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The North Dakota integrated carbon storage complex feasibility study
International Journal of Greenhouse Gas Control 84 (2019) 47–53
Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
The North Dakota integrated carbon storage complex feasibility study ⁎
T
Wesley D. Peck , Scott C. Ayash, Ryan J. Klapperich, Charles D. Gorecki University of North Dakota Energy & Environmental Research Center, 15 North 23rd Street, Stop 9018, Grand Forks, ND, 58202-9018, United States
A R T I C LE I N FO
A B S T R A C T
Keywords: Saline Feasibility CO2 storage Commercial-scale Characterization Williston Basin
The Energy & Environmental Research Center is investigating the feasibility of safely, permanently, and economically storing 50 million tonnes of CO2 in central North Dakota, United States, over a 25-year operational period, should a business case for CO2 storage emerge. The study is part of the U.S. Department of Energy (DOE) National Energy Technology Laboratory CarbonSAFE initiative and addresses the technical and nontechnical challenges of commercially deploying a CO2 storage project. Evaluation of cores from two stratigraphic test wells demonstrate that the Broom Creek Formation (sandstone) is an excellent candidate for the geologic storage of CO2 and the overlying Opeche Formation a competent cap rock.
1. Introduction In June 2017, the Energy & Environmental Research Center (EERC) began a 2-year project to investigate the feasibility of safely, permanently, and economically storing 50 million tonnes (Mt) of CO2 in central North Dakota, United States, over a 25-year operational period. The North Dakota Integrated Carbon Storage Complex Feasibility Study (i.e., North Dakota CarbonSAFE [NDCS]) is addressing the technical and nontechnical challenges specific to commercial-scale deployment of a dedicated CO2 storage project in central North Dakota with a longterm goal to develop a permitted geologic storage opportunity should a business case for dedicated CO2 storage emerge. NDCS is part of the U.S. Department of Energy (DOE) National Energy Technology Laboratory CarbonSAFE initiative. The goal of DOE’s initiative is to develop an integrated CO2 storage complex constructed and permitted for operation in the 2025 time frame. This feasibility study is evaluating two promising geologic storage complexes located adjacent to two separate coal-fired facilities in North Dakota: the Basin Electric Power Cooperative (BEPC)-owned Dakota Gasification Company (DGC) and the Minnkota Power Cooperative (Minnkota)-owned Milton R. Young (MRY) Station (Fig. 1). These locations, one with readily available, captured CO2, are bolstered by an existing CO2 pipeline and progressive North Dakota pore space ownership, long-term liability laws, and North Dakota’s primacy over Class VI (CO2) underground injection wells (U.S. Environmental Protection Agency, 2018). These elements, in combination with a motivated team, create an ideal synergistic scenario for ensuring success of the CarbonSAFE Program and promoting North Dakota’s statewide
vision for carbon management. To address the challenges of the project, the EERC has assembled a diverse and committed team: the Lignite Research Council (LRC), BEPC, ALLETE Clean Energy (ACE), BNI Energy, North American Coal, Minnkota, Schlumberger Carbon Services (Schlumberger), Computer Modelling Group, Ltd. (CMG), and Prairie Public Broadcasting. These partners are providing critical support in the form of financial backing, in-kind support, site access, outreach collaboration, operations data, inputs on risk assessment and evaluation, and software access and support needed to achieve the proposed project objectives. 2. Project location and CO2 source scenarios The NDCS project is located in west-central North Dakota within the bounds of the Williston Basin: a large petroleum-rich geologic basin with nearly 4800 m (16,000 feet) of sedimentary rock at its depocenter (Fig. 1). Within this package of sedimentary rock, the Permian-aged Broom Creek Formation (sandstone) of the Minnelusa Group makes an excellent candidate for the geologic storage of CO2 (Fig. 2) (Peck et al., 2014; Sorensen et al., 2009). The primary upper seal is the overlying Permian Opeche Formation, a regionally continuous red shale and silt with thin lenses of anhydrite and halite. In addition, several thousand meters of Cretaceous-aged shales are found between the lowermost drinking water aquifer and the Broom Creek Formation. The underlying Amsden Formation, which is composed of low-permeability anhydrite, dolomite, and shale, comprises the lower seal. The base of Broom Creek Formation lies approximately 1615 m (5300 feet) above the contact between
⁎
Corresponding author. E-mail addresses: [email protected] (W.D. Peck), [email protected] (S.C. Ayash), [email protected] (R.J. Klapperich), [email protected] (C.D. Gorecki). https://doi.org/10.1016/j.ijggc.2019.03.001 Received 3 October 2018; Received in revised form 13 February 2019; Accepted 1 March 2019 Available online 14 March 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.
International Journal of Greenhouse Gas Control 84 (2019) 47–53
W.D. Peck, et al.
Fig. 1. Location of the North Dakota CarbonSAFE project within the Williston Basin (dashed line).
sedimentary strata and Precambrian basement rock, eliminating concern of injection pressure causing unwanted seismicity near the contact. The NDCS project is also positioned in the lignite-rich portion of the Williston Basin, home to several large-scale (> 400 MW) minemouth lignite-fired energy production facilities. Three of these facilities have been incorporated into CO2 capture scenarios to provide the commercial-scale 2 Mt/yr of CO2 for storage in the Broom Creek Formation (Fig. 2). The primary CO2 source scenario includes DGC’s Great Plains Synfuels Plant, which is currently capturing about 2 Mt of CO2 per year and sending the gas to southern Saskatchewan for CO2 enhanced oil recovery (EOR) in the Weyburn and Midale oil fields. As of September 2018, there is capacity for capture of an additional 1 Mt of CO2 from this facility. A second, and very progressive potential future source of CO2, is “Project Tundra,” a DOE-sponsored collaborative clean coal technology project between Minnkota, ACE, BNI Energy, and the EERC (Project Tundra, 2018). The ultimate goal of Project Tundra is to retrofit an existing power plant with CO2 capture technology for the purposes of dedicated CO2 storage in a saline reservoir and/or associated CO2 storage in conjunction with CO2 EOR. The time line for Project Tundra follows closely with that of DOE’s CarbonSAFE Program, which targets CO2 storage beginning in ˜2025. These two scenarios, along with a third option of capture from Antelope Valley Station (AVS), are depicted in Fig. 3. 3. Characterization activities The deposits of the Broom Creek Formation are predominantly coastal eolian dunes overlain by high-energy, shallow-marine environments of beach or offshore bar (Ziebarth, 1972; Rygh, 1990). In the NDCS study region, the Broom Creek Formation is approximately 1585 to 1920 m (5200 to 6300 feet) below surface with a thickness of about 76 m (250 feet). Peck et al. (2014) performed reconnaissancelevel basinwide modeling of the Broom Creek Formation to determine the prospective CO2 storage resource of the horizon. The static geocellular model created in that study used a multimineral petrophysical analysis approach based on well log data from 208 wells and core data from two wells outside of the current study area. The results of the data analysis, modeling, and the DOE method for estimating prospective CO2 storage resource in saline formations indicate a CO2 storage resource potential of the Broom Creek Formation to be approximately 13 to 42 Gt. The wide range of the capacity estimate is a result of the relative
Fig. 2. Stratigraphic position of the Broom Creek Formation in the North Dakota CarbonSAFE study area.
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Fig. 3. Representation of the CO2 source scenarios envisioned for North Dakota CarbonSAFE.
The initial core analysis reports the highly porous and permeable sandstone layers as having porosity of 20%–30% and permeability to air of 300–1700 mD (Fig. 6). The TDS (total dissolved solids) of the brine sampled from the Broom Creek Formation ranged from 61,000 to 70,000 ppm. Additional analytical investigation will determine the relative permeability of CO2 and brine at reservoir temperature and pressure and investigate the potential for geochemical reactions between native brine, rock matrix, and injected CO2. Finally, geomechanical properties of the cap rock formation will be determined to validate the maximum injection threshold of the system. Results of all laboratory investigations along with reprocessed seismic data are being used to significantly improve the technical understanding of the geologic storage complex present in the study areas and verify assumptions made about the storage potential of the study areas in prior regional assessments. Preliminary analysis of the newly acquired core supports earlier broad assessments that the Broom Creek Formation would be an excellent target for CO2 storage. The new core and logs, augmented by both newly collected and reprocessed legacy seismic data, are being used to develop 3-D geocellular models of the target storage zone in the area. The geocellular models provide the foundation for numerical, multiphase fluid flow, geochemical, and geomechanical simulation efforts to accurately predict potential CO2 and pressure plume extents at both storage areas based on the premise of a 2-Mt-a-year injection rate. Understanding the potential extent of injected CO2 provides a foundation for the magnitude of future pore space leasing requirements; monitoring, verification, and accounting activities; and development of business case scenarios.
paucity of data on the Broom Creek Formation, which increases the uncertainty with respect to its geologic characteristics in the proposed study region. To reduce the technical and nontechnical uncertainty with respect to confirming the feasibility of establishing a certifiable large-scale commercial CO2 storage site, new geologic data were needed. As such, a major component of the NDSC project was to collect localized characterization data of the Broom Creek Formation in central North Dakota. The pillar of this characterization effort was the drilling of two new stratigraphic test wells into the Broom Creek Formation to collect core, geophysical logs, water samples, and pressure data. Analysis and interpretation of these new data will be augmented by analysis of select reprocessed existing 3-D and 2-D seismic data sets and the collection of a new 2-D line of seismic data. The two new characterization wells, one in each of the proposed project areas (Fig. 4), were completed in the winter of 2017–2018. The first stratigraphic test well (Flemmer-1) was located approximately 16 km (10 miles) west of the AVS–DGC facilities and within the boundaries of an existing 3-D seismic survey, a portion of which was purchased, reprocessed, and is being interpreted. Siting the stratigraphic test well within the bounds of the existing seismic data will allow the extrapolation of measurements and interpretations from well log and core data to provide increased understanding of the spatial distribution of geologic and petrophysical properties within the saline Broom Creek Formation. The Flemmer-1 well was drilled to a depth of 2070 m (6790 feet) and yielded 100 m (330 feet) of core (Fig. 5) covering the entire thickness of the Broom Creek Formation along with a portion of the cap rock (Opeche Shale) and underlying Amsden Formation. The Broom Creek section of the core (80 m, 260 feet) comprises 52 m of high-permeability (> 300 mD) sandstone (169 feet), with the balance of the formation thickness comprising interbedded siltstones, shales, and anhydrite. The second stratigraphic test well (BNI-1) was located just west of MRY on property owned by BNI Energy, a project partner. Using new and existing equipment, the EERC acquired a 2-D seismic line through the test well to tie the geology observed at the well to an existing legacy seismic line, which was also purchased and interpreted. The BNI-1 well was drilled to a depth of 1634 m (5360 feet) and yielded 96 m (315 feet) of core which included 83 m of Broom Creek. The Broom Creek comprises 38 m (125 feet) of high-permeability (> 300 mD) sandstone and 45 m of interbedded siltstones, shales, and anhydrite. As with the Flemmer-1 well, the BNI-1 core included a portion of the cap rock and underlying formation. After coring and testing, both wells were successfully plugged and abandoned.
4. Nontechnical challenges Although central North Dakota is an exceptional candidate area for implementing a commercial-scale (50+ Mt of CO2) geologic storage project from a geologic standpoint, the prospect of successfully executing such an endeavor faces several nontechnical challenges. From a broad CCS (carbon capture and storage) perspective, elements such as public acceptance, financial investment, regulatory hurdles, and legalities associated with pore space ownership and long-term liability are often cited as the primary nontechnical challenges. 4.1. Economics The NDCS project is examining specific economic needs and incentives in place to make at least one of the proposed scenarios economically feasible for the project partners. As recognized by DOE and others, the lack of economic incentive is the primary obstacle curtailing 49
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Fig. 4. Map illustrating the two study regions of the North Dakota CarbonSAFE project.
financial investment in CO2 storage projects. Although broader-scale incentives are generally missing, state and federal programs are available that provide tax incentives and loan opportunities. From a North Dakota standpoint, the potential to supply CO2 to a number of promising conventional CO2 EOR fields along an existing CO2 pipeline provides an opportunity to generate a revenue stream to offset capture and storage costs. This potential could be orders of magnitude higher with ongoing and successful research into EOR methods in the Bakken petroleum system (Sorensen et al., 2015, 2016). A memorandum of understanding was signed by ACE, Minnkota, BNI Energy, and the EERC on August 22, 2016, to facilitate further collaboration on the development of an integrated CCS strategy, known as “Project Tundra,” to promote and develop CO2 EOR offsets (Project Tundra, 2018). 4.2. Regulatory Regulatory frameworks associated with the geologic storage of CO2 have been developed to various extents in several states and at the federal level. Conforming to those regulations represents a notable challenge. Within North Dakota, progressive legislation has built successful, long-term subsurface management of its hydrocarbon resources and has been enacted to facilitate the geologic storage of CO2 either in saline reservoirs or associated with EOR operations. On the federal level, the promulgation of Class VI well regulations by the U.S. Environmental Protection Agency (EPA) in 2010 set exacting standards for the construction of CO2 injection wells and formally defined the criteria for determining area of review (AOR). To bring the enforcement of these regulations under control of the state with the federal government providing oversight, North Dakota applied for, and received, primary regulatory authority (primacy) over Class VI injection well activities (U.S. Environmental Protection Agency, 2018). Testimony to the North Dakota Legislative Council concluded that when primacy of federal regulations is extended to the state there is less of an argument
Fig. 5. Samples of Broom Creek sandstone core from the Flemmer-1 stratigraphic test well. 50
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Fig. 6. Core porosity and permeability data for the Flemmer-1 well.
that national lawsuits affect state programs. In the case of establishing a commercial-scale CO2 storage project in North Dakota, this philosophy allows for capitalizing on local knowledge and ensuring timeliness in acquiring necessary permits. In summary, now that North Dakota has been granted primacy, the risk of establishing the permitting pathway to a CO2 storage project is substantially reduced. The issues of pore space ownership and long-term liability have been addressed through state legislation. Specifically, the state has determined that the owner of the surface lands is the owner of the underlying pore space and that this ownership cannot be severed under any agreement; pore space ownership transfers to any new surface land owner. The state has also assumed long-term liability for any sequestered CO2, taking ownership of liability after issuing a CO2 storage operator a Certificate of Site Closure, which indicates that the operator has fulfilled all necessary requirements to ensure permanent storage (North Dakota Century Code, 2019 § 38-22). 4.3. Outreach Despite having a CO2 storage target with promising geologic properties and industry willingness, a potential CO2 storage project can still face opposition if the local community is not on board with the project. Thus an important aspect of a feasibility study is to gauge the level of public acceptance for a potential CO2 storage project. Knowing that public acceptance can hinge on proper and early communication regarding what a CCS project entails, the impact of effective public outreach cannot be overstated. As part of the NDCS, project outreach to stakeholder groups and the public is occurring through individual contact, meetings, wellsite tours (Fig. 7), and open house formats. An Outreach Advisory Group comprising representatives of the project partners and key stakeholders was formed to advise on the development of
Fig. 7. Local high school students visiting the BNI-1 wellsite during drilling to learn about the NDCS project.
plans, activities, and products to ensure consistent messaging targeted at local audiences. Products include general audience presentation slides; general audience project posters; project-focused video shorts for use on the Internet and in presentations; and a media kit comprising general project information, graphics, press releases, and frequently asked questions. A short video (˜8 min) is also being produced to describe how North Dakota is well positioned to meet the energy challenges of a low-carbon future through the safe, permanent storage of CO2 deep underground. Based on input from technical experts and 51
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Fig. 8. Leveraging North Dakota’s infrastructure and regulatory framework for CO2 management for the success of the NDCS Program.
previously attempted. The NDCS project seeks to provide a road map for future development of a commercial CCS project. Until recently, the necessary combination of economic incentives, regulatory requirements, and technical understanding has not been in place. An ideal climate now exists to pursue a large-scale integrated CCS effort because of recent tax incentive programs (U.S. Congress House of Representatives, 2018) and progressive North Dakota pore space ownership and long-term liability laws (North Dakota Century Code, 2019, Chapter 38-22) coupled with the state’s primacy of CO2 injection wells (Class VI [U.S. Environmental Protection Agency, 2018]) (Fig. 8). To lay the groundwork for future phases of this project, a permitting plan incorporating applicable local, state, and federal regulations is being developed with guidance from officials who oversee North Dakota’s primacy of EPA Class VI UIC wells. In addition, there is a growing demand for low- carbon energy sources. North Dakota is at the forefront of energy development and production, and the North Dakota energy industry is motivated to provide solutions to challenges presented by that demand. The state continues to investigate long-term strategies that incorporate all energy resources—traditional and emerging—to meet the nation’s growing energy demand in an environmentally responsible manner. This project will lead to expanded opportunities for the state’s coal and other energy industries and ensure the success of the CarbonSAFE Program.
partners, the video short will provide a concise and consistent set of North Dakota-focused messages on the topic of carbon storage addressing key concerns of area stakeholders. The video will focus on how and why CO2 storage makes sense for North Dakota and on how science and North Dakota regulatory agencies would ensure safe, effective CO2 storage operations. 4.4. Risk assessment Successful implementation of geologic storage projects for CO2 requires developers to assess candidate sites based on a number of site selection criteria, such as storage capacity, economics, regulatory constraints, and potential risks. Risk assessment helps guide geologic storage implementation by guiding stakeholders through the steps involved in identifying and characterizing pertinent risks; proactively developing methods to mitigate the impacts from unacceptable risks; and integrating risk management with project management, design, and implementation. A baseline risk assessment workshop was conducted where EERC project team members led major project participants and other stakeholders through a process to identify potential technical and nontechnical risks that may preclude candidate storage complexes within the two proposed study areas from serving as commercial storage sites. A draft risk register was generated based on the discussion at the workshop. The register provides specific risk factors that will be considered as part of a future scoring process and will help identify items that may require mitigation should the principal risk category be ranked as unacceptable at the conclusion of the risk assessment process. Quantitative assessments of each identified risk will be made by assessing and scoring the probability that a risk event will occur and the resulting impact if it does occur. Once the risk assessment has been completed, a risk treatment strategy will be formulated. Risk treatment includes several different strategies for negative risks, including avoidance, transfer, mitigation, monitoring, and acceptance, and for positive risks, including exploitation, sharing, enhancing, and acceptance.
DOE disclaimer This paper was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.
5. Summary Every CCS project site offers unique opportunities and challenges, and the NDCS project will bring advances in knowledge, technology, and techniques to address these opportunities to advance global knowledge in CCS. Although aspects of these challenges have been addressed through prior research or various legislative actions, an integrated project that seeks to address these challenges and leverage previous efforts to conduct a commercial-scale CCS project has not been
Acknowledgments This material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FE0029488. The authors would like to acknowledge and thank the project’s partners for their participation and generous support, 52
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including Allete Clean Energy, Basin Electric Power Cooperative, BNI Energy, Computer Modelling Group, North American Coal, Minnkota Power Cooperative, the North Dakota Lignite Research Council, Prairie Public Broadcasting, and Schlumberger. The authors would also like to thank CGG GeoSoftware for the use of their software during this work.
Provide Critical Insights on EOR in Tight Oil Plays: American Oil & Gas Reporter, February, 8 P. (Accessed July 2018). www.aogr.com/magazine/cover-story/ historical-bakken-test-data-provide-critical-insights-on-eor-in-tight-oil-p. Sorensen, J., Bailey, T., Dobroskok, A., Gorecki, C., Smith, S., Fisher, D., Peck, W., Steadman, E., Harju, J., 2009. Characterization and Modeling of the Broom Creek Formation for Potential Storage of CO2 From Coal-fired Power Plants in North Dakota: Search and Discovery Article #80046. Sorensen, J.A., Braunberger, J.R., Liu, G., Smith, S.A., Hawthorne, S.A., Steadman, E.N., Harju, J.A., 2015. Characterization and evaluation of the bakken petroleum system for CO2 enhanced oil recovery. Paper Presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference July 20–22, 2015, URTeC Paper No. 2169871. U.S. Congress House of Representatives, 2018. Bipartisan Budget Act of 2018: H.R. 1892–115th Congress, Section 41119, Enhancement of Carbon Dioxide Sequestration Credit. U.S. Environmental Protection Agency, 2018. State of North Dakota Underground Injection Control Program – Class VI Primacy Approval: Federal Register, 83 FR 17758, 40 CFR 147, Document No. 2018-08425, April 24, 2018. pp. 17758–17761. Ziebarth, H.C., 1972. The Stratigraphy and Economic Potential of Permo-pennsylvanian Strata in Southwestern North Dakota [Ph.D. Dissertation]. University of North Dakota, Grand Forks, North Dakota 414 p.
References North Dakota Century Code, Chapter 38-22—carbon dioxide underground storage: 6 p. Peck, W.D., Glazewski, K.A., Braunberger, J.R., Grove, M.M., Bailey, T.P., Bremer, J.M., Gorz, A.J., Sorensen, J.A., Gorecki, C.D., Steadman, E.N., 2014. Broom Creek Formation Outline: Plains CO2 Reduction (PCOR) Partnership Phase III Value-added Report for U.S. Department of Energy National Energy Technology Laboratory Cooperative Agreement No. DE-FC26-05NT42592, EERC Publication 2014-EERC-0909. North Dakota, Energy & Environmental Research Center, August, Grand Forks. Project Tundra, 2018, www.projecttundrand.com (Accessed August 2018). Rygh, M.E., 1990. The Broom Creek Formation (Permian), in Southwestern North Dakota—depositional Environments and Nitrogen Occurrence [Master’s Thesis]. University of North Dakota, Grand Forks, North Dakota 189 p. Sorensen, J.A., Hamling, J.A., 2016. Enhanced Oil Recovery—Historical Bakken Test Data
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Contents lists available at ScienceDirect
International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc
The North Dakota integrated carbon storage complex feasibility study ⁎
T
Wesley D. Peck , Scott C. Ayash, Ryan J. Klapperich, Charles D. Gorecki University of North Dakota Energy & Environmental Research Center, 15 North 23rd Street, Stop 9018, Grand Forks, ND, 58202-9018, United States
A R T I C LE I N FO
A B S T R A C T
Keywords: Saline Feasibility CO2 storage Commercial-scale Characterization Williston Basin
The Energy & Environmental Research Center is investigating the feasibility of safely, permanently, and economically storing 50 million tonnes of CO2 in central North Dakota, United States, over a 25-year operational period, should a business case for CO2 storage emerge. The study is part of the U.S. Department of Energy (DOE) National Energy Technology Laboratory CarbonSAFE initiative and addresses the technical and nontechnical challenges of commercially deploying a CO2 storage project. Evaluation of cores from two stratigraphic test wells demonstrate that the Broom Creek Formation (sandstone) is an excellent candidate for the geologic storage of CO2 and the overlying Opeche Formation a competent cap rock.
1. Introduction In June 2017, the Energy & Environmental Research Center (EERC) began a 2-year project to investigate the feasibility of safely, permanently, and economically storing 50 million tonnes (Mt) of CO2 in central North Dakota, United States, over a 25-year operational period. The North Dakota Integrated Carbon Storage Complex Feasibility Study (i.e., North Dakota CarbonSAFE [NDCS]) is addressing the technical and nontechnical challenges specific to commercial-scale deployment of a dedicated CO2 storage project in central North Dakota with a longterm goal to develop a permitted geologic storage opportunity should a business case for dedicated CO2 storage emerge. NDCS is part of the U.S. Department of Energy (DOE) National Energy Technology Laboratory CarbonSAFE initiative. The goal of DOE’s initiative is to develop an integrated CO2 storage complex constructed and permitted for operation in the 2025 time frame. This feasibility study is evaluating two promising geologic storage complexes located adjacent to two separate coal-fired facilities in North Dakota: the Basin Electric Power Cooperative (BEPC)-owned Dakota Gasification Company (DGC) and the Minnkota Power Cooperative (Minnkota)-owned Milton R. Young (MRY) Station (Fig. 1). These locations, one with readily available, captured CO2, are bolstered by an existing CO2 pipeline and progressive North Dakota pore space ownership, long-term liability laws, and North Dakota’s primacy over Class VI (CO2) underground injection wells (U.S. Environmental Protection Agency, 2018). These elements, in combination with a motivated team, create an ideal synergistic scenario for ensuring success of the CarbonSAFE Program and promoting North Dakota’s statewide
vision for carbon management. To address the challenges of the project, the EERC has assembled a diverse and committed team: the Lignite Research Council (LRC), BEPC, ALLETE Clean Energy (ACE), BNI Energy, North American Coal, Minnkota, Schlumberger Carbon Services (Schlumberger), Computer Modelling Group, Ltd. (CMG), and Prairie Public Broadcasting. These partners are providing critical support in the form of financial backing, in-kind support, site access, outreach collaboration, operations data, inputs on risk assessment and evaluation, and software access and support needed to achieve the proposed project objectives. 2. Project location and CO2 source scenarios The NDCS project is located in west-central North Dakota within the bounds of the Williston Basin: a large petroleum-rich geologic basin with nearly 4800 m (16,000 feet) of sedimentary rock at its depocenter (Fig. 1). Within this package of sedimentary rock, the Permian-aged Broom Creek Formation (sandstone) of the Minnelusa Group makes an excellent candidate for the geologic storage of CO2 (Fig. 2) (Peck et al., 2014; Sorensen et al., 2009). The primary upper seal is the overlying Permian Opeche Formation, a regionally continuous red shale and silt with thin lenses of anhydrite and halite. In addition, several thousand meters of Cretaceous-aged shales are found between the lowermost drinking water aquifer and the Broom Creek Formation. The underlying Amsden Formation, which is composed of low-permeability anhydrite, dolomite, and shale, comprises the lower seal. The base of Broom Creek Formation lies approximately 1615 m (5300 feet) above the contact between
⁎
Corresponding author. E-mail addresses: [email protected] (W.D. Peck), [email protected] (S.C. Ayash), [email protected] (R.J. Klapperich), [email protected] (C.D. Gorecki). https://doi.org/10.1016/j.ijggc.2019.03.001 Received 3 October 2018; Received in revised form 13 February 2019; Accepted 1 March 2019 Available online 14 March 2019 1750-5836/ © 2019 Elsevier Ltd. All rights reserved.
International Journal of Greenhouse Gas Control 84 (2019) 47–53
W.D. Peck, et al.
Fig. 1. Location of the North Dakota CarbonSAFE project within the Williston Basin (dashed line).
sedimentary strata and Precambrian basement rock, eliminating concern of injection pressure causing unwanted seismicity near the contact. The NDCS project is also positioned in the lignite-rich portion of the Williston Basin, home to several large-scale (> 400 MW) minemouth lignite-fired energy production facilities. Three of these facilities have been incorporated into CO2 capture scenarios to provide the commercial-scale 2 Mt/yr of CO2 for storage in the Broom Creek Formation (Fig. 2). The primary CO2 source scenario includes DGC’s Great Plains Synfuels Plant, which is currently capturing about 2 Mt of CO2 per year and sending the gas to southern Saskatchewan for CO2 enhanced oil recovery (EOR) in the Weyburn and Midale oil fields. As of September 2018, there is capacity for capture of an additional 1 Mt of CO2 from this facility. A second, and very progressive potential future source of CO2, is “Project Tundra,” a DOE-sponsored collaborative clean coal technology project between Minnkota, ACE, BNI Energy, and the EERC (Project Tundra, 2018). The ultimate goal of Project Tundra is to retrofit an existing power plant with CO2 capture technology for the purposes of dedicated CO2 storage in a saline reservoir and/or associated CO2 storage in conjunction with CO2 EOR. The time line for Project Tundra follows closely with that of DOE’s CarbonSAFE Program, which targets CO2 storage beginning in ˜2025. These two scenarios, along with a third option of capture from Antelope Valley Station (AVS), are depicted in Fig. 3. 3. Characterization activities The deposits of the Broom Creek Formation are predominantly coastal eolian dunes overlain by high-energy, shallow-marine environments of beach or offshore bar (Ziebarth, 1972; Rygh, 1990). In the NDCS study region, the Broom Creek Formation is approximately 1585 to 1920 m (5200 to 6300 feet) below surface with a thickness of about 76 m (250 feet). Peck et al. (2014) performed reconnaissancelevel basinwide modeling of the Broom Creek Formation to determine the prospective CO2 storage resource of the horizon. The static geocellular model created in that study used a multimineral petrophysical analysis approach based on well log data from 208 wells and core data from two wells outside of the current study area. The results of the data analysis, modeling, and the DOE method for estimating prospective CO2 storage resource in saline formations indicate a CO2 storage resource potential of the Broom Creek Formation to be approximately 13 to 42 Gt. The wide range of the capacity estimate is a result of the relative
Fig. 2. Stratigraphic position of the Broom Creek Formation in the North Dakota CarbonSAFE study area.
48
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Fig. 3. Representation of the CO2 source scenarios envisioned for North Dakota CarbonSAFE.
The initial core analysis reports the highly porous and permeable sandstone layers as having porosity of 20%–30% and permeability to air of 300–1700 mD (Fig. 6). The TDS (total dissolved solids) of the brine sampled from the Broom Creek Formation ranged from 61,000 to 70,000 ppm. Additional analytical investigation will determine the relative permeability of CO2 and brine at reservoir temperature and pressure and investigate the potential for geochemical reactions between native brine, rock matrix, and injected CO2. Finally, geomechanical properties of the cap rock formation will be determined to validate the maximum injection threshold of the system. Results of all laboratory investigations along with reprocessed seismic data are being used to significantly improve the technical understanding of the geologic storage complex present in the study areas and verify assumptions made about the storage potential of the study areas in prior regional assessments. Preliminary analysis of the newly acquired core supports earlier broad assessments that the Broom Creek Formation would be an excellent target for CO2 storage. The new core and logs, augmented by both newly collected and reprocessed legacy seismic data, are being used to develop 3-D geocellular models of the target storage zone in the area. The geocellular models provide the foundation for numerical, multiphase fluid flow, geochemical, and geomechanical simulation efforts to accurately predict potential CO2 and pressure plume extents at both storage areas based on the premise of a 2-Mt-a-year injection rate. Understanding the potential extent of injected CO2 provides a foundation for the magnitude of future pore space leasing requirements; monitoring, verification, and accounting activities; and development of business case scenarios.
paucity of data on the Broom Creek Formation, which increases the uncertainty with respect to its geologic characteristics in the proposed study region. To reduce the technical and nontechnical uncertainty with respect to confirming the feasibility of establishing a certifiable large-scale commercial CO2 storage site, new geologic data were needed. As such, a major component of the NDSC project was to collect localized characterization data of the Broom Creek Formation in central North Dakota. The pillar of this characterization effort was the drilling of two new stratigraphic test wells into the Broom Creek Formation to collect core, geophysical logs, water samples, and pressure data. Analysis and interpretation of these new data will be augmented by analysis of select reprocessed existing 3-D and 2-D seismic data sets and the collection of a new 2-D line of seismic data. The two new characterization wells, one in each of the proposed project areas (Fig. 4), were completed in the winter of 2017–2018. The first stratigraphic test well (Flemmer-1) was located approximately 16 km (10 miles) west of the AVS–DGC facilities and within the boundaries of an existing 3-D seismic survey, a portion of which was purchased, reprocessed, and is being interpreted. Siting the stratigraphic test well within the bounds of the existing seismic data will allow the extrapolation of measurements and interpretations from well log and core data to provide increased understanding of the spatial distribution of geologic and petrophysical properties within the saline Broom Creek Formation. The Flemmer-1 well was drilled to a depth of 2070 m (6790 feet) and yielded 100 m (330 feet) of core (Fig. 5) covering the entire thickness of the Broom Creek Formation along with a portion of the cap rock (Opeche Shale) and underlying Amsden Formation. The Broom Creek section of the core (80 m, 260 feet) comprises 52 m of high-permeability (> 300 mD) sandstone (169 feet), with the balance of the formation thickness comprising interbedded siltstones, shales, and anhydrite. The second stratigraphic test well (BNI-1) was located just west of MRY on property owned by BNI Energy, a project partner. Using new and existing equipment, the EERC acquired a 2-D seismic line through the test well to tie the geology observed at the well to an existing legacy seismic line, which was also purchased and interpreted. The BNI-1 well was drilled to a depth of 1634 m (5360 feet) and yielded 96 m (315 feet) of core which included 83 m of Broom Creek. The Broom Creek comprises 38 m (125 feet) of high-permeability (> 300 mD) sandstone and 45 m of interbedded siltstones, shales, and anhydrite. As with the Flemmer-1 well, the BNI-1 core included a portion of the cap rock and underlying formation. After coring and testing, both wells were successfully plugged and abandoned.
4. Nontechnical challenges Although central North Dakota is an exceptional candidate area for implementing a commercial-scale (50+ Mt of CO2) geologic storage project from a geologic standpoint, the prospect of successfully executing such an endeavor faces several nontechnical challenges. From a broad CCS (carbon capture and storage) perspective, elements such as public acceptance, financial investment, regulatory hurdles, and legalities associated with pore space ownership and long-term liability are often cited as the primary nontechnical challenges. 4.1. Economics The NDCS project is examining specific economic needs and incentives in place to make at least one of the proposed scenarios economically feasible for the project partners. As recognized by DOE and others, the lack of economic incentive is the primary obstacle curtailing 49
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Fig. 4. Map illustrating the two study regions of the North Dakota CarbonSAFE project.
financial investment in CO2 storage projects. Although broader-scale incentives are generally missing, state and federal programs are available that provide tax incentives and loan opportunities. From a North Dakota standpoint, the potential to supply CO2 to a number of promising conventional CO2 EOR fields along an existing CO2 pipeline provides an opportunity to generate a revenue stream to offset capture and storage costs. This potential could be orders of magnitude higher with ongoing and successful research into EOR methods in the Bakken petroleum system (Sorensen et al., 2015, 2016). A memorandum of understanding was signed by ACE, Minnkota, BNI Energy, and the EERC on August 22, 2016, to facilitate further collaboration on the development of an integrated CCS strategy, known as “Project Tundra,” to promote and develop CO2 EOR offsets (Project Tundra, 2018). 4.2. Regulatory Regulatory frameworks associated with the geologic storage of CO2 have been developed to various extents in several states and at the federal level. Conforming to those regulations represents a notable challenge. Within North Dakota, progressive legislation has built successful, long-term subsurface management of its hydrocarbon resources and has been enacted to facilitate the geologic storage of CO2 either in saline reservoirs or associated with EOR operations. On the federal level, the promulgation of Class VI well regulations by the U.S. Environmental Protection Agency (EPA) in 2010 set exacting standards for the construction of CO2 injection wells and formally defined the criteria for determining area of review (AOR). To bring the enforcement of these regulations under control of the state with the federal government providing oversight, North Dakota applied for, and received, primary regulatory authority (primacy) over Class VI injection well activities (U.S. Environmental Protection Agency, 2018). Testimony to the North Dakota Legislative Council concluded that when primacy of federal regulations is extended to the state there is less of an argument
Fig. 5. Samples of Broom Creek sandstone core from the Flemmer-1 stratigraphic test well. 50
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Fig. 6. Core porosity and permeability data for the Flemmer-1 well.
that national lawsuits affect state programs. In the case of establishing a commercial-scale CO2 storage project in North Dakota, this philosophy allows for capitalizing on local knowledge and ensuring timeliness in acquiring necessary permits. In summary, now that North Dakota has been granted primacy, the risk of establishing the permitting pathway to a CO2 storage project is substantially reduced. The issues of pore space ownership and long-term liability have been addressed through state legislation. Specifically, the state has determined that the owner of the surface lands is the owner of the underlying pore space and that this ownership cannot be severed under any agreement; pore space ownership transfers to any new surface land owner. The state has also assumed long-term liability for any sequestered CO2, taking ownership of liability after issuing a CO2 storage operator a Certificate of Site Closure, which indicates that the operator has fulfilled all necessary requirements to ensure permanent storage (North Dakota Century Code, 2019 § 38-22). 4.3. Outreach Despite having a CO2 storage target with promising geologic properties and industry willingness, a potential CO2 storage project can still face opposition if the local community is not on board with the project. Thus an important aspect of a feasibility study is to gauge the level of public acceptance for a potential CO2 storage project. Knowing that public acceptance can hinge on proper and early communication regarding what a CCS project entails, the impact of effective public outreach cannot be overstated. As part of the NDCS, project outreach to stakeholder groups and the public is occurring through individual contact, meetings, wellsite tours (Fig. 7), and open house formats. An Outreach Advisory Group comprising representatives of the project partners and key stakeholders was formed to advise on the development of
Fig. 7. Local high school students visiting the BNI-1 wellsite during drilling to learn about the NDCS project.
plans, activities, and products to ensure consistent messaging targeted at local audiences. Products include general audience presentation slides; general audience project posters; project-focused video shorts for use on the Internet and in presentations; and a media kit comprising general project information, graphics, press releases, and frequently asked questions. A short video (˜8 min) is also being produced to describe how North Dakota is well positioned to meet the energy challenges of a low-carbon future through the safe, permanent storage of CO2 deep underground. Based on input from technical experts and 51
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Fig. 8. Leveraging North Dakota’s infrastructure and regulatory framework for CO2 management for the success of the NDCS Program.
previously attempted. The NDCS project seeks to provide a road map for future development of a commercial CCS project. Until recently, the necessary combination of economic incentives, regulatory requirements, and technical understanding has not been in place. An ideal climate now exists to pursue a large-scale integrated CCS effort because of recent tax incentive programs (U.S. Congress House of Representatives, 2018) and progressive North Dakota pore space ownership and long-term liability laws (North Dakota Century Code, 2019, Chapter 38-22) coupled with the state’s primacy of CO2 injection wells (Class VI [U.S. Environmental Protection Agency, 2018]) (Fig. 8). To lay the groundwork for future phases of this project, a permitting plan incorporating applicable local, state, and federal regulations is being developed with guidance from officials who oversee North Dakota’s primacy of EPA Class VI UIC wells. In addition, there is a growing demand for low- carbon energy sources. North Dakota is at the forefront of energy development and production, and the North Dakota energy industry is motivated to provide solutions to challenges presented by that demand. The state continues to investigate long-term strategies that incorporate all energy resources—traditional and emerging—to meet the nation’s growing energy demand in an environmentally responsible manner. This project will lead to expanded opportunities for the state’s coal and other energy industries and ensure the success of the CarbonSAFE Program.
partners, the video short will provide a concise and consistent set of North Dakota-focused messages on the topic of carbon storage addressing key concerns of area stakeholders. The video will focus on how and why CO2 storage makes sense for North Dakota and on how science and North Dakota regulatory agencies would ensure safe, effective CO2 storage operations. 4.4. Risk assessment Successful implementation of geologic storage projects for CO2 requires developers to assess candidate sites based on a number of site selection criteria, such as storage capacity, economics, regulatory constraints, and potential risks. Risk assessment helps guide geologic storage implementation by guiding stakeholders through the steps involved in identifying and characterizing pertinent risks; proactively developing methods to mitigate the impacts from unacceptable risks; and integrating risk management with project management, design, and implementation. A baseline risk assessment workshop was conducted where EERC project team members led major project participants and other stakeholders through a process to identify potential technical and nontechnical risks that may preclude candidate storage complexes within the two proposed study areas from serving as commercial storage sites. A draft risk register was generated based on the discussion at the workshop. The register provides specific risk factors that will be considered as part of a future scoring process and will help identify items that may require mitigation should the principal risk category be ranked as unacceptable at the conclusion of the risk assessment process. Quantitative assessments of each identified risk will be made by assessing and scoring the probability that a risk event will occur and the resulting impact if it does occur. Once the risk assessment has been completed, a risk treatment strategy will be formulated. Risk treatment includes several different strategies for negative risks, including avoidance, transfer, mitigation, monitoring, and acceptance, and for positive risks, including exploitation, sharing, enhancing, and acceptance.
DOE disclaimer This paper was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.
5. Summary Every CCS project site offers unique opportunities and challenges, and the NDCS project will bring advances in knowledge, technology, and techniques to address these opportunities to advance global knowledge in CCS. Although aspects of these challenges have been addressed through prior research or various legislative actions, an integrated project that seeks to address these challenges and leverage previous efforts to conduct a commercial-scale CCS project has not been
Acknowledgments This material is based upon work supported by the U.S. Department of Energy National Energy Technology Laboratory under Award No. DE-FE0029488. The authors would like to acknowledge and thank the project’s partners for their participation and generous support, 52
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including Allete Clean Energy, Basin Electric Power Cooperative, BNI Energy, Computer Modelling Group, North American Coal, Minnkota Power Cooperative, the North Dakota Lignite Research Council, Prairie Public Broadcasting, and Schlumberger. The authors would also like to thank CGG GeoSoftware for the use of their software during this work.
Provide Critical Insights on EOR in Tight Oil Plays: American Oil & Gas Reporter, February, 8 P. (Accessed July 2018). www.aogr.com/magazine/cover-story/ historical-bakken-test-data-provide-critical-insights-on-eor-in-tight-oil-p. Sorensen, J., Bailey, T., Dobroskok, A., Gorecki, C., Smith, S., Fisher, D., Peck, W., Steadman, E., Harju, J., 2009. Characterization and Modeling of the Broom Creek Formation for Potential Storage of CO2 From Coal-fired Power Plants in North Dakota: Search and Discovery Article #80046. Sorensen, J.A., Braunberger, J.R., Liu, G., Smith, S.A., Hawthorne, S.A., Steadman, E.N., Harju, J.A., 2015. Characterization and evaluation of the bakken petroleum system for CO2 enhanced oil recovery. Paper Presented at the SPE/AAPG/SEG Unconventional Resources Technology Conference July 20–22, 2015, URTeC Paper No. 2169871. U.S. Congress House of Representatives, 2018. Bipartisan Budget Act of 2018: H.R. 1892–115th Congress, Section 41119, Enhancement of Carbon Dioxide Sequestration Credit. U.S. Environmental Protection Agency, 2018. State of North Dakota Underground Injection Control Program – Class VI Primacy Approval: Federal Register, 83 FR 17758, 40 CFR 147, Document No. 2018-08425, April 24, 2018. pp. 17758–17761. Ziebarth, H.C., 1972. The Stratigraphy and Economic Potential of Permo-pennsylvanian Strata in Southwestern North Dakota [Ph.D. Dissertation]. University of North Dakota, Grand Forks, North Dakota 414 p.
References North Dakota Century Code, Chapter 38-22—carbon dioxide underground storage: 6 p. Peck, W.D., Glazewski, K.A., Braunberger, J.R., Grove, M.M., Bailey, T.P., Bremer, J.M., Gorz, A.J., Sorensen, J.A., Gorecki, C.D., Steadman, E.N., 2014. Broom Creek Formation Outline: Plains CO2 Reduction (PCOR) Partnership Phase III Value-added Report for U.S. Department of Energy National Energy Technology Laboratory Cooperative Agreement No. DE-FC26-05NT42592, EERC Publication 2014-EERC-0909. North Dakota, Energy & Environmental Research Center, August, Grand Forks. Project Tundra, 2018, www.projecttundrand.com (Accessed August 2018). Rygh, M.E., 1990. The Broom Creek Formation (Permian), in Southwestern North Dakota—depositional Environments and Nitrogen Occurrence [Master’s Thesis]. University of North Dakota, Grand Forks, North Dakota 189 p. Sorensen, J.A., Hamling, J.A., 2016. Enhanced Oil Recovery—Historical Bakken Test Data
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