The physical process whereby an immiscible fluid phase replaces a second resident fluid in a porous medium is characteristic of many subsurface operations that include remediation of non-aqueous phase liquids (NAPLs), enhanced oil recovery (EOR), and carbon capture and storage (CCS) technology (Edery et al., 2018;Singh et al., 2017). Mobilization of residual NAPL and oil blobs and trapping of gas bubbles are critical to such operations (Geistlinger & Mohammadian, 2015).In CCS applications, the trapping of supercritical carbon dioxide in the interstitial spaces of porous rocks (known as capillary or residual trapping) inhibits plume migration and enhances storage safety and capacity (Al-Menhali et al., 2016;Krevor et al., 2015). Capillary trapping can contribute up to 40% of the overall CO 2 trapping in the first 100 years post-injection (Li et al., 2015), and it is strongly influenced by the wettability of the porous medium (
Most numerical simulation studies have focused on the effect of homogenous wettability on fluid flow dynamics; however, most rocks display spatially heterogeneous wettability. Therefore, we have used direct numerical simulations (DNS) to investigate wettability heterogeneity at pore-scale. We have built a quasi-3D pore-scale model and simulated two-phase flow in a homogenous porous media with homogenous and heterogeneous wettability distributions. Five different heterogeneous wettability patterns were used in this study. We observed that heterogenous wettability significantly affects the evolution of fluid interface, trapped saturation, and displacement patterns. Wettability heterogeneity results in fingering and specific trapping patterns which do not follow the flow behaviour characteristic of a porous medium with homogenous wettability. This flow behaviour indicates a different flow regime that cannot be estimated using homogenous wettability distributions represented by an average contact angle. Moreover, our simulation results show that certain spatial configurations of wettability heterogeneity at the microscale, e.g. being perpendicular to the flow direction, may assist the stability of the displacement and delay the breakthrough time. In contrast, other configurations such as being parallel to the flow direction promote flow instability for the same pore-scale geometry.
Many physical factors are affecting relative permeability. These factors could be wettability, interfacial tension, and pore size distribution of the porous media. All these factors significantly change the shape of the relative permeability curve. The change of interfacial tension of flowing phases can considerably change flow characteristics especially in gas condensate reservoir or gas injection into wells with near miscible conditions. Assuming that physical core properties and experiment conditions are constant, interfacial tension as the only variable would change relative permeabilities. Here our objective is to estimate relative permeability at lower interfacial tensions from immiscible relative permeability. We will also estimate the change of residual oil saturation with interfacial tensions. In this paper, we have implemented Michaelis Menten Kinetics model to evaluate residual oil as a function of interfacial tension. Also, a new set of correlations was purposed to calculate gas and oil relative permeability at different IFT. The accuracy of the model is then assessed against experimental data available in literature and predictions of a default model in commercial simulators (Coat's model). Although the model needs fewer input data and it requires fewer calculations than Coat's model, it improved predictions.
Obtaining reliable relative permeability (kr) values and their variations is difficult particularly in processes involving three-phase flow and flow reversal (e.g. WAG injection) which results in kr hysteresis. The current approach in the industry is to use a three-phase kr correlation (e.g., Stone I, Stone II, Baker) in conjunction with a kr hysteresis model (e.g., Killough, WAG- Hysteresis). However, these models have been mostly developed based on water-wet systems and have rarely been benchmarked against experimental measurements. In this paper, we present the results of an extensive assessment of different three-phase relative permeability models available in the most widely used reservoir simulators. The input two-phase data needed for using three-phase kr correlations were obtained from core flood experiments. The simulation results were directly compared with WAG injection experiments performed under both water-wet and mixed-wet conditions. The results show significant differences between the simulation and experimental results of WAG injection. In water-wet rocks, the results show that without considering kr hysteresis, Stone-I model underestimates WAG performance, but it overestimates oil recovery in mixed-wet rocks. SWI and Baker correlations overestimate WAG performance in water-wet rocks while for mixed-wet rocks they significantly underestimate production data. For both wettabilities, Stone-II significantly underestimates oil production. The generated recovery trends by IKU model show a relative advantage over other models but still underestimates the performance of WAG injection especially for later cycles. Coupling of three-phase kr correlations with hysteresis models (Carlson, Killough and Jargon) generally results in highly overestimated oil recovery predictions especially for mixed-wet conditions. For water-wet systems, coupling Stone-I with WAG-hysteresis model improves the predictions up to the second gas injection period. Nevertheless, serious underestimation is observed for further cycles. The WAG-hysteresis model overestimated WAG performance in mixed-wet systems. To improve its prediction, based on our experimental results, WAG-hysteresis model parameters were adjusted after each cycle. This modified approach improved simulation results in water-wet systems. However, none of the available approaches could adequately reproduce experimental results obtained for mixed-wet conditions. This is a major concern for predication of WAG performance in real reservoirs which are believed to be mixed-wet.
Gas injection schemes (including WAG and SWAG injections) are among the most widely used Enhanced Oil Recovery (EOR) processes for carbonate reservoirs due to their usually low rock permeability. Because of the complex nature of carbonate reservoirs (structural heterogeneities and mixed- to oil-wet conditions), most of the existing reservoir simulators are not able to adequately model EOR processes in these reservoirs. Performing reliable laboratory experiments in reservoir cores under reservoir conditions is necessary in order to evaluate the performance of these oil recovery techniques and obtain the required data to assess the prediction of the currently available models in commercial simulators. In this paper, we present the results of a series of coreflood experiments performed in carbonate rocks. Both reservoir core plugs as well as a dolomite outcrop core were used in the experiments. The cores were aged in reservoir crude oil to restore wettability. Gas and water injection experiments were performed under reservoir conditions and with different injection strategies. Separate multi cycle WAG injection experiments were performed starting with gas (WAG-DI) or water injection (WAG-ID) in order to compare the impact of the order of fluid injection. SWAG injection experiment was also performed with an injection gas to water ratio of unity. The injectivity and production data of different injection strategies were compared. Generally speaking, dolomite cores showed less oil-wet characteristics compared to reservoir carbonate cores which showed strongly oil-wet behaviours. WAG injection starting with waterflood and SWAG injection performed better than waterflood or gas injection alone. Ultimate oil recovery by gas injection was considerably less than that obtained by waterflood. As a result of poor efficiency of the gas injection, the WAG injection starting with gas injection (WAG-DI) showed lower recovery performance compared to the waterflood up until the end of 3rd WAG injection cycle. Nevertheless, WAG-DI ultimately outperformed waterflood. Although SWAG injection outperformed the WAG-ID for the first two cycles of injection but the ultimate residual oil saturation was lower for the WAG-ID injection. In addition to lower ultimate oil recovery, SWAG injection test showed more injectivity issues compared to the WAG-ID injection sequence. The observed trends of residual gas and oil saturations in carbonate reservoir cores were different compared with those of water-wet and mixed-wet sandstone rocks reported in our previous studies in which the residual oil to water was reducing linearly with an increase in trapped gas. The results provide useful insights into mechanisms of oil recovery by gas and water injection in carbonate reservoirs and highlight some important differences with sandstone reservoirs.
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