Carbon dioxide (CO 2 ) injection is a well-established method for increasing recovery from oil reservoirs. However, poor sweep efficiency has been reported in many CO 2 injection projects due to the high mobility contrast between CO 2 and oil and water. Various injection strategies including gravity stable, WAG and SWAG have been suggested and, to some extent, applied in the field to alleviate this problem. An alternative injection strategy is carbonated water injection (CWI). In CWI, CO 2 is delivered to a much larger part of the reservoir compared to direct CO 2 injection due to a much improved sweep efficiency. In CWI, CO 2 is used efficiently and much less CO 2 is required compared to conventional CO 2 flooding, and hence the process is particularly attractive for reservoirs with limited access to large quantities of CO 2 (offshore reservoirs or reservoirs far away from inexpensive natural CO 2 resources). This article describes the results of a pore-scale study of the process of CWI by performing high-pressure visualisation flow experiments. The experimental results show that CWI, compared to unadulterated (conventional) water injection, improves oil recovery as both a secondary (before water flooding) and a tertiary (after water flooding) recovery method. The mechanisms of oil recovery by CWI include oil swelling, coalescence of the isolated oil ganglia and flow diversion due to flow restriction in some of the pores as a result of oil swelling and the resultant fluid redistribution. In this article the potential benefit of a subsequent depressurisation period on oil recovery after the CWI period is also investigated.

Carbonated water injection (CWI) is a CO 2 -augmented water injection strategy that leads to increased oil recovery with added advantage of safe storage of CO 2 in oil reservoirs. In CWI, CO 2 is used efficiently (compared to conventional CO 2 injection) and hence it is particularly attractive for reservoirs with limited access to large quantities of CO 2 , e.g. offshore reservoirs or reservoirs far from large sources of CO 2 . We present the results of a series of CWI coreflood experiments using water-wet and mixed-wet Clashach sandstone cores and a reservoir core with light oil (n-decane), refined viscous oil and a stock-tank crude oil. The experiments were carried out to assess the performance of CWI and to quantify the level of additional oil recovery and CO 2 storage under various experimental conditions. We show that the ultimate oil recovery by CWI is higher than the conventional water flooding in both secondary and tertiary recovery methods. Oil swelling as a result of CO 2 diffusion into the oil and the subsequent oil viscosity reduction and coalescence of the isolated oil ganglia are amongst the main mechanisms of oil recovery by CWI that were observed through the visualisation experiments in high-pressure glass micromodels. There was also evidence of a change in the rock wettability that could also influence the oil recovery. The coreflood test results also reveal that the CWI performance is influenced by oil viscosity, core wettability and the brine salinity. Higher oil recovery was obtained with the mixed-wet core than the water-wet core, with light oil than with the viscous oil and low salinity carbonated brine than high-salinity carbonated brine. At the end of the flooding period, an encouraging amount of the injected CO 2 was stored in the brine and the remaining oil in the form of stable dissolved CO 2 . The experimental results clearly demonstrate the potential of CWI for improving oil recovery as compared with the conventional water flooding (secondary recovery) or as a water-based EOR (enhanced oil recovery) method for watered out reservoirs.

As gas flooding becomes a more viable means of enhanced oil recovery, it is important to identify and understand the pore-scale flow mechanisms, both for the development of improved gas flooding applications and for the predicting phase mobilisation under secondary and tertiary gas flooding. The purpose of this study was to visually investigate the pore-level mechanisms of oil recovery by near-miscible secondary and tertiary gas floods. High-pressure glass micromodels and model fluids representing a near-miscible fluid system were used for the flow experiments. A new pore-scale recovery mechanism was identified which significantly contributed to oil recovery through enhanced flow and cross-flow between the bypassed pores and the injected gas. This mechanism is strongly related to a very low gas/oil interfacial tension (IFT), perfect wetting conditions and simultaneous flow of gas and oil in the same pore, all of which occur as the gas/oil critical point is approached. The results of this study helps us to better understand the pore-scale mechanisms of oil recovery in very low-IFT (near-miscible) systems. In particular we show that in near-miscible gas floods, behind the main gas front, the recovery of the oil continues by cross-flow from the bypassed pores into the main flow stream and as a result almost all of the oil, which has been contacted by the gas, could be recovered. Our observations in high-pressure micromodel experiments have demonstrated that this mechanism can only occur in near-miscible processes (as opposed to immiscible and completely miscible processes), which makes oil displacement by near-miscible gas floods a very effective process.

We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms during the recovery of residual oil by nearmiscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under conditions of very low gas-oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point of the gas-oil system is approached. Ultimate oil recovery by near-miscible SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection. Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous and high-rate gas injection is not possible (e.g. due to supply constraint).

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CO2 injection is increasingly considered as having potential applications as a possible enhanced oil recovery (EOR) process for oil reservoirs. However, poor sweep efficiency has been a problem in many CO2 floods and hence, the injection strategies like WAG (water-alternating-gas) injection have been proposed and applied in the field as a way to mitigate the problem. An alternative injection strategy is CO2-enriched (carbonated) water injection (CWI). This paper presents the results of an integrated experimental and theoretical study on the application of CO2-enriched water flooding for enhanced oil recovery. Direct flow visualisation experiments were carried out using high-pressure transparent porous media. The results of our visualisation experiments demonstrate that CWI, compared to unadulterated water injection, improves oil recovery. The additional oil is recovered as a result of an improved sweep efficiency, due to the oil swelling, viscosity reduction and coalescence of the isolated oil ganglia as a result of CO2 diffusion. This injection strategy is particularly attractive in waterflooded oil reservoirs in which high water saturation adversely affects the performance of conventional CO2 injection methods. CWI can also be carried out in combination with reservoir depressurisation carried out subsequent to CWI or in a cyclic manner in which carbonated and plain water cycles are injected in succession. The results of a mathematical model are also presented which honours our experimental observations and simulates the dynamic process of oil swelling and shrinkage due to CO2 transfer during Carbonated water and plain water injection. Introduction In many reservoirs, after waterflooding, a large volume of oil is still left behind. There is thus scope for processes that can unlock some of the remaining oil to maximise oil recovery from these reservoirs. The use of CO2 injection to enhance oil recovery is often associated with poor sweep efficiency (due to high CO2 mobility) [1]. Therefore, direct injection of CO2 (both continuous flooding and WAG) might not result in economically significant amount of additional oil recovery. In terms of CO2 storage potential, poor sweep efficiency also implies lower storage capacity. An alternative injection strategy is carbonated water (CO2-enriched water) injection. Carbonated water has advantages over direct CO2 injection as it has a better sweep efficiency. In direct CO2 injection, it has been shown that due to low sweep efficiency and gravity segregation, the time scale for CO2 diffusion in oil can be several years [2]. In terms of CO2 storage, since in CWI (carbonated water injection) CO2 is dissolved in water (and later oil) rather than existing as a free phase, CWI would provide a very safe method for CO2 storage. CWI causes the oil to swell and the viscosity of the oil to drop. It can reduce water-oil interfacial tension and can also favourably affect wettability of the reservoir. Swelling of the oil can reconnect the discontinuous residual oil and result in additional oil recovery. Additional oil recovery might also be achieved through a blow down phase subsequent to a period of carbonated water injection. Another water injection period after CWI stage could also cause more fluid redistribution and oil recovery as the rate of CO2 dissolution in the oil during CWI is not necessarily the same as the rate of CO2 stripping from the oil during WI. The objective of this study was to investigate the process of carbonated water injection through conducting flow visualisation experiments and mathematical modelling. To achive this objective, we have performed a series of high-pressure flow visualisation experiments. In this paper we show and discuss the results of one of our experiments carried out to investigate the performance of carbonated water injection (CWI), as a tertiary oil recovery method, after water injection (WI). The experiment was conducted using a high-pressure transparent porous medium (micromodel) at 2000 Psia and 38 °C.

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