Approach to Evaluating the CO2 Storage Capacity in Devonian Deep Saline Aquifers for Emissions from Oil Sands Operations in the Athabasca Area, Canada

Abstract

The Province of Alberta is the largest CO 2 emitter in Canada, with annual emissions close to 250 Mt, of which about 55 Mt CO 2 originate from oil production from oil sands. Geological storage of CO 2 has been identified as the major component of the strategy for reducing greenhouse gas emissions from oil sands operations, which are located in the Athabasca area close to the shallow eastern edge of the Alberta basin. Therefore, CO 2 storage in deep Devonian saline aquifers, located westward of the oil sands operations, may constitute a solution for storing CO 2 from these operations. A regional-scale study of the potential for storing CO 2 in deep Devonian saline aquifers in an area covering ~126,000 km 2 has been undertaken with the aim of identifying suitable sites for CO 2 storage. The Devonian sedimentary succession consists of a succession of stacked sandstone and carbonate saline aquifers separated by intervening shaly and evaporitic aquitards and aquicludes. The approach taken in the study, illustrated in this paper, comprises 11 steps, including: 1) Geological mapping of 29 Devonian formations based on information from more than 34,000 wells; 2) Hydrostratigraphic delineation of the 13 deep saline aquifers identified in this succession; 3) Determination of hydraulic continuity between various aquifers, due to depositional or erosional events; 4) Determination of formation water salinity, which ranges from less than 4000 mg/L (the limit of protected groundwater in Alberta) to close to 440,000 mg/L; 5) Determination of pressures and temperatures in these aquifers, which vary, respectively, between 1 and 30 MPa and between 12 °C and 135 °C; 6) Determination of the CO 2 phase and density at the top of each aquifer, the latter varying between < 25 kg/m 3 where CO 2 is in gas phase to > 800 kg/m 3 where CO 2 is in supercritical state; 7) Determination of well-scale porosity distribution in each aquifer, which varies between 1% and 40%,, based on well logs in 8305 wells and core analyses in 5242 wells; 8) Determination of the areal distribution of CO 2 storage capacity in each aquifer, based on aquifer thickness and porosity, and CO 2 density; 10) Determination of the regions suitable for CO 2 storage in each aquifer based on legal and regulatory constraints and protection of hydrocarbon resources; 10) Determination of permeability distributions in each aquifer, which varies from < 1 mD to > 10 D, based on 214,194 core analyses in 5242 wells and 4318 drill stem tests in 3586 wells; and 11) Identification of target areas for CO 2 storage based on local storage capacity and permeability, both of which have to be high at the local scale. Eleven prospective areas in 10 deep saline aquifers, with a cumulative storage capacity of close to 4 Gt CO 2 , have been identified as a result of this process of evaluation, screening and selection.

Review of CO2 storage efficiency in deep saline aquifers

“…Thus, volumetric estimates of the CO 2 storage resource at the aquifer/regional scale would be broadly appropriate for estimating this resource using proper methodology that takes into account the specific characteristics of the aquifer being evaluated (e.g., Bachu et al, 2014;Peck et al, 2014), rather than arbitrary/constant values for the various parameters, as done in many evaluations performed and published in the late 2000s and early 2010s. These evaluations are an improvement over those performed up to the mid 2000s (see Bradshaw et al, 2007), but still are distorted by the approximations and simplifications used in establishing aquifer characteristics and use of storage efficiency coefficients.…”

An Assessment of the Net Fluid Balance in the Alberta Basin

“…While extensive sustainable fluid storage capacity appears to exist within this area, increasing injection rates and decreasing extraction rates may be reversing the historical regional depletion trend. This trend may be of significance in assessments of regional subsurface storage capacity and near-basement saline aquifer flow characteristics for this area, especially considering the potential for large-scale fluid injection in the basal saline aquifers from future carbon capture and storage activities [70, 98,99].…”

Carbon Storage Potential of North American Oil & Gas Produced Water Injection with Surface Dissolution

“…CO2 capture and storage (CCS) provides the single largest potential for CO2 emissions reduction, and saline aquifers and hydrocarbon reservoirs for enhanced recovery are obvious first choices as potential repositories. However, based on the CCS Development Council [18], it is desirable that CO2 storage operations be at least 800-1000 m deep. In addition, the great majority of oil and gas reservoirs, still in production, are underlain by deep saline aquifers such that storage of CO2 in these aqui-fers may materially impact oil and gas production; consequently, these aquifers or portions thereof may be excluded for CO2 storage in the near term.…”