CO2 Leakage Scenarios in Shale Overburden

Abstract

Potential CO2 leakage from deep geologic reservoirs requires evaluation on a site-specific basis to assess risk and arrange mitigation strategies. In this study, a heterogeneous and realistic numerical model was developed to investigate CO2 migration pathways and uprising time in a shaly overburden, located in the Malaysian off-shore. Fluid flow and reactive transport simulations were performed by TOUGHREACT to evaluate the: (1) seepage through the caprock; (2) CO2-rich brine leakage through a fault connecting the reservoir with seabed. The effect of several factors, which may contribute to CO2 migration, including different rock types and permeability, Fickian and Knudsen diffusion and CO2 adsorption in the shales were investigated. Obtained results show that permeability mainly ruled CO2 uprising velocity and pathways. CO2 migrates upward by buoyancy without any important lateral leakages due to poor-connection of permeable layers and comparable values of vertical and horizontal permeability. Diffusive flux and the Knudsen flow are negligible with respect to the Darcy regime, despite the presence of shales. Main geochemical reactions deal with carbonate and pyrite weathering which easily reach saturation due to low permeability and allowing for re-precipitation as secondary phases. CO2 adsorption on shales together with dissolved CO2 constituted the main trapping mechanisms, although the former represents likely an overestimation due to estimated thermodynamic parameters. Developed models for both scenarios are validated by the good agreement with the pressure profiles recorded in the exploration wells and the seismic data along a fault (the F05 fault), suggesting that they can accurately reproduce the main processes occurring in the system.

Potential Benefits of Horizontal Wells for CO2 Injection to Enhance Storage Security and Reduce Leakage Risks

“…This computed upward CO 2 velocity of 26 m/3000 years had the same magnitude compared with other numerical studies, such as 3 m/100,000 years [36], 8 m/ 100,000 years [58], and 1 to 77 m/1000 years [57]. The numbers are unequal due to differences in the models' properties and grid resolution and should be used only for qualitative comparison.…”

“…The invasion depth in caprock due to diffusion reached over 26 m after 3000 years using a vertical well (based on the values of CO 2 in the aqueous phase (CO 2(aq) ). The CO 2 gas saturation plume (CO 2(g) ) in Figure 7 was only 17 m thick, highlighting that the diffusive flow was more relevant than Darcy flow in the caprock, as concluded by Currenti et al [57] during the numerical investigation of CO 2 leakage scenarios in shale caprock. Higher capillary pressure, critical water saturation typical of the shale (Figure 3), and lower permeability all inhibited the CO 2 convective flow through the caprock.…”

“…Those results show that CO 2 penetration in the caprock is possible (mainly by diffusion) and can generate leakage to the surface or other non-target zones when the migration is associated with flow through fault/fracture potentially activated by the pressure buildup [57]. Figure 8 compares the CO 2 propagation in terms of saturation and aqueous mole fraction when an open fracture with 10 mD of intrinsic permeability and an aperture of 0.00014 m was placed inside the caprock [57]. This represented a single natural fracture with a length of 1600 m which traversed the entire thickness of the caprock (it did not intersect the sandstone).…”

“…With the finer gridblocks, the penetration was reduced by only 15% from the estimated penetration (22 m). Those results show that CO 2 penetration in the caprock is possible (mainly by diffusion) and can generate leakage to the surface or other non-target zones when the migration is associated with flow through fault/fracture potentially activated by the pressure buildup [57]. Figure 8 compares the CO 2 propagation in terms of saturation and aqueous mole fraction when an open fracture with 10 mD of intrinsic permeability and an aperture of 0.00014 m was placed inside the caprock [57].…”

Unveiling Valuable Geomechanical Monitoring Insights: Exploring Ground Deformation in Geological Carbon Storage

“…At the end of the injection phase (Figure 7B), the CO 2 has predominantly remained within the reservoir boundaries. By 70 years (Figure 7C), there is a slight presence of CO 2 detectable in the surrounding rock formation mainly through diffusion or a numerical artifact driven by diffusion due to the course grid considered in our model, as discussed in [59,85]. However, this penetration is minimal and does not constitute a leakage concern as absence of fractures or other flow localization features in this model is assumed.…”