Two-phase Relative Permeability Research Articles

Effects of methane hydrates on two-phase relative permeability in sandstone: Numerical simulation of laboratory experiments

To identify the challenges and limitations in measuring and modelling gas relative permeability in hydrate bearing sandstone, we simulate a series of experiments. Experimental and numerical results are used to examine the amount of hydrates formed as well as how the flow of gas is affected by the hydrate formation. The reservoir simulator TOUGH+HYDRATE was used. The system is represented numerically in both 1-dimensional and 2-dimensional grids. The 1-dimensional simulations are used to check the system consistency by keeping track of the amount of hydrates that are formed, given the initial and boundary conditions. The 2-dimensional simulations are used to measure the effects of heterogeneity in the distribution of hydrates, and its impact on both relative permeability and capillary pressure. The results reveal complexities when comparing experimental and simulated permeability in hydrate-bearing systems. The results from the 1-dimensional calculations show that most experiments have not been able to form the amount of hydrates that is theoretically possible by the initial mix of brine and gas. This indicates that early growth of hydrates can limit mass transfer to inner parts of the core shielding the system for further nucleation. This is supported by the 2-dimensional simulations. These show how a heterogeneous pattern of hydrates can limit fluid flow by (a) reducing the intrinsic permeability, (b) scaling down gas relative permeability, and (c) and scaling up capillary entry pressure of portions of the core. Although these effects do not fully explain the experimental results, the results provide insight to hydrate induced flow restrictions and how these can affect experimental result. • Comparison between simulation and experimental measurements of gas relative permeability of methane hydrate-bearing sandstone. • Heterogeneous formation of hydrates can affect experimental measurements of flow through porous media. • Characterization of hydrate heterogeneity is essential to model effective phase permeability. • Modelled hydrate-driven changes in both permeability and capillary pressure results in a reduction of effective fluid.

A Novel Model for Oil-Water Two-Phase Relative Permeability of Shale Formation During Flowback Based on Fractal Method

A Novel Model for Oil-Water Two-Phase Relative Permeability of Shale Formation During Flowback Based on Fractal Method

Intelligent Microfluidics Research on Relative Permeability Measurement and Prediction of Two-Phase Flow in Micropores

Relative permeability is a key index in resource exploitation, energy development, environmental monitoring, and other fields. However, the current determination methods of relative permeability are inefficient and invisible without considering wetting order and pore structure characteristics either. In this study, microfluidic experiments were designed for figuring out key factors impacting on the two-phase relative permeability. The optimized intelligent image recognition was established for saturation extraction. The deep learning was conducted for the prediction of two-phase permeability based on the inputs from microfluidic experiments and image recognition and optimized. Results revealed that phase saturation, wetting order, and pore topology were the key factors influencing the two-phase relative permeability, with the importance of 38.22%, 34.84%, and 26.94%, respectively. The deep learning-based relative permeability model performed well, with MSE < 0.05 and operational efficiency of 3 ms/epoch. Aiming at relative permeability model optimization, on the one hand, the dividing ratio of training set and testing set for flooding phase relative permeability prediction achieved the highest prediction accuracy at 7 : 3, while that for displaced phase was 6 : 4. On the other hand, tanh() activation function performed 40% more accurate than the sigmoid() activation function.

Relative permeability measurement of coal microchannels using advanced microchip technology

The gas–water flow in coal cleats is an important factor affecting coalbed methane production. However, difficulties are often encountered in the prediction of gas production. Limited understanding of two-phase flow behaviour in microchannels reduces prediction accuracy, often leading to overestimation. In this study, based on micro-computed tomography, advanced microchip technology is used to predict the optimal coal cleat in the polydimethylsiloxane chip. Gas and liquid injection experiments are carried out on the microchannels through the syringe pumps, as the two-phase flow morphology in the system can obtain flow information that cannot be provided by conventional laboratory measurements. The flow capacities of single-phase gas, water, and wetting liquid in the microchannels are compared, alongside determining the flow laws under different wettability and flow rates. The results show that in the single-phase fluid injection experiment, gas is more sensitive to the microchannel size effect than the liquid phase, and hydrophilic liquids flow readily. The gas–water relative permeability value in this study is significantly smaller than that obtained from conventional experiments, based on the steady-state method. This is a result of the gas–water forming a discontinuous plug flow in the microchannel, which produces higher resistance and reduces flow capacity. The occurrence of discontinuous flow regimes challenges the laminar flow assumption adopted in the steady-state method and suggests that conventional laboratory measurements of relative permeability measurements may misrepresent the physics of fluid flows in microchannels. The results also reveal that a hydrophilic environment and a suitable flow rate can increase the two-phase relative permeability. The results of this study enhance our understanding of and approach to core flooding measurement, with the differences in the relative permeability curves indicating that data uncertainty associated with the steady-state method is worthy of further research.

Carbon nanodots for enhanced oil recovery in carbonate reservoirs

Enhanced oil recovery (EOR) operations in oil-wet carbonate reservoirs face enormous challenges such as long-term chemical and thermal stability issues, high retention and adsorption, diffusion, and, accordingly, an inability to reach deep into the reservoir. This study investigates the EOR potential of Carbon nanodots (CNDs) in coreflood experiments using both outcrop and reservoir carbonate samples. CNDs have excellent colloidal stability and mobility in the harsh carbonate reservoir environment. We also compared its performance against an in-house Gemini surfactant (GS8) of excellent surfactancy properties. Experiments were performed at the ”typical” Saudi Arabian reservoir conditions.We tested three flooding patterns using different rock permeabilities and additive concentrations in the SW. Based on the results, the added oil recovery with CNDs and GS8 ranged from 3%–23% and 6%–22%, respectively. At the same dilute concentration, CNDs are more effective than GS8 in increasing oil recovery. X-ray coreflood experiments provided a real-time 1-D saturation profile. It allowed gauging the efficacy of each additive in situ while tracking the oil and water saturation in and recovery from the carbonate samples. The saturation profiles were compared qualitatively against the oil recovery data from these experiments. Unsteady state, two-phase relative permeability curves of the X-ray coreflood experiments revealed the flow characteristics of oil and water during the injection of different fluids. Both CNDs and GS8 increased the oil’s relative permeability, kro and reduced the water’s relative permeability, krw.Overall, CNDs proved highly efficient, economical, and more scalable than a leading surfactant candidate. CNDs are based on a simple, single-pot synthesis process and have a proven-stability and mobility in the field. And in dilute concentrations (10–200 ppm), it alters the dynamic wettability of the carbonate reservoir favorably. Potentially, these can boost the oil recovery at depths (from the injector) that are unreachable by the conventional surfactants.

Assessment of two-phase relative permeability hysteresis models for oil/water, gas/water and gas/oil systems in mixed-wet porous media

Accurate determination of relative permeability curves and their hysteresis is vital for reliable prediction of the performance of oil and gas reservoirs under enhanced recovery processes. Two out of the three available approaches to simulate three-phase relative permeability hysteresis are based on two-phase hysteresis. A few options (e.g., Carlson, Killough and Jargon models) are available in commercial reservoir simulators to account for hysteresis in relative permeability curves under two-phase flow. These models are based on the assumptions of water-wet state of the rocks, while most of the reservoir rocks are mixed-wet. As a result the aim of the present work is to evaluate the performance of these hysteresis models for mixed-wet systems. In addition to the above models, more recent ones such as Beattie et al., Kjosavik et al., Spiteri et al. are also evaluated by coupling an in-house MATLAB code with the Eclipse simulator. The assessments of models are performed by comparing their predictions with those of previously reported comprehensive set of experimentally measured relative permeabilities for different two-phase systems. All possible two phase fluid/fluid systems i.e. oil/water, gas/water and gas/oil are considered. The interfacial tension in the case of oil/gas system is extra low (i.e. 0.04 mN.m−1) and it represents near-miscible condition. It is concluded that hysteresis models developed by Killough and Carlson are unable to accurately predict hysteresis effect on relative permeability in oil/gas system under extra low IFT and mixed-wettability. However, either of Killough and Carlson models could provide satisfactory results in gas/water and oil/water systems, respectively. Beattie et al. model that is not used in Eclipse gave a better fit to experimental data in oil/gas system, but it couldn't provide a suitable fit with experimental data in the cases of gas/water and oil/water systems. For different fluids systems, Kjosavik et al. model results were approximately close to the Killough model during the imbibition process and Beattie et al. during the drainage process. Even the results of the best models in each category of the two phase systems are not very satisfactorily. This study highlights the lack of a versatile hysteresis model to capture the hysteresis effect in all possible two phase systems for the mixed-wettability. As a result it is vital that modified or even novel hysteresis models in the case of mixed-wet system be developed.

Characterization and Analysis of Anisotropic Relative Permeability

Summary The relative permeability functions of two-phase reservoirs are extensively used in modern reservoir-engineering theories for calculations and numerical simulations. In recent years, the theory of anisotropic reservoir development has advanced rapidly, and the anisotropic absolute permeability of reservoirs has been characterized and applied accurately. However, if only the anisotropy of absolute permeability is considered while neglecting the anisotropy of relative permeability, the effective permeability used in the calculations will differ significantly from that of an actual reservoir. In this study, an anisotropy experiment on two-phase relative permeability, with oil and water, was conducted using natural sandstone without fractures, which demonstrated the existence of anisotropy in relative permeability and analyzed its mechanism. The properties and calculation methods for anisotropic relative permeability were studied under the symmetry groups of a rhombic system. Numerical simulations of the reservoir considering anisotropic relative permeability were performed. The results demonstrated that the anisotropic relative permeability significantly affected the development of the oil reservoir, which is primarily indicated by the significant difference in the seepage direction of oil and water, and the complicated oil/water distribution. The results of this study differed significantly from the conventional understanding of remaining oil distribution. The deformed well pattern established for the anisotropy of the absolute permeability indicated a decrease in the oil-recovery ratio.

Application of percolation, critical-path, and effective-medium theories for calculation of two-phase relative permeability.

There has been active development of numerical pore-network simulation of two-phase immiscible flows in porous media in recent years. These models allow for generation of capillary pressure and relative permeability curves. However, percolation models provide an efficient alternative, with reduced reliance on numerical techniques. Implementation of effective medium or critical path theory along with the percolation model allows for evaluation of the relative permeability curves. Both approximations failed to match the irreducible water saturation for water relative permeability. While the effective medium approximation poorly matches the pore network simulator, the critical path approximation is shown to match the result of the oil relative permeability. Despite the difference in end points, there is qualitative agreement between critical path approximation and the pore network simulator. Moreover, observed differences are not necessarily a drawback due to important boundary effects as discussed in the paper. Our results indicate that percolation-theory based predictions have the potential to become an efficient tool for upscaling by computing two-phase flow properties for numerous porosity subdomains.

Hybrid mathematical modelling of three-phase flow in porous media: Application to water-alternating-gas injection

Machine learning algorithms are extensively used to reduce the complexity of applied problems in various fields, including energy. Accurate prediction of the performance of water alternating gas (WAG) injection as an enhanced oil recovery (EOR) process is of great importance in the optimal management of hydrocarbon resources. In the current work, a hybrid mathematical model is proposed for the near-immiscible WAG injection process. We use data-driven sub-models, including least square support vector machine (LSSVM) and adaptive neuro-fuzzy inference system (ANFIS) in series with an empirical model (EM) and a first principle model (FPM) to study three-phase flow in porous media. The LSSVM and ANFIS sub-models predict the two-phase water-oil, gas-oil, and gas-water relative permeabilities. The outputs from these models are supplied to the empirical models (EMs) to estimate the three-phase relative permeabilities for oil, gas, and water phases. The model developed using LSSVM shows a better prediction performance in estimating the relative permeabilities, compared to that using ANFIS. The relative importance parameter analysis reveals that for the LSSVM sub-model, water saturation is the most influencing input parameter for the gas-water and oil-water systems while for the gas-oil system, gas saturation is the most important input parameter. Using the models proposed in this work, some hybrid models are developed to forecast the ultimate recovery factor (RF) in the testing phase. The predicted ultimate RF values are 92.0%, 91.6%, and 82.9% for the correlation-based EM-FPM, LSSVM-EM-FPM, and ANFIS-EM-FPM hybrid models, respectively, in comparison to the measured ultimate RF value of 93.6% after three cycles of water and gasinjection. Among the proposed hybrid models, the LSSVM-EM-FPM model significantly removes the non-linearity of the two-phase relative permeabilities. In general, the LSSVM-EM-FPM hybrid model possesses the same level of accuracy as that of the EM-FPM hybrid model, but with significantly less model complexity and non-linearity. Thus, the LSSVM-EM-FPM hybrid model can be used in demanding applications such as optimization and control of the WAG injection process, leading to a better resource management.

Correction for capillary pressure influence on relative permeability by combining modified black oil model and Genetic Algorithm

The substantial interference of the tight reservoir's capillary pressure on relative permeability measurement can significantly diminish the prediction accuracy of the oilfield production. This study established an innovative method to eliminate the capillary pressure effect on relative permeability calculation by combining the modified numerical simulation model and the Genetic Algorithm. Steady-state measurements were conducted on tight core sample (0.0321mD) to obtain the initial relative permeability curves using Darcy's law. A modified numerical simulation model that considers equivalent phase pressure for water and oil at outlet surface and directly simulates fixed injection-rate boundary conditions without using wells has been proposed. After analysis of water saturation distribution and pressure distribution along the core, absolute permeability, residual water saturation, and the two-phase relative permeability at corresponding saturation need to be optimized by the Genetic Algorithm based on the initial relative permeability curves to match the experimental results. The outcomes show that the optimized absolute permeability is 19.63% higher than the experimentally measured value, and the optimized residual water saturation is 17.46% lower than the experimental residual water saturation. For the other saturations, the differences between the optimized relative permeability and the experimental results range from 25.93% to 10.57%. The whole divergence of the experiment results and the simulation results about average water saturation and inlet pressure using optimized Kr curves is 1.57%, far less than 69.72% of the unoptimized Kr curves. This research is of great significance for accurately obtaining the relative permeability curves of the tight oil reservoir with intense capillary pressure. • A modified black-oil model is built for accurately simulating capillary end effect. • Lower water injection rate affects relative permeability curves more significantly. • The actual residual water saturation is 17.46% lower than the measured one.

Two-Phase Relative Permeability of Rough-Walled Fractures: A Dynamic Pore-scale Modeling of the Effects of Aperture Geometry

Two-Phase Relative Permeability of Rough-Walled Fractures: A Dynamic Pore-scale Modeling of the Effects of Aperture Geometry

Two-Phase Relative Permeability of Rough-Walled Fractures: A Dynamic Pore-scale Modeling of the Effects of Aperture Geometry

Two-Phase Relative Permeability of Rough-Walled Fractures: A Dynamic Pore-scale Modeling of the Effects of Aperture Geometry

Measurement of Relative Permeability Curves of Cores with Different Permeability and Lengths under Unsteady-State

The oil-water and gas-water relative permeability curves are important reference data for the dynamic analysis and numerical simulation of oil and gas reservoir exploitation. Although the petroleum industry of China and other countries have formulated reference standards for the measuring methods of relative permeability of cores, they haven’t given the definite reference values of the core length, therefore we cannot know for sure whether different core length values are required in the measurement and whether the core length has an impact on the measurement results. In view of this gap, this paper conducted a research on the relative permeability of cores with different lengths. The core samples are artificial core with similar properties as the outcrop cores of the Halfaya Oilfield (Iraq), in our experiment, the oil-water and gas-water relative permeability curves of the sample cores were measured and the results suggest that, for the oil-water relative permeability curves, as the core length grows, the iso-permeability points move to the right, and they basically stabilize when the core length is greater than 20cm; as for gas-water relative permeability curves, in case of low-permeability cores, under constant injection pressure, as the core length grows, the iso-permeability points and the two-phase co-permeation areas present an obvious tendency of moving to the left, but when the core length is greater than 20cm, such tendency is not obvious, and the high-permeability cores do not have such characteristics. These results indicate that, the unsteady-state two-phase relative permeability measurement experiments obtained accurate results at a core length of about 20cm, which provided a reference for similar experiments in subsequent research.

Experimental study of a two-phase system relative permeability in reservoir conditions

Experimental study of a two-phase system relative permeability in reservoir conditions

Effect of Temperature on Bitumen/Water Relative Permeability in Oil Sands

The steam-assisted gravity drainage (SAGD) process is among the most applicable thermal enhanced oil recovery (TEOR) methods in North American heavy oil reservoirs. In addition to improving oil mobility through viscosity reduction, the high-temperature condition that a TEOR method causes may significantly alter the fluid flow performance and behavior, as manifested by the relative permeability to fluids in the reservoir. Therefore, in a SAGD and cyclic steam stimulation (CSS), the relative permeabilities can change within the temperature-gradient region developed around the SAGD chamber or between two cycles of CSS processes. However, there is no unique two-phase relative permeability model, especially for bitumen systems to cover a wide range of temperatures. Therefore, the primary objective of this study is to history-match the results of the recent study done by Esmaeili et al. using a new methodology and to conduct limited steady-state relative permeability measurements at different temperatures to confirm the validity of displacement-based relative permeability curves and then to propose a reliable general relative permeability model as a function of temperature. Twelve history-matched bitumen/water relative permeability sets are obtained in a wide range of temperatures from 70 to 220 °C under a confining pressure higher than 1000 psi and the test pressure in the range of 350–400 psi. An in-house developed reservoir simulator was used to obtain relative permeability curves from isothermal displacement data using the history-matching approach. The results demonstrated that both production and pressure-drop data can be matched using the optimized values of parameters of the generalized Corey relative permeability model. Furthermore, a more reliable value for actual residual oil saturation was determined by applying our new methodology in history matching. A comparative analysis with the steady-state relative permeability data allowed us to determine the extent to which the unsteady-state relative permeability is affected by viscous fingering. A considerable shift in both oil and water relative permeability at higher temperatures is noticed. Furthermore, it is also noted that the endpoint relative permeability to oil and water is also altered significantly. The implicit relative permeability data obtained from this study are consistent with the results of the JBN method that were reported in our previous study. By making the parameters of the Corey relative permeability model dependent on temperature, a new model of temperature-dependent bitumen/water relative permeability in sand was developed. It is anticipated that this model can facilitate inclusion of temperature-dependent relative permeability in reservoir simulation studies.

A Comprehensive Model for Estimating Stimulated Reservoir Volume Based on Flowback Data in Shale Gas Reservoirs

Stimulated reservoir volume (SRV) which is generated by horizontal drilling with multistage hydraulic fracturing governs the production in the shale gas reservoirs. Although microseismic data has been used to estimate the SRV, it is high-priced and sometimes overestimated. Additionally, the effect of stress sensitivity on SRV is not considered in abnormal overpressure areas. Thus, the objective of this work is to characterize subsurface fracture networks with stress sensitivity of permeability through the shale gas well production data of the early flowback stage. The flowback regions are first identified with the flowback data of two shale gas wells in South China. Then, we measured the permeability stress sensitivity of the core after fracturing, coupled to the dynamic relative permeability (DRP) calculation to obtain an accurate and simple DRP curve. After that, a comprehensive model is built considering dynamic two-phase relative permeability function and stress sensitivity. Finally, we compared the calculated results with the microseismic data. The results show that the proposed model could reasonably predict the SRV using the flowback data after fracturing. Additionally, compared with the microseismic data, the stress sensitivity should be included, especially in the abnormal overpressure block. It is believed that this mathematical model is accurate and useful. The work provides an efficient approach to estimate stimulated reservoir volume in the shale gas reservoirs.

A Semianalytical Approach for Analysis of Wells Exhibiting Multiphase Transient Linear Flow: Application to Field Data

Summary Rate-transient analysis (RTA) is a useful reservoir/hydraulic fracture characterization method that can be applied to multifractured horizontal wells (MFHWs) producing from low-permeability (tight) and shale reservoirs. In this paper, we applied a recently developed three-phase RTA technique to the analysis of production data from an MFHW completed in a low-permeability volatile oil reservoir in the Western Canadian Sedimentary Basin. This RTA technique is used to analyze the transient linear flow regime for wells operated under constant flowing bottomhole pressure (BHP) conditions. With this method, the slope of the square-root-of-time plot applied to any of the producing phases can be used to directly calculate the linear flow parameter xfk without defining pseudovariables. The method requires a set of input pressure/volume/temperature (PVT) data and an estimate of two-phase relative permeability curves. For the field case studied herein, the PVT model is constructed by tuning an equation of state (EOS) from a set of PVT experiments, while the relative permeability curves are estimated from numerical model history-matchingresults. The subject well, an MFHW completed in 15 stages, produces oil, water, and gas at a nearly constant (measured downhole) flowing BHP. This well is completed in a low-permeability,near-critical volatile oil system. For this field case, application of the recently proposed RTA method leads to an estimate of xfk that is in close agreement (within 7%) with the results of a numerical model history match performed in parallel. The RTA method also provides pressure–saturation (P–S) relationships for all three phases that are within 2% of those derived from the numerical model. The derived P–S relationships are central to the use of other RTA methods that require calculation of multiphase pseudovariables. The three-phase RTA technique developed herein is a simple-yet-rigorous and accurate alternative to numerical model history matching for estimating xfk when fluid properties and relative permeability data are available.

Experimental studies of shear-induced changes in two-phase relative permeability

Numerical reservoir simulation is often used as a tool to forecast the production performance of oil and gas fields. Multi-phase flow functions including relative permeability and capillary pressure relationships are important components for modeling fluid distribution and movement in a porous medium, and they are strongly influenced by the pore structure. Often, relative permeability curves are habitually modified, without consideration of geomechanics effects, during the history match process. However, the depletion or injection of oil and gas reservoirs generally alters the effective stress of the system as a result of either decreasing or increasing of pore pressure. This causes changes in grain arrangement or pore structure. In this paper, a series of isotropically consolidated drained triaxial compression tests were conducted to investigate the behavior of very dense, reconstituted specimens at low effective stress conditions. After restoring the specimens to the desired reservoir conditions, the specimens were sheared under a drained compression-loading path. At various levels of axial strain, steady-state process, absolute and relative permeability tests were performed. Our results showed that in two-phase flow, the oil relative permeability was more sensitive to stress in comparison to the water relative permeability. This change of oil relative permeability was up to about 30%. Also, it was noticed from preliminary capillary pressure measurements that both cycles of drainage were significantly affected by the shear-induced contractive and dilative volume changes. This study supports the notion that relative permeability curves, instead of being kept constant, should be updated depending on the in situ stress-strain behavior.

Two-phase bitumen/water relative permeability at different temperatures and SAGD pressure: Experimental study

The heavy oil or bitumen trapped in subterranean formations in Canada and North America can be effectively produced and recovered using thermal enhanced oil recovery (TEOR) techniques, especially steam assisted gravity drainage (SAGD) processes. Heating the formation to a high temperature greatly reduces the oil viscosity, which increases the oil mobility in the reservoir. In the SAGD process, the steam injected through a long horizontal well creates a steam saturated zone, called steam chamber, around the well that gradually expands laterally and vertically within the reservoir. The edge of the growing steam chamber is where the oil is displaced by the steam. There is a large temperature gradient in the oil drainage zone with steam temperature at the edge of the steam chamber and close to the original reservoir temperature on the other side of the drainage zone. The fluid flow behavior, which is controlled by relative permeability, can be sensitive to the temperature in this transition zone. The objective of this study was to investigate the impact of temperature on two-phase bitumen/water relative permeability of sand over a wide range of temperature from 70 to 220 °C.In the present study, isothermal displacement experiments were conducted with an advanced experimental rig under the confining pressure of 1400 psi using Athabasca bitumen, deionized water, and clean silica sand at six different temperatures. All experiments were repeated to ensure that the results are repeatable and reliable. The JBN (Johnson, Bossler and Neumann) method was used to obtain the two-phase relative permeability. The effect of temperature on relative permeability for the bitumen system was found to be substantial and should be accounted for in simulation of SAGD processes. The endpoint water relative permeability can increase by two orders of magnitude in going from the reservoir temperature to the steam temperature. The endpoint oil relative permeability also increases, albeit more modestly and the residual oil saturation decreases. Besides the relative permeability tests, contact angle and IFT measurements at high-temperature, high-pressure conditions were conducted to evaluate the fluid-fluid and rock-fluid interactions and examine any changes in wettability. According to the contact angle results, the wettability of system was water-wet and shifted toward strongly water-wet at higher temperatures. In addition, the IFT displayed a decreasing trend with temperature and reached the minimum value of 18 mN/m in the temperature range of 125–155 °C.

An experimental study of the effect of three metallic oxide nanoparticles on oil-water relative permeability curves derived from the JBN and extended JBN methods

The relative permeability curves of SiO2, TiO2 and Al2O3 nanofluids-oil and deionized water-oil were carried out by the unsteady state method. Combined with a T2 spectrum comparison of the sandstone core before and after displacement, the influence of different nanofluids on the oil-water relative permeability curve and pore size distribution of the core samples were analyzed. In this paper, the traditional relative permeability data evaluation method (JBN method) is extended by considering capillary pressure changes and the threshold pressure gradient caused by the Jamin effect at the micro pore-throat of the consolidated core sample. The micro capillary force with consideration of the Jamin effect was determined via the gas Jamin effect equation. The relative permeability curve calculated using the extended JBN method was compared with that obtained by the traditional JBN method. The results showed that hydrophilic SiO2, TiO2 and Al2O3 nanoparticles could change the end value of the relative permeability curve relative to that of the deionized water-oil two-phase relative permeability curve. When the relative permeability of the oil phase is minimum, the corresponding water saturation changes from about 0.7 to about 0.9. This means that the oil phase is still able to flow with high nanofluid saturation. The most important point was that the isotonic point shifted to the right, which is very useful for oil displacement and reducing residual oil saturation. The water saturation corresponding to the isotonic point changes from 0.5 to about 0.7, which indicates that hydrophilic nanoparticles can significantly change the wetting properties of the core after entering the core.