Seepage Mechanism Research Articles

Gas Flowrate Evaluation in Coal Coupling the Matrix Shrinkage Effect Caused by Water Extraction

Abstract Estimating production in coal accurately is crucial for promoting the process of safe, efficient, and green coal mining. It has been gradually recognized that horizontal wells with multiple fractures are employed to develop the coal reservoir, which signifies that the linear flow regime will dominate for a rather long time. However, the traditional analysis approaches of transient linear flow regimes may yield the overestimation of coal reservoir property. In this work, a new analytical model was proposed to estimate the rate-transient of wells with multi-fractures in coal reservoir that produce at a constant flowing pressure, which considers multiple flow mechanisms. Especially, the matrix shrinkage effect caused by water extraction from microscopic pores was incorporated, which has never been investigated by current production analysis models. In comparison with the conventional reservoir, the advanced pseudo-pressure and pseudo-time equations incorporating earlier critical mechanisms were established, including the four effects of gas slippage, effective stress, and matrix shrinkage caused by gas desorption/water extraction. In addition, the excellent agreement between the predicted rate by the proposed model and field data was achieved to validate the reliability of proposed models. Furthermore, the sensitivity analysis was carried out to clarify the influence of a series of factors on the seepage mechanism and productivity curve. Results demonstrated that the matrix shrinkage effect caused by water extraction may increase the well production rate in coal reservoirs. Selecting one field case as an example, the production rate predicted by the red curve is obviously higher than that by the green curve, the average discrepancy yields around 39.5%. The relative humidity in the coal matrix will present a positive impact on well production performance. Taking a field case as an instance, when the relative humidity varies from 8% to 14%, the well production sharply increases by about 11.6%.

Experimental and theoretical study on the seepage mechanism characteristics coupling with confining pressure

To investigate the effect of confining pressure Pc on the seepage mechanism characteristics, a new model of seepage mechanism characteristics coupling with confining pressure has been proposed and analyzed. In this model, fracture closure deformation based on the hydraulic aperture is used to combine with Goodman hyperbolic model of fracture. In theory, the physical relationship among confining pressure, seepage pressure and flow rate has been established. For further validating the model, hydro-mechanical tests through single cutting shale fracture sample were conducted in the core holder at different constant seepage pressures (600, 1000, 1400 and 1800 kPa) or different constant flow rates (3, 7, 11 and 15 mL/min) under different confining pressures. The theoretical relationship was used to fit the hydro-mechanical test data, and the result showed that the suggested model could effectively predict the seepage mechanism characteristics. Based on the data of seepage tests under normal stress for shear fracture on diabase rock samples, the regression results shown that the model of seepage mechanism characteristics coupling with confining pressure can be applied well. This research result will contribute to the fracture seepage problem caused by change of in-situ stress in engineering projects.

Seepage mechanisms and permeability differences between loess and paleosols in the critical zone of the Loess Plateau

AbstractThe soil in the Loess Plateau has special permeability characteristics due to the alternating distribution of loess and paleosol layers. Using an analysis of the physical properties, microstructure and thermogravimetric analysis of loess and paleosol, this paper examines strata seepage mechanisms in the loess tableland area and considers the applicability of a hydraulic conductivity empirical formula. The analysis shows that hydraulic conductivity attenuation with depth can be represented by a negative exponential model, while hydraulic conductivity values are not normally distributed. The best‐fitting models of hydraulic conductivity in the horizontal (KH) and vertical (KV) directions are Gaussian models, and both have strong spatial correlations. This study of the difference in permeability between loess and paleosol found that the depositional environment was the dominant causal factor, making the average hydraulic conductivity of most loess layers greater than that of the underlying paleosol layers. Different microstructures between loess and paleosol also confirmed the microscopic explanation in permeability anisotropy and their permeability difference. Thermogravimetric analysis determined temperature ranges for different types of water lost by heat, and then calculated ratios of bound water mass to liquid limit, with an average of 0.768. A modified formula suitable for loess was obtained by integrating the consistency index method and effective porosity ratio model into the hydraulic conductivity empirical formula. Compared with the results of laboratory tests and uncorrected formulas, the modified formula provides a good estimate of strata hydraulic conductivity. Accurate understandings of seepage mechanisms and permeability differences in the loess area are important, promoting ecological restoration and providing scientific guidance for the sustainable development of the Loess Plateau.

Gas–water two-phase productivity model for fractured horizontal wells in volcanic gas reservoirs with natural fractures

ABSTRACT Volcanic gas reservoirs, as new exploration and development fields, are rich in resources and have broad exploration and development prospects. However, compared with the conventional sandstone gas reservoirs, volcanic gas reservoirs have more complex storage and permeability mode, with multiple media including pores, caves and fractures, which determines the strong heterogeneity, complicated seepage mechanisms, and difficult development of volcanic gas reservoirs. To further improve the prediction accuracy of fractured horizontal well productivity in volcanic gas reservoirs, Xushen low-permeability volcanic gas reservoirs are presented as examples herein using the equation of motion based on the principle of equal flow. Considering the stress-sensitive effect, starting pressure gradient, high-speed turbulence effect, and dual porous medium structure, as well as combining the nature of gas and real gas state equations, a gas–water two-phase productivity model is established for a matrix-natural fracture-artificial fracture-wellbore volcanic gas reservoir fractured horizontal well. In addition, factors affecting production are studied. Results indicate that stress-sensitivity coefficient of different media has different effects on the production. The natural-fracture stress-sensitive coefficient has the greatest influence on production. With the increase of the natural-fracture stress-sensitive coefficient, the gas production decreases and the reduction amplitude changes little, which is almost uniform. When natural-fracture stress-sensitive coefficient is 0.08, gas well production decreases by 14.24%. The second is the artificial main fracture stress-sensitivity coefficient. With the increase of the artificial main fracture stress-sensitivity coefficient, the decrease of gas production becomes larger. When artificial main fracture stress-sensitivity coefficient is 0.1, gas well production decreases by 6.6%. The matrix stress-sensitivity coefficient on production is the least, almost zero. The high-speed nonlinear coefficient significantly affected the production. With the increase of the high-speed nonlinear coefficient, the gas well production decreases, and the decrease rate is faster and faster. When the high-speed nonlinear coefficient increases to 10000 m−1, gas well production decreases by 45.65%. However, the starting pressure gradient had little effect on production. Finally, the model is verified by the actual production data of Xushen1-H2 well. The average errors of the gas production, water production, and pressure calculations are 9.65%, 9.63%, and 9.8%, respectively. This study contributes positively to the productivity prediction of fractured horizontal wells in low-permeability volcanic gas reservoirs.

Seepage Mechanism of Tight Sandstone Reservoir Based on Digital Core Simulation Method

Recently, tight sandstone oil has played an increasingly important role in the energy strategies of countries around the world. However, the understanding of a microscopic mechanism is still not clear enough, which has been affecting the improvement of the recovery of tight sandstone oil. In this article, a digital core model was established to simulate the pore network of a physical core with CT scan and difference equations were verified by Fourier counting. Then, a combination of orthogonal tests and cubic digital cores was used to experimentally investigate various parameters including pressure, length, permeability, viscosity, and time. By combining the physical experiments with the digital core methods, it can be observed that the state of the micro-crack affects the conductivity of the core, which may be the decisive reason for changing the pressure gradient. The orthogonal test showed that the sensitivity of the parameters was pressure, length, permeability, time, and viscosity in order. The results of the numerical simulations showed that this method can reveal the seepage mechanism of a tight sandstone reservoir, greatly shortening the experimental time and improving flexibility.

A new dynamic capillary-number-recovery evaluation method for tight gas reservoirs

Currently, it is difficult to accurately evaluate the recovery of tight gas reservoirs owing to its poor physical properties, strong heterogeneity, high water saturation, complex percolation laws. Conventional evaluation methods are often employed to use to calculate the gas recovery and the calculated results are frequently inaccurate in tight gas reservoirs. There is no unified recovery evaluation method for tight gas reservoirs. In this paper, a new dynamic capillary-number-recovery model was established to calculate the tight gas recovery. By using fuzzy mathematics, eight macroscopic factors that have a significant impact on recovery were selected to develop a multi-factor evaluation method for calculating the initial gas recovery. Combined with the microscopic seepage phenomenon and theoretical analysis, a matrix-fracture tight gas reservoir seepage model considering slippage effect, threshold pressure gradient and stress sensitivity effects was established. A new dynamic capillary-number-recovery model was developed to evaluate the initial gas recovery based on the seepage model and the multi-factor evaluation method. This model is more applicable to calculate gas recovery due to the consideration of macroscopic factors and microscopic seepage mechanism in tight gas reservoirs. Meanwhile, the new method was applied to evaluate the gas recovery of A block, which is a typical tight gas reservoir in Changqing gas field, China. The results indicate that the new established method is a feasible means to evaluate the gas recovery in tight gas reservoirs.

Microscopic seepage mechanism of shale gas reservoir

<p indent=0mm>The percentage of nanopores in shale gas reservoirs is quite high, and their structure is complex. The gas flow mechanism in nanopores is different from macroscopic fluid flow. Therefore, understanding the flow mechanism of shale gas in nanopores is of the utmost importance for its efficient production. Several factors affect the permeability of nanopores in shale gas exploitation. These include adsorption and desorption of nanopores, stress sensitivity, and slippage. Therefore, we capitalize on the capillary model and consider adsorption deformation. We establish a shale apparent permeability model to describe the gas flow considering the influence of the slip-off effect. The model is validated experimentally, and the influence of model parameters on apparent permeability is discussed. We demonstrate that our model can reasonably describe the gas flow under the real shale gas reservoir conditions. More specifically, we consider microscopic mechanisms of adsorption deformation, stress sensitivity, and nanoporous gas slippage effect under stress changes. We demonstrate that when constant confining pressure is applied, theoretical predictions are in good agreement with the measured values. As the pore pressure increases, the apparent permeability of shale decreases exponentially. The apparent permeability of the two gases increases with the increase of the average molecular free path. In particular, the larger the pore size, the higher the permeability in the pressure range, and as the pore pressure increases, the permeability gradually decreases. The apparent permeability of shale is more sensitive to the elastic modulus, and the increase of the elastic modulus leads to higher permeability at a given pressure stage. Moreover, the smaller the fracture compression coefficient, the higher the permeability. Finally, the apparent permeability of shale increases as so does the temperature. The proposed model provides guidance for shale gas production and dynamics analysis, capacity prediction, and production system optimization.

Pore Space Reconstruction of Shale Using Improved Variational Autoencoders

Pore space reconstruction is of great significance to some fields such as the study of seepage mechanisms in porous media and reservoir engineering. Shale oil and shale gas, as unconventional petroleum resources with abundant reserves in the whole world, attract extensive attention and have a rapid increase in production. Shale is a type of complex porous medium with evident fluctuations in various mineral compositions, dense structure, and low hardness, leading to a big challenge for the characterization and acquisition of the internal shale structure. Numerical reconstruction technology can achieve the purpose of studying the engineering problems and physical problems through numerical calculation and image display methods, which also can be used to reconstruct a pore structure similar to the real pore spaces through numerical simulation and have the advantages of low cost and good reusability, casting light on the characterization of the internal structure of shale. The recent branch of deep learning, variational auto-encoders (VAEs), has good capabilities of extracting characteristics for reconstructing similar images with the training image (TI). The theory of Fisher information can help to balance the encoder and decoder of VAE in information control. Therefore, this paper proposes an improved VAE to reconstruct shale based on VAE and Fisher information, using a real 3D shale image as a TI, and saves the parameters of neural networks to describe the probability distribution. Compared to some traditional methods, although this proposed method is slower in the first reconstruction, it is much faster in the subsequent reconstructions due to the reuse of the parameters. The proposed method also has advantages in terms of reconstruction quality over the original VAE. The findings of this study can help for better understanding of the seepage mechanisms in shale and the exploration of the shale gas industry.

Numerical Simulation on Mesoscale Mechanism of Seepage in Coal Fractures by Fluid-Sloid Coupling Method

Trying to reveal the mechanism of gas seepage in coal is of significance to both safe mining and methane exploitation. A series of FEM numerical models were built up and studied so as to explore the mesoscale mechanism of seepage in coal fractures. The proposed mesoscale FEM model is a cube with micron fractures along three orthogonal directions. The distribution of velocity and pressure under fluid-solid coupling was obtained, and furthermore, the seepage flow flux and an equivalent permeability of the whole model were calculated. The influences of fracture width, outlet velocity, and in situ stress level on seepage were investigated. The numerical results show that nonlinear Darcy seepage occurs during low velocity zone. The permeability is increased linearly with the increasing of facture width and outlet velocity. A certain change of lateral coefficient of in situ stress also affects seepage. The permeability is increased sharply once deviating the isotropic spherical stress state, but it is no longer changed obviously after the lateral coefficient has been increased or decreased more than 20%. The mesoscale seepage mechanism in coal fractures has been preliminarily revealed by considering fluid-solid coupling effect, and the key factors influencing fluid seepage in coal fractures were demonstrated. The proposed methods and results will be helpful to the further study of seepage behaviour in coal with more complex structures.

Understanding Immiscible Natural Gas Huff-N-Puff Seepage Mechanism in Porous Media: A Case Study of CH4 Huff-N-Puff by Laboratory Numerical Simulations in Chang-7 Tight Core

Understanding Immiscible Natural Gas Huff-N-Puff Seepage Mechanism in Porous Media: A Case Study of CH4 Huff-N-Puff by Laboratory Numerical Simulations in Chang-7 Tight Core

Permeability of Sand-Based Cemented Backfill under Different Stress Conditions: Effects of Confining and Axial Pressures

Sand-based cemented backfill (SBCB) mining technology is instrumental in utilizing coal resources buried under the water bodies. SBCB is exposed to the long-term action of mining-induced stresses in the goaf and groundwater permeating via microcracks along the rock strata. Studying the permeability evolution of SBCB under varying stress states is crucial for protecting coal and water resources below the aquifer. This study is focused on the influence law of different stress states on the SBCB permeability exposed to groundwater, which was tested under different axial and confining pressures using a laboratory seepage meter, particle size analyzer, scanning electron microscope (SEM), and X-ray diffractometer (XRD). Best-fitting quadratic polynomials linking the SBCB permeability with confining and axial pressures, respectively, were obtained via statistical processing of test results. The permeability gradually dropped within the elastic range as the confining and axial pressures increased. Moreover, an increase in the confining pressure caused a more dramatic reduction in the SBCB permeability than the axial pressure. Finally, the SBCB seepage mechanism under different stress states was revealed based on the particle size analysis, XRD patterns, and SEM microstructure. These findings are considered instrumental in substantiating safe mining of coal resources below the water bodies and above the confined groundwater.

Mechanism of pore water seepage in soil reinforced by step vacuum preloading

A laboratory model experiment of step vacuum preloading (SVP) for dredger fills was performed. The soil moisture content and water discharge rate were measured. The seepage mechanism of pore water was analyzed based on the theory of drainage consolidation. The results indicated that the seepage fluid mostly consisted of free water during self-weight sedimentation and under 10 kPa vacuum pressure in the SVP test. The stage corresponding to the application of 20 kPa vacuum pressure was the transitional stage in which both the free water and the loosely bound water participated in the seepage. When higher vacuum pressure was applied, the loosely bound water mostly participated in the seepage. In the SVP test, the complete potential difference channels were established in the test bucket during self-weight sedimentation. The vacuum channels at the center began to form when 10 kPa vacuum pressure was applied, and the free water near the sidewall was discharged through the potential difference channel. With 20 kPa vacuum pressure, the vacuum channel developed continuously from the drainage board to the sidewall of the test bucket, completing the process and ultimately stabilizing as the vacuum pressure increasing. The study of the seepage mechanism of pore water during SVP test is significant for the analysis of pore water seepage under vacuum pressure during the consolidation of soft soil foundation. This study contributes to the existing theory related to vacuum preloading consolidation methods, providing theoretical guidance for the analysis of soil consolidation under drainage conditions.

Research on the application of molecular simulation technology in enhanced oil-gas recovery engineering

In recent years, molecular simulations have received extensive attention in the study of reservoir fluid and rock properties, interactions, and related phenomena at the atomistic scale. For example, in molecular dynamics simulation, interesting properties are taken out of the time evolution analysis of atomic positions and velocities by numerical solution of Newtonian equations for all atomic motion in the system. These technologies assists conducting “computer experiments” that might instead of be impossible, very costly, or even extremely perilous to carry out. Whether it is from the primary oil recovery to the tertiary oil recovery or from laboratory experiment to field test, it is difficult to clarify the oil displacement flow mechanism of underground reservoirs. Computer molecular simulation reveals the seepage mechanism of a certain oil displacement at the microscopic scale, and enriches the specific oil displacement flow theory system. And the molecular design and effect prediction of a certain oil-displacing agent were studied, and its role in the reservoir was simulated, and the most suitable oil-displacing agent and the best molecular structure of the most suitable oil-displacing agent were obtained. To give a theoretical basic for the development of oilfield flooding technology and enhanced oil/gas recovery. This paper presents an overview of molecular simulation techniques and its applications to explore enhanced oil/gas recovery engineering research, which will provide useful instructions for characterizing the reservoir fluid and rock and their behaviors in various oil-gas reserves, and it greatly contribute to perform optimal operation and better design of production plants.

Shale gas production in nanoscale fractures with real gas effect

Shale gas is the key focus of energy development in the twenty-first century. The physical characteristics of shale gas include microscale effect, mixed gas effect (MGE), and real gas effect (RGE). In addition, the geometry size of natural microscale fracture (NMF) should be modeled. However, to the best of our knowledge, these factors are not totally considered in existing models. In this paper, a new model is presented for simulating gas mixture (GM) seepage in NMF with consideration of MGE, RGE and equivalent radius (ER). The simulated results show that: (a) All seepage mechanisms co-exist during the seepage process no matter how the geometry changes. (b) When the GM is very thin or the pressure is low, the transient flow (TF) line is closer to the Knudsen diffusion (KD) line, while when the GM is dense or the pressure is high, the TF line is closer to the SF line. (c) When the geometry size is reduced, the RGE becomes more obvious. The effect of SL on TF is weakened, while the effect of KD on TF is strengthened. (d) The weighting coefficient (WC) of slippage flow (SF) decreases when the geometry size of NMF is reduced; the WC of KD increases when the geometry size of NMF is reduced. In addition, compared with ideal GM, the RGE leads to a lower WC of SF, and the RGE leads to a higher WC of KD. (e) There exists a turning point (TP) for MTR with the increasing of pressure. (f) Below the TP, the MTR increases with pressure, while above the TP, the MTR decreases with pressure. This study presents a useful analytical model for engineers to estimate the transport capacity of GM in NMF and also provides basic equations for software companies to develop gas reservoir numerical simulation software.

New Model for Production Prediction of Shale Gas Wells

In shale reservoirs, pores and fractures are developed, and the seepage mechanism is complicated. The gas well estimated ultimate recovery (EUR) is difficult to be determined. The existing methods ...

Investigation on Nonlinear Flow Behavior through Rock Rough Fractures Based on Experiments and Proposed 3-Dimensional Numerical Simulation

Rock fractures as the main flow channels, their morphological features, and spatial characteristics deeply influence the seepage behavior. Reservoir sandstones as a case study, four splitting groups of fractures with different roughness were scanned to get the geometric features, and then the seepage experiments were taken to analyze the relationship of the pressure gradient ∇ P and flow rate Q , and the critical Reynolds number( Re c ) and wall friction factor ( f ) were determined to explain the translation of linear seepage to nonlinear seepage condition. Based on the scanning cloud data of different rough fractures, the fractures were reconstructed and introduced into the COMSOL Multiphysics software; a 3-dimensional seepage model for rough fractures was calibrated and simulated the seepage process and corresponding pressure distribution, and explained the asymmetry of flow velocity. And also, the seepage characteristics were researched considering aperture variation of different sample fractures; the results indicated that increasing aperture for same fracture decreased the relative roughness, the fitting coefficients by Forchheimer formula based on the data ∇ P ~ Q decreased, and the figures about the coefficients and corresponding aperture described nonlinear condition of the above rough fractures. In addition, the expression of wall friction factor was derived, and relationship of f , Re , and relative roughness indicated that f increased with increasing fracture roughness considering the same aperture, resulting in nonlinear flow more easily, otherwise is not, showing that f could be used to describe the seepage condition and corresponding turning point. Finally, it can be seen from the numerical results that the nonlinearity of fluid flow is mainly caused by the formation of eddies at fracture intersections and the critical pressure gradient decreases with increasing angle. And also, analysis about the coefficient B in the Forchheimer law corresponding to fracture intersections considering the intersecting angle and surface roughness is proposed to reveal the flow nonlinearity. The above investigations give the theoretical support to understand and reveal the seepage mechanism of the rock rough fractures.

Identification of Seepage Mechanisms for Natural Gas Huff-n-Puff and Flooding Processes in Hydrophilic Reservoirs With Low and Ultra-Low Permeabilities

Abstract Hydrocarbon gas flooding/Huff-n-Puff (HNP) can improve the oil recovery in the unconventional reservoirs. Here, the mechanisms accounting for fluid flow in the low-permeability and ultra-low permeability reservoirs were experimentally and theoretically investigated. Core plugs collected from a typical China oilfield were utilized for the experiments. Additionally, methane was used as the injection agent to conduct natural gas HNP/displacement experiments. The results indicated that the use of natural gas as an energy supplement agent and the HNP development method can effectively improve the recovery efficiency of the aforementioned two types of reservoirs. During the HNP process, the oil recovery is effectively enhanced mainly in the first round and second round. Meanwhile, during gas injection and HNP, natural gas can evidently weaken the extraction and reduce the precipitation of heavy components. However, the natural gas injection can establish an effective driving pressure system in low-permeability core plugs, and the interaction between natural gas and oil can change the mobility ratio. Furthermore, it aids in avoiding viscous fingering and premature breakthroughs. Moreover, the oil can be sandwiched between the interface of the gas and water phases to form a slip channel in a hydrophilic core sample, which can quickly produce oil. Finally, a numerical model was developed by considering the reservoir parameters of Changqing Oilfield, China. The oil recovery after eight rounds of CH4 HNP was 80% higher than that achieved via depletion development. Additionally, the oil recovery curves are especially similar in the previous three HNP rounds. These curves show obvious differences from the fourth round onwards, which indicates that the asphaltene deposition and CH4 diffusion slightly affect the oil recovery factor during the initial production period.

A semi-analytical model for horizontal-well productivity in shale gas reservoirs: Coupling of multi-scale seepage and matrix shrinkage

Matrix permeability is an important parameter in shale gas productivity prediction. However, the permeability affected by multi-scale seepage is difficult to calculate accurately. The object of this study is to develop an integrated apparent permeability model for multi-scale seepage mechanisms. The apparent permeability model considered shale gas flow from shrinkable matrix to fracture system with slip flow, Knudsen diffusion, and surface diffusion. The transport capacity change with different seepage mechanisms under different conditions was specifically analyzed. The importance of each parameter in the apparent permeability model was qualified using Grey correlation method. In addition, a semi-analytical model for horizontal-well productivity was developed to describe shale gas transport in reservoir. The semi-analytical model was solved using Laplace integral transformation and point source method. According to the results based on Grey correlation method, the effects of pore radius and Langmuir volume on dimensionless-type curves were discussed. Compared with the pore radius, the Langmuir volume had more influences on the shape of typical curve. The slip flow played the most important role in gas transport in mesopores and macropores when the pressure was more than 2 MPa and the surface diffusion was the primary transporting mechanism at any pressure in micropores but it can be negligible in macropores. The research result presented that the multi-scale seepage mechanisms would be considered in well tests and shale gas production.

Experimental investigation of seepage characteristics in porous rocks with a single fracture

An experimental investigation of seepage characteristics in porous rocks with a single fracture is presented. A seepage system was developed and assembled in the laboratory using two experimental setups. Tests were conducted to quantify the effects of influent pattern, fracture aperture (B), coefficient of permeability of the porous medium (k), hydraulic gradient (J), and water temperature (T) on the seepage characteristics of a porous concrete matrix with a fracture; the porous concrete, with controlled characteristics, was designed to simulate porous rock. The mechanisms of seepage exchange between the porous media and the fracture are discussed, and a new formula for describing the seepage mechanism in a porous rock with a single fracture is proposed. The results showed that B, k, and influent pattern had significant effects on the seepage between the fracture and the porous concrete. The amount of effluent exiting the fracture was greater than that exiting the porous concrete blocks. The proposed model indicated that when B was less than 3.0 mm, the variation in fracture aperture had a significant influence on the effluent from the fracture, while its influence was relatively small when B was greater than 3.0 mm. When k was less than 1.0 cm/s and B increased to 4.8 mm, seepage exited only via the fracture. The proposed mathematical model can be used to effectively estimate the seepage through porous rocks with a fracture.

Modelling of fractured horizontal wells with complex fracture network in natural gas hydrate reservoirs

Shale gas resources (SGR), as a representative of natural gas hydrate reservoirs, have been the main energy supply for the energy consumption currently. The multi-scale pore structure of shale, complicated seepage mechanisms, including Knudsen diffusion, matrix deformation, stress sensitivity, non-Darcy flow and spatial fracture network stimulated by hydraulic fracturing technology have posed huge challenges to an accurate prediction and assessment of shale gas recovery. A full understanding of gas seepage mechanism of shale gas is the critical and scientific issue to develop carbon hydrogen energy resources effectively. It is very urgent to establish a comprehensive mathematical model to analyze the productivity capacity through simultaneously considering various flow mechanisms and fractures network system. To fill this gap, this paper presents a comprehensive numerical model of hydraulic fracturing horizontal well with discrete fracture network where embedded discrete fracture model (EDFM) is employed to characterize the coupled phenomenon between discrete fracture network and fractured SGR. And then two numerical discretization methods, e.g., finite difference and finite-volume, are used to numerically discretize the equations, subsequently, the Newton-Raphson iterative method is adopted to obtain the final solutions. Finally, the sensitivity analysis experiments are employed to investigate the effects of the key parameters. The results can provide some certain guidance for the optimization of stimulated treatment in natural gas hydrate reservoirs.