Impact-driven pressure management via targeted brine extraction—Conceptual studies of CO2 storage in saline formations

Abstract

Large-scale pressure buildup in response to carbon dioxide (CO 2 ) injection in the subsurface may limit the dynamic storage capacity of suitable formations, because elevated pressure can impact caprock integrity, induce reactivation of critically stressed faults, drive CO 2 and/or brine through conductive features into shallow groundwater resources, or may affect existing subsurface activities such as oil and gas production. It has been suggested that pressure management involving the extraction of native fluids from storage formations can be used to control subsurface pressure increases caused by CO 2 injection and storage, thereby limiting the possibility of unwanted effects. In this study, we introduce the concept of "impact-driven pressure management (IDPM)", which involves optimization of fluid extraction to meet local (not global) performance criteria (i.e., the goal is to limit pressure increases primarily where environmental impact is a concern). We evaluate the feasibility of IDPM for a hypothetical CO 2 storage operation in an idealized multi-formation system containing a critically stressed fault zone. Using a newly developed analytical solution, we assess alternative fluid extraction schemes and test whether a predefined performance criterion can be achieved, in this case the maximum allowable pressure near the fault zone. Alternative strategies for well placement are evaluated, comparing near-injection arrays of extraction wells with near-impact arrays. Extraction options include active extraction wells and (passive) pressure relief wells, as well as combinations of both, with and without reinjection into the subsurface. Our results suggest that strategic well placement and optimization of extraction may allow for a significant reduction in the brine extraction volumes. Additional work is required in the future to test the general concept of IDPM for more complex and realistic CO 2 storage scenarios.Page 2 IntroductionFor geologic carbon sequestration (GCS) to have a positive effect on reducing or at least stabilizing atmospheric carbon levels, the anticipated volume of CO 2 that would need to be injected in the subsurface is very large (e.g., Zhou and Birkholzer, 2011). One single coal-fired power plant alone may emit as much as 5-10 million tons of CO 2 per year. Unless storage is conducted in depleted oil or gas reservoirs, where fluids have been previously extracted as a result of production, the pore space in suitable storage formations is already filled with saline water. The CO 2 volume injected into saline formations then needs to be accommodated by expansion of reservoir pore space and compression of fluid in response to pressure buildup and, if reservoir boundaries are open, by pressure-driven migration of native brines into neighboring formations. Large and lasting pressure perturbation in the subsurface is an expected feature of GCS operations (e.g., Nicot, 2008;, and careful monitoring and management of pressure increases is generally considered of great importance to the saf...

Regional-scale brine migration along vertical pathways due to CO<sub>2</sub> injection – Part 2: A simulated case study in the North German Basin

“…(Cihan et al, 2011) developed an analytical model capable of handling multilayered systems considering diffuse leakage (through aquitards) and focused leakage (abandoned well and fault zones). The same analytical model is also applied in (Birkholzer et al, 2012), where pressure-management strategies are compared. (Zeidouni, 2012) presented an analytical model for determining brine flow through a permeable fault zone into aquifers separated by impermeable aquitards.…”

Risk, Liability, and Economic Issues with Long-Term CO2 Storage—A Review

“…This contrasts with far lower (or approximately zero) costs of passive pressure management, where the pressure is allowed to normalize through natural migration of the in situ fluids out of the reservoir, the slow dissolution of the CO 2 into those fluids, or some other natural mechanism. If active pressure management is necessary but the costs of this important method of risk mitigation are prohibitive, then a substantial portion of the technically accessible storage resource (TASR) may not meet economic feasibility criteria for CO 2 storage capacity under current regulations (Schrag 2009;Birkholzer et al 2012Birkholzer et al , 2015Breunig et al 2013;Heidug 2013;Cihan et al 2014;Bachu 2015;Pawar et al 2015).…”

An iterative global pressure solution for the semi-analytical simulation of geological carbon sequestration

“…For example, [29] introduced fluid and matrix compressibility to the similarity solutions governing single-well CO 2 injection presented in [33], while [43] presented a single-phase semi-analytical solution for large scale injection-induced pressure perturbation and leakage in a laterally bounded aquifer-aquitard system. Also, a semi-analytical model estimating multi-phase fluid flux through a single caprock perforation was developed by [27] to determine optimal injection intervals based upon trapping effects for secure CO 2 storage in saline aquifers and [5,9,10] presented and applied a single-phase semi-analytical model for both forced and diffuse leakage in a multi-layer system. Finally, [4] combined solutions presented by [21], [38], and [42] to create a semi-analytical solution for approximating the area of potential impact from a single CO 2 injection well.…”