North Dakota CarbonSAFE Phase III: Site Characterization and Permitting

Project Information

Characterization and Permitting

Flyout Menu
Menu

Project Home

Subsurface Characterization

Subsurface characterization includes the geologic characterization of the Inyan Kara, Broom Creek and Deadwood–Black Island Formations (planned reservoir units) and overlying sealing formations (the Skull Creek, “Opeche”, and Icebox Formations, respectively).

Storage Formation Porosity Permeability Formation Top Depth, ft Lithology Thickness, ft
Broom Creek (upper, middle, and lower sandstone-dominated intervals) 2-27% 0.06-2690 mD ~4,906 Sandstone
Dolostone
Dolomitic Sandstone
Anhydrite 		168
103
26
19
Black Island / Deadwood Formation (A-E) 3.4-15% 0.03-2060 mD ~9782.2-10,770.4 Sandstone
Dolostone
Limestone
 		38.9
92.3
60.9

Seismic Surveys
A 5-mile-long seismic source test and 6.5-mi2 3D seismic survey were acquired in 2019, and a 12-mi2 3D seismic survey and 21 miles of 2D seismic lines were acquired in 2020 The seismic data was used for assessment of the geologic structure, interpretation of interwell heterogeneity, and well placement. No structural features, faults, or discontinuities that would cause concern about seal integrity were observed in the seismic data.

Map showing the 2D and 3D seismic surveys in the Tundra SGS area.

2551 Feet of Core Collected
Two stratigraphic test wells were drilled to augment data available from the offset wells in the study area.

2,551 feet of core collected.

Step Rate Injection Test
Brine injectivity tests were conducted on both the Broom Creek and Deadwood storage formations in one of the cored stratigraphic test wells. The analysis of injectivity tests showed that core-indicated and modeled permeability distributions should be conservatively multiplied by 2.5× and 5× in the Broom Creek and Deadwood geologic models, respectively, prior to numerical simulations of CO2 injection using Computer Modelling Group’s (CMG’s) GEM equation-of-state reservoir simulator.

Step rate injection test.

Reservoir Model
Preliminary reservoir modeling results from both the Broom Creek and Deadwood formations did not indicate migration outside the storage facility area boundaries in either scenario. Storage facility area boundaries were established using a 20-year injection period, 5% CO2 saturation rate, and rounded outward to the nearest 40-acre tract.

Numerical simulation of CO2 injection in the sandstones of the Broom Creek Formation predicted the wellhead injection pressure (WHP) of both wells would not exceed 1700 psi during injection. Bottomhole pressures (BHPs) reached 3,035.1 and 3,018.3 psi for Liberty-1 and Unity-1 wells, respectively. For the Broom Creek CO2 plume boundary delineation, the CO2 plume boundary was modeled using operating assumptions of 20 years at a rate of an annual 4 MMt/year for the first 15 years and 3.5 MMt/year for Years 16 through 20. The reservoir simulation model indicated target injection rates were consistently achievable over 20 years of injection. A total of 77.5 MMt of CO2 would be injected into the Broom Creek Formation with two wells at the end of 20 years. Injected volumes were 41.1 and 36.4 MMt for the Unity-1 and Liberty-1 wells, respectively. A maximum formation pressure increase of 488 psi is estimated in the near-wellbore area during the injection period, which is below the determined maximum wellhead injection pressure of 1700 psi.
The Deadwood–Black Island reservoir model simulation for Phase 2 includes the McCall-1 well, drilled on the same pad as the Broom Creek wells. This model was constrained by wellhead injection pressure (WHP) and bottomhole fracture gradient without any injection rate constraint. Within the sandstones of the Black Island and Deadwood Formations, numerical simulation of CO2 injection predicted that injection BHP will not exceed 6,179 psi during injection operations, assuming a WHP limit of 2,800 psi is maintained. Cumulative CO2 injection at the above-described pressure conditions was 23.4 MMt over the 20 years of injection. The resulting average injection rate of CO2 into the Black Island and Deadwood Formations was 1.17 MMt/year. Near the wellbore area, a maximum increase of 1620 psi was estimated within the Black Island and Deadwood Formations.

Pore Space
North Dakota law grants title of the pore space in all strata underlying the surface of lands and waters to the overlying surface estate, i.e., the surface owner owns the pore space. Prior to initiating the storage of CO2, North Dakota statutes mandate that the storage operator obtain consent of landowners who own at least 60% of the pore space of the storage reservoir. Minnkota successfully secured voluntary consent from >95% of the landowners (by acreage, totaling 18,903 acres) prior to the amalgamation order.

Pore Space Access:

  • ~50 parcels of land
  • ~60 different landowners

Area of Review (AOR)
Results of a geologic model, created by Minnkota, were used to delineate the AOR. Data utilized included well logs, seismic, and core data. Well log data was used to pick formation tops, interpret lithology, estimate petrophysical properties, and determine a time–depth shift for seismic data in the lower confining zones, the upper confining zones, and the injection formations. Geostatistics were used to distribute petrophysical properties throughout the confining zones. Seismic data was used to reinforce interpolation of the formation tops to create structural surfaces, to distribute lithologies, and geologic properties in the model.

Based on the reservoir pressure obtained from J-LOC1, critical threshold pressure for the Broom Creek Formation exists prior to injection, i.e., the Broom Creek is overpressured. The methods described by EPA for estimating the AOR under the Class VI Rule were developed assuming that the storage reservoirs would be in hydrostatic equilibrium with overlying aquifers. Consequently, applying EPA methods to the Broom Creek Formation essentially results in an infinite AOR, which makes regulatory compliance infeasible. Applying a risk-based AOR approach essentially collapses the AOR to the minimum areal extent, as defined by North Dakota statute. This minimum AOR is a 1-mile buffer extent beyond the storage facility area boundary.

Based on the reservoir pressure obtained from J-LOC1, coupled with numeric simulations, the critical threshold pressure for this storage complex will be reached in the Black Island and Deadwood Formations during injection. The AOR shown in the Figure is the extent of the critical threshold pressure as determined using EPA methodology.

Tundra SGS map showing the storage facility area and AORs for both storage reservoirs – the Broom Creek and Deadwood Formations.

Based on the reservoir pressure obtained from J-LOC1, critical threshold pressure for the Broom Creek Formation exists prior to injection, i.e., the Broom Creek is overpressured. The methods described by EPA for estimating the AOR under the Class VI Rule were developed assuming that the storage reservoirs would be in hydrostatic equilibrium with overlying aquifers. Consequently, applying EPA methods to the Broom Creek Formation essentially results in an infinite AOR, which makes regulatory compliance infeasible. Applying a risk-based AOR approach essentially collapses the AOR to the minimum areal extent, as defined by North Dakota statute. This minimum AOR is a 1-mile buffer extent beyond the storage facility area boundary.

Based on the reservoir pressure obtained from J-LOC1, coupled with numeric simulations, the critical threshold pressure for this storage complex will be reached in the Black Island and Deadwood Formations during injection. The AOR shown in the Figure is the extent of the critical threshold pressure as determined using EPA methodology.

Storage Resources
The primary target, Broom Creek formation, is estimated to have potential to inject 77.5 MMt CO2 of prospective storage resource.

The secondary target, Deadwood-Black Island, is estimated to have potential to inject 23.4 MMt CO2 of prospective storage resource.

Permitting

Applicant: Dakota Gasification Company

Applicant: Minnkota Power Cooperative, Inc.

Major NDIC Permitting Requirements and Major Proposed Characterization Activities

First Coal-Fired Power Plan Permitted to Store CO2

CarbonSAFE North Dakota Storage Facility Permits -
Approved January 21, 2022
Public Hearing - Combined application were 1200+ page.
Over 7 hours of testimoney and responding to public comments.

For reliable, affordable electricity in our region, cleaner industries across the United States, and energy stability in societies around the world – Minnkota’s Project Tundra is helping develop the carbon capture technology necessary to meet our global climate goals, right in the heart of North Dakota. Learn more at ProjectTundraND.com.

Team

USA.gov
U.S. Department of Energy
DOE Office of Fossil Energy
DOE Office of Energy Efficiency & Renewable Energy
Office of Electricity Delivery & Energy Reliability

Employees Only
FOIA/Privacy Act
Web Policies
Privacy Policy
Disclaimer
Whistleblower Protection
Vulnerability Disclosure Program
Scroll to Top