State Regulators Workshop on Geologic Sequestration of C02
The Environmental Protection Agency (EPA), in coordination with the Department of
Energy's National Energy Technology Laboratory (NETL), and the Ground Water
Protection Council (GWPC) held a workshop on geologic sequestration of carbon dioxide
(C02) on January 24, 2007 in San Antonio, Texas. At the workshop, representatives of
state governments, EPA Regions, DOE research laboratories and Regional Partnerships,
industry, non-governmental organizations (NGOs), academia, and other interested parties
met in small groups to discuss issues associated with CO2 injection for the purposes of
geologic sequestration (GS).
Participants were asked to formulate questions and identify research needs to be
addressed as EPA prepares to develop a scientifically-sound management strategy for
C02 injection. The participants were organized into groups of 8 to 10 people, with each
group having a mix of representatives from EPA regions, states, industry, research
institutions, academia, and NGOs, to allow for sharing various points of view. The group
discussed the following topics: site characterization; modeling; area of review (AoR);
injection well construction; mechanical integrity testing (MIT); measuring, monitoring,
and verification (MMV); closure and post-closure care; and liability and financial
responsibility.
Below is a compilation of the questions, comments, and observations raised at the
workshop. Note that some of the points raised are out of the scope of an EPA
management framework; they are included here for completeness.
Site Characterization
Questions
• What are the ideal parameters for an injection reservoir?
• What is the impact of a buoyant fluid?
• What geomechanical studies are needed to determine fracture pressures?
• Can the original pressure in a depleted reservoir be an acceptable default for CO2
injection?
• What petrophysical data will be needed? How do rock properties affect seal
requirements?
• How should "produced" (i.e., displaced) water be managed?
• In areas with pre-existing seismic stresses, how important is seismic data for site
consideration?
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Comments and Observations
The group noted that decisions on appropriate injection sites require many site-specific
inputs. The following were offered as information that should be considered in
determining whether a proposed site is appropriate for CO2 injection:
• Faults need to be identified and determinations made as to whether the faults interfere
with containment characteristics.
• Fractures must be understood.
• Know the surface exit points (i.e., points of potential surface release and human
exposure) for CO2.
• Understand the geologic column, including porosity, permeability, and trapping
mechanisms.
• Characterize the overburden and subsurface structures (e.g., using lithology or
outcrop data). Examine cap rock characteristics.
• Identification of the size, capacity, and injectivity of the receiving formation is critical
for site characterization.
• Characterize water-rock-C02 geochemistry; i.e., what is the significance of
mobilizing metals in an oilfield brine?
• Consider coring for chemical testing.
• Consider weather data.
• Accessibility at the surface, e.g., to wildlife, is an important factor.
• Sensitive and populated areas should be assessed.
More detailed geologic site characterization data (e.g., establishing depositional
environments) may be required for CO2 injection than for oil exploration and production.
Generally, the data currently required in UIC permit applications should provide most of
the needed information. Most of the Class I guidelines can be used.
Injection pressure should be limited to avoid creating or opening fractures; pressures need
to be monitored.
Recognize that there are regional differences in the level(s) of public concern and in the
expertise available to evaluate potential injection sites.
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Certain sites (e.g., karst areas or active seismic/fault zones) should not necessarily be
excluded from consideration, but mitigating factors should be considered in decisions.
Have the regional pilot sites met the ideal parameters for a reservoir or were they selected
for convenience?
Research is needed on buoyancy effects/adequacy of cap rock (cap rock integrity is more
important for GS than for oil and gas exploration).
Modeling
Questions
• Can models adequately evaluate the impacts of faults and petrophysics?
• How many cross-sections will be needed to provide data inputs for models? 2-D or
3-D modeling would balance sufficient/adequate data and ability to explain results to
the public and others.
• Should conservative estimates be made for modeling purposes to reduce vulnerability
to human health and the environment?
• Will the use of "agency accepted" models be required?
• Should there be a standard, publicly-available model?
• How can we correlate the various models that are currently available?
• Should modelers be certified or meet minimum qualifications?
• How can time scales be incorporated into models?
Comments and Observations
Participants provided varying opinions on the appropriateness of existing models for C02
injection. Some felt that existing oil and gas reservoir models can be easily adapted to
C02 injection into saline formations, since they are less complex systems. Others felt
that the multi-phase nature of CO2 requires more sophisticated modeling.
Models can provide reasonable estimates, provided there is enough input data to do the
modeling. A carefully designed data collection program for model inputs is needed.
Models should be validated by comparing model results to real-world data.
Models must be continuously updated and recalibrated as new data become available.
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Modeling timeframes of 500 years should be sufficient. Long-range predictions cannot be
confirmed (10,000 years is unrealistic).
Look for models with simple parameters that provide reasonable results.
Quality baseline data (e.g., on water-rock interaction and mineral reactions) is needed to
serve as inputs for the models.
Reporting requirements should include model validation (i.e., what was predicted, how
accurate models were).
A variety of models are acceptable, but there are benefits to standardization.
Regulators and operators must agree on the model to be used (i.e., information and
simulation process).
Models should be conservative ("conservative" needs to be defined).
Area of Review (AoR)
Questions
• Can existing UIC AoR study methods address CO2 sequestration issues (e.g., buoyant
fluids), or must a new method be developed?
• Are standard procedures for AoR studies needed? What should the role of models be?
How many details does the regulator need for models applied to AoR studies (e.g.,
calibration, sensitivity analysis)?
• Is a radial flow model useful or acceptable for CO2?
• Do we have adequate information on CO2 impacts to aquifers?
• For what timeframe should an appropriate area of influence be considered (1 year to
500 years)?
• How much information on well integrity and the number of wells in the area of
review is needed? How can old abandoned wells be identified?
• Is research needed to distinguish areas of elevated pressure (extending beyond the
plume) vs. area of plume migration (in post-closure conditions)?
• How would the AoR for horizontal wells be determined?
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Comments and Observations
Participants offered varying opinions on the appropriateness of using a fixed-radius AoR.
Some felt that a fixed radius AoR is not appropriate; others said that a fixed AoR can be
used initially, but an area similar to the zone of endangering influence (ZEI) should be
used if sufficient data exists to more accurately define the AoR. Some felt that a fixed
minimum radius would be appropriate, although a maximum radius cannot be set. Others
said that AoR studies should be based on volumes of C02 injected and the pressure
influence.
The following considerations for an AoR study were offered:
• The extent of the CO2 plume and extent of pressure increase are important
information. The AoR should be based on injection volume, injection pressure, and
plume movement during the period of interest (which needs to be defined).
• AoR determinations must recognize the two-phase nature of the injected CO2.
• Include information on geologic systems (e.g., deep karst, fluvio-deltaic channels,
and sheet sands).
Research how old wells with old plugs have held up to injection underneath or nearby. If
they demonstrate integrity, the presence of older wells in the AoR may be acceptable.
Some areas with old, undocumented penetrations may not be good candidates for CO2
injection (exclusion zones) unless injection is into significantly deeper formations.
AoR and ZEI are not adequate terms. New terminology is needed to reflect pressure,
injection, CO2 migration, and possibly surface effects.
Participants offered the following comments and observations about corrective action on
wells in the AoR:
• CO2 -water-cement interactions must be further characterized. There are 30 years of
oil industry data.
• Corrective action must be identified and addressed in the permit application process.
• Tailor the response to the extent of the problem.
Well Construction
Questions
• How susceptible are well materials to CO2?
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• What effect will impurities either in the injected CO2 or created through dissolution
have on the injection well and on wells in the AoR?
• Is a standard packer adequate for CO2 injection?
• What types of cement are adequate for C02 injection?
• What is the potential for well blow-outs and how can wells be designed to avoid
them?
• Are there any new well drilling and casing options? What are the implications of
laser drilling and expandable casing for C02 injection?
• Are there any new well intervention techniques?
• What are the implications of introducing microbials into the well for sealing?
Comments and Observations
Use expertise from existing C02 injection wells in enhanced oil recovery (EOR)
operations for constructing C02 GS wells. For example, there is an American Petroleum
Institute (API) study on well construction.
Continue to research how wells that have received C02 during long-standing EOR
operations have held up over time.
CO2 wells that inject into saline formations should be constructed to Class I standards.
Ask a professional organization (e.g., ASTM) to develop construction standards for CO2
sequestration wells.
Construction materials should be carefully selected, monitored, and modified over time
as necessary to adapt to site conditions, the injected stream, and operating parameters.
Appropriate materials exist today.
Properly designed and constructed wells should be able to last for a sufficient period in
the presence of the injected CO2.
Research is needed on additional well sealing methods and into eliminating cements
through expandable casing.
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Mechanical Integrity Testing (MIT)
Questions
• How effective are current MIT techniques in the various circumstances being used for
pilot projects? Which tools are more effective? Which MITs should be used on which
types of wells (e.g., production wells)?
• Should MIT be required for all wells in a field with CO2 sequestration?
• Should micro-annulus leakage be evaluated?
• How much fluid leakage during MIT is acceptable?
• Is there an I131 isotope that is soluble in CO2 for use in the radioactive tracer survey
(RTS)? If not, can another radioactive tracer be used?
• Is continuous pressure monitoring necessary?
• What is the most effective annular fluid that will not react with CO2?
• What is the best way to test for movement around the casing?
• If it can be demonstrated that the casing is secure to water, is it secure to CO2?
• What is an acceptable amount of mechanical integrity (MI) loss (e.g., 5 percent)?
Comments and Observations
MIT should be conducted on a regular basis (at a frequency to be determined). Part 1 and
2 MI demonstrations should be frequent at first, and the frequency may be reduced with
experience, as appropriate.
Explain that MIT failure is not the same as a release to the environment.
Wells used for CO2 injection should be continuously monitored to verify MI.
A broad array of tools is acceptable. A list of available MIT tools would be useful.
Develop a consistent national approach to calculating maximum injection pressure. A
new MIT may need to be developed.
Standard definitions are needed.
Cement records are insufficient; additional MITs are needed for CO2 injection.
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Participants offered suggestions for research topics related to MIT:
• The impact of phase changes on MIT tools.
• The impact of pressures, i.e., above injection zone, to avoid damage to the well.
• Temperature effects along the length of the borehole and casing.
• The appropriateness of temperature logs, noise logs, oxygen activation tests, and
RTS.
• Correlating well failures with injection history.
Measuring, Monitoring, and Verification (MMV)
Questions
• What sensors can be used? Are current down-hole CO2 detection tools acceptable?
• What happens if CO2 is detected? Is corrective action needed? What parameters
need to be set to determine compliance?
• How can leakage be quantified? How well will total volumes injected be known (i.e.,
within 5 percent), and how can we verify 100 percent containment?
• Should an odorant be added to the injected CO2?
• Should the operator's monitoring/verification responsibilities be included in the
permit?
• How will the Underground Injection Control (UIC) and Office of Air and Radiation
(OAR) programs interact on MMV processes?
• Assuming there will be C02 migration, should low migration rates be measured and
documented?
• What if fluids move up-gradient into overlying aquifers?
• What is an appropriate time frame for 4-D seismic monitoring?
• Should monitoring for carbon credits be linked to human health and the environment?
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Comments and Observations
Do not set an arbitrary leakage rate. If acceptable leakage rates are set too low,
demonstrating compliance becomes impossible. C02 must be allowed to migrate out of
the injection zone; this is not leakage. Rather, the concern is about migration to the
surface.
Some leakage will occur, and research on leakage will help advance our understanding of
what factors might increase leakage rates. This information can be used to improve site
selection, well construction, etc.
Baseline surveys are important, e.g., initial baseline chemistry data from private water
wells. These conditions can help assess leakage.
Use a tracer in the CO2 injection stream to make it possible to identify the source.
Monitor within the first porous zone above the confining layer.
Look at geochemical changes.
Research should focus on what is necessary to protect human health and assure safety.
One-size-fits all MMV approaches will not work. Site-specific determinations are
needed. Focus monitoring in areas of anticipated activity. Distinguish between
pilot/demonstration projects and industrial projects.
The sensitivity of measurement tools must be understood. Sensitivity of all tools should
be increased.
Conduct atmospheric monitoring in the vicinity of the injection well.
Light hydrocarbons (e.g., methane) can also migrate and are an issue.
Closure/Post Closure Care
Questions
• Should specialized cements be used to plug all or part of the well?
• Will a CO2 pressure zone create concerns for future drilling (e.g., for resource
exploration or production or waste disposal)?
• For how long should post-monitoring be conducted, if at all? Should the permit
application include a post-injection modeling plan (in advance of closure)?
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• Do current institutional controls cover all closure and post-closure requirements? Are
new controls needed to protect human health and the environment?
Comments and Observations
Closure requirements must include physical specifications as well as a post-closure
MMV regime (details should be defined).
Closure requirements should be on a project-wide basis, not for individual wells.
Proper plugging and abandonment of injection wells is important.
Post-closure monitoring should include: pressure falloff test; seismic monitoring, if
appropriate; and monitoring in and above the injection zone and the USDW.
CO2 plume monitoring requires a unique monitoring regime. Performance confirmation
to assure that the plume is moving where it is supposed to is needed.
Monitoring time frames should be twice as long as the injection period or until there is a
95 percent pressure die-off This has implications for the question of acceptable leakage.
The main question driving monitoring needs is whether pressure returns to normal levels
as expected. If not, then further monitoring might be required. If behavior is as
expected, there is no concern for the injection well.
A long-term record-keeping system is needed.
Liability and Financial Responsibility
Questions
• How should liability be apportioned among the operator, generator, and other
entities?
• Does the federal or state government bear any responsibility for long-term liability
issues?
Comments and Observations: Liability
Liability should last for as long as the injected CO2 has the potential to cause damage. A
suggested timeframe for leakage liability is twice as long as the injection period or until
there is a 95 percent pressure die-off
Consider incorporating notices of prior CO2 injection into the land deeds within the
largest affected area.
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Liability for leakage in the long-term should be transferred to the government. This
should occur within a reasonable period after cessation of the project. Finance through a
CO2 tax similar to Superfund.
Consider involving financial institutions on long-term liability issues, as they will
ultimately determine what we will need to do.
Consider assigning leakage responsibility based on volumes injected. We need a series
of post-injection standards that, if met, reduce liability over time, ultimately removing
liability (e.g., tendency for plume to move as expected, dissolution of C02).
Consider linking liability to a multi-track process. For example, track 1 (to remove
liability) if early monitoring indicates acceptable results; track 2 (rigorous closure
requirements at the end of the project) if not.
Comments and Observations: Financial Responsibility
Financial responsibility demonstrations should be sufficient to ensure the availability of
funds to pay for plugging and securing the wells. Most injection sites will be operated by
viable corporations that are financially responsible.
The financial responsibility requirements should be no more rigorous than those for Class
I wells.
Review RCRA financial responsibility mechanisms.
Other Issues
What are EPA's roles related to health and safety, climate, economic credits?
What other environmental impacts and requirements are involved?
What should the requirements be for sequestration in coal seams?
Is/should CC^be classified as a waste?
Remediation will not be feasible in most cases; it is essential to address health and safety
issues and this is a consideration for credits and accounting.
How does the permitting process incorporate public engagement? What are the best
methods for public outreach? Public perception is important.
Consider surface and mineral rights identification. Also consider inverse correlative
rights, i.e., issues associated with use of another owner's pore space.
Consider permit renewals (e.g., 10 or 15 years) to ensure the project is on track.
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Participants
Phyl Amadi; Salt River Project
Mary Ambrose; Texas Commission on Environmental Quality
Scott Anderson; Environmental Defense
Ken Anthony; BP America Inc.
Stefan Bachu; Alberta Energy & Utilities Board
Lisa Botnen; Energy & Environmental Research Center
Raymond Braitsch; US Department of Energy
Grant Bromhal; NETL
Bill Bryson; Kansas Geological Survey
Jim Bundy; Subsurface Technology, Inc.
Candace C. Cady, P.G.; Utah Department of Environmental Quality
Michael Celia; Princeton University
Michael H. Cochran; Kansas Department of Health and Environment
Ann M. Codrington; USEPA
Alison Cooke; BP Alaska, Inc.
Mary Jane Coombs; West Coast Regional Carbon Sequestration Partnership
Jamie L. Crawford; Mississippi Department of Environmental Quality
Steven Crookshank; American Petroleum Institute
Linda Curran; BP/CCP2
Casie Davidson; Pacific Northwest National Laboratory
Ken E. Davis; Subsurface Technology, Inc.
Kirk Delaune; Sandia Technologies
Len R. Erikson; GWPC
Sarah Forbes; Potomac-Hudson Engineering
Mike Frazier; USEPA - Region 6
Kevin Frederick, P.G.; Wyoming Department of Environmental Quality
Theodore Fritz; USEPA - Region 7
Harlan Gerrish; USEPA - Region 5
Brian Graves; USEPA Region 6
Sallie Greenberg; IL State Geological Survey
Ben Grunewald; GWPC
Bill Guilliam; NETL
Neeraj Gupta; Battelle Memorial Institute
Jacqueline Hardee; Texas Commission on Environmental Quality
Sherri Henderson; GWPC
Dave Hogle; USEPA - Region 8
Susan Hovorka; University of Texas, BEG
Scott Imbus; Chevron
Paul Jehn; GWPC
Nigel Jenvey; Shell Exploration & Production Company
Anhar Karimjee; USEPA
Scott Kell; Ohio DNR
Sue Kelly; USEPA Headquarters
Bruce Kobelski; USEPA - Washington DC
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Jonathan Koplos; The Cadmus Group
Ivan Krapac; Illinois State Geological Survey
Feng Liang; Shell International Exploration & Production Company
John Litynski; DOE/NETL
Jeffrey Logan; WRI
William Mann; USEPA - Region 4
Jeffrey McDonald; USEPA - Region 5
Travis McLing; University of Idaho
Tip Meckel; Texas BEG
Dave Mercer; Schlumberger Water Services
Gregory S. Monson; Shell
Angela Moorman; Birch Becker & Moorman, LLC
Michael P. Nickolaus; GWPC
William O'Dowd; US Department Of Energy
Curtis Oldenburg; Lawrence Berkeley National Laboratory
Scott Painter; Southwest Research Institute
Mike Paque; GWPC
Leslie Patterson; USEPA - Region 5
George Peridas; NRDC
Stephen Piatt; USEPA - Region 3
David J. Rectenwald; USEPA
Shari Ring; The Cadmus Group
George Robin; USEPA - Region 9
Ted Rockwell; USEPA - Region 10
Allan Sattler; Sandia National Lab
Elizabeth Scheehle; USEPA - Washington D.C
Rainer Senger; INTERA, Inc.
Chi Ho Sham; The Cadmus Group
Francis Sherrill; Schlumberger Western Geco
Wen Sherrill; Schlumberger Data Consulting Service
James O. Sparks; Mississippi Department of Environmental Quality
Donald Stehle; Sandia Technologies
Laura Stuart; Arkansas Department of Environmental Quality
Thomas Tomastik; Ohio Department of Natural Resources
Robert F. Van Voorhees; Bryan Cave LLP
John A. Veil; Argonne National Laboratory
Sarah M. Wade; AJW Group
James D. Walker; USEPA - Region 9
Lee Whitehurst; USEPA - Washington DC
Dan Yates; GWPC
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