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Carbon capture and storage, that is the collection of carbon dioxide (CO2) from power plants and its injection underground, is an important technology for reducing CO2 emissions to the atmosphere and hence, mitigating climate change. A key aspect of CO2 storage is the injection rate into the subsurface, which is limited by the pressure at which formation starts to fracture. Hence, it is vital to assess all of the relevant processes that may contribute to the pressure increase in the aquifer during CO2 injection. The central aim of this study is to analyse the ability of the near-well region of a saline formation to conduct fluids, using a set of analytical solutions that enable quick and reliable assessment of CO2 injectivity. In this research, the near-well fluid flow was assumed to be a function of the non-Darcy flow parameter as defined by the Forchheimer equation. For the analysis of single-phase flow problems, the analytical solution for the Forchheimer flow in closed domains was derived and an alternative method for applying analytical solutions associated with a single well to multiple well systems was proposed. The CO2 injection process was modelled as a two-phase system where the non-Darcy flow was assumed for the gas phase only, including a novel representation of the spatially varying fractional flow function. The solution for immiscible flow was further developed to model compositional displacements, which enabled analysis of the porosity reduction due to salt precipitation in a near-well region. Finally, the effects of gas compressibility were examined by integrating the analytical model with an iterative algorithm for correcting gas properties. Results showed that in low permeability formations when CO2 is injected at high rates non-Darcy flow conditions are more favourable for CO2 storage than linear flow due to better displacement efficiency. This, however, came at the cost of increased well pressures. More favourable estimations of the pressure buildup were obtained when CO2 compressibility was taken into account because reservoir pressures were reduced due to the change in the gas phase properties. The non-Darcy flow resulted in a significant reduction in solid salt saturation values, with a positive effect on CO2 injectivity. In the examples shown, non-Darcy flow conditions may lead to significantly different pressure and saturation distributions in the near-well region, with potentially important implications for CO2 injectivity.

We have identified a CO2 and water injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. We propose the use of counter-current injection of gas and water to improve reservoir sweep and trap CO2; water is injected in the upper portion of the reservoir and gas is injected in the lower portion. This process is referred to as water over gas injection or modified simultaneous water alternating gas injection (SWAG). This thesis is based on the results of quasi-validated compositional reservoir simulations in that exact matches were not obtained for the disparate fluids and reservoirs properties but the trends of oil recovery and water cut were accepted as representative of comparative physical mechanisms of displacement. We have compared oil recovery and water cut trends of the compositional simulation model to the displacement experiments conducted by Dyer and Farouq Ali[1] where varying injection rates, number of WAG cycles and size of CO2 slug were investigated. Dyer and Farouq Ali’s displacement experiments used an Aberfeldy crude mixed with liquid petroleum to obtain an oil viscosity of 1055 mPa.s at standard conditions to represent viscosity reservoir conditions. The fluid description used in our compositional simulations are based on PVT-matched properties of oil found in an unconsolidated deltaic, sandstone deposit in the Gulf of Paria, offshore Trinidad. At standard conditions the crude viscosity is 1175mPa.s and at reservoir conditions (81° C and 27.9 MPa) 8 mPa.s. In this region oil density ranges between 940 and 1010 kg/m3 (9-18 degrees API). The PVT properties were matched by regressing: the 3-parameter Peng-Robinson[2] equation of state to the oil relative volume, total relative volume and; the coefficients of the Lohrenz Bray Clark [3]correlation to the viscosity of the crude between 0 and 20MPa at 81.7 °C. The reservoir simulation model was scaled to the length to width ratio of the displacement experiment and, the ratio of gravitational to viscous forces of injected water used in displacement experiments. From this we study we identified the limitations of WAG and the injection parameters favourable to oil recovery, gas trapping and gas storage capacity. We have then used a synthetic reservoir to represent an unconsolidated sand measuring 1000m × 150m × 100m with average porosity of 26% and initial water saturation of 20% to investigate with representative parameters, determined from the comparison with the displacement experiments, to investigate the efficacy of water over gas injection. The original oil in place (OOIP) is 3.12 × 106 m3 (19 MMbbl).The two water injection rates investigated, 100 and 200m3/day(630 and 1260 bbl/day). These rates correspond to water gravity numbers (dimensionless ratio of viscous to gravity forces) 6.3 to 3.1 for our reservoir properties. The gas injection surface rate was 50 000 sm3/day (1.8 Mscf/day) in both instances corresponding to gas gravity numbers ranging between 150 and 200 with varying reservoir flow rates .We have applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals. The producer was vertical in each case. The impact of miscibility was investigated by varying the injection gas composition by comparing the effect of using pure CO2 and a mixture of CO2 and C2-C6 in a 2:1 ratio, on oil recovery, carbon storage and field performance. Eight simulation runs were conducted varying injection gas composition for miscible and immiscible gas drives, water injection rate and injection well orientation. Our results show that water over gas injection can realize oil recoveries ranging from 17 to 30% of original oil in place (OOIP). In each instance more than 50% of the injected CO2 remains in the reservoir with less than 15% of retained CO2 in the mobile phase. The remaining CO2 is distributed in oil, water and trapped gas phases. Our reservoir simulations show that water over gas injection can be applied successfully to recover heavy oil and trap CO2 in an unconsolidated sand. This injection design has also shown immiscible and miscible oil recovery can be improved with horizontal injection. Water injection over gas injection increases contact between injected CO2by dispersing the injected gas over a wider volume in the reservoir, hindering gas override and providing reservoir pressure support. Gas storage is inversely proportional to the water gravity number because of the effect the injected water has on gas saturation distribution. In combination with established industry reservoir management techniques such as pressure control and gas cycling, it may be possible to further improve the oil recovery and carbon storage of water over gas injection.