(413e) North Dakota Carbonsafe – a Success Story

On January 21, 2022, the North Dakota Industrial Commission approved the creation of, and authorized the storage of lignite-generated carbon dioxide in, two storage facilities situated in Oliver County, North Dakota.

Under the Safe Drinking Water Act, the U.S. Environmental Protection Agency (EPA) granted the state of North Dakota primary enforcement responsibility (primacy) under its underground injection control (UIC) program in 2018 for Class VI injection wells. Minnkota Power Cooperative, Inc. (Minnkota), in association with the Energy & Environmental Research Center (EERC), developed its storage facility permit applications with support from the U.S. Department of Energy Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiative, Phase III, and secured the state’s second and third such permits. Over the past several years via the CarbonSAFE program, the EERC and Minnkota conducted commercial-scale site characterization and permitting of two deep saline formations for the geologic storage of anthropogenic CO₂ emissions. These storage horizons will collectively and permanently store nearly 4 million metric tons (MMt) of CO₂ per year, captured as part of Minnkota’s Tundra SGS (secure geologic storage) project. Minnkota’s ambitious initiative to build one of the world’s largest postcombustion carbon capture and storage (CCS) facilities in central North Dakota demonstrates a clear business case and supportive drivers for CCS. Minnkota’s primary generating resource is the 705-MW, two-unit Milton R. Young Station (MRYS), a minemouth lignite coal-fired power plant. The lignite used as the fuel for electrical generation also serves as the primary source of the captured CO₂ that will be securely stored by Tundra SGS.

The proposed Tundra SGS injection site, located in close proximity to the MRYS, will include up to three injection wells, one dedicated monitoring well for the lowest underground source of drinking water, and one deep subsurface monitoring well. Two permitted wells are approved for the injection of CO₂ into the ~4750-ft (1450 m)-deep, 250-ft (76 m)-thick Broom Creek Formation (sandstone, siltstone, anhydrite), with the option for a third well for injection of CO₂ into the interbedded sandstones, siltstones, and carbonates of the Black Island–Deadwood Formation interval (~9300 ft [2835 m] deep; 182 ft [55 m] thick).

To acquire the necessary near-surface and subsurface information to fully characterize the site and meet the requirements for the storage facility permits, two stratigraphic test wells were drilled, cored (>1300 feet [400 m] of core), and logged. In addition, approximately 21 miles
(34 km) of 2D seismic data and 18 square miles (47 km²) of 3D seismic data were acquired in the project area near MRYS and integrated with the geophysical logs collected from the stratigraphic test wells. Geophysical well logs were used to pick formation top depths and interpret lithology and petrophysical properties.

The site-specific data collected were used to validate the presence and quality of the upper and lower seals and inform the construction of geologic models, reservoir simulations, geochemical modeling, and geomechanical analysis to demonstrate the suitability of the two CO₂ storage complexes. Both large domain (5500 mi² [14,245 km²]) and small domain (575 mi² [1490 km²]) versions of these geomodels were created to simulate CO₂ plume growth and large-scale pressure plume effects in each potential storage formation. The resulting geologic models were used in reservoir simulation to delineate the extent of the necessary pore space for CO₂ storage. These map extents were also used to identify which landowners would need to be engaged in the process to unitize (amalgamate) the required pore space.

Measurements taken from two stratigraphic test wells in the project area revealed that the Broom Creek Formation is naturally overpressured, which results in an infinite area of review (AOR) based on EPA standard methodologies. To derive a reasonable and defensible AOR for injection into the Broom Creek Formation, a risk-based AOR delineation process was used.

The EERC and the project team leveraged North Dakota’s Class VI primacy status to prepare and submit successful applications for two storage facility permits and associated monitoring and UIC Class VI injection wells. The applications and their supporting documents were prepared in accordance with the North Dakota Century Code and the North Dakota Administrative Code and show the effectiveness of working with a state that has been granted Class VI primacy.