Gas Relative Permeability Research Articles

Gas permeability of partially saturated cement-based materials considering water sensitivity

Gas permeability is a crucial factor influencing the durability of cement-based materials, which are usually in a partially saturated state. This study examines the impact of the water-to-cement (w/c) ratio, water saturation and water sensitivity on the gas permeability of cement-based materials using Nuclear Magnetic Resonance (NMR) and Mercury Intrusion Porosimetry (MIP). The results indicate that the gas permeability of cement-based materials is strongly related to their porosity and pore size distribution. Relative gas permeability is directly influenced by water saturation and the initial state of the materials, with a noticeable hysteresis effect observed. Furthermore, the water sensitivity of cement-based materials results in no evident, but a slight decrease in gas permeability during water saturation.

The Time-Varying Characteristics of Relative Permeability in Oil Reservoirs with Gas Injection

Relative permeability is a critical parameter in reservoir numerical simulation and production prediction, intimately associated with reservoir architecture and fluid property. During gas injection development, substantial alterations in reservoir properties and fluid phase behavior induce dynamic changes in relative permeability. Clearly characterizing the time-varying features of relative permeability is very useful for an understanding of how gas injection influences fluid mobility within the reservoir and enhances recovery rates. In this paper, core displacement experiments are firstly conducted to obtain the characteristics of the relative permeability of oil and gas under various development stages and displacement conditions, further delineating the comprehensive shifts in reservoir properties at different gas injection stages. Subsequently, a novel reservoir numerical simulation method is proposed that considers the spatial and temporal segmentation of relative permeability curves in the reservoir simulation. Finally, a practical application is presented to clarify the effects of injection and production parameters on the development performance of gas flooding oil reservoirs. The results show the following: (i) Significant time-varying characteristics of relative permeability occur throughout gas injection development, in the early stages of gas injection, where most of the reservoir is at the gas injection front, and a rightward shift in relative oil and gas permeability indicates that gas injection promotes oil mobility. Conversely, in the later stages of gas injection, as the reservoir reaches the trailing edge of gas injection, the change trend in relative oil and gas permeability reverses, shifting leftward, thereby exacerbating the gas breakout phenomena. (ii) Increasing the rate of gas injection causes relative oil and gas permeability to move leftward, effectively enhancing the gas volume sweep coefficient and microscopic oil displacement efficiency at lower injection speeds while reducing development performance at higher injection speeds. (iii) An increase in gas injection pressure causes relative oil and gas permeability to shift rightward, and although it reduces residual oil saturation and enhances microscopic oil displacement efficiency, it also intensifies gas breakout phenomena and lowers the gas volume sweep coefficient. This paper provides theoretical guidance and technical support for the design of gas injection strategies, optimization of injection and production parameters, and production forecasting.

Sensitivity analysis and uncertainty quantification based on the analytical solution for nanoparticle-stabilized foam flow in porous media

A model describing nanoparticle-stabilized foam displacement is proposed in this study. Based on literature experimental data, we include nanoparticle dependence in a simplified version of the Stochastic Bubble Population balance model in local equilibrium. To describe the gas–water fractional flow, we utilize quadratic Corey permeabilities. Our model consists of non-strictly hyperbolic conservation laws, and we investigate the existence of a global solution as a sequence of waves. This simpler model maintains the solution structure of classical Corey’s relative permeability model and allows us to obtain algebraic expressions to analyze the solution type and construct the water saturation profiles. We perform uncertainty quantification and sensitivity analysis of the model describing the foam injection assisted by nanoparticles, considering three relevant quantities of interest: breakthrough time, cumulative water production, and pressure drop. The analytical framework developed allows us to obtain these quantities. Our results show that the effect of nanoparticles is greater than the model’s uncertainty (for all quantities), suggesting that measuring it experimentally is statistically feasible. The presence of nanoparticles also significantly reduces the uncertainty propagation due to foam stabilization. From the sensitivity study, the endpoints of water and gas relative permeability are the most significant parameters for the breakthrough time. For the maximum pressure drop, the gas endpoint relative permeability and the concentration of nanoparticles stand out. Otherwise, water production is more sensitive to a foam-related parameter most of the time. We achieve convergence even using the classical Monte Carlo method, showing how analytical solutions drastically reduce computational costs.

Experimental and numerical evaluation of relative permeability modifiers during water control in a tight gas reservoir

Relative permeability modifier (RPMs) is a water control technique that is implemented for enhancing gas recovery rates and prolonging well productive life during fracturing the tight gas reservoir. RPMs filtrate into formation for a certain depth along with the fracturing fluid to control water output by a “drag” effect on water phase only. To optimize RPM treatment, both experimental investigation and numerical simulation are used in this paper. In laboratory, transient core-flooding tests were conducted to investigate the water control performance of newly formulated polymer (RPM). The relative permeability of gas was corrected due to gas volume changes during displacement. The results showed that the selective water control effect of RPM by reducing water relative permeability dramatically with little impact on gas relative permeability. The RPM concentration was optimized as 0.01 %XSJ-14(A)+0.05 %XSJ-14(B) while injection volume as 5PV by comparison of relative permeability curves. A 2D fracture model of a tight gas model was built to compare the production before and after RPM treatment. The results of numerical simulation confirmed the different flow control effect of RPM on water and gas. A sensitivity analysis was conducted for the effect of fracture length, fracture conductivity, RPM filtration and RR value. The results indicate that there are limits of all the factor on RPM’s water control performance.

Relative permeabilities for two-phase flow through wellbore cement fractures

Multiple fluids are likely to exist in fractures and flow paths associated with leaky wellbores, including liquids (e.g., crude oil) and gases (e.g., gas exsolved from liquid). These fluids occupy and move through different portions of the pore spaces within the fractures depending on many factors, including fluid properties, fracture size, and the amount of the different fluids. Upward leakage of any phase, through the fracture, can contaminate water-bearing formations, create hazardous surface conditions, and compromise the functionality of the wellbore. Early signs of wellbore leaks may be expressed by anomalous pressure behavior at surface monitoring points on cavern storage wells. These pressure anomalies are difficult to interpret, necessitating knowledge of the factors that affect the multiphase flow in fractures and porous media. These parameters are critical to modeling multiphase flow in fractures. This insight can guide further diagnosis and maximize leak remediation. Our study focuses on the relationship of the liquid–gas relative permeabilities for representative variable-aperture wellbore cement fracture. To obtain the relative permeability of each phase, two-phase flow tests were conducted where both fluids were flowing simultaneously through a fractured wellbore cement specimen under a range of factors, namely (1) aperture size, (2) capillary numbers, and (3) viscosity ratio. The flow experiments were conducted under a range of confining stresses and flow velocities, using nitrogen gas and silicone oils (of different viscosities) in a specially designed pressure vessel. The sum of gas and oil relative permeabilities were found to be less than one under all conditions, which indicates that the presence of one phase affects the permeability of the other phase, and vice versa. Since the gas phase flow conditions include a significant inertial flow component in addition to viscous flow, the inertial flow coefficients at different saturation states are presented. The factors affecting the relationship between the relative permeabilities are discussed in detail. A new mathematical model for estimating the relative permeability of wellbore cement fracture is presented and experimentally validated.

Research on Gas Injection Limits and Development Methods of CH4/CO2 Synergistic Displacement in Offshore Fractured Condensate Gas Reservoirs

Gas injection for enhanced oil and gas reservoir recovery is a crucial method in offshore Carbon Capture, Utilization, and Storage (CCUS). The B6 buried hill condensate gas reservoir, characterized by high CO2 content, a deficit in natural energy, developed fractures and low-pressure differentials between formation and saturation pressures, requires supplementary formation energy to mitigate retrograde condensation near the wellbore area through gas injection. However, due to the connected fractures, the B6 gas reservoir exhibits strong horizontal and vertical heterogeneity, resulting in severe gas channeling and a futile cycle, which affects the gas injection efficiency at various levels of fracture development. Based on these findings, we conducted gas injection experiments and numerical simulations on fractured cores. A characterization method for oil and gas relative permeability considering dissolution was established. Additionally, the gas injection development boundary for this type of condensate gas reservoir was quantified according to the degree of fracture development, and the gas injection mode of the B6 reservoir was optimized. Research indicates that the presence of fractures leads to the formation of a dominant gas channel; the greater the permeability difference, the poorer the gas injection effect. The permeability gradation (fracture permeability divided by matrix permeability) in the gas injection area should be no higher than 15; gas injection in wells A1 and A2 is likely to achieve a better development effect under the existing well pattern. Moreover, early gas injection timing and pulse gas injection prove beneficial in enhancing the recovery rate of condensate oil. The study offers significant guidance for the development of similar gas reservoirs and for reservoirs with weakly connected fractures; advancing the timing of gas injection can mitigate the retrograde condensation phenomenon, whereas initiating gas injection after depletion may reduce the impact of gas channeling for reservoirs with strongly connected fractures.

A new formulation for removing condensate blockage for low permeable gas reservoir

Condensate blockage significantly impairs gas production in low-permeability reservoirs by reducing gas relative permeability and increasing condensate saturation near the wellbore. Particularly acute in reservoirs with low pressure and permeability, effective solutions are required to mitigate this formation damage. This study introduces a novel acid treatment strategy aimed at enhancing the injectivity index in gas reservoirs afflicted by condensate blockage. Leveraging mineralogical analysis, Hydrochloric Acid (HCl) was identified as the optimal acidizing agent. The most effective concentrations of HCl for rock dissolution—15% and 7.5%—were determined through dissolution tests. The research further advances by adding methanol to the acid mix, resulting in three distinct formulations: HCl 15 wt%, HCl 15 wt% + methanol, and HCl 7.5 wt% + methanol. Comprehensive wettability alteration tests and coreflood experiments were conducted to evaluate the efficacy of these systems in permeability enhancement. The HCl 7.5 wt% + methanol formulation demonstrated superior performance in permeability improvement and condensate blockage reduction, outshining the other systems. Notably, this new acid system effectively altered wettability from hydrophobic to hydrophilic, facilitating the passage of condensate through the pore throats and thus aiding in the removal of blockages. The integration of methanol with HCl, particularly at a 7.5 wt% concentration, represents a significant advancement in the treatment of condensate blockage in gas reservoirs, promising to improve gas recovery rates by addressing the challenges posed by low-permeability formations.

Gas and Water Relative Permeability in THF Hydrate-Bearing Berea Sandstone

Gas and Water Relative Permeability in THF Hydrate-Bearing Berea Sandstone

Investigating the vaporization mechanism's effect on interfacial tension during gas injection into an oil reservoir

In gas injection, which is one of the fascinating enhanced oil recovery techniques, the main mechanism involves decreasing interfacial tension (IFT). Although various mechanisms can affect the IFT of a system, in most experimental and numerical studies, condensation is considered the dominant mechanism among condensation-vaporization and vaporization. Investigating the impact of each mechanism is crucial as they can influence the IFT of the system and, consequently, the effectiveness of the gas injection method. This study introduces a novel model to assess the influence of different mechanisms on system IFT. The model defines system IFT, adjusts fluid relative permeability to represent miscible, immiscible, and near-miscible states, and utilizes the Buckley–Leverett method to analyze gas fractional flow and saturation profiles when injecting carbon dioxide (CO2), methane (CH4), and nitrogen (N2). Furthermore, the research explores the impact of injection pressure and IFT at minimum miscible pressure (IFT0) on gas injection efficiency. Based on our results, for both live and dead oil, the condensation mechanism reduces IFT and near-miscible pressure; switching to a condensing-vaporizing mechanism increases these parameters. This trend was consistent across all gases studied (N2, CO2, CH4), with a more significant effect observed on the CH4-live oil system compared to N2 and CO2. Controlling the condensing mechanism in IFT measurements enhances gas flow rate and relative permeability curve within the medium. Higher injection pressure in the condensing mechanism and IFT0 = 0.5 leads to faster fluid movement and improved relative permeability due to increased driving forces. Higher IFT0 accelerates the relative permeability of fluids and gas movement within the medium by promoting miscibility sooner. The impact of IFT0 was more pronounced on the dead oil–gas system compared to the live oil–gas system in this study.

Analysis and modelling of gas relative permeability in reservoir by hybrid KELM methods

Analysis and modelling of gas relative permeability in reservoir by hybrid KELM methods

Study on multi‐cycle gas‐water displacing mechanism in underground gas storage of low‐permeability reservoir based on PNM

AbstractA deep understanding of the pore‐scale multi‐cycle two‐phase seepage mechanism of gas‐water systems in low‐permeability reservoirs is crucial for enhancing oil and gas recovery and optimizing the operating conditions of underground gas storage. A pore network model was reconstructed using micro‐CT images of low‐permeability core samples from the Dagang Oilfield, China. The mathematical models of gas‐water flow in the pore‐scale models were established based on Poiseuille's law and the quasi‐static displacement theory, considering the gas compressibility and slip effects. The porosity, pore size, absolute permeability, and relative permeability (Kr) of oil‐water and gas‐water were calculated using pore network simulations and validated against experimental benchmark data of the same samples. The effects of multi‐cycle displacement, rock wettability, and average pore pressure on the gas‐water two‐phase flow were simulated and analyzed. The results showed that the relative permeability of gas (Krg) at the same water saturation level significantly increased when the gas compressibility and slip effects were considered. With an increase in the number of gas‐water displacement cycles, Krg at the same water saturation level showed a decreasing trend, indicating a reduction in the gas seepage capability. Krg decreased with increasing water contact angle. With an increase in the average pore pressure, Krg decreased and gradually increased when the average pressure exceeded 25 MPa.

Gas–water percolation of tight sandstone reservoirs with different pore types in the Ordos Basin

To investigate the percolation mechanism of tight sandstone reservoirs, qualitative and quantitative methods are applied to analyze the pore structure of the Ordos Basin through scanning electron microscopy and high-pressure mercury injection. Based on gas–water relative permeability data and the visualization of real sandstone models, a gas–water displacement experiment was carried out to simulate the percolation mechanism and fluid distribution of different pore types. The results show that: ① The percolation of different pore types varies greatly, and the irreducible water saturation decreases when the reservoir properties improve. The relative permeability of gas at an irreducible water saturation increases, the width of the two-phase percolation area increases, and the percolation ability is enhanced as the reservoir properties improve. ② The gas–water displacement mode changes from fingering to uniform displacement with the improvement of pore type, which is beneficial to the formation of effective reservoirs filled with natural gas under the same hydrocarbon generation conditions. ③ The time required for the pressure relief of samples with good reservoir properties is short, and the recovery is higher with the improvement of pore type. ④ The residual water in samples with a poor pore type increases, which decreases the relative permeability of gas and recovery. A reasonable development pattern should be carried out, and the production pressure difference should be strictly controlled to maximize productivity. This study provides theoretical guidance for the development of tight sandstone reservoirs in the Ordos Basin.

An Analytical Relative Permeability Model Considering Flow Path Structural Characteristics for Gas-Liquid Two-Phase Flow in Shale Fracture

Summary Relative permeability models are essential in describing the multiphase fluid flow in reservoir rocks. Literature work has shown that the existing theoretical models of relative permeability cannot perfectly describe the two-phase flow experimental data in fractures because those models are mostly developed for porous media (such as sandstone) or proposed without fully taking the specific characteristics of two-phase flow into consideration. In this paper, we propose a theoretical two-phase flow relative permeability model based on the tortuous flow channels, considering the structural characteristics of two-phase flow in the fractures. This model considers that the gas and liquid flow through different channels of different shapes and sizes at the same time. The formula for two-phase relative permeability was derived from cubic law in fracture and Darcy’s law, with the influence of the slip effect of the gas phase also considered. The results from different models were compared using several series of experimental data. The model proposed in this paper has a better fit than the others for the raw experimental data. This study demonstrates that it is crucial to take the flow paths and distribution of the two phases into consideration to model the two-phase flow in fracture accurately. This work also found that the tortuosity of the gas channel at the irreducible liquid saturation has a negative effect on gas relative permeability but positive to liquid relative permeability. Moreover, the model demonstrates that the decrease in aperture leads to an increase in the gas relative permeability due to gas slippage, while the impact of gas slippage reduces under high pressure.

Estimating the Influencing Factors of Gas–Water Relative Permeability in Condensate Gas Reservoirs under High-Temperature and High-Pressure Conditions

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs.

Analysis of permeability anisotropy of marine hydrate-bearing sediments using fractal theory combined with X-CT

Permeability anisotropy plays a crucial role in accurately predicting fluid productions during hydrate exploitation. However, the mechanisms governing permeability anisotropy have yet to be fully elucidated. This study conducted experiments on methane hydrate formation/dissociation in both unsaturated and saturated quartz sands, followed by X-ray computed tomography scanning and pore structure characterizations. Fractal parameters, encompassing fractal dimension, tortuosity fractal dimension, and maximum pore diameter, were employed to characterize the evolution of pore structure and changes in permeability anisotropy. Results show that the fractal dimension and maximum pore diameter decreased, while the tortuosity fractal dimension increased with the increase of hydrate saturation. Larger maximum pore diameter and smaller tortuosity fractal dimension in the horizontal direction become more pronounced with increasing hydrate saturation, resulting in heightened permeability anisotropy (kh/kv). The permeability anisotropy increases from 1.77 to 3.20 with hydrate saturation increasing from 0 to 0.38 in unsaturated sands, and from 1.47 to 4.70 with hydrate saturation increasing from 0 to 0.49 in saturated sands. Gas and water relative permeability anisotropy also amplifies with increasing hydrate saturation. Extrapolating to field tests, the findings suggest that horizontal wells present a more favorable option for gas production, especially in reservoirs with high hydrate saturation.

Two-phase flow visualization experiments in variable-aperture fractures: The correlation between flow structure, displacement efficiency and relative permeability

The correlation of flow structure, displacement efficiency and relative permeability for two-phase flow in variable-aperture fractures is critical for many fractured rock applications. A systematic visualization method for two-phase flow experiments was developed and four transparent variable-aperture fracture samples were duplicated by epoxy casting method. A total of 112 times two-phase flow experiments of nitrogen displacing water under various gas flow rates were performed and the corresponding results of images and pressure data during flow process were recorded and analyzed based on optical principles. On the basis of the competition between capillary resistance and inertia force of gas, the flow structure can be generally divided into four states including capillary resistance dominant (CR) state with few flow paths in two lateral sides without fingering flow, competitive (CP) state with the occurrence of clear fingering flow phenomenon, inertia force of gas dominant (IF) state showing more chaotic gas distributions, and steady (SD) state that has few changes in flow paths. The growth of displacement efficiency is greatly affected by the four transition states, in which the increment of displacement efficiency in Frac-1 that has gone through the three states of flow structure approaches 30%, and that of Frac-2 and Frac-3 are about 15%, while Frac-4 with little change of flow structure is less than 10%. As a consequence, the relationship between saturation and relative permeability of gas becomes steeper from Frac-1 to Frac-4 with greater deviation from X, V–C and Corey models due to the smaller variation range of gas saturation, and an improved v-type model is obtained where the exponent n shows a positive correlation to fracture mean aperture.

Anisotropy analysis of two-phase flow permeability in the multi-stage shear process of hydrate-bearing sediments

Natural gas hydrate is a promising energy resource for the future. However, due to the shallow burial and low-degree of consolidation, hydrate-bearing sediment (HBS) is prone to deform under stress. And this will lead to dynamic changes in reservoir permeability. In this study, the micro-structure of shearing HBS specimen with hydrate saturation of 45.1% under different confining pressures (1, 3 MPa) were obtained by the micro-focus CT, the micro-structure changes and two-phases permeability characteristics evolution were analyzed. The results show that with the increasing axial strain, the absolute permeability increase firstly and decrease. The capillary pressure in vertical direction is always larger than that in horizontal directions. During primary gas flooding and secondary water flooding, the gas-water relative permeability anisotropy of different direction gradually enhances, and reach maximum with the largest axial strain. At low effective confining pressure, the gas-water relative permeability in each direction does not vary with axial strain. At high effective confining pressure, the relative water permeability in each direction decreases with the increase of axial strain, the relative gas permeability in the horizontal direction increases with the increase of axial strain, and the relative gas permeability in the vertical direction has no obvious pattern.

Analyzing the impact of the interaction between hydraulic fracturing fluid and Kerogen on its wettability alteration

The increasing demand for exploring and developing unconventional reservoirs has sparked active research into hydraulic fracturing. However, the effect of hydraulic fracturing fluid on kerogen wettability alteration resulting from their interaction remains inadequately understood. This study aims to experimentally quantify the impact of hydraulic fracturing fluid on kerogen wettability alterations as a function of thermal maturity level. To achieve this objective, kerogens isolated from various organic-rich shale rocks of different types and maturities were mixed with synthetic hydraulic fracturing fluid at a temperature of 80 °C for 14 days. The resulting kerogen wettability was analyzed with the sessile drop method, Ion Chromatography (IC), and Attenuated Total Reflectance Fourier-Transform Infrared spectroscopy (ATR-FTIR), while Rock-Eval pyrolysis experiments were conducted as well to determine the kerogen geochemistry changes. After experiments, ANSYS-CFD was utilized to conduct numerical simulations of two-phase fluid flow to identify the impact of wettability on gas-water relative permeability.This study experimentally demonstrated that hydraulic fracturing fluid interacting with kerogen results in significant wettability alterations, which depend on the type and maturity of the kerogen. The Drop Shape Analyzer (DSA) results revealed that the air/water-contact angle decreased after the reaction for every type and maturity of kerogen, although the wettability alteration was greater with higher kerogen maturity. The ATR-FTIR findings revealed that mature kerogen isolates experienced a reduction in their hydrophobic functional groups, whereas kerogen isolates with relatively lower maturity demonstrated a potential loss of such groups, possibly resulting from oxidation. This trend toward hydrophilicity is consistent with the DSA results. The numerical modeling results indicated that the relative permeability was strongly influenced by the wettability of the formation. A water-wet formation led to a higher water relative permeability compared to the relative permeability of gas, and vice versa. These results represent a significant step forward in assessing multiphase fluid transport in organic-rich shales and hydrocarbon production.

Flow parameter setting methods in numerical simulation of the unconventional reservoir and its impact on production

Abstract Tight reservoirs have poor physical properties and complex pore structures, and well production is often affected by the starting threshold gradient, stress sensitivity, and water blockage. In this paper, the numerical simulation method is used to make these three factors equal. In addition, normalized influence coefficient analysis and grey relation analysis are used to investigate the degree of influence of each factor on well production. In this study, three methods are developed to set the threshold pressure gradient according to the permeability zoning, and the effect of reservoir heterogeneity is considered to set the threshold pressure gradient for unconventional reservoirs. The equivalent accuracy of the numerical simulation of the threshold pressure gradient can be improved compared to the traditional method. Stress sensitivity and water blockage effects are equated by correcting for rock compressibility coefficient and gas relative permeability. The fit rate of the gas well production history is improved by 2–3% after considering complex factors. The inclusion of the complex factors reduces the reservoir energy mobilization. The threshold pressure gradient results in an additional pressure reduction of about 1.8 MPa around the gas well. Residual gas identification and development is helped by clarifying the effect of complex factors on formation pressure When only the effect of a single factor is considered, water blockage has the most significant effect on gas well production, followed by threshold pressure and the weakest stress sensitivity. When several factors are considered together, the effect of stress sensitivity is increased.

Modeling two-phase flow behaviour in a shale gas reservoir with complex fracture networks and flow dynamics

In this work, a robust and pragmatic method has been developed, validated, and applied to describe two-phase flow behaviour of a multifractured horizontal well (MFHW) in a shale gas formation. As for a fracture subsystem, its permeability modulus, non-Darcy flow coefficient, and slippage factor have been defined and embedded into the governing equation, while an iterative method is applied to update the gas/water saturation in each fracture segment within discrete fracture networks. Different from the traditional treatment that a water-source/sink in the matrix is simplified by assuming it as a constant term, a skin factor on a fracture face is defined and introduced to represent the change in relative permeability in the matrix domain at each timestep, while the adsorption/desorption term is incorporated into the diffusivity equation to accurately calculate the shale gas production by taking the adsorbed gas in nanoscale porous media into account. Then, the theoretical model can be applied to accurately capture the two-phase flow behaviour in different subdomains. The accuracy of this newly developed model has been confirmed by the numerical simulation and then it is extended to field applications with excellent performance. The stress-sensitivity, non-Darcy flow, and slippage effect in a hydraulic fracture (HF) are found to be obvious during the production, while the initial gas saturation in a matrix and HFs imposes an evident influence on the production profile. As for an HF with a high gas saturation, the dewatering stage is missing and water from the matrix can be neglected during a short production time. For the matrix subsystem, a high-water saturation in the matrix near an HF can affect gas production during the entire stage since gas relative permeability in the HF remains low. In addition, the adsorption/desorption in the matrix subsystem can increase gas production but decrease water production. Compared to the observed gas/water production rates for field applications, the solutions obtained from the method in this work are found to be well matched, confirming its reliability and robustness.