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Regulatory Uncertainty and its Effects on Monitoring Activities of a Major Demonstration Project: The Illinois Basin – Decatur Project Case
Available online at www.sciencedirect.com
ScienceDirect Energy Procedia 114 (2017) 5570 – 5579
13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Regulatory uncertainty and its effects on monitoring activities of a major demonstration project: The Illinois Basin – Decatur Project case R.A. Locke IIa *, S.E. Greenberga, P. Jaguckib, I.G. Krapaca, H. Shaoa a
Illinois State Geological Survey, 615 E. Peabody Dr., Champaign IL, 61820 USA b Hekla Environmental, Westerville, OH 43081 USA
Abstract Regulatory uncertainty is a component of carbon storage projects that can significantly affect project resources and timelines. The Illinois Basin – Decatur Project (IBDP) is a one-million tonne, deep-saline CO2 storage project led by the Midwest Geologic Sequestration Consortium (MGSC) that was initiated before the United States carbon storage regulatory framework was fully developed. To address uncertainty in the evolving regulatory environment, a comprehensive, risk-based, monitoring strategy was used that was expected to be over and above the anticipated new regulatory requirements. Ten years after its initiation, the IBDP has successfully completed the pre-injection and injection phases and is currently in the post-injection site care and monitoring phase. The IBDP experienced two lengthy permitting processes that proved to be the rate-limiting factor for the project, increased the length of time before the project could begin injection, and required additional resources to conduct the project. Future projects are likely to continue to have significant amounts of regulatory uncertainty as their respective project designs and monitoring programs will need to be evaluated by regulators on a case-by-case basis. Operators and regulators alike can benefit from frequent proactive communications during the permitting process in order to significantly reduce the length of the permitting process, maintain the critical safeguards of the Class VI rules, and ultimately meet timely goals for reductions to atmospheric CO2 emissions. ©2017 2017The TheAuthors. Authors. Published Elsevier © Published by by Elsevier Ltd.Ltd. This is an open access article under the CC BY-NC-ND license Peer-review under responsibility of the organizing committee of GHGT-13. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2 storage, regulatory, uncertainty, monitoring, permitting, Illinois Basin – Decatur Project
* Corresponding author. Tel.: +1-217-333-3866; fax: +1-217-333-2830. E-mail address: [email protected]
1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1697
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1. Introduction Mitigation of climate change requires immediate actions to reduce anthropogenic CO2 emissions to minimize or avoid future negative impacts. Storing CO2 in subsurface geologic formations has been identified as a viable mitigation strategy and has led to numerous projects around the world [1]. The Illinois Basin – Decatur Project (IBDP), located in Decatur, Illinois USA, is one such project designed to test the safety and effectiveness of carbon storage. The IBDP is a one-million tonne, deep-saline CO2 storage project led by the Midwest Geologic Sequestration Consortium (MGSC), one of the seven United States Department of Energy – National Energy Technology Laboratory’s Regional Carbon Sequestration Partnerships. The IBDP is a fully integrated demonstration project in the central United States in the largest-capacity saline reservoir of the Illinois Basin. An overview of this project was provided by Finley [2]. At the beginning of the project in 2005, the carbon storage regulatory framework in the United States was not established and regulatory requirements of the project were guided by the existing Underground Injection Control (UIC) program framework. In order to identify, assess, prioritize, mitigate, and actively manage project risk, IBDP employed and has maintained a comprehensive risk management framework, including a risk-based monitoring strategy [3, 4]. Throughout the project, a range of monitoring, verification, and accounting (MVA) tools have been used by the project to monitor the atmosphere, near surface, and deep subsurface [5, 6, 7, 8, 9, 10]. 2. Sources of Regulatory Uncertainty There are a range of potential sources of uncertainty for carbon storage projects [11, 12, 13, 14]. Regulatory uncertainties can be considered in general and project-specific contexts and are especially important because they can have significant impacts to project resources and outcomes. General regulatory uncertainty includes factors where the project has no control or input (e.g., change in government leadership, change in regulatory framework or implementation). Project-specific regulatory uncertainty includes factors where the project has some level of control or input that can affect its impact to the project. In the United States carbon storage regulatory environment, projectspecific regulatory uncertainty is mainly related to the UIC Class VI permitting process. The cost to a project for addressing regulatory uncertainty can range from actions with no cost implications to those that may present significant costs and in some cases may even jeopardize the viability of a project. During the IBDP permitting experience, project-specific regulatory uncertainty had (and will continue) to have very direct impact to project resources (e.g., additional cost or resources needed to address a regulatory-related risk). Specific examples include: an extended permitting timeline, recompletion of monitoring wells, the level of effort needed to develop and conduct Class VI project plans, the ability to conduct testing and monitoring to track the extent of the CO2 plume and pressure front, responding to regulator requests for additional information during the permit application review, financial assurance obligations, and final permit conditions such as, long-term monitoring and testing obligations, length of post-injection site care (PISC) period monitoring, and closure criteria related to nonendangerment. The most critical areas of project-specific regulatory uncertainty are described below in the context of the IBDP permitting experience and monitoring strategy. 3. The IBDP Permitting Experience In the United States, underground injection wells are regulated as part of the Safe Drinking Water Act (SDWA) [15], which includes protection of underground sources of drinking water (USDWs). Until 2010, five classes of underground injection control (UIC) wells were regulated by the United States Environmental Protection Agency (US EPA) or by individual states that had regulatory primacy [16]. At that time, the State of Illinois held primacy for all five classes, Class I through Class V. In January 2008, the IBDP submitted a UIC Class I injection permit application to the Illinois Environmental Protection Agency (IEPA). In January 2009, the IBDP site operator, Archer Daniels Midland Company (ADM), received a draft Class I - Non-hazardous UIC permit issued by the IEPA. The draft permit did not include approval for the planned injection, but did include authorization for the project to drill the injection well (CCS1). It was also a
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crucial step in validating that the project was on track to meet the existing regulatory requirements and ultimately seeking a final permit for authorization to inject. Between 2009 and 2011, additional site characterization was performed, site infrastructure was constructed and baseline monitoring networks were established. A condition of the Class I permit was that the project was required to apply for a Class VI well permit from the federal regulatory authority under the new regulatory framework when it was finalized. The greatest areas of regulatory uncertainty encountered during the pre-injection and injection phases of the IBDP were determining the scope of planning, documentation, and monitoring that would eventually be required for the Class VI permit. In order to address some of the uncertainty during the review of the Class VI permit, the IBDP maintained a comprehensive, risk-based, monitoring strategy that was expected to be over and above the anticipated regulatory requirements. That required additional project resources, but was necessary to reduce overall project risk by providing greater project flexibility to fully meet the conditions of the Class VI permit when they were finalized. The condition of being held to a future requirement which had not been defined did significantly impact project budgets, staff assignments, site development, monitoring costs, and overall project schedule. Coincident with the IBDP Class I permitting process, the US EPA promulgated final regulations in December 2010 for a new class of injection well (Class VI) specific to the injection of CO2 into the subsurface. The rules were effective in September 2011 and were published in the Code of Federal Regulations (CFR) in 40 CFR 146 Subpart H [17]. In October 2011, the final UIC Class I permit was issued to the site operator and authorization to inject one million tonnes of CO2 was received. The conversion of the IBDP Class I permit was not automatic and the IBDP was required to go through the full Class VI application process. Under the Class VI rules [17] and guidance [18], no area permits are allowed for storage projects. A separate application is required for each planned injection well. However, if multiple permits are needed, all information gathered for the permit application may be leveraged and used as efficiently as possible, minimizing differences between each separate application, assuming each of the injection wells is in a similar geologic setting. The IBDP required only one permit application for its injection well, CCS1. New Class VI permit applications are required to include six key components: 1. General administrative project and contact information. 2. Site Characterization Data – including data on both the injection and confining zones and information on all USDWs in the area. 3. A map showing the planned injection well location and the preliminary Area of Review (AoR). 4. A tabulation of all wells in the AoR which penetrated the confining formations and/or the injection reservoir. 5. Project plans that eventually become part of the permit to drill and operate the well. Plans include: (1) AoR and Corrective Action Plan, (2) Testing and Monitoring Plan, (3) Injection Well Plugging Plan, (4) PostInjection Site Care and Site Closure Plan, and (5) Emergency and Remedial Response Plan. 6. Provision for financial responsibility. The IBDP Class VI permit application was submitted in December 2011. The IBDP was already injecting CO2 under the Class I permit and continued to inject while its Class VI permit was being reviewed. After submission, requests for additional information were received and addressed by the project team during 2012 and 2013. Typically, a Class VI permit would be issued in stages. The first stage provides the operator the authority to drill and test the injection well in accordance with the permit. Once the well is drilled and tested, a completion report with final well specifications and test data would be submitted to the regulatory agency for review. Authorization to inject CO2 would only be approved as part of the final stage after a review of the completion report, adjustments to project and monitoring program design based on the new information gained during drilling of the injection well, and responses by the applicant to any additional requests by the US EPA.
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For IBDP, the final Class VI permit was issued in 2014 as the injection phase of the project was nearing completion and went into effect in February 2015. The Class I permit was subsequently terminated. During the 3-year injection period (November 2011 through November 2014), the IBDP operated under the Class I permit and successfully injected over 999,000 tonnes of CO2 into the lower Mt. Simon Sandstone with no indications of CO2 leakage from the intended storage reservoir. Because of the timing of its issuance, the final IBDP Class VI permit mainly addressed the PISC activity and plugging of well CCS1. It also aligned IBDP PISC monitoring activities with the adjacent Illinois Industrial CCS (ILICCS) project and its injection well (CCS2) that is scheduled to begin operation in 2017 with up to 5 million tonnes injected over 5 years. These projects hold the first-ever United States UIC Program final permits for Class VI wells. Both permits were issued with ADM as the permit holder and monitoring programs for both projects were coordinated as a result of the US EPA permit review process. A timeline of key permitting milestones is shown in Table 1. Table 1. Timeline and milestones for the Illinois Basin - Decatur Project related to major Class I and Class VI permitting activities. Year 2008
2009
Month
Milestone
January
Class I Non-hazardous permit submitted to IEPA
May, June, August, December
Revisions to Class I permit application
October
Public comment period for permit application
December
Draft Class I permit issued (included authority for well construction)
January
Draft Class I permit becomes effective
October
Permit modifications to Class I permit
2010
December
Class VI regulations finalized by US EPA
2011
September
Illinois does not apply for primacy of UIC Class VI US EPA Region 5 is the IBDP Class VI regulating authority
October
Final Class I permit issued for CO2 injection
November
CCS1 CO2 injection begins
December
IBDP Class VI permit application submitted to US EPA Requests for additional information by US EPA
2012–2013 2014
2015
September
Public comment period for Class VI application
November
CCS1 CO2 injection completed Public hearing for Class VI application
December
Final Class VI permit issued
April
Public comment period to terminate Class I permit
February
Final Class VI permit becomes effective
July
Class I permit is terminated
From the date of submission, the Class I permitting process took approximately one year for a draft permit to be issued and more than 3.5 years for a final permit to be issued. While some benefit to the extended permitting time was realized due to additional time for project planning and baseline data gathering, the lengthy permitting process added very significant delays to project activities and the ultimate goal of conducting the demonstration project. Similarly the IBDP Class VI permitting process took over four years from submission to final effective permit. Because IBDP and the adjacent IL-ICCS project permits were the first two final permits of their kind, some of the length of the permitting process can be attributed to the evolving regulatory framework. However, it is not anticipated that many future projects would have an interest or incentive to bear that lengthy process. For future projects in the United States to have the greatest opportunity to make significant impacts to reduction of atmospheric CO2 concentrations on a timescale needed to meet recently stated goals (i.e., 2 degree Celsius scenarios), times for permit review and issuance
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will need to be significantly reduced. It should be noted that the Class VI guidance documents allow for a staged permit (e.g., conditional permit issued and then completion of site characterization, permit revision, agency review and approval). The guidance further allows for multiple iterations contingent on each round of review and at various stages throughout the project life. This presents significant ongoing uncertainties and risks to project budgets and schedules. 4. The IBDP Monitoring Approach From a commercial perspective, monitoring programs in geological storage projects need to inevitably be focused on the project components perceived to have the highest risk. Thus, risk management is an effective basis for the development of monitoring program [19]. Throughout a storage project life cycle, the project risk profile will change, and thus a risk-based monitoring strategy should also be expected to change [3, 19, 20]. Fig. 1 from the UIC Program Class VI Well Testing and Monitoring Guidance document shows the relationships of required monitoring program activities to potential project risk and different project phases [21]. Before implementation of the MVA program at the IBDP, a risk assessment was conducted in February 2008 using project participants as well as other experts involved in CCS projects in the US and Canada [3, 22]. The assessment evaluated risks associated with safety, research objectives, public acceptance, and successfully storing the injected CO2. Risks were characterized by likelihood and severity of negative impact. An extensive MVA program was then designed with the types of monitoring, locations, frequencies, and durations of monitoring influenced by the project risk assessment and overall risk management framework. The MVA program was intended to mitigate risks with unacceptable project outcomes, and was periodically reviewed by the project management team to reduce all unacceptable levels of risk. Other overarching goals of the MVA program are/were (1) to establish pre-injection conditions to evaluate potential impacts from CO2 injection, (2) to demonstrate that project activities are protective of human health and the environment [in part by ensuring that all regulatory conditions are met], and (3) to quantify and track CO2 stored in the Mt. Simon Sandstone reservoir. Site monitoring activities were tailored based on site-specific subsurface data collected during the pre-injection phase of the project. Research and compliance monitoring was initiated in 2009 by the establishment of multiple monitoring networks (e.g., groundwater, soil flux, soil gas) and collected up to 24 months of pre-injection data. By 2011, all primary monitoring networks and methods had been established. The IBDP site has also been used as a test site for development and validation of emerging monitoring technologies. A summary of the timing and range of monitoring techniques used at the IBDP site are shown in Table. 2. Data availability and existing site information differs significantly for greensites and brownsites as described by Wolaver et al. [23]. Greensites may be more costly to characterize because of the initial lack of data and they may also have greater initial uncertainty about whether the site has suitable characteristics for CO2 storage (e.g., desired reservoir and seal quality). This is an area where IBDP was able to leverage limited regional information from previous geological investigations (e.g., local borehole data, 2D seismic data) before field activities for site characterization were conducted. It should be noted by project operators that the acquisition of new site data can have significant impacts on project and monitoring plans, especially with respect to the AoR. The AoR defines the anticipated maximum extent of the project impact either by plume extent or pressure increases (and thus the most relevant areas to be considered for a carbon storage monitoring program). Therefore, acquisition of new information with the potential to affect the AoR should be carefully planned and integrated into project and permitting workflows.
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Fig. 1. Generalized testing and monitoring activities during the life cycle of a storage project (from EPA [22]).
With injection completed and the IBDP Class VI permit finalized in 2014, the project has been able to focus on moving from a comprehensive research and compliance mode to a significantly more targeted monitoring mode that has been tailored to address the Class VI requirements. Under the Class VI permit, a significant number of changes occurred to the IBDP monitoring program. For example, groundwater monitoring under the Class I permit was focused on 11 sentinel parameters that were primarily selected for their sensitivity to detect fluid quality changes resulting from interactions with CO2 or brine. Those parameters were pH, temperature, specific conductance, dissolved oxygen, dissolved CO2 as total inorganic carbon, alkalinity, bromide, chloride, calcium, sodium, and groundwater elevation at four sampling locations in Pennsylvanian-age bedrock, which was considered the lower most USDW under the Class I permit. The Class VI permit added groundwater sampling locations from three deeper depths (St. Peter Sandstone, Ironton-Galesville Formation and Mt. Simon Sandstone) and retained the four sampling locations in Pennsylvanianage bedrock. The permit also increased the number of water quality parameters to be monitored from 11 to 30 that included additional major and minor elements and isotopes. Regulatory changes to other monitoring methods and frequencies (e.g., well logging, seismic surveys, microseismic monitoring) also occurred but are not described in this paper. Since 2015, a major decrease in research monitoring intensity has occurred. For example, shallow groundwater sampling was reduced from monthly monitoring of 17 shallow wells to quarterly monitoring of 4 shallow wells, and weekly soil flux monitoring was reduced to monthly in 2015 and then terminated at the end of the 2015 field season.
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Freq.
Pre-injection
Subsurface
Near-Surface
Surface
2008 2009
Injection
Post-Injection
2010
2011
2012
2013
2014
2015
2016
2017
2018
x
x
p
p
Aerial imagery
SA
x
x
x
x
x
x
Eddy covariance
C
x
x
x
x
x
x
Soil flux - network
W-Q
x
x
x
x
x
x
x
Soil flux - multiplexer
C
x
x
x
x
x
x
Tunable diode laser- single path
C
x
x
Tunable diode laser- multi path
C
InSAR
BW
Continuous GPS
C
Soil gas sampling
Q-A
Shallow groundwater sampling 1,2
M-Q
Shallow electrical earth resistivity
A
Pressure/temp. - VW1 and CCS1 1,2
C
Pulsed neutron (CCS1, VW1, GM1) 1,2
Q-A
Deep fluid sampling (VW1) 2
SA
Passive seismic monitoring (GM1) 2
C
Seismic/3D VSP imaging 1,2 Mechanical integrity (CCS1, VW1) 1,2
x x
x x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
p
p
x
x
x
x
x
x
p
p
x
x
x
x
x
TBD
TBD
x
x
x
x
x
p
p
x
x
x
x
x
x
p
p
SA-A
x
x
x
x
x
x
A
x
x
x
x
x
x
x
x
x
x
x
x
x
The conditions of the IBDP Class VI final permit required additional fluid sampling from the deeper sampling formations resulting in the need for more infrastructure, preparation of each well prior to sampling, and greater logistical difficulties of sampling at depths from 900 to 2,100 m (3,000 to 7,000 ft) These efforts were significantly greater than the required shallow (43 m; 140 ft) fluid sampling for the IBDP Class I permit and resulted in additional personnel time and equipment costs to the IBDP. An example of cost increases resulting from the Class VI permit is illustrated in Table 3 when just the cost to analyze fluid samples is considered. An approximate fourfold increase in compliance-related analytical costs were realized by the IBDP when site monitoring was aligned with the final Class VI rules when considering the original IBDP project wells (4 shallow and VW1). An approximate fivefold increase occurred when also considering wells associated with the IL-ICCS project (VW2 and GM2). These costs were associated with the increase in permit compliance sampling locations (increased number of samples) and the increase
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in water quality parameters to be measured. The project was already conducting additional non-permit related monitoring to develop a comprehensive set of environmental data. Many of the previously research-related parameters were added to the Class VI regulatory monitoring program which increased the resources needed to address mandatory monitoring components. Because the scope (injection mass, length of project, geographic extent) of the IBDP demonstration is significantly smaller than a full-scale commercial project (e.g., injection of > 50 million tonnes over decades), the increase in regulatory monitoring requirements were significant, but not unbearable. The biggest monitoring adaptations implemented by the IBDP were related to downscaling the number of research-related monitoring types, locations, parameters, and frequencies as the project was in its PISC period. It is suggested that for future large-scale storage projects, the use of risk-based, adaptive monitoring programs will be needed to optimize monitoring costs throughout a project life cycle. In those circumstances, it may also be appropriate to identify components of monitoring programs that are unnecessarily comprehensive (e.g., fluid chemistry analyses) in favor of less numerous, but yet fully effective sentinel parameters or techniques (e.g., downhole water quality sensors) after sufficient baseline data have been acquired. Table 3. Example of differences in Class I vs. Class VI groundwater monitoring analytical costs (in $USD). N/A = not applicable.
Well (Formation)
Sample Frequency
Number of Sampling Locations
Number of Samples (includes QC)
Cost /sample ($)
Cost /year ($)
Class I
Class VI
Class I
Class VI
Class I
Class VI
Class I
Class VI
Class I
Quarterly
Quarterly
4
4
24
24
110
310
2,640
7,440
VW1 (Ironton-Galesville)
Not required
Annual
0
1
0
3
N/A
420
N/A
1,260
VW1 (Mt. Simon)
Not required
Annual
0
1
0
3
N/A
420
N/A
1,260
VW2 (Mt. Simon)
N/A
Annual
N/A
3
N/A
5
N/A
420
N/A
2,100
GM2 (St. Peter)
N/A
Annual
N/A
1
N/A
3
N/A
420
N/A
1,260
Total Cost
2,640
13,320
Shallow (Pennsylvanian)
Class VI
5. Future Project-Specific Regulatory Uncertainty Monitoring results (e.g., observed reservoir pressures in comparison with modeled pressures, assessments of repeat pulsed neutron well logging results) and project data assessments indicate that the IBDP CO2 plume has spread within a thin, high permeability zone in the lowermost Mt. Simon Sandstone and that a low permeability zone in the upper part of the lower Mt. Simon Sandstone is acting as an effective baffle to limit CO2 migration and pressure transmission above 2,094 m (6,870 ft) [4]. The most significant remaining sources of regulatory uncertainty for the IBDP are related to monitoring program requirements during the PISC period. They include the length of PISC period monitoring and the process by which a non-endangerment determination will be sought from the US EPA for the project to proceed to closure. After CO2 injection ceases the permittee is required to continue to conduct monitoring specified in the PISC for at least 50 years or for the duration of the alternative timeframe approved by the Director (40 CFR 146.93[b][2] or [3]). The demonstration of an alternative timeframe for non-endangerment of a USDW to the UIC program director must include: (1) summary of existing monitoring and laboratory data, (2) comparison of monitoring data and model predications and model documentation in relation to (a) pressure decline within the injection zone and any other zones such that formation fluids cannot be forced into USDWs or the timeframe for pressure decline to reach pre-injection
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pressures, (b) predicted rate of plume migration within injection zone and timeframe for cessation of migration, (3) site-specific processes resulting in CO2 trapping and predicted rate of trapping, (4) characterization of confining zones to ensure their integrity to impede fluid (CO2 and formation fluids) movement, (5) evaluation for potential conduits for fluid movement, (6) analysis to identify and assess aspects of the alternative PISC that contribute to significant uncertainty. Based on those criteria, an adjusted PISC of 10 years was requested by the permittee and granted. The adjusted PISC timeframe is linked to the completion of IL-ICCS injection and would not likely begin before 2022. Even with the approved alternative timeframe, monitoring must continue until the geologic sequestration project no longer poses an endangerment to USDWs. The approval of an alternative timeframe is based on monitoring and other site-specific data in conjunction with numerical modeling. Because of the importance of modeling in all phases of the project (e.g., pre-injection AoR estimations, estimates of plume migration and formation pressure responses, PISC plume stabilization estimates and CO2 trapping mechanisms), it is essential for projects to document numerical model metadata, keep comprehensive records of model input and output, maintain model operability, and maintain continuity in modeling knowledge throughout a project. It is anticipated that the IL-ICCS project (and by association, the IBDP) will demonstrate non-endangerment using the same basis under which the 10-year PISC period was requested, and US EPA approval of the non-endangerment documentation will be required before the projects can enter the closure phase. 6. Summary and Recommendations The IBDP experienced two lengthy permitting processes that proved to be the rate-limiting factor for the project, increased the length of time before the project could begin injection, and required additional resources to conduct the project. The permitting process involved multiple key stakeholders: project developer, site owner, content experts, and regulators at the State and Federal level. As new regulatory frameworks are being developed and tested, there is critical need for capacity building, communication, and explicit understanding of the permitting process. The negotiation of terms, permit conditions, modelling of the AoR, PISC expectation from early permits, such as from the IBDP and IL-ICCS projects, can have significant impact and set precedence for future projects. Operators and regulators alike can benefit from frequent proactive communications during the permitting process in order to significantly reduce the length of the permitting process, maintain the critical safeguards of the Class VI rules, and ultimately meet timely goals for reductions to atmospheric CO2 emissions. Timing and intensity of monitoring programs at different project stages should be carefully planned. The IBDP purposely maintained a comprehensive monitoring strategy throughout the pre-injection and injection phases of the project in anticipation of the Class VI rule finalization and the issuance of final permit conditions for the IBDP. After the project completed injection and the Class VI permit went into effect for the PISC, the IBDP research-related monitoring intensity was greatly reduced. The Class VI regulations provide flexibility for storage operators to design a site specific testing and surveillance program. Long-term MVA programs should remain aware of and test new technologies that can improve monitoring efficiencies and effectiveness to reduce overall monitoring costs. Further, to minimize the need for additional permit modifications related to risk-based monitoring program adjustments, it is recommended that future Class VI applicants consider including an iterative and adaptive monitoring strategy in their initial permit application for the purpose of optimizing monitoring activities throughout the life of the project. Acknowledgements The Midwest Geological Sequestration Consortium (MGSC) is funded by the U.S. Department of Energy through the National Energy Technology Laboratory (NETL) via the Regional Carbon Sequestration Partnership Program (contract number DE-FC26-05NT42588) and by a cost share agreement with the Illinois Department of Commerce and Economic Opportunity, Office of Coal Development through the Illinois Clean Coal Institute.
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References [1] Intergovernmental Panel on Climate Change (Core writing team, Pachauri RK, Reisinger A, editors). Contribution of working groups I, II and III to the fourth assessment report of the Intergovernmental Panel on Climate Change. Geneva, Switzerland; 2007. [2] Finley RJ. An overview of the Illinois Basin-Decatur Project. Greenhouse Gases Sci and Technol 2014; 4, 5: 571–579. [3] Hnottavange-Telleen K. Risk management at the Illinois Basin – Decatur Project: A FEPs-based approach. Greenhouse Gases Sci Technol 2014; 4, 5: 604–616. [4] Couëslan ML, Smith V, El-Kaseeh G, Gilbert J, Preece N, Zhang L, Gulati J. Development and implementation of a seismic characterization and CO2 monitoring program for the Illinois Basin – Decatur Project. Greenhouse Gas Sci. Technol 204; 4, 5: 626–644. [5] Couëslan ML, Butsch R, Will R., Locke RA. 2014. Integrated reservoir monitoring at the Illinois Basin – Decatur Project. Energy Proc 2014; 63: 2836–2847. [6] Carman CH, Locke II RA, Blakley CS. Update on soil CO2 flux monitoring at the Illinois Basin – Decatur Project, USA. Energy Proc 2014; 63: 3869–3880. [7] Frailey SM, Damico J, Leetaru HE. Reservoir characterization of the Mt. Simon Sandstone, Illinois Basin, USA. Energy Proc 2011; 4: 5487– 5494. [8] Korose CP, Locke II RA, Blakley CS, Carman CH. Integration of near-surface monitoring information using ArcGIS at the Illinois Basin – Decatur Project, USA. Energy Proc 2014; 63: 3945–3955. [9] Locke RA, Krapac I G, Lewicki JL, Curtis-Robinson E. Characterizing near-surface CO2 conditions before injection–Perspectives from a CCS project in the Illinois Basin, USA. Energy Proc 2011; 4: 3306–3313. [10] Locke R, Larssen D, Salden W, Patterson C, Kirksey J, Iranmanesh A, Wimmer B, Krapac I. Preinjection reservoir fluid characterization at a CCS demonstration Site: Illinois Basin – Decatur Project, USA. Energy Proc 2013; 37: 6424–6433. [11] Whittaker S, Kneppers A. Lessons in the development of large-scale CO2 storage projects. Energy Proc 2013; 37: 3646–3654. [12] Senior B, Bradshaw J, Chikkatur A, Wright M. Planning saline reservoir storage developments—the importance of getting started early. Energy Proc 2011; 4: 4575–4582. [13] Markusson N, Kern F, Watson J, Arapostathis S, Chalmers H, Ghaleigh N, Heptonstall P, Pearson P, Rossati D, Russell S. A socio-technical framework for assessing the viability of carbon capture and storage technology. Technol Forecasting Social Change 2012; 79, 5: 903–918. [14] Bouquet S, Bruel D, de Fouquet C. Large-scale storage in a deep saline aquifer: Uncertainties in predictions due to spatial variability of flow parameters and their modeling. Transp Porous Media 2016; 111, 1: 215–238. [15] United States Code of Federal Regulations. Title 42, Chapter 6A, Subchapter XII. https://www.gpo.gov/fdsys/pkg/USCODE-2010-title42/pdf/USCODE-2010-title42-chap6A-subchapXII.pdf. Accessed August 2016. [16] United States Underground Injection Control Program Website. https://www.epa.gov/uic [17] United States Code of Federal Regulations. Part 146, Subpart H. https://www.gpo.gov/fdsys/pkg/FR-2010-12-10/pdf/2010-29954.pdf#page=63. Accessed August 2016. [18] United States Environmental Protection Agency. Class VI well guidance website. https://www.epa.gov/uic/final-class-vi-guidance-documents. Accessed August 2016. [19] Harbert W, Daley TM, Bromhal G, Sullivan C, Huang L. Progress in monitoring strategies for risk reduction in geologic CO2 storage. Int J Greenhouse Gas Control 2016; 51: 260–275. [20] Pawar RJ, Bromhal GS, Carey JW, Foxall W, Korre A, Ringrose PS, Tucker O, Watson MN, White JA. Recent advances in risk assessment and risk management of geologic CO2 storage. Int J Greenhouse Gas Control 2015; 40: 292–311. [21] US Enviromental Proection Agency, 2013. Underground injection control (UIC) program Class VI well testing and monitoring guidance. Office of Water (4606M), EPA 816-R-13-001, http://www.epa.gov/safewater. Accessed August 2016. [22] Hnottavange-Telleen K, Krapac I, Vivalda C. Illinois Basin-Decatur Project: Initial risk assessment results and framework for evaluating site performance. Energy Proc 2009; 1: 2431–2438. [23] Wolaver BD, Hovorka SD, Smyth RC. Greensites and brownsites: Implications for CO2 sequestration characterization risk assessment and monitoring. Int J Greenhouse Gas Control 2013; 19: 49–62.
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13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, 14-18 November 2016, Lausanne, Switzerland
Regulatory uncertainty and its effects on monitoring activities of a major demonstration project: The Illinois Basin – Decatur Project case R.A. Locke IIa *, S.E. Greenberga, P. Jaguckib, I.G. Krapaca, H. Shaoa a
Illinois State Geological Survey, 615 E. Peabody Dr., Champaign IL, 61820 USA b Hekla Environmental, Westerville, OH 43081 USA
Abstract Regulatory uncertainty is a component of carbon storage projects that can significantly affect project resources and timelines. The Illinois Basin – Decatur Project (IBDP) is a one-million tonne, deep-saline CO2 storage project led by the Midwest Geologic Sequestration Consortium (MGSC) that was initiated before the United States carbon storage regulatory framework was fully developed. To address uncertainty in the evolving regulatory environment, a comprehensive, risk-based, monitoring strategy was used that was expected to be over and above the anticipated new regulatory requirements. Ten years after its initiation, the IBDP has successfully completed the pre-injection and injection phases and is currently in the post-injection site care and monitoring phase. The IBDP experienced two lengthy permitting processes that proved to be the rate-limiting factor for the project, increased the length of time before the project could begin injection, and required additional resources to conduct the project. Future projects are likely to continue to have significant amounts of regulatory uncertainty as their respective project designs and monitoring programs will need to be evaluated by regulators on a case-by-case basis. Operators and regulators alike can benefit from frequent proactive communications during the permitting process in order to significantly reduce the length of the permitting process, maintain the critical safeguards of the Class VI rules, and ultimately meet timely goals for reductions to atmospheric CO2 emissions. ©2017 2017The TheAuthors. Authors. Published Elsevier © Published by by Elsevier Ltd.Ltd. This is an open access article under the CC BY-NC-ND license Peer-review under responsibility of the organizing committee of GHGT-13. (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. Keywords: CO2 storage, regulatory, uncertainty, monitoring, permitting, Illinois Basin – Decatur Project
* Corresponding author. Tel.: +1-217-333-3866; fax: +1-217-333-2830. E-mail address: [email protected]
1876-6102 © 2017 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). Peer-review under responsibility of the organizing committee of GHGT-13. doi:10.1016/j.egypro.2017.03.1697
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1. Introduction Mitigation of climate change requires immediate actions to reduce anthropogenic CO2 emissions to minimize or avoid future negative impacts. Storing CO2 in subsurface geologic formations has been identified as a viable mitigation strategy and has led to numerous projects around the world [1]. The Illinois Basin – Decatur Project (IBDP), located in Decatur, Illinois USA, is one such project designed to test the safety and effectiveness of carbon storage. The IBDP is a one-million tonne, deep-saline CO2 storage project led by the Midwest Geologic Sequestration Consortium (MGSC), one of the seven United States Department of Energy – National Energy Technology Laboratory’s Regional Carbon Sequestration Partnerships. The IBDP is a fully integrated demonstration project in the central United States in the largest-capacity saline reservoir of the Illinois Basin. An overview of this project was provided by Finley [2]. At the beginning of the project in 2005, the carbon storage regulatory framework in the United States was not established and regulatory requirements of the project were guided by the existing Underground Injection Control (UIC) program framework. In order to identify, assess, prioritize, mitigate, and actively manage project risk, IBDP employed and has maintained a comprehensive risk management framework, including a risk-based monitoring strategy [3, 4]. Throughout the project, a range of monitoring, verification, and accounting (MVA) tools have been used by the project to monitor the atmosphere, near surface, and deep subsurface [5, 6, 7, 8, 9, 10]. 2. Sources of Regulatory Uncertainty There are a range of potential sources of uncertainty for carbon storage projects [11, 12, 13, 14]. Regulatory uncertainties can be considered in general and project-specific contexts and are especially important because they can have significant impacts to project resources and outcomes. General regulatory uncertainty includes factors where the project has no control or input (e.g., change in government leadership, change in regulatory framework or implementation). Project-specific regulatory uncertainty includes factors where the project has some level of control or input that can affect its impact to the project. In the United States carbon storage regulatory environment, projectspecific regulatory uncertainty is mainly related to the UIC Class VI permitting process. The cost to a project for addressing regulatory uncertainty can range from actions with no cost implications to those that may present significant costs and in some cases may even jeopardize the viability of a project. During the IBDP permitting experience, project-specific regulatory uncertainty had (and will continue) to have very direct impact to project resources (e.g., additional cost or resources needed to address a regulatory-related risk). Specific examples include: an extended permitting timeline, recompletion of monitoring wells, the level of effort needed to develop and conduct Class VI project plans, the ability to conduct testing and monitoring to track the extent of the CO2 plume and pressure front, responding to regulator requests for additional information during the permit application review, financial assurance obligations, and final permit conditions such as, long-term monitoring and testing obligations, length of post-injection site care (PISC) period monitoring, and closure criteria related to nonendangerment. The most critical areas of project-specific regulatory uncertainty are described below in the context of the IBDP permitting experience and monitoring strategy. 3. The IBDP Permitting Experience In the United States, underground injection wells are regulated as part of the Safe Drinking Water Act (SDWA) [15], which includes protection of underground sources of drinking water (USDWs). Until 2010, five classes of underground injection control (UIC) wells were regulated by the United States Environmental Protection Agency (US EPA) or by individual states that had regulatory primacy [16]. At that time, the State of Illinois held primacy for all five classes, Class I through Class V. In January 2008, the IBDP submitted a UIC Class I injection permit application to the Illinois Environmental Protection Agency (IEPA). In January 2009, the IBDP site operator, Archer Daniels Midland Company (ADM), received a draft Class I - Non-hazardous UIC permit issued by the IEPA. The draft permit did not include approval for the planned injection, but did include authorization for the project to drill the injection well (CCS1). It was also a
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crucial step in validating that the project was on track to meet the existing regulatory requirements and ultimately seeking a final permit for authorization to inject. Between 2009 and 2011, additional site characterization was performed, site infrastructure was constructed and baseline monitoring networks were established. A condition of the Class I permit was that the project was required to apply for a Class VI well permit from the federal regulatory authority under the new regulatory framework when it was finalized. The greatest areas of regulatory uncertainty encountered during the pre-injection and injection phases of the IBDP were determining the scope of planning, documentation, and monitoring that would eventually be required for the Class VI permit. In order to address some of the uncertainty during the review of the Class VI permit, the IBDP maintained a comprehensive, risk-based, monitoring strategy that was expected to be over and above the anticipated regulatory requirements. That required additional project resources, but was necessary to reduce overall project risk by providing greater project flexibility to fully meet the conditions of the Class VI permit when they were finalized. The condition of being held to a future requirement which had not been defined did significantly impact project budgets, staff assignments, site development, monitoring costs, and overall project schedule. Coincident with the IBDP Class I permitting process, the US EPA promulgated final regulations in December 2010 for a new class of injection well (Class VI) specific to the injection of CO2 into the subsurface. The rules were effective in September 2011 and were published in the Code of Federal Regulations (CFR) in 40 CFR 146 Subpart H [17]. In October 2011, the final UIC Class I permit was issued to the site operator and authorization to inject one million tonnes of CO2 was received. The conversion of the IBDP Class I permit was not automatic and the IBDP was required to go through the full Class VI application process. Under the Class VI rules [17] and guidance [18], no area permits are allowed for storage projects. A separate application is required for each planned injection well. However, if multiple permits are needed, all information gathered for the permit application may be leveraged and used as efficiently as possible, minimizing differences between each separate application, assuming each of the injection wells is in a similar geologic setting. The IBDP required only one permit application for its injection well, CCS1. New Class VI permit applications are required to include six key components: 1. General administrative project and contact information. 2. Site Characterization Data – including data on both the injection and confining zones and information on all USDWs in the area. 3. A map showing the planned injection well location and the preliminary Area of Review (AoR). 4. A tabulation of all wells in the AoR which penetrated the confining formations and/or the injection reservoir. 5. Project plans that eventually become part of the permit to drill and operate the well. Plans include: (1) AoR and Corrective Action Plan, (2) Testing and Monitoring Plan, (3) Injection Well Plugging Plan, (4) PostInjection Site Care and Site Closure Plan, and (5) Emergency and Remedial Response Plan. 6. Provision for financial responsibility. The IBDP Class VI permit application was submitted in December 2011. The IBDP was already injecting CO2 under the Class I permit and continued to inject while its Class VI permit was being reviewed. After submission, requests for additional information were received and addressed by the project team during 2012 and 2013. Typically, a Class VI permit would be issued in stages. The first stage provides the operator the authority to drill and test the injection well in accordance with the permit. Once the well is drilled and tested, a completion report with final well specifications and test data would be submitted to the regulatory agency for review. Authorization to inject CO2 would only be approved as part of the final stage after a review of the completion report, adjustments to project and monitoring program design based on the new information gained during drilling of the injection well, and responses by the applicant to any additional requests by the US EPA.
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For IBDP, the final Class VI permit was issued in 2014 as the injection phase of the project was nearing completion and went into effect in February 2015. The Class I permit was subsequently terminated. During the 3-year injection period (November 2011 through November 2014), the IBDP operated under the Class I permit and successfully injected over 999,000 tonnes of CO2 into the lower Mt. Simon Sandstone with no indications of CO2 leakage from the intended storage reservoir. Because of the timing of its issuance, the final IBDP Class VI permit mainly addressed the PISC activity and plugging of well CCS1. It also aligned IBDP PISC monitoring activities with the adjacent Illinois Industrial CCS (ILICCS) project and its injection well (CCS2) that is scheduled to begin operation in 2017 with up to 5 million tonnes injected over 5 years. These projects hold the first-ever United States UIC Program final permits for Class VI wells. Both permits were issued with ADM as the permit holder and monitoring programs for both projects were coordinated as a result of the US EPA permit review process. A timeline of key permitting milestones is shown in Table 1. Table 1. Timeline and milestones for the Illinois Basin - Decatur Project related to major Class I and Class VI permitting activities. Year 2008
2009
Month
Milestone
January
Class I Non-hazardous permit submitted to IEPA
May, June, August, December
Revisions to Class I permit application
October
Public comment period for permit application
December
Draft Class I permit issued (included authority for well construction)
January
Draft Class I permit becomes effective
October
Permit modifications to Class I permit
2010
December
Class VI regulations finalized by US EPA
2011
September
Illinois does not apply for primacy of UIC Class VI US EPA Region 5 is the IBDP Class VI regulating authority
October
Final Class I permit issued for CO2 injection
November
CCS1 CO2 injection begins
December
IBDP Class VI permit application submitted to US EPA Requests for additional information by US EPA
2012–2013 2014
2015
September
Public comment period for Class VI application
November
CCS1 CO2 injection completed Public hearing for Class VI application
December
Final Class VI permit issued
April
Public comment period to terminate Class I permit
February
Final Class VI permit becomes effective
July
Class I permit is terminated
From the date of submission, the Class I permitting process took approximately one year for a draft permit to be issued and more than 3.5 years for a final permit to be issued. While some benefit to the extended permitting time was realized due to additional time for project planning and baseline data gathering, the lengthy permitting process added very significant delays to project activities and the ultimate goal of conducting the demonstration project. Similarly the IBDP Class VI permitting process took over four years from submission to final effective permit. Because IBDP and the adjacent IL-ICCS project permits were the first two final permits of their kind, some of the length of the permitting process can be attributed to the evolving regulatory framework. However, it is not anticipated that many future projects would have an interest or incentive to bear that lengthy process. For future projects in the United States to have the greatest opportunity to make significant impacts to reduction of atmospheric CO2 concentrations on a timescale needed to meet recently stated goals (i.e., 2 degree Celsius scenarios), times for permit review and issuance
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will need to be significantly reduced. It should be noted that the Class VI guidance documents allow for a staged permit (e.g., conditional permit issued and then completion of site characterization, permit revision, agency review and approval). The guidance further allows for multiple iterations contingent on each round of review and at various stages throughout the project life. This presents significant ongoing uncertainties and risks to project budgets and schedules. 4. The IBDP Monitoring Approach From a commercial perspective, monitoring programs in geological storage projects need to inevitably be focused on the project components perceived to have the highest risk. Thus, risk management is an effective basis for the development of monitoring program [19]. Throughout a storage project life cycle, the project risk profile will change, and thus a risk-based monitoring strategy should also be expected to change [3, 19, 20]. Fig. 1 from the UIC Program Class VI Well Testing and Monitoring Guidance document shows the relationships of required monitoring program activities to potential project risk and different project phases [21]. Before implementation of the MVA program at the IBDP, a risk assessment was conducted in February 2008 using project participants as well as other experts involved in CCS projects in the US and Canada [3, 22]. The assessment evaluated risks associated with safety, research objectives, public acceptance, and successfully storing the injected CO2. Risks were characterized by likelihood and severity of negative impact. An extensive MVA program was then designed with the types of monitoring, locations, frequencies, and durations of monitoring influenced by the project risk assessment and overall risk management framework. The MVA program was intended to mitigate risks with unacceptable project outcomes, and was periodically reviewed by the project management team to reduce all unacceptable levels of risk. Other overarching goals of the MVA program are/were (1) to establish pre-injection conditions to evaluate potential impacts from CO2 injection, (2) to demonstrate that project activities are protective of human health and the environment [in part by ensuring that all regulatory conditions are met], and (3) to quantify and track CO2 stored in the Mt. Simon Sandstone reservoir. Site monitoring activities were tailored based on site-specific subsurface data collected during the pre-injection phase of the project. Research and compliance monitoring was initiated in 2009 by the establishment of multiple monitoring networks (e.g., groundwater, soil flux, soil gas) and collected up to 24 months of pre-injection data. By 2011, all primary monitoring networks and methods had been established. The IBDP site has also been used as a test site for development and validation of emerging monitoring technologies. A summary of the timing and range of monitoring techniques used at the IBDP site are shown in Table. 2. Data availability and existing site information differs significantly for greensites and brownsites as described by Wolaver et al. [23]. Greensites may be more costly to characterize because of the initial lack of data and they may also have greater initial uncertainty about whether the site has suitable characteristics for CO2 storage (e.g., desired reservoir and seal quality). This is an area where IBDP was able to leverage limited regional information from previous geological investigations (e.g., local borehole data, 2D seismic data) before field activities for site characterization were conducted. It should be noted by project operators that the acquisition of new site data can have significant impacts on project and monitoring plans, especially with respect to the AoR. The AoR defines the anticipated maximum extent of the project impact either by plume extent or pressure increases (and thus the most relevant areas to be considered for a carbon storage monitoring program). Therefore, acquisition of new information with the potential to affect the AoR should be carefully planned and integrated into project and permitting workflows.
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Fig. 1. Generalized testing and monitoring activities during the life cycle of a storage project (from EPA [22]).
With injection completed and the IBDP Class VI permit finalized in 2014, the project has been able to focus on moving from a comprehensive research and compliance mode to a significantly more targeted monitoring mode that has been tailored to address the Class VI requirements. Under the Class VI permit, a significant number of changes occurred to the IBDP monitoring program. For example, groundwater monitoring under the Class I permit was focused on 11 sentinel parameters that were primarily selected for their sensitivity to detect fluid quality changes resulting from interactions with CO2 or brine. Those parameters were pH, temperature, specific conductance, dissolved oxygen, dissolved CO2 as total inorganic carbon, alkalinity, bromide, chloride, calcium, sodium, and groundwater elevation at four sampling locations in Pennsylvanian-age bedrock, which was considered the lower most USDW under the Class I permit. The Class VI permit added groundwater sampling locations from three deeper depths (St. Peter Sandstone, Ironton-Galesville Formation and Mt. Simon Sandstone) and retained the four sampling locations in Pennsylvanianage bedrock. The permit also increased the number of water quality parameters to be monitored from 11 to 30 that included additional major and minor elements and isotopes. Regulatory changes to other monitoring methods and frequencies (e.g., well logging, seismic surveys, microseismic monitoring) also occurred but are not described in this paper. Since 2015, a major decrease in research monitoring intensity has occurred. For example, shallow groundwater sampling was reduced from monthly monitoring of 17 shallow wells to quarterly monitoring of 4 shallow wells, and weekly soil flux monitoring was reduced to monthly in 2015 and then terminated at the end of the 2015 field season.
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Freq.
Pre-injection
Subsurface
Near-Surface
Surface
2008 2009
Injection
Post-Injection
2010
2011
2012
2013
2014
2015
2016
2017
2018
x
x
p
p
Aerial imagery
SA
x
x
x
x
x
x
Eddy covariance
C
x
x
x
x
x
x
Soil flux - network
W-Q
x
x
x
x
x
x
x
Soil flux - multiplexer
C
x
x
x
x
x
x
Tunable diode laser- single path
C
x
x
Tunable diode laser- multi path
C
InSAR
BW
Continuous GPS
C
Soil gas sampling
Q-A
Shallow groundwater sampling 1,2
M-Q
Shallow electrical earth resistivity
A
Pressure/temp. - VW1 and CCS1 1,2
C
Pulsed neutron (CCS1, VW1, GM1) 1,2
Q-A
Deep fluid sampling (VW1) 2
SA
Passive seismic monitoring (GM1) 2
C
Seismic/3D VSP imaging 1,2 Mechanical integrity (CCS1, VW1) 1,2
x x
x x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
p
p
x
x
x
x
x
x
p
p
x
x
x
x
x
TBD
TBD
x
x
x
x
x
p
p
x
x
x
x
x
x
p
p
SA-A
x
x
x
x
x
x
A
x
x
x
x
x
x
x
x
x
x
x
x
x
The conditions of the IBDP Class VI final permit required additional fluid sampling from the deeper sampling formations resulting in the need for more infrastructure, preparation of each well prior to sampling, and greater logistical difficulties of sampling at depths from 900 to 2,100 m (3,000 to 7,000 ft) These efforts were significantly greater than the required shallow (43 m; 140 ft) fluid sampling for the IBDP Class I permit and resulted in additional personnel time and equipment costs to the IBDP. An example of cost increases resulting from the Class VI permit is illustrated in Table 3 when just the cost to analyze fluid samples is considered. An approximate fourfold increase in compliance-related analytical costs were realized by the IBDP when site monitoring was aligned with the final Class VI rules when considering the original IBDP project wells (4 shallow and VW1). An approximate fivefold increase occurred when also considering wells associated with the IL-ICCS project (VW2 and GM2). These costs were associated with the increase in permit compliance sampling locations (increased number of samples) and the increase
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in water quality parameters to be measured. The project was already conducting additional non-permit related monitoring to develop a comprehensive set of environmental data. Many of the previously research-related parameters were added to the Class VI regulatory monitoring program which increased the resources needed to address mandatory monitoring components. Because the scope (injection mass, length of project, geographic extent) of the IBDP demonstration is significantly smaller than a full-scale commercial project (e.g., injection of > 50 million tonnes over decades), the increase in regulatory monitoring requirements were significant, but not unbearable. The biggest monitoring adaptations implemented by the IBDP were related to downscaling the number of research-related monitoring types, locations, parameters, and frequencies as the project was in its PISC period. It is suggested that for future large-scale storage projects, the use of risk-based, adaptive monitoring programs will be needed to optimize monitoring costs throughout a project life cycle. In those circumstances, it may also be appropriate to identify components of monitoring programs that are unnecessarily comprehensive (e.g., fluid chemistry analyses) in favor of less numerous, but yet fully effective sentinel parameters or techniques (e.g., downhole water quality sensors) after sufficient baseline data have been acquired. Table 3. Example of differences in Class I vs. Class VI groundwater monitoring analytical costs (in $USD). N/A = not applicable.
Well (Formation)
Sample Frequency
Number of Sampling Locations
Number of Samples (includes QC)
Cost /sample ($)
Cost /year ($)
Class I
Class VI
Class I
Class VI
Class I
Class VI
Class I
Class VI
Class I
Quarterly
Quarterly
4
4
24
24
110
310
2,640
7,440
VW1 (Ironton-Galesville)
Not required
Annual
0
1
0
3
N/A
420
N/A
1,260
VW1 (Mt. Simon)
Not required
Annual
0
1
0
3
N/A
420
N/A
1,260
VW2 (Mt. Simon)
N/A
Annual
N/A
3
N/A
5
N/A
420
N/A
2,100
GM2 (St. Peter)
N/A
Annual
N/A
1
N/A
3
N/A
420
N/A
1,260
Total Cost
2,640
13,320
Shallow (Pennsylvanian)
Class VI
5. Future Project-Specific Regulatory Uncertainty Monitoring results (e.g., observed reservoir pressures in comparison with modeled pressures, assessments of repeat pulsed neutron well logging results) and project data assessments indicate that the IBDP CO2 plume has spread within a thin, high permeability zone in the lowermost Mt. Simon Sandstone and that a low permeability zone in the upper part of the lower Mt. Simon Sandstone is acting as an effective baffle to limit CO2 migration and pressure transmission above 2,094 m (6,870 ft) [4]. The most significant remaining sources of regulatory uncertainty for the IBDP are related to monitoring program requirements during the PISC period. They include the length of PISC period monitoring and the process by which a non-endangerment determination will be sought from the US EPA for the project to proceed to closure. After CO2 injection ceases the permittee is required to continue to conduct monitoring specified in the PISC for at least 50 years or for the duration of the alternative timeframe approved by the Director (40 CFR 146.93[b][2] or [3]). The demonstration of an alternative timeframe for non-endangerment of a USDW to the UIC program director must include: (1) summary of existing monitoring and laboratory data, (2) comparison of monitoring data and model predications and model documentation in relation to (a) pressure decline within the injection zone and any other zones such that formation fluids cannot be forced into USDWs or the timeframe for pressure decline to reach pre-injection
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pressures, (b) predicted rate of plume migration within injection zone and timeframe for cessation of migration, (3) site-specific processes resulting in CO2 trapping and predicted rate of trapping, (4) characterization of confining zones to ensure their integrity to impede fluid (CO2 and formation fluids) movement, (5) evaluation for potential conduits for fluid movement, (6) analysis to identify and assess aspects of the alternative PISC that contribute to significant uncertainty. Based on those criteria, an adjusted PISC of 10 years was requested by the permittee and granted. The adjusted PISC timeframe is linked to the completion of IL-ICCS injection and would not likely begin before 2022. Even with the approved alternative timeframe, monitoring must continue until the geologic sequestration project no longer poses an endangerment to USDWs. The approval of an alternative timeframe is based on monitoring and other site-specific data in conjunction with numerical modeling. Because of the importance of modeling in all phases of the project (e.g., pre-injection AoR estimations, estimates of plume migration and formation pressure responses, PISC plume stabilization estimates and CO2 trapping mechanisms), it is essential for projects to document numerical model metadata, keep comprehensive records of model input and output, maintain model operability, and maintain continuity in modeling knowledge throughout a project. It is anticipated that the IL-ICCS project (and by association, the IBDP) will demonstrate non-endangerment using the same basis under which the 10-year PISC period was requested, and US EPA approval of the non-endangerment documentation will be required before the projects can enter the closure phase. 6. Summary and Recommendations The IBDP experienced two lengthy permitting processes that proved to be the rate-limiting factor for the project, increased the length of time before the project could begin injection, and required additional resources to conduct the project. The permitting process involved multiple key stakeholders: project developer, site owner, content experts, and regulators at the State and Federal level. As new regulatory frameworks are being developed and tested, there is critical need for capacity building, communication, and explicit understanding of the permitting process. The negotiation of terms, permit conditions, modelling of the AoR, PISC expectation from early permits, such as from the IBDP and IL-ICCS projects, can have significant impact and set precedence for future projects. Operators and regulators alike can benefit from frequent proactive communications during the permitting process in order to significantly reduce the length of the permitting process, maintain the critical safeguards of the Class VI rules, and ultimately meet timely goals for reductions to atmospheric CO2 emissions. Timing and intensity of monitoring programs at different project stages should be carefully planned. The IBDP purposely maintained a comprehensive monitoring strategy throughout the pre-injection and injection phases of the project in anticipation of the Class VI rule finalization and the issuance of final permit conditions for the IBDP. After the project completed injection and the Class VI permit went into effect for the PISC, the IBDP research-related monitoring intensity was greatly reduced. The Class VI regulations provide flexibility for storage operators to design a site specific testing and surveillance program. Long-term MVA programs should remain aware of and test new technologies that can improve monitoring efficiencies and effectiveness to reduce overall monitoring costs. Further, to minimize the need for additional permit modifications related to risk-based monitoring program adjustments, it is recommended that future Class VI applicants consider including an iterative and adaptive monitoring strategy in their initial permit application for the purpose of optimizing monitoring activities throughout the life of the project. Acknowledgements The Midwest Geological Sequestration Consortium (MGSC) is funded by the U.S. Department of Energy through the National Energy Technology Laboratory (NETL) via the Regional Carbon Sequestration Partnership Program (contract number DE-FC26-05NT42588) and by a cost share agreement with the Illinois Department of Commerce and Economic Opportunity, Office of Coal Development through the Illinois Clean Coal Institute.
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