a b s t r a c tA significant amount of theoretical, numerical and observational work has been published focused on various aspects of capillary trapping in CO 2 storage since the IPCC Special Report on Carbon Dioxide Capture and Storage (2005). This research has placed capillary trapping in a central role in nearly every aspect of the geologic storage of CO 2 . Capillary, or residual, trapping -where CO 2 is rendered immobile in the pore space as disconnected ganglia, surrounded by brine in a storage aquifer -is controlled by fluid and interfacial physics at the size scale of rock pores. These processes have been observed at the pore scale in situ using X-ray microtomography at reservoir conditions. A large database of conventional centimetre core scale observations for flow modelling are now available for a range of rock types and reservoir conditions. These along with the pore scale observations confirm that trapped saturations will be at least 10% and more typically 30% of the pore volume of the rock, stable against subsequent displacement by brine and characteristic of water-wet systems. Capillary trapping is pervasive over the extent of a migrating CO 2 plume and both theoretical and numerical investigations have demonstrated the first order impacts of capillary trapping on plume migration, immobilisation and CO 2 storage security. Engineering strategies to maximise capillary trapping have been proposed that make use of injection schemes that maximise sweep or enhance imbibition. National assessments of CO 2 storage capacity now incorporate modelling of residual trapping where it can account for up to 95% of the storage resource. Field scale observations of capillary trapping have confirmed the formation and stability of residually trapped CO 2 at masses up to 10,000 tons and over time scales of years. Significant outstanding uncertainties include the impact of heterogeneity on capillary immobilisation and capillary trapping in mixed-wet systems. Overall capillary trapping is well constrained by laboratory and field scale observations, effectively modelled in theoretical and numerical models and significantly enhances storage integrity, both increasing storage capacity and limiting the rate and extent of plume migration.

Early deployment of carbon dioxide storage is likely to focus on injection into mature oil reservoirs, most of which occur in carbonate rock units. Observations and modeling 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. Here, 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. 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 storage of carbon dioxide in deep brine-filled permeable rocks is an important tool for CO 2 emissions mitigation on industrial scales. Residual trapping of CO 2 through capillary forces within the pore space of the reservoir is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO 2 migration within the reservoir. In this study we have evaluated the impact of reservoir conditions of pressure, temperature, and brine salinity on the residual trapping characteristic curve of a fired Berea sandstone rock. The observations demonstrate that the initial-residual characteristic trapping curve is invariant across a wide range of pressure, temperature, and brine salinities and is also the same for CO 2 -brine systems as a N 2 -water system. The observations were made using a reservoir condition core-flooding laboratory that included high-precision pumps, temperature control, the ability to recirculate fluids for weeks at a time, and an X-ray CT scanner. Experimental conditions covered pressures of 5-20 MPa, temperatures of 25-50 C, and 0-5 mol/kg NaCl brine salinity. A novel coreflooding approach was developed, making use of the capillary end effect to create a large range in initial CO 2 saturation (0.15-0.6) in a single coreflood. Upon subsequent flooding with CO 2 -equilibriated brine, the observation of residual saturation corresponded to the wide range of initial saturations before flooding resulting in a rapid construction of the initial-residual curve. For each condition we report the initial-residual curve and the resulting parameterization of the Land hysteresis models.

Residual trapping, CO 2 Storage, mixed-wet carbonate, Enhanced Oil Recovery, micro X-ray 9 CT, carbon utilization. Geologic CO 2 storage has been identified as key to avoiding dangerous climate change. 13Storage in oil reservoirs dominates the portfolio of existing projects due to favorable 14 economics. However, in an earlier related work, Al-Menhali and Krevor (2016), it was 15 identified that an important trapping mechanism, residual trapping, is weakened in rocks with

The wettability of CO 2 -brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Recent contact angle measurement studies have reported sensitivity in wetting behavior of this system 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-CO 2 displacing brine-through effects on the wetting state. Eight reservoir condition drainage capillary pressure characteristic curves were measured using CO 2 and brine in a single fired Berea sandstone at pressures (5-20 MPa), temperatures (25-508C), and ionic strengths (0-5 mol kg 21 NaCl). A ninth measurement using a N 2 -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 N 2 -water curve when scaled by the interfacial tension. Reservoir conditions were not found to have a significant impact on the capillary strength of the CO 2 -brine system during drainage through a variation in the wetting state. Two steady-state relative permeability measurements with CO 2 and brine and one with N 2 and brine similarly show little variation between conditions, consistent with the observation that the CO 2 -brine-sandstone system is water wetting and multiphase flow properties invariant across a wide range of reservoir conditions.