CO2 storage in deep saline aquifers: something old, something new


The Government of Alberta’s Carbon Sequestration Tenure Management Plan currently focuses on permanent removal of carbon dioxide in areas deeper than 1,000m that do not have associated hydrocarbon recovery. . Many deeper areas that were tested in the 1950s and 1960s for hydrocarbons are aquifers and have turned into potential CO2 sequestration goals. These deep zones avoid some of the risks associated with CO2-EOR and depleted oil and gas deposits, including the presence of old wellbores or potential future development of hydrocarbons. On March 3, the government issued a request for full project proposals from companies interested in building, owning and operating carbon sequestration centers outside the industrial heartland region, with an application deadline. set for May 2, 2022. (Government of Alberta, 2022).

While the Basal Cambrian Sandstone (BCS) received the most buzz (Figure 1)— the Shell Quest (north of Edmonton) and Aquistore (near the Saskatchewan-US border) projects sequester CO2 in this aquifer—BCS may not be the optimal target in many parts of Alberta. Work to date by Canadian Discovery (CDL) has shown that there are other Cambrian, Ordovician, Silurian and Devonian aquifers at Elk Point that could better serve as CO2 candidates for storage 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 region-specific subsurface expertise. The workflow combines geological and hydrodynamic assessments (Figure 2)and aims to minimize the risk of CCUS at the regional level and, where data is available, at the local level by:

  • Basement categorization
  • Identification of tanks and seals
  • Identification of saline aquifers
  • Protect groundwater

Geological assessment

Geological evaluation ensures target areas meet critical parameters, including reservoir-seal pairs, porosity and permeability requirements, and provides rock volume (area and thickness) and reservoir data to determine the pore volume available for CO2 storage capacity calculations. picture 3 shows examples of CDL’s geological mapping of the Basal Cambrian sandstone from publicly available data from the Shell’s Quest app. Near Shell injection wells, the BCS is over 2,000m deep, 30-40m thick, and has a porosity of up to 23% and a permeability of over 7 darcies. (Donaldson, 2020). The estimated pore volume is about 520 e6 m3/twp.

Hydrodynamic evaluation

Hydrodynamic assessment ensures target areas meet regional flow and containment requirements, and also provides CO2 density estimates for storage capacity calculations, an estimate of the density difference between water and CO2 in a saline aquifer, and some confirmation of permeability estimates by DST analysis. Figure 4 shows examples of hydrodynamic mapping of the BCS by CDL. Near Shell injection wells, temperature, pressure and CO2 average density 65°C, 20,460 kPa and just over 690 kg/m3respectively.

CO estimate2 Storage capacity in saline aquifers

CO estimate2 storage capacity in saline aquifers requires determining the pore volume of rock available, the depth-specific carbon dioxide density, and the storage efficiency factor, Es. The aforementioned lack of data for areas at depth makes assessing the capacity of saline aquifers more difficult than for depleted oil and gas fields.

The storage efficiency factor takes into account the presence of water and CO2and is a function of reservoir properties and fluid dynamics, including:

  • Geometry (structural vs dynamic traps)
  • Heterogeneity
  • Gravity segregation
  • Distribution of permeability
  • Pressure limits

Initial estimates of Es are based on the distribution and quality of the data, the expected reservoir continuity from analogues, and the scale of the storage estimate (local or regional). The storage efficiency factor changes with scale – there is an increased potential for these factors to negatively impact storage with increasing area extent and heterogeneity (i.e. i.e. on a regional scale). Efficient CO2 BCS storage capacity near Shell injection wells is expected to be between 50 and 70 MT/twp, depending on the efficiency factor used.

To learn more about how CDL’s detailed geological and hydrodynamic assessments will help with your company’s comprehensive project proposal to the Government of Alberta, or to learn more about CDL’s upcoming projects CO from the deep saline aquifer of Alberta2 Sequestration study contact us at 403.269.3644 or [email protected]

The references

Bachu, S., 2006. The potential for carbon dioxide geological storage 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. U.S. Department of Energy Office of Fossil Energy, National Energy Technology Laboratory

Donaldson, WS 2020. Shell’s Quest for the Holy Grail of Carbon Capture and Storage. Accessed March 2022.

Government of Alberta. 2022. Request for Full Project Proposal for Carbon Sequestration Centers March 3, 2022.

Peck, W.D., Liu, G., Klenner, R., Gorecki, CD, Steadman, EM, and Harju, JA 2014. “Storage Capacity and Regional Implications for Large-Scale Storage in the Basal Cambrian System.” PCOR Phase III, Task 16 Deliverable D92, CO Plains2 (PCOR) Partnership.

Shell Canada. 2010. Quest Carbon Capture and Storage Project. Directive 65: Request for CO2 Diagram of acid gas storage.


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