Oil Relative Permeability Research Articles

Mysteries behind the Low Salinity Water Injection Technique

Low salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique in both secondary and tertiary injection modes. The objective of this paper is to investigate the main mechanisms behind the LSWI effect on oil recovery from carbonates through history-matching of a recently published coreflood. This paper includes a description of the seawater cycle match and two proposed methods to history-match the LSWI cycles using the UTCHEM simulator. The sensitivity of residual oil saturation, capillary pressure curve, and relative permeability parameters (endpoints and Corey’s exponents) on LSWI is evaluated in this work. Results showed that wettability alteration is still believed to be the main contributor to the LSWI effect on oil recovery in carbonates through successfully history matching both oil recovery and pressure drop data. Moreover, tuning residual oil saturation and relative permeability parameters including endpoints and exponents is essential for a good data match. Also, the incremental oil recovery obtained by LSWI is mainly controlled by oil relative permeability parameters rather than water relative permeability parameters. The findings of this paper help to gain more insight into this uncertain IOR technique and propose a mechanistic model for oil recovery predictions.

Oil recovery modeling of macro-emulsion flooding at low capillary number

Emulsion flooding has been shown to offer a significant potential as an enhanced-oil recovery (EOR) strategy. Moreover, recovery mechanisms of several chemical EOR methods, including alkaline and alkaline-surfactant flooding applied to heavy oil, are linked to in situ formation of emulsions. To enable emulsion flooding designs, EOR mechanisms must be adequately represented in reservoir simulators to upscale pore-level effects to the continuum in porous media. In this work, we have incorporated two known effects of emulsion flooding, namely an increased pore-level displacement efficiency and a macroscopic mobility control through changes in relative permeability curves. To this end, we used three types of emulsion and oil relative permeability curves: (1) through history matching of unsteady-state emulsion flooding data; (2) from direct use of Darcy law on steady state two-phase flow experiments; and (3) synthetic curves at which pore level displacement efficiency is characterized by the curve end-point saturation and the macroscopic sweep efficiency by the water curve end-point. A parametric analysis of a 1/4 of a 5-spot geometry shows that the displacement efficiency effect is predominantly responsible for the incremental oil recovery observed experimentally. The results also indicate that the amount of oil recovered depends on the complete relative permeability curves, and not only the end-point values. These findings imply that properly designed emulsions should produce significant recovery benefits.

Studying low-salinity waterflooding recovery effects in sandstone reservoirs

Numerous core-flooding experiments have shown that low-salinity water flooding (LSWF) could improve oil recovery in sandstone reservoirs. However, LSWF recovery effects remain highly contentious primarily because of the absence of crucial boundary conditions (boundary conditions are defined throughout the paper as the initial and final, contact angle and interfacial tension values). The objective of this paper is to conduct a parametric study using statistical analysis and simulation to measure the sensitivities of LSWF recovery effects in sandstone reservoirs. The summary of 411 core-flooding experiments discussed in this paper highlights the extent and consistency in reporting boundary conditions, which has two implications for statistical analysis: (1) the statistical correlations of the residual oil saturation to chlorite (0.7891) are strong, whereas the statistical correlations of the residual oil saturation to kaolinite (0.4399) contents, as well as to the wettability index (0.3890), are comparably lower, the majority of dataset entries are missing, and no prediction model can be generated; (2) if a prediction model is generated without clay content values and a wettability index, even though LSWF effects emphasizes wettability modification by virtue of oil aging time and the strong influence of brine cation and divalent ion concentrations on Sor, the prediction model’s regression curve and confidence level are poor. Reservoir simulations conducted to examine LSWF recovery sensitivities conclude that LSWF recovery effects are governed based on the initial and final wetting states. In all wetting states except for weak water-wet conditions, the increase in oil relative permeability is the underlining recovery effect. In weak water-wet conditions, LSWF incremental recovery is driven by low capillary pressures. In weak oil-wet conditions, the secondary LSWF recovery effect is the change of the non-wetting phase to oil. In all wetting states, an appreciable decrease in interfacial tension (IFT) is realized at the breakthrough recovery. The decrease in IFT is the primary recovery effect in strong water-wet conditions.

Integrated reservoir characterization and simulation of a shallow, light-oil, low-temperature reservoir: Umiat field, National Petroleum Reserve, Alaska

Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated. The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density. These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.

Network modeling of asphaltene deposition during two-phase flow in carbonate

A network model is modified to compute formation damage resulting from asphaltene deposition in porous media containing two-phase flow. The model predictions are compared to experimental data of six core samples under similar reservoir conditions. The model is applied to study the effect of asphaltene deposition on throat size distribution, wettability alterations from water-wet to oil-wet, water and oil relative permeability, and capillary pressure in two mechanisms of drainage and imbibition. The asphaltene induced damage is considered by two mechanisms; the smaller throats are plugged owing to large asphaltene particles and the larger throats diameter is decreased.

The effect of saturation history on three-phase relative permeability: An experimental study

We investigate the effect of different saturation histories relevant to various oil displacement processes (including secondary and tertiary gas injections) on three-phase gas/oil/brine relative permeabilities of water-wet sandstone. It is found that three-phase water (wetting phase) relative permeability is primarily a function of water saturation and shows no dependency upon saturation history. Three-phase gas (nonwetting phase) relative permeability is also a function of gas saturation as well as the direction of gas saturation change. Three-phase relative permeability to oil (intermediate-wetting phase) appears to depend on all phase saturations, and saturation history have no significant impact on it. Three-phase oil relative permeability shows weak sensitivity to initial oil saturation prior to gas injection. The functional forms of oil relative permeability with saturation, particularly at low oil saturations, are also examined. It is observed that, at high oil saturations where networks of oil-filled elements govern oil flow, oil relative permeability exhibits a quartic form with oil saturation whereas, at low oil saturations where flow is believed to be controlled by layer drainage, it shows a quadratic form . The quadratic form of three-phase oil relative permeability is consistent with the theoretical interpretation of layer drainage at the pore scale.

Study on the Surfactant/Polymer Combination Flooding Relative Permeability Curves in Offshore Heavy Oil Reservoirs

Different kinds of compound solutions were prepared by using different concentrations of hydrophobically associating polymers and sulfonate type surfactant. The static viscosity and interfacial tension of these solutions were measured. On the experimental conditions of the Suizhong 36-1 oilfield, the relative permeability curves of the water flooding and the surfactant/polymer combination flooding were measured through the constant speed unsteady method and the experimental data were processed through the way of J.B.N. The several existing kinds of viscosity processing methods of non-newtonian fluid were compared and analysed , and a new way is put forward . The results show that the relative permeability of the flooding phase is very low while displacing the heavy oil; the relative permeability of oil in combination flooding is higher than that in water flooding, the relative permeability of flooding phase in combination flooding is lower than that in water flooding and the residual oil saturation of combination flooding is lower than that of water flooding. Meanwhile, the concentrations of polymer and surfactant have a great influence on the surfactant/polymer combination relative permeability curves.

Experimental Study on Effect of Temperature on Heavy Steam/Oil Relative Permeability

Because of the instability of steam and tough requirement of HTHP equipments in steam flooding laboratory simulation, it is rather difficult to obtain representative Steam/Oil relative permeability curves with high precision. In addition, although the effect of temperature on Water/Oil relative permeability curves has been studied a lot both at home and aboard, there are still some controversy perspectives, and research on temperature effect on Steam/Oil relative permeability is rare. As to the above issue, an improved steam flooding experimental method is launched to obtain accurate base data, and then simplified JBN method is applied for data processing. The Result revealed that the improved experimental methods and simplified JBN formulas can obtain representative Steam/Oil relative permeability with high precision, and temperature affects steam/oil relative permeability in various aspects, as temperature increased, oil relative permeability and irreducible water saturation increased while steam relative permeability and residual oil saturation decreased.

Development of sodium silicate-based inorganic water shut-off composition for low-permeability heterogeneous reservoirs

The article is devoted to development of low-viscosity water shut-off composition based on sodium silicate aqueous solution with an adjustable mechanism of gelation, the application of which will improve the efficiency of remedial cementing operations in conditions of heterogeneous low-permeability terrigenous reservoirs of Western Siberia. Evaluation criteria for determination of optimal concentrations of chemicals were as follows: gelation time, yield stress and gel plastic strength. Based on the results of the research it was found that sodium silicate aqueous solutions are capable to gel when interacting with chrome alum; it was also determined that changing the sodium silicate - chrome alum ratio makes it possible to adjust strength characteristics and gelation time of the composition proposed. The effectiveness of application of the water shut-off composition developed is confirmed by the results of low-permeability terrigenous core sample filtration studies with water shutoff treatment simulation in heterogeneous layered formation. It has been established that the proposed composition has selective insulating properties and to a greater extent reduces permeability of saturated intervals. After treatment with water shut-off composition it is recommended to inject a 15%- aqueous sodium hydroxide solution in order to restore permeability in oil-saturated interlayers with no destruction of the insulating shield in water-saturated reservoir compartments. Application of water shut-off composition during injection well treatment will make it possible to reduce amount of produced water and involve the previously non-draining oil stocks in the development; in addition, the alkali slug injection will restore filtration properties of oil-saturated intervals and increase oil relative permeability due to the effect of alkaline water flooding.

黏度对不同渗透率稠油油藏流体渗流特征的影响

稠油中胶质、沥青质形成的结构造成的黏度异常反映了稠油油藏的特性，对稠油的渗流特征有非常重要的影响。通过配制不同含稠油比例的油样，利用流变仪和岩心驱替装置，对不同黏度油样的流变性及其在多孔介质中的渗流特征进行了实验研究，分析了黏度对稠油渗流特征的影响。结果表明：随着油样中所含稠油比例增大，多孔介质中油样的非牛顿渗流特性增强，且渗透率越小，油样的非牛顿特性表现越明显；随着油样中稠油比例增大，水相相对渗透率迅速增大，而油相相对渗透率急剧降低，导致开采效果变差，且对流体在较低渗透率岩样中的相对渗透率影响大于高渗透率的岩样；随着被驱替油样中稠油比例增加，产出液中含水率上升的速度加快，且渗透率越低，含水率随采出程度增加的速度越快。 The viscosity abnormality caused by the asphaltenes and resins in heavy oil reflects the characteristics of heavy oil reservoirs and has very important influence on seepage rule of heavy oil. The oil samples containing different heavy oil ratio were prepared. The rheological properties of different viscosity oil sample and its flow characteristics in porous media were experimentally studied by the rheometer and the core displacement device. The effects of viscosity to percolation characteristic of heavy oil were analyzed in detail. The results show the non-Newtonian seepage characteristic of oil samples in porous media enhances with increasing the proportion of heavy oil in the oil samples. The smaller the permeability of the porous media, the non-Newtonian behavior of oil samples is more obvious. As the heavy oil ratio increases, the relative permeability of water increases rapidly and the oil relative permeability decreases sharply which become worse at the oil recovery effect. The influence on relative permeability of fluids in the lower permeability cores is more than high permeability ones. The water cut increases rapidly in the produced fluids with increasing the proportion of heavy oil in the oil sample. The lower the permeability of the cores, the water cut with recovery percent increases more rapidly.

The effect of wall roughness on two-phase flow in a rough-walled Hele-Shaw cell

Many studies focus on the flow of multiple phases in smooth fractures yet most real fractures are rough thus flow regime maps and results for multiphase flow in smooth fractures are not completely applicable to flow in rough fractures. The effect of wall roughness is difficult to understand in multiphase flow in fractures since it leads to heterogeneities of the fracture aperture and potentially alters the roles of capillary and viscous forces in the flow. Here, the effects of wall roughness, fracture orientation, and fluids flow direction within a fracture, modeled as narrow gap in a Hele-Shaw cell, on co-current flow of oil and water were examined. The results are presented in the form of oil and water relative permeability curves. The results demonstrate that roughness impacts phase distribution, flow regimes, and phase relative permeability (a measure of phase interference); roughness increases oil–water phase interference and hysteresis of the flow resistance when scanning up and down in water saturation. Fractal analysis of images of the phase arrangement in the fracture reveals that the fractal dimension (reflects geometry and complexity), lacunarity (gappiness and complexity), and tortuosity relate the complexity of flow and the change in relative permeability behavior. The experimentally derived relative permeability data were fitted to the saturation exponent model and to an equivalent homogenous single-phase model.

Integrated geologic modeling and reservoir simulation of Umiat: A frozen shallow oil accumulation in national petroleum reserve of Alaska

Current high oil price and availability of new technologies allow re-evaluation of oil resources previously considered uneconomic. The Umiat oil field is one such resource: a unique, shallow (275−1055ft), low-pressure (200−400psia) reservoir within the permafrost zone with no initial gas cap, located north of the Arctic Circle, 80miles west of the Trans Alaska Pipeline System (TAPS) with an estimated 1.5 billion barrels of oil in place.A static model was built based on reinterpretation of original log and core data and seismic information. A permeability anisotropy ratio of 0.45 was incorporated into the geologic model. A Monte Carlo simulation was conducted to estimate the different degrees of uncertainty in the original oil in place (OOIP) estimates. To cover the wide permeability range (0–500md), three sand groups (rock types) were defined and assigned appropriate capillary pressure and relative permeability curves. These were included in the dynamic model along with measured PVT data and gas–oil relative permeabilities in the presence of ice to evaluate the performance of immiscible gas injection using a multilateral wagon wheel well pattern with horizontal well length of 1500ft.The new simulation results show that with 50years of gas injection, recovery factors for the base case (400psia injection pressure) and two cases with 600 and 800psis injection pressures are 10.81%, 13.77%, and 16.66% respectively, keeping other parameters constant. These recovery numbers will reduce by 14% and 9% when producing GOR is restricted to 5000scf/STB and 10,000scf/STB, respectively. Due to unknown characteristics of natural fractures, several permeability anisotropy (Kv/Kh) ratios were considered. Simulation results indicate that lower anisotropy ratio will reduce oil recovery, probably due to inhibition in the downward movement of gas.The result obtained by this study contributes to the understanding of uncertainties in resource estimates and evaluating ranges of oil recovery in reservoir modeling. Despite limited data and lack of production history to tune the model, the results demonstrate that the economics of the proposed development plan bear a high degree of uncertainty and risk. These findings strongly encourage the operator to include development plan strategies to reduce the risk and enhance the quantity and quality of input simulation data.

The Calculation of Oil-water Relative Permeability From Capillary Pressure Data in an Oil-wet Porous Media: Case Study in a Dolomite Reservoir

Estimating relative permeability curves from capillary pressure data is a well-known technique and the reliability of these techniques for approximation of liquid-gas relative permeability curves had thoroughly investigated. However, there is not enough information to conclude which method is the standard one for calculating oil-water relative permeability curves. The authors utilized various capillary pressure techniques such as the Corey, Brooks-Corey, Li-Purcell, and Li-Burdine methods to calculate oil-water relative permeabilities using the measured oil-water capillary pressure data in drainage process in an oil-wet Dolomite reservoir. Despite wide popularity of Purcell and Burdine methods for calculating relative permeability, the authors used new Li-Purcell and Li-Burdine methods. The calculated results were compared to the experimental data of oil-water relative permeabilities measured in a Dolomite reservoir. The Corey and Brooks-Corey models show an acceptable and nearly exact match with the measured oil relative permeability values. However, the Li-Purcell and Li-Burdine models underestimate the values for wetting phase in most cases. It is also worth mentioning that, except Li-Purcell method, the results of all other methods for calculating nonwetting phase relative permeability are almost the same and they are in good agreement with the measured data. Results of this work reveal that calculation of oil-water relative permeability using the capillary pressure data is also a reliable technique in oil-wet systems.

Measuring Oil and Water Relative Permeability in a Single Fracture and Researching Its Impacting Factors

For the research of oil and water relative permeability in single fracture it is important to study the law of flow in fractured-vuggy reservoirs. Base on the wetting property of the field, single-fracture acrylic models with different fracture apertures are created. Using these models, oil and water relative permeability with different water-oil viscosity ratio, different fracture aperture, different fracture dip, and different displacing velocity are measured by the steady-state method. How the relative permeability is influenced by these factors is further studied. The results show that: when the water-oil viscosity ratio is close to 1, the shape of relative permeability curve is similar to X. Relative permeability of oil and water decreases with increasing water-oil viscosity ratio and decreasing fracture aperture and increasing displacing velocity. Fracture dip has little effect on the shape of the relative permeability curve. Residual oil saturation decreases with decreasing water-oil viscosity ratio, increasing fracture aperture, increasing fracture dip, and increasing displacing velocity.

An Estimation of Water-Oil Relative Permeability Full Curves by ANFIS

Adaptive neuro-fuzzy inference system is an intelligent nonlinear, multivariable technique. In this study, an adaptive neuro-fuzzy inference system was used to identify complex relations between water-oil relative permeability curves and rock and fluid properties. Sixty-seven relative permeability curves from Iranian carbonate and sandstone reservoirs were used in this study. An adaptive neuro-fuzzy inference system was then used to predict un-normalized relative permeability full curves as a function of different rock and fluid properties. High correlation coefficients (R 2) of 0.88 and 0.94 were obtained for oil and water relative permeability curves, respectively. Water relative permeability curves also show no dependency to wettability index of the core and fluid system while oil curves show weak dependency. Adaptive neuro-fuzzy inference system models showed very promising to obtain real water-oil relative permeability full curves when the required core and fluid properties are available. Finally, the effect of porosity, initial water saturation, and wettability on relative permeability curves was investigated by constructed models. Relative permeability of both phases increased with porosity and showed decreasing with initial water saturation. Wettability has no considerable effect on relative permeability curves.

Study on Performance Evaluation of Dispersed Particle Gel for Improved Oil Recovery

This work investigates the performance of dispersed particle gel (DPG) by core flow tests including injectivity, selective plugging, thermal stability, and improved oil recovery (IOR). Results showed that the resistance factor is small when DPG was injected, but obviously became larger while turning into brine water flooding. Both the oil and water relative permeability were reduced and greater reduction appeared in water relative permeability. DPG could block water flow without affecting oil flow, and oil–water segregated flow mechanism was proposed to explain this selective plugging. The injection pressure increases, caused by strong plugging due to the DPG aggregation aging in high temperature, which was consistent with the observation of atomic force microscope (AFM) photos. The DPG could effectively block high permeability zone and produce oil from low permeability zone, which could provide a practical way to enhance hydrocarbon recovery while reducing water production for extremely heterogeneous reservoirs.

An Improved Three-Phase Relative Permeability and Hysteresis Model for the Simulation of a Water-Alternating-Gas Injection

Summary Water-alternating-gas (WAG) injection in waterflooded reservoirs can increase oil recovery and extend the life of these reservoirs. Reliable reservoir simulations are needed to predict the performance of WAG injection before field implementation. This requires accurate sets of relative permeability (kr) and capillary pressure (Pc) functions for each fluid phase, in a three-phase-flow regime. The WAG process also involves another major complication, hysteresis, which is caused by flow reversal happening during WAG injection. Hysteresis is one of the most important phenomena manipulating the performance of WAG injection, and hence, it has to be carefully accounted for. In this study, we have benefited from the results of a series of coreflood experiments that we have been performing since 1997 as a part of the Characterization of Three-Phase Flow and WAG Injection JIP (joint industry project) at Heriot-Watt University. In particular, we focus on a WAG experiment carried out on a water-wet core to obtain three-phase relative permeability values for oil, water, and gas. The relative permeabilities exhibit significant and irreversible hysteresis for oil, water, and gas. The observed hysteresis, which is a result of the cyclic injection of water and gas during WAG injection, is not predicted by the existing hysteresis models. We present a new three-phase relative permeability model coupled with hysteresis effects for the modeling of the observed cycle-dependent relative permeabilities taking place during WAG injection. The approach has been successfully tested and verified with measured three-phase relative permeability values obtained from a WAG experiment. In line with our laboratory observations, the new model predicts the reduction of the gas relative permeability during consecutive water-and-gas-injection cycles as well as the increase in oil relative permeability happening in consecutive water-injection cycles.

Experimental investigations of variations in petrophysical rock properties due to carbon dioxide flooding in oil heterogeneous low permeability carbonate reservoirs

Carbon dioxide has been successfully applied worldwide as an enhanced oil recovery process. Several important factors still have not been studied thoroughly. Therefore, this experimental study was carried out to investigate the variations in petrophysical reservoir rock properties of oil heterogeneous low permeability carbonate reservoirs. The main objectives of this experimental study are to investigate the effects of CO2 injection in tight limestone reservoir rocks on porosity, absolute and relative permeability, oil–water interfacial tension (IFT), reflective index, and reservoir water shielding phenomenon. Actual rock and fluid samples from an oil field in Abu Dhabi, UAE, are used to conduct this study at similar reservoir conditions of 4,000 psia and 250 °F. Oil recovery, permeability, porosity, and relative permeability were measured before and after the supercritical carbon dioxide (SC-CO2) flood to examine the effects of SC-CO2 flood on the variation in different oil and rock properties of tight composite limestone reservoir rocks. Detailed compositional analysis of initial and produced oil samples of core flood experiments were analyzed using gas chromatography to assess the mechanism of CO2 improved oil recovery. The results indicated that the application of SC-CO2 flooding under secondary and tertiary modes reduces porosity and permeability, alters relative permeability to a more water-wet condition, and reduces the oil/water IFT as a function of pore volume injected. Furthermore, the extracted components of the crude oil were also proven to be a function of injected CO2 pore volume. The applications of the attained results of this study provide much better understanding of different variation occurring in oil reservoirs under SC-CO2 injection and can be used effectively to validate and improve numerical simulation studies.

Horizontal well inflow performance relationship in foamy heavy oil reservoirs

Abstract Based on the recovery feature, oil and gas relative permeability law and driving mechanism of foamy heavy oil reservoirs, inflow performance relationship of horizontal wells in this kind of reservoirs was studied using multi-component numerical simulation and reservoir engineering methods. A dimensionless IPR equation of horizontal wells in foamy heavy oil reservoirs was also presented. Applying foamy oil multi-component numerical simulation, the IPR curve of horizontal wells in foamy heavy oil reservoirs was obtained: when the average formation pressure is high, the right end of the IPR curve is slightly upturned which shows foamy oil characteristics; with the decrease of average formation pressure, the characteristics of conventional solution-gas-drive reservoirs begin to appear. After comparing the dimensionless IPR curve of foamy heavy oil reservoirs with that of conventional solution-gas-drive reservoirs, it was found that: when dimensionless pressure is high, for both of these two kinds of reservoirs, dimensionless pressure and dimensionless oil production basically display linear relationship; when dimensionless pressure is low, the right end of the IPR curve of foamy heavy oil reservoirs is slightly upturned and that of conventional solution-gas-drive reservoirs is downturned. The relative error between the oil production calculated by the dimensionless IPR equation of horizontal wells in foamy heavy oil reservoirs and actual oil production is less than 13%. This research result can be used to direct the development of foamy heavy oil reservoirs.

Recovery Mechanisms and Relative Permeability for Gas/Oil Systems at Near-Miscible Conditions: Effects of Immobile Water Saturation, Wettability, Hysteresis, and Permeability

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 interfacial tension (IFT). In this paper, we present the results of a series of two- and three-phase gas injection (drainage) and oil injection (imbibition) core flood experiments for a 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- 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 permeability (kr) curves in the 65 mD core. Hysteresis was less for the 1000 mD core (in comparison to the 65 mD core), but it still could not be ignored. Near-miscible kr hysteresis was significan...