V>ERr\ Geologic Sequestration of
Carbon Dioxide
United States
Environmental Protection
Agency
Underground Injection
Control (UIC) Program
Class VI Well Construction
Guidance
May 2012
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Office of Water (4606M)
EPA816-R-11-020
May 2012
http ://water. epa. gov/drink/
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Disclaimer
The Class VI injection well classification was established by 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 done to provide information and recommendations that may be helpful
for 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 public notice.
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
EPA's Federal Requirements Under the Underground Injection Control Program for Carbon
Dioxide Geologic Sequestration Wells, are codified in the US Code of Federal Regulations [40
CFR 146.81 et seq.], referred to as the Class VI Rule. The Class VI Rule establishes a new class
of injection well (Class VI) and sets minimum federal technical criteria for Class VI injection
wells for the purpose of protecting underground sources of drinking water (USDWs). This
guidance is part of a series of technical guidance documents that EPA is developing to support
owners or operators of Class VI wells and the UIC Program permitting authorities in the
implementation of the Class VI Rule. The Class VI Rule and associated documents are available
at http://water.epa.gov/type/groundwater/uic/wells sequestration.cfm.
This UIC Program Class VI Well Construction Guidance describes the construction and
operating requirements unique to Class VI injection wells and provides suggested options for
meeting the Class VI Rule requirements for well materials, design, and construction.
Injection well construction is a critical aspect of the Class VI Rule. Proper well construction is
necessary to ensure that carbon dioxide is safely injected into and contained within the targeted
injection zone for the protection of USDWs. Improper well construction can contribute to a loss
of mechanical integrity which potentially may lead to well failure and potential leakage of
carbon dioxide from the well into USDWs. A well that has lost mechanical integrity can serve as
a conduit for fluid migration out of the injection zone or serve as a conduit for the migration of
native formation fluids between USDWs and other permeable zones. Improper well construction
may also result in the carbon dioxide not reaching the intended injection zone.
Assessments of appropriate construction materials and design for these new Class VI injection
wells are based on the experience of decades of deep injection well construction and operation
under the UIC Class I and Class II well programs. This guidance also draws from the latest
research being conducted regarding the injection of carbon dioxide for geologic sequestration
(GS) and from the materials and technology knowledge that has been developed over many
decades by the oil and gas industry to drill and construct production and injection wells in oil and
gas fields.
This guidance describes, for Class VI injection well owners or operators, the construction,
testing, and operating requirements for an approved Class VI injection well. It includes guidance
and recommendations on how to meet these requirements. This document also describes the
information that the UIC Program Director will evaluate when reviewing a permit application for
a Class VI injection well. There are many resources available on well construction; therefore,
this guidance is focused on meeting the requirements of the Class VI Rule for Class VI well
construction and operation.
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Table of Contents
Disclaimer i
Executive Summary ii
Table of Contents iii
List of Figures v
Acronyms and Abbreviations vi
Definitions vii
1 Introduction 1
1.1 The Importance of Well Construction 1
1.2 Purpose 2
2 Construction Requirements for Class VI Injection Wells 4
2.1 Preventing Fluid Movement Outside of Injection Zone 4
2.1.1 Demonstrating Mechanical Integrity 4
2.1.2 Typical Injection Well Components Preventing Fluid Movement 5
2.2 Designing Class VI Wells for Logging and Workovers 8
2.2.1 Design Considerations 8
2.2.2 Continuous Monitoring of the Annulus 9
2.2.3 Deviation Checks 10
2.2.4 CaliperLogs 10
2.3 Well Plan and Design Information to Submit to the UIC Program Director With a Class
VI Injection Well Permit Application 13
2.4 Designing Class VI Wells for Down-hole Stresses 13
2.4.1 Types of Stresses 13
2.4.2 Corrosion Considerations 17
2.4.3 Stress and Compatibility Information to Submit to the UIC Program Director
with a Class VI Injection Well Permit Application 19
2.5 Cementing the Casing of Class VI Wells 20
2.5.1 Different Stage Options for Cementing 22
2.5.2 Cementing Information to Submit to the UIC Program Director with the Class
VI Injection Well Permit Application 24
2.5.3 Cement Compatibility 25
2.5.4 Cement Bond and Variable Density Logs 27
2.6 Selecting the Tubing and Packer of Class VI Wells 29
2.7 Additional Well Construction Information to Submit to the UIC Program Director with
a Class VI Injection Well Permit Application 30
2.8 Selecting Surface and Down-Hole Shut-Off Devices for Class VI Wells 31
2.8.1 Surface Safety Systems 31
2.8.2 Down-Hole Devices 31
2.8.3 Shut-off System Information to Submit to the UIC Program Director with a
Class VI Injection Well Permit Application 32
3 Considerations for Conversion of Other Well Types to Class VI 33
3.1 Permit Application Submittals 34
3.2 Considerations for Repermitted Wells 35
3.2.1 Material Strength 35
3.2.2 Material Compatibility 36
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3.2.3 Well Design 37
3.2.4 Mechanical Integrity 38
4 Operating Requirements for Class VI Injection Wells 40
4.1 Injection Pressure Requirements of Class VI Wells 40
4.2 Monitoring of the Annular Space of Class VI Wells 41
4.3 Maintaining Mechanical Integrity of Class VI Wells 41
5 Conclusions 42
6 References 44
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List of Figures
Figure 1. Relevant API Specifications and Recommended Practices (RP) for Injection Well
Construction 2
Figure 2. Selected Class VI Injection Well Related Construction References 3
Figure 3. Schematic of a Class VI Injection Well 5
Figure 4. Schematic of a Well Packer 8
Figure 5. Schematic of a Landing Nipple 9
Figure 6. Mechanical Caliper Logging Tool 12
Figure 7. Stresses on the Well Bore 16
Figure 8. API Well Cement Types 17
Figure 9. Schematic of Two-Stage Cementing 23
Figure 10. Reactions of Carbon Dioxide with Cement 26
Figure 11. Cement Bond Log and Variable Density Log Displays 28
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Acronyms and Abbreviations
API American Petroleum Institute
C-S-H Calcium Silica Hydrate
EOR Enhanced Oil Recovery
EGR Enhanced Gas Recovery
EPA U.S. Environmental Protection Agency
GRE Glass Reinforced Epoxy
GS Geologic Sequestration
H2O Water
MI Mechanical Integrity
MIT Mechanical Integrity Test
MPa megapascals
Pa pascals
ppm parts per million
RP Recommended Practice
SCADA Supervisory Control and Data Acquisition
SDWA Safe Drinking Water Act
SS Stainless Steel
TDS Total Dissolved Solids
UIC Underground Injection Control
USDW Underground Source of Drinking Water
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Definitions
Key to definition sources:
1: Class VI Rule Preamble.
2: EPA's UIC website (http://water.epa.gov/tvpe/groundwater/uic/glossary.cfm).
3: Definition drafted for the purposes of this document.
4:40CFR146.81(d).
5: 40 CFR 144.6(f) and 144.80(f).
6:40CFR144.3.
Annulus means the space between the well casing and the wall of the bore hole; the space
between concentric strings of casing; the space between casing and tubing.1
Ballooning refers to the expansion of tubular well materials caused by high pressure.3
Ball valve A valve consisting of a hole drilled through a ball placed in between two seals. The
valve is closed when the ball is rotated in the seals so the flow path no longer aligns and is
blocked.1
Brine refers to water that has a quantity of salt, especially sodium chloride, dissolved in it. Large
quantities of brine are often produced along with oil and gas.2
Buoyancy refers to the upward force on one phase (e.g., a fluid) produced by the surrounding
fluid (e.g., a liquid or a gas) in which it is fully or partially immersed, caused by differences in
pressure or density.1
Burst strength refers to the pressure, when applied normal to the surface, that will cause a
mechanical well component to rupture.3
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 does not apply to any carbon dioxide stream that meets the definition of a
hazardous waste under 40 CFR Part 261.4
Casing refers to the 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.1
Cement refers to the 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 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.l
Choke refers to a device using an orifice to regulate flow or pressure.3
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Choke bean refers to a device in a choke that regulates flow through the choke.3
Class VI wells means wells that are not experimental in nature that are used for geologic
sequestration of carbon dioxide beneath the lowermost formation containing a USDW; or, wells
used for geologic sequestration of carbon dioxide that have been granted a waiver of the
injection depth requirements pursuant to requirements at 40 CFR 146.95; or, wells used for
geologic sequestration of carbon dioxide that have received an expansion to the areal extent of an
existing Class II enhanced oil recovery or enhanced gas recovery aquifer exemption pursuant to
40 CFR 146.4 and 144.7(d).5
Collapse strength refers to the pressure which will cause a mechanical well component to
collapse.3
Confining zone means a geologic formation, group of formations, or part of a formation
strati graphically overlying the injection zone(s) that acts as barrier to fluid movement. For Class
VI wells operating under an injection depth waiver, confining zone means a geologic formation,
group of formations, or part of a formation strati graphically overlying and underlying the
injection zone.4
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.1
Deviation angle means the angle from which the well bore has deviated from vertical.1
Drilling mud means a heavy suspension used in drilling an "injection well," introduced down
the drill pipe and through the drill bit.6
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.1
Flapper valve means a valve consisting of a hinged flapper that seals the valve orifice. In Class
VI wells, flapper valves can engage to shut off the flow of the carbon dioxide when acceptable
operating parameters are exceeded.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.1
Free water refers to water in cement which is not chemically bound to the cement and is free for
hydration.
Geologic sequestration means the long-term containment of a gaseous, liquid or supercritical
carbon dioxide stream in subsurface geologic formations. This term does not apply to its capture
or transport.4
Geologic sequestration project means an injection well or wells used to emplace a carbon
dioxide stream beneath the lowermost formation containing a USDW; or, wells used for geologic
sequestration of carbon dioxide that have been granted a waiver of the injection depth
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requirements pursuant to requirements at 40 CFR 146.95; or, wells used for geologic
sequestration of carbon dioxide that have received an expansion to the areal extent of an existing
Class II enhanced oil recovery or enhanced gas recovery aquifer exemption pursuant to 40 CFR
146.4 and 144.7(d). It includes the subsurface three-dimensional extent of the carbon dioxide
plume, associated area of elevated pressure, and displaced fluids, as well as the surface area
above that delineated region.4
Injectate means the fluids injected. For the purposes of the Class VI Rule, this is also known as
the carbon dioxide stream.1
Injection zone means a geologic formation, group of formations, or part of a formation that is of
sufficient areal extent, thickness, porosity, and permeability to receive carbon dioxide through a
well or wells associated with a geologic sequestration project.4
Landing nipple refers to a component made of a short heavy piece of tubular material that has a
machined interior to provide a seal and a locking profile. Landing nipples enable the installation
of flow control devices such as plugs, chokes, and valves.3
Logging means the measurement of physical properties in or around the well.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).1
Mechanical integrity test 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.1
Microseismic monitoring refers to a technique that uses instruments to measure very small
movements in the earth.3
Packer means a mechanical device that seals the outside of the tubing to the inside of the long-
string casing, isolating an annular space.1
Portland cement refers to a hydraulic cement made by reacting a pulverized calcium silicate
hydrate material (C-S-H), which in turn is made by heating limestone and clay in a kiln, with
water to create a calcium silicate hydrate and other reaction products.3
Pozzolan refers to a siliceous or aluminous material that is used as an additive in Portland
cement to reduce the calcium hydroxide content and increase the C-S-H content.3
Radius of curvature refers to the radius of a circle whose arc represents the curvature in a given
well bore.3
Reaming refers to widening a borehole using a drilling bit or tool.3
Shoe refers to a rounded collar that is screwed onto the bottom of the casing. It has a check valve
in it to prevent backflow of cement slurry. During installation it guides the casing toward the
center of the well bore. During cementing cement flows through the shoe and into the space
between the casing and formation.3
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Shut-off device refers to a valve coupled with a control device which closes the valve when a set
pressure or flow value is exceeded. Shut-off devices in injection wells can automatically shut
down injection activities when operating parameters unacceptably diverge from permitted
values.2
Supercritical fluid refers to a fluid above its critical temperature (31.1°C for carbon dioxide)
and critical pressure (73.8 bar for carbon dioxide).1
Tensile strength refers to the maximum force an element can take in tension before it breaks.3
Tiltmeter refers to an instrument used to measure very small changes in the tilt of an object from
the horizontal.3
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.1
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.2
Underground Injection Control Program refers to the program EPA, or an approved state, is
authorized to implement under the Safe Drinking Water Act (SDWA) that is responsible for
regulating the underground injection of fluids by injection wells. This includes setting the federal
minimum requirements for construction, operation, permitting, and closure of underground
injection wells.3
Underground Injection Control Program Director refers to the chief administrative officer of
any state or tribal agency or EPA Region that has been delegated to operate an approved UIC
program.
Underground Source of Drinking Water means an aquifer or portion of an aquifer that
supplies any public water system or that contains a sufficient quantity of ground water to supply
a public water system, and currently supplies drinking water for human consumption, or that
contains fewer than 10,000 mg/L total dissolved solids and is not an exempted aquifer.1
Well bore refers to the hole that remains throughout a geologic (rock) formation after a well is
drilled.3
Wireline refers to a wire or cable that is used to deploy tools and instruments downhole and that
transmits data to the surface.3
Workover refers to any maintenance activity performed on a well that involves ceasing injection
or production and removing the wellhead.3
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1 Introduction
1.1 The Importance of Well Construction
The United States Environmental Protection Agency (EPA) established the Underground
Injection Control (UIC) program in the 1980s to protect underground sources of drinking water
(USDWs) from contamination by injection well activities. EPA''s Federal Requirements Under
the Underground Injection Control (UIC) Program for Carbon Dioxide Geologic Sequestration
Wells, codified in the US Code of Federal Regulations [40 CFR 146.81 et seq.], is referred to as
the Class VI Rule. The Class VI Rule establishes a new class of underground injection well
(Class VI) and sets minimum federal technical criteria for Class VI injection wells for the
purpose of protecting USDWs from endangerment. The UIC Program Class VI injection well
requirements are designed to protect USDWs and prevent endangerment from carbon dioxide
injection and related activities. The requirements will also ensure that the carbon dioxide reaches
the intended injection zone and is properly confined.
The materials and techniques for constructing wells in a way that prevents the migration of fluids
along the well bore are well documented and have been employed in the construction of many
Class II wells regulated under the Safe Drinking Water Act (SDWA). For decades, Class II wells
have been constructed and operated for injection of carbon dioxide into mature oil reservoirs to
enhance oil production. For these enhanced oil recovery (EOR) operations, thousands of
injection wells have been successfully constructed and operated by numerous oil and gas
companies in many different oil fields in the United States. In addition, Class I hazardous waste
injection has provided experience in the injection and containment of buoyant and corrosive
material.
While there are some similarities between carbon dioxide injection in Class VI wells and carbon
dioxide injection in Class II wells, there are also some important differences. These differences
include higher injection rates for geologic sequestration (GS), as Class VI wells are likely to
inject more carbon dioxide into formations than Class II wells, resulting in higher pressures.
Higher rates are also of concern because carbon dioxide is less dense than most subsurface fluids
and will tend to migrate to the top of the injection zone. Also, Class II wells are known to inject
into geologic structures that trap hydrocarbons and thus carbon dioxide, whereas less may be
known initially about the geology (e.g., structure and stratigraphy) at GS sites. The time frame of
Class VI injection will likely be considerably longer than is typical in Class II wells.
Additionally, carbon dioxide has the potential to be corrosive in the presence of water. Proper
well construction should address this potential corrosivity and is essential for the protection of
USDWs. An improperly constructed well can lead to loss of well integrity that could lead to
carbon dioxide or formation fluid leakage from the well bore and into USDWs. Flaws in
construction may also allow carbon dioxide to leak from the formation after it has been injected.
Finally, since the goal of GS is the long term storage of carbon dioxide, the well integrity must
be maintained for the life of the project or it could potentially serve as a conduit for carbon
dioxide flow out of the injection zone even after injection has ceased.
The American Petroleum Institute (API) is a professional trade organization for the oil and gas
industry. The API develops recommended standards and practices, including practices related to
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well construction and operation which are used throughout the industry. These oil and gas well
technologies and practices provide a foundation for Class VI well construction technology. In
addition, standard practices from Class I injection well construction inform Class VI
requirements. Figure 1 lists API reports that provide specifications and recommended best
practices applying to well construction. Figure 2 includes several references that provide details
on well construction; many are specific to wells injecting carbon dioxide. Complete references
for the literature mentioned in Figures 1 and 2 are provided in the Reference Section (Section 6)
of this document.
The remainder of this guidance addresses Class VI injection well construction to ensure the
prevention of fluid movement, highlights the unique challenges of well construction due to the
buoyancy and corrosivity of carbon dioxide or resulting reaction products, and assists potential
Class VI injection well owners or operators in complying with the Class VI injection well
construction and operation requirements. EPA recommends that the references listed in this
guidance, in addition to other appropriate references, be consulted for general details on aspects
of typical deep injection well construction.
Relevant API Specifications and Recommended Practices (RPs)
API Specification 5CT- Specification for Casing and Tubing
API RP 5C1 - Recommended Practices for Care and Use of Casing and Tubing
API RP 10B-2 - Recommended Practice for Testing Well Cements
API Specification IDA - Specification on Cements and Materials for Well Cementing
API RP 10D-2 - Recommended Practice for Centralizer Placement and Stop Collar Testing
API Specification 11D1 - Packers and Bridge Plugs
API RP 14B- Recommended Practice 14B, Design, Installation, Repair, and Operation of
Subsurface Safety Valve Systems
API RP 14C- Recommended Practice 14C, Recommended Practice for Analysis, Design,
Installation and Testing of Basic Surface Safety Systems for Offshore Production Platforms
API Guidance Document HF1 - Hydraulic Fracturing Operations - Well Construction and
Integrity Guidelines
Figure 1. Relevant API Specifications and Recommended Practices (RP) for Injection Well
Construction
1.2 Purpose
This document is intended as a resource to help familiarize well owners or operators, along with
regulators, with the aspects of Class VI well construction that are important for achieving well
integrity and preventing leaks into a USDW. It is intended to guide owners or operators on
meeting the construction requirements of the Class VI Rule. This is not intended to be a
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comprehensive guidance explaining all the details of injection well construction. Injection well
construction is a well-known practice and there are many resources available that describe the
necessary construction details. This document is intended to be used as a reference that
highlights some important considerations for Class VI injection wells in particular, including
addressing the buoyancy and corrosivity of carbon dioxide, and to mention other previously
published more detailed documents for additional assistance.
Well Construction References
General Construction
Randhol et al., 2007. Ensuring Well Integrity in Connection with CO2 Injection
Lyons and Plisga, 2005. Standard Handbook of Petroleum and Natural Gas Engineering 2nd
Edition
Bellarby, 2009. Well Completion Design
Aadnoy, 1996. Modern Well Design
EPA, 1982. Well Construction Practices and Technology
Cementing
Watson, 2009. CO2 Storage: Wellbore Integrity Evaluation and Integrity across the Caprock
Sweatman et al., 2009. Effective Zonal Isolation for CO2 Sequestration Wells
Nelson and Guillot. 2006. Well Cementing
Materials Compatibility
Meyer, 2007. API Summary of Carbon Dioxide Enhanced Oil Recovery Injection Well
Technology
Horizontal Well Issues
Joshi, 1991. Horizontal Well Technology
Cement Evaluation
Duguid and Crow, 2007. CO2 Well Integrity and Wellbore Monitoring
Safety Valves
Garner et al., 2002. At the Ready: Subsurface Safety Valves
Sides, 1992. Injection Safety Valve Solutions for CO2 WAG Cycle Wells
Drilling
Medley and Reynolds, 2006. Distinct Variations of Managed Pressure Drilling Exhibit
Application Potential
Figure 2. Selected Class VI Injection Well Related Construction References
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2 Construction Requirements for Class VI Injection Wells
The Class VI Rule details the requirements for Class VI well construction [40 CFR 146.86(a)].
These are generally performance-based requirements developed to ensure that Class VI injection
wells are constructed in a manner that ensures safe underground injection and storage of carbon
dioxide and prevents endangerment of USDWs. These requirements address well components
that serve to restrict the movement of both injectate and native fluids, address well operability,
and ensure that the carbon dioxide will reach the intended injection zone and remain confined.
2.1 Preventing Fluid Movement Outside of Injection Zone
The Class VI Rule requires that the Class VI injection well be constructed to prevent movement
of fluids into or between USDWs or other unauthorized zones [40 CFR 146.86(a)(l)]. This
requirement is one of the more critical aspects of the UIC program. Most elements of the specific
construction requirements of the Class VI Rule are intended to achieve this objective.
2.1.1 Demonstrating Mechanical Integrity
Mechanical integrity is a key concept related to the performance of an injection well, and the
prevention of injected fluid movement into or between USDWs or other unauthorized zones [40
CFR 146.88(d) and 146.89]. Mechanical integrity of the well is achieved by ensuring that each of
the components of the well are constructed with appropriate materials and are functioning
together as intended. Maintaining mechanical integrity helps prevent the well and well bore from
becoming conduits for fluid migration out of the injection zone. There are two aspects of
mechanical integrity: internal and external.
Internal mechanical integrity is the absence of significant leaks in the casing, tubing, or packer.
These well components act as the main barriers preventing contact between the injectate (the
injected carbon dioxide stream) and the surrounding geologic formations through which the well
has been drilled and constructed. Ensuring that these components are constructed properly with
appropriate materials and that they remain intact (e.g., are not compromised and do not fail)
when subject to stresses or corrosive (and other) operational conditions may prevent carbon
dioxide from moving out of the well bore during injection. The pressure applied during an
internal mechanical integrity test should be limited to prevent casing ballooning that could create
cement defects.
External mechanical integrity is defined as the absence of significant leakage outside of the
casing. Maintaining external mechanical integrity ensures that the injected carbon dioxide, which
tends to be more buoyant than native formation fluids, does not migrate upwards from the
injection zone after it has been injected; therefore ensuring zonal isolation of the injected carbon
dioxide. The main construction component for ensuring external mechanical integrity is the
cement between the casing and the borehole wall. Properly emplaced cement should both prevent
fluid movement by sealing the annular space between the casing and the formation, and protect
the well casing from stress and corrosion. Cementing considerations for Class VI injection wells
are discussed later in Section 2.5 of this document.
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2.1.2 Typical Injection Well Components Preventing Fluid Movement
Figure 3 illustrates the typical components of an injection well that are relevant to maintaining
mechanical integrity and to ensuring that fluids do not migrate from the injection zone into
USDWs. These components are the casing, tubing, cement, and packer.
Injected CO2
• Cement
• Surface casing
Lowermost USDW Base
-Intermediate casing
- Injection tubing
-Annulus
-Long string casing
"Borehole
• Injection packer
Injection zone perforations
• Total depth
Note: Figure not to scs/e
Schematic of Class VI Injection Well
Figure 3. Schematic of a Class VI Injection Well
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Casing
An injection well typically consists of one or more successively smaller concentric pipes
(essentially thick walled pipes within pipes) placed in the well bore. All but the innermost pipe
(called the tubing) serve as well casings (see Figure 3). Leaks in the casing can allow fluid to
escape into unintended zones or allow fluid movement between zones. The construction
materials selected for the casing and the casing design must be appropriate for the fluids and
stresses encountered in the site-specific down-hole environment [40 CFR 146.86(b)(l)]. See
Section 2.4.2 for additional discussion of appropriate materials for casing. Carbon dioxide in
combination with water forms carbonic acid, which is corrosive to many well components.
Native fluids can also contain corrosive elements such as brines and hydrogen sulfide. Therefore,
the casing must be manufactured of materials that are compatible with fluids with which it might
come into contact [40 CFR 146.86(b)(l)].
The surface casing is the largest in diameter. It must extend from the ground surface through the
base of the lowermost USDW [40 CFR 146.86(b)(2)]. This casing is emplaced and cemented
into the bore hole from the base of the lowermost USDW up to the ground surface, serving to
both prevent fluids from entering USDWs and prevent migration of fluids between USDWs and
other formations, as the casing isolates the injection fluid. If the lowermost USDW is particularly
deep, multiple strings of casing may be used as surface casing. Each string must be cemented to
the surface. The smallest diameter casing extends into the injection zone and is referred to as the
long-string casing. The long-string casing is routinely perforated in the injection zone to allow
fluid to flow out of the injection well and into the injection formation. The spaces between the
long-string casing and the surface casing, the long-string casing and the geologic formation, and
the surface casing and the geologic formation are called annuli. These annuli are required to be
filled with cement in Class VI injection wells, along both the surface and the long-string casing
[40 CFR 146.86(b)(3)]. The Class VI Rule requires the long-string casing extend from the
ground surface down to the injection zone [40 CFR 146.86(b)(3)].
If the well is very deep, there may be one or more intermediate casings of intermediate diameter
between the surface casing and the long-string casing. These casings would be cemented in place
as well [40 CFR 146.86(b)(3)]. Cementing considerations for Class VI injection wells are
discussed in Section 2.5 of this document.
In some cases, owners or operators may choose to use liners in injection wells. Liners are similar
to casing except they are supported by hangers within the casing itself instead of from the
surface. Liners can be used as a completion technique or as a remedial solution to contain a leak
in the casing. Liners, if used, are well materials and must meet all the requirements that would
apply to casing. This includes being cemented to the surface, having sufficient structural
strength, and compatibility with the fluids with which they are expected to come into contact [40
CFR 146.86(b)(l) and 146.86(b)(4)]. If an owner or operator plans to use a liner, EPA
encourages the owner or operator to communicate the need for the liner and to determine
appropriate construction techniques and testing required to ensure mechanical integrity of the
liner with the UIC Program Director. However, the use of liners may not always be the best
approach due to potential mechanical integrity impacts. Therefore, the owner or operator may
want to consider alternatives to liner use.
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Tubing
The tubing is a smaller pipe which runs inside the long-string casing from the ground surface
down to the injection zone. The injectate moves down the tubing, out through the perforations in
the long-string casing, and into the injection zone. The tubing ends at a point just below the
packer. The space between the long-string casing and tubing is referred to as the annulus and
must be filled with a noncorrosive fluid [40 CFR 146.88(c)].
The tubing forms another barrier between the injected fluid and the long-string casing. Like the
casing, it must be designed to withstand the stresses and fluids with which it will come into
contact [40 CFR 146.86(c)(l)]. Appropriate materials for tubing are discussed further in Section
2.4.2. The tubing and long-string casing act in concert to form two levels of protection between
the carbon dioxide stream and the geologic formations above the injection zone.
Cement
Cement is important for providing structural support of the casing, preventing contact of the
casing with corrosive formation fluids, and preventing vertical movement of fluids and gases,
including carbon dioxide. Current research indicates that a good cement job is one of the key
factors in effective zonal isolation (Watson, 2009; Bachu and Bennion, 2009).
A good cement job begins with the drilling process. The down-hole pressures, fluids, and drilling
mud can be managed when drilling so that down-hole conditions are suitable for well
construction, cementing, and subsequent injection of carbon dioxide.
Proper placement of the cement for a Class VI injection well is critical, as errors can be difficult
to fix later. Failing to cement the casing its entire length, failure of the cement to bond with the
casing or formation, not centralizing the casing during cementing, cracking, and alteration of the
cement can all allow migration of fluids along the well bore. If carbon dioxide escapes the
injection zone through the well bore because of a failed cement job, the well would be out of
compliance with the Class VI Rule and required to cease injection [40 CFR 146.88(f)]. It is
important to consider, when planning for the cementing of Class VI wells, that carbon dioxide
can react with the typical Portland cements commonly used in well construction. Additional
discussion of cement reactions as well as alternatives to Portland cement are included in Section
2.5.3.
Packer
A packer is a customary sealing device at the lower end of the tubing which keeps fluid from
migrating from the injection zone into the annulus between the long-string casing and tubing
(See Figure 4). It must also be made of materials that are compatible with fluids with which it
will come into contact [40 CFR 146.86(c)(l)].
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Figure 4. Schematic of a Well Packer
2.2 Designing Class VI Wells for Logging and Workovers
Logging involves lowering instruments into the well to perform testing and monitoring of the
well or the surrounding geologic formation. Numerous tests and instruments are used to evaluate
the formation, determine the reservoir pressure, assess the condition of the well bore, determine
the mechanical integrity of the well, and track the movement of the carbon dioxide plume. All of
these activities are essential for the proper operation of a Class VI well. In addition, periodic
maintenance will need to be performed during the life of an injection well. Maintenance through
a well workover involves sealing off the well, removing the wellhead and either removing
equipment or lowering maintenance tools into the well. These workovers are essential to
maintaining a properly functioning well and can include replacing and repairing tubing, packer,
valves and sensors, repairing corroded casing, and remedial cementing. During a workover, tools
may need to be lowered into the well, along with valves to seal the lower portions of the well.
Logging activities are generally planned; workovers may be planned, but may also arise as result
of an emergency. Wells must be designed to accommodate tools necessary for these logging and
workover activities [40 CFR 146.86(a)(2)]. Failure to do so can result in the loss of important
information or even in the loss of the entire well, resulting in noncompliance with the Class VI
Rule that would require cessation of injection if mechanical integrity were lost [40 CFR
146.88(f)].
2.2.1 Design Considerations
Two factors determine if the well is appropriately constructed to allow the necessary equipment
for logs and workovers: the diameter and the radius of curvature of the well. To meet the
requirements of the Class VI Rule that the well be designed to allow testing [40 CFR
146.86(a)(2)], the diameter of the well must be larger than the largest instrument/tool that may be
used in the well. The radius of curvature of the well can limit the length of the instruments/tools
that can be used. The casing and radius of curvature of the well should be designed so that any
appropriate equipment/tool that may be used in the well will pass without getting stuck. The
requirements for testing, monitoring and site characterization of a Class VI injection well are
codified in the Class VI Rule and discussed in both the Draft UIC Program Class VI Well Site
Characterization Guidance and the Draft UIC Program Class VI Well Testing and Monitoring
Guidance. The suggested appropriate equipment sizes can be obtained from the specific
equipment manufacturers.
Owners or operators may also want to consider installing landing nipples above the packer.
Landing nipples allow for the installation of temporary safety valves that can be used as
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temporary replacements for failed down-hole safety valves or can be used to seal off the
formation from the well bore during a workover operation (see Figure 5). However, landing
nipples do present a protrusion into the tubing which can interfere with wireline equipment so
their use should be considered with respect to the entire Testing and Monitoring plan to ensure
maximum usefulness.
Figure 5. Schematic of a Landing Nipple
Liners may also affect the ability to perform logging and workover tasks. Liners narrow the
casing diameter and present an additional layer of metal through which logs have to be
conducted. If liner use is considered, these factors should be taken into account to ensure that the
ability to repair or monitor the well will not be impaired.
The owner or operator of the well must submit construction plans to the UIC Program Director
with the permit application [40 CFR 146.82(a)(12)]. Items such as casing diameter, radius of
curvature, and angle of deviation will typically be included in such plans. They must also submit
a Testing and Monitoring Plan in accordance with 40 CFR 146.90, which will include the tests
and specific pieces of equipment to be used during testing and logging of the well [40 CFR
146.82(a)(15)]. This information allows the UIC Program Director to determine whether the well
is capable of accommodating the necessary equipment for testing, monitoring, and maintenance
of the well. If any changes are made as a result of information obtained during the drilling of the
well, revised information must be submitted to the UIC Program Director before well operation
commences [40 CFR 146.82(c)(9)]. Additional information on the Testing and Monitoring Plan
can be found in the Draft UIC Program Class VI Well Testing and Monitoring Guidance.
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2.2.2 Continuous Monitoring of the Annulus
The well must be constructed to allow for continuous monitoring of the annular space between
the injection tubing and the long-string casing, [40 CFR 146.86(a)(3)]. Continuous monitoring
will require a pressure gauge. More details on the monitoring required and how to accomplish it
are provided in the Draft UIC Program Class VI Well Testing and Monitoring Guidance.
2.2.3 Deviation Checks
Deviation checks are required during drilling on all holes constructed by drilling a pilot hole that
is enlarged by reaming or another method [40 CFR 146.87(a)(l)]. Deviation checks measure the
deviation of the borehole from vertical. In many cases, a smaller-diameter pilot hole will be
drilled prior to construction of the injection well. In cases where the injection well borehole is
constructed by enlarging the pilot hole, the possibility exists for the accidental creation of two
'divergent' holes, which may act as vertical avenues for fluid movement. The main purpose of
deviation checks are to ensure no divergent holes have been drilled. Deviation checks also aid in
determining the path of the well and ensuring it reaches the intended injection zone. In order to
adequately test for divergent holes, a deviation check needs to be conducted on the pilot hole
prior to enlarging, and the final borehole.
Application
A deviation check measures the angle of the well and can detect whether the borehole is off of
true vertical. The deviation check can be conducted using measurement-while-drilling
equipment, or it can be performed by removing the drill and lowering a separate piece of
equipment on a wireline. Inclinometers are the simplest logging tools used to perform deviation
checks, and consist of a pendulum or other device lowered into the borehole that measures the
angle of the well relative to true vertical. Accel erometers are more advanced, and consist of an
electronic tool that measures the acceleration due to gravity. A set of three accelerometers
mounted on perpendicular axes can give three-dimensional information on the path of the
wellbore. More modern equipment also may include magnetometers or gyroscopes, which
directly measure borehole depth and direction. In all cases, the three-dimensional path of the well
bore is calculated from logging results using mathematical algorithms.
Interpretation
EPA anticipates that the results of the deviation survey will provide a representation of the three-
dimensional path of the pilot hole and the final enlarged borehole. Overlaying the schematics
will ensure that the original pilot hole has been completely encompassed by the final borehole,
and no divergent holes exist. If divergent holes are identified, the remaining depth of the
divergent pilot hole needs to be completely filled with cement, and the cementing records
provided to the UIC Program Director for approval prior to injection.
2.2.4 Caliper Logs
The Class VI regulations require that caliper logs be conducted before installation of the surface
casing, and before installation of the long-string casing [40 CFR 146.87(a)(2)(i) and 40 CFR
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146.87(a)(3)(i)]. The caliper log is a record of the borehole diameter as it varies with depth, and
is used to detect washed out zones that may have occurred during borehole drilling. Caliper log
results may also indicate the presence of fractures, but caliper logs alone are not an acceptable
form of a fracture finder log.
Application
Mechanical caliper logging tools consist of several detector arms fitted along a central shaft
(Figure 6). During measurement, the probe is lowered to the bottom of the borehole, and arms
are fully extended until they contact the borehole wall. As the logging tool is pulled upwards the
detector arms extend in locations with a large borehole diameter, and retract in locations with a
smaller diameter. The arms' movements are converted to an electrical signal that is transmitted
to the surface and recorded (EPA, 1982b).
Interpretation
The recorded caliper log is a graph of the internal radii measured by each arm as a function of
depth. One trace represents the average diameter of the borehole. The caliper log is analyzed to
ensure that the borehole diameter is consistent throughout the vertical length of the well, and
there has been no collapse or wash-out. The results from the caliper log are used to calculate the
amount of cement needed and to identify any potential areas of lost circulation. They may also
be used to correct logs that are dependent on the size of the borehole, such as gamma logs. After
casing installation, caliper logs may also be used as a form of a casing inspection log to measure
the internal radii of the casing, and detect breaks, distortion, or corrosion.
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Source: Schlumburger, 2009
Note: Figure not to scale
Large Diameter Caliper Tool with 60
Measuring Arms and Two Centralizers
Figure 6. Mechanical Caliper Logging Tool
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2.3 Well Plan and Design Information to Submit to the UIC Program Director With a
Class VI Injection Well Permit Application
The required project plans, mentioned in Section 2.2 and in more detail in the UIC Program
Class VI Well Project Plan Development Guidance, as well as the required construction material
and design information discussed in this guidance document, must be submitted to the UIC
Program Director as part of the Class VI permit application [40 CFR 146.82(a)(12) and 146.86].
The UIC Program Director should evaluate the information submitted on the proposed injection
well and compare that information to the related procedures and equipment proposed for use in
the Testing and Monitoring Plan for consistency. The Class VI Rule includes specific
construction requirements for components of the well such as the casing, tubing, cement, and
packer [40 CFR 146.86(b) and 146.86(c)]. Other Class VI injection well construction
requirements address elements of underground injection that are specific to GS, such as the
subsurface reaction products like carbonic acid [40 CFR 146.86(b)(5)].
If the casing does not appear to be large enough to accommodate the proposed equipment, the
UIC Program Director may require a larger casing or may require revisions to the Testing and
Monitoring Plan to direct the use of different tests or equipment so that the appropriate testing
devices and monitoring required by the Class VI Rule can be accommodated by the proposed
Class VI injection well design.
The UIC Program Director should also evaluate the construction aspects of the casing, tubing,
packer, and cement to ensure that they will not allow fluid migration out of the injection zone.
The UIC Program Director should review the materials used in these components to ensure their
compatibility with the carbon dioxide stream and the formation fluids. The strength of the
materials will also be reviewed to ensure their ability to withstand the stresses of the down-hole
environment. More details on specific elements that the UIC Program Director may review for
the casing, tubing, packer, and cement are found later in this document. The UIC Program
Director should review the proposed construction of the annular space between the tubing and
long-string casing to ensure that it allows measurement of pressure and other variables. For more
details, see the Draft UIC Program Class VI Well Testing and Monitoring Guidance.
2.4 Designing Class VI Wells for Down-hole Stresses
2.4.1 Types of Stresses
The Class VI Rule requires that the well be constructed to withstand anticipated stresses, last the
lifetime of the project, and be compatible with fluids with which the materials may be expected
to come into contact [40 CFR 146.86(b)(l)]. This requirement applies to the casing and cement.
Well materials in the down-hole environment are subject to multiple stresses. Stresses the owner
or operator should consider in well design and construction include, but are not limited to:
• Pressure from the injectate;
• Pressure from the formation;
• Tensile stress from the weight of the casing or tubing;
• Compressive stress during installation;
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• Cyclic stress from cycling the injection on and off;
• Stress from extreme temperatures; and
• Stresses from temperature changes.
Although not anticipated during normal operations, another source of potential stress could be
due to a rapid change in carbon dioxide volume in the event the carbon dioxide being injected
undergoes a phase change. For example, this might happen if there was a sudden loss of pressure
at the wellhead.
Horizontal and deviated wells can experience additional stresses not experienced by vertical
wells (Cernocky and Scholibo, 1995). Additional stresses are caused by the weight of the rock
column, especially in weak or unconsolidated formations. In vertical wells, the force from the
weight of the rocks is parallel to the well bore and does not impart additional stress on the well.
The portion of the casing in the curved portion of the well also experiences additional stress from
being curved. Installation through the bend also causes higher friction and torque to be exerted
on the casing. Because of the additional stresses on the casing in horizontal wells, thicker casing
walls or stronger casing materials may be advantageous.
Extreme temperatures can provide stress on well materials. High temperatures can cause
expansion of materials and weaken their strength. If cold fluids are injected they can result in
freezing of annular fluids which can apply additional stresses on the well materials.
Cyclic stresses can also be produced by fluctuations in temperatures, for example if the
temperature of the fluids injected varies substantially from the reservoir pressure and injection is
not continuous. Any of these stresses can cause components to fail and potentially lead to the
escape of fluids from the injection zone and a violation of Class VI construction requirements
[40 CFR 146.86(a)(l)]. If this occurs, the owner or operator will be required to cease injection
[40 CFR 146.88(f)].
The well must be constructed to withstand all the stresses of the down-hole environment [40
CFR 146.86(a)(l)]. Figure 7 presents the different stresses or forces that can be encountered and
EPA recommends to be factored into the Class VI injection well design and construction. Many
stresses can be predicted and factored into well design, although a safety factor is normally
included to account for unanticipated stresses (e.g., a stuck pipe during casing placement, sudden
unanticipated pressure changes).
The external stress on the well casing and tubing from the formation, the internal stress on the
well casing and tubing from injection, and the force along the well casing and tubing should all
be determined. The well components should be designed to withstand the maximum anticipated
stress in each direction [40 CFR 146.86(c)(3)(vi) and 146.86(c)(3)(vii)]. EPA understands that a
safety factor typically is included in determining the necessary strength of the well materials, and
recommends that an appropriate safety factor be agreed upon with the UIC Program Director.
The loading from the formation or compressive force is a combination of the formation pressure,
which can be measured, and any additional loading from the rock column, on portions of the well
that are not perfectly vertical. The force from the rock column can be predicted given knowledge
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of the rock column. Further information on determining formation pressure can be found in the
Draft UIC Program Class VI Well Site Characterization Guidance.
The internal loading on the well is determined by the injection pressure and/or the pressure on
the annulus between the casing and tubing [40 CFR 146.86(c)(3)(iii) and 146.86(c)(3)(iv)]. The
injection pressure is a fundamental well design parameter and therefore is known before
construction begins. Axial loading is loading along the long dimension of the well boring. If the
casing is being suspended from the surface (such as it would be during installation) the axial
loading is the weight of the casing below a given point minus any buoyant forces. In the case of
stuck pipe, the axial force will be upward and tend to compress the casing instead of pull on it.
Mechanical stresses can often be predicted knowing the site characteristics. Many well
construction contractors have proprietary software that can calculate the stresses to which a well
is subject. EPA expects these programs to be able to calculate the forces in the outward, inward,
and axial directions.
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Tensile
Compressive
Collapse
Burst
Note: Figure not to scale
Stresses Exerted on Well Casings
Figure 7. Stresses on the Well Bore.
The loading in each of the stress directions should be compared to the strength of the material in
that direction. The loadings correspond to the burst, collapse, and tensile strengths of the material
[40 CFR 146.83(c)(3)(vii)]. EPA anticipates that the manufacturer of the materials should be
able to provide acceptable loading capacity estimates. EPA recommends selecting materials that
can resist maximum stresses anticipated in all three directions with a safety factor to account for
unanticipated stresses. If stronger casing or tubing is needed, different alloys can be chosen, or
thickness can be increased to increase the strength of the well construction materials. Cement
strengths can be modified by various additives. API Specification 5Cr(see Figure 1) provides
tubing and casing specifications that can aid in choosing the appropriate materials. For cements,
API specification 10A lists typical cements used in oil and gas wells. The API cements are all
Portland based with various additives to alter cure time, strength, and sulfate resistance. Figure 8
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provides a summary of the API cement types. Most oil and gas wells use Class G or H cements
(Azar and Samuel, 2007).
API Well Cement Types
Well
Class
Class A
Class B
Class C
Class D
Class E
Class F
Class G
Class H
Depth
Surface to 6,000'
Surface to 6,000'
Surface to 6,000'
6,000' to 10,000'
10,000' to 14,000'
10,000' to 16,000'
Surface to 8,000'
(as manufactured)
Surface to 8,000'
(as manufactured)
Sulfate
resistance
options a
O
M, H
O, M, H
M, H
M, H
M, H
M, H
M, H
Notes
Used when special properties are not
required
Used when conditions require moderate to
high sulfate resistance
Used when high early strength is needed
Used under moderately high pressure and
temperature conditions
Used under high pressure and temperature
conditions
Used under extremely high pressure and
temperature
Basic well cement. Can add accelerators or
retarders to cover a wide range of well
depths and temperatures
Basic well cement. Can add accelerators or
retarders to cover a wide range of well
depths and temperatures
a: O = ordinary, M = moderate, H = high. Source: American Petroleum Institute (2002).
Figure 8. API Well Cement Types
2.4.2 Corrosion Considerations
In addition to being designed to withstand stresses, well materials must also be compatible with
any fluids with which they may be expected to come into contact [40 CFR 146.86(b)(l) and
146.86(c)(l)]. When carbon dioxide combines with water, carbonic acid is formed and this
carbonic acid is corrosive to steel and other metals. It can react with cement and alter the C-S-H
and calcium hydroxide material found in typical Portland cements. The formation fluids can also
interact with the carbon dioxide stream and the cement. Impurities such as sulfide, sulfate, and
nitrogen oxides, either in the carbon dioxide stream or the formation fluid, can also accelerate
corrosion. Increased temperatures may also cause corrosion reactions to progress faster than at
lower temperatures. Chemical alteration of cement by carbon dioxide will be discussed further in
Section 2.5.3. The remainder of this Section will focus on the compatibility of the metallic
elements with carbon dioxide.
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It is important to measure the water content of the carbon dioxide injectate as part of the required
characterization of the injectate [40 CFR 146.82(a)(7)(iv)]. If the water content of the injectate or
stream is higher than 50 ppm, then corrosion-resistant materials are suggested on all components
of the injection well that would come into contact with the carbon dioxide stream (Meyer, 2007).
For example, standard injection well construction materials (such as carbon steel) have been used
successfully in well construction where carbon dioxide streams include water in an amount equal
to or less than 50 ppm. However, if the carbon dioxide stream includes an amount of water at
greater than 50 ppm, carbon steel will likely undergo corrosion and EPA recommends that in this
case the Class VI injection well operator discuss with the UIC Program Director the use of more
corrosion resistant well construction materials in order to meet the requirements at 40 CFR
146.86(b)(l) and 40 CFR 146.86(c)(l). These sections of the Class VI Rule require compliance
with applicable standards such as ASTM or API standards.
Corrosion testing of the proposed well materials and manufacturer's corrosion ratings may also
be beneficial and should be considered in the selection of well materials. If other circumstances
may cause mixing of carbon dioxide with water in contact with well components, then corrosion
resistant materials may need to be considered. For example, if water were to be injected into the
well before or after carbon dioxide injection, increased corrosion of exposed metal parts could be
encountered.
The UIC Program Director should consider these site-specific conditions in evaluating the
proposed well construction. Although the carbon dioxide may push formation water away from
the injection well, components of the well that are in contact with the formation must also be
compatible with formation fluid. Considering effective placement of the cement sheath or
selecting corrosion-resistant casing materials designed for the entire project life, pursuant to 40
CFR 146.86(b), should ensure the well maintains integrity.
Typical corrosion resistant materials include 316 stainless steel, fiberglass, or lined carbon steel
for casing and tubing. Casing and tubing can be lined with glass reinforced epoxy, plastic, or
cement. If lined casing or tubing is used, care is recommended during installation to avoid
damaging the lining (Meyer, 2007). Other metal parts such as packers and valves can be nickel
plated or made of other high nickel alloys.
EPA recommends that care be taken to comprehensively discuss Class VI injection well design
and construction material specifications with the UIC Program Director; such discussions should
consider the anticipated operational conditions of the project. The material specifications are
recommended to account for not only contact with wet or dry carbon dioxide but also formation
fluids, impurities within the carbon dioxide stream, and physical contact between construction
materials such as tubing and packer to prevent galvanic corrosion. Galvanic corrosion can be
prevented by isolating dissimilar materials using non-conducting elements between the two
metals.
Cathodic protection can also be used to protect well elements from corrosion, although the
sacrificial anode will require periodic replacement, which could be a disadvantage for providing
long term corrosion protection.
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2.4.3 Stress and Compatibility Information to Submit to the UIC Program
Director with a Class VI Injection Well Permit Application
The following items must be submitted to the UIC Program Director with a Class VI injection
well permit application [40 CFR 146.86(b)(l)(i)-(ix)]:
• Depth to the injection zone;
• Injection pressure, external pressure, internal pressure, and axial loading;
• Size and grade of all casing strings (wall thickness, external diameter, nominal
weight, length, joint specification, and construction material);
• Corrosiveness of the carbon dioxide stream and formation fluids;
• Down-hole temperatures;
• Lithology of injection and confining zones;
• Type or grade of cement and cement additives;
• Quantity, chemical composition, and temperature of the carbon dioxide stream; and
• Construction plans for the well.
Corrosiveness of the carbon dioxide stream and formation fluids can be determined by
measuring the composition of the fluids along with physical properties such as pH,
oxidation/reduction potential, and temperature. Alternatively, the results of corrosion testing of
well materials with the carbon dioxide stream and/or formation fluids can provide information on
Corrosiveness. If any of the above information changes because of additional information gained
during drilling of the well after the permit application was approved, the revised information
must be submitted to the UIC Program Director before carbon dioxide injection operations can
begin [40 CFR 146.82(c)(5)]. The UIC Program Director should review the information to
determine the adequacy of the construction plans. The materials proposed to be used will be
compared to the information about the Corrosiveness of the injectate and its chemical
composition. EPA expects that the information on the injection depth, temperatures, injection
and formation pressures, and loadings will be compared by the UIC Program Director to the
materials proposed and the appropriate construction standards to ensure that the materials
proposed to be used in constructing the Class VI injection well can last the life of the project.
The UIC Program Director may request additional information from the owner or operator
submitting the permit application if it is unclear that the proposed construction materials can
withstand the anticipated down-hole environment, based on the collected site characterization
data [40 CFR 146.82(a)(21)]. Such additional information requested may include any results of
corrosion tests with the proposed construction materials and carbon dioxide stream to be used,
stress modeling results, or results of strength tests on the materials to be used. For more details
on corrosion testing, see the Draft UIC Program Class VI Well Testing and Monitoring
Guidance.
EPA encourages dialogue between the UIC Program Director and the proposed injection well
owner or operator on the construction materials selected and proposed, as well as on any
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appropriate additional safety factors to use. EPA anticipates that the final decision of the UIC
Program Director on the appropriate well construction materials be made after a consultative
process.
2.5 Cementing the Casing of Class VI Wells
The Class VI Rule requires that surface casing extend through the base of the lowermost USDW
and be cemented to the surface through the use of single or multiple strings of casing and stages
of cement [40 CFR 146.86(b)(2)]. A long-string casing must extend at least to the injection zone
and be cemented to the surface [40 CFR 146.86(b)(3)]. EPA recommends that the exact depth of
the long-string casing be determined in consultation with the UIC Program Director in order to
optimize both protection to USDWs and the GS capability of the well. When cement cannot be
recirculated to the surface, as demonstrated through the use of logs, it may be acceptable to use
staged cementing to achieve cementing to the surface [40 CFR 146.86(b)(4)].
As previously discussed, the surface casing provides stability to the well bore by preventing
unconsolidated soils and aggregates from falling into the borehole. It also typically decreases the
amount of drilling mud used in the deeper portions of the well. By extending through the base of
the lowermost USDW, the surface casing also seals off USDWs and other permeable zones from
deeper intervals of the well bore. Thus, it provides an additional barrier to fluid or injectate
migration into a USDW if the tubing and long-string casing should fail. Cementing of the long-
string casing serves to seal off the well bore and may prevent fluid or injectate leaks through the
casing from entering a permeable zone, such as a USDW. If the cement was absent or improperly
emplaced, and there was a tubing and casing failure, carbon dioxide could enter a permeable
zone and then potentially migrate into USDWs through an annulus, faults, or abandoned wells,
which would be a permit violation, and would require cessation of injection [40 CFR 146.88(f)].
Cementing the casing also protects it from exposure to carbonated brine and other corrosive
fluids.
Well cementing is a common construction practice performed in the oil and gas drilling industry.
Creation of a tight interface between the cement, casing, and the formation is the key to
hydraulic isolation. Figure 2 lists some references that describe the cementing process in detail.
Additional references are included in Section 6 of this document.
The Class VI Rule requires use of centralizers in the long-string casing [40 CFR 146.86(b)(3)],
and in all other cementing processes, centralizers are recommended. Centralizers hold the casing
in the center of the well bore during the cementing process. If centralizers are not used, the
cement may end up being thinner (or even non-existent) on one side of the well bore, and the
thinner portion will possibly be more susceptible to failure. Centralizer placement is especially
important for the section of the injection well passing through the confining zone and into the
injection interval. Schumacher et al. (1996) found that using centralizers at every joint for 200
feet above and below the production interval of oil wells produced the best results.
The Class VI Rule allows for cementing to be performed in one or more stages [40 CFR
146.86(b)(4)]. However, EPA prefers single stage cementing because it forms a single cement
column with no seams and does not require locating the cement top. In single stage cementing,
the cement is injected down the well bore through a cement shoe and into the annulus (e.g.,
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between the casing and well bore). The cement is circulated until it reaches the surface and is
then allowed to set.
Another consideration for owners or operators is that the drilling mud used impacts the quality of
the cement job. During well drilling, fluid or mud is circulated through the well bore to lubricate
the drill bit and remove rock cuttings generated during drilling. The pressure created by a
circulated column of drilling mud also serves to prevent fluids from intruding into the well bore
from the formation. If the hydrostatic pressure of the drilling mud is less than the hydrostatic
pressure of a formation (i.e., an "under balanced" condition), fluid from the formation may enter
the well bore and, in some circumstances, may cause drilling problems and/or create conditions
that make well cementing more difficult. In contrast, drilling mud circulating at too high a
pressure (an "over balanced" condition) may result in drilling mud flowing from the well into the
formation, sometimes clogging formation pores or even fracturing the formation. Fracturing of
the confining zone(s) is prohibited by the Class VI Rule [40 CFR 146.88(a)].
Significantly under or over balanced drilling contributes to well conditions that might result in a
poor or failed cement job that may result in channels or micro-annuli (very small channels) in the
cement that may serve as conduits for fluid migration. Such channels may lead to fluid migration
and violation of the Class VI requirements [40 CFR 146.86(a)(l)]. In addition to adjusting the
mud density, the fluid pressure may be controlled by altering pumping rates and using closed
loop drilling systems.
Proper displacement of the drilling mud from the formation is also important. Mud that is not
properly displaced can cause poor bonding of the cement to the formation and lead to channels
along the well bore. Drilling mud can be cleaned out using displacement fluids. Special chemical
treatments such as acid washes can also remove drilling mud. Another possibility is using metal
"scratchers" attached to the casing which is rotated to mechanically clean the formation (Shryock
and Smith, 1981).
Additionally, horizontal wells can provide other challenges for cementing. For example, the use
of centralizers is especially important in cementing of deviated or horizontal wells. In a
horizontal well, gravity will tend to cause the casing to sit at the bottom of the well bore, which
can lead to little or no cement along the bottom of the casing, the drilling fluids penetrating
deeper into the formation on the bottom of the well bore, greater formation damage, and settling
of the cement. Cement settling can lead to a separation of the cement solids and the water which
can cause channeling. EPA recommends that centralizer placement in horizontal wells be closer
than the placement in vertical wells.
Horizontal wells also take longer to drill, and the chance of formation damage and cement
settling tends to increase over time. Underbalanced drilling with horizontal wells is often used to
decrease the extent of formation damage by drilling fluids. Using cement that has no free water,
as determined by an API free water test, can help prevent settling and channeling of the cement
used in horizontal wells (Joshi, 1991). Keeping the drilling fluid turbulent, using special drilling
fluids, and maintaining consistent velocities of the fluid around the pipe have also been found to
limit solids channeling and result in better horizontal well cementing jobs (Powell et al., 1995;
Lockyeretal., 1990; Sabins, 1990).
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2.5.1 Different Stage Options for Cementing
In some cases, cementing along the well casing from the injection zone up to the ground surface
in a single stage, as discussed in Section 2.5, may not be possible. The pressure exerted by the
cement column increases as the height of the column increases. In very deep wells the pressure
may become so great that the cement pumps can no longer maintain the pressure, or the pressure
from the cement column under construction may fracture weaker formations. In some cases,
highly fractured formations or formations with large voids may not allow cement to circulate to
the surface, as the cement will flow into the fractures and voids in the formation instead of
stacking vertically in a column up to the ground surface. If single stage cementing cannot be
successfully performed, multi-staged cementing may be used [40 CFR 146.86(b)(4)]. Multi-
staged cementing can be two-stage, three-stage, or continuous two-stage cementing.
Two- Stage Cementing
Two-stage cementing is performed similarly to single stage cementing, except that a cement
collar with cement ports is installed at an appropriate point in the well. The cement collar allows
cement to be injected into the annulus between the casing and formation at some point in the
column under construction other than the bottom of the well. Figure 9 of this guidance document
shows a schematic of a two-stage cementing process. EPA recommends that an appropriate point
for the cement collar may be the halfway point of the well or just above a fractured zone where
the cement circulation might be lost.
To successfully accomplish two-stage cementing, the cement is pushed out of the well bore using
a fluid. Two plugs, often referred to as bombs because of their shape, are then dropped. The first
plug closes the section of the well below the collar and stops cement from flowing into the lower
portion of the well. The second plug (or opening bomb) opens the cement ports in the collar
allowing cement to flow into the annulus between the casing and formation through the cement
collar. Cement is then circulated down the well bore, out the cement ports, into the annulus
between the casing and formation, and up to the ground surface. Once cementing is complete, a
third plug is dropped to close the cement ports (Lyons and Plisga, 2005). If the time between the
first and second stage is long enough for the cement to begin to set, care should be taken that the
first stage is stopped significantly below the cement ports.
Continuous Two-Stage and Three-Stage Cementing
In continuous two-stage cementing, there is no break between the injection of cement between
the first and second stages. Continuous two-stage cementing requires less time than regular two-
stage cementing, but it requires a more precise knowledge of the cement level to avoid plugging
the cement ports. Three-stage cementing is very similar to two-stage cementing, except that two
cement collars are used instead of one. The method used will largely be determined by the
characteristics of the well bore. If there are two weak formations where circulation is lost or the
well is very deep, three-stage cementing may be advantageous.
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Second-stage slurry
Second-stage flow path
Circulating ports
Cement collar
Opening bomb
First-stage slurry
First-stage flow path
Note: Figure not to scale
Two-Stage Cementing Process
Figure 9. Schematic of Two-Stage Cementing
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Reverse Circulation Cementing
Another option for cementing is called reverse circulation cementing. In this form of cementing,
cement is circulated directly down the annulus between the casing and formation. This technique
reduces the bottom hole pressure exerted by the cement column because, instead of the cement
traveling all the way down the tubing and then up the exterior of the casing, the cement column
only extends from the surface to the bottom of the hole. It often requires use of a lighter weight
cement and is more difficult to accomplish than standard cementing. There may be some
difficulty in reverse cementing associated with ensuring that the cement has reached the bottom
of the casing. The location of the cement can be found using a number of logging tools. For more
information on logs, see the Draft UIC Program Class VI Well Testing and Monitoring
Guidance.
A related procedure that is occasionally used is a "cement top-off." This technique is used if
cement circulation falls short of the surface by a small amount. In this situation, additional
cement is sometimes pumped directly into the annulus using a small diameter pipe called a
tremie pipe. Ideally, such circumstances can be avoided through proper knowledge of the
formations being cemented and the use of proper cementing procedures. If cement falls short of
the surface by a small amount, topping off using a tremie pipe may be acceptable. Care should be
taken to ensure that cement is distributed all the way around the casing and that a good cement
bond is formed. If the cement is topped off using a tremie pipe, this should be indicated on as-
built drawings submitted prior to well operation [40 CFR 146.82(c)(5)]. As with other cementing
procedures, it is recommended they be discussed with the UIC Program Director so that adequate
logging to ensure proper cement integrity can be planned.
In some cases, fractured and highly porous formations may make circulation to the surface
impossible. In these cases, the Class VI Rule allows alternative methods of cementing if
approved by the UIC Program Director, provided that the owner or operator can demonstrate by
using cement logs that evaluate the cement in a radial direction that the cement does not allow
fluid movement behind the well bore (e.g., it will still prevent fluid movement up the annulus
between the casing and formation) [40 CFR 146.86(b)(4)]. A determination on alternative
methods of cementing would be made by the UIC Program Director, and certain
recommendations may be that the cement should be continuous through the entire confining
layer, at a minimum, and that permeable zones should also be isolated from each other to prevent
cross migration of fluids between zones.
2.5.2 Cementing Information to Submit to the UIC Program Director with the
Class VI Injection Well Permit Application
With the submittal of a Class VI permit application, the owner or operator must describe the
cementing process and the type of cement to be used [40 CFR 146.86(b)(l)(viii)]. If staged
cementing is used, EPA recommends indicating the location and timing of each stage. If
continuous cementing cannot be achieved, the owner or operator must indicate the logs used to
show cementing will prevent fluid flow along the well bore, as discussed above [40 CFR
146.86(b)(4)]. If actual conditions deviate from the proposed plans during construction, the
processes used must be submitted prior to operation [40 CFR 146.82(c)(5)]. A cement evaluation
log that radially investigates the cement for each casing string must be submitted to the UIC
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Program Director upon installation of the casing [40 CFR 146.87(a)(2),(3)]. For more
information on the testing, sampling, and logging requirements of the Class VI rule, see the Draft
UIC Program Class VI Well Testing and Monitoring Guidance.
The UIC Program Director should review the proposed cementing method to determine if
cement can be circulated to the surface. If site characterization data reveals weak formations or
formations with significant fractures, the UIC Program Director should check to ensure that these
formations have been taken into account. Staged cementing plans will be reviewed to determine
if the locations are appropriate and properly take into account weak formations and cement
column height. Upon completion, the UIC Program Director should review cement evaluation
logs to ensure that cementing was completed to the surface and that channels, cracking, or annuli
that could allow fluid movement are not present. If cementing was not continuous, the UIC
Program Director should check the cement evaluation logs to ensure that no fluid pathways exist
from the injection zone into shallower formations and that no pathways exist for cross-migration
of fluids between permeable zones that may endanger USDWs.
2.5.3 Cement Compatibility
As with other well components, the cement and any additives to the cement must be compatible
with the carbon dioxide stream and formation fluids [40 CFR 146.86(b)(5)]. Reactions that can
occur when carbon dioxide comes into contact with Portland cement are shown in Figure 10. To
create the reaction, a certain amount of carbon dioxide migration has to occur along the cement
sheath. The most likely migration pathway is the cement interface with casing and formation,
which is created by inefficient cement placement. The initial reaction of carbon dioxide with
Portland cement, shown in the first cement dissolution reaction, can cause alteration to form
calcium carbonate, which is not necessarily harmful to the well, since calcium carbonate can
increase the cement strength and decrease permeability.
Further reactions between carbon dioxide and water shown in the remaining reactions, however,
can lead to the dissolution of calcium carbonate and leave behind a porous silica gel. These later
reactions can lead to a loss of strength and increase cement permeability. Sulfate, which may be
present naturally or as an impurity in the carbon dioxide, can also react with cement. In addition,
higher temperatures experienced in down-hole environments can increase the rates of alteration
of Portland cement (Barlet-Gouedard et al., 2006; Kutchko et al., 2008; Duguid and Scherer,
2009). If the alteration of the chemical composition of the cement progresses far enough, then
failure of the cement may occur. Failure of the cement may lead to migration of carbon dioxide
out of the injection zone and violation of the Class VI Rule [40 CFR 146.86(a)(l) and 146.88(f)].
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Reactions of Carbon Dioxide with Cement
CO2 dissociation
CO2 + H2O <-> H2CO3
H2CO3 <-> H+ + HCO3"
HCO3~<->H+ + CO32~
Cement dissolution
Ca(OH)2(s) + 2H+ + CO32~-> CaCO3 (s) + 2H2O
Ca3Si2O7H»4H2O(s) + 2H+ + CO32~-> CaCO3(s) + SiOxOHx(s)
Ca(OH)2 (s) + H+ + HCO3" -> CaCO3(s) + 2H2O
Ca3Si2O7H»4H2O(s) + H+ + HCO3" -> CaCO3 (s) + SiOxOHx(s)
Calcium carbonate dissolution
CO2 + H2O + CaCO3(s) <-> Ca2+ + 2HC
2H+ + CaCO3(s) <-> CO2 + Ca2+ + H2O
Source: Duguid (2008).
Figure 10. Reactions of Carbon Dioxide with Cement
Designing cement to withstand alteration by carbon dioxide and other elements including higher
temperatures and pressures is common in the oil and gas industry. EPA recommends that
potential Class VI injection well owners or operators recognize that the injection volumes
anticipated for GS are much higher than with oil- and gas-related injection practices, and
therefore corrosion resistance is even more important. Again, cement and cement additives must
be compatible with the carbon dioxide stream and formation fluids as required by 40 CFR
146.86(b)(5). Figure 2 of this guidance document includes references that address corrosion
resistant cements in more detail.
Portland cement is the most common cement used in oil and gas wells. Portland cement is
thermodynamically unstable with regard to alteration by carbon dioxide, so some alteration of
the cement is inevitable. Numerous studies have been conducted since 2005 to examine the
alteration of cement by carbon dioxide and additional studies are under way. Some of these
studies are listed in Figure 2 and in the References (Section 6). While research continues, some
consensus has begun to emerge and will likely solidify as more studies are conducted. Studies
have found the rate and extent of alteration varies and depends upon numerous factors.
Temperature is an important factor; high temperatures accelerate the rate of alteration (Barlet-
Gouedard et al., 2006), but can also produce cements that are less permeable and more resistant
to alteration (Kutchko et al., 2007). The flow rate of fluids around the cement is another
important factor, as higher flow rates can transfer fresh carbon dioxide to the cement and result
in further alteration (Duguid and Scherer, 2009). In static conditions (where there is very low or
limited flow of carbon dioxide to the cement), the buffering from the formation or cement itself
can slow down the chemical reactions resulting in alteration (Kutchko et al., 2007, Duguid,
2008).
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Gaseous or supercritical carbon dioxide may cause less alteration than carbon dioxide dissolved
in water, as the supercritical carbon dioxide can result in a surface layer of less permeable
calcium carbonate. Field studies examining carbon dioxide alteration of cement in carbon
dioxide wells have found evidence of alteration of the cement along the cement-formation
interface and reduced permeability and strength of the cement. The permeability and strength
reductions, however, were not enough to cause the cement to fail and the permeability value was
still smaller than the maximum API recommended value (Carey et al., 2007; Crow et al., 2009).
While all Portland based cements will eventually undergo carbonation by carbon dioxide, the
conditions to which the cement will be exposed can be predicted and the well can be designed to
better resist those conditions. Additives are available that may facilitate cement resistance to
carbon dioxide and other constituents such as sulfate. Some alternatives that can aid in increasing
carbon dioxide resistance include:
• Additives that lower the calcium hydroxide content of the cement. While additives such
as quartz, silica fume, and fly ash can increase the rate and depth of carbonation
penetrating into cement (Sweatman, 2010), these additives also prevent increases in
porosity, because they have greater resistance to carbonic acid than the surrounding
calcium carbonate; and
• Non-Portland cements which are not as susceptible to attack by carbon dioxide, including
phosphate based, pozzolan-lime, gypsum, microfme, expanding cements, calcium
aluminate, latex, resin or plastic cements, and sorel cements.
2.5.4 Cement Bond and Variable Density Logs
Cement bond and variable density logs are required after setting and cementing the surface
casing and long-string casing [40 CFR 146.87(a)(2)(ii) and 146.87(a)(3)(ii)]. These logs use
sonic signals to determine the condition of cement behind the casings and its bonding to the
casings. The two cement logs provide complementary information, and are typically run
simultaneously. Interpreted together, the logs indicate the presence or absence of cement behind
the casing, and the quality of the cement-formation bond. Portions of this section have been
adopted from a previous EPA guidance (USEPA, 1982b).
Application
A single logging tool consisting of a rotating sonic transmitter and two receivers is used to
conduct both tests. The receivers are set at different spacings-one is used for the cement bond
log, and the other for the variable density log. The transmitter emits a signal that is radiated in all
directions while the tool is moved vertically through the borehole. The cement bond log receiver,
set three to four feet from the transmitter, detects and measures the amplitude of the first arrival
of the reflected sonic signal. When cement is present and firmly bonded to the casing, the
attenuation of the signal is large compared to when cement is not present. By recording the
amplitude of the sonic signal, it is possible to detect locations where the cement bond may not be
adequate and a potential for fluid movement exists.
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The variable density log measures the travel time of the transmitted signal and can provide
additional information on the quality of the cement. The variable density log receiver is typically
set at five feet from the transmitter. The recorded log is a photographic display of the arrival of
the sonic signal, and appears as a series of alternating light and dark bands representing
variations in positive and negative signals.
Increasing
Signal Amplitude
Increasing
Transit Time
.
a
Q
Cement Bond Log
Variable Density Log
Source: EPA. 1982
Typical Cement Bond Log and
Variable Density Log Displays
Figure 11. Cement Bond Log and Variable Density Log Displays
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Interpretation
Examples of a cement bond log and variable density log are provided in Figure 11. For the
cement bond log, an increase in recorded amplitude of at least 20 percent corresponds to
locations of lower signal attenuation and potentially the absence of an adequate cement bond.
For the variable density log, the regularity or irregularity of bands indicates the quality of the
cement job. For this log, a continuous record of the sonic wave is recorded as the tool is moved
vertically through the borehole. The left-most (earliest arriving) bands on the variable density log
indicate the condition of the casing-cement bond and lend verification to the cement bond log.
Bands further right (later arriving) indicate the condition of the acoustical coupling of the cement
and formation. If the cement is well-coupled to both the casing and formation, the right-most
bands (last arriving) are indicative of the formation characteristics as the sound energy penetrates
deeply. Properly cemented portions of the casing are characterized by weak, almost
indistinguishable pipe signal on the left-hand side, and wavy, irregular formation signal on the
right-hand side.
Cement needs to be present behind all casings and effectively bonded to the casing to provide an
adequate seal against fluid movement. If the results of cement bond and variable density logging
indicate the absence of cement or an improper seal, action needs to be taken to properly cement
the casings prior to commencing injection.
2.6 Selecting the Tubing and Packer of Class VI Wells
The Class VI regulations require that injection occur through tubing. The tubing must be
compatible with the carbon dioxide stream [40 CFR 146.86(c)(l)]. Tubing materials are
generally similar to the casing well materials listed in Sections 2.1.2 and 2.4.2. The tubing should
also be designed with the same types of stressors in mind. The tubing must be designed with
burst strength to withstand the injection pressure and the collapse strength to withstand the
pressure in the annulus between the tubing and the casing [40 CFR 146.86(b)(l)].
The Class VI regulations also require that injection occur through a packer, set opposite a
cemented interval at a depth approved by the UIC Program Director, and compatible with the
carbon dioxide stream [40 CFR 146.86(c)(l) and (2)]. Most well construction references include
detailed information on tubing and packer. Figure 2 of this guidance document also includes a
list of references that discuss the topic in greater depth.
Packers are often made from a hardened rubber such as Buna-N or nitrile rubbers and are nickel
plated. Proper materials for packers are important as they are likely to come into contact with
corrosive fluids such as carbon dioxide or corrosive brines at some point during the project life.
The packer must be compatible with any fluids it may come into contact with [40 CFR
146.86(c)(l)]. Placement of the packer can also be an important consideration, influenced by
numerous factors. If the packer is placed above the confining layer, it will allow logs to be run
next to the casing through the confining layer without having to pull the tubing. Alternatively,
placing the packer close to the perforations may allow instruments used for carbon dioxide
plume tracking, such as geophones, to be placed closer to the expected plume. Packer placement
can also affect how mechanical integrity tests are conducted and may affect the stress placed on
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well components. The owner or operator should consider these factors, in consultation with the
UIC Program Director, in order to select the best location for the packer according to project-
and site-specific circumstances.
2.7 Additional Well Construction Information to Submit to the UIC Program Director
with a Class VI Injection Well Permit Application
The owner or operator must submit the following information concerning the tubing and packer
to the UIC Program Director at the time of the permit application [40 CFR 146.86(c)(3)(i)-(vii)]:
• Depth of setting;
• Characteristics of the carbon dioxide stream (chemical content, corrosiveness,
temperature, and density) and formation fluids;
• Maximum proposed injection pressure;
• Maximum proposed annular pressure;
• Proposed injection rate (intermittent or continuous) and volume and/or mass of the
carbon dioxide stream;
• Size of tubing and casing; and
• Tubing tensile, burst, and collapse strengths.
The UIC Program Director should compare the proposed depth of setting of the packer to all
submitted site characterization information to ensure that the packer is set within an approved
cemented interval. EPA recommends that the specific location of the packer be determined based
on a consideration of site-specific circumstances, such as how the packer will affect cement
logging, plume tracking tools, planned mechanical integrity tests, and well component stresses.
The UIC Program Director should make sure the interval across which the packer is set is
cemented by reviewing cement bond logs. Lack of cement would leave only the casing to serve
as a barrier to fluid movement up the well. After reviewing the site characterization data and the
tubing and packer depths, the UIC Program Director should either approve the proposed tubing
and packer placement or require a revised placement for the tubing and packer.
The proposed injection pressure will be compared to the burst strength of the tubing to ensure
sufficient strength. The collapse strength of the tubing will be compared to the proposed
maximum annular pressure. If the proposed annular pressure is greater than the collapse pressure
of the tubing, the UIC Program Director may either require more competent tubing or allow for a
reduction in annular pressure. If a lower annular pressure is allowed, EPA recommends that the
owner or operator still maintain a positive pressure on the annulus. There should also be an
adequate safety margin between the annular pressure and the tubing collapse pressure and/or the
casing burst pressure. The tensile strength of the tubing will be compared to the tensile stress
created by the total mass of the tubing to ensure the tubing will not break during installation. The
characteristics of the carbon dioxide stream will be compared to the corrosion resistance of the
materials proposed for use. This will help ensure that corrosion will not threaten the integrity of
the tubing or packer.
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If drilling, construction, and logging of the well reveal any changes to information used by the
UIC Program Director to determine and specify requirements for tubing and packer , the revised
information must be submitted to the UIC Program Director prior to operation of the injection
well [40 CFR 146.82(c)(2), 40 CFR 146.82(c)(5)].
2.8 Selecting Surface and Down- Hole Shut-Off Devices for Class VI Wells
2.8.1 Surface Safety Systems
The Class VI Rule requires the installation and use of alarms and automatic surface shut-off
systems for onshore injection wells and, at the discretion of the UIC Program Director, down-
hole shut off systems may also be required [40 CFR 146.88(e)(2)]. For offshore Class VI
injection wells located within state territorial waters, alarms and automatic down-hole shut-off
systems are required [40 CFR 146.88(e)(3)]. Although surface shut-off systems are not required
for offshore wells, EPA recommends they be installed in addition to the required down-hole
systems. Surface safety valves can be beneficial to protect against failures above the downhole
valve and to provide a second barrier against loss of well control.
Surface safety systems generally consist of one or more valves and a control system such as a
Supervisory Control and Data Acquisition (SCADA) system. Because lengthy hydraulic control
lines are not needed to trigger the valve, a wider variety of valves can be employed. The valves
are also installed on the wellhead instead of in the casing and can be of larger diameter and
provide less of a pressure drop. Any valve used for downhole applications may also be used as a
surface valve. In addition, other types of surface-only valves may be used. References listed in
Figures 1 and 2 of this guidance document can be consulted for more details on surface safety
valves and systems. Surface valves are typically connected to a SCADA or other similar system
that monitors variables such as pressure, temperature, and flow. The control system can be set to
trigger the valve to close the well if certain alarms are triggered such as a low or high pressure.
2.8.2 Down-Hole Devices
Subsurface or down-hole safety valves have most commonly been used in offshore applications
in the oil and gas industry. They have also been used in onshore applications where backflow out
of the well would pose a danger such as for acid-gas injection wells or wells operating under
high pressure/high temperature conditions. Figure 2 of this guidance document includes several
published references that discuss down-hole safety valves in more detail.
All down-hole safety valves are designed to be fail-safe and to shut in response to changes in
injection pressure or injection rate. The main differences among the different types of valves are in
the degree and type of control, and in accessibility. Tubing-retrievable surface-controlled safety
valves are the most common down-hole shut-off systems. This type of valve is held open by
pressure applied through a hydraulic control line from the surface. When open, the valve does
not protrude into the flow. It is set to automatically close if a monitored parameter, such as
pressure or flow rate, exceeds pre-set limits. Tubing-retrievable valves are attached to the tubing,
as their name implies; therefore, they can be removed for servicing by pulling the tubing.
Wireline-retrievable surface-controlled safety valves are also available and can be used to
replace failed tubing-retrievable valves or as temporary valves during workovers. For these
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surface-controlled valves, the pre-set injection pressure and flow rate values that trigger valve
closing can be changed from the surface without pulling the safety valve from the subsurface.
There are also a variety of other down-hole safety valves that shut when pre-set pressure or flow
limits are exceeded, but the triggering limits cannot be controlled or changed from the surface.
These are referred to as direct control valves. Most of these valves use flapper type valves that
include check valves, fixed choke velocity valves, variable orifice valves, and pressure
differential operated valves. These valves vary in durability, ease of servicing, and in their
opening mechanisms. At the point they are located in the injection tubing, surface-controlled or
direct control valves (even when fully open) can impede injection flow and cause a drop in
pressure. The references provided in Figures 1 and 2 provide more details on the advantages and
disadvantages of each specific type of valve.
2.8.3 Shut-off System Information to Submit to the UIC Program Director with a
Class VI Injection Well Permit Application
The owner or operator must submit, with the permit application, schematics and other
appropriate drawings of the surface and subsurface construction details of the well [40 CFR
146.82(a)(l 1) and 146.82(a)(12)], these schematics should include the type and location of the
safety valve(s) and any landing nipples, if used.
The UIC Program Director should review the type of shut-off system proposed and evaluate its
utility and appropriateness for the proposed well. The UIC Program Director should review the
closure mechanism to ensure that it will close the valve in the event of a failure of the control
equipment. The UIC Program Director should also review the closing parameters and compare
them to expected conditions to ensure they are adequate and will not allow fluid to migrate out of
the injection zone. Information the UIC Program Director may consider in making this
determination include formation pressure, proposed injection pressure, and the presence of any
potentially toxic substances in the injection stream or the formation (e.g., hydrogen sulfide,
methane).
If the shut-off system (e.g., at the surface, or down-hole) is triggered at any time during project
operation, the owner or operator must investigate as expeditiously as possible the cause of the
valve triggering [40 CFR 146.88(f)]. If the well has lost mechanical integrity the owner or
operator must cease injection immediately, notify the UIC Program Director within 24 hours,
determine the cause of the failure, make plans to repair the well, and take all reasonable steps to
determine if carbon dioxide has escaped the injection zone [40 CFR 146.88(f)(l)-(f)(4)]. Such
steps may include monitoring for carbon dioxide at the surface or in zones above the confining
layer using the methods described in the Draft UIC Program Class VI Well Testing and
Monitoring Guidance. Once the well repair/workover schedule is known, the UIC Program
Director should be notified of the repairs 30 days in advance [40 CFR 146.91(b)(2)]. The owner
or operator must restore mechanical integrity to the well and demonstrate this to the UIC
Program Director [40 CFR 146.88(f)(4)]. A planned date for when injection is expected to
resume should also be given to the UIC Program Director along with the well repair schedule [40
CFR 146.88(f)(5)].
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3 Considerations for Conversion of Other Well Types to Class VI
The considerations discussed to this point focused on construction of new Class VI wells.
However, the Class VI Rule allows for the repermitting of an existing well as a Class VI well,
provided the owner or operator can demonstrate to the UIC Program Director that the well under
consideration was engineered and constructed to meet the requirements of 40 CFR 146.86(a)1
and ensure protection of USDWs, in lieu of requirements at 40 CFR 146.86(b) and 146.87(a).
This section presents considerations for owners or operators and UIC Program Directors where
repermitting of an existing well as a Class VI well is under consideration. It includes information
owners or operators should submit to the UIC Program Director to demonstrate that a converted
well will be suitable for GS and ensure USDW protection. Wells that are converted to Class VI
do not need to meet all of the logging and pre-/post-construction requirements that apply to
newly constructed Class VI wells, specifically requirements that focus on pre-construction
logging and cementing at 40 CFR 146.86(b) and 146.87(a). However, it may be appropriate to
conduct some of the tests specified in these requirements (e.g., cement bond logs) prior to or
during permitting to demonstrate well suitability.
This section provides information about the manner in which an owner or operator may
demonstrate that an existing well is appropriate for Class VI injection for GS and clarifies the
information that a UIC Program Director will review prior to approving a well for repermitting
as a Class VI well, while addressing the intent of the requirements at 40 CFR 146.86(b) and
146.87(a).
EPA recommends that this section of the guidance be read in concert with Sections 1 and 2 of
this document, because much of the well construction information in Sections 1 and 2, as well as
the requirements at 40 CFR 146.82 through 146.85 and 40 CFR 146.89 through 146.95, remain
applicable to owners or operators applying to repermit a well for Class VI injection. Wells that
might be converted to Class VI wells include Class I wells, Class II wells, and Class V
experimental technology wells, monitoring wells, and stratigraphic test wells. For additional
information on transitioning Class II wells to Class VI, including determining the point at which
repermitting as a Class VI well is necessary, see the Draft Underground Injection Control
Program Guidance on Transitioning Class II Wells to Class VI.
If the UIC Program Director evaluates well construction information submitted for repermitting
of an existing well and determines that USDW protection cannot be ensured for the duration of a
Class VI project, a Class VI permit may be denied and an owner or operator may need to
construct a new Class VI well or identify a different well for repermitting as a Class VI well.
1 40 CFR 146.86(a) General. The owner or operator must ensure that all Class VI wells are constructed and
completed to (1) Prevent the movement of fluids into or between USDWs or into any unauthorized zones; (2) Permit
the use of appropriate testing devices and workover tools; and (3) Permit continuous monitoring of the annulus
space between the injection tubing and long string casing.
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Additionally, EPA recommends that owners or operators who construct a stratigraphic test well
in advance of a planned GS project, with the intention of repermitting the stratigraphic well as a
Class VI well consult with the UIC Program Director prior to commencing construction of the
stratigraphic well. This consultation will inform appropriate construction that meets the Class VI
requirements and should facilitate repermitting of the well to Class VI at the appropriate time.
3.1 Permit Application Submittals
Owners or operators seeking to repermit existing wells as Class VI wells must submit a complete
Class VI permit application that meets the requirements of 40 CFR 146.82(a). Some aspects of
the Class VI permit application will need to be modified to accommodate the fact that the well
was previously constructed. Specifically, the original well schematics required at 40 CFR
146.82(a)(l 1), and well construction procedures required at 40 CFR 146.82(a)(12), should be
submitted with the permit application, along with additional information, as-built specifications,
or explanations that demonstrate to the UIC Program Director that the well was constructed to
allow safe carbon dioxide injection over the life of the project. These materials, submitted with
the permit application, should also demonstrate that the well currently has, and is able to
maintain, internal and external mechanical integrity over the life of the project. The table below
provides an overview of the requirements of the Class VI Rule that necessitate different
considerations for owners or operators repermitting existing wells for Class VI GS.
The UIC Program Director will evaluate the submitted information, in concert with the rest of
the permit application and, in consultation with the owner or operator, determine what remedies
may be needed to address concerns and ensure safe injection.
Class VI Requirements:
Special Considerations for Repermitting Existing Wells as Class VI Wells
Rule Section
40 CFR 146. 81
40 CFR 146.82
40 CFR 146.83 to
40 CFR 146.85
40 CFR 146.86
40 CFR 146. 87
40 CFR 146.88 to
40 CFR 146.95
Considerations
• Same as for new wells
• Provide as-built schematics and construction procedures to
demonstrate that repermitting is appropriate
• Submit recent or newly conducted well-log information and mechanical
integrity test results
• Demonstrate that any needed remedial actions have been performed
o Logging and testing program data (146.82(c)(7)) should reflect any
pre-injection testing needed to demonstrate proper construction
• Same as for new wells
• Demonstrate that the well was engineered and constructed to meet the
requirements of 40 CFR 146.86(a) and ensure protection of USDWs
• Demonstrate that cement placement and materials are appropriate for
carbon dioxide injection for GS
• Demonstrate that the well was engineered and constructed to meet the
requirements of 40 CFR 146.86(a) and ensure protection of USDWs
o If necessary, perform additional tests of the well to support a
demonstration of suitability for GS
• Same as for new wells
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Similarly, information submitted prior to authorizing injection, per 40 CFR 146.82(c), will need
to be modified to demonstrate that injection can be safely conducted. This should include the
results of any remediation performed to address the considerations described in the sections
below.
3.2 Considerations for Repermitted Wells
An owner or operator should consider well material strength, material compatibility with carbon
dioxide and formation fluids, injection well design, and mechanical integrity when
contemplating repermitting a well for Class VI injection. The sections below present: 1)
considerations for owners or operators to facilitate a demonstration that an existing well is
appropriate for Class VI injection for GS (including potential remedies to address deficiencies)
and 2) information that should be submitted to the UIC Program Director to support a
determination that repermitting is appropriate.
3.2.1 Material Strength
Injection and formation pressures at GS projects are anticipated to be greater than those
encountered in Class I or Class II wells, and will also likely be higher than pressures in
monitoring or stratigraphic test wells. Where an owner or operator is seeking to repermit an
existing well as a Class VI well, the owner or operator must evaluate and consider these
pressures prior to submitting an application for repermitting. The owner or operator should
review both the design specifications of the well and its current condition in order to evaluate the
well's integrity to withstand pressures anticipated at the Class VI operation. Considering material
strength addresses the purpose of the requirements at 40 CFR 146.86(b)(l), which require that
the casing and cementing program be designed to prevent the movement of fluids into or
between USDWs through the use of materials of sufficient structural strength. More information
on design specifications for strength is found in Section 2.4 of this guidance.
Considerations for the Owner or Operator
An owner or operator converting a well must consider whether the original design of the well is
appropriate for GS. Ideally, construction records and schematics detailing the casing type and
cement placement in the well will be available. If original design information or schematics are
not available, pressure testing records may reveal some information on the strength of the casing.
The burst and collapse pressures of the existing casing and tubing should be compared to the
proposed injection pressures. If the burst pressure of the casing is lower than or close to the
injection pressure, the casing may need to be drilled out and replaced or the well may not be
suitable for conversion.
While the design strength of the well casing is important, casing can degrade over time due to
corrosion and other stresses. Therefore, assessing the current casing condition is important. To
assess the current condition of the casing, an owner or operator should conduct an internal
mechanical integrity test that meets the requirements for testing new wells at 40 CFR
146.87(a)(4) or submit results of a recent internal mechanical integrity test. Casing evaluation
tools such as caliper logs and casing inspection logs may also provide useful information. If tests
reveal casing degradation, the owner or operator, in consultation with the UIC Program Director,
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should consider the long-term viability of the well and may consider either drilling out and
replacing the casing, using a liner, or finding an alternative well. Where internal mechanical
integrity cannot be demonstrated, a well should not be further considered for repermitting as a
Class VI well.
Information to Submit to the UIC Program Director
The UIC Program Director will evaluate whether the injection well casing is of sufficient
strength to withstand the planned injection pressures at a Class VI well. An owner or operator
should submit all available design information on the original well construction to support this
review and may wish to refer to 40 CFR 146.86(b) for information on the data the Director will
evaluate when assessing material strength. In addition, a recent pressure test at a pressure at least
equal to the proposed injection pressure can demonstrate the adequacy of the well design. The
UIC Program Director may also request other evaluation tests, such as caliper logs, casing
inspection videos, or tracer logs. For additional information on well material strength and
compliance with requirements at 40 CFR 146.86(a) and (c), see Sections 2.4 and 2.6 of this
document.
3.2.2 Material Compatibility
Another unique aspect of the Class VI Rule is an assessment of well material compatibility with
the carbon dioxide stream and formation fluids, discussed in Section 2.4.2. Compatibility is
necessary to ensure that well materials will retain integrity throughout the life of the Class VI
project.
Considerations for the Owner or Operator
To support an evaluation of the compatibility of well materials, the owner or operator must first
characterize the carbon dioxide stream [40 CFR 146.82(a)(7)(iv)]. Carbon dioxide concentration
and water content are two key parameters to evaluate. Impurities including sulfate, sulfide, and
nitrates, should also be examined. Additionally, an analysis of formation fluids in the injection
zone for these parameters and pH, as required at 40 CFR 146.82(a)(8) and 146.87(c), will inform
a determination of material compatibility.
The casing, tubing, and cement materials should be evaluated based on knowledge of the
anticipated composition of the carbon dioxide stream, formation fluids, the water content of the
carbon dioxide stream, and the potential for reactions between the well materials and the
injectate and formation fluids. Corrosive combinations such as wet carbon dioxide, hydrogen
sulfide, or low pH formation fluids may necessitate a well with more corrosion-resistant well
materials such as stainless steel or other advanced well materials and corrosion resistant cements.
High concentrations of sulfate may also require special cements. Wells that were constructed of
corrosion-resistant materials (e.g., 316 stainless steel) or materials that meet ASTM/API
standards are likely to be good candidates for conversion to Class VI.
If the compatibility of the materials with the carbon dioxide stream remains in question,
corrosion tests using the carbon dioxide stream and well materials may help determine
compatibility. For information about these tests, see the Draft UIC Program Class VI Well
Testing and Monitoring Guidance (Section 3.4). If the casing materials are not compatible with
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the carbon dioxide stream, the casing may need to be replaced or a liner inserted. If the cement is
not compatible, the well may not be suitable for repermitting.
Information to Submit to the UIC Program Director
The owner or operator should provide the UIC Program Director with any original construction
specifications or schematics for the well, including casing material and thickness and the type(s)
of cement. Analysis of both the injection stream, pursuant to requirements at 40 CFR 146.87(c),
and any formation fluids, submitted pursuant to 40 CFR 146.82(a)(7)(iv), will also be necessary
to support an assessment of the adequacy of the well materials for carbon dioxide injection for
GS. If there are questions regarding the adequacy of materials, corrosion testing results and an
indication of any well construction materials that meet or exceed relevant ASTM/API standards
may inform a UIC Program Director's decisions on repermitting.
EPA recommends that the owner or operator and UIC Program Director discuss the well design
and construction materials used, particularly in the context of the anticipated operational
conditions of the project after repermitting. The material specifications should account for not
only contact with wet or dry carbon dioxide but also formation fluids, impurities within the
carbon dioxide stream, and physical contact between construction materials such as the tubing
and packer to prevent galvanic corrosion. For additional information on well material
compatibility see Sections 2.4 through 2.6 of this document.
3.2.3 Well Design
An additional consideration for repermitting existing wells as Class VI wells is well design and
cement placement. While Class VI wells must be cemented to the surface, there is some
flexibility afforded owners or operators of wells applying to repermit existing wells as Class VI
wells. Specifically, wells converting to Class VI may not need to meet the requirement that their
long-string casing be cemented to the surface if the owner or operator can demonstrate, to the
UIC Program Director's approval, that there is proper zonal isolation. However, in all cases,
repermitting is contingent upon a demonstration that the well meets the requirements at 40 CFR
146.86(a) to prevent the movement of fluids into or between USDWs or into any unauthorized
zones.
Considerations for the Owner or Operator
To demonstrate zonal isolation, an owner or operator must demonstrate, at a minimum, that the
surface casing has intact cement from the bottom of the lowermost USDW to the surface.
Additionally, the long-string casing must be cemented from the production zone into the
confining layer. The well should also be cemented across any permeable layers such as oil or gas
bearing zones and high TDS aquifers.
Temperature or cement logs performed at the time of original well construction may be helpful
in identifying the areas of the well that are cemented. Original well logs or cores may also be
necessary to identify permeable zones. If these records are not available, a new set of logs may
be necessary and requested by the UIC Program Director. A new cement log evaluating the
cement in the radial direction will not only show the location of the cement but also evaluate its
integrity. See Section 2.2 for information on performing these logs.
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If cement is not present or is inadequate in permeable areas, drilling out the well and re-
cementing may be necessary; alternatively, an owner or operator may determine that the well is
not suitable for conversion.
Information to Submit to the UIC Program Director
The owner or operator should provide the UIC Program Director with stratigraphic records and
well logs that identify where the cement is within the well and its placement relative to any
permeable zones. The owner or operator should also demonstrate that all permeable zones have
been cemented, and that the surface casing extends below the lowermost USDW and is cemented
to the surface. For additional information on well design and cementing requirements for new
wells, which may inform data submittals, see Section 2.5 of this guidance and the requirements
at40CFR146.86(b).
3.2.4 Mechanical Integrity
Ensuring that a well can pass periodic mechanical integrity testing, allow continuous monitoring,
and maintain mechanical integrity throughout its life are key requirements for any well
conversion. An owner or operator will need to demonstrate to the UIC Program Director that a
well under consideration for repermitting as a Class VI well was designed to maintain both
internal and external mechanical integrity, has mechanical integrity at the time of repermitting,
and is likely to maintain integrity under the proposed operating conditions throughout the
planned life of the GS project. If a well is repermitted as a Class VI well, an owner or operator
must continuously monitor the well for internal mechanical integrity [40 CFR 146.89(b)] and
conduct external mechanical integrity tests at least once every year [40 CFR 146.89(c)].
Considerations for the Owner or Operator
Maintaining internal mechanical integrity of the well to be converted will ensure delivery of
the carbon dioxide to the injection zone and prevent it from leaking into surrounding formations.
A pressure test at or above the proposed injection pressure is the most straightforward way to
determine if the well has maintained internal mechanical integrity. An owner or operator may
also run a casing inspection log and tracer surveys to complement the pressure test and
demonstrate internal mechanical integrity. External mechanical integrity ensures that carbon
dioxide in the injection zone will not migrate, through channels in the cement, up the well bore
to other permeable formations and that fluids cannot move between formations. A cement bond
log evaluating the cement radially may help identify any potential channels in the existing
cement, while tracer logs, temperature logs, and noise logs should be used to supplement
information collected through the cement bond log. See Section 4.3 of this guidance, and the
Draft UIC Program Class VI Well Testing and Monitoring Guidance for additional information
on demonstration of mechanical integrity for Class VI wells.
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Information to Submit to the UIC Program Director
An owner or operator should submit any mechanical integrity tests performed on the well to
inform repermitting decisions. While past tests will be useful, recent tests are necessary to ensure
that the well currently has mechanical integrity, is capable of accepting carbon dioxide at
planned injection rates and volumes, and will maintain mechanical integrity over the planned
duration of the proposed Class VI project. If integrity tests reveal leaks in the tubular materials,
flaws in the cement, or issues that cannot be easily resolved, the UIC Program Director, in
consultation with the owner or operator, may determine that a well is not suitable for carbon
dioxide injection for repermitting.
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4 Operating Requirements for Class VI Injection Wells
The daily operations of a Class VI injection well are important to maintaining the integrity of the
well and ensuring the safe sequestration of carbon dioxide. Class VI operating requirements [40
CFR 146.88] include requirements for operating pressures, mechanical integrity, and automatic
shut-off systems (discussed in Section 2.8).
4.1 Injection Pressure Requirements of Class VI Wells
The Class VI Rule requires that the injection pressure not exceed 90 percent of the injection zone
fracture pressure except during stimulation [40 CFR 146.88(a)]. All stimulation programs must
be approved by the UIC Program Director as part of the permit application [40 CFR
146.82(a)(9)].The Class VI Rule prohibits injection between the outermost casing and the well
bore [40 CFR 146.88(b)].
Maintaining the injection pressure below 90 percent of the injection zone fracture pressure is a
conservative requirement that prevents the injection zone from being fractured and diminishes
the likelihood of fracturing the confining zone which could result in fluid movement out of the
injection zone. In some cases, a well stimulation program may be necessary to achieve the
desired injectivity of the Class VI injection well. Stimulation usually occurs during completion
of the well and may also be conducted if injectivity decreases over the course of the injection
project.
Some stimulation methods can induce and propagate fractures. If stimulation is to be performed,
a plan for the stimulation procedure must be submitted to the UIC Program Director with the
other required Class VI permit approval application information [40 CFR 146.82(a)(9)]. If
stimulation is to be performed, other than for formation testing conducted under 40 CFR 146.82,
the UIC Program Director must be notified at least 30 days before the operation is performed [40
CFR 146.91(d)(2)]. In either case, the proposed stimulation method must demonstrate that it will
not fracture the confining zone or otherwise allow injection or formation fluids to endanger
USDWs [40 CFR 146.88(a)]. This can be accomplished by modeling pressures and showing that
the fracture pressure of the confining zone is never exceeded.
The modeled pressures can be confirmed using technologies such as tiltmeters and microseismic
monitoring to monitor and refine the model; however, these technologies are still experimental
and may not be applicable in all circumstances. If additional chemicals are to be used in
stimulation it should be shown that they will not react with the confining layer. Information on
calculating the fracture pressure of a formation can be found in the Draft UIC Program Class VI
Well Site Characterization Guidance. The API Guidance Document RF1 - Hydraulic Fracturing
Operations - Well Construction and Integrity Guidelines also contains information on ways to
perform stimulation without fracturing the confining layer. Additionally, the Draft UIC Program
Class VI Well Testing and Monitoring Guidance provides additional information on how to
monitor injection pressure.
Injection between the casing and the formation is not allowed [40 CFR 146.88(b)], as it would
provide no barrier between the carbon dioxide and the formation. The Class VI Rule requires the
space between the casing and the formation to be cemented [40 CFR 146.86(b)(2) and
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146.86(b)(3)]. More information on cementing requirements is available in Section 2.5 of this
guidance and in the documents referenced in Figures 1 and 2 of this guidance document.
4.2 Monitoring of the Annular Space of Class VI Wells
The Class VI Rule requires that the annulus be filled with a non-corrosive fluid and that the
annular pressure between the tubing and the casing be maintained at a pressure higher than the
injection pressure, unless the UIC Program Director determines that this requirement might harm
the integrity of the well or endanger USDWs [40 CFR 146.88(c)]. This requirement provides a
continuous check on the mechanical integrity of the well. If holes or fractures develop either in
the casing, tubing, or packer, the pressure and fluid volume in the annulus will begin to change.
In addition, if the pressure in the annulus is higher than the injection pressure, any leak in the
tubing will not result in fluid escaping. Instead fluid from the annulus will flow into the tubing.
Using a non-corrosive fluid in the annular space prevents corrosion of the tubing or casing by the
annular fluid. If the owner or operator is concerned that an annular pressure higher than the
injection pressure will damage the well or endanger USDWs, EPA recommends that they consult
with the UIC Program Director to find an applicable solution that will both safeguard USDWs
and protect the well. Options may include a more competent casing or operating at a lower, but
still positive, annular pressure.
The Draft UIC Program Class VI Well Testing and Monitoring Guidance addresses the subject
of monitoring the annular pressure in more detail.
4.3 Maintaining Mechanical Integrity of Class VI Wells
The Class VI Rule also requires that the owner or operator maintain the mechanical integrity of
the well [40 CFR 146.88(d)]. Maintaining mechanical integrity ensures that no carbon dioxide
can leak and cause endangerment of USDWs. In addition to continuous monitoring for
mechanical integrity, mechanical integrity is also verified by periodically conducting mechanical
integrity tests (MITs) [40 CFR 146.89(c),(d),(e), and (g)]. See Section 2.1.1 of this guidance
document and the Draft UIC Program Class VI Well Testing and Monitoring Guidance for more
details on how to perform MITs on Class VI injection wells. The installation and use of
continuous recording devices to monitor various pressures and volumes, as well as injection rates
is also required [40 CFR 146.88(e)(l)]. Designing for continuous monitoring is discussed in
Section 2.2.2 of this document, and the methods and technologies available for this monitoring
are discussed in the Draft UIC Program Class VI Well Testing and Monitoring Guidance.
As noted, the requirements for shut-off devices [40 CFR 146.88(e)(2) and 146.88(e)(3)] are
discussed in Section 2.8.
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5 Conclusions
Class VI injection well construction is a critical factor in meeting the requirement to prevent
fluid migration into or between USDWs [40 CFR 146.86(a)(l)]. The construction requirements
of the Class VI Rule describe the detailed construction information to be submitted to the UIC
Program Director with a Class VI injection well permit application. The main components of the
injection well are the casing, cement, tubing, and packer.
• All components of Class VI wells must be constructed to withstand the stressors of the
down-hole environment and be compatible with the carbon dioxide stream and any other
fluids with which they might come into contact.
• The surface casing must extend through the base of the lowermost USDW through the
use of a single or multiple casing strings and be cemented to the surface [40 CFR
146.86(b)(2)].
• The long-string casing must extend to the injection zone and be cemented to the surface
[40 CFR 146.86(b)(3)].
• The casing must be designed to allow continuous monitoring of the annular space
between the casing and tubing [40 CFR 146.86(a)(3)].
• This annular space must be filled with a non-corrosive fluid approved by the UIC
Program Director and the owner or operator must maintain a pressure on the annulus
greater than the operating injection pressure, unless the UIC Program Director determines
that such pressure requirements could harm the integrity of the well or endanger USDWs
[40 CFR 146.88(c)].
• If single stage cementing of either the surface casing or long-string casing is not possible,
the cement can be staged [40 CFR 146.86(b)(4)].
• Sufficient centralizers are required in cementing the long-string casing [40 CFR
146.86(b)(3)] and are recommended for all casings.
• The tubing must be designed to allow for entry and use of appropriate logging and
workover tools [40 CFR 146.86(a)(2)].
• A packer must be set at a depth opposite a cemented interval at a location approved by
the UIC Program Director [40 CFR 146.86(c)(2)].
• Surface shut-off systems are required for all onshore wells and down-hole shut-off
systems are required in all offshore wells within state territorial waters [40 CFR
146.88(e)(2) and 146.88(e)(3)].
• Down-hole shut-off systems can be required at the discretion of the UIC Program
Director for Class VI injection wells located onshore [40 CFR 146.88(e)(2)].
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Operational aspects are very important in preventing fluid migration out of the injection
zone. Operating requirements for Class VI wells are at 40 CFR 146.88.
The injection pressure must not exceed 90 percent of the fracture pressure of the injection
zone, except during UIC Program Director-approved periods of well stimulation [40 CFR
146.88(a)].
Injection is not allowed between the outermost casing and the formation [40 CFR
146.88(b)].
The owner or operator must maintain mechanical integrity of the well at all times [40
CFR 146.88(d)].
If a loss of mechanical integrity is detected either through monitoring or triggering of an
alarm, the UIC Program Director must be notified within 24 hours, injection must be
stopped, and the cause of the lack of integrity must be investigated to determine if any
fluids have entered an unauthorized zone [40 CFR 146.88(f)(l)-(4)]. Mechanical integrity
must be restored and the UIC Program Director notified before injection can resume.
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