Simulation of the impact of faults on CO2 injection into sandstone reservoirs. Issue 3 (8th April 2013)

• Record Type: Journal Article
• Authors: Pasala, S. M.; Forster, C. B.; Deo, M.; Evans, J. P.
• Is Part Of: Geofluids. Volume 13:Issue 3(2013:Aug.)
• Page Start: 344
• Page End: 358
• Publication Date: 2013-04-08
• Subjects: Hydrogeology -- Periodicals; Sedimentary basins -- Periodicals; Fluids -- Migration -- Periodicals; Groundwater flow -- Periodicals; Geothermal resources -- Periodicals; Fluid dynamics -- Periodicals; Earth -- Crust -- Periodicals; 551.49
• DOI: 10.1111/gfl.12029
• Languages: English
• ISSNs: 1468-8115

Abstract

<abstract abstract-type="main" id="gfl12029-abs-0001"> <title>Abstract</title> <p>Numerical simulations of multiphase CO<sub>2</sub> behavior within faulted sandstone reservoirs examine the impact of fractures and faults on CO<sub>2</sub> migration in potential subsurface injection systems. In southeastern Utah, some natural CO<sub>2</sub> reservoirs are breached and CO<sub>2</sub>‐charged water flows to the surface along permeable damage zones adjacent to faults; in other sites, faulted sandstones form barriers to flow and large CO<sub>2</sub>‐filled reservoirs result. These end‐members serve as the guides for our modeling, both at sites where nature offers 'successful' storage and at sites where leakage has occurred. We consider two end‐member fault types: low‐permeability faults dominated by deformation‐band networks and high‐permeability faults dominated by fracture networks in damage zones adjacent to clay‐rich gouge. Equivalent permeability (<italic>k</italic>) values for the fault zones can range from <10<sup>−14</sup> m<sup>2</sup> for deformation‐band‐dominated faults to >10<sup>−12 </sup>m<sup>2</sup> for fracture‐dominated faults regardless of the permeability of unfaulted sandstone. Water–CO<sub>2</sub> fluid‐flow simulations model the injection of CO<sub>2</sub> into high‐<italic>k</italic> sandstone (5 × 10<sup>−13 </sup>m<sup>2</sup>) with low‐<italic>k</italic> (5 × 10<sup>−17 </sup>m<sup>2</sup>) or high‐<italic>k</italic> (5 × 10<sup>−12 </sup>m<sup>2</sup>) fault zones that correspond to deformation‐band‐ or fracture‐dominated faults, respectively. After 500 days, CO<sub>2</sub> rises to produce an inverted cone of free and dissolved CO<sub>2</sub> that spreads laterally away from the injection well. Free CO<sub>2</sub> fills no more than 41% of the pore space behind the advancing CO<sub>2</sub> front, where dissolved CO<sub>2</sub> is at or near geochemical saturation. The low‐<italic>k</italic> fault zone exerts the greatest impact on the shape of the advancing CO<sub>2</sub> front and restricts the bulk of the dissolved and free CO<sub>2</sub> to the region upstream of the fault barrier. In the high‐<italic>k</italic> aquifer, the high‐<italic>k</italic> fault zone exerts a small influence on the shape of the advancing CO<sub>2</sub> front. We also model stacked reservoir seal pairs, and the fracture‐dominated fault acts as a vertical bypass, allowing upward movement of CO<sub>2</sub> into overlying strata. High‐permeability fault zones are important pathways for CO<sub>2</sub> to bypass unfaulted sandstone, which leads to reduce sequestration efficiency. Aquifer compartmentalization by low‐permeability fault barriers leads to improved storativity because the barriers restrict lateral CO<sub>2</sub> migration and maximize the volume and pressure of CO<sub>2</sub> that might be emplaced in each fault‐bound compartment. As much as a 3.5‐MPa pressure increase may develop in the injected reservoir in this model domain, which under certain conditions may lead to pressures close to the fracture pressure of the top seal.</p> </abstract>