Oil Relative Permeability Research Articles

Solid-Liquid Interfacial Effects on Residual Oil Distribution Utilizing Three-Dimensional Micro Network Models

A number of experiments on fluid flow at the micro/nano-scale have demonstrated that flow velocity obviously deviates from the classical Poiseuille’s law due to the micro forces between the wall and the fluid. Based on an oil–water two-phase network simulation model, a three-dimensional pore-scale micro network model with solid–liquid interfacial effects was established. The influences of solid–liquid interface effects including van der Waals force and wettability on the residual oil distribution and relative permeability were investigated through microscopic simulation. The effects of pore radius, pore–throat size ratio, shaping factor, and coordination number on the residual oil distribution were analyzed at the same time. The results showed that the oil recovery would be overestimated by about 4% without van der Waals force in a water-wet reservoir. The impact of van der Waals force on water-wet reservoirs was significantly obvious in contrast with oil-wet reservoirs. In addition, the residual oil distribution was significantly influenced by pore radius in water-wet reservoir, comparatively influenced by pore–throat size ratio in oil-wet reservoir. The present study illustrates the successful application of three-dimensional micro network models considering solid–liquid interfacial effects, and provides new insights for oil recovery enhancement.

Approximate Semi-analytical Solution for Injection–Falloff–Production Well Test: An Analytical Tool for the In Situ Estimation of Relative Permeability Curves

An injection–falloff–production test (IFPT) was originally proposed in Chen et al. (in: SPE conference paper, 2006. doi: 10.2118/103271-MS , SPE Reserv Eval Eng 11(1):95–107, 2008) as a well test for the in situ estimation of two-phase relative permeability curves to be used for simulating multiphase flows in porous media. Hence, we develop an approximate semi-analytical solution for the two-phase saturation distribution in an oil–water system during the flowback period of an IFPT according to the mathematical theory of waves. In fact, we show that the weak solution we construct for the saturation equation for the flowback period satisfies the Oleinik entropy condition and hence is unique. In addition, we allow the governing relative permeabilities during the flowback period to be different from the relative permeabilities during injection. Using the saturation solution with the steady-state pressure theory of Thompson and Reynolds, we obtain a solution for the wellbore pressure during the flowback period. By comparing results from our solution with those from a commercial numerical simulator, we show that our approximate semi-analytical solution yields accurate saturation profiles and bottom hole pressures history. The use of very small time steps and a highly refined radial grid is necessary to generate a good solution from a reservoir simulator. The approximate analytical pressure solution developed is used as a forward model to match pressure and water flow rate data from an IFPT in order to estimate reservoir rock absolute permeability and skin factor in conjunction with in situ imbibition and drainage water–oil relative permeabilities.

Application of waterflooding technique to the Angut oilfield in the northern part of Afghanistan

The purpose of the paper is to use the Buckley–Leverett frontal displacement theory to evaluate the recovery of oil by waterflooding for the Angut oilfield in northern Afghanistan. The waterflooding technique, in which oil is displaced by injecting water into the underlying petroleum reservoir, is investigated for the reservoir field where oil extraction has not been started. The effectiveness of the waterflooding technique is demonstrated by laboratory experiments using a horizontal plane model. The relative permeabilities of oil and water, residual oil saturation and irreducible water saturation are inspected through the experiments. The theory is then applied to the Angut oilfield to evaluate the amount of oil recovery from Angut oilfield by waterflooding technique.

Identifiability of parameters of three-phase oil relative permeability models under simultaneous water and gas (SWAG) injection

We assess the relative performance of a suite of selected models to interpret three-phase oil relative permeability data and provide a procedure to determine identifiability of the model parameters. We ground our analysis on observations of Steady-State two- and three-phase relative permeabilities we collect on a water-wet Sand-Pack sample through series of core-flooding experiments. Three-phase experiments are characterized by simultaneous injection of water and gas into the core sample initiated at irreducible water saturation, a scenario which is relevant for modern enhanced oil recovery techniques. The selected oil relative permeability models include classical and recent formulations and we consider their performance when (i) solely two-phase data are employed and/or (ii) two- and three-phase data are jointly used to render predictions of three-phase oil relative permeability, kro. We assess identifiability of model parameters through the Profile Likelihood (PL) technique. We rely on formal model discrimination criteria for a quantitative evaluation of the interpretive skill of each of the candidate models tested. We also evaluate the relative degree of likelihood associated with the competing models through a posterior probability weight and use Maximum Likelihood Bayesian model averaging to provide model-averaged estimate of kro and the associated uncertainty bounds. Results show that assessing identifiability of uncertain model parameters on the basis of the available dataset can provide valuable information about the quality of the parameter estimates and can reduce computational costs by selecting solely identifiable models among available candidates.

Field-scale simulation of CO2 enhanced oil recovery and storage through SWAG injection using laboratory estimated relative permeabilities

Numerical simulations are widely used to investigate the performance of simultaneous water and gas (SWAG) injection in an oil field. However, they usually use two-phase water and gas relative permeability functions (krg) and one of the known correlations (e.g., Stone, Baker) to calculate oil relative permeability in a three-phase displacement. Moreover, the same krg is used for all SWAG injections, irrespective of miscibility conditions or fraction of gas injected (FGI).Recent experiments have shown that gas relative permeability functions in three-phase SWAG are significantly different from the conventionally used two-phase functions. This paper investigates the impact of using experimentally estimated three-phase gas relative permeability functions on co-optimization study of CO2 storage and enhanced oil recovery (EOR). A three-dimensional, layered reservoir model initially saturated with oil and connate water is used to examine different injection schemes for co-optimizing oil recovery and CO2 storage efficiency. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane by molar fraction. Numerical simulations are run at 70 °C and at three pressures (1300, 1700, and 2100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. SWAG displacements are run at an FGI of 0.5 for immiscible, near-miscible and miscible conditions. Then the effect of FGI dependent relative permeability on co-optimization of CO2 storage and EOR is investigated in the near-miscible condition for FGI values 0.25, 0.5, 0.75 and 1.0.Experimentally estimated three-phase gas relative permeability results in lower CO2 mobility. This leads to higher CO2 saturation and lower water saturation at the end of simulation. The significant increase in CO2 storage efficiency and hence the co-optimization function are more prominent in near-miscible and miscible displacements than in immiscible. Although, for the homogeneous model, ultimate oil recovery is the same when two-phase or experimentally estimated three-phase relative permeabilities are used, ultimate recovery value is significantly affected in the heterogeneous reservoir model.

Crude Oil Quantity and Its Effect on Chalk Surface Wetting

Injection of a Smart Water, with a modified and optimized ionic composition, is an environmentally friendly and cheap enhanced oil recovery (EOR) method. To be able to optimize the ionic composition to cause wettability alteration in the reservoir, one must understand the initial wetting of the reservoir. Experimental studies have confirmed that acidic material in the crude oil, especially negatively charged carboxylates, R–COO–, are the most important wetting parameters toward positively charged carbonate surfaces that dictate the rock wettability. The carboxylate molecules bond strongly to the carbonate surface, and these crude oil anchor molecules can only be removed from the calcite surface by chemical reactions. Generating representative core wettability during core restoration in the laboratory is important for doing realistic oil recovery studies, capillary pressure and relative permeability measurements. Water-wet outcrop chalk cores showing good reproducibility were used to study adsorption of carboxylic material onto chalk. Crude oil with a known acid number (AN) was flooded in different quantities through water-wet chalk cores containing 10% formation water saturation. The core wetting was evaluated by spontaneous imbibition tests, forced imbibition tests, and chromatographic wettability tests. The results of the work showed that the core wetting was determined by the amount of crude oil flooded through the core. The one core that had seen only 5 pore volumes (PV) of crude oil behaved much more water-wet than the core that had seen 15 PV of the same crude oil. Oil recovery by spontaneous imbibition was both lower and slower from the core that had seen the most oil, owing to the difference in wetting and capillary forces. With forced imbibition, viscous forces were introduced and the oil recovery immediately increased in both cores. The increase in oil recovery from the most water-wet core was larger than that of the less water-wet core, despite the residual oil saturation and, consequently, the EOR potential being lower in the most water-wet core. This suggested that the capillary forces not only influenced the spontaneous imbibition but also the forced imbibition, leading to a difference in recovery, which was related to a difference in wetting.

Study on microheterogeneity and seepage law of reservoir after long-term water flooding

In order to carry out research on variation of microheterogeneity in sandstone reservoir after long-term water flooding in the complex faulted oilfields, the cores are cut from typical wells of main oil layers of two blocks in the Jidong Oilfield, and the experiments of long-term water flooding are conducted. Based on the mercury-injection data at different water cut stages during water flooding and the digital core data reconstructed by X-ray CT scanning, the variation of microheterogeneity of reservoir at different water cut stages during long-term water flooding of core are quantitatively characterized through fractal dimension method and 3D pore network model, and the rule of oil–water seepage at different water cut stages is characterized. The study showed that the middle–high-permeability reservoir has a good fractal structure with fractal dimension between 2 and 3. The large pore has the less fractal dimension, and the better homogeneity and pore structure than the small one. After the cores are washed by long-term water flooding, and as the water cut increases, the fractal dimensions of large and small pore gradually decrease, mean and medium pore diameters increase, the relative sorting coefficient decreases, the distribution probability of throat radius of core generally increases, and the microheterogeneity of reservoir weakens. Moreover, the oil relative permeability curves are almost overlapped, and the water relative permeability curves result in a big difference. Under the same water saturation, as the water cut increases, the fractal dimension decreases, the water relative permeability increases, and the oil–water common seepage points shift to the left.

CO2 flooding strategy to enhance heavy oil recovery

Abstract CO2 flooding is one of the most promising techniques to enhance both light and heavy oil recovery. In light oil recovery, the production pressure in CO2 flooding in general keeps constant in order to maintain the miscibility of injected CO2 and crude oil; while in heavy oil recovery, a depleting pressure scheme may be able to induce foamy oil flow, thus the oil recovery could be further enhanced. In this study, different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one. Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO2 flooding strategies. For the core-flooding experiments, 1500 mD sandstone cores, formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition (55 °C and 11 MPa) were used. Before each CO2 flooding test, early stage water-flooding was conducted until the water cut reached 90%. Different CO2 injection rates and production pressure control strategies were tested through core-flooding experiments. Experimental results indicated that a slower CO2 injection rate (2 ml/min) led to a higher recovery factor from 31.1% to 36.7%, compared with a high CO2 injection rate of 7 ml/min; for the effects of different production strategies, a constant production pressure at the production port yielded a recovery factor of 31.1%; while a pressure depletion with 47.2 kPa/min at the production port yielded 7% more oil recovery; and the best pressure control scheme in which the production pressure keeping constant during CO2 injection period, then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5% of the initial OOIP. For the numerical simulations study, the same oil relative permeability curve was applied to match the experimental results to all tests. Different gas relative permeability curves were obtained when the production pressure schemes are different. A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases. The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes. Through this study, it is suggested that the pressure control scheme can be optimized in order to maximize the CO2 injection performance for enhanced heavy oil recovery.

A new water drive curve at ultra-high water cut stage and application in prediction of oilfield development

For the water-flooded reservoir at ultra-high water cut stage, the ratio of oil and water relative permeability and the water saturation deviate from the linear relationship and show the downwarping trend in the semi-log coordinate, and the conventional water drive curves show the upwarping trend. Aiming at predicting the dynamic, recoverable reserve and recovery of oilfields at ultra-high water cut stage, a new formula characterizing the relation between the ratio of oil and water relative permeability and the water saturation was proposed, derivation of a new water drive curve was done by reservoir engineering methods, and the formula of recoverable reserve and recovery was derived. Comparison of the new water drive curve and the conventional one through numerical simulation and field application showed higher accuracy and better adaptability resulted from the new water drive curve, which solved the problems of upwarping and big prediction error in curves of ultra-high water cut stage.

Effect of temperature on the oil–water relative permeability for sandstone reservoirs

Temperature has a significant effect on oil–water relative permeability, which is very important in reservoir development. Considerable controversy persists regarding the effects of temperature and concerning how to obtain representative relative permeability curves. This work studies the effect of temperature on the oil–water relative permeability of tight sandstone and analyzes the influences of absolute permeability, clay mineral content, and pore throat structure on relative permeability curves at different temperatures. The results indicate that irreducible water saturation increases linearly with temperature increase, while residual oil saturation decreases nonlinearly with temperature increase. In addition, when temperature increases, both oil and water relative permeability increase under the same water saturation and the crossover saturation moves rightwards, which indicates that the system becomes more water-wet. Due to the significant effect of temperature on relative permeability, experimental results from lab tests cannot accurately reflect fluid flow characteristics under the reservoir condition. In order to overcome this problem, this paper proposes a novel method to translate lab results into reservoir values by combining the Johnson–Bossler–Naumann (JBN) technique and the empirical method. The comparison between the calculation and the lab results is consistent. The conclusions of the paper provide a valuable reference for laboratory tests under high temperature, and they can be used for preliminary evaluation purposes.

An Experimental Investigation of Viscous-Oil Recovery Efficiency as a Function of Voidage-Replacement Ratio

Summary Recovery processes with a voidage-replacement ratio (VRR) (VRR = injected volume/produced volume) of unity rely solely on viscous forces to displace oil, whereas a VRR of zero relies on solution-gas drive. Activating a solution-gas-drive mechanism in combination with waterflooding with periods of VRR less than unity (VRR < 1) may be optimal for recovery. Laboratory evidence suggests that recovery for VRR < 1 is enhanced by emulsion flow and foamy (i.e., bubbly) crude oil at pressures under bubblepoint for some crude oils. This paper investigates the effect of VRR for two crude oils referred to as A1 (88 cp and 6.2 wt% asphaltene) and A2 (600 cp and 2.5 wt% asphaltene) in a sandpack system (18-in. length and 2-in. diameter). The crude oils are characterized with viscosity, asphaltene fraction, and acid/base numbers. A high-pressure experimental sandpack system (1 darcy and Swi = 0) was used to conduct experiments with VRRs of 1.0, 0.7, and 0 for both oils. During waterflood experiments, we controlled and monitored the rate of fluid injection and production to obtain well-characterized VRR. On the basis of the production ratio of fluids, the gas/oil and /water relative permeabilities were estimated under two-phase-flow conditions. For a VRR of zero, the gas relative permeability of both oils exhibited extremely low values (10−6−10−4) caused by internal gas drive. Waterfloods with VRR < 1 displayed encouraging recovery results. In particular, the final oil recovery with VRR = 0.7 [66.2% original oil in place (OOIP)] is more than 15% greater than that with VRR = 1 (55.6% OOIP) with A1 crude oil. Recovery for A2 with VRR = 0.7 (60.5% OOIP) was identical to the sum of oil recovery for solution-gas drive (19.1% OOIP) plus waterflooding (40.1% OOIP). An in-line viewing cell permitted inspection of produced fluid morphology. For A1 and VRR = 0.7, produced oil was emulsified, and gas was dispersed as bubbles, as expected for a foamy oil. For A2 and VRR < 1, foamy oil was not clearly observed in the viewing cell. In all cases, the water cut of VRR = 1 is clearly greater than that of VRR = 0.7. Finally, three-phase relative permeability was explored on the basis of the experimentally determined two-phase oil/water and liquid/gas relative permeability curves. Well-known algorithms for three-phase relative permeability, however, did not result in good history matches to the experimental data. Numerical simulations matched the experimental recovery vs. production time acceptably after modification of the measured krg and krow relationships. A concave shape for oil relative permeability that is suggestive of emulsified oil in situ was noted for both systems. The degree of agreement with experimental data is sensitive to the details of gas (gas/oil system) and oil (oil/water system) mobility.

Adsorption of Acidic Crude Oil Components onto Outcrop Chalk at Different Wetting Conditions during Both Dynamic Adsorption and Aging Processes

Restoration of carbonate reservoir core material for special core analysis has been debated in the literature for some time. An important goal of core restoration is to reproduce initial reservoir wetting properties because wettability dictates important reservoir parameters, such as capillary pressure and relative permeability of oil and water. It has previously been found that acidic polar components in crude oil dictate the wetting properties in carbonate core material. In this paper, the effects on chalk wettability from crude oil flooding, core aging, and mild core cleaning were investigated experimentally. The experimental results confirmed that adsorption of acidic polar components is an instantaneous process and that a dynamic equilibrium was achieved with a specific adsorption capacity of the initially very water-wet chalk surface. The crude oil flooding reduced the water-wet surface area. Core aging for 2 weeks at the test temperature reduced the water-wet surface area even further, which appear...

Comparative assessment of three‐phase oil relative permeability models

AbstractWe assess the ability of 11 models to reproduce three‐phase oil relative permeability ( ) laboratory data obtained in a water‐wet sandstone sample. We do so by considering model performance when (i) solely two‐phase data are employed to render predictions of and (ii) two and three‐phase data are jointly used for model calibration. In the latter case, a Maximum Likelihood (ML) approach is used to estimate model parameters. The tested models are selected among (i) classical models routinely employed in practical applications and implemented in commercial reservoir software and (ii) relatively recent models which are considered to allow overcoming some drawbacks of the classical formulations. Among others, the latter set of models includes the formulation recently proposed by Ranaee et al. (), which has been shown to embed the critical effects of hysteresis, including the reproduction of oil remobilization induced by gas injection in water‐wet media. We employ formal model discrimination criteria to rank models according to their skill to reproduce the observed data and use ML Bayesian model averaging to provide model‐averaged estimates (and associated uncertainty bounds) of by taking advantage of the diverse interpretive abilities of all models analyzed. The occurrence of elliptic regions is also analyzed for selected models in the framework of the classical fractional flow theory of displacement. Our study confirms that model outcomes based on channel flow theory and classical saturation‐weighted interpolation models do not generally yield accurate reproduction of data, especially in the regime associated with low oil saturations, where water alternating gas injection (WAG) techniques are usually employed for enhanced oil recovery. This negative feature is not observed in the model of Ranaee et al. (2015) due to its ability to embed key effects of pore‐scale phase distributions, such as hysteresis effects and cycle dependency, for modeling observed during WAG.

An Influence of Polymer-Alkaline and Nanoparticles as Chemical Additives on the Immiscible Displacement and Phase Relative Permeability

In this study, a chemical additive made by a combination of polymer, alkaline, and silica nanoparticles is used to control the oil recovery and relative permeability curves. Various parametersincluding the type and concentration of polymer, alkaline, and nanosilica particles have been studied.To evaluate the efficiency of these additives, we performed unsteady state displacement experimentsunder the JBN method and determined the pressure gradient across the core samples. Theexperimental observations emphasized that by using the appropriate chemical additives the relativepermeability of the phases is changed towards higher oil relative permeability values, which results inthe oil recovery. The results of this study can improve the chemical flooding for heavy oil recovery.

Numerical Investigation of Coupling Multiphase Flow and Geomechanical Effects on Water Loss During Hydraulic-Fracturing Flowback Operation

SummaryLess than half the fracturing fluid is typically recovered during the flowback operation. This study models the effects of capillarity and geomechanics on water loss in the fracture/matrix system, and investigates the circumstances under which this phenomenon might be beneficial or detrimental to subsequent tight-oil production. During the shut-in (soaking) and flowback periods, the fracture conductivity decreases as effective stress increases because of imbibition. Previous works have addressed fracture closure during the production phase; however, the coupling of imbibition caused by multiphase flow and stress-dependent fracture properties during shut-in is less understood.A series of mechanistic simulation models is constructed to simulate multiphase flow and fluid distribution during shut-in and flowback. Three systems—matrix, hydraulic fracture, and microfractures—are explicitly represented in the computational domain. Sensitivities to wettability and multiphase-flow functions (relative permeability and capillary pressure relationships) are investigated. As wettability to water increases, matrix imbibition increases. Imbibition helps to displace the hydrocarbons into nearby microfractures and hydraulic fractures, enhancing initial oil rate, but it also hinders water recovery. The results indicate that fracture closure may enhance imbibition and water loss, which, in turn, leads to further reduction in fracture pressure and conductivity. Results also suggest that more-aggressive flowback is beneficial to water cleanup and long-term oil production in stiff rocks, whereas this benefit is less prominent in medium-to-soft formations because of excessive fracture closure. Because no direct correlation between high initial oil-flow rate and improved cumulative oil production is observed, measures for increasing oil relative permeability are recommended for improving long-term oil production.This work presents a quantitative study of the controlling factors of water loss caused by fluid/rock properties and geomechanics. The results highlight the crucial interplay between imbibition and geomechanics in short- and long-term production performances. The results in this study would have considerable impact on understanding and improving current industry practice in fracturing design and assessment of stimulated reservoir volume.

Quantitative Characterization of Dynamic Heterogeneity in Reservoirs With Stratified Noncommunicating Layers

Due to the difference of permeability in reservoir and viscosities between oil and water, oil displacement efficiencies at different locations differ significantly. Also, along with the water flooding process, the differences of oil displacement efficiencies change in time and manifest dynamic characteristics, which is called dynamic heterogeneity in this paper. A new parameter called “conductivity index” (IC) is defined, and the Gini coefficient of IC (GCIC) is selected to quantitatively characterize the dynamic heterogeneity in reservoirs with stratified noncommunicating layers. Then, the changing laws and influential factors of GCIC are investigated by physical experiments and numerical simulation methods. Finally, the application of dynamic heterogeneity in individual-layer water injection technique is studied. Based on the theory of seepage flow mechanics, the formula of IC is derived. IC not only contains static parameters including permeability, water, and oil viscosity but also contains dynamic parameters including water and oil relative permeabilities, which are both function of water saturation and also function of rock type. Therefore, IC can reflect the dynamic heterogeneity caused by water flooding process. A five parallel sandpacks' water flooding experiment is conducted to investigate the changes of dynamic heterogeneity. Results show that the value of GCIC increases rapidly before the water breakthrough of the sandpack with highest permeability. Then, after water breakthrough, GCIC decreases slowly. A new parameter GCI is defined to represent the average increase of GCIC during the water flooding process. By numerical simulation method, the influences of Gini coefficient of permeability (GCP) and oil viscosity on GCI are studied. Results show that GCI increases along with the increase of oil viscosity. And GCI first increases and then decreases along with the increase of GCP. When GCP equals 0.6, GCI gets its maximum value. Taking block P of Shengli Oilfield in China, for example, the changes of dynamic heterogeneity along the water flooding process are studied. Results show that the dynamic heterogeneity of each well group varies greatly before and after water flooding. For some well groups, the relative sizes of GCIC even reverse. The performances of different cases in individual-layer water injection technique are investigated by numerical simulation method. Results show that the case both considering dynamic heterogeneity and the remaining oil volume gets the best performance.

Investigation of effect of pore sizes and pore sorting on two phase relative permeability in imbibition process

Relative permeability is one of the main petroleum recovery controller that is a function of porous media and the reservoir fluid. Water flooding titled as one of the eldest EOR methods is still used in some of reservoirs. For proper perception and description of rheology in reservoir scale, knowing the flowing fluid processes specifications and mechanisms and also recognition of porous media type in pore-scale is necessary. In this way, the new age has arrived in reservoir study by introducing porosity model on glass. We can have the two-dimension porous media in actual size by designing a microfluidic chip. This article implies the effects of heterogeneity on relative permeability curves by micro model system and water flooding. High definition photos from different water and oil saturations and also Goodyear equations are used for analyzing the effects of heterogeneity on water and oil permeability in pore-scale. In conclusion, it is observed that in glass micro model oil and water relative permeability curves are dependent on porous media pores sizes. So that as much as these pores grows, the relative permeability will be increased. Moreover, pores sizes distribution and direction have effects on relative permeability.

Relative Permeability Characterization for Water-Alternating-Gas Injection in Oil Reservoirs

Summary Large quantities of oil usually remain in oil reservoirs after conventional waterfloods. A significant part of this remaining oil can still be economically recovered by water-alternating-gas (WAG) injection. WAG injection involves drainage and imbibition processes taking place sequentially; therefore, the numerical simulation of the WAG process requires reliable knowledge of three-phase relative permeability (kr) accounting for cyclic-hysteresis effects. In this study, the results of a series of unsteady-state two-phase displacements and WAG coreflood experiments were used to investigate the behavior of three-phase kr and hysteresis effects in the WAG process. The experiments were performed on two different cores with different characteristics and wettability conditions. An in-house coreflood simulator was developed to obtain three-phase relative permeability values directly from unsteady-state WAG experiments by history matching the measured recovery and differential-pressure profiles. The results show that three-phase gas relative permeability is reduced in consecutive gas-injection cycles and consequently the gas mobility and injectivity drop significantly with successive gas injections during the WAG process, under different rock conditions. The trend of hysteresis in the relative permeabilty of gas (krg) partly contradicts the existing hysteresis models available in the literature. The three-phase water relative permeability (krw) of the water-wet (WW) core does not exhibit considerable hysteresis effect during different water injections, whereas the mixed-wet (MW) core shows slight cyclic hysteresis. This may indicate a slight increase of the water injectivity in the subsequent water injections in the WAG process under MW conditions. Insignificant hysteresis is observed in the oil relative permeability (kro) during different gas-injection cycles for both WW and MW rocks. However, a considerable cyclic-hysteresis effect in kro is observed during water-injection cycles of WAG, which is attributed to the reduction of the residual oil saturation (ROS) during successive water injections. The kro of the WW core exhibits much-more cyclic-hysteresis effect than that of the MW core. No models currently exist in reservoir simulators that can capture the observed cyclic-hysteresis effect in oil relative permeability for the WAG process. Investigation of relative permeability data obtained from these displacement tests at different rock conditions revealed that there is a significant discrepancy between two-phase and three-phase relative permeability of all fluids. This highlights that not only the three-phase relative permeability of the intermediate phase (oil), but also the three-phase kr of the wetting phase (water) and nonwetting phase (gas) are functions of two independent saturations.

Salinity of injection water and its impact on oil recovery absolute permeability, residual oil saturation, interfacial tension and capillary pressure

Laboratory tests and field applications show that low-salinity water flooding could lead to significant reduction of residual oil saturation. There has been a growing interest with an increasing number of low-salinity water flooding studies. However, there are few quantitative studies on flow and transport behavior of low-salinity IOR processes.This paper presents laboratory investigation of the effect of salinity injection water on oil recovery, pressure drop, permeability, IFT and relative permeability in water flooding process. The experiments were conducted at the 80°C and a net overburden pressure of 1700psi using core sample. The results of this study have been shown oil recovery increases as the injected water salinity up to 200,000ppm and appointment optimum salinity. This increase has been found to be supported by a decrease in the IFT. This effect caused a reduction in capillary pressure increasing the tendency to reduce the residual oil saturation.

Modeling of Two-Phase Relative Permeability in Cambrian and Early Miocene Sandstone Reservoirs: A Case Study, Egypt

The relative permeability is the ratio of the effective permeability to the absolute permeability. Due to the importance of relative permeability in reservoir simulation, there is a dominant need to upscale it. So, several models were introduced to modeling the relative permeability. Some correlation models were dependent on capillary pressure measurements, while other models did not require such measurements. In this study, four relative permeability correlation models were chosen to apply them on two sandstone reservoir (labeled A and B) data sets. The two reservoirs belong to different ages and depositional environments. Both reservoirs are located in the Southern Gulf of Suez, Egypt. Reservoir A is the Nubian sandstone of Cambrian age. Reservoir B is the Nukhul clastic of Early Miocene age. The data sets include laboratory measurements of unsteady-state gas–oil relative permeability and steady-state water–oil relative permeability tests. The results indicate that the practical and modified Corey models were the most applicable model for the studied reservoirs. Additionally, prediction of relative permeability at saturation end points was carried out based on using routine core porosity and permeability by introducing new empirical equations. The relative permeability was used to identify rock wettability, water cut, water cutoffs and the areal and vertical sweep efficiencies.