Multiphase flow for CO2 injection in saline aquifers and oil reservoirs: multi-scale observations
Creators: name: Al-Menhali, Ali
Publisher: name: Imperial College London
Year: 2016

description: Geologic CO2 storage has been identified as key to avoiding dangerous climate change. Carbon dioxide is also injected into oil fields to enhance oil recovery (EOR). The aim of EOR is to enhance recovery by reducing the residual or remaining oil inside the pore space of reservoir rocks while the aim of carbon storage is to maximize CO2 trapping. The processes governing trapping are fundamentally rooted in the wettability or capillarity of the system. The wettability of CO2-brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Therefore, understanding the wetting properties of storage sites and its impact on multiphase flow properties is crucial. In this work, three aspects of wettability were investigated: The impact of reservoir conditions on the capillarity and multiphase flow of CO2-brine-sandstone systems, the impact of fractional wettability on capillary trapping of CO2 in mixed-wet carbonate rocks and the physical basis of capillary trapping behaviour in mixed-wet systems using pore scale observations. This thesis sought to resolve an outstanding uncertainty about the effective wetting properties of CO2-brine rock systems, characteristic of CO2 storage in saline aquifers. Contact angle measurement studies have reported sensitivity in wetting behaviour of CO2-brine-sandstone systems to pressure, temperature, and brine salinity. We report observations of the impact of reservoir conditions on the capillary pressure characteristic curve and relative permeability of a single Berea sandstone during drainage, CO2 displacing brine, through effects on the wetting state. Eight reservoir condition drainage capillary pressure characteristic curves were measured using CO2 and brine in a single fired Berea sandstone at pressures (5–20 MPa), temperatures (25–50 oC), and ionic strengths (0–5 mol kg-1 NaCl). A ninth measurement using a N2-water system provided a benchmark for capillarity with a strongly water wet system. The capillary pressure curves from each of the tests were found to be similar to the N2-water curve when scaled by the interfacial tension. Reservoir conditions were not found to have a significant impact on the capillary strength of the CO2-brine system during drainage through a variation in the wetting state. Two steady-state relative permeability measurements with CO2 and brine and one with N2 and brine similarly show little variation between conditions, consistent with the observation that the CO2-brine-sandstone system is water wetting and multiphase flow properties invariant across a wide range of reservoir conditions. While saline aquifers make up the majority of the storage capacity, storage in oil reservoirs dominate the portfolio of existing projects due to favourable economics when combined with EOR. Observations and modelling have shown how capillary trapping leads to the immobilization of CO2 in saline aquifers, enhancing the security and capacity of storage. There are, however, no observations of trapping in rocks with a mixed-wet-state characteristic of hydrocarbon-bearing carbonate reservoirs, where most of the oil is reserved. Here, we report the observations of residually trapped CO2 in mixed-wet systems. The motivation of the work is to understand the residual trapping process underpinning the safety of geologic CO2 storage as it pertains to CO2 injection into oil fields. We found that residual trapping of supercritical CO2 in a limestone altered to a mixed-wet state with oil was significantly less than trapping in the unaltered rock. In unaltered samples, the trapping of CO2 and N2 were indistinguishable, with a maximum residual saturation of 24%. After the alteration of the wetting state, the trapping of N2 was reduced, with a maximum residual saturation of 19%. The trapping of CO2 was reduced even further, with a maximum residual saturation of 15%. Best-fit Land-model constants shifted from C = 1.73 in the water-wet rock to C = 2.82 for N2 and C = 4.11 for the CO2 in the mixed-wet rock. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. This is the first multi-scale study directly tying the underlying pore scale displacement physics to the residual trapping property used in flow modelling conventionally measured at larger scales. These are also the first observations at the pore scales of supercritical CO2 trapped in mixed wet rocks characteristic of oil field carbonates. In situ measurements of contact angles showed that CO2 varied from non-wetting to wetting throughout the pore space, with contact angles ranging 25o &lt; θ&lt; 127o; in contrast, N2 was non-wetting with a smaller range in contact angle 24o &lt; θ&lt; 68o. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems. The result is a uniquely comprehensive and self-consistent dataset showing how the pore scale effects of wettability alteration lead to large scale decreases in trapping with significant relevance for CO2 storage in oil fields. The results indicate that plume migration will be less constrained by capillary trapping for CO2 storage projects using oil fields compared with those for saline aquifers. The work provides a significant enhancement in our knowledge of CO2 injection into oil fields for enhanced oil recovery and storage – the geologic unit currently dominating the deployment of the first mover generation of industrial scale storage projects globally.