Geologic Sequestration of Carbon
    United States
    Environmental Protection
    Agency
                      Draft Underground Injection Control
                      (UIC) Program Guidance on
                      Transitioning Class II Wells to Class VI
                      Wells
Office of Water (4606M)         EPA 816-P-l 3-004               December 2013

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                                     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.
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                               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 etseq.]. 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/ui c/wells_sequestrati on.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.
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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.
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                                Table of Contents

1        Introduction	1
   1.1    Comparison of Class II and Class VIUIC 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)(l-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 Inj ected 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 Programs 1
   4.1    Class HER 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-l
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                                     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 Hand Class VI Wells	3
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                        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
S ACROC    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
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                                     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.
4:40CFR146.81(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.l

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.

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
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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, non-
hazardous 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
strati graphically 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 strati graphically 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
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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
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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).

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
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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 (31.1°C 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/1 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
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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
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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
CFR144.19(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/tvpe/groundwater/uic/class6/gsguidedoc. cfm.
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   1.1   Comparison of Class II and Class VIUIC 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)(l)], 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
(SOWA), 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

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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
40CFR
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 % 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

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 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
40CFR
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)(l))
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

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Requirement
Type
Testing and
monitoring
requirements
Reporting
requirements
Injection well
plugging
Post-injection
site care and
site closure
Emergency
and remedial
response
Class VI
Regulatory
Citations
40CFR
146.90
40CFR
146.91
40CFR
146.92
40CFR
146.93
40CFR
146.94
Class II Requirements (Summary)
and Regulatory Citations
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)(l-2))
Submit annual monitoring report.
(40 CFR 146.23(c))
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)(l))
None.
Submit contingency plans to cope
with well failures so as to prevent
migration of fluids into a USDW.
(40 CFR 146.24(b)(4))
Significant Differences between Class II and
Class VI Requirements
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.
Class VI require:
• Semi-annual monitoring report;
• Electronic reporting; and
• Record-keeping.
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.
Class VI regulations require post-injection
site care or monitoring; no such
requirements exist for Class II.
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

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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 IIUIC
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 IIER 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 144.5l(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-by-
       case 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

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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 re-
permitting 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 operational -
and 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, seethe 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 transit!oning 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

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       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 IIER 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

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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

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(a)
            •p  250,-OQO
            D
               .- Larkin, 1937
                                                 Year
                                                      Advanced Resources International
                      1930
        Source: Ward and Cooper, JS95
1940    1950     1960     1970    1980     1990     2000

                    Ysar

                         Advanced Resources Internationa)
(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
                                                                10

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                  Number of active CO2 EOR projects per State
                       1-5    f~~l 11-15

                       6-10
Source: 2010 EOR
Survey
DOE Carbon Atlas projected
regions of capacity in active
and depleted reservoirs
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
                                                 11

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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 pressure-
isolated 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; lessen 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., lessen 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                           12

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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.
                                                CO.pipeline

CO,
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' '
Oil
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well


t



!

Oil


Oil
storage
tank

IJ 1 Sales

Water disposal
well
^ss*
       Wofe: Figure not to scale
       Source: Modified from Geti. 1998; EPKI. 7999
CO.      I—I Oil/water  f—\ Waler

C0,/oil/water  t^ Oil
 (a)
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells
                                                    13

-------
                                                 CO pipeline






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compressor
(if needed)







I
-«— Wate


Recycled CO,
•^ -*—


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• ^ ^'
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Water disposal
well
^~^^
                    HD
           linj
   Wofe: F/gure nof to sca/e
   Source: Modified from Getz, 1998: EPRI. 1999
(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
14

-------
received the maximum practical volume of carbon dioxide, injection ceases. The Class VI GS
project continues during PISC and eventually ends with site closure.
        Oil Production
       and Water-flooding
                             EOR
  c
  o
 t*
  0)
 |E"
  "
 "Jo
o
I
TJ
O
£
    i
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a
c
TO
                                    J
                    O/O Self Identifies
                            or
                  Director Determination
                                         'Transition Point':
                                           O/O Obtains
                                          Class VI Permit
                                                                 PISC
                                            Project Risk
                                            to USDWs
 Post-
Closure
                                                                       Time
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
                                                                                        15

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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 Directors1 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                          16

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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 VIUIC
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                          17

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                                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 forgeochemical simulations (NETL, 2011).


   3.1   Reservoir Pressure, Injection Rate and Production Rate  [40 CFR 144.19(b)(l-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                            18

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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 VIUIC 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)(l)]

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 (/",/) may be determined by the
following equation:

                                                                    [l]
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Where Pu is the average fluid pressure within the lowermost USDW, pi 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                          20

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                      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 (h;nt), 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.
        z = 1950 m
        z = 1900 m
        z = 1800 m
        z = 1030 m
        z = 1000 m
           z = 0m
w
USDW
hint = 1900m
Pu= 0.49 MPa
Confining Unit
Injection Zone
hint = 1700m
Pi = 6.72 MPa
Confining Unit









400m (1/4 mile)





10m








                                                                   note: not to scale
  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
21

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                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
                  Scenarios           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
  transit!oning 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 (7\/) 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                          22

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                Box 1, continued: Example of Determining Pressure Changes
                                                                    -Scenario 1

                                                                    -Scenario 2

                                                                    -Scenario 3

                                                                    •Scenario 4
                                                                	Threshold Pressure Great
                                                                    Enough to Cause Fluid
                                                                    Movement into the USDW
                                                      300
  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
23

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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 UICProgram
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
IIER 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                          24

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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 (/\/), 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 IIER 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 transit!oning 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 VIUIC
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                          25

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          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).


03
Q_
^
-*^

f




m
9

-

7 -

K -
\J

5


4
3
9

'"^, 	
X*^















_ . _ ... .

extraction rate at 360 days




Enough to Cause Fluid
Movement into the USDW





z ii
0 200 400 600 800
Time, d
  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
26

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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 transit!oning 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 zone-
confining zone contact. The cement plug  should have sufficient integrity to contain separate-
phase 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                          27

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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 transit!oning 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. 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
 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                          28

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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)(l) 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                          29

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   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                          30

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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 IIER project will transition to a Class VIGS 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, high-
temperature 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                          31

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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                          32

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     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)(l)]. 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 re-
       permitted 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)].

    •   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
    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.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells
                                   33

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       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)(l)]. 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 VIUIC 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)(l) 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)(l)]; 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 re-
       permitting, 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                          34

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       her authority to request additional information to inform a final decision on whether re-
       permitting 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 VIUIC 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)(l) 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                          35

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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 VIUIC 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                          36

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requirement that their long string casing be cemented to the surface. Under such circumstances,
EPA anticipates that the Class VIUIC 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                         3 7

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the well and (geologic) formations the well intersects is available to the Class VIUIC 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                          38

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   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 shut-
off 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 VIUIC
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                          39

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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)(l-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
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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)(l)]. 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).
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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 VIUIC
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)];
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    •   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.
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     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)].
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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;
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    •   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 separate-
       phase 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.
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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 transit!oned 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 IIER 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  transit!oning 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                         47

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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)(l),
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)(l)) 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)(l), 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)(l), 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

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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)(l), 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
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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)(l)]. 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                          50

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   •   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
       strati graphic 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.

IDS 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                          51

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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                          52

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    •   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 strati graphically;

    •   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, seethe UIC Program Class VI Primacy Manual for State Directors.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells                          53

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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                         54

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6   References

Advanced Resources International (ARI). 2006. Evaluating the potential for 'Game Changer'
       Improvements in Oil Recovery Efficiency from CC>2 Enhanced Oil Recovery. Prepared
       for U.S. DOE, Office of Oil and Natural Gas, Office of Fossil Energy. February 2006.
       Available on the Internet at:
       http://www.fe.doe.gov/programs/oilgas/publications/eor co2/Game  Changer Document
        2 06 with  appendix.pdf

Benson S.M. 2007. Overview of Geological Storage of Carbon Dioxide. National Research
       Council Geological Storage Roundtable. Washington DC, May 31, 2007.

Carey, J.W., M. Wigand, SJ. Chipera, G. WoldeGabriel, R. Pawar, P.C. Lichtner, S.C. Wehner,
       M.A. Raines, and G.D. Guthrie, Jr. 2007. Analysis and Performance of Oil Well Cement
       with 30 years of CO2 Exposure from the SACROC Unit, West Texas, USA. International
       Journal of Greenhouse Gas Control.  1: 75-85.

Celia, M.A., S. Bachu, J.M. Nordbotten, S.E. Gasda, andH.K. Dahle. 2004. Quantitative
       estimation of CO2 leakage from geological storage: Analytical models, numerical models,
       and data needs, p. 663-671. In M. Wilson et al. (ed.) Proc. Int. Conf. on Greenhouse Gas
       Control Technologies, 7th, Vancouver, BC, Canada. 5-9 Sept. 2004. Vol. 1. Elsevier
       Science, Amsterdam.

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
       Assessment Task Force. CSLF-T-2009-04.
       http ://www. cslforum. org/publications/documents/RATF_Phase 1 FinalReport.pdf.

Deel, D. K. Mahajan, C.R. Mahoney, H.G. Mcllvried, and R.D. Srivastava. 2007. Risk
       assessment and management for long-term storage of CO2 in geologic formations -
       United States Department of Energy R&D. Systemics,  Cybernetics and Informatics, 5(1),
       79-84. Available on the Internet at:
       http://www.iiisci.0rg/j ournal/CV$/sci/pdfs/P807791.pdf.

DOE. 2010. Carbon Sequestration Atlas of the United States and Canada. Third Edition (Atlas
       III).

Doughty, C.,  Freifeld, B.M., Trautz, R.C. Site characterization for CO2 geologic storage and
       vice versa: the Frio brine pilot, Texas, USA as a case study. J. Environ Geol. 2007.

Energy Information Administration (EIA). 2009. Annual Energy Review 2008. Energy
       Information Administration, U.S. Department of Energy. Washington, DC. DOE/EIA-
       0384(2008). June 2009.
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells                         55

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Electric Power Research Institute (EPRI). 1999. Enhanced Oil Recovery Scoping Study, EPRI,
       Palo Alto, CA: 1999. TR-113836.

lessen, K., A.R. Kovscek, and P.M. Orr, Jr. 2005. Increasing CC>2 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, co-
       contaminant 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, andN. Thaulow. 2007. Degradation of
       well cement by CC>2 under geologic sequestration conditions. Environmental Science and
       Technology. 41: 4787-4792.

Kutchko, B., B.R. Strazisar, N. Huerta, G. Lowry, D. Dzombak, andN. 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 CC>2  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/carbon-
       seq/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:
       http://www.netl.doe.gov/technologies/oil-
       gas/publications/EP/small CO2 eor_primer.pdf. March 2010.

NETL. 2011. Best Practices for: Risk Analysis and Simulation for Geologic Storage of CO2.
       DOE/NETL-2011/1459. Available on the Internet at:
       http://www.netl.doe.gov/technologies/carbon seq/refshelf/BPM RiskAnalysisSimulation
       .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
Draft UIC Program Guidance on Transitioning Class II Wells to Class VI Wells                         56

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Nicot, J.-P., Oldenburg, C.M., Bryant, S.L., Hovorka, S.D., Pressure perturbations from geologic
       carbon sequestration: Area-of-review boundaries and borehole leakage driving forces.
       Presented at the 9th International Conference on Greenhouse Gas Control Technologies
       (GHGT-9), Washington, D.C., November 16-20, 2008. GCCC Digital Publication Series
       #08-03h.

Nordbotten, J.M.,  M.A. Celia, and S. Bachu. 2004. Analytical solutions for leakage rates through
       abandoned wells. Water Resource. Res. 40:W04204, doi: 10.1029/2003WR002997.

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.

Oldenburg, C.M.,  S.L. Bryant, and J-P Nicot. 2009. Certification framework based on effective
       trapping for geologic carbon sequestration. International Journal  of Greenhouse Gas
       Control. 3(4): 444-457.

Saripalli, P.,  and P. McGrail. 2002. Semi-analytical approaches to modeling deep well injection
       of CO2 for geologic sequestration. Energy Conversion & Management. 43: 185-198.

Stauffer, P.H., H.S. Viswanthan,  R.J. Pawar, M.L. Klasky, and  G.D. Guthrie. CO2-PENS: A
       CO2 sequestration system model supporting risk-based decisions. Proceedings of the 16th
       International Conference  on Computational Methods in Water Resources; Copenhagen,
       Denmark, June 19-22, 2006. Available on the Internet at:
       http://www.goldsim.com/downloads/documents/LANL  CO2 Paper.pdf

Walton, F.B., J.C. Tait, D. LeNeveu, and M.I.  Sheppard. 2004.  Geological storage of CO2: a
       statistical approach to assessing performance and risk. In: E.S. Rubin, D.W. Keith and
       C.F. Gilboy (Eds.), Proceedings of 7th  International Conference on Greenhouse Gas
       Control Technologies, Sept 5-9, 2004, Vancouver, Canada. Volume 1: Peer-Reviewed
       Papers and Plenary Presentations, IEA  Greenhouse Gas Programme, Cheltenham, UK,
       2004. Available on the Internet at: http://www.granite.mb.ca/~sheppard/GHGT7.pdf.

Xu, T., J.A. Apps, K. Pruess,  and H. Yamamoto. 2007. Numerical modeling of injection and
       mineral trapping of CO2 with H2S and SO2 in a sandstone formation.  Chem. Geol. 242:
       319-346.

Zhou, Q., J.T. Birkholzer, C.-F. Tsang,  and J. Rutqvist. 2008. A method for quick assessment of
       CO2 storage capacity in closed and semi-closed saline formations. Int. J. Greenhouse Gas
       Control. 2: 626-639.
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                    Appendix I.




Detailed Comparison of Class II and Class VI Regulations

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                                    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 % mile
     around an injection well or a width of % 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 by-
products 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-l

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                                    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
CFR146.8(b)]:
•   Following an initial pressure test, monitoring of the tubing-
    casing 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

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                                    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 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).
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)].	
Draft UIC Program
Class II to Class VI Well Transitioning Guidance
                                                                                                              A-3

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                                     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)(l)*]:
                                                            •   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
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                                    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
[40CFR146.86(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
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                                     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
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                                    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.
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                                    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
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Detailed Comparison of Requirements for Class II and VI Wells
Requirement
Type
Operating,
Monitoring, and
Reporting
Requirements
(continued)




























Class II Requirements





























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
Class VI Requirements
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 [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:
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                                     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
    40CFR146.90(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)).
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                                   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
                                                            CFR146.90(j) for details).
                                                            The owner or operator must provide the Director with a
                                                            quality assurance and  surveillance plan for all testing and
                                                            monitoring requirements.
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                                    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
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                                    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
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                                   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.
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                                     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)(l) 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
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                                     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
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                                    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
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                                     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, post-
                                                                injection 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
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                                    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
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                                    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 (RISC):
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 RISC.
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 post-
    injection 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
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                                   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:
           Immediately cease injection;
           Take all steps reasonably necessary to identify and
           characterize any release;
           Notify the Director within 24 hours; and
           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.
                                                                o
                                                                o
                                                                                    o
                                                                                    o
Draft UIC Program
Class II to Class VI Well Transitioning Guidance
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                                   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.
Draft UIC Program
Class II to Class VI Well Transitioning Guidance

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