Gas-water Relative Permeability Research Articles

Experimental studies on the movable-water saturations of different-scale pores and relative permeability of low-medium rank coals from the Southern Junggar Basin

The movable-water saturation (MWS) of coal is critical for the flow of coalbed methane (CBM), however, there is a relative lack of research on it, especially of different-scale pores. The relative permeability of coal is another crucial parameter for CBM development due to its strong control on the characteristics of both gas and water production, but it also remains relatively unexplored. Naturally, little attention has been paid to the connections between the MWS and the relative permeability.In this study, an innovative experiment combining water-saturated coal core displacement test with low-field nuclear magnetic resonance (LNMR) was designed to obtain the MWSs of different-scale pores and gas-water relative permeabilities of coals simultaneously. The relative permeability results show that low-medium coals from the Southern Junggar Basin (SJB) were characterized by low MWSs, narrow spans of two-phase flow, and low end-point relative permeabilities to water (Krw*) and gas (Krg*), which were all disadvantageous for CBM development. The calculated MWSs of different-scale pores through the amplitude of T2 spectrum show that “macropores and fractures (MF)” have the highest MWS, with mesopores following next, “micropores and transition pores (MT)” possess the lowest MWS. Correlation analyses show that the total MWSs and movable porosities both present strong positive correlations with the Ka, Krw*, and Krg*. The irreducible water causes a greater obstacle to gas flow than to water flow. The MWSs of different-scale pores all exhibit positive impacts on the coal permeabilities. However, compared with MWSs of MT and MF, the MWSs of mesopores exhibit the strongest correlation with Ka, Krw*, and Krg*, indicating the critical role in affecting the fluid flow of coal. Besides, two significant parameters, cleat tortuosity (η) and cleat size distribution index (λ) of SJB coals, were determined. η and λ were rank-dependent. Coal macerals also have impacts on η and λ.

Stress dependent gas-water relative permeability in gas hydrates: A theoretical model

Research activities are currently being conducted to study multiphase flow in hydrate-bearing sediments (HBS). In this study, in view of the assumption that hydrates are evenly distributed in HBS with two major hydrate-growth patterns, i.e., pore filling hydrates (PF hydrates), wall coating hydrates (WC hydrates) and a combination of the two, a theoretical relative permeability model is proposed for gas-water flow through HBS. Besides, in this proposed model, the change in pore structure (e.g., pore radius) of HBS due to effective stress is taken into account. Then, model validation is performed by comparing the predicted results from the derived model with that from the existing model and test data. By setting the value of hydrate saturation to zero, our derived model can be reducible to the existing model, which demonstrates that the existing model is a special case of our model. The results reveal that, under the same saturation, relative permeability to water K rw (or gas K rg ) in PF hydrates is smaller than that in WC hydrates. Moreover, the morphological characteristics of relative permeability curve (relative permeability versus gas saturation) for WC hydrate and PF hydrate are different. Cited as : Lei, G., Liao, Q., Lin, Q., Zhang, L., Xue, L. Chen, W. Stress dependent gas-water relative permeability in gas hydrates: A theoretical model. Advances in Geo-Energy Research, 2020, 4(3): 326-338, doi: 10.46690/ager.2020.03.10

Gas-water relative permeability of unconventional reservoir rocks: Hysteresis and influence on production after shut-in

Relative permeability is one of the most important parameters in reservoir modeling. However, measurements of relative permeability in unconventional reservoir rocks are rare, and the influence of relative permeability hysteresis on reservoir studies has not previously been addressed. This paper presents a systematic investigation of gas-water relative permeability and hysteresis based on a laboratory technique developed through our previous work. Gas relative permeability was measured using the modified gas expansion method under the scenario of drainage and subsequent imbibition. Water relative permeability was estimated based on Brooks-Corey (1956) equations. Results of gas-water relative permeability that cover a broader range of saturation than that in our previous work were obtained. Causes of relative permeability hysteresis are discussed in detail. The laboratory-based gas-water relative permeability of one of the samples is compared to history-matched results from the literature, and upscaling of the laboratory result is discussed on the basis of this comparison. Finally, the potential influence of relative permeability hysteresis on water and gas production after hydraulic fracturing and shut-in is illustrated through a conceptual model and quantitative analysis. Gas production rates can be overestimated after hydraulic fracturing when hysteresis is ignored. Shut-in can enhance gas production rates significantly. Enhancement of production rate is greater at the initial phase, but it diminishes later, after continuous expansion of the imbibition zone. This work presents the first known study of gas-water relative permeability hysteresis in unconventional reservoir rocks.

A fractal model for gas-water relative permeability curve in shale rocks

Initial water content and subsequent fracturing fluid injection lead to gas-water flow in shale nanopores, especially the water-wet pores. But there is few research and experiment to introduce relative permeability curves governing multiphase transport behaviors in shale nanopores. With the consideration of water true slippage and gas slippage, an analytical model illustrating gas-water relative permeability curve in fractal-like tree pore structures has been constructed, aiming to explain gas-water two phase flow behaviors and further evaluate the effects of pore size distributions and water films on gas-water transport. Sensitivity analysis verifies that smaller pore radius, more branching levels and less branching number tend to increase the gas relative flow capacity. Also, ignoring the existence of high-viscosity water molecules has been discovered to reduce water flow resistance. But if the high-viscosity water film loses its mobility, water relative permeability drops slightly. In contrast, mobile bulk water molecules are mainly conducive to increase the gas molecules relative movements. Besides, the analysis of pore size distribution confirms that the fractal-like tree network possesses a more significant gas dominancy compared with log-normal pore network.

Impact of pore structure and clay content on the water-gas relative permeability curve within tight sandstones: A case study from the LS block, eastern Ordos Basin, China

The water-gas relative permeability of tight sandstones governs the gas production performance and recovery efficiency in a gas reservoir. Reservoir heterogeneity cannot be neglected when we extrapolate water-gas relative permeability curves. However, efforts to determine the variation with rock types and controls of the gas and water permeability have proven insufficient. Rock composition and pore structures play an important role in the spatial variation of water-gas relative permeability and vary with diagenesis evolution. In this study, we investigated the influence of pore-throat structure, clay content and cements on the water-gas relative permeability curves within tight sandstones using casting thin sections, field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), high pressure mercury injection (HPMI), and gas displacement tests on samples from the LS Block, eastern Ordos Basin, China. The results show that there is a weak relationship between the spatial variation of the water-gas relative curves and the physical properties and pore size distribution of tight sandstones. The length of the two-phase flow zone is not closely related to the porosity and permeability in tight sandstones. The gas relative permeability of the crossing point is closely related to the gas permeability, not the water phase permeability. Nevertheless, the clay content is positive to the gas saturation of the crossing point and the length of the two-phase flow. Subsequently, the water-gas relative permeability curves are divided into three types based on the simultaneous vadose region area (SVRA). Finally, the genesis of the change in the water and gas relative permeability of each type is analyzed.

Multiphase flow model from pores to cores in organic-rich shale

The multiphase flow processes during water injection and flowback in shales are largely affected by its multiscale pore structure, different pore types and complex fluid transport mechanisms. At present, it is difficult to measure shale multiphase flow properties in laboratory. This study presents an upscaling model to derive core-scale relative permeability from pore-scale multiphase simulation using organic matter (OM)/inorganic matter (IOM) pore network models. Gas and water absolute permeabilities on OM/IOM pore network models are determined, and gas-water two-phase imbibition (during water injection) and drainage (during flowback) processes in the IOM pore network model are conducted using the invasion percolation theory. A core-scale model is generated with stochastically distributed IOM/OM patches. The upscaled relative permeabilities are derived by assembling gas-water transport properties in the IOM/OM based on the corresponding pore network simulation results. The upscaling method is validated by comparison with an analytical model during water injection and flowback processes. Furthermore, the impacts of total organic carbon (TOC) content and intrinsic permeability ratio of OM to IOM on the upscaled relative permeabilities are analyzed. The critical TOC content and intrinsic permeability ratio at which OM influences the upscaled relative permeabilities are determined. This study provides an effective upscaling workflow to obtain core-scale gas-water relative permeabilities based on pore-scale modeling considering multiple gas/water transport mechanisms in different pore systems.

Pore Structure and Permeability Characterization of High‐rank Coal Reservoirs: A Case of the Bide‐Santang Basin, Western Guizhou, South China

AbstractThe methods of nuclear magnetic resonance (NMR) spectroscopy, mercury injection porosimetry (MIP), and gas‐water relative permeability (GWRP) were used to reveal the pore structure and permeability characteristics of high‐rank coal reservoirs in the Bide‐Santang basin, western Guizhou, South China, to provide guidance for coalbed methane (CBM) exploration and exploitation and obtain direct insights for the development of CBM wells. The results indicate that the coal reservoirs in the study area are characterized by well‐developed adsorption pores and poorly developed seepage pores. The bimodal NMR transverse relaxation time (T2) spectra and the mutation in the fractal characteristic of the MIP pore volume indicate poor connectivity between the adsorption pores and the seepage pores. As a result, the effective porosity is relatively low, with an average of 1.70%. The irreducible water saturation of the coal reservoir is relatively high, with an average of 66%, leading to a low gas relative permeability under irreducible water saturation. This is the main reason for the low recovery of high‐rank CBM reservoirs, and effective enhanced CBM recovery technology urgently is needed. As a nondestructive and less time‐consuming technique, the NMR is a promising method to quantitatively characterize the pores and fractures of coals.

Study on Water Displacing Gas Relative Permeability Curves in Fractured Tight Sandstone Reservoirs Under High Pressure and High Temperature.

Water–gas relative permeability is an important parameter for the rational development of gas fields. Conventional measurement methods are carried out at normal temperature and pressure without considering the actual conditions of high temperature and high pressure. The water displacing gas process in fractured tight sandstone reservoirs, under formation condition (116 MPa and 160 °C), was simulated by the self-manufactured displacing apparatus. The results show that cores under formation condition have the larger residual gas saturation, the smaller two-phase coexisting area, the lower water/gas relative permeability, and the lower displacement efficiency than that under normal conditions. The relative permeability declines slowly and the residual gas saturation is high, making the process of replacing the gas more difficult. The number and the interconnection quality of fractures affect the shape and the position of the displacing curves. It provides a reference for the rational development and further research of fractured tight sandstone reservoir.

An Improved Relative Permeability Model for Gas-Water Displacement in Fractal Porous Media

Many researchers have revealed that relative permeability depends on the gas-water-rock interactions and ultimately affects the fluid flow regime. However, the way that relative permeability changes with fractal porous media has been unclear so far. In this paper, an improved gas-water relative permeability model was proposed to investigate the mechanism of gas-water displacement in fractal porous media. First, this model took the complexity of pore structure, geometric correction factor, water film, and the real gas effect into account. Then, this model was compared with two classical models and verified against available experimental data. Finally, the effects of structural parameters (pore-size distribution fractal dimension and tortuosity fractal dimension) on gas-water relative permeability were investigated. It was found that the sticking water film on the surface of fracture has a negative effect on water relative permeability. The increase of geometric correction factor and the ignorance of real gas effect cause a decrease of gas relative permeability.

Permeability jail for two-phase flow in tight sandstones: Formulation, application and sensitivity studies

Permeability jails in tight rocks correspond to saturation values where no phase is mobile. This can lead to severe impacts on hydrocarbon production. However, although this is a severe and significant problem, there is a limited understanding of the mechanisms behind the concept of a permeability jail, its dependence on pore size distributions, saturations and pressure. In a previous work, we describe a model to compute the flow resistance during two-phase flow in tight rocks. In this paper, we extend our work to propose a model for the permeability jail in tight rocks to calculate relative permeabilities during two-phase flow. The rock is assumed to be characterized by a bundle of capillary tubes with non-uniform radii where the fluids are present as discontinuous phases. The pore-scale flow resistance is calculated which takes into account the capillary pressure induced by the Jamin effect as well as the water and gas viscous forces. The model is validated by experimental data of gas-water relative permeability tests and Nuclear Magnetic Resonance (NMR) experiments on tight cores from the Sichuan Basin in Southwest China. According to the model, the pressure drop between the inlet and outlet sides of the core should be higher than the maximum capillary pressure to maintain flow during the experiments. We also observe that the relative permeability curves are pressure-sensitive. An increase in the pressure drop leads to a reduction of gas relative permeability and an increase of water relative permeability. However, the influence of this pressure drop is somewhat limited. Once trapped in a permeability jail, fluids generally cannot regain flow capability by changing the pressure drop over a small range of values. This necessitates a careful consideration of the factors contributing to the permeability jail in order to avoid loss of well productivity.

Sensitivity of unsteady-state gas-water relative permeability to experimental artefacts and interpretation techniques; case study from a gas reservoir in south Iran

Relative permeability is a key determinant of how a reservoir simulation model performs. Although laboratory measurement techniques for two-phase relative permeability are well-established, but still the difficulties and uncertainties persist. The present study aims to investigate the effect of several parameters, including pressure difference, end-effects, interpretation techniques (analytical and numerical), and mineral dissolution, on the unsteady-state gas-water relative permeability curves. For this purpose, a number of precisely planned experiments were carried out on two subsurface anhydrite dolomite samples collected from a well-known gas reservoir in south Iran.In summary, the measured gas relative permeability (krg) was underestimated at low injection pressures mainly due to the capillary end-effect and a significantly low volume of brine production in compare to the considerable volume that was retained at the end face. Moreover, despite the end-effect was overcame at high injection pressures, but significantly high krg values were recorded at water saturations close to the residual value and the measurements were corrected considering a gas slippage factor at the endpoint.Furthermore, greater wetting phase relative permeability (krw) values were driven from numerical (history matching) interpretation of the results compared with the analytical approach that could be due to the automatic end-effect correction by the numerical techniques where the capillary pressure is accounted for.Finally, to investigate the effect of anhydride dissolution on overestimation of the measured gas relative permeability, the interaction of NaCl brine with anhydride was reviewed using the Computed Tomography (CT) images taken before and after the test.

Influence of reservoir heterogeneity on water invasion differentiation in carbonate gas reservoirs

Diversified heterogeneities tend to occur in carbonate gas reservoirs due to different scales and distribution densities of pores, vugs and fractures in reservoirs, and consequently the water invasion laws of gas reservoirs are more different. In this paper, the methods quantitatively describing the matching relationships between pores, vugs and fractures were improved based on full-diameter core digital processing and analysis so as to understand the heterogeneity of carbonate reservoirs and its influence on the water invasion laws of gas reservoirs and then predict the water invasion dynamics of gas reservoirs. Firstly, a new method to evaluate the contribution of microfractures to reservoir seepage capacity was established according to the analysis chart of percolation theory. Then, gas–water relative permeability and rock compressibility were measured by conducting gas/water seepage and fluid–solid coupling stress sensitivity experiments under the conditions of actual gas reservoir pressure and temperature. And accordingly the effects of various fractures and caves on the gas invasion laws of gas reservoirs were analyzed. Finally, the method to predict the differentiation characteristics of water invasion influence of the reservoirs with different types of physical properties was developed based on the water invasion characteristics of typical carbonate gas reservoirs in the Sichuan Basin. The following research results were obtained. First, in a broad sense, different types of carbonate reservoirs are classified as a triple continuum. The development of fractures speeds up the appearance of water invasion in gas reservoirs while the uniform development of caves slows down the appearance of water invasion effect. Second, the development of microfractures is a prerequisite for ultra-low porosity reservoirs to possess the ability of medium permeability or high permeability. The water invasion law in this case is obviously different from the channeling along large fractures or the water invasion in the network small fracture development belt. Third, the stress sensitivity of reservoir porosity in aquifer is the main source of formation water invasion energy. This characteristic is more prominent in the early stage of the exploitation of abnormal high pressure gas reservoirs. The research results have been applied to water invasion energy assessment, water invasion performance forecast and water control measure effectiveness prediction in a number of carbonate reservoirs in the Sichuan Basin. And they provide effective technical guidance for water invasion control in complex gas reservoirs and further understanding of water invasion differentiation laws.

Experimental investigation into the relative permeability of gas and water in low-rank coal

Understanding the relative permeability characteristics of coal in a gas-water system is crucial for coalbed methane development. Due to a lack of experimental information on the gas-water relative permeability of coal, the relative permeability of the low-rank coals in the Erlian Basin in the north of China was investigated under different conditions using the unsteady-state method. The studied coals are dominated by huminite with high moisture content, volatile yield, and low ash yield. The pore sizes of the coals feature a bimodal pattern distribution with a higher left peak of approximately 10–100 nm and a relatively lower right peak of approximately 10000 nm. The measurement of mercury intrusion-extrusion hysteresis also suggests that ink bottle-shaped pores are possibly developed within the coals. The results from relative permeability tests with methane (CH4) and water depend on the pore structure, coal wettability, confining pressure, and pressure difference in the coal. The results show that a definite correlation does not exist between relative permeability and porosity in the low-rank coal. However, macropore porosity rather than the whole range of the porosity is the most likely property affecting the water relative permeability, whereas the effect of pore size on gas relative permeability varies along with a broader range. It has been observed that the low-rank coal with higher water wettability exhibits lower water relative permeability, narrower two-phase span, higher gas relative permeability, and irreducible water saturation. With the increase in the confining pressure, both the methane and water relative permeabilities decrease, while the ratio of relative permeability (krw/krg) increases. This suggests that the confining pressure has less influence on water relative permeability than that on gas. As the pressure difference increases under the same effective stress, the residual water saturation in the low-rank coals decreases, and the associated two-phase span increases. Water relative permeability obviously increases above the crossover point water saturation, whereas gas relative permeability increases below the crossover point water saturation.

An integrated approach for gas-water relative permeability determination in nanoscale porous media

This paper provides an integrated approach to simulate gas-water relative permeability in nanoscale porous media with interfacial effects using fractal theory. The calculation results with present model considering the interfacial effects match the laboratory results very well. The characteristics of relative permeability were analyzed under different values of Hydrogen bond (∏h), Double layer repulsive force (∏e), Long-range van der Waals force (∏w) and Short-range structure repulsive force (∏s). The result shows that the interfacial effects can promote the fluid flow in the nanoporous media and the relationship is as follows: ∏h>∏e>∏w>∏s. ∏h and ∏e improve spreading obviously, which are accounted for more than 70%.Then the ∏w affects spreading accounts for 1/5 nearly. In addition, the analysis of fractal dimension on relative permeability is carried out to indicate that the gas-water relative permeability decreases with the increase of the fractal dimension. While the capillary force has impact on relative permeability slightly. The new insight and theoretical basis could be obtained for CO2 geological storage and shale gas extraction from nanoscale porous media.

Gas-water relative permeability model for tight sandstone gas reservoirs

The pores in tight sandstone gas reservoir are mostly in microscale, and the gas water two-phase flow behavior through those pores is considerably complicated, thus, how to establish a reliable relative permeability model is the urgent problem to be solved. Based on the single fluid continuity equation of the microtube, second-order slip model and the fractal scaling theory, the gas-water relative permeability model of tight sandstone gas reservoir is established. The model considers the gas slippage effect, the pore throat structure and the water saturation distribution. The reliability is validated by a variety of published experimental data of gas-water relative permeability. The results show that: 1) The established model can be reasonably adopted to describe the fluid flow behavior in the tight sandstone reservoir with microscale pores. 2) The increase of pressure and water saturation will reduce the effect of slippage effect on the relative permeability of gas phase. When the pressure is less than 1 MPa, the gas relative permeability is extremely sensitive to the pressure. The impact of temperature on the gas relative permeability is limited and can be neglected. 3) A higher fractal dimension of pore size distribution is beneficial to the relative permeability of gas phase, but it has a negative impact of the relative permeability of water phase. Similarly, a higher fractal dimension of tortuosity results in a higher gas phase relative permeability but a little lower water relative permeability.

A Novel Method for Gas–Water Relative Permeability Measurement of Coal Using NMR Relaxation

Using the conventional volumetric method in unsteady-state relative permeability measurements for unconventional gas reservoirs, such as coal and gas shale, is a significant challenge because the movable water volume in coal or shale is too small to be detected. Moreover, the dead volume in the measurement system adds extra inaccuracy to the displaced water determination. In this study, a low-field nuclear magnetic resonance (NMR) spectrometer was introduced into a custom-built relative permeability measurement apparatus, and a new method was developed to accurately quantify the displaced water, avoiding the drawback of the dead volume. The changes of water in the coal matrix and cleats were monitored during the unsteady-state displacement experiments. Relative permeability curves for two Chinese anthracite and bituminous coals were obtained, matching the existing research results from the Chinese coalbed methane area. Moreover, the influences of confining pressure on the shape of the relative permeability curve were evaluated. Although uncertainties and limits exist, the NMR-based method is a practical and applicable method to evaluate the gas/water relative permeability of ultra-low permeability rocks.

Analysis of Two-Phase Gas–Water Flow in Carbonate Reservoirs

Gas–water relative permeability (GWRP) is measured in the tests of full-diameter cores. Based on the obtained GWRP curves, the standard normalized curves are plotted for three types of carbonate reservoirs: matrix pore, fracture and solution pore. The corresponding gas and water two-phase flow model was deduced by considering stress sensitivity and non-Darcy effect, and the IPR curve calculation and analysis of gas wells of the three types were carried out. Based on huge gap between the matrix and fracture permeability, the phenomenon of gas drive water mainly exists in the cracks. So the conventional gas–water relative permeability of fractured gas reservoirs was modified.

Experimental Determination of Gas Relative Permeability Considering Slippage Effect in a Tight Formation

In this paper, the gas relative permeability considering slippage effect has been experimentally examined under various experimental conditions (i.e., ambient, high confining pressure, and high temperature). Experimentally, Klinkenberg permeabilities of 12 core samples have been measured by using steady-state flow experiment. It has been found that the Klinkenberg permeability is independent of the experimental temperature and dramatically decreases as confining pressure is increasing. Furthermore, linear correlations have been newly developed between the Klinkenberg permeability and the gas-measured permeability under various conditions. Subsequently, the developed correlations are correspondingly applied to calibrate the gas relative permeability. It has been found that the gas relative permeability can be overestimated without consideration of the slippage effect, i.e., Klinkenberg effect. In addition, the newly developed correlations have been applied to analyze the sensitivity of gas–water relative permeability to gas-measured permeability, confining pressure, and temperature. It is demonstrated that mobile water greatly alleviates the gas relative permeability in comparison to irreducible water. Although an increased confining pressure simultaneously reduces the effective water phase and gas phase permeability, the gas relative permeability increases and the water relative permeability decreases as the confining pressure increases. It is attributed to the fact that the effective water phase permeability is more sensitive to the confining pressure. Given an elevated experimental temperature, the gas relative permeability is reduced while the water relative permeability is enhanced, implying the significance of temperature effect on gas–water relative permeability measurements.

Theory study of gas–water relative permeability in roughened fractures

It has been shown that gas–water relative permeability in fracture or fractured porous media plays an important role in determination of flow characteristics for gas–water two-phase flow. The accurate prediction of gas–water two-phase flow in fracture or fractured media is hence highly important. In most recent analytical models for gas–water relative permeability in fracture, the fracture is conceptualized as smooth wall. Reliable characterization of roughened fracture surface is severely limited. The analytical models for gas–water two-phase relative permeability in roughened fracture are scarce, thus, it is desirable to develop an analytical model for gas–water relative permeability in fracture with roughened surface. The goal of this work is to present an analytical model for gas–water relative permeability in roughened fracture. The rough surface topography of roughened fracture can be addressed by fractal theory. In addition, the proposed model is modified by considering the influence of tortuosity to study the gas–water relative permeability in fractured porous media. The proposed gas–water relative permeability is found to be a function of the structural parameters of roughened fracture. The predictions of relative permeability by the proposed model have similar variation trend with available experimental data, which verifies the theoretical models. We also conduct several sensitivity studies. These proposed analytical models provides a more realistic representation of gas–water two-phase flow in roughened fracture and fractured porous media, and gives rise to more reliable gas–water relative permeability curves that can be used for analyzing gas–water two-phase flow characteristic in fractured reservoirs.

A Fractal Model for Gas–Water Relative Permeability in Inorganic Shale with Nanoscale Pores

A reliable gas–water relative permeability model in shale is extremely important for the accurate numerical simulation of gas–water two-phase flow (e.g., fracturing fluid flowback) in gas-shale reservoirs, which has important implication for the economic development of gas-shale reservoir. A gas–water relative permeability model in inorganic shale with nanoscale pores at laboratory condition and reservoir condition was proposed based on the fractal scaling theory and modified non-slip boundary of continuity equation in the nanotube. The model not only considers the gas slippage in the entire Knudsen regime, multilayer sticking (near-wall high-viscosity water) and the quantified thickness of water film, but also combines the real gas effect and stress dependence effect. The presented model has been validated by various experiments data of sandstone with microscale pores and bulk shale with nanoscale pores. The results show that: (1) The Knudsen diffusion and slippage effects enhance the gas relative permeability dramatically; however, it is not obviously affected at high pressure. (2) The multilayer sticking effect and water film should not be neglected: the multilayer sticking would reduce the water relative permeability as well as slightly decrease gas relative permeability, and the film flow has a negative impact on both of the gas and water relative permeability. (3) The increased fractal dimension for pore size distribution or tortuosity would increase gas relative permeability but decrease the water relative permeability for a given saturation; however, the effect on relative permeability is not that notable. (4) The real gas effect is beneficial for the gas relative permeability, and the influence is considerable when the pressure is high enough and when the nanopores of bulk shale are mostly with smaller size. For the stress dependence, not like the intrinsic permeability, none of the gas or water relative permeability is sensitive to the net pressure and it can be ignored completely.