Accurate determination of relative permeability hysteresis is needed for reliable prediction of WAG injection. We report two series of gas/water kr hysteresis curves obtained from corefloods under mixed-wet conditions. The first set began by water injection (imbibition: I) in the core saturated with hydrocarbon gas and immobile water. Then, the injection of gas (Drainage: D) and water continued sequentially and in total, three imbibitions and two drainages were carried out (IDIDI). In the second series, the core was initially 100% saturated with water and the experiment started with drainage (gas injection) followed by successive imbibitions (water) and drainages (DIDIDI) periods. The measured pressure drop and production data were history matched to obtain krg and krw values for each imbibition and drainage. The results show cycle-dependent hysteresis for both krg and krw curves. Therefore, the current assumption in existing hysteresis models that the drainage scanning curves follow the preceding imbibition curve is not supported by our experiments. Historic behaviour of both krg and krw is qualitatively different for these two series of experiments. This shows that unlike water-wet systems, relative permeability historic behaviour in mixed-wet system can be a function of injection scenario (saturation history). In the IDIDI series, both krg and krw decreased as the alternation between imbibition and drainage injection continued. In the DIDID series, no significant hysteresis was observed for krw, but krg in drainage cycles were higher than the corresponding values in preceding imbibition cycles. The results reveal that, none of the widely used hysteresis models (e.g., Carlson, Killough) is able to predict the observed cyclic kr hysteresis for alternating injection of gas and water. The results suggest that for mixed-wet systems it is necessary to consider irreversible hysteresis loops for both the wetting and non-wetting phases. In addition to WAG injection, the results presented in this paper and the conclusions drawn also have applications in underground hydrocarbon gas storage which usually involves cyclic pressurization (drainage) and depressurization (imbibition) on annual basis.
Water flooding and gas injection are two widely used improved oil recovery techniques that can be applied individually or combined as water alternating gas (WAG) or simultaneous gas and water (SWAG) injection. To do reservoir development planning, for possible implementation of these oil recovery schemes, reliable reservoir performance prediction is needed. Most of the existing reservoir simulators are unable to adequately account for all the complex multi-phase and multi-physics processes involved in these oil recovery techniques. That is particularly the case under mixed-wet and low gas-oil IFT (near-miscible) conditions. Performing reliable laboratory experiments is the key to evaluating the performance of these oil recovery techniques under reservoir conditions.
We present the results of a comprehensive series of well-controlled coreflood experiments carried out under mixed-wet condition using a very low IFT gas-oil system. The experiments include oil recovery by water flood (WF), continues gas injection (CGI), two series of WAG, and two series of SWAG injection tests. The difference between the two WAG experiments is the order in which gas and water injections are carried out. The first WAG test started with water injection whereas the second WAG experiment started with gas injection. The difference between the two SWAG experiments is the gas/water (SWAG) ratio, which was 0.25 for the first one and 1.0 for the second SWAG test.
The results show that in both mixed-wet cores, WAG injection has a superior performance over WF, CGI and SWAG injection. Oil recovery by the WAG test which had started with water injection was higher than the WAG test started with gas injection. SWAG performed better compare to CGI. However, surprisingly, SWAG resulted in lower oil recovery compared to primary waterflood in these mixed-wet systems. It was observed that increasing the gas/water ratio in SWAG leads to faster gas breakthrough, higher produced gas/oil ratio and further reduction in the recovery performance of SWAG. Compared to the other injection strategies, a very high pressure drop across the core was observed during SWAG injection indicating injectivity problems with the application of the process in mixed-wet rocks. The results show that for mixed-wet rocks, amongst the studied injection strategies, SWAG is the worst and alternating injection of water and gas (WAG), starting with a water flood period, is the best injection strategy.
One major problem in the prediction of the performance of Water Alternating Gas (WAG) process is the uncertainty associated with the changes in three-phase relative permeability (kr) values of oil, gas and water in different cycles, which is known as cyclic hysteresis. In this work we have investigated the effect of cyclic injection on three phase kr by performing a series of coreflood experiments under both water-wet and mixed-wet conditions. WAG experiments started with water injection (I) followed by gas injection (D) and this cyclic injection of water and gas was repeated (IDIDID). Three-phase relative permeabilities were obtained analytically from the coreflood data using an extension of Buckley-Leveret formula to three-phase flow.
The results show the importance of properly accounting for irreversible kr hysteresis loops (especially for gas and oil) in the processes involving cyclic injection under three-phase flow conditions. Gas relative permeability (krg) dropped in successive cycles under both water-wet and mixed-wet conditions. krg hysteresis was larger in the water-wet system compared to the mixed-wet case. The results also reveal cyclic hysteresis for oil relative permeability (kro), which tends to increase in successive gas injection periods. The improvement in kro was larger in the water-wet system. In both water-wet and mixed-wet systems, the largest krw hysteresis happens for the transition from two-phase (oil/water system) to three-phase system (from 1st water injection into 1st gas injection) and the subsequent WAG cycles does not show much hysteresis for krw in our experiments.
The paper also offers insights into and explanations for the observed cyclic hysteresis behaviour based on our understanding of the pore-scale and core-scale displacement mechanisms involved in WAG injection. The results highlight some serious shortcomings of the existing reservoir simulators for reliable simulation of oil recovery processes involving three-phase flow and flow reversal.
Accurate determination of relative permeability values and their hysteresis is crucial for obtaining a reliable prediction of the performance of water-alternating-gas (WAG) injection in oil reservoirs. In this paper we report two series of gas/oil relative permeability curves obtained from coreflood experiments carried out in a mixed-wet core under a very low oil/gas interfacial tension (IFT) of 0.04mN.m-1. The first set of the corefloods began by oil injection (imbibition) in the core saturated with gas and immobile water (Swi). This was followed by a period of gas injection (drainage) and this sequential injection of oil and gas continued and in total, three imbibition and two drainage periods were carried out. In the second series of experiments, the core was initially saturated with oil and immobile water and the experiment started with a gas injection followed by cycles of drainage and imbibitions.
The measured pressure drop and production data were history matched through simulation analysis to obtain krg and kro values for each of the imbibition and drainage cycles. The results show that both the oil and the gas relative permeability curves show cycle-dependent hysteresis despite the very low gas/oil IFT. Therefore, the current assumption in existing models (such as Land, Carlson and Killough) that the drainage scanning kr curves follow the preceding imbibition curve is not supported by our coreflood experiments.
When compared to our measured data, Carlson model predictions for krg in imbibition direction are poor. Killough model predictions underestimate krg and overestimate kro especially near trapped gas saturation regions. Beattie et al. hysteresis model is able to capture the krg and kro behavior that we observed in our experiments qualitatively, but it is still unable to predict the value of the observed hysteresis. The results suggest that for mixed-wet systems, it is necessary to consider irreversible hysteresis loops for both the wetting and non-wetting phases. Such capability currently does not exist in reservoir simulators due to lack of appropriate predictive tools.
The In-Situ Combustion (ISC) as a thermal EOR process has been studied deeply in heavy oil reservoirs and is a promising method for certain non-fractured sandstones. However, its feasibility in fractured carbonates remained questionable. The aim of the present work was to understand the recovery mechanisms of ISC in fractured models and to evaluate the effect of fractures geometrical properties such as orientation, density, location and networking on the ISC recovery performance. Combustion parameters of a fractured low permeable carbonate heavy oil reservoir in Middle East called KEM; applied to simulation study. Simulator has been validated with KEM combustion tube experimental data and validated model modified to 3D semi-scaled combustion cells. It was found that in fractured models oxygen first flows into the fractures and then diffuses from all sides into the matrix. Combustion of the oil in the fractures produces water ahead of fracture combustion front which prohibits oxygen from early breakthrough through fractures into producer. Water imbibes into matrix and causes further oil drainage. Part of this oil imbibes into downstream matrices and the other part produces into producer through fractures. The oxygen diffusion/water imbibition based recovery mechanism is slower in production rates compare to conventional model recovery mechanism, and also results in lower quality of produced oil. It was found that ISC recovery was higher in the presence of networked fractures (presence of both longitudinal and traversal fissures) compare to the case of presence of either longitudinal or traversal fracture systems. Results show that ISC is more feasible in the case of densely fractured reservoirs such as those in the Middle East. Further, sensitivity analysis on air injection rate, formation thickness, injection well depth of perforation and also feasibility of water alternating gas (air), WAG, process for fracture model have been studied.
Near-miscible gas injection represents a number of processes of great importance to reservoir engineers including hydrocarbon gas injection and CO2 flood. Very little experimental data is available in the literature on displacements involving very low-IFT (interfacial tension). In this paper, we present the results of a series of two-phase and three-phase gas injection (drainage) and oil injection (imbibition) core flood experiments for an gas/oil system at near-miscible (IFT= 0.04 mN.m-1) conditions. Two different cores; a high-permeability (1000 mD) and a lower permeability (65 mD) core were used in the experiments and both water-wet and mixed-wet conditions were examined.
The results show that despite a very low gas-oil IFT, there is significant hysteresis between the imbibition and drainage oil and gas relative permeabilities (kr) curves in the 65mD core. Hysteresis was less for 1000mD core (compared to the 65 mD core) but it still could not be ignored. Near-miscible kr hysteresis was significant for both water-wet and mixed-wet systems. Presence of immobile water in the water-wet cores improved oil relative permeabilities but reduced gas relative permeabilities in both imbibition and drainage directions. As a result, oil recovery for gas injection experiments improved when the rock contained immobile water. Both oil and gas relative permeabilities reduced when the rock wettability was altered to mixed wet from water wet and as a result, oil recovery by gas injection in the mixed-wet rock was less than that obtained under water-wet conditions. We offer explanations for these observations based on our understanding of the pore-scale interactions and mechanisms, the distribution of fluid phases and their spreading bahaviour.
The results help us better understand the impact of some of the important parameters pertinent to kr and its hysteresis especially in very low IFT gas-oil systems and mixed-wet rocks. Understanding these effects and behavior is important for improved prediction of the performance of gas injection and water-alternating gas (WAG) injection in oil reservoirs.