The Government of Alberta Carbon Sequestration Tenure Management plan currently focuses on the permanent disposal of carbon dioxide into zones deeper than 1,000m that have no associated hydrocarbon recovery. Many deeper zones that were tested in the ‘50s and ‘60s for hydrocarbons are water-bearing and have morphed into potential CO2 sequestration targets. These deep zones avoid some of the risks associated with CO2-EOR and depleted oil and gas pools, including the presence of legacy wellbores or potential future hydrocarbon development. On March 3, the Government released a Request for Full Project Proposals from companies interested in building, owning, and operating carbon sequestration hubs outside of the industrial heartland region, with an application deadline of May 2, 2022 (Government of Alberta, 2022).
While the Basal Cambrian Sandstone (BCS) has received most of the buzz (figure 1)—both the Shell Quest (north of Edmonton) and the Aquistore (near the SK/USA border) projects sequester CO2 in that aquifer—the BCS might not be the optimal target in many areas throughout Alberta. Canadian Discovery’s (CDL) work-to-date has shown that there are other Cambrian, Ordovician, Silurian and Devonian Elk Point aquifers that could better serve as CO2 storage candidates in some locations, while in other areas a project may require multiple targets to meet storage needs.
CDL Carbon Storage Workflow
CDL has developed a fully integrated subsurface workflow to characterize the suitability of deep saline aquifers for carbon storage in Alberta and other provinces, and can provide area-specific subsurface expertise. The workflow combines geological and hydrodynamics evaluations (figure 2), and is focused on minimizing CCUS risk at the regional and, when data are available, at the local level by:
- Categorizing the subsurface
- Identifying reservoirs and seals
- Identifying saline aquifers
- Protecting groundwater
The geological evaluation ensures that target zones meet critical parameters including reservoir-seal pairs, porosity and permeability requirements, and provides rock volume data (area and thickness) and reservoir data to determine the pore volume available for CO2 storage capacity calculations. Figure 3 shows examples of CDL’s geological mapping of the Basal Cambrian Sandstone from publicly available data from Shell’s Quest application. In the vicinity of Shell’s injector wells, the BCS is over 2,000m deep, 30–40m thick, and has porosity up to 23% and permeability over 7 darcies (Donaldson, 2020). The estimated pore volume is around 520 e6 m3/twp.
The hydrodynamics evaluation ensures that the target zones meet regional scale flow and containment requirements, and also provides CO2 density estimates for storage capacity calculations, an estimate of the density difference between the water and CO2 in a saline aquifer, and some confirmation of permeability estimates through the analysis of DSTs. Figure 4 shows examples of CDL’s hydrodynamics mapping of the BCS. In the vicinity of Shell’s injector wells, temperature, pressure and CO2 density average 65°C, 20,460 kPa and just over 690 kg/m3, respectively.
Estimating CO2 Storage Capacity in Saline Aquifers
Estimating CO2 storage capacity in saline aquifers requires determining the available rock pore volume, the depth-specific density of carbon dioxide and the storage efficiency factor, Es. The aforementioned lack of data for zones at depth makes evaluating saline aquifer capacity more difficult than for depleted oil and gas pools.
The storage efficiency factor accounts for the presence of both water and CO2, and is a function of reservoir properties and fluid dynamics including:
- Geometry (structural vs dynamic traps)
- Gravity segregation
- Permeability distribution
- Pressure limitations
Initial estimates of Es are based on data distribution and quality, the expected continuity of the reservoir from analogues, and the scale of the storage estimate (local or regional). The storage efficiency factor changes with scale—there is increased potential for these factors to negatively impact storage with increasing areal extent and heterogeneity (i. e. at regional scales). The effective CO2 storage capacity for the BCS in the vicinity of Shell’s injector wells is expected to be between 50 to 70 MT/twp, depending on the efficiency factor used.
To learn more about how CDL’s detailed geological and hydrodynamics evaluations will assist with your company’s Full Project Proposal to the Government of Alberta, or to learn more about CDL’s upcoming Alberta Deep Saline Aquifer CO2 Sequestration Study contact us at 403.269.3644 or email@example.com.
Bachu, S., 2006. The potential for geological storage of carbon dioxide in northeastern British Columbia. Summary of Activities 2006, BC Ministry of Energy, Mines and Petroleum Resources, p 1-48.
DOE-NETL. 2015. DOE-NETL. Carbon Storage Atlas Fifth Edition. US Department of Energy Office of Fossil Energy, National Energy Technology Laboratory
Donaldson, W. S. 2020. Shell’s Quest for the Holy Grail of Carbon Capture and Storage. Accessed March 2022. https://digest.canadiandiscovery.com/article/7299
Government of Alberta. 2022. Request for Full Project Proposal For Carbon Sequestration Hubs March 3, 2022.
Peck, W.D., Liu, G., Klenner, R., Gorecki, C.D., Steadman, E.M. and Harju, J.A. 2014. “Storage Capacity and Regional Implications for Large-Scale Storage in the Basal Cambrian System.” PCOR Phase III, Task 16 Deliverable D92, Plains CO2 reduction (PCOR) Partnership.
Shell Canada. 2010. Quest Carbon Capture and Storage Project. Directive 65: Application for a CO2 Acid Gas Storage Scheme.