EPA Technical Workshop on Geosequestration:
Well Construction and Mechanical Integrity Testing
March 14, 2007; Albuquerque, New Mexico
Workshop Notes
EPA held a technical workshop in Albuquerque, New Mexico on March 14, 2007 to address well
construction and mechanical integrity testing (MIT) issues as related to geologic sequestration
(GS) of carbon dioxide (CO2). Fifty-one (51) representatives of the oil and gas industry, oil field
service companies, academia, U.S. Department of Energy (DOE) national laboratories and
Regional Partnerships for Carbon Sequestration, the Interstate Oil and Gas Compact Commission
(IOGCC), five States and a Canadian Province, and EPA Headquarters and Regional staff
attended the workshop. (See Attachment 1 for a list of the attendees.)
The workshop format included a recap of the International Energy Agency (IEA) Third Wellbore
Integrity Network Meeting (held on March 12 and 13, 2007 in Santa Fe, New Mexico); technical
presentations on current research by industry, academia, and government agencies; a progress
report on the American Petroleum Institute (API) C02 well standards; and an introduction to
EPA Underground Injection Control (UIC) regulations on selected well types. In the mid-
afternoon, workshop participants split into two breakout sessions to discuss research needs on
well construction and MIT.
Welcome and Introductions
Bruce Kobelski, EPA Office of Ground Water and Drinking Water, welcomed the workshop
participants. He noted that many of the individuals in attendance, and some of the organizations
they represent, have not participated in previous EPA GS workshops, and therefore would
provide important new perspectives as EPA begins to gather the information it needs to develop
a management framework for GS. EPA has participated in and attended many meetings related
to GS to obtain input and share ideas with various stakeholders and experts. Recent examples of
such meetings include the Ground Water Protection Council (GWPC) meetings on risk
framework in Portland, Oregon in September 2005 and on CO2 injection technical issues in
Austin, Texas in January 2006. EPA staff have also attended and participated in a GS Site
Characterization Conference in Berkeley, CA in March 2006 and a World Resources Institute
workshop on liability issues in Washington, D.C., in October 2006.
Mr. Kobelski noted that EPA is currently assessing options for a management framework for
CO2 injection for the purposes of GS. GS presents many technical challenges that go beyond
those associated with CO2 injection for enhanced oil and gas recovery (EOR/EGR). For
example, GS will involve a variety of geologic settings apart from oil and gas reservoirs (e.g.,
saline aquifers and unmineable coal seams). In addition, the CO2 from coal-fired power plants
will contain impurities (i.e., sulfur and nitrogen oxides, and metals such as mercury) that are not
typically found in the CO2 used in EOR/EGR operations, and GS will involve significantly
greater volumes and longer storage times.
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Mr. Kobelski pointed out that the current workshop is a follow-up of a State Regulators'
workshop held in San Antonio, Texas on January 24, 2007, where representatives from States,
industry, academia, and research institutions provided input on research questions that EPA
needs to address in developing a management framework for GS. This well construction and
MIT workshop is an important first step in the formulation of a research agenda to answer
important questions to ensure that GS practices will not endanger underground sources of
drinking water and public health.
Mr. Kobelski then reviewed the day's agenda (see Attachment 2). In the first half of the
workshop, experts working directly on well construction and MIT issues would provide
background information and some key questions on current research activities. (Their
presentations are found in Attachment 3; hyperlinks to the presentations are on the titles within
these notes.) In the mid-afternoon, the workshop participants would be split into two breakout
groups to discuss existing research and research gaps related to well construction and MIT of
CO2 injection wells.
Wellbore Integrity and the Geologic Sequestration of C02: A Perspective from the IEA
Greenhouse Gas R&D Programme Wellbore Integrity Network
Bill Carey, Los Alamos National Laboratory, provided an overview of the work by the IEA
Wellbore Integrity Network. The IEA Wellbore Integrity Network assesses and communicates
the state of knowledge and research needs related to the long-term integrity of wellbore systems
in C02-rich environments. Focus areas include:
•	Field experience with CO2 and wellbore materials, e.g., cement placement; studies of
wells exposed to CO2; and case histories and wellbore statistics especially on legacy
wells.
•	Monitoring and wellbore logging and results.
•	Remediation approaches and costs.
•	Experimental research on cement-C02 interactions and CCVresistant cements.
•	Numerical modeling, e.g., CO2 fate and distribution in the reservoir; transport
modeling of CO2 cement; and leakage simulations.
•	Policies and regulations, including API practices, Minerals Management Service
(MMS) regulations, and Canadian and European approaches.
The Network has held three annual meetings, the most recent of which was in Santa Fe, New
Mexico on March 12 and 13, 2007. Key issues identified include the following:
•	Wellbore integrity problems do exist in oil and gas operations and are often due to
cementing practices.
•	Casing and tubular corrosion can be more rapid than cement degradation.
•	Methods to evaluate the leakage potential of older wells and within fields with
multiple wells, and remediation methods are needed.
•	Needed research on cement includes evaluating the performance of new CCVresistant
cements and methods to evaluate cement-C02 reactions.
•	More sensitive logging and field monitoring tools are needed.
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• Accessing data to help evaluate wellbore performance from private companies and
regulatory bodies should be a priority.
Dr. Carey also described research underway on CCVwellbore interaction mechanisms and on
reconciling field, lab, and modeling data on C02-cement reactivity. Following his presentation,
participants offered the following questions and comments:
Is anything known about the CO 2 conditions at the Scurry Area Canyon Reef Oil
Committee (SACROC)? Samples taken from above the caprock appeared to be
carbonated, although it is unclear for how long and to how much injected CO2 they were
exposed.
Would wells in a potential CO2 storage field that have been plugged and abandoned by
UlC-approved methods be considered "sequestration-ready? " A number of participants
responded that UIC requirements would only be applicable to injection wells. Production
wells are outside of the UIC Program's authority, although they may have followed UIC-
approved plugging and abandonment procedures.
C02-Cement Interactions: From the Lab to the Well
Matteo Loizzo of Schlumberger Carbon Services Engineering summarized research on C02-
cement reactions and development of CCVresistant cement. Interaction between cement and
C02 follows a three-step process, which includes carbonic acid diffusion,
dissolution/carbonation, and leaching. Cement sheath defects (e.g., placement defects and cracks
and microannuli) will accelerate degradation. Carbonation healing/plugging may be effective
only at small scales.
A CO2 resistant cement formulation based on "CRETE" technology and a reduced-Portland
binder is being researched. This design optimizes particle size distribution to reduce porosity
and permeability and to maximize its mechanical properties and compatibility with CO2. Mr.
Loizzo added that watered-down cement is not suitable for C02 injection wells.
Participants asked the following questions of Mr. Loizzo:
How does CO2 affect the compressive strength of the cement? The strength initially drops
and then increases. It is difficult to measure the strength of samples in the lab due
mechanical instabilities in the samples that produce spalling. This leads to lower
unconfined compressive strength for the full sample than may be expected from the
carbonated material itself.
What type of design could counteract corrosive effects? The ideal formula is a
compromise between the binder and its reaction to the CO2. Rather than completely
eliminating the use of Portland cement, Portland cement is being combined with other
cement types.
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What exotic cements have been studied? Latex cement, which is used for hydrocarbon
gases, has been found to be a poor choice for C02 injection. Epoxy cement has also been
studied, but it is of limited availability and is very expensive.
Well Integrity Experience in Alberta, Canada
Stefan Bachu of the Alberta Energy and Utilities Board (EUB) presented the Canadian
experience with C02 injection. In Canada, injection falls entirely under provincial jurisdiction.
In Alberta, the EUB has jurisdiction over both oil and gas production and deep well injection and
disposal, under the authority of Directive 65 (for disposal operations), and Directive 51 (for well
construction). Under these Directives, Class III wells are for injection of hydrocarbons, or inert
and other gases, for the purpose of storage or enhanced hydrocarbon recovery; C02 is
specifically mentioned as an example.
Acid gas injection has been practiced in western Canada since 1990. In that time frame, 6
million tons (the equivalent of a single power plant's annual C02 emissions) have been injected;
60 percent of the injection is to saline aquifers and the remainder is to oil and gas fields. To date,
only one incident has occurred, where an acid gas injection well in British Columbia failed in
2004 (due to ice formation in the annular fluid). Examples of C02-E0R projects in Canada
include the Weyburn Field and the Pembina-Cardium project.
Dr. Bachu concluded that existing regulatory requirements and controls seem to be adequate for
the operational phase of C02 injection; however, there are not yet regulations for the post-
operational phase. Proper injection site selection and characterization are important, and
monitoring of injection well integrity is critical. The long term effects of the injected acid gas on
cements and casing in older wells is not well known, and poorly constructed wells may pose the
greatest risk associated with C02 injection. The number of abandoned production wells in oil
and gas reservoirs is one of the key concerns for GS projects.
Following Dr. Bachu's talk, participants asked the following questions:
Is there anything to report about CO2 migration or flow in the Weyburn Field? The field
is in Saskatchewan, and outside of the EUB's jurisdiction. A participant added that C02
migration is occurring but is within the intended formations
What is a typical Area of Review (AoR) for a Class III well? The AoR is determined
through modeling. Typical AoRs are on the order of Vi mile; they may be larger in more
complex situations.
Is any of the acid gas injection in Alberta to saline aquifers? Yes; and while
permeability changes have been observed, no problems have been identified.
Is the Pembina field part of the DOE pilot effort? No, but the Zama field is, and it is
operating.
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A Comprehensive Wellbore Integrity Program
Charles Christopher of BP Americas, Inc. presented an overview of the Carbon Capture Project's
Sequestration, Monitoring, and Verification program. He outlined the components of a
comprehensive wellbore integrity program, including the need for good data on current well
inventories, historical statistics on the effects of C02. and well autopsies and analysis of
recovered cement and tubulars. Good modeling will require an understanding of the mechanisms
of attack on cements, and researchers are beginning to understand these and identify appropriate
modeling parameters.
Mr. Christopher also provided a status report on a well autopsy/corrosion field study of a CO2
production well. In October 2006, the tubing and packer were removed, and found be in good
shape after 22 years, due to protection by the tubing liner and annulus fluid (in fact, the foundry
stenciling was still visible on the tubing). Other testing of the well includes logging, cement
evaluations, and X-ray diffraction and scanning electron microscopy of cement cores.
No questions were raised after Mr. Christopher's talk.
Geological Storage of Carbon Dioxide: Models and Parameters
Sarah Gasda of Princeton University provided an overview of models that assess wellbore
leakage and geologic storage of C02. The study team compared modeling options, including 3-
D numerical solutions, vertically-averaged equations, and semi-analytical solutions to assess
abandoned well performance and potential leakage. The comparisons focused on the Edmonton-
Wabamun Lake Area of Alberta, because data on abandoned well location and formation
permeability are available. A combination of analytical and numerical models could allow rapid
simulations of mass transfers within aquifers based on permeability inputs to provide a broad
assessment of processes occurring within the injection reservoir. The models can also be used to
detect critically leaky wells based on pressure changes (i.e., the wells are more permeable than
the formation).
Participants offered the following questions and discussion points on Ms. Gasda's presentation:
Were any other modeling codes, e.g., ECLIPSE, examined? These models are slower
than the numerical models used and are more appropriate to single well analyses, rather
than the reservoir-scale simulations performed.
The oil and gas industry has used these models at the reservoir scale. While these
models can be used at the reservoir-scale, in non-industry applications (e.g., saline
aquifers), fewer data inputs may be available than is typically available for oil and gas
fields. Numerical models offer a means to model the reservoir with whatever data are
available. They offer a broad-brush approach that generates results that can be presented
to the public with a reasonable degree of certainty. The study team has validated their
model against the ECLIPSE model.
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No migration petitions may serve as an analog to the modeling approach, i.e., bounding
the problem. Ms. Gasda responded that the intent of their models is to assist decision-
makers in evaluating the fate of CO2 in storage and these models will also provide useful
information to the public by trading off complexities with simpler and easy to understand
models.
Selecting Sites for Geological Sequestration: Wellbore Integrity and Other Criteria
Jason Heath, of the New Mexico Institute of Mining and Technology and a member of the
Monitoring, Mitigation, and Verification (MMV) and Site Characterization groups of the Southwest
Regional Partnership, presented work underway in the Southwest Regional Partnership. CO2
sources in the study region include power plants and other sources that generate about 100
million tons of CO2 annually. One of the partnership's first tasks was to identify suitable GS
sites. Site selection must consider practical issues (e.g., site ownership and regulatory
requirements); technical issues (proximity to high-capacity storage reservoirs and low-risk
geology); and well integrity. Sites along existing CO2 pipelines are preferred.
A well integrity analysis is being performed in the Aneth Unit in southern Utah, which will be
flooded with CO2 in June, 2007, to determine whether CO2 will leak from the target reservoir
and how this can be monitored. There is concern about well construction deficiencies (e.g.,
insufficient casing and cementing) in older wells in the Aneth Unit. Speculation about the
migration of saline water from the De Chelly aquifer upward into the Navajo aquifer by wells
was made by some researchers, but well-migration has not been verified. Analysis of well
construction deficiencies included temperature logs or cement bond logs and reviews of
information on the depth of surface or intermediate casing and cement placement in the wellbore
annulus.
Participants asked the following questions of Mr. Heath:
Has any monitoring been performed in the vulnerable wells identified in the Aneth Unit?
No monitoring has been performed in the vulnerable wells by the Southwest Partnership.
The Southwest Partnership developed plans to monitor groundwater wells in the shallow
aquifer in the vicinity of the vulnerable oil wells. However, the oil company denied
permission for this monitoring. The landowners are very sensitive to any groundwater
sampling in the area - the oil company feels it is best not to bother landowners at present.
An EPA participant commented that US EPA requires the oil company to frequently
monitor and periodically test all injection wells for mechanical integrity.
If monitoring could be done, what parameters would the study team monitor?
Conductivity, temperature, alkalinity, pH, major ions, trace metals, and isotopes of
hydrogen, oxygen, dissolved carbon, and dissolved strontium.
Is any remediation planned? Most of the wells in the Aneth Unit were drilled before the
UIC Program was put in place. These "grandfathered wells" will not require remediation
unless they are shown to pose a substantial risk of fluid movement into the underground
source of drinking water (the Navajo Aquifer). No casing or cementing remediation for
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any wells is planned at this time. However, wells must be remediated if they show
evidence of fluid movement in the uncemented portion of the wellbore annulus or
develop casing leaks, and during plugging and abandonment operations. Injection wells
with known construction deficiencies will require frequent monitoring for fluid pressure
and movement in the wellbore annulus, under the terms of the UIC permit for CO2
injection in the Aneth Unit EOR project.
EPA Region 9 has not yet received the application for C02 flooding at the Aneth Unit. It
is possible that after EPA's review of the forthcoming application, some wells may need
to be remediated, but since the wells have been "grandfathered," remediation will not be
required unless a real danger to the aquifer can be shown. Injection wells that fail
mechanical integrity testing or develop excessive pressure in the tubing/casing annulus
during operations must cease injection pending remedial work to restore mechanical
integrity or must be plugged and abandoned if repairs are unsuccessful.
If CO 2 escapes the Paradox Formation, this could pose a risk; the lack of data poses risk
as well. There is a long history of water flooding, and a small CO2 pilot was performed
in the Aneth Unit in 1998. There is some experience upon which to draw. C02 leakage
has occurred in the past in a nearby unit, into which CO2 has been injected for 20 years.
In this leakage event, holes in the casing caused an apparent discharge of C02. along with
saltwater and oil, to a shallow aquifer and spring. The well was plugged and the aquifer
was remediated; monitoring continues.
Is there any gas in the reservoir? No.
API Activity on CO2 Well Construction/Integrity and CO2 Capture and Geosequestration
Ron Sweatman, Global Business and Technical Solutions, Halliburton, presented API's activities
related to CO2 well construction and carbon capture and storage (CCS). Current work includes
the API CCS Work Group, which is studying CO2EOR practices, and a joint project with the
International Petroleum Industry Environmental Conservation Association to develop guidelines
(i.e., recommended practices, or "RPs") for emission reductions from CCS projects. The API RP
90 Committee is evaluating annular casing pressure (ACP) management for offshore wells; while
not specific to CO2, this document will provide guidance on wellhead pressures.
The Well Planning and Design task group (RP-65) is studying well casing pressure prevention
and remediation practices and recommended practices intended for federal regulations. One
product, RP 65-2 addresses pressure barriers and related well construction practices, and is
relevant for preventing CO2 leaks during well construction. This draft document is undergoing
final review to resolve comments made on the letter ballot which approved the draft for
publication.
The task group is currently developing RP 65-3, "Practices to Prevent or Remediate Annular
Casing Pressure [ACP]." The report will present recommended practices to prevent, detect, and
remediate ACP during well construction, production, injection, and abandonment (including
prevention and remediation of CO2 leaks). Topics to be covered include preventive practices for
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sustained well integrity (e.g., well design; diagnostics during well construction; mechanical,
chemical, and formation barriers; and MIT) and remedial practices (e.g., ACP detection and
diagnostics, well integrity monitoring after abandonment, cementing barriers, and casing/liner
pipe repair methods). The casing pressure assessments conducted relate to sustained casing
pressure by formation or injected fluids including hydrocarbons, CO2, H2S, H20, brine, etc.
Publication in late 2008 or 2009 is expected.
Participants asked the following questions of Mr. Sweatman:
When will RP 65-2 be final? It should be published in 2007; about 3 to 6 months are
needed to address the many comments received on the letter ballot of the last draft and
for a possible second vote to decide any unresolved technical comments for the final
product.
What is the difference between sustained casing pressure (SCP) and thermal induced
annular casing pressure (on slide 12)? SCP is caused by annular flow of formation or
injected fluids. Thermal induced annular casing pressure is caused by trapped fluid
pressure in or near the wellbore.
UIC Program Class I and II Well Construction and MIT Requirements
Brian Graves, EPA Region 6, summarized the federal UIC Program requirements for Class I
nonhazardous waste and Class II injection wells, which could serve as a starting point for a
management framework for C02 GS wells. UIC construction requirements address casing and
cement, packer, well materials and cementing; logs and tests; and information about the injection
formation. MIT requirements include internal, or Part 1 MIT (i.e., an initial pressure test, then
monitoring annulus pressure, and pressure test every 5 years) and external, or Part 2 MIT (i.e.,
temperature, noise or other approved log every 5 years). For Class II wells, adequate cement
records may be substituted for the external MIT.
Participants asked no questions following Mr. Graves' talk.
Technical Breakout Sessions
The participants split into two groups to discuss questions related to construction and MITs for
wells that will inject CO2 for GS and to identify what the groups consider as the top research
needs or gaps. Participants were also asked to discuss whether they felt that specific
requirements related to construction and MIT or a performance-type standard would be more
appropriate for CO2 GS. Following the breakouts, the entire group reconvened and a reporter
from each breakout session reported on its findings.
Session A - Well Construction
Participants in the well construction breakout session generally felt that little additional research
on construction materials is necessary, adding that injection well drilling and construction are
well developed technologies, and the UIC Class I requirements may be sufficient for CO2 GS.
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They added that the composition of the CO2 that will be injected may affect construction
requirements for GS operations. Bill Carey reported to the group on the discussions during
breakout Session A.
General comments and research needs on well construction
•	API has developed recommended practices and protocols for properly designed and
constructed wells.
•	Pilot tests with significant (i.e., real-world) volumes of CO2 are needed; these would
reveal new research needs.
•	Performance-based construction standards may be appropriate (Class I hazardous
waste wells may be a model). Standards should be based on how long the well is
expected to last and on risk.
•	Existing protocols were developed based on research over the past 20-30 years (e.g.,
metallurgy and induced failures); however, much of this research is confidential.
•	C02 composition (i.e., impurities in the stream) may drive additional research
requirements for metallurgy, etc. What impurities would cause the CO2 injectate to
be defined as "hazardous?" CO2 stream composition will depend on fuel type, capture
processes, and transportation requirements.
•	What is the "life expectancy of the well" for management purposes, i.e., are we
concerned with the injection period (20-30 years) or the abandonment phase
(hundreds of years) as well? This will impact management of the well.
•	See the "Wink sink" example. Sink holes developed from improperly constructed oil
and gas wells in Wink, TX.
•	Research need: developing lower cost materials that perform as well as high-cost
materials is needed.
Discussion and research on casing
•	Significant research experience from EOR and acid gas operations, e.g., from
SACROC, provides a good working basis for well construction.
•	API's CCS working group is conducting a survey of CO2 operators on performance
of metallurgy and coatings.
•	Abandonment procedures may need to be more stringent for GS (e.g., full cementing
of the wellbore). Consider applying temporary abandonment procedures as an interim
approach, allowing for monitoring and modifications.
•	Casing specifications depend on possible impurities, formation brine, pressure,
temperature and operational conditions.
•	Internal coatings protect the inside of the casing and degrade.
•	Casing options include chrome tubing (see SPE documents), expandable tubing,
titanium casing (as in geothermal applications), fiberglass casing, and inhibited
packer fluid for additional protection. However, are these costly options needed?
•	Research need: study the impacts of injection at varying depths.
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Discussion and research on cementing
•	Cement specifications depend on the presence of CO2 impurities; formation brine; and
pressure, temperature and operational conditions.
•	API documents list cements and non-API materials.
•	Some geological environments (salt domes) may self-heal and close any openings.
•	Cement should run the entire length of the wellbore (i.e., per Class I requirements).
This cannot always be done and may not be desirable (e.g., cut casing at depth and fill
the hole or allow formation collapse).
•	Research need: alternative (non-Portland) cements, e.g., phosphate-based cement
(Burkhaven and Halliburton study).
Discussion and research on drilling
•	Installed pressure/temperature, pH, and other sensors for monitoring.
•	Is there a difference between GS and other drilling operations?
•	Deviated wells pose cementing risks.
Session B - Mechanical Integrity Testing
Participants in the breakout session on MIT believed that MIT requirements may need some fine
tuning to meet the needs of C02 GS operations. In particular, the types of MITs and frequency
of testing may need additional evaluation. Participants cautioned that properly constructed and
operated C02 GS wells should not be damaged by too frequent testing. Matteo Loizzo reported
on the discussions in Session B.
1) What information on GS operations is needed/most relevant to selecting MITs that accurately
represent the integrity of the well and alert operators to possible problems?
•	Most of the C02-specific and general MIT information EPA needs already exists
with: hazardous waste injection well operators (injection wells); UIC Class II
CO2/EOR operators (injection wells); CO2 producers (production wells); oil and gas
companies (production wells); oil field service companies (injection and production
wells); States (injection and production wells), and natural gas storage operations
(injection wells). (Note: Natural gas storage operations and production wells are not
regulated under the UIC Program.)
•	Research need: Review lab, field, and modeling studies on cement-related micro-
annuli self-enhancing (enlarging) vs. self-healing (sealing) conducted by laboratories,
the oil and gas industry, and oil service companies.
•	Additional note regarding the formal UIC regulatory language of "no significant
leak" (re: internal MIT) and "no significant fluid movement" (re: external MIT):
some felt that the word "significant" was too ambiguous while others said that this
was perhaps intentional to give the primacy or DI authority more flexibility.
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2)	How do the properties of CO 2 GS operations (e.g., thermal changes, phase changes,
corrosivity, and pressures), impact well integrity and the appropriateness/usefulness of various
available tests?
•	Phase change is probably a more significant mechanical integrity concern than
corrosivity. Retaining the C02 in a supercritical state may be appropriate.
•	Research needs:
o Phase changes and its effect on flow along the borehole,
o Research on phase changes should address its possible contribution to CO2
migration to the surface, whether it could cause injected C02 to freeze, possible
contribution to well blowouts, its effects of CO2 coming out of solution, and how
phase changes might affect mechanical integrity pressure tests,
o Do acid gas mixtures (CO2 and H2S) and acid gas injection experiences provide
information on phase changes?
o Can temperature changes (in the well system or immediately outside the well in
the wellbore) indicate leaks?
3)	How would the presence of impurities in the CO2 stream (e.g., SOx, NOx, andH2S) impact MI
of the well and the appropriateness or usefulness of available tests?
•	The presence of impurities in the CO2 may affect selection of the appropriate casing
which would, in turn, affect the choice of appropriate MITs.
(In other words, if well construction is appropriate for the injectate stream, then the
selection of the appropriate MIT is straightforward.)
•	Impurities may cause scaling and affect MI.
•	If impurities are permitted to be present in the C02, this would impact appropriate
well completions, e.g., specific materials for packers would be required.
•	H2S can affect phase change properties; however, removing impurities may be cost-
prohibitive. H2S is more toxic than C02.
•	Research need: Additional research is needed on the impact of impurities (and the
impact of wet vs. dry C02) on well mechanical integrity. SOx is the greater concern,
because it combines with water to form sulfuric acids.
•	Additional notes: Oil and gas industry has MIT performance regulations for
production wells. Also, one participant speculated that operators know which MIT
would result in the lowest chance for MIT failure given the specific conditions of the
well being tested, and that some operators might choose to use this "lowest
performing," yet UlC-approved MIT. This prompted the question of whether
operators should be allowed to select the MITs to use.
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4)	What MIT data from existing CO2 injection wells is useful for predicting MI and testing needs
at the scale anticipatedfor GS?
•	In Texas, casing problems are very rare; cement squeezes are sometimes needed.
•	There are differences in the impacts to well systems from corrosive injectate vs.
corrosive geologic/oil and gas zones (affecting cement and casing).
•	Tubing and packer leaks are prevalent in older fields. Annulus leakage is common in
older wells. This may be a problem for EOR wells. If there are CO2/EOR tubing
problems, appropriate MITs are available.
•	Much information from monitoring of excessive pressures is available.
•	Research needs:
o Examine external MIT failure rates; operators are required to report this.
Examine the few, rare cases of cement problems in Texas; can these cases be
linked to a construction problem or a corrosion problem? (Does corrosion only
become a problem if there is a pre-existing construction problem?)
o Further research on the Texas Railroad Commission UIC/MIT data.
5)	How do the MITfailure rates for Class II wells that inject CO 2 compare to other injection
wells?
•	This information would be available in workover reports and daily logs.
•	Research need: Further research the data from the Texas Railroad Commission on
MIT failure rates by injectate type (i.e., acid gas, CO2, fresh water, and brackish
water).
6)	Have any Class II wells that inject CO2 experienced leakages along the borehole either to the
surface, or into USDWs or other formations? If so, was the CO 2 a contributing factor to the
leakage?
•	One case involved leakage in the long-string casing that caused movement of CO2
into an aquifer and spring. A report is available from EPA Region 9.
•	The "Salt Creek Field" reportedly had/has a CCVrelated leak. (Follow-up with
Schlumberger.)
7 & 9) How do the properties of CO 2 GS operations (e.g., thermal changes, phase changes,
corrosivity, and pressures), impact well integrity and the appropriateness or usefulness of
various available internal and external MIT procedures?
•	It is possible to measure the casing thickness.
•	Electrical resistivity logs can detect pitting and other casing problems, and
televiewers can be used to assess the integrity of the casing. These MIT methods are
pretty well understood.
•	The value of the use of these known MITs will be increased if well construction and
MIT selection/use is better integrated.
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8) How might the temperature changes associated with injecting supercritical CO2 affect
pressure tests?
•	Research needs:
o Research the phenomenon of a cold injection fluid opening up or enlarging gaps
within the well system,
o Impact of large temperature differentials between injectate and well
system/formation on pressure tests. Industry may have a lot of information on
this subject.
o How would C02 in the annulus affect a pressure test?
10)	What is the best way to test for fluid movement along the casing in CO2 GS wells?
•	While existing MITs can detect fluid movement, these MITs and other available
monitoring methods cannot detect the rate or volume of movement.
•	Advanced mapping tools may be needed.
•	Research need: Monitoring methods/MITs that could detect rates and volumes of
fluid movement along the casing (not just the presence/absence of movement).
11)	What is the data quality of the cementing records for CO 2 injection wells, and how does this
compare to external MITs or logs?
•	Cement records are important and necessary for monitoring and documenting well
construction.
•	Cement records are not an appropriate substitute for digital logs or external MITs for
CO2 injection wells.
12)	Is there an isotope that is soluble in CO2for use in the radioactive tracer survey?
•	Yes - some/many are available (and are expensive).
13)	Over what time frames do MI changes occur in CO2 injection wells?
•	Gross mechanical integrity problems appear early on.
•	Early MITs, plus subsequent monitoring allow for developing a staged approach to
managing risk.
•	MMS may have developed a regulation to address this (infrequent MIT is acceptable
if no problems appear).
•	See API 90 report.
•	MITs every 5 years may be too infrequent.
•	Research need: Research regarding time frames of MI changes and necessary MIT
frequency. (Note: This directly relates to research needs under question 1 on self-
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enhancing vs. self-healing micro-annuli and question 14 on the Texas MIT data to see
if new or old wells tend to have MIT failures.)
14)	Is successful performance early in the life of the project an indicator that MI will be
maintained over the long term?
•	This is addressed in the risk framework.
•	Research need: Texas may have useful data on MIT failure rates (for example among
new vs. old wells; see related research needs for questions 4 and 13).
15)	What annular fluids will not react with CO 2?
•	Existing geochemistry studies can answer this question.
16)	What methods are available to evaluate micro-annulus leakage in CO2 GS wells?
•	Existing MITs can evaluate the presence/absence of flow along the outside of the
casing.
•	Research need: If more than presence/absence information on flow/leakage is
needed, then research is needed on the rate and volume of flow/leakage (see question
10).
Next Steps/Closing
EPA will prepare notes of the meeting and make them available on its website. EPA will take
everything discussed in the workshop under consideration as it develops the well construction
and MIT components of the GS management framework. Participants are invited to send
additional ideas or comments to GS workshop s@cadmusgroup. com.
EPA plans to hold other technical workshops in the coming months. While these workshops have
not been scheduled, anticipated topics include site characterization, Area of Review, and liability
and financial responsibility. EPA also plans to hold a meeting on risk analysis and framework,
possibly in conjunction with the World Resources Institute liability workshop this spring.
EPA will continue to participate in other events related to GS. Some examples in the coming
months include:
•	American Association of Petroleum Geologists (AAPG) Annual Convention is being
held on April 1-4 in Long Beach, California. The agenda includes sessions on GS
and EOR.
•	A Schlumberger/Massachusetts Institute of Technology workshop will be held in
Cambridge, Massachusetts on April 23 and 24.
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•	The Interstate Oil and Gas Compact Commission (IOGCC) will meet in Mobile,
Alabama on May 5-8.
•	The next IEA Well Monitoring Network Meeting will be held on October 31 and
November 1 in Edmonton, Alberta.
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ATTACHMENTS
1.	Workshop Participants
2.	Workshop Agenda
3.	Presentations
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Workshop Participants
James Anderson; Shell Oil
Stefan Bachu; Alberta Energy & Utilities Board
Lawrence Bengal; Oil and Gas Commission of Arkansas
Kevin Bliss; Interstate Oil and Gas Compact Commission
Glenn Breed; Wyoming Department of Environmental Quality
Bill Carey; Los Alamos National Laboratory
Robert Carpenter; Chevron Energy Technology Company
Rick Chalaturnyk; University of Alberta
Carl Chavez; NM Oil Conservation Division
Wendy Cheung; US EPA Region 8
Charles Christopher; BP
Jesse Claffey; Schlumberger Carbon Services
Karen Cohen; U.S. Department of Energy/NETL
Cal Cooper; ConocoPhillips
Andrew Duguid; Schlumberger Carbon Services
Richard Ezeanyim; Oil Conservation/EMNRD
Mark Fesmire; New Mexico Oil Conservation Division
Craig Gardner; Chevron
Sarah Gasda; Princeton University
Brian Graves; US EPA Region 6
Tor Harald Hanssen; Statoil ASA
Jason Heath; New Mexico Tech
Bruno Huet; Princeton University
Scott Imbus; Chevron Energy Technology Co.
Nicolas Jacquemet; BRGM (French Geological Survey)
Peter Jordan; Subsurface Technology, Inc.
Steve King; Subsurface Technology, Inc.
Bruce Kobelski; USEPA
Jonathan Koplos; The Cadmus Group, Inc.
Randall Larkin; Consultant
Samuel Lewis; Halliburton
Harry G. Limb; ConocoPhillips
Matteo Loizzo; Schlumberger
Chuck Lowe; Ohio EPA
William Mann; US EPA Region 4
Frans Mulders; TNO
Jean-Philippe Nicot; Texas Bureau of Economic Geology
William O'Connor; US Dept. of Energy
Michael Parker; ExxonMobil Production
Robert Puis; Ground Water & Ecosystems Restoration Division, EP
Shari Ring; The Cadmus Group, Inc.
Daniel Sanchez; NM Oil Conservation Division
Allan Sattler; Sandia National Laboratories
Elizabeth Scheehle; US EPA
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Chi Ho Sham; The Cadmus Group, Inc.
Arne Valland Singelstad; Statoil ASA
Donald Stehle; Sandia Technologies, LLC
Ronald (Ron) Sweatman; Halliburton
Richard Theskin; California Department of Conservation, Division of Oil & Gas
Robert Van Voorhees; Bryan Cave LLP
James Walker; USEPA Region 9
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