFR 

146.88(c)] and maintaining MI of the well [40 CFR 146.88(d)]. Similarly, Class VI well owners 

or operators are subject to specific procedures at 40 CFR 146.88(f)(1-5) if a loss of MI is 

discovered or a shutdown (i.e., down-hole or at the surface) is triggered. While similar 

requirements may have been included as conditions of a Class II permit, owners or operators will 

need to be aware of these more comprehensive Class VI requirements and ensure that they are 

met.

For more information on injection well operation, refer to the UIC Program Class VI 

Implementation Manual for State Directors as well as the UIC Program Class VI Well 

Construction Guidance.

4.3.2 Mechanical Integrity 

The primary differences in the MI testing requirements for Class VI owners or operators relative 

to those for Class II well owners or operators are the need to continuously monitor to 

demonstrate internal MI and the increased frequency of external MITs for Class VI compared to 

Class II. 

Following transition to Class VI, owners or operators must continuously monitor injection 

pressure, flow rate and injected volumes, as well as the annular pressure and fluid volume to 

demonstrate internal MI of their injection wells [40 CFR 146.89(b)]. Although the Class II 

injection wells may have been equipped to monitor these parameters, owners or operators

transitioning to Class VI should ensure that the equipment is appropriate for collecting data in 

the appropriate format for supporting the required reporting of these data in compliance with the 

Class VI regulations. 

Following transition to Class VI, owners or operators must demonstrate external MI of their 

injection wells at least annually; this will likely be an increase from the Class II permit 

conditions, as the federal Class II regulations require either a demonstration of external MI at 

least once every five years [40 CFR 146.23(b)(3)] or documentation of cementing records [40 

CFR 146.8(c)(2)]. Owners or operators of Class VI wells also must demonstrate external MI 

using a tracer survey or a temperature or noise log [40 CFR 146.89(c)(2)]. Following transition 

to Class VI, owners or operators would no longer be able to submit cementing records to 

demonstrate the presence of adequate cement to prevent significant fluid movement into a 

USDW through vertical channels adjacent to the well bore in lieu of conducting external MITs, 

as the Class II regulations allow at 40 CFR 146.8(c)(2).

Owners or operators applying for a Class VI permit must run a casing inspection log if required 

by the UIC Program Director, as specified at 40 CFR 146.89(d). Owners or operators of Class II 

wells should be prepared for this additional possible requirement because both the Class II and 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 41

Class VI regulations allow for flexibility regarding MITs, at the UIC Program Director’s 

discretion [40 CFR 146.8(d); 40 CFR 146.89(g)]. The Class VI UIC Program Director may 

require any other test to evaluate MI. Tests other than those listed in the Class VI Rule may be 

used if allowed by the Class VI UIC Program Director and upon written approval of the 

Administrator.

For more information on MI, refer to the UIC Program Class VI Implementation Manual for 

State Directors, UIC Program Class VI Well Construction Guidance and the UIC Program Class 

VI Well Testing and Monitoring Guidance.

4.3.3 Testing and Monitoring

Owners or operators of Class VI wells must develop and implement a comprehensive Testing 

and Monitoring Plan for their projects that includes injectate monitoring, corrosion monitoring, 

MIT of the well, pressure fall-off testing, ground water quality monitoring, carbon dioxide plume 

and pressure front tracking and, at the Class VI UIC Program Director’s discretion, surface air 

and soil gas monitoring [40 CFR 146.90(h)]. The Testing and Monitoring Plan must also include 

a quality assurance and surveillance plan for all testing and monitoring that is performed [40 

CFR 146.90(k)].

Some Class VI testing and monitoring requirements are unique (e.g., plume tracking), and others 

must be performed at different frequencies than may have been required in the Class II permit. 

Therefore, owners or operators must be aware of these new requirements and ensure that all of 

the required information is included in the Testing and Monitoring Plan submitted with the Class 

VI permit application, per 40 CFR 146.82(a)(15). 

One of the most significant differences in the monitoring requirements is that Class VI well 

owners or operators must track the extent of the carbon dioxide plume and pressure front [40 

CFR 146.90(g)]. For former (Class II) ER projects, the separate-phase carbon dioxide plume may 

include carbon dioxide already present in the injection zone due to previous Class II injection 

activities. The Class VI owner or operator must use direct methods to monitor for pressure 

changes in the injection zone [40 CFR 146.90(g)(1)]. Additionally, indirect methods (e.g., 

seismic, electrical, gravity, or electromagnetic surveys and/or down-hole carbon dioxide 

detection tools) are required to track the separate phase carbon dioxide plume unless the Class VI 

UIC Program Director determines, based on site-specific geology, that such methods are not 

appropriate or feasible [40 CFR 146.90(g)(2)]. In general, the geologic scenarios where ER 

operations occur, i.e., porous rock layers overlain by impermeable formations, domes and 

structural or stratigraphic traps, are amenable to seismic and other geophysical methods. Owners 

or operators are likely to have conducted such surveys of the reservoir and area previously; this 

information may inform development of this aspect of the testing and monitoring regime. It 

should be noted, however, that older 2D seismic data may not be useful as a baseline for plume 

tracking if there is inadequate resolution or if the data collection were not suitable for detection 

of carbon dioxide.

Following transition to Class VI, owners or operators must periodically monitor ground water 

quality and geochemical changes above the confining zone(s), as specified at 40 CFR 146.90(d). 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 42

The number, placement and depth of monitoring wells will be site-specific and based on 

information collected during baseline site characterization. The owner or operator of a Class VI 

well may also be required to conduct surface air and/or soil gas monitoring at the Class VI UIC 

Program Director’s discretion [40 CFR 146.90(h)].

Much of the remaining required testing and monitoring activities may have been included as a 

condition of the Class II permit. However, owners or operators may need to conduct these 

activities at different frequencies following transition to Class VI. For example:

• Continuous monitoring is required for injection pressure, rate and volume; the pressure 

on the annulus between the tubing and the long string casing; and the annulus fluid 

volume added [40 CFR 146.90(b)] and annual external MITs [40 CFR 146.90(e)]. See the 

discussion of MITs for additional considerations;

• Quarterly corrosion monitoring of the well is required at 40 CFR 146.90(c);

• A casing inspection log, if required by the Class VI UIC Program Director, may be 

conducted at a frequency established in the Testing and Monitoring Plan pursuant to 

requirements at 40 CFR 146.89(d); and

• A pressure fall-off test at least once every five years, as specified at 40 CFR 146.90(f).

The owner or operator must review the Testing and Monitoring Plan at least once every five 

years to incorporate operational and monitoring data and the most recent AoR reevaluation [40 

CFR 146.90(j)]. After this review, the owner or operator must submit a demonstration to the 

Class VI UIC Program Director that no amendment is needed. Otherwise, he or she must submit 

an amended Testing and Monitoring Plan to be approved by the Class VI UIC Program Director 

and incorporated into the permit. Amended plans or demonstrations must be submitted to the 

Class VI UIC Program Director within one year of an AoR reevaluation, following significant 

changes to the facility, or when required by the Class VI UIC Program Director.

For more information on testing and monitoring, refer to the UIC Program Class VI Well Testing 

and Monitoring Guidance.

4.3.4 Reporting 

The reporting requirements at Class VI wells are more comprehensive and detailed than the 

annual reports that are typically required for Class II wells. Following transition to Class VI, 

owners or operators must submit project monitoring and operational data at varying intervals, 

including:

• Semi-annual reports of operating data and certain monitoring data [40 CFR 146.91(a)];

• The results of MITs, any other injection well testing required by the Class VI UIC 

Program Director, and any well workovers within 30 days [40 CFR 146.91(b)]; 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 43

• Notification within 24 hours of obtaining any evidence that the injected carbon dioxide 

stream and associated pressure front may cause an endangerment to a USDW, any 

noncompliance with a permit condition, any event that may endanger USDWs, or any 

release of carbon dioxide to the atmosphere or biosphere detected through any required 

surface air and/or soil gas monitoring [40 CFR 146.91(c)]; and 

Notification 30 days prior to any planned well workover, stimulation, or test of the injection well 

[40 CFR 146.91(d)].The most significant change in reporting following the transition to Class VI 

is that owners or operators will need to report to EPA electronically, as required at 40 CFR 

146.91(e). For additional information about reporting, see the UIC Program Class VI

Implementation Manual for State Directors as well as the UIC Program Class VI Well 

Recordkeeping, Reporting, and Data Management Guidance for Owners and Operators.

Owners or operators of Class VI wells must retain most operational monitoring data for 10 years 

after the data are collected and must retain data on the carbon dioxide stream until 10 years after 

site closure, as required under 40 CFR 146.91(f). 

4.3.5 Injection Well Plugging 

In general, the requirements associated with plugging all UIC injection wells are similar. 

However, owners or operators of Class VI wells are subject to more specific requirements at 40 

CFR 146.92 following transition (from Class II to Class VI). These requirements are to ensure 

that the cement and materials used to plug the injection well are compatible with the potentially 

corrosive fluids that result when carbon dioxide mixes with water. The purpose of such 

requirements is to prevent well plugging materials from degrading over time and to help prevent 

the movement of fluids into or between USDWs. Owners or operators of Class VI wells are 

afforded flexibility in selecting plugging materials and methods, provided that the materials are 

suitable for contact with carbon dioxide and carbon dioxide-rich fluids; owners or operators must 

describe these in the Injection Well Plugging Plan [40 CFR 146.92(b)].

Owners or operators of Class VI wells must develop, gain approval of, and follow an Injection 

Well Plugging Plan [40 CFR 146.92(b)]. Although it is likely that Class II an Class VI permits 

include similar requirements for plugging the injection well, the Class VI Rule contains specific 

requirements at 40 CFR 146.92. Specifically, owners or operators must flush the well with a 

buffer fluid, determine bottomhole reservoir pressure, perform a final external MIT and plug the 

well using plugs and cements that are compatible with carbon dioxide and the geochemistry of 

down-hole fluids in the formation.

Owners or operators of Class VI wells must submit a notice of intent to plug at least 60 days 

prior to plugging the well [40 CFR 146.92(c)]. At this time, owners or operators of Class VI 

wells must update the Well Plugging Plan if needed. Following plugging, owners or operators 

must submit a plugging report within 60 days, as specified at 40 CFR 146.92(d). 

For more information on injection well plugging, refer to the UIC Program Class VI 

Implementation Manual for State Directors and the UIC Program Guidance on Class VI Well 

Plugging, Post-Injection Site Care, and Site Closure.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 44

4.3.6 Post-Injection Site Care and Site Closure

The Class VI Rule at 40 CFR 146.93 incorporates an extended PISC, which is unique in the UIC 

Program and not required of other injection well classes. Class VI well owners or operators must 

prepare, gain approval of, and follow a comprehensive PISC and Site Closure Plan [40 CFR 

146.93(a)]. 

Class VI well owners or operators must perform monitoring and site care following cessation of 

injection to show the position of the separate-phase carbon dioxide plume and the associated area 

of elevated pressure [40 CFR 146.93(b)]. This site care, which includes monitoring of ground 

water quality and the position of the carbon dioxide plume and pressure front, must continue for 

a timeframe established in the permit (i.e., the 50-year default or an alternative timeframe 

established by modeling) or until the owner or operator can demonstrate to the UIC Program 

Director, based on site monitoring data, that the project no longer poses a risk of endangerment 

to USDWs. 

The owner or operator of a Class VI well must notify the Class VI UIC Program Director in 

writing at least 120 days prior to site closure and cessation of PISC activities, as specified at 40 

CFR 146.93(d). Any changes to the PISC and Site Closure Plan that have not been previously 

submitted must be submitted at this time. Following the Class VI UIC Program Director’s 

authorization of site closure, the owner or operator must plug all monitoring wells, as specified at 

40 CFR 146.93(e), submit a site closure report within 90 days, as specified at 40 CFR 146.93(f), 

and record a notation on the deed to the facility property or any other document that is normally 

examined during title search, as specified at 40 CFR 146.93(g).

For more information on PISC and site closure, refer to the UIC Program Guidance on Class VI 

Well Plugging, Post-Injection Site Care, and Site Closure.

4.3.7 Emergency and Remedial Response

Requirements for emergency and remedial response are unique for owners or operators of Class 

VI wells. Class VI well owners or operators must develop, gain approval of, and follow a 

comprehensive Emergency and Remedial Response Plan that describes actions to be taken to 

address events that may cause endangerment to a USDW during the construction, operation and 

PISC periods of a GS project, as required by 40 CFR 146.94. 

Owners or operators of Class VI wells are provided flexibility to design a site-specific plan that 

meets the requirements of 40 CFR 146.94(a). If an owner or operator obtains evidence of 

endangerment to a USDW, he or she must: (1) immediately cease injection; (2) take steps to 

identify and characterize any release; (3) notify the Class VI UIC Program Director within 24 

hours; and (4) implement the approved Emergency and Remedial Response Plan [40 CFR 

146.94(b)]. Class VI owners or operators must also update the Emergency and Remedial 

Response Plan if needed following every AoR reevaluation or other significant change to the 

project (a minimum of at least once every 5 years) [40 CFR 146.94(d)].
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 45

Details on how to prepare an Emergency and Remedial Response Plan are included in Section 6 

of the UIC Program Class VI Well Project Plan Development Guidance.

4.4 Area Permits 

Class II wells may be permitted on a field-basis through the use of an area permit. The use of 

area permits, however, is not an option for the permitting of Class VI wells, and owners or 

operators of Class II wells that are seeking to obtain Class VI permits must seek an individual 

permit for each well [40 CFR 144.33(a)(5)].

Permitting Class VI wells on an individual basis will help to more closely ensure that every well 

is constructed, operated, monitored, plugged and closed in a manner that is protective of USDWs 

and that the review is at an appropriate level of detail. Importantly, requiring separate permits for 

each well will ensure that the public has an opportunity to provide input on each well in the field 

as it is constructed or brought online. For example, while permitting authorities may be able to 

seek comment on several wells in an area at once, soliciting comment/input on each well will 

ensure that the public is aware of the number of wells in the area and has an opportunity to 

comment on each.

Owners or operators of Class II wells that were permitted under area permits before transitioning 

to Class VI may achieve efficiencies by considering the common elements and information about 

each well as they transition to operating under a Class VI permit. Considering all wells in a field 

will ensure that the site is evaluated and operated in a holistic manner and that all aspects of the 

project that may impact USDWs have been evaluated. For example: 

• Class VI well owners or operators can perform a single modeling exercise to accomplish 

the AoR delineations and AoR reevaluations for several wells to meet the requirements of 

40 CFR 146.84. The computational AoR modeling should account for all anticipated 

injection and resultant pressure changes caused by each well in a depleting/former oil and 

gas field, including any wells that the owner or operator anticipates bringing online in the 

future;

• While each well in a GS project will be subject to MITs and corrosion monitoring (per 40 

CFR 146.89 and 40 CFR 146.90), owners or operators may work with the permitting 

authority to align testing schedules in the permits for each well so that the owner or 

operator can arrange to have equipment and contractors on site for all required testing at 

the same time;

• Some required testing and monitoring may be performed to satisfy the conditions of 

several permits at once. For example, owners or operators may wish to conduct ground 

water monitoring or carbon dioxide plume and pressure front tracking over an area that 

would satisfy the testing and monitoring requirements for several Class VI permits and 

that would meet the requirements of 40 CFR 146.90(d) and (g). This approach should be 

described in the Testing and Monitoring Plan, approved by the Class VI UIC Program 

Director, and included in each permit;
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 46

• Owners or operators will need to report the results of all required testing and monitoring 

for each well individually, as required at 40 CFR 146.91 (even if this means submitting 

multiple copies of the same report). However, EPA expects that electronic reporting will 

mitigate the burden associated with any duplication. For additional information about 

reporting, see the UIC Program Class VI Well Recordkeeping, Reporting, and Data 

Management Guidance for Owners and Operators;

• If several wells in a field have similar construction, owners or operators may plan to plug 

each well in a similar manner; however, a separate Injection Well Plugging Plan is 

required for each well (i.e., tailored to its depth), as required at 40 CFR 146.93. The plan 

must be a condition of each injection well’s permit; and

• As with operational-phase testing and monitoring, as owners or operators cease injection, 

they may consider implementing a post-injection ground water monitoring or separatephase carbon dioxide plume and pressure front tracking regime that satisfies the PISC

and Site Closure Plans of several permits simultaneously and meets the requirements of 

40 CFR 146.94.

The owner or operator should discuss the commonalities among all wells in a field and the 

implications of combining common elements and activities associated with multiple 

wells/permits with the Class VI UIC Program Director, while ensuring that every well is 

constructed, operated, monitored, plugged and closed in a manner that is protective of USDWs.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 47

5 Transitioning Wells and Aquifer Exemptions

The UIC Program regulations include criteria at 40 CFR 146.4 that allow for exemption of 

aquifers from SDWA protection under specific circumstances. To be exempted, an aquifer 

cannot currently serve as a source of drinking water [40 CFR 146.4(a)] and will not serve as a 

source of drinking water due to any of the factors specified at 40 CFR 146.4(b), e.g., that it is 

mineral, hydrocarbon or geothermal energy producing or is situated at a depth or location which 

makes recovery of water for drinking water purposes economically or technologically 

impractical. Aquifers may also be exempted if they have a total dissolved solids (TDS) content 

that is greater than 3,000 mg/L and less than 10,000 mg/L and are not reasonably expected to 

supply a public water system [40 CFR 146.4(c)]. However, even if an aquifer meets the criteria 

in 40 CFR 146.4, EPA may disapprove an exemption if other health, safety, or water availability 

concerns exist. Aquifer exemptions associated with oil- and gas-related injection (Class II 

activities) typically extend a quarter to one half-mile from the well bore.

The Class VI Rule amended 40 CFR 146.4 to add criteria at 40 CFR 146.4(d) for expanding the 

areal extent of an existing aquifer exemption for a Class II well that is being transitioned to a 

Class VI well (see Section 5.1). The Class VI Rule requires that aquifer exemption expansion 

requests be treated as substantial revisions to a state’s primacy program under 40 CFR 145.32 

and must therefore be signed by the EPA Administrator (see Section 5.3 for additional 

information about the EPA review and approval process).

The Class VI Rule precludes the issuance of new aquifer exemptions for GS projects. However, 

the Class VI Rule does allow for the expansion of the areal extent of existing aquifer exemptions 

where an aquifer exemption was previously issued for a Class II ER operation. This offers some 

flexibility in selection of GS sites and provides a mechanism for ER operations injecting into 

exempted aquifers to expand the exemption and continue injecting if their well is re-permitted as 

a Class VI well for the purpose of GS. Such exemptions must meet the criteria at 40 CFR 144.7 

and 40 CFR 146.4(d).

5.1 Aquifer Exemptions and GS Projects

Owners or operators who wish to transition their Class II ER wells to Class VI wells can request 

that EPA expand the areal extent of an existing aquifer exemption associated with the Class II 

well [40 CFR 144.7(d)]. Following approval of the expansion of the areal extent of an aquifer 

exemption, the owner or operator must meet all of the requirements for Class VI wells. 

Expansion of the areal extent of an aquifer exemption is an option limited under 40 CFR 146.4 to 

Class II projects injecting into exempted aquifers and that are transitioning from Class II to Class 

VI; however, in no other circumstances are aquifer exemptions permissible for Class VI wells. In 

no cases will injection into non-exempted USDWs or any injection that endangers USDWs be 

permitted [40 CFR 146.86(a)]. Furthermore, if the previously exempted aquifer/injection zone is 

above or between USDWs, the owner or operator must apply for an injection depth waiver in 

addition to the application for an aquifer exemption expansion (see the requirements for injection 

depth waivers at 40 CFR 146.95) as these requirements address unique and independent USDW 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 48

protection requirements. For additional information on applying for injection depth waivers, see 

the UIC Program Class VI Well Injection Depth Waivers Guidance.

5.2 Applying to Expand the Areal Extent of an Aquifer Exemption 

To continue injecting for the purpose of GS into an aquifer that has been exempted for ER, an 

owner or operator will need to apply to expand the areal extent of the aquifer exemption. In 

addition to defining the areal limits of the expanded aquifer exemption per 40 CFR 144.7(d)(1), 

an owner or operator must submit information to support a determination that the proposed 

exemption meets the criteria at 40 CFR 146.4(d). 

The paragraphs below present information and recommendations for how applicants can submit 

information to demonstrate that the proposed aquifer exemption expansion meets the 

requirements at 40 CFR 146.4(d), including meeting the requirements for applying to expand the 

areal extent of an existing aquifer exemption (per 40 CFR 144.7(d)(1)) and supporting an 

evaluation of the request (per 40 CFR 144.7(d)(2)). Many types of information are recommended 

in these sections; however EPA anticipates that much of this information would be generated or 

collected as part of the site characterization or Class VI permit application process.

Defining the New Limits of the Aquifer Exemption per 40 CFR 144.7(d)

In the request to expand the areal extent of an existing aquifer exemption, the owner or operator 

must, per 40 CFR 144.7(d)(1), define and describe, in geographic and/or geometric terms that are 

clear and definite, all aquifers or parts of aquifers that are to be designated as exempted using the 

criteria at 40 CFR 146.4(d). Because of the potentially larger volumes of carbon dioxide to be 

injected for a Class VI GS project and the fact that there will be no associated production of the 

carbon dioxide to reduce pressures in the injection formation, it is likely that the areal extent of a 

Class VI aquifer exemption will need to be larger than the existing Class II aquifer exemption. 

The areal extent of a Class VI aquifer exemption expansion should be based upon the predicted 

extent of the injected carbon dioxide plume and any mobilized fluids that may result in 

degradation of water quality over the lifetime of the project [40 CFR 144.7(d)(2)(ii)]. To ensure 

that all areas potentially impacted by the injection activity are exempted, EPA recommends that 

the delineation be informed by the computational modeling performed for the AoR determination 

required at 40 CFR 146.84(c)(1), and that owners or operators perform modeling prior to 

requesting an expansion of the areal extent of an existing aquifer exemption and request the 

exemption of an area that is at least as expansive as the maximum extent of the carbon dioxide 

plume and pressure front over the life of the project. 

Importantly, determination of the expanded exemption area should take into account the 

migration of the dissolved carbon dioxide plume and all associated fluids that may degrade water 

quality. See 40 CFR 144.6(d)(2). Such fluids may extend beyond the separate-phase plume and 

pressure front. Thus, the new area of the requested aquifer exemption expansion may be larger 

than the AoR for the Class VI well. 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 49

To define and describe the area of the expanded aquifer exemption in terms that are clear and 

definite and support the UIC Program Director’s evaluation of the request at 40 CFR 144.6(d)(2), 

EPA recommends that owners or operators provide a narrative description, maps, illustrations, or 

other information, including: 

• Regional and local maps showing the areal extent of the current aquifer exemption and 

the area of the requested expansion. Maps may be submitted specifically for the aquifer 

exemption, or narrative may be provided that references a highlighted area on maps 

provided as part of the overall permit application required at 40 CFR 146.82. Maps 

should show the desired lateral limits of the aquifer exemption expansion; 

• Perpendicular cross sections to demonstrate the stratigraphic and structural characteristics 

of the aquifer in the region of the expansion. Cross sections may be used to illustrate the 

thickness of the aquifer in the area of the aquifer exemption; and 

• A discussion of any structures or other features that differ between the original aquifer 

exemption area and the requested expansion area. 

The owner or operator may provide a synopsis of the results of the computational modeling 

conducted to support the AoR delineation required at 40 CFR 146.84(c)(1), including a map 

showing the anticipated AoR and the requested aquifer exemption expansion area. 

The owner or operator should bear in mind that, due to the nature of GS operations, it is EPA’s 

intention that only one aquifer exemption expansion should be granted for a GS project—at the 

time that the Class VI permit application is submitted. Thus, an owner or operator should not 

plan to continually expand an aquifer exemption for a Class VI operation and instead should use 

conservative assumptions in the computational modeling and define an area for the expanded 

aquifer exemption that is sufficiently large to account for possible changes to the computational 

model that may arise during AoR reevaluations over the life of the GS project. 

In identifying the expanded aquifer exemption area, the owner or operator should make use of all 

relevant information gathered and used to support site characterization and AoR delineation. 

EPA strongly recommends that the owner or operator take into account uncertainties in data 

inputs for the model and model parameters and consider the upper and lower limits of the AoR 

predictions. Sensitivity analyses performed as part of the AoR modeling effort will likely 

indicate a range of predictions that will help owners or operators understand which parameters 

most strongly influence model predictions. Understanding these sources of uncertainty may help 

in determining how to accommodate future AoR model estimates in the requested aquifer 

exemption expansion.

The potential role of geologic features should be considered. For example, data for facies 

analysis provided as part of the site characterization information required at 40 CFR 

146.82(a)(3)(iii) may indicate preferential flow paths that could affect transport of separate-phase 

carbon dioxide. Certain types of structural traps might be expected to limit separate-phase plume 

and fluid movement and could function as reasonable boundaries to the exempted area under 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 50

permitted operating conditions. Such geologic features will have been incorporated into the 

conceptual model developed for AoR delineation; awareness of the site conceptual model may 

help in anticipating where the greatest uncertainties lie and how the AoR and fluid migration 

might change over time. Further information on AoR determination is provided in the UIC 

Program Class VI Well Area of Review Evaluation and Corrective Action Guidance.

Informing a Determination that the Proposed Exemption Meets the Criteria at 40 CFR 

146.4(d)

An owner or operator seeking to expand the areal extent of an existing aquifer exemption should 

submit information to support a determination that the proposed area of the expanded aquifer 

exemption meets all of the following criteria at 40 CFR 146.4(d):

• It does not currently serve as a source of drinking water;

• The TDS content of the ground water is more than 3,000 mg/L and less than 10,000 

mg/L; and

• It is not reasonably expected to supply a public water system.

The sections below provide recommended approaches for how the owner or operator can 

compile the information necessary to support a determination that an expansion of the areal 

extent of an aquifer exemption is appropriate. 

Not Currently a Source of Drinking Water

Information must be provided to demonstrate that the portion of the aquifer proposed for 

exemption “does not currently serve as a source of drinking water” [40 CFR 146.4(d)(1)]. EPA 

interprets water that currently serves as a source of drinking water to include water that is being 

withdrawn at the time of the application and water that will be withdrawn in the future by wells 

that are currently in existence. The initial area of the exempted aquifer would have already been 

established as not serving as a source of drinking water. EPA recommends that the owner or 

operator review information submitted in the original aquifer exemption application concurrent 

with an assessment of the new area for which the aquifer exemption expansion is requested to 

meet the requirements at 40 CFR 146.4(d). This may be accomplished by providing information 

on water suppliers and private drinking water wells in the surrounding region and their source 

waters. 

The types of information that may be useful to submit to support a determination that the area 

proposed for exemption “does not currently serve as a source of drinking water” in the 

surrounding area include:

• Names and contact information for drinking water utilities;

• Numbers and locations of production wells and the aquifers in which they are screened;
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 51

• Locations of private drinking water wells; 

• Maps(s) of the region showing the locations of drinking water wells and the proposed 

exemption area;

• Cross sections of the region showing the aquifers being used for drinking water and their 

stratigraphic relationship to the injection formation and the proposed aquifer exemption 

area; and

• Local and regional population numbers, along with associated surface land uses (e.g., 

neighborhoods, businesses, cities).

Information about drinking water utilities should be available on municipal websites if owners or 

operators are not already familiar with drinking water providers in the surrounding region. Water 

systems may also be located using EPA’s Safe Drinking Water Information System (SDWIS) at 

http://www.epa.gov/enviro/facts/sdwis/search.html, which allows searching by county. Locations 

of both public and private water supply wells may be obtainable through records of state well 

permits; however, some of this information may not be publicly available to owners or operators 

(i.e., for reasons related to water security). Owners or operators may also contact a state’s 

department of health or environmental protection or other relevant agency and request a well 

search. Hydrogeologic maps and related information may be obtained from state geological 

surveys, state departments of environmental protection, or the U.S. Geological Survey (USGS). 

The UIC Program Class VI Well Injection Depth Waivers Guidance provides further details on 

obtaining information about water supplies and about local and regional hydrogeology. 

TDS of More than 3,000 mg/L and Less than 10,000 mg/L

The TDS content of the originally-exempted area (i.e., exempted for the Class II operation) 

should have been established in the original aquifer exemption application. The owner or 

operator is encouraged to review the original application materials for data to verify that the TDS 

of the ground water in the formation is more than 3,000 mg/L and less than 10,000 mg/L. The 

owner or operator should provide data and analyses to support a finding that the ground water in 

the proposed aquifer exemption expansion area is more than 3,000 mg/L TDS and that the 

criterion at 40 CFR 146.4(d)(2) is therefore met. If the TDS concentration in the proposed 

aquifer exemption expansion area is greater than 10,000 mg/L, that portion of the formation is 

not a USDW, and an aquifer exemption is not needed. If the TDS concentration is lower than 

3,000 mg/L, an expansion of the areal extent of an aquifer exemption cannot be granted because 

it would not meet the requirement for the TDS content to be greater than 3,000 mg/L [40 CFR 

146.4(d)(2)].

If the aquifer has been thoroughly characterized in the region of the requested aquifer exemption, 

analyses of ground water from relevant portions of the proposed expansion area may already be 

available. Also, some states, e.g., in the western United States, have statewide data on the 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 52

lowermost USDWs within the state. This information may be out of date, but may provide a 

starting point for this effort. 

In some cases, where analyses have not been conducted or are not available, other data and 

analyses will be needed to support a determination that the TDS is greater than 3,000 mg/L TDS. 

It may be necessary for the owner or operator to obtain and submit new values for TDS by 

sampling the ground water in the expanded exemption area or by estimating the TDS 

concentration from other data such as well logs. Some of this work may already have been done 

as part of the site characterization process for the GS project (see the UIC Program Class VI 

Well Site Characterization Guidance). 

EPA recommends that the owner or operator submit recent data, including:

• Maps of the region showing sample locations with TDS concentrations; 

• Original laboratory reports, if available; and 

• New laboratory reports, if additional samples were taken.

Maps showing the extent of the AoR and proposed aquifer exemption area, along with relevant 

cross sections, are discussed above. Appropriate features should be highlighted, and a narrative 

that describes available information and substantiates evidence that TDS concentrations in the 

proposed aquifer exemption area meet the requirements should be provided.

Not Reasonably Expected to Supply a Public Water System

EPA recommends that the owner or operator submit information to support a determination that 

the aquifer is not reasonably expected to supply a public water system [40 CFR 146.4(d)(3)]. 

Factors that can impact the likelihood of an aquifer serving as a future source of drinking water 

include use for hydrocarbon production (i.e., because it is unlikely that waters in the vicinity of 

oil and gas operations are used as drinking water sources); being situated at a depth or location 

where recovery of water for drinking water is impractical; or being too contaminated to be 

remediated for human consumption. It is likely that the original aquifer exemption associated 

with Class II wells was based on the presence of economically valuable mineral, hydrocarbon, or 

geothermal energy resources. Information and data about such usage within the expanded area 

may include:

• Maps showing the locations of economically viable and potentially economically viable 

deposits that are also USDWs (shown on geologic maps and cross-sections);

• Logging (e.g., geophysical well logs) results or drill stem test results indicating that 

commercially producible quantities of oil and/or natural gas are present;
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 53

• Maps and descriptions of past or current hydrocarbon exploration, production, or 

recovery activities in the area, including injection and production well locations, API 

numbers and/or production information;

• Data from oil and gas producers that are in the area or that produce from the formation(s) 

of interest;

• Information on whether future recovery of mineral resources or hydrocarbons has been 

permitted and/or planned; 

• Production history of other wells in the vicinity that produce from the horizon in 

question;

• Maps and cross sections showing the locations of aquifers that are not currently used but 

that may be used in the future (if appropriate) and their relationship to the injection zone, 

both laterally and stratigraphically;

• Future projections of regional water usage, population and urban development, if 

available; and

• Potential changes in water supply: new wells, aquifer storage and recovery activities, or 

population growth that could require that water be purchased from other water systems. 

Information provided on these changes should demonstrate that sufficient supply and 

resources exist to support future use as demand increases or changes without using the 

exempted aquifer.

Information on oil and gas resources or development may be available from USGS’s Mineral 

Resources Data System, USGS’s National Oil and Gas Assessment, or the U.S. Bureau of Land 

Management (BLM)’s Oil and Gas Management Program. Useful information may also be 

available from state geological surveys and state oil and gas agencies.

5.3 Evaluating Requests for Aquifer Exemption Expansions

States or tribes with primacy will review the request and, if the information submitted supports a 

determination that an aquifer exemption is warranted, they may identify the aquifer or portion of 

an aquifer as exempt, after notice and opportunity for a public hearing [40 CFR 144.7(b)(3)]. The 

state or tribe would then submit a request for a revision to their state program to the appropriate 

EPA regional office. (A state or tribe without primacy would forward the exemption request to 

the EPA regional office that implements the UIC Program.) 

No designation of an expansion to the areal extent of a Class II aquifer exemption for GS 

injection will be final unless approved by the EPA Administrator as a revision to the applicable 

federal UIC Program under 40 CFR part 147 as a substantial revision of an approved state UIC 

Program [40 CFR 145.32]. For additional information on establishing and revising state UIC 

Programs, see the UIC Program Class VI Primacy Manual for State Directors.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 54

As discussed above, 40 CFR 144.7(d)(2) outlines the information that the UIC Program Director 

must consider in evaluating requests to expand the areal extent of a Class II aquifer exemption:

• The current and potential future use of the aquifer or portion of aquifer to be 

exempted [40 CFR 144.7(d)(2)(i)]. The UIC Program Director and EPA will verify that 

no drinking water wells are located in the injection formation in the proposed aquifer 

exemption expansion area. They will also consider anticipated future water supplies for 

the area and the availability of other suitable sources that could meet future needs, 

verifying that the information provided adequately describes the future use of the area to 

be exempted. 

• The predicted extent of the injected carbon dioxide plume and any mobilized fluids 

that could degrade water quality [40 CFR 144.7(d)(2)(ii)] and endanger USDWs that 

are outside of the exempted area (and therefore afforded protection under SDWA). The 

UIC Program Director and EPA will ascertain whether the injected plume and pressure 

front or mobilized fluids could potentially migrate outside of the exempted area over the 

lifetime of the GS project. This will involve evaluating the proposed expanded area of the 

aquifer exemption in concert with the computational AoR modeling results. 

• Whether the areal extent of the expanded aquifer exemption is sufficient to account 

for any possible revisions to the computational model during required AoR 

reevaluations [40 CFR 144.7(d)(2)(iii)]. The UIC Program Director and EPA should 

consider carefully the factors used in delineating the expanded aquifer exemption area, 

including model sensitivity analyses and the conceptual model of the site geology. This 

information can provide insight regarding whether and how much predictions may 

change as a result of the model updates required at 40 CFR 146.84(e).

• Any relevant information submitted for an injection depth waiver [40 CFR 

144.7(d)(2)(iv)]. Maps and cross sections of the project area can provide information 

relevant to both the aquifer exemption expansion and the injection depth waiver. 

Similarly, information on current and future water use required in the waiver application 

report will support an assessment of whether the proposed exemption area meets the 

criteria at 40 CFR 146.4(d). 
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells 55

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Benson S.M. 2007. Overview of Geological Storage of Carbon Dioxide. National Research 

Council Geological Storage Roundtable. Washington DC, May 31, 2007.

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Crow, W., D.B. Williams., B. Carey, M. Celia, and S. Gasda. 2009. Wellbore integrity analysis 

of a natural carbon dioxide producer. Energy Procedia. 1: 3561-3569.

Carbon Sequestration Leadership Forum (CSLF), 2009. Phase I Final Report from CSLF Risk 

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DOE. 2010. Carbon Sequestration Atlas of the United States and Canada. Third Edition (Atlas 

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Doughty, C., Freifeld, B.M., Trautz, R.C. Site characterization for CO2 geologic storage and 

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Electric Power Research Institute (EPRI). 1999. Enhanced Oil Recovery Scoping Study, EPRI, 

Palo Alto, CA: 1999. TR-113836.

Jessen, K., A.R. Kovscek, and F.M. Orr, Jr. 2005. Increasing CO2 storage in oil recovery. Energy 

Conversion & Management. 46: 293–311.

Klusman, R. 2003. Evaluation of leakage potential from carbon dioxide EOR/sequestration 

project. Energy Conversion & Management. 44: 1921-1940.

Knauss, K.G., J.W. Johnson, and C.I. Steefel. 2005. Evaluation of the impact of CO2, cocontaminant gas, aqueous fluid and reservoir rock interactions on the geologic 

sequestration of CO2. Chem. Geol. 217: 339–350.

Kutchko, B., B.R. Strazisar, D.A. Dzombak, G. Lowry, and N. Thaulow. 2007. Degradation of 

well cement by CO2 under geologic sequestration conditions. Environmental Science and 

Technology. 41: 4787-4792. 

Kutchko, B., B.R. Strazisar, N. Huerta, G. Lowry, D. Dzombak, and N. Thaulow. 2009. CO2

reaction with hydrated Class H well cement under geologic sequestration conditions: 

Effects of flyash admixtures. Environmental Science and Technology. 32: 3947–3952.

LeNeveu, D.M., F.B. Walton, J.C. Tait, M.I. Sheppard, and K. Haug. 2006. The role of the upper 

geosphere in mitigating CO2 surface releases in wellbore leakage scenarios. Prepared for 

Natural Resources Canada, CANMET Energy Technology Centre – Devon. Available on 

the Internet at: http://www.netl.doe.gov/publications/proceedings/06/carbonseq/Poster%20208.pdf.

Meyer, J. 2007. Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well 

Technology. Prepared for the Amer. Petroleum Institute. Wash., DC. Available on the 

Internet at: http://www.gwpc.org/e-library/documents/co2/API%20CO2%20Report.pdf.

NETL. 2010. Carbon Dioxide Enhanced Oil Recovery Untapped Domestic Energy Supply and 

Long Term Carbon Storage Solution. Available on the Internet at: 

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.pdf.

Nicot, J-P., P. Saripalli, R. Bouroullec, H. Castellanos, S. Hovorka, S. Lakshminarasimhan, and 

J. Paine. 2006. Development of Science-Based Permitting Guidance for Geological 

Sequestration of CO2 in Deep Saline Aquifers Based on Modeling and Risk Assessment: 

Final Scientific Report. DOE Agreement No. DE-FC25-04NT42210. Available on the 

Internet at: http://www.osti.gov/bridge/servlets/purl/901785-qgxT7R/901785.pdf.
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carbon sequestration: Area-of-review boundaries and borehole leakage driving forces. 

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(GHGT-9), Washington, D.C., November 16-20, 2008. GCCC Digital Publication Series 

#08-03h.

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OGJ (Oil and Gas Journal). 2008. SPECIAL REPORT: More US EOR projects start but EOR 

production continues decline. Oil and Gas Journal, April 21, 2008.

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of CO2 for geologic sequestration. Energy Conversion & Management. 43: 185–198.

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mineral trapping of CO2 with H2S and SO2 in a sandstone formation. Chem. Geol. 242:

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CO2 storage capacity in closed and semi-closed saline formations. Int. J. Greenhouse Gas 

Control. 2: 626–639.
Appendix I.

Detailed Comparison of Class II and Class VI Regulations
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-1

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

AoR Delineation 

and Corrective 

Action: Class II and 

VI requirements 

differ in 

methodology for 

AoR delineation and 

application of 

corrective action. 

For Class II wells the 

AoR is determined 

either by a modified 

Theis equation or by 

a fixed radius; and 

all corrective action 

must be performed 

before a permit is 

issued. For Class VI 

wells, the AoR is 

determined by 

computational 

modeling of 

multiphase fluid 

flow; and corrective 

action can be 

phased. 

The AoR is determined either by a zone of endangering influence

or a fixed radius [40 CFR 146.6]. 

• Zone of endangering influence is defined differently under 

Class II requirements for well permits and area permits, 

and determined based on pressures in the injection zone 

that may cause the migration of the injection and/or 

formation fluid into an USDW. The delineation of this zone 

depends on some hydrogeologic parameters and use of a 

mathematical model, such as a modified Theis equation. It 

should be conducted for an injection time period equal to 

the expected life of the injection well or pattern. 

• Fixed radius is defined as a fixed distance of at least 1⁄4 mile 

around an injection well or a width of 1⁄4 mile for the 

circumscribing area around an injection area. While 

determining the fixed radius, factors to be considered are: 

chemistry of injected and formation fluids, hydrogeology, 

population and ground water use and dependence and 

historical practices in the area. 

The owner or operator must identify all known wells within the 

AoR that penetrate the proposed injection zone, or in the case 

of wells operating over the fracture pressure of the injection 

formation, all known wells within the AoR that penetrate

formations affected by the increase in pressure. [40 CFR 

146.24(a)(3)]. 

For new wells, the owner or operator must also submit a plan 

describing corrective action necessary to prevent fluid 

movement into USDWs [40 CFR 146.24]. The Director will 

consider the following for evaluating the adequacy of corrective 

action: nature and volume of fluid; nature of native fluids or byproducts of injection; potentially affected population; geology; 

hydrogeology; history of the injection operations; completion 

The AoR is delineated using computational modeling that accounts 

for the physical and chemical properties of all phases of the 

injected carbon dioxide stream and is based on available site 

characterization, monitoring, and operational data [40 CFR 

146.84(a)]. It is computed for the time period starting from 

commencement of injection activities until plume movement 

ceases, until pressure differentials no longer can cause the 

movement of fluids into a USDW, or until the end of a fixed time 

period determined by the Director [40 CFR 146.84(c)]. 

Additionally, the owner or operator must prepare, maintain and 

comply with an AoR and corrective action plan, periodically 

reevaluate the delineation, and perform corrective action [40 CFR 

146.84(b)]. 

Corrective action requires identification of all penetrations and 

ensuring that abandoned wells in the AoR have been plugged in a 

manner that prevents the movement of fluids into or between 

USDWs [40 CFR 146.84(c) and (d)]. 

Under the Class VI Rule, corrective action can be addressed on a 

phased basis [40 CFR 146.84(b)].
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-2

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

AoR Delineation 

and Corrective 

Action (continued)

and plugging records; abandonment procedures in effect at the 

time the well was abandoned; and hydraulic connections with 

USDWs [40 CFR 146.7 and 40 CFR 144.55].

Mechanical 

Integrity: 

Mechanical integrity 

is defined in

identical for both 

Class II and Class VI 

wells. However, 

there are 

differences in 

methods used for 

testing the 

mechanical 

integrity. 

Methods used for evaluating the absence of significant leaks [40 

CFR 146.8(b)]:

• Following an initial pressure test, monitoring of the tubingcasing annulus pressure with sufficient frequency while 

maintaining an annulus pressure different from atmospheric 

pressure measured at the surface; or

• Pressure test with liquid or gas; or

• Records of monitoring showing the absence of significant 

changes in the relationship between injection pressure and 

injection flow rate for certain specified types of enhanced 

recovery wells.

Methods used for determining the absence of significant fluid 

movement into an USDW [40 CFR 146.8(c)]: 

• The results of a temperature or noise log; or

• Cementing records demonstrating the presence of 

adequate cement to prevent such migration.

Methods used for evaluating the absence of significant leaks [40 

CFR 146.89(b)]:

• An initial annular pressure test; and

• Continuous monitoring of the following: 1) injection pressure, 

rate, injected volumes; 2) pressure on the annulus between 

tubing and long string casing; and 3) annulus fluid volume.

Methods used for determining the absence of significant fluid 

movement (at least once per year) [40 CFR 146.89(c)]: 

• An approved tracer survey such as an oxygen-activation log; or

• A temperature or noise log.

Additionally if required by the Director, and at a frequency 

specified in the testing and monitoring plan, the owner or 

operator must run a casing inspection log to determine the 

presence or absence of corrosion in the long string casing. [40 CFR 

146.89(d)].
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-3

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Plugging and 

Abandonment: Well 

plugging 

requirements 

between Class II and 

VI wells differ in the 

methods that can be 

used to plug wells. 

Class VI well 

requirements 

include additional 

testing and activities 

prior to plugging. 

Also, owners or 

operators are 

required to give 

notices prior to 

plugging and submit 

a report after 

plugging. 

The well shall be plugged with cement plugs which will be placed 

by one of the following [40 CFR 146.10(a)]:

• The Balance method;

• The Dump Bailer method;

• The Two-Plug method; or

• An alternative method approved by the Director.

The well to be abandoned shall be in a state of static equilibrium 

with the mud weight equalized top to bottom, either by 

circulating the mud in the well at least once or by a comparable 

method prescribed by the Director, prior to the placement of 

the cement plug(s) [40 CFR 146.10(a)].

Prior to the well plugging, the owner or operator must flush each 

Class VI injection well with a buffer fluid, determine bottomhole 

reservoir pressure, and perform a final external mechanical 

integrity test [40 CFR 146.92(a)]. 

The owner or operator of a Class VI well must prepare, maintain, 

and comply with a well plugging plan that will include all of the 

following [40 CFR 146.92(b)]: 

• Appropriate tests or measures for determining bottomhole 

reservoir pressure;

• Appropriate testing methods to ensure external mechanical 

integrity as specified in 40 CFR 146.89;

• The type and number of plugs to be used;

• The placement of each plug, including the elevation of the top 

and bottom of each plug; and

• The type, grade, and quantity of material to be used in 

plugging. The material must be compatible with the carbon 

dioxide stream; and

• The method of placement of the plugs.

The owner or operator must notify the Director in writing at least 

60 days before well plugging (Notice of intent to plug) [40 CFR 

146.92(c)].

Within 60 days after plugging, the owner or operator must submit 

a plugging report to the Director [40 CFR 146.92(d)].

Prior to granting approval for the plugging and abandonment of 

a Class II well the Director shall consider the following 

information [40 CFR 146.24(d)]:

• The type, and number of plugs to be used;

• The placement of each plug including the elevation of top 

and bottom;

• The type, grade, and quantity of cement to be used;

• The method of placement of the plugs; and

• The procedure to be used to meet the requirements of 40 

CFR 146.10(c).
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-4

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Construction: Siting, 

casing and 

cementing, and 

logging, sampling, 

and testing 

requirements for 

Class VI wells are 

more 

comprehensive and 

explicitly defined.

They differ in 

methodologies for 

testing and 

information to be 

collected. 

Siting: All new Class II wells shall be sited in such a fashion that 

they inject into a formation which is separated from any USDW 

by a confining zone that is free of known open faults or fractures 

within the AoR [40 CFR 146.22(a)].

Siting: The wells shall be sited in areas with a suitable geologic 

system [40 CFR 146.83(a)] and comprised of:

• An injection zone(s) of sufficient areal extent, thickness, 

porosity, and permeability to receive the total anticipated 

volume of the carbon dioxide stream;

• Confining zone(s) free of transmissive faults or fractures and 

of sufficient areal extent and integrity to contain the injected 

carbon dioxide stream and displaced formation fluids and 

allow injection at proposed maximum pressures and volumes 

without initiating or propagating fractures in the confining 

zone(s).

The Director may require identification and characterization of

additional zones [40 CFR 146.83(b)].

Casing and Cementing: 

Casing and cementing materials used are required to prevent 

fluid movement into or between USDW and shall be designed 

for the life expectancy of the well. Information considered by 

the Director for newly drilled wells [40 CFR 146.22(b)] includes:

• Depth to the injection zone;

• Depth to the bottom of all USDWs; and

• Estimated maximum and average injection pressures.

The Director may also consider:

• Nature of formation fluids;

• Lithology of injection and confining zones;

• External pressure, internal pressure, and axial loading;

• Hole size;

• Size and grade of all casing strings; and

• Class of cement.

Existing or newly converted Class II wells in existing fields are 

Casing and Cementing: 

Casing and cementing materials used are required to prevent fluid 

movement into or between USDWs and shall be designed for the 

life of the GS project with sufficient structural strength. All well 

materials shall be compatible with fluids, meeting or exceeding 

standards. Information considered by the Director include [40 CFR 

146.86(b)(1)*]:

• Depth to the injection zone(s);

• Injection pressure, external pressure, internal pressure, and 

axial loading;

• Hole size;

• Size and grade of all casing strings (wall thickness including 

any threaded casing sections, external diameter, nominal 

weight, length, joint specification, and construction material);

• Corrosiveness of the carbon dioxide stream and formation 

fluids;

• Down-hole temperatures;

• Lithology of injection and confining zone(s);
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-5

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Construction

(continued)

subject to the regulatory controls that existed at the time of 

drilling, if the wells are in compliance with those controls and 

well injection will not result in the movement of fluid unto a 

USDW so as to create a significant health risk. Newly drilled 

wells in existing fields are subject to requirements of the state 

for casing and cementing, if they meet such requirements and 

well injection will not result in the movement of fluids into a 

USDW so as to create a significant health risk. 

There are no tubing and packer requirements explicitly specified 

in Class II regulations.

• Type or grade of cement and cement additives; and

• Quantity, chemical composition, and temperature of the 

carbon dioxide stream.

Surface casing must extend through the base of the lowermost 

USDW and be cemented to the surface through the use of a single 

or multiple strings of casing and cementing [40 CFR 146.86(b)(2)*].

At least one long string casing, using a sufficient number of 

centralizers, must extend to the injection zone and must be 

cemented by circulating cement to the surface in one or more 

stages [40 CFR 146.86(b)(3)*] or any other approved method [40 

CFR 146.86(b)(4)*].

Cement and cement additives must be compatible with the carbon 

dioxide stream and formation fluids and of sufficient quality and 

quantity to maintain integrity over the design life of the GS project 

[40 CFR 146.86(b)(5)*].

Class VI well owners or operators must comply with the tubing and 

packer requirements listed at 40 CFR 146.86(c) related to materials 

used, their placement in the well, and reporting requirements. The 

Director may request additional information from the owner or 

operator and subsequently determine and specify additional 

requirements for tubing and packer.

Logging, Sampling, and Testing [40 CFR 146.22]: Appropriate logs 

and other tests must be conducted during the drilling and 

construction of new Class II wells. A descriptive report 

interpreting the results of that portion of those logs and tests 

which specifically relate to (1) an USDW and the confining zone 

adjacent to it, and (2) the injection and adjacent formations shall 

be prepared by a knowledgeable log analyst and submitted to

the Director [40 CFR 146.22(f)]. At a minimum, these logs and

Logging, Sampling, and Testing [40 CFR 146.87*]: During the 

drilling and construction of a Class VI injection well, the owner or 

operator must run appropriate logs, surveys, and tests to 

determine or verify the depth, thickness, porosity, permeability, 

and lithology of, and the salinity of any formation fluids in all 

relevant geologic formations to ensure conformance with the 

injection well construction requirements under 40 CFR 146.86 and 

to establish accurate baseline data against which future
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-6

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Construction

(continued)

tests include:

• Deviation checks on all holes at sufficiently frequent 

intervals.

• Other tests and logs: 

o For surface casing: electric and caliper logs before 

casing is installed; and a cement bond, 

temperature, or density log after the casing is set 

and cemented.

o For intermediate and long strings of casing: 

electric, porosity and gamma ray logs before the 

casing is installed; fracture finder logs; and a 

cement bond, temperature, or density log after the 

casing is set and cemented. 

• For new Class II wells or projects, the following information 

concerning the injection formation: fluid pressure, 

estimated fracture pressure, and physical and chemical 

characteristics of the injection zone. 

measurements may be compared. The owner or operator must 

submit to the Director a descriptive report prepared by a 

knowledgeable log analyst that includes an interpretation of the 

results of such logs and tests [40 CFR 146.87(a)*]. At a minimum,

these logs and tests include:

• Deviation checks during drilling on all holes at sufficiently 

frequent intervals.

• Before and upon installation of the surface casing:

o Resistivity, spontaneous potential, and caliper logs 

before the casing is installed; and

o A cement bond and variable density log to evaluate 

cement quality radially, and a temperature log after 

the casing is set and cemented.

• Before and upon installation of the long string casing:

o Resistivity, spontaneous potential, porosity, caliper, 

gamma ray, fracture finder logs, and any other logs 

the Director requires for the given geology before the 

casing is installed; and

o A cement bond and variable density log, and a 

temperature log after the casing is set and cemented.

• A series of tests designed to demonstrate the internal and 

external mechanical integrity of injection wells, which may 

include:

o A pressure test with liquid or gas;

o A tracer survey such as oxygen-activation logging;

o A temperature or noise log; and

o A casing inspection log.

• Any alternative methods that provide equivalent or better 

information and that are required by and/or approved of by 

the Director.

• The owner or operator must take whole borehole cores or 

sidewall cores of the injection zone and confining system and 

formation fluid samples from the injection zone(s), and must
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-7

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Construction

(continued)

submit to the Director a detailed report prepared by a log 

analyst that includes: well log analyses (including well logs), 

core analyses, and formation fluid sample information. 

• The owner or operator must record the fluid temperature, pH, 

conductivity, reservoir pressure, and static fluid level of the 

injection zone(s).

• At a minimum, the owner or operator must determine or 

calculate the following information concerning the injection 

and confining zone(s):

o Fracture pressure;

o Other physical and chemical characteristics of the 

injection and confining zone(s); and

o Physical and chemical characteristics of the formation 

fluids in the injection zone(s).

• Upon completion, but prior to operation, the owner or 

operator must conduct the following tests to verify 

hydrogeologic characteristics of the injection zone(s):

o A pressure fall-off test; and

o A pump test; or

o Injectivity tests.

• The owner or operator must provide the Director with the 

opportunity to witness all logging and. The owner or operator 

must submit a schedule of such activities to the Director 30 

days prior to conducting the first test and submit any changes 

to the schedule 30 days prior to the next scheduled test.
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-8

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements:

The requirements 

under the Class VI 

Rule are more 

comprehensive and 

detailed for 

operating, 

monitoring, and 

reporting. Class VI 

Rule also outlines 

the recordkeeping 

requirements 

whereas there are 

no recordkeeping 

requirements under 

Class II regulations.

Operating:

Operating requirements [40 CFR 146.23(a)] for Class II wells 

specify that:

• Injection pressure at the wellhead cannot exceed a 

maximum value to assure that the pressure during injection 

does not initiate new fractures or propagate existing 

fractures in the confining zone. In no case can injection 

pressure cause the movement of injection or formation 

fluids into a USDW.

• Injection between the outermost casing protecting USDWs 

and the well bore is prohibited.

Operating [40 CFR 146.88]: 

• Except during stimulation, the owner or operator must ensure 

that injection pressure does not exceed 90 percent of the 

fracture pressure of the injection zone(s) so as to ensure that 

the injection does not initiate new fractures or propagate 

existing fractures in the injection zone(s). In no case may 

injection pressure initiate fractures in the confining zone(s) or 

cause the movement of injection or formation fluids that 

endangers a USDW. All stimulation programs must be 

approved by the Director as part of the permit application and 

incorporated into the permit. [40 CFR 146.88(a)]

• Injection between the outermost casing protecting USDWs 

and the well bore is prohibited. [40 CFR 146.88(b)]

• The owner or operator must fill the annulus between the 

tubing and the long string casing with a non-corrosive fluid 

approved by the Director. The owner or operator must 

maintain a pressure on the annulus that exceeds the 

operating injection pressure, unless the Director determines 

that such requirement might harm the integrity of the well or 

endanger USDWs. [40 CFR 146.88(c)]

• Other than during periods of well workover (maintenance) 

approved by the Director in which the sealed tubing-casing 

annulus is disassembled for maintenance or corrective 

procedures, the owner or operator must maintain mechanical 

integrity of the injection well at all times. [40 CFR 146.88(d)]

• The owner or operator must install and use [40 CFR 

146.88(e)]:

o Continuous recording devices to monitor: The 

injection pressure; the rate by volume and/or mass, 

and temperature of the carbon dioxide stream; and 

the pressure on the annulus between the tubing and 

the long string casing and annulus fluid volume; and

o Alarms and automatic surface shut-off systems or, at 
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-9

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements

(continued)

the discretion of the Director, down-hole shut-off 

systems (e.g., automatic shut-off, check valves) for 

onshore wells or, other mechanical devices that 

provide equivalent protection; and

o Alarms and automatic down-hole shut-off systems 

for wells located offshore but within state territorial 

waters, designed to alert the operator and shut-in 

the well when operating parameters such as annulus 

pressure, injection rate, or other parameters diverge 

beyond permitted ranges and/or gradients specified 

in the permit.

• If a shutdown (i.e., down-hole or at the surface) is triggered or 

a loss of mechanical integrity is discovered, the owner or 

operator must immediately investigate and identify the cause 

of the shutoff. If, upon such investigation, the well appears to 

be lacking mechanical integrity, or if monitoring indicates that 

the well may be lacking mechanical integrity, the owner or 

operator must do all of the following [40 CFR 146.88(f)]:

o Immediately cease injection;

o Take all steps reasonably necessary to determine 

whether there may have been a release of the 

injected carbon dioxide stream or formation fluids 

into any unauthorized zone;

o Notify the Director within 24 hours;

o Restore and demonstrate mechanical integrity to the 

satisfaction of the Director prior to resuming 

injection; and

o Notify the Director when injection is scheduled to 

resume.

Monitoring:

Monitoring requirements [40 CFR 146.23(b)] include:

• Monitoring of the nature of injected fluids at time intervals 

sufficiently frequent to yield data representative of their 

Monitoring [40 CFR 146.90]:

The owner or operator of a Class VI well must prepare, maintain, 

and comply with a testing and monitoring plan. Testing and 

monitoring for the project must include all of the following:
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-10

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements

(continued)

• characteristics;

• Observation of injection pressure, flow rate, and cumulative 

volume with the following minimum frequencies:

o Weekly for produced fluid disposal operations;

o Monthly for enhanced recovery operations;

o Daily during the injection of liquid hydrocarbons 

and injection for withdrawal of stored 

hydrocarbons; and

o Daily during the injection phase of cyclic steam 

operations.

o The owner or operator is also required to record

one observation of injection pressure, flow rate,

and cumulative volume at a reasonable interval, no 

greater than 30 days.

• A demonstration of mechanical integrity pursuant to 40 CFR 

146.8 at least once every five years during the life of the 

injection well;

• Maintenance of all monitoring results until the next permit 

review (see 40 CFR 144.52(a)(5)); and

• Hydrocarbon storage and enhanced recovery may be 

monitored on a field or project basis rather than on an 

individual well basis by manifold monitoring. Manifold 

monitoring may be used in cases of facilities consisting of 

more than one injection well, operating with a common 

manifold. Separate monitoring systems for each well are not 

required provided the owner or operator demonstrates that 

manifold monitoring is comparable to individual well

monitoring.

• Analysis of the carbon dioxide stream with sufficient 

frequency to yield data representative of its chemical and 

physical characteristics;

• Installation and use of continuous recording devices to 

monitor injection pressure, rate, and volume; the pressure on 

the annulus between the tubing and the long string casing; 

and the annulus fluid volume added; and

• Corrosion monitoring of the well materials for loss of mass, 

thickness, cracking, pitting, and other signs of corrosion, which 

must be performed on a quarterly basis (see details at section 

40 CFR 146.90(c)).

• Periodic monitoring of the ground water quality and 

geochemical changes above the confining zone(s) or 

additional identified zones including:

o The location and number of monitoring wells; and

o The monitoring frequency and spatial distribution of 

monitoring wells.

• A demonstration of external mechanical integrity at least once 

per year until the injection well is plugged and, if required by 

the Director, a casing inspection log at a frequency established 

in the testing and monitoring plan.

• A pressure fall-off test at least once every five years unless 

more frequent testing is required by the Director.

• Testing and monitoring to track the extent of the carbon 

dioxide plume and the presence or absence of elevated 

pressure (e.g., the pressure front) by using:

o Direct methods in the injection zone(s); and

o Indirect methods (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or down-hole carbon 

dioxide detection tools).

• The Director may require surface air monitoring and/or soil 

gas monitoring to detect movement of carbon dioxide that 

could endanger a USDW (see details at 40 CFR 146.90(h)).
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-11

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements

(continued)

• The Director may require any additional monitoring.

• The owner or operator is required to periodically review the 

testing and monitoring plan. In no case can the review of the 

testing and monitoring plan be conducted less than once 

every five years. Based on this review, the Director may 

require an amended testing and/or monitoring plan that will 

demonstrate that no amendment is needed (see section 40 

CFR 146.90(j) for details).

• The owner or operator must provide the Director with a 

quality assurance and surveillance plan for all testing and 

monitoring requirements.
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-12

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements

(continued)

Reporting: 

Reporting requirements [40 CFR 146.23(c)] include: 

• An annual report to the Director summarizing the 

monitoring results, including monthly records of 

injected fluids, and any major changes in characteristics 

or sources of injected fluid. 

• Owners or operators of hydrocarbon storage and ER

projects may report on a field or project basis rather 

than an individual well basis where manifold 

monitoring is used.

Reporting [40 CFR 146.91]: 

For each permitted Class VI well, the owner or operator must 

submit:

• Semi-annual reports containing:

o Any changes to the physical, chemical, and other 

relevant characteristics of the carbon dioxide stream 

from the proposed operating data;

o Monthly average, maximum, and minimum values for

injection pressure, flow rate and volume, and annular 

pressure;

o A description of any event that exceeds operating 

parameters for annulus pressure or injection 

pressure specified in the permit;

o A description of any event which triggers a shut-off 

device, the source that triggered the shut-off, and the 

response taken;

o The monthly volume and/or mass of the carbon 

dioxide stream injected over the reporting period and 

the volume injected cumulatively over the life of the 

project;

o Monthly annulus fluid volume added; and

o The results of implementing the monitoring

requirements detailed above.

• Report, within 30 days, the results of:

o Periodic tests of mechanical integrity;

o Any well workover; and

o Any other test of the injection well conducted by the 

permittee as required by the Director.

• Report, within 24 hours:

o Any evidence that the injected carbon dioxide stream 

or associated pressure front may cause an 

endangerment to a USDW;

o Any noncompliance with a permit condition, or 

malfunction of the injection system, which may cause 
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-13

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements

(continued)

fluid migration into or between USDWs;

o Any triggering of a shut-off system (i.e., down-hole or 

at the surface);

o Any failure to maintain mechanical integrity; or

o For surface air/soil gas monitoring or other 

monitoring technologies, if required by the Director, 

any indicated release of carbon dioxide to the 

atmosphere or biosphere.

• Owners or operators must notify the Director in writing 30 

days in advance of:

o Any planned well workover;

o Any planned stimulation activities, other than 

stimulation for formation testing; and

o Any other planned test of the injection well 

conducted by the permittee.

• Owner or operators must submit all required reports, 

submittals, and notifications to EPA in an electronic format 

approved by EPA.

• Records shall be retained by the owner or operator as follows:

o All data collected under 40 CFR 146.82 for Class VI 

permit applications shall be retained throughout the 

life of the geologic sequestration project and for 10 

years following site closure.

o Data on the nature and composition of all injected 

fluids collected pursuant to 40 CFR 146.90(a) shall be 

retained until 10 years after site closure. The Director 

may require the owner or operator to deliver the 

records to the Director at the conclusion of the 

retention period.

o Monitoring data collected pursuant to 40 CFR 

146.90(b) through (i) shall be retained for 10 years 

after it is collected.

Well plugging reports, post-injection site care data, 

including, if appropriate, data and information
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-14

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Operating, 

Monitoring, and 

Reporting 

Requirements

(continued)

collected and used to develop the demonstration of 

the alternative post-injection site care timeframe, 

and the site closure report prepared pursuant to 

requirements at 40 CFR 146.93(f) and (h) shall be 

retained for 10 years following site closure.

• The Director has authority to require the owner or operator to 

retain any records required in this subpart for longer than 10 

years after site closure.
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-15

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Information to be 

considered by the 

Director (Permit 

Application): Permit 

application 

requirements 

overlap in some 

areas, such as the 

requirement of a 

map showing the 

injection well and 

the AoR. However, 

Class VI 

requirements 

include additional 

information, such as 

detailed 

hydrogeologic 

properties of the 

formations, 

additional maps and 

cross-sections, 

baseline 

geochemical data, 

and various plans. 

40 CFR 146.24 Information to be considered by the Director 

Certain maps, cross-sections, tabulations of wells within the 

AoR, and other data may be included in the application by 

reference provided they are current, readily available to the 

Director (for example, in the permitting agency's files), and 

sufficiently identified to be retrieved. In cases where EPA issues 

the permit, all the information in this section is to be submitted 

to the Administrator.

40 CFR 146.82 Required Class VI permit information 

For converted Class I, Class II, or Class V experimental wells, 

certain maps, cross-sections, tabulations of wells within the AoR

and other data may be included in the application by reference 

provided they are current, readily available to the Director, and 

sufficiently identified to be retrieved. In cases where EPA issues 

the permit, all the information in this section must be submitted to

the Regional Administrator.

Prior to the issuance of a permit for an existing Class II well to 

operate or the construction or conversion of a new Class II well:

• Information required in 40 CFR 40 CFR 144.31 and 40 CFR 

144.31(g);

• A map showing the injection well or project area for which a 

permit is sought and the applicable AoR. Within the AoR, 

the map must show the number or name and location of all 

existing producing wells, injection wells, abandoned wells, 

dry holes, and water wells. The map may also show surface 

bodies of waters, mines (surface and subsurface), quarries 

and other pertinent surface features including residences 

and roads, and faults if known or suspected. Only 

information of public record and pertinent information 

known to the applicant is required on this map. This 

requirement does not apply to existing Class II wells; and

• A tabulation of data reasonably available from public 

records or otherwise known to the applicant on all wells 

within the AoR included on the map which penetrate the 

proposed injection zone or, in the case of Class II wells 

operating over the fracture pressure of the injection 

formation, all known wells within the AoR which penetrate 

formations affected by the increase in pressure. Such data 

shall include a description of each well's type, construction, 

date drilled, location, depth, record of plugging and 

Prior to the issuance of a permit for the construction of a new 

Class VI well or the conversion of an existing Class I, Class II, or 

Class V well to a Class VI well:

• Information required in 40 CFR 144.31(e)(1) through (6) of this 

chapter;

• A map showing the injection well for which a permit is sought 

and the applicable AoR. Within the AoR, the map must show 

the number or name, and location of all injection wells, 

producing wells, abandoned wells, plugged wells or dry holes, 

deep stratigraphic boreholes, state- or EPA-approved 

subsurface cleanup sites, surface bodies of water, springs, 

mines (surface and subsurface), quarries, water wells, other 

pertinent surface features including structures intended for 

human occupancy, state, tribal, and territory boundaries, and 

roads. The map should also show known and suspected faults. 

Only information of public record is required to be included on 

this map;

• Information on the geologic structure and hydrogeologic 

properties of the proposed storage site and overlying 

formations, including:

o Maps and cross sections of the AoR;

o The location, orientation, and properties of known 

and suspected faults and fractures that may transect 

the confining zone(s) in the AoR and a discussion of a 
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-16

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Information to be 

considered by the 

Director (continued)

completion, and any additional information the Director 

may require. In cases where the information would be 

repetitive and the wells are of similar age, type, and 

construction the Director may elect to only require data on 

a representative number of wells. This requirement does 

not apply to existing Class II wells.

• Proposed operating data:

o Average and maximum daily rate and volume of 

fluids to be injected.

o Average and maximum injection pressure; and

o Source and an appropriate analysis of the chemical 

and physical characteristics of the injection fluid.

• Appropriate geological data on the injection zone and 

confining zone including lithologic description, geological 

name, thickness and depth;

• Geologic name and depth to bottom of USDWs which may 

be affected by the injection;

• Schematic or other appropriate drawings of the surface and 

subsurface construction details of the well;

• In the case of new injection wells, the corrective action 

proposed; and

• A certificate that the applicant has assured through a 

performance bond or other appropriate means, the 

resources necessary to close the plug or abandon the well.

In addition the Director may consider the following:

• Proposed formation testing program;

• Proposed stimulation program;

• Proposed injection procedure;

• Proposed contingency plans, if any, to cope with well 

failures so as to prevent migration of contaminating fluids 

into an USDW; and

• Plans for meeting the monitoring requirements.

determination that they would not interfere with 

containment;

o Data on the depth, areal extent, thickness, 

mineralogy, porosity, permeability, and capillary 

pressure of the injection and confining zone(s); 

including geology/facies changes based on field data 

which may include geologic cores, outcrop data, 

seismic or other geophysical surveys, well logs, and 

names and lithologic descriptions;

o Geomechanical information on fractures, stress, 

ductility, rock strength, and in situ fluid pressures 

within the confining zone(s);

o Information on the regional seismic history including 

the presence and depth of seismic sources and a 

determination that the seismicity would not interfere 

with containment; and

o Geologic and topographic maps and cross sections 

illustrating regional geology, hydrogeology, and the 

geologic structure of the local area.

• A tabulation of all wells, active and inactive, within the AoR 

which penetrate the injection or confining zone(s). Such data 

must include a description of each well's status (active or 

inactive), type, construction, date drilled, location, depth, 

associated borelog, record of plugging and/or completion, and 

any additional information the Director may require;

• Maps and stratigraphic cross sections indicating the general 

vertical and lateral limits of all USDWs, water wells and springs 

within the AoR, their positions relative to the injection 

zone(s), and the direction of water movement, where known;

• Baseline geochemical data on subsurface formations, 

including all USDWs in the AoR;
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-17

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Information to be 

considered by the 

Director (continued)

• For the proposed GS site:

o Average and maximum daily rate and volume and/or 

mass and total anticipated volume and/or mass of 

the carbon dioxide stream;

o Average and maximum anticipated injection 

pressure;

o The source(s) of the carbon dioxide stream; and

o An analysis of the chemical and physical 

characteristics of the proposed carbon dioxide 

stream.

• Proposed pre-operational formation testing program to obtain 

an analysis of the chemical and physical characteristics of the 

injection zone(s) and confining zone(s);

• Proposed stimulation program, a description of stimulation 

fluids to be used and discussion of a determination that 

stimulation will not interfere with containment;

• Proposed procedure to outline steps necessary to conduct 

injection operation;

• Schematics or other appropriate drawings of the proposed 

surface and subsurface construction details of the well;

• Proposed injection well construction procedures;

• Proposed AoR and corrective action plan;

• A demonstration, satisfactory to the Director, that the 

applicant has met the financial responsibility requirements;

• Proposed testing and monitoring plan;

• Proposed injection well plugging plan;

• Proposed post-injection site care and site closure plan;

• At the Director's discretion, a demonstration of an alternative 

post-injection site care timeframe;

• Proposed emergency and remedial response plan;

• A list of contacts, submitted to the Director, for those states, 

tribes, and territories identified to be within the AoR of the 

Class VI project; and
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-18

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Information to be 

considered by the 

Director (continued)

• Any other information requested by the Director.

• The Director shall notify, in writing, any states, tribes, or 

territories within the AoR of the Class VI project based on

information provided in the permit.

Prior to granting approval for the operation of a Class II well, the 

Director shall consider the following information:

• All available logging and testing program data on the well;

• A demonstration of mechanical integrity;

• The anticipated maximum pressure and flow rate at which 

the permittee will operate.

• The results of the formation testing program;

• The proposed injection procedure; and

• For new wells, the status of corrective action on defective 

wells in the AoR.

Prior to granting approval for the operation of a Class VI well, the 

Director shall consider the following information:

• The final AoR based on modeling, using data obtained during 

logging and testing of the well and the formation;

• Any relevant updates, based on data obtained during logging 

and testing of the well and the formation, to the information 

on the geologic structure and hydrogeologic properties of the 

proposed storage site and overlying formations;

• Information on the compatibility of the carbon dioxide stream 

with fluids in the injection zone(s) and minerals in both the 

injection and the confining zone(s), based on the results of the 

formation testing program, and with the materials used to 

construct the well;

• The results of the formation testing program;

• Final proposed injection well construction;

• The status of corrective action on wells in the AoR; 

• All available logging and testing program data on the injection 

well; 

• The demonstration of mechanical integrity;

• Any updates to the proposed AoR and corrective action plan, 

testing and monitoring plan, injection well plugging plan, postinjection site care and site closure plan, or the emergency and 

remedial response plan; and

• Any other information requested by the Director.
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-19

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Financial 

Responsibility 

A certificate that the applicant has assured through a 

performance bond or other appropriate means, the resources 

necessary to close plug or abandon the injection well [40 CFR 

146.24(a)(9)].

The owner or operator must demonstrate, to the satisfaction of 

the Director, and maintain financial responsibility by using 

instrument(s), such as trust funds, surety bonds, letter of credit, 

insurance, self insurance, escrow account, any other instruments 

to cover the cost of corrective action, injection well plugging, post 

injection site care and site closure, emergency and remedial 

response (see 40 CFR 146.85 for details). 
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-20

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Post Injection Site 

Care and Site 

Closure (PISC): 

Class VI Rule 

includes a specific 

section for the post 

injection site care

and site closure, 

whereas Class II 

requirements do not 

include any specific 

regulations for PISC. 

None. Class VI Rule Post Injection Site Care requirements are [40 CFR 

146.93]: 

• The owner or operator of a Class VI well must prepare, 

maintain, and comply with a plan for post-injection site care 

and site closure.

• The site will be monitored following the cessation of injection 

to show the position of the carbon dioxide plume and 

pressure front and demonstrate that USDWs are not being 

endangered.

• Demonstration of alternative post-injection site care 

timeframe. At the Director's discretion, the Director may 

approve, in consultation with EPA, an alternative postinjection site care timeframe other than the 50 year default, if 

an owner or operator can demonstrate during the permitting 

process that an alternative post-injection site care timeframe 

is appropriate and ensures non-endangerment of USDWs.

• Notice of intent for site closure. The owner or operator must 

notify the Director in writing at least 120 days before site 

closure. 

• After the Director has authorized site closure, the owner or 

operator must plug all monitoring wells in a manner which will 

not allow movement of injection or formation fluids that 

endangers a USDW.

• The owner or operator must submit a site closure report to 

the Director within 90 days of site closure, which must 

thereafter be retained at a location designated by the Director 

for 10 years. 

• Each owner or operator of a Class VI injection well must 

record a notation on the deed to the facility property or any 

other document that is normally examined during title search.

• The owner or operator must retain for 10 years following site 

closure, records collected during the post-injection site care 

period. 
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-21

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Emergency and 

Remedial Response:

Class VI

requirements 

include a separate 

section for 

emergency and 

remedial response,

whereas Class II 

requirements do not 

include this topic.

None. Class VI Rule emergency and remedial response requirements are 

[40 CFR 146.94]: 

• As part of the permit application, the owner or operator must 

provide the Director with an emergency and remedial 

response plan.

• If the owner or operator obtains evidence that the injected 

carbon dioxide stream and associated pressure front may 

cause an endangerment to a USDW, the owner or operator

must:

o Immediately cease injection;

o Take all steps reasonably necessary to identify and 

characterize any release;

o Notify the Director within 24 hours; and

o Implement the emergency and remedial response 

plan approved by the Director.

• The Director may allow the owner or operator to resume 

injection prior to remediation if the owner or operator

demonstrates that the injection operation will not endanger 

USDWs.

• The owner or operator shall periodically review the 

emergency and remedial response plan at least once every 

five years.
Draft UIC Program 

Class II to Class VI Well Transitioning Guidance A-22

Detailed Comparison of Requirements for Class II and VI Wells

Requirement 

Type Class II Requirements Class VI Requirements

Injection Depth

Waivers: Under the 

Class VI Rule, 

owners or operators

can apply for a 

waiver to inject 

above the 

lowermost USDW.

However, there are

no specific 

requirements 

restricting he 

injection depth for 

Class II wells.

None. In seeking a waiver of the requirement to inject below the 

lowermost USDW, the owner or operator must submit a 

supplemental report concurrent with permit application (see 40 

CFR 146.95 for details). 

*Pursuant to requirements at 40 CFR 146.81(c), owners or operators seeking to convert existing wells to Class VI geologic sequestration wells must 

demonstrate to the Director that the wells were engineered and constructed to meet the requirements at 40 CFR 146.86(a) and ensure protection of USDWs, 

in lieu of requirements at 40 CFR 146.86(b) and 146.87(a). See Section 4 of this guidance for additional information on requirements for transitioning wells.