SEPA
United States
Environmental Protection
Agency
Geologic Sequestration of Carbon
Dioxide
Draft Underground Injection Control
(UIC) Program Guidance on Class VI
Well Plugging, Post-Injection Site Care,
and Site Closure
Office of Water (4606M)
EPA 816-P-13-005
April 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), referred to as the
Class VI Rule, establishes a new class of injection well (Class VI).
The Safe Drinking Water Act (SDWA) provisions and EPA regulations cited in this document
contain legally-binding requirements. In several chapters, this guidance document makes
recommendations and offers alternatives that go beyond the minimum requirements indicated by
the Class VI Rule. This is intended to provide information and recommendations that may be
helpful for UIC Class VI Program implementation efforts. Such recommendations are prefaced
by the words 'may' or 'should' and are to be considered advisory. They are not required
elements of the Class VI 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. 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 codified in the U.S. Code of Federal
Regulations [40 CFR 146.81 et seq.] and are referred to in this document 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). This guidance is part of a series of technical guidance documents that
the United States Environmental Protection Agency (EPA) is developing to support owners or
operators of Class VI wells and UIC Program permitting authorities in the implementation of the
Class VI Rule. The Class VI Rule and related documents are available at
http://water.epa.gov/type/groundwater/uic/wells sequestration.cfm.
The Class VI Rule includes requirements for well plugging [40 CFR 146.92] and post-injection
site care (PISC) [40 CFR 146.93] that are designed to ensure that after injection ceases, the
geologic sequestration (GS) project does not pose a threat to USDWs. Owners or operators must
properly plug the injection well, monitor the site for a timeframe established in the permit (e.g.,
50 years or an alternative timeframe), demonstrate to the UIC Program Director that conditions
at the site have stabilized and do not pose a threat of endangerment to USDWs, and complete the
plugging of monitoring wells to enable site closure. The activities to be conducted during these
stages of the project must be detailed in the Injection Well Plugging Plan [40 CFR 146.92(b); 40
CFR 146.82(a)(16)] and the PISC and Site Closure Plan [40 CFR 146.93(a); 40 CFR
146.82(a)(17)] and documented through well plugging reports [40 CFR 146.92(d)], non-
endangerment demonstrations [40 CFR 146.93(b) and (c)], and a site closure report [40 CFR
146.93(f)]. This Draft UIC Program Guidance on Class VI Well Plugging, Post-Injection Site
Care, and Site Closure provides information to help owners or operators perform the necessary
activities to successfully transition from the operational phase of a GS project to the PISC phase
and, ultimately, to site closure.
After injection ceases at a GS project, the injection well must be plugged to ensure that the well
does not become a conduit for fluid movement into USDWs [40 CFR 146.92], Required
injection well plugging activities include flushing the well with a buffer fluid, testing the external
mechanical integrity of the well, and emplacing cement into the well in a manner that will
prevent fluid movement that may endanger USDWs [40 CFR 146.92(a) and (b)]. Additionally,
materials used for injection well plugging must be compatible with the injectate [40 CFR
146.92(b)(5)], This document provides information on performing mechanical integrity testing
prior to well plugging, preparing the well for plugging, and selecting plugging materials, plug
depths, and emplacement methods [40 CFR 146.92(b)(4)-(6)]. Other relevant guidance
documents are referenced as appropriate. The document also provides guidance on preparing the
required notices of intent to plug and plugging reports. Owners or operators are encouraged to
consider using similar procedures when plugging monitoring wells.
The PISC period entails monitoring as specified in the UIC Program Director-approved PISC
and Site Closure Plan [40 CFR 146.93(a); 40 CFR 146.82(a)(17)]. This monitoring is an
extension of the monitoring conducted during the operational phase of the project designed to
ensure that USDWs are protected from endangerment. EPA anticipates that it will be similar to
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operational phase monitoring; however, changes to the frequency and types of monitoring may
be made during the PISC period (e.g., a decrease in monitoring frequency). Changes in PISC
monitoring must be made through approved revisions to the PISC and Site Closure Plan [40 CFR
146.93(a)(4)], PISC must continue for a timeframe established in the permit (e.g., 50 years or an
alternative timeframe established based on site-specific data, modeling, and other required lines
of evidence as described at 40 CFR 146.93(c)) until an owner or operator can demonstrate non-
endangerment. During PISC, an owner or operator may be able to demonstrate non-
endangerment of USDWs in advance of the timeframe established in the permit [40 CFR
146.93(b)(1)], Under such circumstances, the owner or operator may submit non-endangerment
information to the UIC Program Director to support site closure, and the UIC Program Director
may subsequently approve an amended PISC and Site Closure Plan to authorize early site
closure. This guidance document includes considerations and recommendations to help owners
or operators petition for an alternate PISC timeframe (i.e., other than the 50-year default) during
permitting; revise the PISC timeframe during the injection operation; and make a non-
endangerment demonstration for revision to the PISC and Site Closure Plan.
The guidance also discusses the information that the owner or operator must submit to
demonstrate non-endangerment [40 CFR 146.93(b)(3)] showing that no additional monitoring is
needed to ensure that the project does not pose a risk to USDWs before the UIC Program
Director will authorize site closure. Once the non-endangerment demonstration is approved by
the UIC Program Director and site closure has been authorized, 120 days' notice of intent must
be submitted [40 CFR 146.93(d)]; following site closure, a site closure report must be sent to the
UIC Program Director within 90 days [40 CFR 146.93(f)]. The types of documentation to be
included in the notifications (e.g., well plugging, notification to authorities, records regarding the
injectate) are described at 40 CFR 146.93(f). This document includes guidance on providing the
necessary information that the UIC Program Director will need to make a decision regarding site
closure, as well as guidance on completing requirements for the site closure report.
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Table of Contents
Disclaimer i
Executive Summary ii
Table of Contents iv
List of Figures vi
List of Tables vi
Acronyms and Abbreviations vii
Definitions viii
1 Introduction 1
1.1 The Phases of a GS Project 1
1.2 Injection Well Plugging Requirements 2
1.3 Post-Injection Site Care Requirements 2
1.4 Site Closure Requirements 2
1.5 Relationship of this Guidance to Related Guidance Documents 3
2 Well Plugging 4
2.1 Purpose of Well Plugging 4
2.2 Timing of Well Plugging 4
2.3 Development and Submittal of Injection Well Plugging Plan 5
2.4 Tests to Perform Prior to Plugging 6
2.4.1 Determination of Bottomhole Reservoir Pressure 7
2.4.2 Mechanical Integrity Testing 8
2.5 Preparation of Well Prior to Plugging 8
2.5.1 Well Inspection and Initial Preparation 9
2.5.2 Well Cleaning 9
2.5.3 Remedial Operations 10
2.5.4 Establishment of Static Equilibrium 11
2.5.5 Preparation for Recompletion of Injection Well 12
2.6 Performing Well Plugging 12
2.6.1 Mechanical (Bridge) Plugs and Inflatable Packers 12
2.6.2 Cement Plugging Materials 13
2.6.3 Locations of Cement Plug Placement 16
2.6.4 Methods for Plug Emplacement 17
2.6.5 Considerations for Offshore Wells 21
2.7 Development and Submittal of Plugging Report 21
3 Post-Injection Site Care (PISC) 23
3.1 PISC Monitoring 23
3.1.1 PISC and Site Closure Plan and Reevaluation 24
3.1.2 Use of Monitoring Wells in PISC Monitoring 28
3.1.3 Geophysical Surveys during PISC 29
3.1.4 Additional PISC Monitoring 30
3.1.5 Frequency of PISC Monitoring 30
3.1.6 Reporting of PISC Monitoring Results 31
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3.2 PISC Monitoring Timeframe 32
3.2.1 Class VI Rule Default Timeframe 33
3.2.2 Alternative PISC Timeframe 33
3.3 Demonstration of USDW Non-Endangerment 40
3.3.1 Summary of Existing Monitoring Data 41
3.3.2 Comparison of Monitoring Data and Model Predictions and Model
Documentation 41
3.3.3 Evaluation of Carbon Dioxide Plume 41
3.3.4 Evaluation of Mobilized Fluids 43
3.3.5 Evaluation of Reservoir Pressure 43
3.3.6 Evaluation of Potential Conduits for Fluid Movement 46
4 Site Closure 47
4.1 Site Closure Notification 47
4.2 Monitoring Well Plugging 48
4.3 Site Closure Reporting and Recordkeeping 49
4.4 Post-Site Closure Activities 50
5 References 51
Appendix A. Sample Template of an Injection Well Plugging Plan A-l
Appendix B. Sample Template of a Notice of Intent to Plug a Class VI Injection Well B-l
Appendix C. Sample Template of a Class VI Injection Well Plugging Report C-l
Appendix D. Sample Template of a Class VI Post-Injection Site Care and Site Closure
Plan D-l
Appendix E. Sample Template of a Class VI Non-Endangerment Demonstration E-l
Appendix F. Sample Template of a Notice of Intent to Close a GS Project F-l
Appendix G. Sample Template of a GS Project Closure Report G-l
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List of Figures
Figure 1. Risk Curve for a GS Project 1
Figure 2. Relationship Between Bottomhole Pressure and Surface Pressure 8
Figure 3. Typical Squeeze Cementing Operation, Showing Packer Above Perforations to
Control Pressure and Cement Flow 11
Figure 4. Bridge Plug 13
Figure 5. Schematic of Class VI Injection Well Prior to Well Preparation for Plugging, After
Preparation, and After Plugging and Abandonment 16
Figure 6. Principles of the Balance Method 18
Figure 7. Example of the Retainer Method 19
Figure 8. Principles of the Two-Plug Method 20
Figure 9. Hypothetical GS Project Showing Initial and Revised AoR 27
Figure 10. Historical Reservoir Pressure Data within the Injection Zone and Model
Predictions for Three Monitoring Wells at Hypothetical GS Project 45
List of Tables
Table 1. Examples of Common Cement Additives 14
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Acronyms and Abbreviations
AoR Area of Revi ew
API American Petroleum Institute
AWWA American Water Works Association
CAA Clean Air Act
CERCLA Comprehensive Environmental Response, Compensation,
and Liability Act (Superfund)
CFR Code of Federal Regulations
EGR Enhanced Gas Recovery
EOR Enhanced Oil Recovery
EPA United States Environmental Protection Agency
GHG MRR Green House Gas Monitoring and Reporting Rule
GS Geologic Sequestration
MIT Mechanical Integrity Test
NETL Nati onal Energy T echnol ogy Lab oratory
PISC Post-Injection Site Care
QA/QC Quality Assurance/Quality Control
RCRA Resource Conservation and Recovery Act
SC Specific Conductivity
SDWA Safe Drinking Water Act
TDS Total Dissolved Solids
TVD True Vertical Depth
UIC Underground Injection Control
USDW Underground Source of Drinking Water
USEPA United States Environmental Protection Agency
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Definitions
Key to definition sources:
1: Source: 40 CFR 144.3.
2: Class VI Rule Preamble.
3: Source: 40 CFR 146.81(d).
4: This definition was drafted for the purposes of this document.
5: EPA's UIC website (http://water.epa.gov/type/groundwater/uic/glossarv.cfm).
6: Source: 40 CFR 144.6(f) and 144.80(f).
Administrator means the Administrator of the United States Environmental Protection Agency,
or an authorized representative.1
Annulus means the space between the well casing and the wall of the borehole; the space
between concentric strings of casing; the space between casing and tubing.
Area of review (AoR) means the region surrounding the geologic sequestration project where
USDWs may be endangered by the injection activity. 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 displaced fluids, and is based on available site characterization,
monitoring, and operational data as set forth in 40 CFR 146.84.3
Bottomhole pressure means the pressure at the bottom of the well bore. It may be measured
directly with a downhole pressure transducer, or in some cases estimated from the surface
pressure and the height and density of the fluid column.4
Brine means 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.
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 under 40 CFR part 261.
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 outermost 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 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 IIEOR or EGR 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 inputs and
predictions (i.e., outputs)4
Confining zone means a geologic formation, group of formations, or part of a formation
stratigraphically overlying the injection zone(s) that acts as barrier to fluid movement. For Class
VI wells operating under an injection depth waiver, confining zone means a geologic formation,
group of formations, or part of a formation stratigraphically overlying and underlying the
injection zone(s).3
Corrective action means the use of UIC Program Director-approved methods to assure that
wells within the AoR do not serve as conduits for the movement of fluids into USDWs.3
Corrosive means having the ability to wear away a material by chemical action. Carbon dioxide
mixed with water forms carbonic acid, which can corrode well materials.2
Enhanced Oil or Gas Recovery (EOR/EGR) typically means the process of injecting a fluid
(e.g., water, brine, or carbon dioxide) into an oil or gas bearing formation to recover residual oil
or natural gas. The injected fluid thins (decreases the viscosity) and/or displaces extractable oil
and gas, which is then available for recovery. This is also used for secondary or tertiary
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.
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.3
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
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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 IIEOR or EGR 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.3
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.
Injectate means the fluids injected. For the purposes of the Class VI Rule, this is also known as
the carbon dioxide stream.
Injection depth waivers refers 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.4
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 GS project.3
Mechanical integrity 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
Model means a representation or simulation of a phenomenon or process that is difficult to
observe directly or that occurs over long timeframes. 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.
Mud refers to a generic term for a wide range of drilling fluids, usually water or oil but
occasionally synthetically based with high concentrations of suspended solids.4
Packer means a mechanical device that seals the outside of the tubing to the inside of the long-
string casing, isolating an annular space.
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.4
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Plug means a watertight, gastight seal installed in a bore hole or well to prevent movement of
fluids that may be mechanical or composed of cement or other material that are capable of zonal
isolation.4
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.4
Post-injection site care (PISC) means appropriate monitoring and other actions (including
corrective action) needed following cessation of injection to ensure that USDWs are not
"3
endangered, as required under 40 CFR 146.93.
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
"3
fluids or formation fluids into a USDW.
Site closure means the specific point or time, as determined by the UIC Program Director
following the requirements under 40 CFR 146.93, at which the owner or operator of a GS site is
released from PISC responsibilities.3
Supercritical fluid means a fluid above its critical temperature (31.1ฐC for carbon dioxide) and
critical pressure (73.8 bar for carbon dioxide)4
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
-3
vertical extent to allow fluids to move between formations.
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 (UIC) 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 well injection. This includes setting the
federal minimum requirements for construction, operation, permitting, and closure of
underground injection wells.4
Underground Injection Control (UIC) Program Director refers to the chief administrative
officer of any approved 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
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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
Well bore refers to the hole that remains throughout a geologic (rock) formation after a well is
drilled.4
Well plugging refers to the act of sealing off a well so that all USDWs and producing zones are
zonally isolated and the well bore, casings, and annulus can no longer act as a conduit for fluids.
Plugging typically involves the injection of alternating layers of mud and cement into the well
bore, casings, and annulus.4
Workover refers to any maintenance activity performed on a well that involves ceasing injection
and removing the wellhead.4
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1 Introduction
The Underground Injection Control (UIC) Program of the United States Environmental
Protection Agency (EPA) is responsible for regulating the construction, operation, permitting,
and closure of injection wells that place fluids underground. EPA's federal Requirements Under
the Underground Injection Control Program for Car bon Dioxide Geologic Sequestration Wells
[40 CFR 146.81 et seq.], referred to as the Class VI Rule, created a new UIC injection well class,
Class VI, specifically for the injection of carbon dioxide for the purpose of geologic
sequestration (GS).
1.1 The Phases of a GS Project
The risk posed to underground sources of drinking water (USDWs) during the operation of a GS
project increases during the injection phase as carbon dioxide is injected and subsurface
pressures increase; risk will likely decrease during post-injection site care (PISC) as the carbon
dioxide plume begins to dissipate and pressures stabilize. While the actual magnitude and change
in project risk during these phases depend on site-specific factors, Figure 1 below illustrates how
risk to USDWs changes throughout the life of a GS project.
CO, Injection
and Monitoring
Siting/
Evaluation
Post-Closure
Project
Risk
Injection
Rate
Figure 1. Risk Curve for a GS Project.
To address the risks to USDWs following the cessation of injection (i.e., during the PISC and
post-closure phases in Figure 1), the Class VI Rule at 40 CFR 146.92 and 146.93 includes
requirements that owners or operators must follow to properly plug their injection wells, monitor
the site until it can be demonstrated that it no longer poses an endangerment risk, and close the
GS site. The purpose of this guidance is to explain these requirements for Class VI well owners
or operators and UIC Program Directors. EPA encourages communication between the owner or
operator and the UIC Program Director throughout the process of planning for and executing all
aspects of the GS project, including well plugging and PISC.
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1.2 Injection Well Plugging Requirements
Well plugging refers to the activities associated with removing well components, flushing the
well, and installing plugs. Proper well plugging is important for ensuring that the well is properly
abandoned and does not provide a conduit for fluid movement that might endanger USDWs.
Class VI well owners or operators must prepare, maintain, and comply with an Injection Well
Plugging Plan [40 CFR 146.92(b)], Specifically, the owner or operator must flush each injection
well with a buffer fluid, determine bottomhole pressure, perform a final external mechanical
integrity test (MIT), and plug the well with materials that are compatible with carbon dioxide.
EPA also recommends that well plugging materials be compatible with the formation fluids. The
requirements for plugging Class VI injection wells are included in the Class VI Rule at 40 CFR
146.92 and are discussed in detail in Section 2 of this guidance.
The procedures required at 40 CFR 146.92 apply specifically to injection wells. However,
owners or operators may consider employing the same well plugging procedures when plugging
monitoring wells at the end of the PISC period (see Section 4.2)]. Performing such activities on
monitoring wells will help to demonstrate non-endangerment to USDWs [40 CFR 146.93(b)(2)]
and help ensure that the wells do not allow movement of injection or formation fluids [40 CFR
146.93(e)],
1.3 Post-Injection Site Care Requirements
PISC refers to the time period immediately following cessation of injection until site closure.
Although there is no longer injection during this phase, the project still poses some risk to
USDWs due to elevated pressures and the presence of mobile-phase carbon dioxide.
Owners or operators of Class VI wells must prepare, maintain, and comply with a PISC and Site
Closure Plan [40 CFR 146.93(a)], Specifically, owners or operators must monitor the site to
show the position of the carbon dioxide plume and pressure front and demonstrate that USDWs
are not endangered during the approved PISC monitoring timeframe [40 CFR 146.93(b)], The
purpose of these requirements is to ensure that any risk to USDWs is detected and appropriate
remediation/corrective action is taken in the case of endangerment.
Section 3 discusses PISC including monitoring, the default and alternative timeframes, and the
evaluation of risk reduction to USDWs and the non-endangerment demonstration for this phase
of the GS project.
1.4 Site Closure Requirements
Site closure refers to the procedures and period immediately following PISC, when an owner or
operator must plug and abandon all monitoring wells to enable the end of the Class VI project
and termination of the permit [40 CFR 146.93(e)], Site closure commences only when there is no
longer risk of endangerment to USDWs and when authorized by the UIC Program Director.
Site closure regulations are established to ensure that all PISC monitoring wells are plugged
appropriately and to the UIC Program Director's satisfaction, that all project records are
maintained, and that future land owners are made aware of the project and previous land use.
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Accordingly, the owner or operator must provide the UIC Program Director with a notice of
intent for site closure at least 120 days prior to site closure [40 CFR 146.93(d)], plug all
monitoring wells [40 CFR 146.93(e)], submit a site closure report within 90 days of site closure
[40 CFR 146.93(f)], and record a notation in the deed or similar document [40 CFR 146.93(g)],
Note that following site closure, the owner or operator is responsible for any remedial action
deemed necessary to prevent USDW endangerment caused by the injection operation (see
Section 4.4).
Site closure regulations are discussed in further detail in Section 4.
1.5 Relationship of this Guidance to Related Guidance Documents
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
UIC Class VI injection well. Other UIC Program GS guidances that owners or operators
performing injection well plugging, PISC, and site closure activities may find useful are
available on the UIC Program's website at
http://water.epa.gov/tvpe/groundwater/uic/wells sequestration.cfm.
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2 Well Plugging
This section includes a discussion of the UIC Class VI well plugging requirements [40 CFR
146.92] and practices suitable for injection and monitoring wells associated with a GS project.
Some information in this document has been incorporated from other UIC Program guidance
documents (USEPA, 1982; USEPA, 1989). Guidance from the American Petroleum Institute
(API, 1993) is also referenced, along with more recent literature on specialty plugging materials
that may be suitable for the unique aspects of a GS project (i.e., carbon dioxide-bearing fluids in
the injection zone). In addition, several testing activities discussed briefly below (e.g.,
mechanical integrity testing) are described in detail in the UIC Program Class VI Well Testing
and Monitoring Guidance.
2.1 Purpose of Well Plugging
Proper plugging of injection and monitoring wells is a long-standing requirement of the UIC
Program, designed to ensure that wells do not serve as conduits for fluid movement into USDWs
following cessation of injection and site closure. Just as requirements and best practices for
primary cementing are designed to produce properly constructed wells with mechanical integrity,
the Class VI well plugging requirements [40 CFR 146.92; 40 CFR 146.93(e)] are intended to
ensure that an abandoned well maintains integrity and will not pose a threat to USDWs. For this
reason, well plugging activities must be described in the Injection Well Plugging Plan [40 CFR
146.92(b); 40 CFR 146.82(a)(16)], properly performed per 40 CFR 146.92(b), and documented
in plugging reports [40 CFR 146.92(d)] and the site closure report [40 CFR 146.93(f)(1)] to the
satisfaction of the UIC Program Director.
2.2 Timing of Well Plugging
Plugging activities will most likely begin upon cessation of injection. However, the immediate
plugging of the injection well is not a requirement, as some owners or operators may elect to
convert an injection well to a monitoring well. In either scenario, once injection has ceased, the
injection apparatus in the well serves no further purpose; therefore, the owner or operator may
either choose to plug the well and complete all plugging activities or perform some of the
preparatory activities (e.g., mechanical integrity testing, well cleaning) and recomplete the well
for monitoring purposes. EPA recommends that any such recompletion take place as soon as
practical to allow continued acquisition of pressure data. In the case of recompletion of the
injection well, the owner or operator will be required to plug the well upon demonstration of
non-endangerment made for site closure [40 CFR 146.93(e)], Regardless of the timing of
injection well plugging, the plugging must be done in a manner pursuant to requirements at 40
CFR 146.92 to ensure that the well does not become a conduit for fluid movement into USDWs.
The plugging must be performed according to the approved Injection Well Plugging Plan
submitted with the Class VI permit application [40 CFR 146.92(b); 40 CFR 146.82(a)(16)].
The Class VI Rule, at 40 CFR 146.92(c), requires that the owner or operator notify the UIC
Program Director in writing at least 60 days before plugging of an injection well (a template for
notice of intent to plug is provided in Appendix B). At this time, if any changes have been made
to the original Injection Well Plugging Plan, the owner or operator must also provide the revised
Injection Well Plugging Plan [40 CFR 146.92(c)], This 60-day time period allows for an ongoing
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dialogue between owners or operators and the UIC Program Directors regarding planned well
plugging activities. Once well plugging procedures have been finalized, or confirmation has been
made that no changes to the Injection Well Plugging Plan are necessary, well plugging may
proceed. A well plugging report must be submitted to the UIC Program Director by the owner or
operator within 60 days of plugging the injection well [40 CFR 146.92(d)],
Monitoring wells must also ultimately be plugged [40 CFR 146.93(e)], Some (if not all)
monitoring wells will need to remain in use during PISC to perform required monitoring; the
locations to be sampled will be specified in the approved PISC and Site Closure Plan [40 CFR
146.93(a)(2)(iii)]. However, if any monitoring wells will not be included in the post-injection
monitoring program, the owner or operator may choose to plug them at the beginning of the
post-injection period. If the PISC and Site Closure Plan is amended during the PISC phase of the
project [40 CFR 146.93(a)(4)], EPA recommends that the owner or operator plug monitoring
wells that will no longer be used for sampling to eliminate the potential that they become
conduits for fluid movement. Thus, the plugging schedule for monitoring wells may be adjusted
as appropriate in consultation with the UIC Program Director and reflected in changes to the
PISC and Site Closure Plan.
Because improperly abandoned monitoring wells may become conduits for fluid movement into
USDWs (similar to improperly abandoned injection wells), EPA recommends that owners or
operators plug their monitoring wells in a similar manner to that used to meet the requirements
for injection well plugging as discussed in Sections 2.5 and 2.6. A more detailed discussion of
monitoring well plugging is included in Section 4.2 of this guidance document.
At the end of PISC, and after the UIC Program Director has authorized site closure, the owner or
operator must demonstrate that all monitoring and injection wells have been plugged in a manner
that will not allow movement of injection or formation fluids that endangers a USDW [40 CFR
146.93(e); 40 CFR 146.93(f)(1)], EPA also recommends that owners or operators submit notice
of intent to plug monitoring wells 60 days in advance and monitoring well plugging reports
within 60 days after plugging.
2.3 Development and Submittal of Injection Well Plugging Plan
The Class VI Rule at 40 CFR 146.82(a)(16) requires owners or operators to prepare and submit a
proposed Injection Well Plugging Plan with the permit application for approval by the UIC
Program Director. The UIC Program Director-approved plan is incorporated into the Class VI
permit.
The Injection Well Plugging Plan must include a description of how the owner or operator will
meet the Class VI injection well plugging requirements at 40 CFR 146.92. The plan must include
the following information:
Appropriate tests or measures to identify bottomhole reservoir pressure to determine
the appropriate plugging fluid density [40 CFR 146.92(b)(1)];
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Appropriate testing methods to ensure external mechanical integrity to demonstrate
that the long-string casing and cement that are left in the ground after the well is
plugged will maintain their integrity [40 CFR 146.92(b)(2)];
The type and number of plugs to be used for plugging of the injection well [40 CFR
146.92(b)(3)];
The placement of each plug, including the elevation of the top and bottom of each
plug, recommended to be submitted along with schematics and drawings, if
appropriate [40 CFR 146.92(b)(4)];
The type, grade, and quantity of material to be used in plugging. The material must be
compatible with the carbon dioxide stream [40 CFR 146.92(b)(5)]; and
The method of placement of the plugs, such as the balance method, retainer method,
or two-plug method [40 CFR 146.92(b)(6)],
Stratigraphic information at the GS site, such as the location and thickness of the injection zone
and USDW-containing formations, their geochemistry, well construction details, and the
composition of the carbon dioxide stream or injectate are important factors to consider while
developing an Injection Well Plugging Plan. Also, the UIC Program Director will evaluate the
plan in conjunction with the site characterization data and other proposed plans, such as the Well
Construction Plan and proposed operating conditions. Submittal, evaluation, and approval of the
Injection Well Plugging Plan may be an iterative process, and ongoing communication is
encouraged between the owner or operator and the UIC Program Director.
Although the Class VI Rule does not require periodic reviews and amendments to the Injection
Well Plugging Plan throughout the operation/injection phase, EPA recommends that owners or
operators evaluate how any changes in facility operation, any new data collected during
monitoring and/or area of review (AoR) reevaluations, or any adverse events that required an
emergency response may warrant amendments to the various plans, including the Injection Well
Plugging Plan. If the Injection Well Plugging Plan is revised, the revised plan must be submitted
when notifying the UIC Program Director of the intent to plug the well, at least 60 days prior to
conducting the plugging activity [40 CFR 146.92(c)],
The development of the Injection Well Plugging Plan is described further in the UIC Program
Class VI Well Project Plan Development Guidance, including details on what specific
information must be included in the plan, how the plan should be structured, how the
amendments to the plan should be made, and what underlying data must be submitted with the
plan. A tempi ate/example of an Injection Well Plugging Plan is given in Appendix A of this
document.
2.4 Tests to Perform Prior to Plugging
Prior to injection well plugging, the Class VI Rule requires that the owner or operator flush each
Class VI injection well with a buffer fluid (discussed in Section 2.5), determine bottomhole
reservoir pressure, and perform a final external MIT [40 CFR 146.92(a)], Determination of
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bottomhole pressure and mechanical integrity are needed to plan any remedial activities and to
ensure that plugging materials and procedures are selected correctly.
2.4.1 Determination of Bottomhole Reservoir Pressure
Bottomhole pressure refers to the pressure of the fluids at the location of the perforations (i.e.,
screened interval) of the injection well. Prior to the plugging of a Class VI well, the owner or
operator is required to determine bottomhole pressure pursuant to requirements at 40 CFR
146.92(a), using the tests or measures described in the UIC Program Director-approved Injection
Well Plugging Plan [40 CFR 146.92(b)(1)], The purposes of testing bottomhole reservoir
pressure prior to plugging are to: (1) determine the density of fluid that should be used during
flushing and well cleaning; (2) determine the density of plugging (buffer) fluid needed to
establish static equilibrium prior to plug emplacement; and (3) obtain a measurement of pressure
at the injection well that should be used in calculations of pressure decay within the injection
zone.
After injection ceases and the well is shut in, bottomhole pressure can be estimated from
downhole pressure transducers or, in some cases, wellhead (i.e., surface) pressure measurements.
If a single fluid phase is present in the well bore, wellhead pressure measurements may be used
with knowledge of the average fluid density, and the true vertical depth (TVD) of the well.
Bottomhole pressure is equal to wellhead pressure plus the hydrostatic pressure from the weight
of the fluid column between the wellhead and well bottom (Figure 2). However, when separate
fluid phases are present in the well bore (e.g., gas and supercritical fluid), more complex
thermodynamic modeling methods will need to be used to estimate bottomhole pressure from
wellhead pressure (see e.g., Nurafza and Fernagu, 2009).
Because of temperature effects and density variations in the fluid, a more robust approach for
determining bottomhole pressure is to obtain actual measurements with a dedicated downhole
pressure gauge or with a pressure gauge lowered into the borehole. Further information regarding
measurement of well pressures is available in the UIC Program Class VI Well Testing and
Monitoring Guidance.
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BHP = SP + HP
(Bottom Hole (Surface (Hydrostatic
Pressure) Pressure) Pressure)
Figure 2. Relationship Between Bottomhole Pressure and Surface Pressure.
Adapted from: Drilling Formulas and Drilling Calculations (no date).
2.4.2 Mechanical Integrity Testing
Prior to injection well plugging, the owner or operator must perform a final external MIT as
required at 40 CFR 146.92(a). The appropriate testing methods must be specified in the UIC
Program Director-approved Injection Well Plugging Plan [40 CFR 146.92(b)(2)], Unless an
alternative test is approved by the EPA Administrator and the UIC Program Director under 40
CFR 146.89(e), the Class VI Rule at 40 CFR 146.89(c) requires that the owner or operator use at
least one of the following external MITs: an approved tracer survey (e.g., oxygen activation log);
a temperature log; or a noise log.
The purpose of conducting a final MIT is to verify the absence of leakage through channels
adjacent to the well bore or the well's long-string casing that may result in significant fluid
movement into a USDW. A demonstration of external mechanical integrity indicates that the
cement and casing that are left in the ground after well plugging and site closure will maintain
integrity over time. If a loss of external mechanical integrity is detected within the well,
appropriate corrective action must be taken during or prior to well plugging, as described in
Section 2.6.3 [40 CFR 146.88(f)(4)]. Further information regarding external MITs is available in
the UIC Program Class VI Well Testing and Monitoring Guidance.
2.5 Preparation of Well Prior to Plugging
Preparation of the injection well for plugging is important for ensuring the establishment of solid
plugs and long-term protection of USDWs. Several activities are necessary at this preparatory
stage: well cleaning, remedial operations, and the establishment of static equilibrium within the
well. EPA emphasizes that injection zone pressure should be controlled at all times to prevent
flow out of the injection zone. This will be accomplished through the use of workover and
plugging (buffer) fluids that are correctly weighted and compatible with the injectate and
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formation fluids. Because an improperly abandoned monitoring well can pose a risk to USDWs,
EPA recommends that monitoring wells be similarly prepared for plugging.
2.5.1 Well Inspection and Initial Preparation
Prior to well plugging, EPA recommends that the owner or operator identify details on well
construction, geologic information in the vicinity of the well bore, and information on the
dominant geochemistry around the well bore and of formation fluids. This information may
support decisions on the placement of each plug and the type, grade, and quantity of material to
be used in plugging. The Class VI Rule requires that information on the plugging materials be
specified in the Injection Well Plugging Plan [40 CFR 146.92(b)(5)]; if this initial preparation
stage suggests that changes are needed, a revised Injection Well Plugging Plan will need to be
submitted with the notice of intent to plug [40 CFR 146.92(c)], Information on well construction,
geology, and geochemistry will also allow an assessment of compatibility of the materials with
the environment in the vicinity of the well, including the formation fluids.
2.5.2 Well Cleaning
2.5.2.1 Flushing of Well
Prior to removal of the injection tubing and packer, the well must be flushed [40 CFR 146.92(a)],
This is done with workover fluids, which are specially prepared brines or muds that are
circulated through the well to remove any remaining injection fluids and to remove fine debris
such as congealed drilling mud or small particles such as sand (USEPA, 1982). The potential for
corroding well materials should be controlled, and the workover fluid should be chemically
compatible with both formation fluids and solids in the downhole environment. In the case of a
GS project, the workover fluid must be compatible with carbon dioxide and carbon dioxide-rich
brines and must, therefore, be buffered against low pH conditions that might be encountered
downhole [40 CFR 146.92(a)],
All sections of the well that will be left intact after plugging and have been in contact with
injection or annular fluids should be flushed. These components include the annular space, long-
string casing, perforated zone, and possibly the injection packer. If the packer has been removed
prior to flushing, workover fluid may be circulated via the injection tubing (prior to its removal).
If the packer has not been removed, injection of flushing fluids would need to occur via the
injection tubing as well as directly into the annulus. It may also be possible to unseat both the
tubing and packer for this flushing stage, and then remove them.
2.5.2.2 Removal of Well Components and Obstructions
The removal of well equipment prior to plugging is necessary to open the well for access. In
general, uncemented and non-permanent components of the well should be removed. This
includes downhole monitoring devices, such as pressure transducers, and the downhole shut-off
device if installed. Injection tubing is almost always removed because it serves no purpose after
the operational phase of the project (USEPA, 1989); removal is done with a workover rig. After
circulation of the workover fluid, the tubing may be unseated and removed. The packer may be
retrievable, or it may be permanent. If it is permanent and cannot be removed, it may be drilled
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through (USEPA, 1989). If the tubing and packer cannot be removed, the tubing may be cut
above the packer.
At this stage, larger debris such as metal pins and tools can be removed using a junk
basket/retriever or a "fishing" magnet. In some cases it may not be possible to remove all pieces
of larger debris from the well. Pieces of equipment inadvertently lodged downhole may need to
be milled or drilled through if they cannot be retrieved.
Casing that is not cemented to the formation poses a fluid migration risk. Because the surface
and long-string casings in a Class VI injection well will be cemented to the surface [40 CFR
146.86(b)(2) and (3)], they will generally not be removed. For monitoring wells that predate the
project, however, there may be sections of uncemented casing. If so, the casing may need to be
removed, or the owner or operator may need to squeeze cement behind portions of the casing to
ensure zonal isolation and prevent fluid migration that may endanger USDWs.
2.5.3 Remedial Operations
Deficiencies that may be found during well inspections at any phase of a GS project (e.g., during
injection or in preparation of well plugging) include cement channeling, casing leaks, corroded
sections of casing, and collapsed sections of casing (USEPA, 1989). Owners or operators are
required to repair any deficiencies to ensure that the casing does not leak during or after well
plugging and potentially endanger USDWs [40 CFR 146.88(f)], In planning remedial operations,
the owner or operator should take into account the results of external mechanical integrity testing
[40 CFR 146.92(a)], as well as historical MIT data and records of any remedial work done
during the lifetime of the well, to locate areas of concern. As information on potential
remediation needs emerges, owners or operators are encouraged to include planned remedial
activities in any revisions to the Injection Well Plugging Plan.
In the case of a buckled or collapsed casing, the casing may be opened up using a casing roller or
swaging tool (USEPA, 1989). Squeeze cementing, however, is the most common remedial
measure, and it is needed in cases of channeled or absent cement behind the casing. This
procedure serves to protect against fluid movement behind the casing, and it is considered an
important step in ensuring the long-term protection of USDWs.
Squeeze cementing involves placing a cement slurry across a leaking section of casing.
Hydraulic pressure is used to force the cement through leaks or perforations in the casing to
provide a cement seal between the casing and the formation (Figure 3). If a section of the well
bore requires cementing behind the casing (e.g., defects from primary cementing), but the casing
does not have leaks or perforations, it may be necessary to perforate the casing first. If a portion
of casing is uncemented (e.g., in a monitoring well), and the casing is to be left in place, it may
be necessary to circulate cement behind the casing through perforations to provide a new cement
sheath.
Owners or operators should ensure that the squeeze pressure and cement slurry are correctly
selected. The pressure will need to be sufficient to force the cement into the desired zone without
fracturing the formation. The cement slurry will need to be compatible with the formation and
should be formulated to control filtration of water from the cement solids (formation of filter
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cake). A detailed discussion of the basics of squeeze cementing is provided by Smith (1976).
Additional information on cement types is provided in the UJC Program Class VI Well
Construction Guidance and below in Section 2.6.3.
primary cement -
mud filter cake
-tubing
-squeeze packer
-cement
Figure 3. Typical Squeeze Cementing Operation, Showing Packer Above Perforations to
Control Pressure and Cement Flow.
Adapted from: Smith (1976).
2.5.4 Establishment of Static Equilibrium
The last stage of well preparation prior to plugging is establishment of static equilibrium within
the well bore. This involves introducing a plugging fluid that is free of excessive movement and
for which flow into and out of the well is controlled. Because at least one long-string casing in a
GS injection well must extend to the injection zone, effectively creating separation from USDWs
and other formations [40 CFR 146.86(b)(3)], loss of fluid to formations along the well bore will
not be a significant concern during injection well plugging. However, the plugging fluid should
be able to control injection zone pressure. If there are sections of the well bore for which casing
has been removed (e.g., in a monitoring well), the plugging fluid must be able to control pressure
from high-pressure formations or prevent loss of fluid to low-pressure formations.
The plugging fluid should permit placement of cement plugs at the desired depth and should be
suitable to remain as a fluid between the cement plugs, maintaining physical and chemical
stability indefinitely (USEPA, 1982). The fluid should have uniform weight and produce
minimal movement during the setting and hardening of the cement. Excessive fluid movement
during setting can contaminate the slurry or cause it to migrate, resulting in a non-sealing plug
with reduced strength (API, 1993; USEPA, 1989; Smith, 1976). Drilling mud is often selected as
a plugging fluid, and it should be formulated to be compatible with the cement and to control
pressure where necessary. The needed mud weight (density) can be estimated from bottomhole
pressure [determined as required at 40 CFR 146.92(a)] and the vertical depth.
A suggested plugging fluid might contain: (1) fresh water or brine; (2) bentonite (gel or clay); (3)
attapulgite (a type of clay); and (4) lost circulation material (as needed) (USEPA, 1989). A
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weighting material such as barite, sand, or hematite may be needed to produce a fluid with
greater density. The plugging fluid will replace the fluid used for flushing, and it may require
several circulations to complete the replacement. After circulation of the fluid, the fluid level in
the well should be observed visually to note if there is fluid movement. Adequate circulation and
establishment of static conditions with a plugging fluid of appropriate weight and viscosity will
help ensure quality cement plugs. Additional information is provided by USEPA (1989).
2.5.5 Preparation for Recompletion of Injection Well
Well preparation will also be needed if an injection well is to be recompleted for use as a
monitoring well, but steps may be modified as appropriate to prepare for installation of any
necessary monitoring hardware. Flushing of the well should be done, small debris should be
circulated out, and larger debris should be removed. The injection tubing should be pulled, and
any necessary remedial actions should be performed to address casing leaks or defective cement,
including those steps outlined in this guidance. After well preparation, recompletion with
hardware for monitoring (e.g., downhole fluid sampling systems, sensors, etc.) may be done. If
needed, new packers may be installed to isolate the injection zone and/or other zones that will be
monitored.
If an owner or operator wishes to convert an injection well and has not previously provided plans
for doing so, EPA recommends that the owner or operator update the monitoring well scheme
and the PISC and Site Closure Plan prior to giving the required 60 days' notice of well plugging.
This will allow time for the UIC Program Director to evaluate the conversion and associated
specifications.
2.6 Performing Well Plugging
Establishing secure plugs pursuant to 40 CFR 146.92 is a crucial step in ensuring long-term
protection of USDWs after a well is no longer in use. Plugging is achieved through the use of
mechanical and cement plugs. Mechanical plugs help in isolating high pressure zones such as the
injection zone. A series of strategically placed cement plugs, however, provide the primary
means of ensuring long term zonal isolation in an abandoned well bore. Issues an owner or
operator should consider in planning the plugging activities include: (1) the locations of critical
formations such as USDWs so that there is no fluid migration; (2) the locations of any previously
remediated portions of the well; (3) the design of the cement slurry; and (4) the best method of
cement emplacement. At all stages, control of pressure in the injection zone will need to be
maintained. If there are any uncased sections (e.g., in a monitoring well), control of exposed
high- or low-pressure zones should also be maintained. Although the Class VI Rule requirements
at 40 CFR 146.92 apply to plugging of the injection well, EPA recommends the use of careful
plugging methods as described for injection wells for plugging of monitoring wells.
2.6.1 Mechanical (Bridge) Plugs and Inflatable Packers
A mechanical or bridge plug is a downhole tool that is used to isolate a pressurized zone such as
the injection zone (Figure 4). These plugs are often placed in the casing above the injection zone
or above other equipment such as a packer or tubing that cannot be removed. They are available
in models made with corrosion-resistant alloys. This is important for plugs used to isolate the
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injection zone in a Class VI well, where the plug will be exposed to carbon dioxide and carbon
dioxide-rich fluids. Bridge plugs may be permanent or temporary, and they should be made of
strong but sufficiently brittle material, such that they can be drilled through, if necessary, to re-
enter the well bore. Those set for the plugging of Class VI wells will likely be permanent, and
cement plugs should be emplaced above them. Alternatively, if the owner or operator intends to
cement across the perforated injection zone, a cement retainer may be placed at the top of the
injection zone, beneath which cement will be squeezed (see Section 2.6.4). Some bridge plugs
can also serve as cement retainers.
Figure 4. Bridge Plug.
From: Wyoming Completion Technologies (no date).
Inflatable packers, which have rubber and steel components, are a potential alternative to
mechanical bridge plugs (e.g., Vaucher and Brooks, 2010). They can pass through restrictions
and inflate to several times their original outside diameter. At this time, data are lacking on the
performance of these devices in a carbon dioxide-rich environment. However, given their
potential utility, interested owners or operators may wish to consult with the UIC Program
Director regarding their use.
2.6.2 Cement Plugging Materials
The type, grade, and quantity of material to be used in plugging must be specified in the
Injection Well Plugging Plan [40 CFR 146.92(b)(5)], The cement used for plugs should form a
bond with the casing and should be compatible (nonreactive) with the plugging fluid. It must also
be compatible with the carbon dioxide stream [40 CFR 146.92(b)(5)] and should be compatible
with carbon dioxide-formation fluid mixtures. In addition, the cement slurry needs to be able to
be pumped into place and to set and gain strength in a reasonable amount of time (Calvert and
Smith, 1994). The cement slurry should also have certain properties with respect to the plugging
fluid; it should have a higher yield strength and plastic viscosity. However, differences in the
densities of the cement and plugging fluid should be minimized to allow the cement to be placed
at the desired depth (USEPA, 1982).
Bottomhole pressure and temperature affect the properties and setting time of the cement and
should be taken into account when designing the slurry (Smith, 1976). For example, high
pressures decrease the setting time, while high temperatures cause cement to lose strength and
gain permeability. Depth is also important for determining the necessary placement time, and
retarding agents or accelerators may be needed to control the setting time (API, 1993). Table 1
presents some of the additives used to control cement properties, generally in API cement
classes. See Smith (1976) or Kosmatka et al. (2003) for a more comprehensive list of additives
and their uses.
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Table 1. Examples of Common Cement Additives.
From: Smith (1976).
AikliliM' type
K\;i ill pics/com posit ion
I sc/benefit
Accelerator
Calcium chloride
Sodium chloride
Gypsum
Faster setting, high early strength
Retarder
Lignosulfonates
Organic acids
CMHEC
Slower setting, increased pumping time,
better flow properties
Dispersants
Organic acids
Polymers
Sodium chloride
Lignosulfonates
Thinner slurry, decreased fluid loss, better
mud removal, better placement
Silica flour
Silicon dioxide
Stabilized strength, lower permeability
Pozzolans
Fly ash
Lower density, increased durability
Heavy-weight additives
Hematite
Ilmenite
Barite
Sand
Dispersants
Greater density
Weight-reducing
additives
Bentonite-attapulgite
Gilsonite
Diatomaceous earth
Perlite
Pozzolans
Lower density
USEPA (1982) suggests that most plugging needs can be met with a cement such as API Class
A, G, or H. API Spec 10 provides details on the specifications for cements and materials for well
cementing (API, 2002), and ASTM CI50 - 11/C150M - 11 gives the standard specifications for
Portland cement. Because of the corrosive nature of wet supercritical carbon dioxide and carbon
dioxide-rich fluids, however, owners or operators of GS projects should consider cements that
offer resistance to carbonic acid. This may entail use of non-Portland cements or Portland
cements with additives. In particular, additives that reduce the percentage of carbon dioxide-
reactive material (calcium hydroxide) in the cement will reduce susceptibility to carbonic acid
(e.g., Moroni et al., 2009). Pozzolans, such as fly ash or silica fume, may be added to boost the
portion of silica in a Portland-containing mixture and provide better resistance to carbon dioxide.
Also, dispersants reduce the water content in the slurry and produce cement with lower
permeability and reduced vulnerability to degradation (Calvert and Smith, 1994).
Non-Portland cements, which are non-reactive or less reactive with carbonic acid, include
pozzolan-lime cement, gypsum cement, microfine cement, expanding cements, calcium
aluminate cement, latex cement, resin or plastic cements, and sorel cements. In particular,
calcium aluminate cement (also referred to as high aluminate cement) blended with additives has
been found to be resistant to carbon dioxide-rich environments (Meyer, 2007). ASTM
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International (ASTM) standards exist for some specialty cements (e.g., ASTM C1438 - 99
(2005)el: Standard Specification for Latex and Powder Polymer Modifiers for Hydraulic
Cement Concrete and Mortar; ASTM C1707 - 10: Standard Specification for Pozzolanic
Hydraulic Lime for Structural Purposes). The UIC Program Class VI Well Construction
Guidance contains additional discussion of cements that may be suitable for carbonic acid-rich
environments. Also, newer commercial cements now available in the oil and gas industry are
designed specifically for carbon dioxide-rich environments such as those associated with GS or
enhanced oil recovery (EOR) operations.
Stresses due to variation in downhole pressure and temperature are known to contribute to
cement defects, including the formation of microannuli and loss of zonal isolation (Goodwin and
Crook, 1992; Thiercelin et al. 1998). Although downhole pressure and temperature conditions
will be more stable after plugging than during the injection phase of a project, cement properties
should be suitable for any anticipated tests and downhole conditions.
More recent literature (e.g., Liversidge and Agarwal, 2006; Le Roy-Delage et al., 2000;
Nagelhout et al., 2005) has explored the use of flexible, expanding cements for plugging
operations, including offshore projects. These cements include expanding agents (e.g., calcium
oxide-based) and additives to increase flexibility. The resulting systems have increased elasticity
and decreased compressibility and permeability, and they maintain strength. In a GS setting, the
superior sealing and decreased permeability of these cements may be beneficial in providing
protection from degradation of cement and resulting fluid migration. Owners or operators may
wish to consider the costs and benefits of such materials and, if interested, discuss their use with
the UIC Program Director.
Bentonite nodules have been studied as a plugging material for deep wells (e.g., Englehardt and
Wilson, 2001; Clark and Salsbury, 2003). Compressed sodium bentonite provides good plugging
capability because it hydrates (thereby providing swelling), and it has lower permeability than
cement. It can also be emplaced without the need for a rig and can be easily drilled out if the well
needs to be reentered. Bentonite nodules (1 to 6 inches in size) have been found to form a good
plug even in high salinity conditions. Compressed bentonite in the shape of bullets has been
found to produce good pressure containment as well (Towler et al., 2008). Compressed bentonite
is also flexible and can adjust its shape if the casing moves, reducing the risk of formation of
microannuli. However, research may still be needed on emplacement methods.
Because bentonite pellets cannot be pumped into the well, they need to be dropped through the
fluid. Care needs to be taken to avoid bridging of the pellets above the desired plug depth
resulting in potential improper plug placement. Compressed bentonite plugs also have poor
compressive strength and have limited pressure capabilities (USEPA, 2002). Compatibility of
bentonite plugs with carbon dioxide or carbon dioxide-rich brine remains to be evaluated.
Choices of plugging material will ultimately be addressed in the Injection Well Plugging Plan in
consultation with the UIC Program Director [40 CFR 146.92(b)(5)],
Other materials studied for use in well plugs include pumpable (fluor)silicone and perfluoro-
ether silicone elastomers (e.g., Bosma et al., 2000). Although the compatibility of these materials
with a carbon dioxide-rich environment has not been established, they may be sandwiched
between conventional cement plugs to provide extra sealing capability.
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2.6.3 Locations of Cement Plug Placement
The type and number of plugs to be installed, as well as the placement of each plug (top and
bottom), must be specified in the Injection Well Plugging Plan as required at 40 CFR
146.92(b)(3) and (4). In most cases, a continuous column of cement is not necessary, but plugs
should be placed at critical locations to prevent communication between the injection zone and
USDWs (Figure 5). EPA recommends that owners or operators emplace plugs: (1) above the
lowermost production and/or injection zone; (2) above, below, and/or through each USDW; (3)
at the bottom of intermedi ate and surface casings; (4) across any casing stubs (pulled casing
sections); and, (5) at the surface (USEPA, 1989). Owners or operators may also consider
emplacing cement across the injection zone's perforated interval by squeezing cement below a
retainer set above the injection zone. Plugs may also be placed at other depths and locations at
the UIC Program Director's discretion.
In horizontal wells it is suggested that a bridge plug be installed above the kickoff point, with a
cement plug on top of it. EPA also recommends that owners or operators consider emplacing
cement across perforated sections of laterals. In addition, if a vertical pilot hole has been drilled
below the kickoff point into a permeable formation, that portion of the hole should be plugged as
well.
Cement plug
Cement
Surface casing
Long string casing
Cement plug
Plugging fluid
Injection Zone
Confining Zone
Schematic of GS Injection Well Prior to Well Preparation for Plugging,
Note: Figurenotioscale After Preparation, and After Plugging and Abandonment
Before Well After Well
Preparation Preparation
After Plugging
and Abandonment
Long string casing
Plugging fluid
Bridge plug capped
with cement
Injection tubing
-Annulus
Long string casing
Borehole
ฆ Injection packer
Injection zone perforations
Total depth
* Cement
- Surface casing
Cement
Surface casing
Lowermost USDW Base
Figure 5. Schematic of Class VI Injection Well Prior to Well Preparation for Plugging,
After Preparation, and After Plugging and Abandonment.
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For protection of USDWs, API (1993) recommends that a 100-foot plug be set from below the
base of the lowermost USDWs to the base of the USDW. EPA recommends that plugs in GS
settings be at least that long. Furthermore, given the potential for the presence of carbonic acid
near a Class VI well, EPA strongly recommends that owners or operators consider longer plugs,
especially in critical zones such as above the injection zone.
2.6.4 Methods for Plug Emplacement
Plugs should be set sequentially from bottom of the well to the top, with adequate time in
between to allow setting. A bridge plug will likely be set to isolate the injection zone. Bridge
plugs may also be used to help position cement plugs at intermediate depths and prevent them
from migrating. After emplacing a cement plug and allowing it to set, it may be tested by
tagging, a method in which pipe is run into the well to locate the top of the plug. This indicates if
the top of the plug is at the desired depth and whether it has acquired strength. It does not,
however, indicate whether the cement has set properly throughout the entire plug. USEPA
(1989) recommends that plugs in critical locations or that are suspected to be of inadequate
quality be tagged.
Accepted and established methods for the emplacement of cement plugs that would be suitable
for a GS project include: the balance method; the retainer method; and the two-plug method.
Brief summaries for each are included below. The dump bailer method is generally not suitable
for plugging deep wells and is not discussed in this guidance. The method(s) for plug
emplacement that will be used for a specific project must be specified in the Injection Well
Plugging Plan [40 CFR 146.92(b)(6)],
2.6.4.1 Balance Method
The balance method is simple and commonly used, but requires a great deal of operator skill. A
drillpipe or tubing is run downhole, and cement is pumped through until the level of cement
outside the tubing equals the level inside (Figure 6). Tubing should be centralized to ensure even
flow of cement around the pipe. The tubing is then withdrawn from the well, excess cement is
reverse circulated out of the tubing, and the cement is left in place to set (Smith, 1976; API,
1993).
As noted above, movement of the plugging fluid can compromise the integrity of the plug. Use
of a small diameter tubing and slow, careful emplacement and withdrawal can be helpful in
minimizing disturbance. Fluid spacers or small amounts of non-chemically treated mud may be
used ahead of and behind the cement in the tubing to prevent contamination with the plugging
fluid if compatibility is a concern (API, 1993). Another factor in successful plugging is careful
calculation of cement, water, and displacement volumes. Further details and an example of
cement volume calculations are provided in USEPA (1989).
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Placement
Borehole
Cement
Placement tubing
run into hole
Cement-slurry
placed in hole
Level of cement-slurry
balanced
Placement tubing
removed
Source: USEPA, 1982
Note: Figure not to scale
Principles of the Balance Method
Figure 6. Principles of the Balance Method.
From: USEPA (1982).
2.6.4.2 Retainer Method
The cement retainer method is useful for setting plugs in uncased boreholes (e.g., an uncased
section of an abandoned well or older monitoring well) and can be used to cement across the
perforated casing in the injection zone. Retainers permit cement to be emplaced beneath the
packer under pressure, forcing cement into the surrounding formation. Different models of
cement retainers may be emplaced by tubing, drillpipe, or wireline. Some can be converted to
Draft VIC Program Guidance on Class VI Well 18
Plugging, Post-Injection Site Care, and Site Closure
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bridge plugs. Owners or operators should verify that any retainers used are drillable. A cement
plug should be emplaced above the retainer.
Exact procedures may vary depending upon the retainer selected. In the example below, the
retainer is attached to the bottom of the tubing. The tubing with the retainer is lowered to the
bottom of the well, and cement is pumped through the retainer and allowed to rise up in the hole
50-100 feet above the final depth of the retainer, forming a cement plug above the depth of the
retainer. The tubing is then pressurized, and cement is pumped under pressure below the retainer
into the surrounding formation. The retainer valve is then closed, the tubing is disengaged and
withdrawn, and the retainer remains in place with a plug of cement above it (Figure 7).
Additional details are provided in USEPA (1982).
S:\PROJECTS'iES10.0O35CADMUSEPA_DOCDEV'VRDRAW1NGS'iES 10Jป35_O2W.CDR 3-29-10
Ws,
3
Retainer run Cement-slurry Packer set and Placement tubing
into hole placed cement squeezed removed
Into formation
Source: USEPA, 1982
Note: Figure not to scale
Example of the Retainer Method
Figure 7. Example of the Retainer Method.
From: USEPA (1982).
2.6.4.3 Two-Plug Method
This method is more complex than the balance method, but provides advantages. Upper and
lower tubing plugs are used to separate the plugging fluid from the cement slurry, minimizing
cement contamination. It also offers good control over cement emplacement, which is especially
advantageous in deep wells.
Draft tJIC Program Guidance on Class VI Well
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In this method, the lower tubing plug proceeds down the tubing stopping at the depth of the
desired cement plug. The cement slurry is then pumped through the tubing. When the desired
amount of cement has been pumped, the top tubing plug follows. It is caught in a plug-catcher
tool in the tubing and does not pass into the well. A latching device prevents further
displacement of fluid, allowing good control over the amount of cement emplaced and the
location of the top of the cement plug. Further details are provided in USEPA (1982) and Smith
(1976) (Figure 8).
i
-Plug
catcher
- Cement
enters
annulus
Excess slurry
Top plug
caught
- Bottom plug
pumped out
u
Reverse circulation
cuts off top of
cement plug
ฆ Bottom plug
Source: USEPA, 1982
Note: Figure not to scale
Principles of the Two-Plug Method
Figure 8. Principles of the Two-Plug Method.
From: USEPA (1982).
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2.6.5 Considerations for Offshore Wells
Generally, plugging and abandonment of offshore injection wells will be similar to procedures
for onshore wells. As with onshore wells, cement plug locations should be selected to isolate the
injection zone and protect USDWs. There are, however, some additional considerations for
placing cement plugs near the ocean floor in offshore environments due to the mud found at and
below the sea floor. Any annuli in the well that are open to the mudline should be plugged to
prevent migration of mud or other fluids down into the well or to prevent fluids in the annulus
from migrating upward. Special materials and procedures may be necessary due to the lower
density and unconsolidated nature of the sediment above the mudline. One recommendation is to
place a top in the well within 150 feet of the mudline (Jirapongpipat, 2007).
Cementing in the mud environment near the ocean floor can be more difficult. The mud may mix
with the cement, or heavier cement can displace the mud and lose its shape. Cross flow in the
cementing area can also be problematic. These problems can be avoided by placing a barrier
between the mud and cement such as a bentonite pill or a spacer fluid, by using circulation
methods that circulate cement to the side but not vertically, and by using special cements such as
lightweight cements (King, 2009). Cement evaluation logs will also be important to ensure that a
proper cement job was obtained, especially above the mudline. In developing an Injection Well
Plugging Plan for offshore Class VI wells, EPA recommends that owners or operators consult
with professionals that specialize in well plugging for offshore projects.
2.7 Development and Submittal of Plugging Report
Within 60 days after plugging, the owner or operator must submit a plugging report to the UIC
Program Director [40 CFR 146.92(d)], The purpose of this report is to document that the
plugging activities approved in the Injection Well Plugging Plan [40 CFR 146.92(b)] or any
revisions to that plan were executed to the UIC Program Director's satisfaction and that the well
will not be a conduit for fluid movement. The report must be certified as accurate by the owner
or operator and by the person who performed the plugging operation, and the owner or operator
must retain the plugging report for 10 years following site closure [40 CFR 146.92(d); 40 CFR
146.91(f)(4)],
Although a well plugging report is not explicitly required for monitoring wells, EPA encourages
owners or operators to submit such reports. Proper plugging of monitoring wells is important for
the long-term protection of USDWs, and although documentation is ultimately required at the
time of site closure [40 CFR 146.93(f)(1)], prompt documentation of plugging done during the
PISC period will help to demonstrate non-endangerment of USDWs.
Minimum documentation to provide in the well plugging report includes the following
information, which will have been approved in the Injection Well Plugging Plan:
Results of tests to determine bottomhole pressure and mechanical integrity;
The type and number of plugs used;
Cement type, grade, weight, and quantities for plugs;
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Method of cement plug emplacement; and
Top and bottom of each cement plug.
A template with required elements for preparation of the well plugging report is provided in
Appendix C. In addition, EPA suggests that the following information on well preparation and
remediation also be included to demonstrate to the UIC Program Director that the well was in
good condition for the installation of the plugs:
Well flushing activities, required at 40 CFR 146.92(a), including fluid type and
volumes used;
Notes on removal of large debris;
Documentation of removal of downhole components (e.g., pressure transducer,
packer, shut-off devices);
Documentation of removal of injection tubing;
Reports on remedial activities (e.g., squeeze cementing records);
Plugging fluid type and volume used to establish static conditions; and
Notes on any plugs that were tagged.
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3 Post-Injection Site Care (PISC)
After the injection phase of a GS project, the project must be monitored as the plume and
pressure front will continue to pose a risk of endangerment to USDWs. This is because (1)
injected carbon dioxide will remain mobile for site and project-specific periods of time and may
continue to migrate away from the injection well(s); and (2) elevated pressure within the
injection zone, and in some cases overlying zones, will persist for a site-specific period of time
and continue to be a driver for fluid movement and may pose an endangerment to USDWs. (See
the UIC Program Class VI Well Area of Review Evaluation and Corrective Action Guidance and
the UIC Program Class VI Well Testing and Monitoring Guidance for additional discussion of
plume migration.) Therefore, PISC monitoring is required by the Class VI Rule in order to track
the evolution of the plume and pressure front and to demonstrate that USDWs are not
endangered after the injection phase of the project [40 CFR 146.93(b)], During PISC, EPA
encourages owners or operators to build on successful monitoring strategies employed during the
injection phase of the project. PISC monitoring strategies, including monitoring technologies and
frequency, are based on site-specific conditions and may change over time. This section
discusses monitoring techniques that may be used during PISC (Section 3.1) as well as PISC
duration (Section 3.2).
3.1 PISC Monitoring
PISC monitoring is required to show the position of the carbon dioxide plume and pressure front
and demonstrate that USDWs are not being endangered [40 CFR 146.93(b)], To meet these
objectives, PISC monitoring programs should be designed to track the location of carbon dioxide
and other mobilized constituents within the injection zone, track fluid pressures, and monitor the
integrity of monitoring wells and former injection wells.
Types of monitoring that may be applicable during PISC include mechanical integrity testing of
former injection wells and monitoring wells, pressure measurements and analysis of ground
water geochemistry (via monitoring wells), surface and downhole geophysical surveys and logs
for imaging the carbon dioxide plume or any potential leakage, and surface air and/or soil gas
monitoring. These monitoring strategies are discussed in the UIC Program Class VI Well Testing
and Monitoring Guidance as they also pertain to monitoring during the injection phase of a GS
project. Due to similarities in the application of monitoring strategies during the injection and
PISC phases of a GS project, EPA refers the reader to the UIC Program Class VI Well Testing
and Monitoring Guidance for a more detailed discussion of these monitoring techniques. This
section is intended to supplement the UIC Program Class VI Well Testing and Monitoring
Guidance by presenting additional considerations that pertain solely to monitoring during PISC.
EPA has designed a regulatory framework that allows for development of a tailored, site-specific
PISC and Site Closure Plan that meets minimum Class VI requirements and is approved by the
UIC Program Director. The PISC and Site Closure Plan, which is required by the Class VI Rule
to be submitted with the Class VI permit application [40 CFR 146.93(a); 40 CFR 146.82(a)(17)],
is intended to allow for the design of a site-specific PISC monitoring strategy (see Section 3.1.1).
While allowing for site-specific conditions that will dictate the details of PISC monitoring, EPA
anticipates that some of the recommendations in this and the UIC Program Class VI Well Project
Plan Development Guidance will be applicable to most GS projects. Generally, EPA encourages
Draft UIC Program Guidance on Class VI Well
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owners or operators of GS projects to use monitoring strategies during PISC that were successful
during the injection phase of the project. Similarly, EPA encourages a frequency and level of
monitoring during the beginning of PISC that is similar to monitoring at the end of the injection
phase. As potential risks to USDWs decrease over time, as reflected by monitoring data, EPA
encourages owners or operators to consult with the UIC Program Director regarding the
frequency and amount of site monitoring. In this way, PISC monitoring frequency can be
evaluated to establish the most appropriate monitoring intervals, and PISC monitoring frequency
may increase or decrease before eventually ending with final site closure (see Section 3.2).
3.1.1 PISC and Site Closure Plan and Reevaluation
GS project owners or operators are required to prepare, maintain, and comply with a plan for
PISC and site closure [40 CFR 146.93(a)], The PISC and Site Closure Plan must provide a
description of proposed PISC monitoring locations, methods, and frequencies [40 CFR
146.93(a)(2)(iii)]. This plan is submitted with the permit application, is subject to UIC Program
Director approval, and must be reevaluated, as discussed below. The purpose of the plan is to
promote the development of a site-specific strategy for PISC monitoring and to communicate
that strategy to the UIC Program Director prior to project approval. The PISC and Site Closure
Plan will describe the anticipated methods that will be used to determine risk to USDWs during
PISC; under what conditions risk of endangerment no longer exists, resulting in project site
closure; and under what conditions the frequency of PISC monitoring may be reduced [40 CFR
146.93(a)(2)], The structure of the plan and additional details are discussed in the UIC Program
Class VI Well Project Plan Development Guidance.
Although the PISC and Site Closure Plan, including post-injection monitoring strategies, is
initially established prior to the start of the project, owners or operators may modify the plan and
resubmit it to the UIC Program Director at any time during the life of the project. The UIC
Program Director will make a decision regarding approval within 30 days [40 CFR
146.93(a)(4)], This approach allows the owner or operator to incorporate information obtained
during the course of the project and refine the PISC and Site Closure Plan as needed. Owners or
operators are encouraged to evaluate the necessity of revising the plan within one year of an AoR
reevaluation (for details regarding AoR reevaluation, see the UIC Program Class VI Well Area
of Review and Corrective Action Guidance), following any significant changes to the facility
such as an increase in the number of injection or monitoring wells in the project AoR, or on a
schedule to be determined by the UIC Program Director. The purpose of the reevaluation is to
incorporate any new monitoring data or changes to the site computational model that warrant
changes in PISC monitoring, or any changes in the methodology proposed to be used to
demonstrate non-endangerment of USDWs.
At the cessation of injection, owners or operators are required to submit an amended PISC and
Site Closure Plan or demonstrate that no revisions are necessary [40 CFR 146.93(a)(3)],
Revisions to the plan or the demonstration that no revisions are necessary should be based on
monitoring data collected during injection and newer revisions of the site computational model.
Box 3-1 provides an example of planned PISC monitoring at a hypothetical project and revisions
based on AoR reevaluation.
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Box 3-1. Hypothetical Example of PISC Monitoring Plan and Revision.
This box presents an example summary of a PISC monitoring plan for a hypothetical
GS project. This example is based on the hypothetical GS project used throughout the
UIC Program Class VI Well Area of Review Evaluation and Corrective Action
Guidance. The PISC monitoring plan is a component of the PISC and Site Closure Plan,
and it describes proposed monitoring techniques and frequencies (Section 3.1.1). The
hypothetical project consists of three injection wells, and injection is planned for thirty
years (Figure 9).
The proposed PISC monitoring program submitted with the PISC and Site Closure Plan
in the initial permit application calls for an initial continuation of monitoring conducted
during the injection phase, as follows:
Fluid sampling and pressure monitoring using a series of 18 monitoring wells;
some are screened within the injection zone, and others are screened above the
primary confining zone:
o Monitoring wells MW-4, MW-6, MW-13, MW-16, MW-17, and MW-
18 are proposed to be constructed after injection begins, and the
remaining wells are proposed to be constructed prior to injection. All
wells are proposed to be constructed prior to PISC.
o Fluid geochemical and pressure monitoring are proposed to be
conducted once every 6 months at the beginning of PISC and to decrease
over time based on pre-defined criteria that are listed in the plan for each
monitoring well. In this way, the number of monitoring wells used will
decrease over time,
o Monitoring wells will be closed in accordance with site closure
requirements at the point when they are no longer in use.
Indirect geophysical surveys are to be conducted initially once every two years,
with frequency decreasing in future years based on repeat surveys demonstrating
that the carbon dioxide plume is migrating at rates slower than pre-defined
criteria.
The internal integrity of the monitoring wells will be assessed via a pressure test
during every sampling event. External integrity of all monitoring wells will be
evaluated at least once every three years during PISC while each well is active.
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Box 3-1. Hypothetical Example of PISC Monitoring Plan and Revision.
The initial PISC and Site Closure Plan also describes the site-specific PISC timeframe
and monitoring criteria that will be used to demonstrate non-endangerment of USDWs.
In this case:
The PISC timeframe is assumed to be 50 years (for a total project timeframe of
80 years). The Plan does not include a demonstration that would allow for an
alternative PISC timeframe other than 50 years.
Several risk-based site-specific criteria are given that will be used to
demonstrate non-endangerment of USDWs. These include:
o Return of pressure within the injection zone to pre-injection conditions at
all monitoring wells that remain in use.
o Stable or decreasing levels of carbon dioxide in sampled fluids,
o Stable or increasing pH in sampled fluids above the confining zone,
o Levels of any drinking water contaminants are below actionable levels
(i.e., maximum contaminant levels or secondary standards) and are
stable or decreasing over time for at least two years in any fluids
sampled above the primary confining zone,
o The results of at least three consecutive geophysical surveys that
demonstrate the separate-phase carbon dioxide plume is no longer
growing in size, either laterally or vertically,
o All artificial penetrations, including former injection and monitoring
wells, within 1 mile of the extent of the separate-phase plume and
pressure front, have been evaluated and determined to not pose a risk of
endangerment to USDWs. This may include monitoring of USDWs and
soil gas in the direct vicinity of all artificial penetrations.
The UIC Program Director approved of these specifications listed in the initial PISC
and Site Closure Plan that was submitted with the permit application. After the
commencement of injection, the AoR was reevaluated every 5 years. During the first
three AoR reevaluations (5 years, 10 years, 15 years), it was demonstrated that the
initial AoR delineation was adequate, and no model calibration was necessary. At 20
years, based on comparison of modeling and monitoring data, it was determined that the
computational model should be recalibrated, and a revised AoR resulted. The revised
AoR extended further towards the east than the initial AoR (Figure 9).
Draft UIC Program Guidance on Class VI Well
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Box 3-1. Hypothetical Example of PISC Monitoring Plan and Revision
Injection
well #1
ซ<>
Injection
well #2
Injection
well #3
5ป0
MW-9
Explanation
Injection
w#ll #1
O Injection well
MW-1
# Monitor well
ซซ ^ Initially delineated area of i
Area of review after reevaluation at 20 years
Sourco: Danisi B Stephens & Associates Inc.
MW-13
(revised)
Figure 9. Hypothetical GS Project Showing Initial and Revised AoR.
The location of MW-13 is revised after AoR reevaluation, as shown
by the orange arrow.
Upon reevaluation of the AoR at 20 years, the PISC and Site Closure Plan was also
revised. The following major changes were made to the plan;
MW-13 had not been constructed as of 20 years after injection. The location of
MW-13 was revised to be located in the predominant direction of plume
migration and outside of the revised AoR (Figure 9). The plan specifies that
MW-13 will remain as an active monitoring well until final site closure.
Artificial penetrations in the newly identified area of eventual plume migration
were identified, and a plan was outlined for assessment and monitoring of those
penetrations.
New criteria for the USDW non-endangerment demonstration were added for
MW-13. Non-endangerment criteria include no detection through direct and
indirect monitoring of separate-phase carbon dioxide fluids from MW-13, no
presence of elevated pressure, and no change in geochemistry that indicates
fluid changes beyond allowable levels. If any of these criteria are violated, the
owner or operator has committed to reevaluation of the PISC and Site Closure
Plan at that time and establishment of additional non-endangerment criteria.
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3.1.2 Use of Monitoring Wells in PISC Monitoring
During the injection phase of the GS project, the use of monitoring wells is required. Data
acquired using monitoring wells is necessary to gather in situ measurements of fluid pressures
[40 CFR 146. 90(g)(1)], collect ground water samples above the confining zone for geochemical
analysis [40 CFR 146.90(d)], and provide verification of geophysical surveys.
During the beginning of PISC, EPA encourages owners or operators to continue to use any
monitoring wells screened within the injection zone, above the primary confining zone, and
within any USDWs. Owners or operators may use monitoring wells that have been previously
constructed and used for monitoring during the injection phase of the project. Former carbon
dioxide injection wells may also be considered for use as monitoring wells. Additional
monitoring wells may need to be installed during PISC if there is evidence from existing
monitoring and/or modeling that the carbon dioxide plume may be continuing to migrate away or
in new directions vertically or laterally from the location of the injection well (see Box 3-1).
These wells should be screened in any zone(s) anticipated to exhibit separate-phase carbon
dioxide, such as in newly identified plume migration areas. To directly monitor for USDW
endangerment, wells may also be located within overlying USDWs. If the owners or operators
determine that additional monitoring wells are necessary for protection of USDWs, they must
revise the PISC and Site Closure Plan and re-submit it to the UIC Program Director for approval
prior to the construction of any new wells [40 CFR 146.93(a)(4)], At the time that the owner or
operator, in consultation with the UIC Program Director, determines that a monitoring well is no
longer needed for site monitoring, EPA encourages the owner or operator to plug such wells in a
manner that will not lead to the endangerment of a USDW. All monitoring wells must be
plugged prior to site closure [40 CFR 146.93(e)],
Constituents of interest to monitor using monitoring wells may include carbon dioxide, major
anions and cations, organics, total dissolved solids (TDS), pH, temperature, any mobilized or
injected drinking water contaminants of concern, the presence of formation fluids that may be
displaced as a result of injection, and, if required by the UIC Program Director, tracers that have
been co-injected with carbon dioxide during the project. The UIC Program Class VI Well
Testing and Monitoring Guidance discusses appropriate methods for collection and analysis of
ground water samples from monitoring wells, interpretation of results, and reporting to the UIC
Program Director. Generally, increasing carbon dioxide concentration, decreasing pH, or a
change in the geochemical signature of water may indicate fluid migration. A stabilization of
these parameters may indicate that fluid migration rates are decreasing, particularly at those
monitoring wells located farther from the injection well(s).
Monitoring well data may become more ambiguous and difficult to interpret at the outer portions
of the carbon dioxide plume, depending on the number and location of monitoring wells.
Concentrations of key constituents will be smaller in these areas and more difficult to
differentiate from background sources. Additionally, the supercritical carbon dioxide plume may
exhibit thin, laterally extensive zones at the top of the injection zone (i.e., gravity tongues, see
e.g., Ide et al., 2007). Water sampled from monitoring wells with a relatively long perforated
interval may dilute carbon dioxide present in this thin zone. Uncertainty analysis of monitoring
well data may include plotting of historical trends for comparison to recently collected data and
conducting statistical comparisons for significance. Although increasing the number of
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monitoring wells in the network may be costly, installation of new monitoring wells may be used
to reduce uncertainty in interpretation of ground water monitoring results. Methods exist for
determination of well placement to reduce uncertainty (e.g., Meyer and Brill, 1988). As
discussed below, geophysical methods may also be used to reduce monitoring data uncertainty.
In addition to monitoring to ensure ground water quality, monitoring wells may be used to
directly measure reservoir pressure through the use of pressure transducers or, for the case of
relatively shallow wells, the measurements of the static fluid level within the well. Methods for
determination of reservoir pressure from monitoring wells are also described in the UIC
Program Class VI Well Testing and Monitoring Guidance. During PISC, fluid pressures within
the injection zone are anticipated to decrease over time because injection is no longer occurring
and pressure dissipates. Elevated fluid pressure is a key driver of risks to USDWs, and EPA
therefore encourages pressure monitoring to be a primary focus of PISC monitoring. An
observed sustained decrease in fluid pressures over time will be a key justification for a UIC
Program Director to consider allowing PISC monitoring to decrease and eventually end.
Importantly, the rate of fluid pressure decline may not be steady within particular zones due to
heterogeneity in the subsurface, as it depends on site-specific geologic properties of the injection
zone and overlying zones. Fluid pressures may also fluctuate due to external factors, including
local fluid extraction and injection, and ground water recharge.
3.1.3 Geophysical Surveys during PISC
The Class VI Rule, at 40 CFR 146.90(g), requires the use of both indirect (i.e., geophysical) and
direct methods for carbon dioxide plume and pressure-front tracking during the injection phase
of a project, unless the UIC Program Director determines, based on site-specific considerations,
that indirect methods are not suitable. Generally, these same site-specific considerations apply to
the use of geophysical techniques during PISC. If geophysical techniques have been used during
the injection phase of the project, EPA encourages the owner or operator to continue periodic
geophysical surveys during PISC.
Geophysical monitoring techniques provide broad, non-point measurements and can be used to
estimate the extent of the separate-phase carbon dioxide plume and, in some cases, pore pressure.
Although they are not quantitative and may be subject to uncertainties in interpretation,
geophysical methods complement the point measurements collected using monitoring wells.
Applicable geophysical methods that may be used for PISC monitoring include seismic,
electromagnetic, gravity surveys, and ground displacement (e.g., interferometric synthetic
aperture radar, or InSAR). As discussed in the UIC Program Class VI Well Testing and
Monitoring Guidance, monitoring uncertainty is reduced when monitoring well and geophysical
data are both collected and interpreted in a complementary fashion.
Time-lapse application of geophysical surveys involves repeat measurements in the same
locations over time to evaluate changes in subsurface conditions. Comparison among sequential
surveys is contingent upon geophysical methods being geo-referenced and, in some cases, being
located at exactly the same coordinates. Changes in near-surface conditions such as soil-water
saturation may also have a large impact on comparability among geophysical surveys. Due to the
potentially long PISC duration, repeatability and comparability of repeat geophysical surveys
may be challenging at GS projects. EPA encourages 'truthing' of geophysical data with data
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collected at monitoring wells to help potentially reduce error from changes in near-surface
conditions and aid in comparison of repeat geophysical surveys.
These geophysical monitoring techniques are used in many applications including the injection
of carbon dioxide for EOR and enhanced gas recovery (EGR). Some geophysical techniques as
applied to Class VI projects, however, remain in the research and development stage as the GS
industry continues to evolve (NETL, 2009). EPA anticipates that application and interpretation
of geophysical monitoring techniques will improve during the lifetime of early GS projects. As
with other injection well technologies and UIC well classes, EPA encourages owners or
operators to consider adopting any newly accepted geophysical techniques that develop during
the lifetimes of their GS projects, including during PISC, in consultation with their UIC Program
Directors.
3.1.4 Additional PISC Monitoring
In addition to tracking the carbon dioxide plume and pressure front using monitoring wells and
geophysical techniques, owners or operators may need to continue additional monitoring to
demonstrate that USDWs are not being endangered [40 CFR 146.93(b)], For example, EPA
encourages owners or operators to perform periodic mechanical integrity and corrosion testing of
monitoring wells to ensure that they maintain integrity and do not allow for fluid movement that
may endanger a USDW. Furthermore, other monitoring techniques, including surface air and/or
soil gas monitoring, may be used to complement geophysical techniques and monitoring wells in
evaluating endangerment of USDWs. The reader is referred to the UIC Program Class VI Well
Testing and Monitoring Guidance for further details regarding these monitoring techniques.
3.1.5 Frequency of PISC Monitoring
The appropriate frequency of monitoring and reporting is influenced by site-specific conditions
and will therefore change over time during PISC. During the initial stage of PISC, EPA
encourages monitoring at a similar frequency as was performed during the end of the injection
phase. The frequency of PISC monitoring activities may be reduced over time if a demonstration
can be made that the risk of endangerment to USDWs is decreasing and monitoring data are
relatively stable. Some parameters (e.g., pressure, temperature) may be monitored continuously
using permanent downhole equipment. For those parameters, summary data (monthly average,
minimum, and maximum values) may be submitted with the same frequency as parameters that
are periodically measured, such as geochemical data.
EPA encourages the owner or operator to submit with the PISC and Site Closure Plan specific
benchmarks that can indicate a demonstrated decrease in risk to USDWs, thus allowing the UIC
Program Director to consider decreasing the frequency of PISC monitoring. For example,
reduction in PISC monitoring frequency may be based on:
Observation of continual decrease in reservoir pressure toward pre-injection conditions;
Steady or favorable trends in observed geochemical monitoring data over a pre-defined
period;
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Several repeat demonstrations of monitoring well integrity with MITs; and
A demonstration that reduced monitoring will not lead to endangerment of USDWs.
When benchmarks listed in the PISC and Site Closure Plan are met, the owner or operator is
encouraged to consult with the UIC Program Director regarding reduction in the frequency of
monitoring at the site.
3.1.6 Reporting of PISC Monitoring Results
The GS project owner or operator must submit a proposed schedule for reporting the results of
PISC monitoring with the PISC and Site Closure Plan [40 CFR 146.93(a)(2)(iv)]. EPA
encourages the owner or operator to submit monitoring results on an annual basis, or more
frequently, dependent on site conditions. EPA recommends that the following information be
submitted with all reports:
A list of all monitoring events that have taken place during the reporting period and all
monitoring dates;
Identification of any data gaps;
Identification of any changes to the monitoring program during the reporting period (e.g.,
drilling of new monitoring wells, closure of monitoring wells);
Presentation, synthesis, and interpretation of the entire historical data set of monitoring
results, with respect to any change in risk of endangerment to USDWs;
Any necessary changes to the project PISC and Site Closure Plan to continue protection
of USDWs;
For ground water geochemistry monitoring using wells:
o The most recent and up-to-date historical database of all ground water monitoring
results and Quality Assurance/Quality Control (QA/QC) monitoring results;
o Interpretation of any changing trends and evaluation of fluid leakage and
migration, including uncertainty analysis (if appropriate). This may include
graphs of relevant trends and interpretive diagrams (e.g., Piper and Stiff
diagrams);
o A map showing all monitoring wells and indicating those wells that are believed
to be in the location of the separate-phase carbon dioxide plume;
o An evaluation of data quality for each sampling event;
o If required by the UIC Program Director, copies of all laboratory analytical
reports;
o Records of calibration of all field instrumentation;
o A description of all sampling equipment and sampling methods used;
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o Sample chain of custody records;
o The name and contact information for the EPA-certified laboratory conducting the
analysis; and
o Documentation of the monitoring well construction specifications (or reference to
previously submitted documentation), sampling procedure, laboratory analytical
procedure, and QA/QC standards.
For ground water pressure monitoring:
o Measured depth to fluid, or pressure transducer readings in all wells, fluid density,
and fluid temperature;
o If using pressure transducers, records of the most recent calibration or verification
of the measurement instruments;
o Records of the surveying of wellhead and measurement point elevations (or
reference to previously submitted documentation);
o Calculated pressure in all wells; and
o Time-series graphs and pressure or head maps used in interpretation of pressure
data.
For geophysical surveys:
o A description and technical justification of all survey techniques and
methodologies used (or reference to previously submitted documentation);
o A map showing the location of all survey equipment positions during the test;
o If required by the UIC Program Director, all raw data collected by the survey
equipment, a description of all data processing steps taken, and the major
assumptions used during data processing;
o An interpretation of all geophysical surveys relating to the position of the plume
and/or pressure front, and fluid leakage, including any available information on
method sensitivity and any out of zone anomalies that require follow up; and
o Maps showing the interpreted location of separate-phase carbon dioxide in the
injection zone and its location in any additional zones in which it was detected.
3.2 PISC Monitoring Timeframe
As required by the Class VI Rule, the default PISC monitoring timeframe is 50 years after the
cessation of injection [40 CFR 146.93(b)(1)], However, at the time of permit submission, the
owner or operator may propose a PISC timeframe other than 50 years [40 CFR 146.93(c)], As
discussed below, the proposal for an alternative PISC timeframe must be based on a detailed
demonstration that the project will no longer cause a risk of endangerment to USDWs at the end
of the proposed timeframe. The proposed timeframe is subject to UIC Program Director
approval. The PISC timeframe, either 50 years or an alternative timeframe, must be provided in
the PISC and Site Closure Plan [40 CFR 146.93(a)(2)(v)].
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Regardless of the PISC timeframe defined in the PISC and Site Closure Plan, the owner or
operator must continue PISC monitoring until the owner or operator has demonstrated and the
UIC Program Director has approved the demonstration that there is no longer a risk of
endangerment to USDWs [40 CFR 146.93(b)(3)], If the owner or operator can demonstrate prior
to the end of the pre-defined PISC timeframe that there is no longer risk of endangerment to
USDWs (hereafter referred to as the USDW non-endangerment demonstration), the UIC
Program Director may approve site closure. Alternatively, if at the end of the pre-defined PISC
timeframe there is evidence of risk of endangerment to USDWs, the UIC Program Director may
require PISC to continue until those risks no longer exist [40 CFR 146.93(b)(4)],
It is important to note that, as discussed above (Section 3.1.5), PISC monitoring scope and
frequency may change over time and may decrease substantially over time based on site
conditions. For example, geochemical monitoring using wells may decrease from a frequency of
quarterly initially after injection ceases, to annually at the end of PISC. In this way, the burdens
associated with PISC may decrease over time, even prior to the end of PISC. Any changes to the
monitoring program must be based on pre-defined criteria in the PISC and Site Closure Plan or
be proposed in a revised PISC and Site Closure Plan that is subject to UIC Program Director
approval [40 CFR 146.93(a)(4)],
3.2.1 Class VI Rule Default Timeframe
The default PISC timeframe required by the Class VI Rule is 50 years [40 CFR 146.93(b)(1)],
Unless the owner or operator proposes and the UIC Program Director approves an alternative
timeframe (see Section 3.2.2), the owner or operator should be prepared to continue PISC
monitoring for 50 years after the cessation of injection and should base all planned data
collection and reporting on this PISC duration. EPA defined the default PISC timeframe based
on a review of research studies, industry reports, and existing environmental programs. Owners
or operators should also refer to the UIC Program Class VI Financial Responsibility Guidance
for information on demonstrating that monitoring costs and any potential leakage encountered
during PISC can be covered financially.
3.2.2 Alternative PISC Timeframe
The owner or operator has the option of submitting to the UIC Program Director a demonstration
for a PISC timeframe other than the 50 year default [40 CFR 146.93(c)], This application,
submitted with the Class VI permit application, is based on a demonstration that an alternative
timeframe is appropriate and ensures non-endangerment of USDWs, and it is based on detailed
site-specific analyses. The Class VI Rule at 40 CFR 146.93(c)(1) establishes several data sources
and analyses that must be considered and documented in this demonstration and that must be
considered by the UIC Program Director. Also, 40 CFR 146.93(c)(2) lists additional criteria that
must be met.
The alternative PISC timeframe demonstration should state the timeframe requested by the
owner or operator and provide substantial documentation to support the petition. The UIC
Program Director will evaluate the demonstration and will verify that the methods used are
consistent with accepted protocols and requirements in the Class VI Rule. EPA suggests that to
meet the requirements at 40 CFR 146.93(c), a demonstration of an alternative PISC timeframe
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should include the sections listed below. The owner or operator is encouraged to consult with the
UIC Program Director regarding additional information that should be submitted based on site-
specific conditions [40 CFR 146.93(c)(xi)].
3.2.2.1 Modified PISC Timeframe
The owner or operator may, at any time during the life of a GS project, submit information to
support establishing a revised PISC timeframe other than the timeframe initially established in
the original PISC and Site Closure Plan (or subsequent revisions). This demonstration must be
based on monitoring and operational data collected during site operations and modeling of the
extent of the carbon dioxide plume and pressure front [40 CFR 146.93(c)], EPA recommends
that if the owner or operator opts to establish a PISC timeframe as part of a PISC and Site
Closure Plan update, they should submit information that meets all of the criteria at 40 CFR
146.93(c) to demonstrate that the timeframe is appropriate and protective of USDWs.
This option is available to either amend an alternative PISC timeframe that was included in the
original PISC and Site Closure Plan submitted with the Class VI permit application or to justify
that an alternative timeframe is appropriate if the Class VI permit included the default PISC
timeframe. If the UIC Program Director approves the alternative PISC timeframe, it would be
incorporated into the PISC and Site Closure Plan and the Class VI operating permit. Such a
change would require the UIC Program Director to modify the Class VI permit [40 CFR
144.39(a)(5)(iv)]. A permit modification under 40 CFR 144.39 would require notification to the
public and an opportunity for comment.
EPA acknowledges that some owners or operators of Class VI wells may plan to eventually
produce the carbon dioxide from the injection zone or are interested in preserving this option
(e.g., to sell the carbon dioxide for EOR/EGR). Owners or operators are encouraged to consider
the planned withdrawal of the carbon dioxide as a factor in developing an alternative PISC
timeframe or revising their PISC timeframe during the life of the GS operation. EPA
recommends that owners or operators plan a post-injection monitoring period and regime that
extends for at least as long as the carbon dioxide is to remain in the ground and until a significant
quantity of it is produced such that a demonstration of non-endangerment can be made that
pressures and mobile carbon dioxide do not pose a risk to USDWs. As withdrawal of the carbon
dioxide proceeds and subsurface pressures begin to decline, the owner or operator may choose to
discuss modifying the monitoring schedule (or plans for conducting the non-endangerment
demonstration) with the UIC Program Director. However, PISC must continue until pressure
reductions and plume stabilization are observed and non-endangerment can be demonstrated
pursuant to requirements at 40 CFR 146.93(b)(1). The UIC Program Director will not be able to
authorize site closure until non-endangerment is demonstrated based on monitoring data, as
required at 40 CFR 146.93(b)(3). The owner or operator should also recognize that if planned
production of the carbon dioxide does not occur, the PISC and Site Closure Plan might need to
be amended and the permit modified following the requirements at 40 CFR 144.39(a)(5)(iv).
EPA encourages the owner or operator and the UIC Program Director to coordinate and discuss
monitoring and operating data and other information about the facility if the owner or operator
seeks to amend the PISC timeframe. See the UIC Program Class VI Well Project Plan
Development Guidance for additional information on preparing and updating the PISC and Site
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Closure Plan and the UIC Program Class VI Implementation Manual for State Directors for
additional information about the procedures for modification of Class VI permits and the related
plan amendments.
3.2.2.2 Results of Computational Modeling Performedfor Delineation of the AoR [40 CFR
146.93(c)(i)]
The Class VI Rule requires that the AoR be delineated using sophisticated computational
modeling that accounts for separate phase flow of carbon dioxide and water [40 CFR 146.84],
Computational modeling performed for AoR delineation is discussed in the UIC Program Class
VI Well Area of Review Evaluation and Corrective Action Guidance. EPA recommends that the
alternative PISC demonstration be based in part on the results of this computational modeling.
Modeling results may be used to demonstrate the timeframes of pressure decline and rates of
plume migration after injection ceases (see below). EPA recommends that comprehensive results
of computational modeling, including results for the post-injection period, be presented as well.
For more information on how to report modeling results, please see the UIC Program Class VI
Well Area of Review Evaluation and Corrective Action Guidance. Importantly, EPA
recommends that model uncertainty analysis, including sensitivity analyses and evaluation of
model calibration, be presented with any model submittals. Model uncertainty analysis is
discussed in the UIC Program Class VI Well Area of Review Evaluation and Corrective Action
Guidance. Presentations of modeling results and additional criteria for modeling as they pertain
to PISC are discussed in the following sections.
3.2.2.3 Predicted Timeframe for Pressure Decline [40 CFR 146.93(c)(1)(H)]
A prediction of the timeframe for pressure decline upon the cessation of injection must be
included with the alternative PISC demonstration [146.93(c)(l)(ii)]. EPA recommends that the
prediction of pressure decline be based at least in part on results of computational modeling
performed for delineation of the AoR. Importantly, any modeling used for the alternative PISC
demonstration must be calibrated to existing site data where sufficient data are available [40 CFR
146.93(c)(2)(iv)].
Fluid pressures that pose a risk of endangerment to USDWs are discussed in detail in the UIC
Program Class VI Well AoR Evaluation and Corrective Action Guidance. A threshold minimum
pressure within the injection zone, termed the 'pressure front' (Pi,/), is defined by calculation of
the pressure increase within the injection zone that could potentially force fluids through a
hypothetical open conduit into an overlying USDW:
pi,f =pu+pig- (zu - zi) [Eci-1 ]
where Pu is the initial pressure within the lowermost USDW, p, is the fluid density of the
injection zone, z* and z are the representative elevation of the USDW and injection zone,
respectively, and g is the acceleration due to gravity. Importantly, Eq. 1 is only valid for GS
projects that are not located in over-pressurized formations (i.e., the hydraulic head in the
injection zone is equal to or lesser than the hydraulic head in the USDW prior to injection).
Regions of the injection zone with pressures equal to or greater than Pif are at enhanced risk of
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USDW endangerment. When pressures decline to less than PUf, there is no longer risk of
endangerment from increased pressures within the injection zone.
The owner or operator is encouraged to identify the timeframe after cessation of injection when
pressures are less than or equal to i\/. Alternatively, the owner or operator is encouraged to
identify the timeframe after which pressures will decline to pre-injection conditions. The
estimated timeframes may be based on computational modeling results, and/or additional
quantitative analysis. See the UIC Program Class VI Well Area of Review Evaluation and
Corrective Action Guidance for further discussion of pressure calculation. The owner or operator
is also required to identify the distance between the injection zone and the nearest USDWs above
and/or below the injection zone [40 CFR 146.93(c)(l)(x)]. As shown by Eq. 1, this distance is a
key determinant of the threshold pressure that may lead to fluid movement that endangers a
USDW.
The rate of pressure decay is a function of injection zone permeability, compressibility, the
injected volume of carbon dioxide, the areal extent and thickness of the formation, and the
presence of lateral strati graphic confining features. The sensitivity of these parameters must be
evaluated and related uncertainty assessed when making a demonstration [40 CFR 146.93
(c)(2)(vi)].
3.2.2.4 Predicted Rate of Plume Migration [40 CFR 146.93(c)(l)(iii)J
A prediction of the timeframe for carbon dioxide plume migration to cease must be included [40
CFR 146.93(c)(l)(iii)] and should be based at least in part on results of computational modeling
performed for delineation of the AoR. The owner or operator is encouraged to estimate, based on
the modeling results, the timeframe for separate-phase carbon dioxide to cease moving/growing
laterally and vertically away from the injection wells. Modeled plume migration rates will be
sensitive to the dip of the confining zone/injection zone interface, permeability, porosity, and
relative-permeability characteristic curve parameters of the injection and confining zones. If the
site geology includes a structural trap (e.g., dome, fault, or stratigraphic pinch-out), horizontal
migration of carbon dioxide will be limited once the plume reaches such structural features. This
should be taken into account when predicting plume migration and formulating PISC plans. The
sensitivity of these parameters should be evaluated and related uncertainty assessed [40 CFR
146.93(2)(vi)].
EPA recognizes that in some cases, modeled plume migration rates may be very slow while not
completely "stopping." Owners or operators are encouraged to evaluate the time it would take for
the plume to reach potential receptors (e.g., active or abandoned wells). When the plume is
migrating so slowly that this timeframe becomes exceedingly long (e.g., hundreds or thousands
of years), the plume migration rate may be considered sufficiently minor as to no longer pose a
risk to USDWs.
3.2.2.5 Trapping Processes and Predicted Rate of Carbon Dioxide Trapping {40 CFR
146.93(c)(1) (iv)-(vi)]
Specific processes leading to carbon dioxide trapping at the site must be identified, including
physical entrapment and immobilization at the injection zone/confining zone interface, capillary
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trapping, dissolution of carbon dioxide into ground water, mineralization, and any additional
relevant processes [40 CFR 146.93(c)(l)(iv)]. The trapping rate for each of these processes must
also be estimated [40 CFR 146.93(c)(l)(v)]. The physical trapping effects of structural features
(e.g., domes, faults, or pinch-outs) should also be considered in predicting carbon dioxide
trapping. These predictions may be based in part on the results of computational modeling
performed for AoR delineation and should incorporate a good geologic conceptual model, which
should be updated during injection operations as part of the AoR reevaluation required at 40
CFR 146.84(e). EPA expects, however, that prediction of dissolution and mineralization rates
may require additional quantitative methodologies beyond what will typically be conducted for
AoR modeling. For example, detailed geochemical modeling, which is expected to be beyond the
scope of many AoR modeling efforts, may be necessary to estimate trapping rates. Owners or
operators may also conduct literature studies or perform laboratory tests or field-specific studies
to better estimate trapping rates. Alternatively, the owner or operator may estimate trapping rates
based on observations at similar projects, under similar conditions. The owner or operator is
encouraged to consult the UIC Program Director in choosing an appropriate methodology for
estimation of trapping rates at the site.
Relevant assumptions and parameters used for estimation of trapping rates for each process
should be discussed. Additionally, the results of laboratory analyses, research studies, and/or
field studies used to estimate trapping rates must be identified [40 CFR 146.93(c)(l)(vi)]. The
extent to which the owner or operator expects that carbon dioxide trapping will lead to changes
in risks to USDWs over time should be discussed.
3.2.2.6 Confining Zone Characterization [40 CFR 146.93(c)(l)(vii)J
The owner or operator is required to present results of characterization of the confining zone,
including a demonstration that it is free of transmissive faults, fractures, and micro-fractures, and
that it is of appropriate thickness, permeability, and integrity to impede fluid movement [40 CFR
146.93(c)( 1 )(vii)]. Where relevant, EPA recommends that structural traps (e.g., faults, domes, or
pinch-outs) that can serve important roles in containing the carbon dioxide also be noted. The
owner or operator is encouraged to draw on information and data collected pursuant to
requirements at 40 CFR 146.82(a)(3)(ii) and (iii) and 146.83(a)(2). Beyond the information and
data collected pursuant to 40 CFR 146.82, the owner or operator should consider regions of the
confining zone predicted to come into contact with the carbon dioxide plume or mobilized fluids
for the first time during post-injection. The owner or operator is also encouraged to explain how
the data summarized in this section were used in computational modeling and demonstrations of
pressure decline, plume migration, and trapping (see above).
3.2.2.7 Assessment of Potential Conduits for Fluid Movement [40 CFR 146.93(c)(l)(viii)(x)]
The owner or operator must identify potential conduits for fluid movement including planned
injection wells and project monitoring wells associated with the GS project or any other projects
in areas that may be reasonably expected to come into contact with supercritical carbon dioxide
and/or mobilized fluids [40 CFR 146.93(c)(l)(viii)]. The owner or operator is encouraged to
draw on data collected pursuant to requirements at 40 CFR 146.82(a)(4). Of particular
importance are any potential leakage pathways, such as surrounding injection or production
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wells, that are predicted to come into contact with mobilized fluids only after the cessation of
injection.
For all abandoned wells within the AoR, the owner or operator must present information on
construction and an assessment of the quality of plugs [40 CFR 146.93(c)(l)(ix)]. The owner or
operator is encouraged to draw on data collected pursuant to 40 CFR 146.84(c)(2). EPA also
suggests that these data be collected and presented for any artificial penetrations outside of the
initial AoR that may be reasonably expected to come into contact with mobilized fluids, based on
modeling and analyses used to predict plume migration and pressure dissipation. The reader is
referred to the UIC Program Class VI Area of Review Evaluation and Corrective Action
Guidance regarding the evaluation of abandoned wells.
EPA encourages the owner or operator to provide a demonstration that potential conduits for
fluid movement will not pose an endangerment to USDWs beyond the alternative timeframe
requested in the application. The owner or operator is also required to identify the distance
between the injection zone and the nearest USDWs above and/or below the injection zone [40
CFR 146.93(c)(l)(x). This distance is a key determinant of the risks posed to USDWs by
artificial penetrations.
3.2.2.8 Additional Criteria for Alternative PISC Timeframe Demonstration
The Class VI Rule requires that information submitted with this application meet the following
criteria [40 CFR 146.93(c)(2)]:
All analyses and tests must be accurate, reproducible, and performed in accordance
with established quality assurance standards [40 CFR 146.93(c)(2)(i)]. The owner or
operator is encouraged to follow accepted protocols, including the use of peer-
reviewed methods, to ensure that all analyses meet these criteria. Furthermore, the
owner or operator is required to submit a QA/QC plan to demonstrate that all analyses
meet these standards (see below).
Estimation techniques must be appropriate, and EPA-certified test protocols must be
usedwhere available [40 CFR 146.93(c)(2)(ii)]. Computational modeling and the
resulting interpretation to evaluate changes in risks to USDWs may be prone to
uncertainty and error. To minimize error in analyses, the owner or operator is
encouraged to use accepted methods, including EPA-certified methods and standards
approved by ASTM, the American Water Works Association (AWW A), or similar
entities.
Predictive models must be appropriate and tailored to the site conditions,
composition of the carbon dioxide stream and injection and site conditions over the
life of the GS project [40 CFR 146.93(c)(2)(iii)]. The reader is referred to the UIC
Program Class VI Well Area of Review Evaluation and Corrective Action Guidance
regarding model development and appropriateness using site-specific information and
parameters.
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Predictive models must be calibrated using existing information (e.g., at Class I,
Class II, or Class V experimental technology well sites) where sufficient data are
available [40 CFR 146.93(c)(2)(iv)]. Model calibration refers to adjustment of model
parameters in order to match model results to monitored site observations. For
example, model calibration may consist of adjusting site permeability values within a
reasonable range such that previously observed pressure measurements are consistent
with model results. Where data that may be used for model calibration are readily
available, owners or operators must perform model calibration prior to use of
computational modeling results in the alternative timeframe demonstration. The
reader is referred to the UIC Program Class VI Well Area of Review Evaluation and
Corrective Action Guidance for additional information regarding model calibration.
Reasonably conservative values and modeling assumptions must be used and
disclosed to the UIC Program Director whenever values are estimated on the basis of
known, historical information instead of site-specific measurements [40 CFR
146.93(c)(2)(v)]. In some cases in computational modeling or other quantitative
analyses, parameter values from peer-reviewed literature sources may be used when
site-specific data are not available. Typically, literature searches result in a range of
reasonable parameter values. In these cases, the owner or operator must select values
from the reported range that are reasonably conservative (i.e., values that result in a
longer estimated PISC timeframe) and are also consistent with other data used to
model site-specific information. This is of particular importance for those modeling
parameters for which the model has been shown to be highly sensitive. The owner or
operator must also disclose the source of all parameters used.
An analysis must be performed to identify and assess aspects of the alternative PISC
timeframe demonstration that contribute significantly to uncertainty. The owner or
operator must conduct sensitivity analyses to determine the effect that significant
uncertainty may contribute to the modeling demonstration [40 CFR 146.93(c)(2)(vi)].
Analyses used in the alternative timeframe demonstration, including computational
modeling, are prone to uncertainty. Model uncertainty is a result of the uncertainties
related to the underlying science of the governing equations and the uncertainty in the
parameter values input to represent the actual system (USEPA, 2003). There is
significant uncertainty in modeling predictions of GS due to a number of factors:
difficulties in determining the structural geology and the permeability field
throughout the area likely to be affected by large injection volumes; a relative lack of
data on the behavior of supercritical carbon dioxide in the subsurface; the drastic
changes in transport behavior of carbon dioxide caused by changes in pressure and/or
temperature; and the buoyant nature of carbon dioxide relative to native formation
fluids. The impact of parameter uncertainty on modeling results can be characterized
through a model sensitivity analysis, which consists of sequentially varying a single
parameter in successive model simulations while keeping all other model features
constant. Sensitivity analyses provide an indication of those modeling parameters that
most affect predictions of carbon dioxide migration, trapping, and pressure changes,
and provide guidance regarding which parameters to focus on during data collection,
parameter estimation, and model calibration.
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An approved QA/QC plan must address all aspects of the demonstration [40 CFR
146.93(c)(2)(vii)]. A QA/QC project plan must be submitted with the demonstration.
It will describe all QA/QC standards to which the owner or operator will adhere. The
purpose of the QA/QC plan is to outline all steps taken by the owner or operator
during development of the demonstration to ensure that data and analyses are
accurate, reproducible, and complete. EPA encourages the owner or operator to
review relevant federal EPA and state guidance regarding development of QA/QC
project plans. Applicable federal EPA guidance includes USEPA (2002).
3.2.2.9 Adjustment of Computational Model During Injection
During the injection phase of the project, the owner or operator is required to reevaluate the AoR
periodically to compare model predictions to monitoring results [40 CFR 146.84(e)], When
computational model predictions and site monitoring data differ significantly, this reevaluation
may result in adjustment of the computational model by calibration. The geologic conceptual
model should also be updated as needed to address any new information obtained about the site
geology; the revisions to the geologic conceptual model should also be reflected in updates to the
computational modeling. (See the UIC Program Class VI Well Area of Review Evaluation and
Corrective Action Guidance.) Following calibration, the owner or operator is encouraged to
submit a revised PISC and Site Closure Plan that describes how changes to the model affect
predictions of pressure dissipation, plume migration rates, trapping, and additional processes that
affect risks to USDWs and the alternative PISC timeframe demonstration. In some cases, this
model reevaluation may indicate a need to lengthen the alternative PISC timeframe, and such
results should be reported to the UIC Program Director with all appropriate documentation.
Using this information, the UIC Program Director may reevaluate the alternative PISC
timeframe following model calibration and may lengthen the timeframe accordingly.
Alternatively, such information may substantiate a revised, shorter PISC as discussed in Section
3.2.2.
3.3 Demonstration of USDW Non-Endangerment
During PISC, the owner or operator may submit a demonstration of non-endangerment of
USDWs to reduce the initial permitted PISC monitoring timeframe. The UIC Program Director
may reduce the PISC monitoring timeframe to less than the default of 50 years (or UIC Program
Director-approved alternative timeframe) based on this demonstration [40 CFR 146.93(b)(2)], In
all cases, including in the event that PISC has occurred for the default of 50 years, the owner or
operator must submit the demonstration of USDW non-endangerment prior to the approval of the
end of PISC [40 CFR 146.93(b)(3)], If the UIC Program Director determines that risks to
USDWs persist at the site, he/she may extend PISC beyond the previously established PISC
timeframe [40 CFR 146.93(b)(4)],
The demonstration of USDW non-endangerment differs from the demonstration for an
alternative PISC timeframe (Section 3.2.2) because the non-endangerment demonstration occurs
during PISC rather than initially during the project permitting phase, and it is based primarily on
collected site monitoring data rather than modeling predictions. EPA encourages the owner or
operator to include within the PISC and Site Closure Plan details regarding how the non-
endangerment demonstration will be made on a site-specific basis and the information and
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conditions that the owner or operator intends to use to confirm and demonstrate non-
endangerment. The non-endangerment demonstration should take the form of a detailed report
submitted to the UIC Program Director. This report should include all relevant monitoring data
and interpretations upon which the non-endangerment demonstration is based and any other
information necessary for the UIC Program Director to replicate the analysis. EPA suggests that
the non-endangerment demonstration report include the information described in the following
subsections.
3.3.1 Summary of Existing Monitoring Data
A summary of all previous monitoring data at the site, including data collected during the
injection and PISC phases of the project, should be submitted to help demonstrate non-
endangerment. Data submittals may take the forms of databases or tables and raw data (e.g.,
laboratory reports, geophysical survey data), which must be submitted in an electronic format
[40 CFR 146.90(e)], Accompanying the data submittal should be a narrative explanation of
monitoring activities, including the dates of all monitoring events, changes to the monitoring
program over time, and an explanation of all monitoring infrastructure that has existed at the site.
Data should also be compared with baseline data on fluid chemistry collected during the site
characterization process as required at 40 CFR 146.82(a)(6) and 146.87(d)(3); see the UIC
Program Class VI Well Site Characterization Guidance. EPA's suggested format for PISC
monitoring reporting is provided in Section 3.1.6.
3.3.2 Comparison of Monitoring Data and Model Predictions and Model Documentation
The results of computational modeling used for AoR delineation and for demonstration of an
alternative PISC timeframe may be used by the owner or operator to support the demonstration
of USDW non-endangerment. The owner or operator is encouraged to provide a detailed
comparison of monitoring data collected during PISC with modeled predictions of plume
migration and pressure dissipation during PISC. The objective of this comparison is to assess if
modeling predictions have been reasonably valid for understanding system behavior after the
cessation of injection and to validate the non-endangerment demonstration. If PISC monitoring
results and model predictions agree well, this suggests that modeling results may be useful for
supporting the non-endangerment demonstration. See the UIC Program Class VI Well Area of
Review Evaluation and Corrective Action Guidance for examples of the comparison of
monitoring results and model predictions and discussion of model uncertainty analysis. If
modeling predictions are going to be used for non-endangerment demonstration, EPA
encourages the owner or operator to additionally submit all model documentation and supporting
data. Refer to the UIC Program Class VI Well Area of Review Evaluation and Corrective Action
Guidance for reporting of model predictions.
3.3.3 Evaluation of Carbon Dioxide Plume
Under certain conditions, the separate-phase and aqueous-phase carbon dioxide plumes may
continue to migrate after injection ceases, as influenced by (1) the presence or lack of a
stratigraphic trap; (2) the presence or lack of a structural trap; (3) carbon dioxide moving up-dip
at the injection zone/confining zone interface; (4) the presence of significant highly permeable
pathways that lead to preferential plume migration; and (5) the persistence of a pressure
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differential that results in fluid movement. If the carbon dioxide plume comes into contact with a
vertical leakage pathway, it may pose a risk of endangerment to USDWs. Therefore, risk of
endangerment to USDWs decreases substantially when plume migration ceases or is extremely
slow.
For the separate-phase carbon dioxide plume, the risk to USDWs will decrease when the extent
of pure-phase carbon dioxide ceases to grow either laterally or vertically. This condition may be
met if the vast majority of carbon dioxide is trapped via trapping mechanisms and, for the case of
relatively non-dipping formations, if formation pressure differentials decline such that there is no
longer a driving force for carbon dioxide movement. The aqueous-phase carbon dioxide plume
will continue to migrate via advection with regional ground water flow and diffusion away from
the separate-phase source. Although the separate-phase source may be stabilized, the aqueous
phase plume may continue to provide a risk of endangerment to USDWs within areas of the
injection zone with elevated pressures. As carbon dioxide concentrations decrease further from
the separate-phase source, risks associated with the plume itself concomitantly decrease. Risks
associated with the pressure front surrounding the plume, however, can persist regardless of the
carbon dioxide concentration (See Section 3.3.5).
For both the separate- and aqueous-phase plumes, the risk to USDWs may be low even in the
event of some plume migration. This is the case if plume migration rates are extremely small,
and/or if a demonstration can be made that no leakage pathways exist in the direction(s) of plume
migration within long timeframes (e.g., hundreds to thousands of years).
Monitoring data are integral to the determination of plume migration rates and stabilization. As
discussed above, a suite of monitoring technologies are available and may be applied in the PISC
stage of a GS project. These include monitoring wells, which may be used to assess risk to
USDWs if there are enough of them to allow a reasonable inference of plume migration rates. If
downgradient monitoring wells screened within the injection zone do not reveal separate-phase
carbon dioxide in sampling events over an extended period of time, this can be used as evidence
that the plume has not migrated into that area, and upper and lower bounds of the plume
migration rates can be estimated. Furthermore, monitoring wells screened above the confining
layer may be used to determine aqueous-phase concentrations of carbon dioxide and mobilized
constituents in order to assess USDW endangerment.
Geophysical surveys provide data over large areas and thus can be more useful in demonstrating
plume migration compared to monitoring wells. By comparing the results of geophysical surveys
conducted over time, plume migration rates can be estimated.
Supplementary to monitoring data, modeling results can be used to assess the risk posed to
USDWs. Modeling may be used to estimate the phase-state and degree of trapping of carbon
dioxide over time. If a demonstration can be made, in conjunction with monitoring data, that a
vast majority of the carbon dioxide has been immobilized via trapping mechanisms, this is strong
evidence that the risk to USDWs posed by the carbon dioxide plume has decreased. Modeling
may also be used to estimate future plume migration. Modeling results, including sensitivity
analyses, may be used to demonstrate that plume migration rates are negligible based on
available site characterization, monitoring, and operational data.
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3.3.4 Evaluation of Mobilized Fluids
In addition to carbon dioxide, mobilized fluids may pose an ongoing risk to USDWs. These
include native fluids that are high in TDS and therefore may impair a USDW, and fluids
containing mobilized drinking water contaminants (e.g., arsenic, mercury, hydrogen sulfide).
Geochemical data collected from monitoring wells is integral to a demonstration that mobilized
fluids no longer pose a risk to USDWs. Of particular importance are any monitoring wells that
are screened above the primary confining zone, within any USDWs, and in the vicinity of any
known leakage pathways. Monitoring data indicating steady or decreasing trends of potential
drinking water contaminants below actionable levels (e.g., secondary and maximum contaminant
levels) is necessary for this demonstration. The acceptable levels of TDS and all potential
drinking water contaminants in any relevant zones should be defined in the PISC and Site
Closure Plan. Additionally, the duration, in years, of observed steady or decreasing trends that
may indicate USDW non-endangerment, should also be listed.
3.3.5 Evaluation of Reservoir Pressure
Pressure decline is integral to the decrease of risk to USDWs. Increased pressure is the primary
driving force for fluid movement that may endanger a USDW. Pressure differentials will decay
over time after the cessation of injection. The rate of pressure decay is a function of injection
zone permeability, compressibility, the injected volume of carbon dioxide, the areal extent and
thickness of the formation, and the presence of lateral strati graphic confining features.
To demonstrate that there is no risk of endangerment to USDWs, the pressures within the
injection zone should decline until there is no risk of fluid movement into a USDW or,
alternatively, to pre-injection conditions. Monitoring using downhole pressure transducers is the
most reliable metric of pressure decline over time; commercial systems are available to provide
continuous downhole monitoring for pressure and temperature, and these may be a useful option
(see the UIC Program Class VI Well Testing and Monitoring Guidance). Pressure should be
emphasized as one of the key measurements during PISC monitoring. Models, including robust
numerical simulators and simpler analytic or semi-analytic methods, can be used to estimate
pressure decay. Models may be used to supplement monitoring data in order to estimate pressure
in areas with little or no monitoring data as well as to estimate future trends. When interpreting
and reporting model results, uncertainty analyses are recommended, including sensitivity
analysis (see the UIC Program Class VI Well Area of Review Evaluation and Corrective Action
Guidance).
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Box 3-2. Demonstration of USDW Non-Endangerment.
This box provides an example of some of the data that may be used in the USDW non-
endangerment demonstration, based on the hypothetical project presented above in Box
3-1 and the UIC Program Class VI Area of Review Evaluation and Corrective Action
Guidance. The owner or operator had included a PISC timeframe of 50 years in the
PISC and Site Closure Plan. However, 40 years after the cessation of injection (70
years total from the beginning of injection), the owner or operator has determined that
sufficient data exist to demonstrate no ongoing risk of USDW endangerment. Data used
in this demonstration include assessment of the location and migration rate of the
carbon dioxide plume and mobilized fluids, results of MITs, and pressure monitoring
results within the injection zone. This box focuses on pressure measurement data and
modeling.
At 40 years after the cessation of injection, three monitoring wells remain in use at the
project: MW-9, MW-12, and MW-13 (see Figure 9). Recall that MW-13 had been re-
sited to be outside of the expected influence of the project, in the direction of
preferential fluid movement. Historical pressure measurements are plotted versus time
in years from the beginning of injection. Model results are also plotted, and are based
on the most recently calibrated model. As can be seen, model predictions and observed
pressure data agree reasonably well, which increases confidence in use of the model for
evaluating future trends.
At 40 years after the cessation of injection, pressure has declined to pre-injection levels
in all three wells (Figure 10). Based on risk-based criteria listed in the PISC and Site
Closure Plan, pressure decline to pre-injection levels is one factor indicative of USDW
non-endangerment. Model results confirm that pressures will continue to decline or be
steady at levels that do not pose an endangerment to USDWs. Importantly, elevated
pressure has not been observed in MW-13, consistent with the AoR reevaluation that
occurred 20 years after the beginning of injection (see Box 3-1).
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Box 3-2. Demonstration of USDW Non-Endangerment.
16.0
15.5
15.0
14.5
14.0
13.5
13.0
Well MW-9
oe
0 10 20 30 40 50 60 70 80 90 100
Time (years)
Model Results o Monitoring Data
16.0
15.5
15.0
14.5
14.0 ฆ
13.5
13.0
Well MW-13
ฐฐ Ado ฎ .
'&>o
0 10 20 30 40 50 60 70 80 90 100
Time (years)
Model Results o Monitoring Data
Well MW-12
16.0
15.5
15.0
14.5
14.0
13.5
13.0
\
o
0 10 20 30 40 50 60 70 80 90 100
Time (years)
Model Results o Monitoring Data
Figure 10. Historical Reservoir Pressure Data within the Injection Zone and
Model Predictions for Three Monitoring Wells at Hypothetical GS Project.
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3.3.6 Evaluation of Potential Conduits for Fluid Movement
Potential conduits for fluid movement, or leakage pathways, include active and abandoned wells,
faults, and fractures. The demonstration of USDW non-endangerment should include an
assessment of all potential conduits for fluid movement in the vicinity of the project. The
demonstration may include a narrative explanation of all analyses that have been conducted to
identify potential conduits (i.e., aeromagnetic surveys, records review), a listing of all potential
conduits, and an explanation of why each conduit no longer poses any risk of endangerment of a
USDW. Relevant supporting analyses may include assessment of the proximity of conduits to
USDWs, monitoring for carbon dioxide in the local region around potential conduits, and well
integrity testing.
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4 Site Closure
Site closure activities required at 40 CFR 146.93(d) through (h) include: notifying the UIC
Program Director of intent to close the site; plugging all monitoring wells; submitting a site
closure report; and recording a notation on the deed to the facility or other documents that the
land has been used to sequester carbon dioxide. Additional site closure activities may include
removing all surface equipment and restoring the site to its prior land surface condition (e.g., site
restoration, site grading, and planting vegetation) or to a condition approved by the UIC Program
Director.
Site closure requirements are established to ensure that all PISC monitoring wells are plugged
appropriately and to the UIC Program Director's satisfaction, that all GS project records are
maintained, that necessary documentation is provided to the UIC Program Director, and that the
future land owners are made aware of the injection operation and that carbon dioxide is stored
under the surface.
Site closure may only occur after the UIC Program Director releases the owner or operator of a
GS site from PISC responsibilities following a demonstration that the site no longer poses a risk
of endangerment to USDWs pursuant to requirements at 40 CFR 146.93(b) (see Section 3).
Additionally, with the conclusion of site closure, the owner or operator will be released from
financial responsibility requirements associated with the GS project (40 CFR 146.85(b)(1); see
the UIC Program Class VI Financial Responsibility Guidance).
While not required, EPA recommends that owners or operators describe in their PISC and Site
Closure Plan how they plan to conduct site closure following the conclusion of the PISC period.
For Class VI projects with plans that include proposed site closure procedures, activities will
proceed accordingly as required at 40 CFR 146.93(a) and should be carried out in fulfillment of
the requirements at 40 CFR 146.93(d) through (h). See the UIC Program Class VI Well Project
Plan Development Guidance for more information regarding the preparation of the PISC and
Site Closure Plan and Section 3.1.1 of this guidance document for how to conduct reevaluations
of this plan.
4.1 Site Closure Notification
Owners or operators are required to notify the UIC Program Director in writing at least 120 days
prior to planned site closure [40 CFR 146. 93(d)], At this time, if any changes have been made to
the original PISC and Site Closure Plan, the owner or operator must also provide the revised
plan. A notification period shorter than 120 days may be allowed by the UIC Program Director
prior to a planned site closure. For details of submitting the notification and the revised plan to
the EPA electronic reporting system, see the UIC Program Class VI Well Recordkeeping,
Reporting, and Data Management Guidance for Owners and Operators.
A site closure notice submitted by the owner or operator of a Class VI well to the UIC Program
Director may include:
Facility information, such as the facility name and location;
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A list of contact personnel (e.g., names, titles, phone numbers, email addresses) for
allowing timely direct communication to resolve any pressing issues; and
A projected closure date, no less than 120 days following the site closure notification
submission, unless the UIC Program Director has approved a different period prior to
notice submission.
EPA envisions that this notification would take the form of a letter from the owner or operator to
the UIC Program Director with all of the information described above. Appendix F provides a
template of such a letter.
EPA recommends that upon receipt of this notification, the UIC Program Director and the owner
or operator discuss the planned site closure activities to ensure that all parties agree on the
activities that must be performed.
4.2 Monitoring Well Plugging
The primary activity during site closure will be plugging of all monitoring wells at the site in a
manner that prevents movement of injection or formation fluids that would endanger a USDW
[40 CFR 146.93(e)], Proper plugging of injection and monitoring wells is a long-standing
requirement in the UIC Program designed to ensure that injection or monitoring wells do not
serve as conduits for fluid movement following cessation of injection and site closure in order to
ensure protection of USDWs.
Because improperly abandoned monitoring wells may become conduits for fluid movement into
USDWs (similarly to improperly abandoned injection wells), EPA recommends that owners or
operators plug their monitoring wells using procedures similar to those used to plug injection
wells, particularly regarding the use of plugging materials that are resistant to carbon dioxide and
carbon dioxide-rich brines. While advance notification of monitoring well plugging is not
explicitly required (i.e., 60 days before plugging as is required for injection wells at 40 CFR
146.92(c)], EPA recommends that the owner or operator notify the UIC Program Director in
advance of plugging monitoring wells. This notification may take the form of a letter similar to
the notification of plugging the injection well presented in Appendix B.
The requirements at 40 CFR 146.92 for plugging a Class VI injection well are discussed in
Section 2 of this guidance document. Owners or operators may consider the same types of
information when selecting methods for monitoring well plugging as they do for injection well
plugging. Relevant information includes well depth and construction, borehole diameter,
location, well type, subsurface formations penetrated by the well, and how the composition of
the carbon dioxide may affect plugging materials. This information will help determine the type
and number of plugs that are necessary for monitoring wells, the method of emplacement, and
the type, grade, and quantity of material to be used. As required for injection well plugging, the
materials used for plugging monitoring wells also need to be compatible with the carbon dioxide
stream and/or formation fluids with which they will be in contact. See Section 2 above for
additional information and appropriate well plugging methods. Information on plugging
monitoring wells is also provided in "Region V Guidelines for Class I Well Monitoring Plans,"
available at: http://www.epa.gov/r5water/uic/r5guid/monitor well, htm #partii.
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4.3 Site Closure Reporting and Recordkeeping
The Class VI Rule requires the owner or operator to submit a site closure report to the UIC
Program Director within 90 days of site closure [40 CFR 146.93(f)], The purpose of the report is
to document appropriate closure procedures as well as provide information about the operation
that may be of interest to future land owners and planners. Such information is needed to help
authorities impose appropriate conditions on subsequent drilling activities that may penetrate the
injection or confining zone(s).
The site closure report must document appropriate injection and monitoring well plugging as
specified in 40 CFR 146.92 and described in Sections 2 and 4.2 of this guidance document [40
CFR 146.93(f)(1)]. The report should include a description of pre-plugging activities and the
plugging procedures used to demonstrate that plugging requirements have been met.
The report must also contain a copy of a survey plat that has been submitted to the local zoning
authority designated by the UIC Program Director [40 CFR 146.93(f)(1)], The survey plat must
indicate the location of the injection well relative to permanently surveyed benchmarks. In
addition, EPA recommends that the plat also identify the locations of all monitoring wells. The
owner or operator must submit a copy of the survey plat to the Regional Administrator of the
appropriate EPA regional office within 90 days of site closure.
The site closure report must also include documentation of appropriate notification and
information to state, local, and tribal authorities that have authority over drilling activities [40
CFR 146.93(f)(2)]. This notification will enable them to impose appropriate conditions on
subsequent drilling activities that may penetrate the injection and confining zone(s). The purpose
of any such conditions would be to avoid compromising the containment of injected carbon
dioxide and potentially endangering USDWs. Such documentation may include information such
as the names of entities being informed; copies of letters sent to accompany the information;
maps of the AoR indicating the location of the injection well, plume, and pressure front;
important dates (e.g., operation period, PISC period, site closure); and site characterization
information.
The site closure report must also include records reflecting the nature, composition, and volume
of the carbon dioxide stream [40 CFR 146.93(f)(3)]; this may take the form of historical analyses
of injectate. EPA recommends that the results of any other geochemical analyses conducted at
the site also be submitted.
The site closure report submitted to the UIC Program Director must be retained by the owner or
operator for 10 years following site closure [40 CFR 146.93(f)], Concurrently, a copy of the
report will be submitted to EPA and will be retained in the EPA electronic reporting system [40
CFR 146.91(e)], The UIC Program Director has authority to require the owner or operator to
retain any records for longer than 10 years after site closure [40 CFR 146.91(f)(5)],
Appendix G presents a recommended template for a site closure report. More information on the
format and details of the site closure report and how to submit it can be found in the UIC
Program Class VI Well Recordkeeping, Reporting, and Data Management Guidance for Owners
and Operators.
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Following site closure, 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 a title search by a potential purchaser of the property [40 CFR 146.93(g)], The notation
must include the following information:
That the land has been used for GS;
The name of the state agency, local authority, and/or tribe with which the survey plat was
filed, as well as the address of the EPA Regional Office to which it was submitted; and
The volume of fluid injected, the injection zone(s), and the period over which the
injection occurred.
4.4 Post-Site Closure Activities
Following site closure, the owner or operator is responsible for any remedial action deemed
necessary for USDW endangerment caused by the injection operation. Therefore, the owner or
operator is still financially liable for the site. Under the final Class VI Rule, once an owner or
operator has met all regulatory requirements under 40 CFR Part 146 for Class VI wells and the
UIC Program Director has approved site closure pursuant to requirements at 40 CFR 146.93, the
owner or operator will generally no longer be subject to enforcement for regulatory
noncompliance. Separate from EPA's authority to enforce regulatory compliance, an owner or
operator may be subject to a response order under Section 1431 of SDWA even after proper site
closure is approved under 40 CFR 146.93. Under Section 1431 of SDWA, the Administrator
may require an owner or operator to take necessary response measures if he or she receives
information that a contaminant is present or is likely to enter a public water system or a USDW,
which may present an imminent and substantial endangerment to the health of persons, and the
appropriate state and local authorities have not acted to protect the health of such persons. The
action may include issuing administrative orders or commencing a civil action for appropriate
relief against the owner or operator of a Class VI well. If the owner or operator fails to comply
with the order, they may be subject to a civil penalty for each day in which such violation occurs
or failure to comply continues. Furthermore, after site closure an owner or operator may remain
liable under tort and other remedies, or under other federal statutes including, but not limited to,
the Clean Air Act (CAA), 42 U.S.C. 7401-7671; the Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA), 42 U.S.C. 9601-9675; and the Resource
Conservation and Recovery Act (RCRA), 42 U.S.C. 6901-6992.
Additional information related to post-closure activities is available in the UIC Program Class
VIFinancial Responsibility Guidance. Additionally, in a 2008 paper, EPA provided information
on different approaches to stewardship of carbon dioxide GS sites after site closure (USEPA,
2008). Although the SDWA does not explicitly provide EPA the authority to transfer liability
from the owner or operator of a Class VI well to another entity, the paper intended to inform
readers on important concepts that may be useful in developing an approach to post-site-closure
stewardship.
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5 References
American Petroleum Institute (API), 1993. Environmental Guidance Document: Well
Abandonment and Inactive Well Practices for U.S. Exploration and Production
Operations. API Bulletin E3. January 31, 1993.
API, 2002. API Specification 10A - Specification on Cements and Materials for Well Cementing
(includes Addendum 1). (23rd ed.)
ASTM Standard C1438-99(2005)el, "Standard Specification for Latex and Powder Polymer
Modifiers for Hydraulic Cement Concrete and Mortar," ASTM International, West
Conshohcken, PA, 2005, DOI: 10.1520/C1438-99R05E01, www.astm.org.
ASTM Standard C150 - 11 / C150M -11, "Standard Specification for Portland Cement." ASTM
International, West Conshohcken, PA, DOI: 10.1520/C0150_C0150M-11,
www.astm.org.
ASTM Standard C1707-10, "Standard Specification for Pozzolanic Hydraulic Lime for
Structural Purposes," ASTM International, West Conshohcken, PA, DOI:
10.1520/C1707-10, www.astm.org.
Bosma, M.G.R., Cornelissen, E.K., and Schwing, A., 2000. Improved experimental
characterisation of cement/rubber zonal isolation materials. Society of Petroleum
Engineers, SPE 64762.
Calvert, D.G., and Smith, D.K., 1994. Issues and techniques of plugging and abandonment of oil
and gas wells. Society of Petroleum Engineers, SPE 28349.
Clark, J., and Salsbury, B., 2003. Well abandonment using highly compressed sodium bentonite
- an Australian case study. Society of Petroleum Engineers, SPE 80592.
Drilling Formulas and Drilling Calculations, no date. Available on the Internet at:
http://www.drillingformulas.com/tag/hvdrostatic-pressure-equation/.
Englehardt, J., and Wilson, M.J., 2001. New abandonment technology new materials and
placement techniques. Society of Petroleum Engineers, SPE 66496.
Goodwin, K.J., and Crook, R.J., 1992. Cement sheath stress failure. SPE Drilling Engineering,
Vol. 7: 291-296.
Ide, S.T., Jessen, K., and Orr, F.M. Jr., 2007. Storage of CO2 in saline aquifers: Effects of
gravity, viscous, and capillary forces on amount and timing of trapping. International
Journal of Greenhouse Gas Control, Vol. 1: 481-491.
Jirapongpipat, P., 2007. Well Plugging & Abandonment Guide. Available on the Internet at:
http://www.thaidecom.com/files/Well%20Plugging%20and%20Abandonment%20Guidel
ine.pdf.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
51
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King, G.E., 2009. Plug and Abandonment Basics. Available on the Internet at:
http://gekengineering.com/Downloads/Free Downloads/Plug-
and Abandonment Basics.pdf.
Kosmatka, S.H., Kerkhoff, B., and Panarese, W.C., 2003. Design and Control of Concrete
Mixtures. Portland Cement Association.
LeRoy-Delage, S., Thiercelin, M., and Vidick, B., 2000. New cement systems for durable zonal
isolation. Society of Petroleum Engineers, SPE 59132.
Liversidge, D., and Agarwal, S.T., 2006. Permanent plug and abandonment solution for the
North Sea. Society of Petroleum Engineers, SPE 100771.
Meyer, J.P., 2007. API Summary of Carbon Dioxide Enhanced Oil Recovery Injection Well
Technology. Prepared for API. Available on the Internet at:
http://www.api.org/policy/environment/.
Meyer, P.D., and Brill, E.D. Jr., 1988. A Method for Locating Wells in a Groundwater
Monitoring Network Under Conditions of Uncertainty. Water Resources Research, Vol.
24: 1277-1282.
Moroni, N., Santra, A., Ravi, K., and Hunter, W., 2009. Holistic design of cement systems to
survive CO2 environment. Society of Petroleum Engineers, SPE 12473.
Nagelhout, C.G., Bosma, M.G.R., Mul, P.J., Krol, G.G., van Velzen, J.F.G., Joldersma, J.S.,
James, S.G., Dargaud, B., Schreuder, G.J.R., and Thery, F., 2005. Laboratory and field
validation of a sealant system for critical plug and abandon situations. Society of
Petroleum Engineers, SPE/IADC 97347.
National Energy Technology Laboratory (NETL), 2009. Best Practices for Monitoring,
Verification, and Accounting of Carbon Dioxide Stored in Deep Geologic Formations.
First Edition. DOE/NETL-311/081508. Available on the Internet at:
http://www.netl.doe.gov/technologies/carbon seq/infrastructure/bestpractices.html.
Nurafza, P.R., and Fernagu, J., 2009. Estimation of Static Bottom Hole Pressure From Weil-
Head Shut-in Pressure for a Supercritical Fluid in a Depleted HP/HT Reservoir. Society
of Petroleum Engineers, SPE 124578.
Smith, D.K., 1976. Cementing. Monograph Volume 4 of the Henry L. Doherty Series. Society of
Petroleum Engineers of American Institute of Mining, Metallurgical, and Petroleum
Engineers.
Thiercelin, M.J., Dargaud, B., Baret, J.F., and Rodriguez, W.J., 1998. Cement design based on
cement mechanical response. Society of Petroleum Engineers, SPE Drilling &
Completion, December 1998, SPE 52890.
Towler, F., Victorov, H., Zamfir, G., and Ignat, P., 2008. Plugging wells with hydrated bentonite,
Part 2: Bentonite bars. Society of Petroleum Engineers, SPE 115524.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
52
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United States Environmental Protection Agency (USEPA), 1982. Technical Manual: Injection
Well Abandonment. Prepared by Geraghty and Miller, Inc. Available on the Internet at:
http://www.epa.gov/ogwdw/uic/pdfs/Historical/techguide uic tech manual abandonmt.
pdf.
USEPA, 1989. Technical Assistance Document: Cementing for the Plugging and Abandonment
of Injection Wells. Prepared by Engineering Enterprises, Inc. Available on the Internet at:
http://www.epa.gov/ogwdw/uic/pdfs/Historical/techguide uic cementing plug 1989.pdf
USEPA, 2002. Guidance for Quality Assurance Project Plans for Modeling. EPA QA/G-5M.
Available on the Internet at: http://www.epa.gov/QUALITY/qs-docs/g5m-fmal.pdf.
USEPA, 2003. Draft Guidance on the Development, Evaluation, and Application of Regulatory
Environmental Models. Prepared by The Council for Regulatory Environmental
Modeling. Available on the Internet at:
http://www.modeling.uga.edu/tauc/other papers/CREM%20Guidance%20Draft%2012 0
3 pdf.
USEPA, 2008. Approaches to Geologic Sequestration Site Stewardship After Site Closure. EPA
816-B-08-002. Available on the Internet at:
http://www.epa.gov/ogwdwOOO/uic/pdfs/support uic co2 stewardshipforsiteclosure.pdf.
Vaucher, D., and Brooks, R., 2010. Advantages of inflatable packer technology for temporary or
permanent well abandonment in the Gulf of Mexico. Society of Petroleum Engineers,
SPE 130270.
Wyoming Completion Technologies. No date. High pressure, ball type, fluid control valve.
Available on the Internet at: http://wct.directairnet.com/products.html.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
53
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Appendix A.
Sample Template of an Injection Well Plugging Plan
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Appendix A: Sample Template of an Injection Well Plugging Plan
Facility Information
Facility name:
Facility contacts (names, titles, phone numbers, email addresses):
Location (town/county/etc.):
Planned tests or measures to determine bottomhole reservoir pressure:
Planned external MIT(s):
Information on Plugs:
Plug #1
Plug #2
Plug #3
Plug #4
Plug #5
Plug #6
Plug #7
Diameter of Boring in Which
Plug Will be Placed
Depth to Bottom of Tubing or
Drill Pipe
Sacks of Cement to be Used
(each plug)
Slurry Volume to be Pumped
Slurry Weight
Top of Plug
Bottom of Plug
Type of Cement or Other
Material
Method of Emplacement (e.g.,
balance method, retainer
method, or two-plug method)
Attachments:
Injection well construction plan/schematics showing depth to tubing stub, exposed formation
intervals, casing diameters, depths, etc.
Information on formations, depths to USDWs, etc.
Schematic/drawings of the placement of all plugs.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
A-l
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Appendix B.
Sample Template of a Notice of Intent to Plug a
Class VI Injection Well
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Appendix B: Sample Template for a Notice of Intent to Plug an Injection Well
[Today's Date]
Insert Name of Owner or Operator
Insert Return Address
To: Insert Name of UICProgram Director
In compliance with 40 CFR 146.92(c) of the United States Code of Federal Regulations (CFR), this is to
provide to the Director of the UIC Class VI Program notice of [insert name of owner or operator]' s
intention to plug [insert identifying information about the injection well] at the [insert name of facility]
geologic sequestration (GS) project. The Class VI well is located at: [insert location of well (e.g.,
latitude/longitude)].
Plugging is anticipated to occur on: [insert projected plugging date/time, no less than 60 days after the
date of the letter].
Use one of the following two paragraphs as appropriate depending on whether changes to the Injection
Well Plugging Plan are needed:
Please note that [insert name of owner or operator] intends to plug the well as described in the approved
Injection Well Plugging Plan that was submitted to satisfy the permit application requirements at 40 CFR
146 .82 for [insert permit number],
OR
Please note that, based on a review of information collected since submittal of the Injection Well
Plugging Plan to satisfy the permit application requirements at 40 CFR 146.82 for [insert permit
number], [insert name of owner or operator] has identified some needed changes to the Injection Well
Plugging Plan. A revised Injection Well Plugging Plan is attached to this letter.
If you have any questions about the planned plugging of [insert name ofproject/facility], please contact
me or any of the following staff:
Primary contact: Insert name, title, phone, number/email address
Additional contact (e.g., legal contact): Insert name, title, phone, number/email address
(as necessary)
Additional contact (e .g., chief engineer): Insert name, title, phone, number/email address
(as necessary)
Sincerely,
Insert name of owner or operator contact
Insert title
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
B-l
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Appendix C.
Sample Template of a Class VI Injection
Well Plugging Report
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Appendix C: Template for an Injection Well Plugging Report
Facility Information
Facility Name:
Facility Address:
Facility Contacts (names, titles, phone numbers, email addresses):
Location (town/county/etc.):
Permit Number:
Injection Well Plugging (Repeat as neededfor each injection well associated with the project.)
Results of tests or measures to determine bottomhole reservoir pressure:
Results of external MIT(s):
Information on Plugs:
Plug #1
Plug #2
Plug #3
Plug #4
Plug #5
Plug #6
Plug #7
Diameter of Boring in Which
Plug Was Placed
Depth to Bottom of Tubing or
Drill Pipe
Sacks of Cement Used (each
plug)
Slurry Volume that was
Pumped
Slurry Weight
Top of Plug
Bottom of Plug
Type of Cement or Other
Material
Method of Emplacement (e.g.,
balance method, retainer
method, or two-plug method)
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
C-l
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Casing and Tubing Record after Plugging
Size
Weight (lb/ft)
To be put in Well (ft)
To be left in Well (ft)
Diameter of Boring
Checklist and Additional Information Attached
Injection well construction schematics showing actual depth to tubing stub, exposed
formation intervals, casing diameters, depths, others.
Information on formations, depths to USDWs, other.
Schematic/drawings of the placement of all plugs showing their actual depth.
Retain Copy of Report
A copy of this well plugging report will be retained by [insert name of owner or operator] for
10 years following the date of site closure, [list date of site closure].
Certification
I certify under the penalty of law that I have personally examined and am familiar with the information submitted in
this document and all attachments and that, based on my inquiry of those individuals immediately responsible for
obtaining the information. I believe that the information is true, accurate, and complete. I am aware that there are
significant penalties for submitting false information, including the possibility of fine and imprisonment. (Ref. 40
CFR 144.32)
Name and Official Title (Please type or print)
Signature
Date Signed
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
C-2
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Appendix D.
Sample Template of a Class VI Post-Injection Site Care
and Site Closure Plan
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Appendix D: Sample Template of a PISC and Site Closure Plan
Facility Information
Facility name:
Facility contacts (names, titles, phone numbers, email addresses):
Location (town/county/etc.):
Pre- and Post-Injection Pressure Differential
Figure: Predicted pressure changes (pre-injection to the cessation of injection).
Source: AoR delineation modeling.
Predicted Position of the Carbon Dioxide Plume and Associated Pressure Front at Site
Closure
Figure: Map showing the extent of the carbon dioxide plume and pressure front at site closure.
Source: AoR delineation modeling.
Post-Injection Monitoring Plan
Ground Water Quality Monitoring
Monitoring well name/location/map reference:
Well depth/formation(s) sampled:
Parameter/Analyte
Frequency
Aqueous and pure phase carbon dioxide
Total dissolved solids
pH
Specific conductivity (SC)
Temperature
Other parameters (e.g., major anions and cations; trace metals;
tracers; hydrocarbons; and volatile organic compounds)
Sampling methods:
Analytical techniques:
Laboratory to be used/ chain of custody procedures:
Quality assurance and surveillance measures:
Plan for guaranteeing access to all monitoring locations:
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
D-l
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Carbon Dioxide Plume and Pressure Front Tracking
Direct Pressure Monitoring
Well Location/Map Reference
Depth(s)/Formation(s)
Frequency
Quality assurance and surveillance measures:
Plan for guaranteeing access to all monitoring locations:
Indirect Carbon Dioxide Plume and Pressure Front Tracking
Describe indirect methods to be used (e.g., types of indirect surveys to be performed, the
planned areal extent/resolution of geophysical surveys, and plannedfrequency/schedule) and
their associated quality assurance and surveillance measures, and plans to record and report
the results.
Direct Geochemical Plume Monitoring
If it is determined that direct geochemical monitoring of the plume is necessary, describe
the locations where samples will be taken and parameters to be monitored.
Monitoring Location/Map Reference
Frequency
Sampling methods:
Analytical techniques:
Laboratory to be used/ chain of custody procedures:
Quality assurance and surveillance measures:
Plan for guaranteeing access to all monitoring locations:
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
D-2
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Surface Air and/or Soil Gas Monitoring (if required by the UIC Program Director)
Monitoring Location/Map Reference
Frequency
Sampling methods:
Analytical techniques:
Laboratory to be used/ chain of custody procedures:
Quality assurance and surveillance measures:
Plan for guaranteeing access to all monitoring locations:
Additional Monitoring (if required by the UIC Program Director)
Describe testing techniques and equipment and their associated quality assurance and
surveillance measures, testing frequency (e.g., anticipated test dates), and plans to record
and report the results.
Proposed Schedule for Submitting Post-Injection Monitoring Results
Planned Testing/Monitoring
Reporting Schedule
Ground Water Quality Monitoring Data
E.g., quarterly
Carbon Dioxide Plume and Pressure Front
Tracking Data
Direct Pressure Monitoring Data
Indirect Carbon Dioxide Plume and Pressure
Front Tracking Data
Surface Air and/or Soil Gas Monitoring Data
(if required by the UIC Program Director)
Additional Monitoring Data (if required by
the UIC Program Director)
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
D-3
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Alternative Post-Injection Site Care Timeframe
Describe the alternative post-injection site care timeframe and provide the demonstration
made under 40 CFR 146.82(a)(18), if that demonstration has been approved by the UIC
Program Director. The demonstration of an alternative post-injection site care timeframe
must meet the criteria under 40 CFR 146.93(c)(l) and (2). The description here should
include expected dates that a non-endangerment demonstration may be made and
advanced schedules for PISC and site closure.
Site Closure Plan
Planned Remedial/Site Restoration Activities:
Describe plans for removing all surface equipment and restoring vegetation.
Information on Plugs for Monitoring Well #1:
Plug #1
Plug #2
Plug #3
Plug #4
Plug #5
Plug #6
Plug #7
Diameter of Boring in Which
Plug Will be Placed
Depth to Bottom of Tubing or
Drill Pipe
Sacks of Cement to be Used
(each plug)
Slurry Volume to be Pumped
Slurry Weight
Top of Plug
Bottom of Plug
Type of Cement or Other
Material
Method of Emplacement (e.g.,
balance method, retainer
method, or two-plug method)
Include additional tables for other monitoring wells.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
D-4
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Appendix E.
Sample Template of a Class VI Non-Endangerment Demonstration
-------
Appendix E: Sample Template of a USDW Non-Endangerment Demonstration
Facility Information
Facility name:
Facility contacts (names, titles, phone numbers, email addresses):
Location (town/county/etc.):
Introduction
Summary explanation of why owner or operator believes that USDWs are no longer
endangered, and primary supporting rationale. Include reference to later sections and
supporting data.
List of all USDWs that are in the vicinity of the GS project and information on depth,
presence of artificial penetrations, water quality, and use as a drinking water source.
Operational history, including total amount of carbon dioxide injected, characteristics of
the carbon dioxide stream, and total areal size of the area of review.
Summary of Existing Monitoring Data
Narrative description of all monitoring activities that have taken place at site, including
dates, types of monitoring, changes to monitoring.
All supporting information for any submitted monitoring data, as listed at Section 3.1.6.
Attachment 1: Series of tables summarizing ground water geochemistry data and pressure
measurements over time
Attachment 2: Series of graphs showing time-series trends at all site monitoring wells for
carbon dioxide, pH, TDS, any identified drinking water contaminants, and reservoir
pressure
Attachment 3: Final electronic submittal of all monitoring data, in database or accepted
format
Attachment 4: Maps showing most recent data on the extent of separate-phase carbon
dioxide, based on data from monitoring wells and geophysical surveys.
Attachment 5: Maps showing most recent pressure data as measured from monitoring
wells.
Comparison of Monitoring Data and Model Predictions
Narrative comparison of monitoring data and model predictions from most recently
calibrated computational model.
All supporting information for modeling submittals, as described in the UIC Program
Class VI Well Area of Review Evaluation and Corrective Action Guidance.
Attachment 6: Series of time-series graphs and/or maps comparing model predictions and
monitoring results of reservoir pressure.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
E-l
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Attachment 7: Series of maps comparing evolution of the separate-phase carbon dioxide
plume based on monitoring results and modeling predictions.
Attachment 8: Series of tables and/or other supporting data that document model
calibration procedures, and relative difference in model predictions and calibration target
data.
Evaluation of Carbon Dioxide Plume
Narrative evaluation of the risks to USDWs posed by the carbon dioxide plume (both
separate-phase and dissolved) over time, including current conditions.
Quantitative evaluation of current plume migration rates in all directions away from the
injection well, including vertically. If plume migration is still occurring, calculation of
estimated timeframes for plume to reach any known migration pathways and/or USDWs.
Evaluation of Mobilized Fluids
Narrative evaluation of the extent of fluid migration at the project over time and the risks
posed to any USDWs by fluid mobilization.
Listing of all drinking water contaminants present in the injection zone and any overlying
zones impacted by the project, and identification of the original source of all drinking
water contaminants (e.g., contaminant in the carbon dioxide stream, dissolution of
mineral matrix).
Quantitative or semi-quantitative prediction of the fate and transport of any drinking
water contaminants in the future.
Evaluation of areas exhibiting elevated levels of TDS and evaluation of future migration
of high TDS water.
Evaluation of Reservoir Pressure
Narrative evaluation of the risks to USDWs posed by elevated pressure historically at the
site and currently.
Quantitative comparison of current pressure to thresholds necessary to force fluid from
the injection zone into the lowermost USDW and/or comparison of current reservoir
pressure levels and pre-injection levels.
Predictions of future pressure trends and reference to any supporting analyses (e.g.,
modeling).
Evaluation of Potential Conduits for Fluid Movement
Reference to listing of all artificial penetrations present in vicinity of GS project that may
penetrate the confining zone. This list should be included in the permit application as
required by 40 CFR 146.83(f)(4).
For each artificial penetration, explanation of any assessments/tests conducted to evaluate
risks to USDWs.
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
E-2
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Appendix F.
Sample Template of a Notice of Intent to Close a GS Project
-------
Appendix F: Sample Template for a Notice of Intent to Close a GS Project
[Today's Date]
Insert Name of Owner or Operator
Insert Return Address
To: Insert Name of UICProgram Director
In compliance with 40 CFR 146.93(d) of the United States Code of Federal Regulations (CFR), this
document is to provide notice to the Director of the UIC Class VI Program of [insert name of owner or
operator]'s intention to close the [insert name of facility]geologic sequestration (GS) project. The GS
project to be closed is located at: [insert location of facility (e.g., town, county)].
Closure is anticipated to occur on: [insertprojected closure date, no less than 120 days after the date of
this letter].
Use one of the following two paragraphs as appropriate depending on whether changes to the site
closure plan are needed:
Please note that [insert name of owner or operator] intends to close the project as described in the
approved Post-Injection Site Care and Site Closure Plan that was submitted to satisfy the permit
application requirements at 40 CFR 146.82 for [insertpermit number],
OR
Please note that, based on a review of information collected since submittal of the Post-Injection Site Care
and Site Closure Plan to satisfy the permit application requirements at 40 CFR 146.82 for [insert permit
number], [insert name of owner or operator] has identified some needed changes to the site closure plan.
A revised site closure plan is attached to this letter.
If you have any questions about the planned closure of [insert name ofproject/facility], please contact me
or any of the following staff:
Primary contact: Insert name, title, phone, number/email address
Additional contact (e.g., legal contact): Insert name, title, phone, number/email address
(as necessary)
Additional contact (e .g., chief engineer): Insert name, title, phone, number/email address
(as necessary)
Sincerely,
Insert name of owner or operator contact
Insert title
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
F-l
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Appendix G.
Sample Template of a GS Project Closure Report
-------
Appendix G: Template for a Site Closure Report
Facility Information
Facility Name:
Facility Address:
Facility Contacts (names, titles, phone numbers, email addresses):
Location (town/county/etc.):
Permit Number:
Injection Well Plugging (Attach copies of the plugging reports for all injection wells associated
with the project.)
Monitoring Well Plugging
Results of tests or measures to determine bottomhole reservoir pressure:
Results of external mechanical integrity test(s):
Information on Plugs for Monitoring Well #1: (to be repeated for each monitoring well)
Monitoring Well Location
Monitoring Well Depth
Plug #1
Plug #2
Plug #3
Plug #4
Plug #5
Plug #6
Plug #7
Diameter of Boring in Which
Plug Was Placed
Depth to Bottom of Tubing or
Drill Pipe
Sacks of Cement Used (each
plug)
Slurry Volume that was
Pumped
Slurry Weight
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
G-l
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Plug #1
Plug #2
Plug #3
Plug #4
Plug #5
Plug #6
Plug #7
Top of Plug
Bottom of Plug
Type of Cement or Other
Material
Method of Emplacement (e.g.,
balance method, retainer
method, or two-plug method)
Casing and Tubing Record after Plugging
Size
Weight (lb/ft)
That was put in Well (ft)
That was left in Well (ft)
Diameter of Boring
Remedial/Site Restoration Activities:
Include a description of completed site restoration activities such as removing all surface
equipment and restoring vegetation (or status, as appropriate).
Survey Plat
Name of the agency with which the survey plat was filed.
A copy of a survey plat that has been submitted to the local zoning authority designated by
the UIC Program Director. It must indicate the location of the injection well relative to
permanently surveyed benchmarks, pursuant to 40 CFR 146.93(f)(1). EPA recommends
including the locations of all monitoring wells relative to permanently surveyed benchmarks.
Notifications
Provide/attach copies or evidence of:
Notation on the deed to the facility property that the land has been used for GS.
The name of the state agency, local authority, and/or tribe with which the survey plat was
filed, as well as the address of the EPA Regional Office to which it was submitted.
Documentation of appropriate notification and information to state, local, and tribal
authorities that have authority over drilling activities.
The volume of fluid injected, the injection zone(s) into which carbon dioxide was injected,
and the time period of injection.
Information on the source and composition of the carbon dioxide (recommended).
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
G-2
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Insert/attach laboratory reports (or a representative report, if the carbon dioxide stream was
relatively constant in composition). Include the name of the laboratory, analytical techniques,
and quality assurance and surveillance measures.
Analyte
Representative Percentage
Carbon dioxide
H2S
Nitrogen
Other hydrocarbon gases (e.g., methane,
ethane)
Others
Certification
I certify under the penalty of law that I have personally examined and am familiar with the information submitted in
this document and all attachments and that, based on my inquiry of those individuals immediately responsible for
obtaining the information. I believe that the information is true, accurate, and complete. I am aware that there are
significant penalties for submitting false information, including the possibility of fine and imprisonment. (Ref. 40
CFR 144.32)
Name and Official Title (Please type or print)
Signature
Date Signed
Draft UIC Program Guidance on Class VI Well
Plugging, Post-Injection Site Care, and Site Closure
G-3
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