Fractured Shale Reservoirs Research Articles

Study on microscale pore structure and bedding fracture characteristics of shale oil reservoir

Accurately characterizing the cross-scale structure of pores and fractures in shale reservoirs is the theoretical basis for efficient exploration and development of shale oil and gas. In this paper, (a) Based on the research background of different shale maturity and sedimentary characteristics, a three-dimensional model of cross-scale pore-fracture structure is established; (b) Based on a large number of CT characterization data of core pore-fracture structure, the characteristics of pore-fracture development under different geometric dimensions (25 mm and 2 mm) are statistically analyzed; (c) Pore and fracture structures of mixed shale, felsic shale and laminated felsic shale is comparatively studied, and the pore structure and bedding fracture characteristics of shale oil reservoir is revealed. Results show that: (a) for the bedding fracture porosity, felsic shale in Group I is 0.36 %–0.89%; mixed shale in Group I is 0.34 %–0.47%; mixed shale in Group III is 0.12 %–0.86%; mixed shale gravelly dolomite in Group III is 0.13 %–0.15%. (b) Compared with block 1, the laminated felsic shale bedding in block 2 is more developed. (c) CT imaging is based on density difference. Different components of shale samples are distinguished by gray scale.

Numerical investigation on hydraulic fracture propagation and multi-perforation fracturing for horizontal well in Longmaxi shale reservoir

Hydraulic fracturing is one of the key technologies of shale gas extraction. Deeply comprehending the distribution characteristics of hydraulic fracture networks in shale reservoirs is significant for the shale gas fracturing design and production estimation. The efficient description of fluid–solid coupling is essential for modeling the hydraulic fracturing process. In this paper, based on the mechanical parameters from the laboratory test results, the fluid–solid coupling model in PFC2D is improved and employed to establish a DEM model for the hydraulic fracturing of shale reservoirs. The key factors affecting the hydraulic fracture propagation characteristic are investigated, furthermore, based on the geological parameters of Changning shale gas production areas, a multi-perforation fracturing numerical model of the shale reservoir horizontal well is established, and the distribution characteristics of the hydraulic fracture network in staged fracturing are analyzed and revealed. The results indicate that the main factor affecting the formation of a fracture network in the vertical section of the shale reservoirs is the coalescence of interbedding fractures. A large number of secondary interbedding fractures generated by the primary through-bedding fracture can form a complex fracture network, which is exactly the fracture morphology required for hydraulic fracturing in shale gas exploitation. According to the results of hydraulic fracture distribution characteristics under different perforation spacings, the optimal perforation spacing requires that the fractures extend to the maximum range under the premise of hydraulic fracture coalescence can form an effective network and guarantee low economic cost and construction technical difficulties.

Characteristics and Gas-Bearing Properties of Yanchang Formation Shale Reservoirs in the Southern Ordos Basin

Ordos Basin is a multicycle superimposed cratonic basin in northern China with a simple internal structure and a gentle stratigraphic slope. It is characterized by extensive development, numerous oil and gas-bearing layers, and complete source-reservoir-caprock assemblages. However, the research on continental shale reservoirs and gas-bearing characteristics in the southern part of the basin is not in-depth enough, which restricts the further exploration and development of shale gas in this area. In this paper, the development characteristics of pores and fractures in shale reservoirs and the gas-bearing characteristics of Yanchang Formation shale in the study area are summarized by the comprehensive use of field outcrop, core, and logging, combined with common thin section observation, scanning electron microscope observation, X-ray diffraction analysis, and other methods and techniques. Research indicates that the cement content of the sandstone in the Yanchang Formation reservoir in the south of Ordos is generally 5%-25%. The reservoir also has a large number of primary pores, secondary pores, and microfractures. The gas content of the Yanchang Formation shale represented by Chang 7 is related to both organic matter and pore structure.

A 3D hybrid DFPM-DFM Model for gas production from fractured shale reservoirs

Hydraulic fracturing as a key technology has been applied to improve gas productivity from shale reservoirs. Both induced hydraulic fractures (HFs) and inherent natural fractures (NFs) delineate a shale reservoir into matrix and fracture domains. Accurate characterizations of matrix and fracture are critical in evaluating gas production. In this work, an in-house built 3D discrete fracture model (DFM) was proposed to explicitly represent the distribution of the NFs network. Gas flow in shale matrix containing multiscale pores in inorganic matters (IOM) and organic matters (OM) was represented by a dual-fractal permeability model (DFPM). Consequentially, a hybrid DFPM–DFM model was proposed to couple gas flow and geomechanics the model was solved by commercial software based on the finite element method. The proposed model was verified using field data from a shale reservoir. The model was further employed to investigate the impacts of fractally-distributed pore size and fracture attributes on the evolutions of permeability and the associated gas production. The results showed that the fractally distributed pore size of IOM accounts for the diverse profiles of permeability evolution that exhibits a downward trend before rebounding. The impacts of pore diameter and tortuosity index on cumulative gas production were quantitatively analysed. We also highlighted the remarkable effects of fracture patterns (fracture connectivity, aperture and number) on cumulative gas production. This work provides a framework to explore the multiscale structural heterogeneities on hydrocarbon recovery and shale deformation.

Experimental evaluation of the flow resistance of CO2 foam fracturing fluids and simulation prediction for fracture propagation

Shale gas fracturing requires huge amounts of water, but most well pads are located mainly in hilly areas where water is scarce. Water supply issues have limited the industrialization of shale gas development. CO2 foam fracturing fluids can meet the requirements for large-scale hydraulic fracturing of shale gas and relieve pressure on water resources. Friction calculations of CO2 foam fracturing fluids in conduit flow are key to the reliability of overall fracturing procedures, affecting fracture targeting and reservoir stimulation effects. Through the analysis of the experimental data of carbon dioxide foam fracturing fluid flow under the simulated reservoir conditions, the influence of pressure, temperature, shear rate, foam quality and other factors on the friction characteristics of CO2 foam fracturing fluid was obtained, and the mathematical calculation model of the friction coefficient of CO2 foam fracturing fluid was established, and the pipe string friction and bottom hole pressure during the fracturing process were obtained, Thus, the shape and extension behavior of hydraulic fractures in the process of carbon dioxide foam fracturing in shale reservoir are simulated and predicted, which provides a theoretical basis for effective evaluation of fracturing effect.

Data-Driven Fracture Morphology Prognosis from High Pressured Modified Proppants Based on Stochastic-Adam-RMSprop Optimizers; tf.NNR Study

Data-driven models with some evolutionary optimization algorithms, such as particle swarm optimization (PSO) and ant colony optimization (ACO) for hydraulic fracturing of shale reservoirs, have in recent times been validated as one of the best-performing machine learning algorithms. Log data from well-logging tools and physics-driven models is difficult to collate and model to enhance decision-making processes. The study sought to train, test, and validate synthetic data emanating from CMG’s numerically propped fracture morphology modeling to support and enhance productive hydrocarbon production and recovery. This data-driven numerical model was investigated for efficient hydraulic-induced fracturing by using machine learning, gradient descent, and adaptive optimizers. While satiating research curiosities, the online predictive analysis was conducted using the Google TensorFlow tool with the Tensor Processing Unit (TPU), focusing on linear and non-linear neural network regressions. A multi-structured dense layer with 1000, 100, and 1 neurons was compiled with mean absolute error (MAE) as loss functions and evaluation metrics concentrating on stochastic gradient descent (SGD), Adam, and RMSprop optimizers at a learning rate of 0.01. However, the emerging algorithm with the best overall optimization process was found to be Adam, whose error margin was 101.22 and whose accuracy was 80.24% for the entire set of 2000 synthetic data it trained and tested. Based on fracture conductivity, the data indicates that there was a higher chance of hydrocarbon production recovery using this method.

Cryogenic liquid nitrogen stimulation-induced cracking in gas-enriched shale reservoirs: A numerical investigation

Cryogenic shock-induced brittle cracking has promising application prospects in reservoir stimulation. In this paper, a fully coupled thermo-hydro-mechanical (T-H-M) model combined with the statistical meso-damage theory is proposed to investigate the trans-scale progressive cracking process of shale gas reservoirs stimulated by liquid nitrogen (LN2). In this theoretical framework, shale meso-heterogeneity in both thermo-mechanical and hydraulic properties is characterized by two independent statistical distribution functions; temperature-dependent rock properties and temperature- and pressure-dependent fluid thermodynamic properties are described using some experimental and theoretical formulas. The numerical model is implemented in a finite element context and subsequently validated against existing classical coupling results. Numerical results demonstrate that LN2 fracturing accompanied by the unique cryogenic shock effect leads to a complex cracking process involving multiple-point fracture initiation, asymmetric macrofracture propagation, and primary fracture bifurcation. Sensitivity analysis indicates that approximately equidistant or equilength radial fractures may be generated at a lower stress difference, lower permeability, or higher elastic modulus; both fracture initiation pressure and induced fracture morphology are more sensitive to injected fluid temperature relative to initial reservoir temperature; a larger thermal expansion coefficient is beneficial for inducing more fractures, but not applicable to the thermal conductivity. Preferable candidates for LN2 stimulation to generate multiple fractures in shale reservoirs are recommended. It is also found that compared with H2O and supercritical CO2, fracturing using LN2 can generate fractures with lower initiation pressure and greater complexity. Preliminary results confirm the potential of using LN2 fracturing to improve the stimulation effect of shale reservoirs.

Simulation study of micro-proppant carrying capacity of supercritical CO2 (Sc-CO2) in secondary fractures of shale gas reservoirs

Micro-proppants with stronger portability have more potential to migrate to the massive micro-sized secondary fractures (SFs) or natural fractures activated by supercritical CO2 (Sc-CO2) fracturing in shale gas reservoirs. However, the transportation behaviour of micro-proppants in massive SFs has been scarcely studied to date. In this study, we report the simulation of micro-proppant migration across a fracture intersection during Sc-CO2 fracturing based on a combination of computational fluid dynamics and the discrete element method. A straight fracture intersection model was first validated against experimental data from an earlier study. Next, the influential factors, including fluid viscosity, cross angle, proppant diameter, fluid velocity and the ratio of proppant diameter to SF, were examined in the transportation behaviour of micro-proppants in Sc-CO2 fracturing. The results show that the poor proppant distribution in SFs is dominated by the ultralow viscosity of Sc-CO2, but the decrease of proppant diameter to 25 μm presents slurry flow behaviour, resulting in a migration distance around 8 times longer than that of 200 μm and much stronger proppant-carrying capacity into SFs. The transportation behaviour of micro-proppants into SFs depends on the suspended proppants concentration and the rolling proppants from the proppant embankment in the primary fracture (PF), determined by the combined effects of different factors. Fast fluid velocity of 0.2 m/s increases the priority of the proppant embankment formation in SFs. Cross angles greater than 45° limit the suspended proppants in SF, and the proppant embankment in the SF dominantly depends on rolling proppants from PF. Greater SF aperture facilitates proppants transportation into the SF due to the reduced bridging effect, but not into the PF. The key findings are optimized proppant-carrying capacity into SFs and improved stimulated volume during Sc-CO2 fracturing in shale reservoirs.

Data-Driven Inversion-Free Workflow of Well Performance Forecast Under Uncertainty for Fractured Shale Gas Reservoirs

Abstract Well performance prediction and uncertainty quantification of fractured shale reservoir are crucial aspects of efficient development and economic management of unconventional oil and gas resources. The uncertainty related to the characterization of fracture topology is highly difficult to be quantified by the conventional model-based history matching procedure in practical applications. Data-space inversion (DSI) is a recently developed inversion-free and rapid forecast approach that directly samples the posterior distribution of quantities of interest using only prior model simulation results and historical data. This paper presents some comparative studies between a recent DSI implementation based on iterative ensemble smoother (DSI-IES), model-based history matching, and conventional decline curve analysis (DCA) for shale gas rate forecast. The DSI-IES method treats the shale gas production rate as target variables, which are directly predicted via conditioning to historical data. Dimensionality reduction is also used to regularize the time-series production data by low-order representation. This approach is tested on two examples with increasing complexity, e.g., a fractured vertical well and a multistage fractured horizontal well in the actual fractured Barnett shale reservoir. The results indicate that compared with the traditional history matching and DCA methods, the DSI-IES obtains high robustness with a high computational efficiency. The application of data-space inversion-free method can effectively tap the potential value directly from historical data, which provides theoretical guidance and technical support for rapid decision-making and risk assessment.

Experiment and DEM simulation study on mechanical behaviors of shale under triaxial cyclic loading and unloading conditions

During shale gas exploration, natural fractures in shale reservoirs may be induced by cyclic loads frequently encountered in different geological processes, including tectonic movements, seismic actions, and artificial construction interference (vertical and horizontal wells drilling and cyclic hydraulic fracturing). In this paper, experiments and PFC2D simulations are conducted to investigate the mechanical response and mechanism of shale specimens under cyclic loading and unloading. Using the experimental and simulation results, the strength and deformation characteristics and strain energy and damage evolutions during the cyclic loading-unloading process are quantified and analyzed. The damage variable characterized by plastic deformation, deformation modulus, and dissipated energy is thoroughly analyzed. Based on the PFC2D simulation, the micro-crack distribution and evolution are further studied, and the results can reflect the experiments well and reveal the damage mechanism under cyclic loading. Furthermore, the experiments and simulations indicate that the degree of fatigue damage is closely related to the number of cycles the specimens undergo, and a small number of cycles may not have a distinct effect on the strength.

A two-phase type-curve method with multiscale fluid transport mechanisms in hydraulically fractured shale reservoirs

The quantitative understanding of hydraulic fracture (HF) properties guides accurate production forecasts and reserve estimation. Type curve is a powerful technique to characterize HF and reservoir properties from flowback and long-term production data. However, two-phase flow of water and hydrocarbon after an HF stimulation together with the complex transport mechanisms in shale nanopores exacerbate the nonlinearity of the transport equation, causing errors in type-curve analysis. Accordingly, we propose a new two-phase type-curve method to estimate HF properties, such as HF volume and permeability of fracture, through the analysis of flowback data of multi-fractured shale wells. The proposed type curve is based on a semianalytical solution that couples the two-phase flow from the matrix with the flow in HF by incorporating matrix influx, slippage effect, stress dependence, and the spatial variation of fluid properties in inorganic and organic pores. For the first time, multiple fluid transport mechanisms are considered into two-phase type-curve analysis for shale reservoirs. We analyze the flowback data from a multi-fractured horizontal well in a shale gas reservoir to verify the field application of the proposed method. The results show that the fracture properties calculated by the type-curve method are in good agreement with the long-time production data.

Seismic pre-stack inversion for physical and anisotropic parameters in fractured shale reservoirs

AbstractThe estimation of physical and anisotropic parameters is of great importance for the characterization of fractured reservoirs. Vertical fractures developing in a laterally isotropic (VTI) setting are equivalent to orthotropic anisotropic (OA) media common in stratified fractured shale reservoirs. To obtain independent anisotropic and physical information, a novel reflection coefficient approximation containing physical and anisotropic parameters is derived to improve the stability of the inversion for orthotropic media. To simplify the equation for the reflection coefficient, an approximate rock physics model is constructed using the approximate theory of rock modulus. The estimated parameters are reduced from nine to six. The accuracy analysis reveals that the new reflection coefficient is appropriate and suitable for inversion. In addition, a stepwise Bayesian amplitude versus angle and azimuth (AVAZ) inversion method with smooth background constraints is developed to estimate the anisotropic and physical parameters from the azimuthal seismic data. The smooth background constraint improves the robustness of the inversion. And the stepwise inversion strategy solves the problem that the contribution of the fracture parameter to the reflection coefficient is smaller than the other parameters. Synthetic cases show that the proposed stepwise Bayesian AVAZ inversion method is feasible in estimating the anisotropic parameters for OA media even when the signal-to-noise ratio is 2. The field cases show that the proposed inversion method has good stability and robustness in predicting shale reservoirs with vertical or near-vertical fractures.

Experimental study on fracture propagation and induced earthquake reduction by pulse hydraulic fracturing in shale reservoirs

Large-scale and complex cracks have always been the eternal goal of hydraulic fracturing (HF) technology in shale reservoirs, but there has been the public concern that the HF could trigger earthquake disasters. It is urgent to develop the new HF technology that can generate a large number of complex cracks and reduce the risk of induced earthquake. Herein, the fracture propagation, fluid pressure distribution and acoustic emission (AE) energy of four types of hydraulic fracturing are analyzed through laboratory experiment and numerical simulation in this study. The new rectangular pulse HF is proposed. It is concluded that the pulse HF with higher fluid pressure gradient takes a shorter time to fracture shale. It is easier to form complex cracks. Relying on reciprocating impact and strong “Water Hammer Effect”, the pulse HF can form a large number of micro-cracks and reduce the energy released at the moment of complete failure of shale. The research shows that the pulse HF with the larger pressure gradient performs better in fracturing shale and reducing the risk of induced earthquake. The rectangular pulse HF has more significant advantages than the sine and triangle pulse HF. It relies on low instantaneous rock rupture energy, long rupture time and widely distributed low energy rupture events to reduce induced earthquakes. These can help to develop the pulse HF technology and reduce the risk of induced earthquakes for shale gas exploitation.

Research on Rock Physics Modeling Methods for Fractured Shale Reservoirs

The Sichuan Basin is a significant region for exploration and development of shale gas in China, and it is essential to clarify the impact of deep shale gas reservoir parameters on cost-effective development at scale to ensure national energy security. Rock physics modeling is a significant means of communicating the physical and elastic parameters of rocks. A rock physics modeling method applicable to fractured shale gas reservoirs is proposed for the current situation of complex fluid relationships in shale gas reservoirs and unclear characteristics of gas identification seismic response. In this paper, based on the Self Consistent Approximation (SCA) model and the differential effective medium (DEM) model, the anisotropic source of shale is used as a starting point to add bound water, kerogen, clay, and brittle minerals, the Schoenberg linear slip theory is used to add fracture disturbance effects, and then the Brown–Korringa model is used to perform fluid replacement under anisotropic conditions. Finally a rock physics model applicable to fractured shale gas reservoirs is obtained, and the established rock physics model is used for analysis of elastic parameters, Thomsen parameters, and fracture weakness parameters. Rock physics tests were performed on shale in southern Sichuan as an example. The experimental results show that the model established by the process can accurately invert the longitudinal and transverse wave velocities of the shale, which can provide a conceptual basis for the study of fractured shale gas reservoirs.

Numerical Study on Hydraulic Fracture Propagation in a Layered Continental Shale Reservoir

The distribution of beddings varies greatly in shale reservoirs. The influence of beddings on hydraulic fracture propagation has often been studied using simplified geological models, i.e., uniformly distributed bedding models. However, the propagation processes of hydraulic fractures in shale reservoirs with complicated distributed beddings remains unclear. In this research, an outcrop-data-based bedding model of a continental shale formation in the Ordos Basin, China, is built. A mathematical model for fracture propagation is built using the discrete element method and is then verified by a hydraulic fracturing experiment. Reservoir-scale simulations are employed to investigate the influence of geological factors and engineering factors on fracture geometry. The study finds that beddings have significant inhibitory effects on fracture height growth; hydraulic fractures have difficulty in breaking through zones with densely distributed beddings. If a hydraulic fracture encounters a bedding plane with a larger aperture, it is more likely to be captured and expand along the weak interface. High vertical stress difference and a high fluid injection rate can promote the vertical penetration of hydraulic fractures through beddings and activate the bedding system to yield a complex fracture network. Increments in fluid viscosity can increase the resistance of fracture propagation, thereby reducing fracture complexity.

3D natural fracture model of shale reservoir based on petrophysical characterization

The existence and distribution of natural fractures in shale reservoirs is of great significance to shale gas exploitation. A 3D fracture spatial distribution model with varying reservoir burial depth and regional tectonicsin southeastern Chongqing is constructed based on an enhanced DFN modeling method. Fracture volume density (P32) is calculated by petrophysical test and verified from test wells. The geometric parameters of fractures (length, occurrence, opening) are clustered by regional tectonics. Uncertainties are considered by a stochastic description of the fracture network geometry, utilizing Monte Carlo simulation techniques. The application of the model in seven wells and the quantitative analysis of the relationship between fracture density and burial depth allow the modeling to be extended to deep and ultra-deep reservoirs. Fracture models with reservoirs buried depth over 3000 m are predicted and analyzed. For the various input parameters, the influence of model size and fracture shape on model reliability is analyzed. The establishment of fracture model can effectively quantitatively characterize the reservoir fracture distribution at different burial depths, and its efficient implementation in finite element software can provide support for shale gas mining engineering.

Numerical Simulation of the Fracture Propagation Mechanism during Supercritical Carbon Dioxide Fracturing in Shale Reservoirs

Abstract To investigate the fracture propagation mechanism during supercritical CO2 fracturing in shale reservoirs, a numerical model was proposed based on the displacement discontinuity method. The Peng–Robinson equation was introduced to determine the variations in CO2 properties during the fracturing process. Considering natural fracture distribution in shale reservoirs, the fracture propagation mechanisms during supercritical CO2 fracturing in shale reservoirs under different horizontal stress differences and matrix permeabilities were analyzed. The influence of the proportion of CO2 preenergizing on fracture morphology was discussed. The results obtained via numerical simulation show that supercritical CO2 is beneficial to create a more complex fracture network by activating natural fractures under the same horizontal stress difference. CO2 easily penetrates into the matrix near the fracture surfaces, increasing reservoir energy. However, when the permeability of shale reservoirs exceeds 0.04×10−3 μm2, substantial filtration of CO2 into the reservoir matrix occurs near the well bore, limiting the activation of natural fractures around the fracture tip. A higher proportion of CO2 preenergizing during fracturing is conducive to improve the fracture complexity while reducing the fracture aperture.

The influence of multi-metal-veins on fractures propagation investigated by the experiment and simulation

Fracture propagation is affected by multi-metal-veins formed by geological diagenesis in shale during the hydraulic fracturing. However, the influence of multi-metal-veins on fractures propagation remains unclear. To solve the problem, based on the semi-circle bending (SCB) test and the extended finite element (XFEM) theory, the interaction between multi-metal-veins and fractures is investigated. The experimental results reveal that the fractures usually deflect at the upper or lower interfaces between metal veins and rocks (e.g. the specimen S-2), which is different from the propagation behavior of fractures in calcite veins. Meanwhile, the fracture toughness of the specimen S-1 is 24.40% higher than that of the specimen S-2, indicating that the increasing of total thickness of multiple metal veins increases the resistance to the fracture vertical propagation. The simulation results show that the increasing of the number, total thickness of veins, the modulus difference between veins and rock, the approach angle and the notch angle all increase the resistance of the fracture passing through metal veins. The maximum deviation distance (Dmax) of the fracture decreases with the number of veins, while thickness combination types of metal veins do not affect Dmax. The reduction of the notch angle leads to the more tortuous fracture propagation path. Finally, we propose a new comprehensive fracture network pattern. Fracture networks are divided into two categories, including orthogonal fracture networks and sub-orthogonal fracture networks, and then divided into six sub-categories further. The research results will provide reference for hydraulic fracturing of shale reservoirs containing multi-metal-veins.

Characterization and Modelling of Multiscale Natural Fractures in Shale Reservoirs: A Case Study from a Block in the Southern Sichuan Basin

Natural fractures are vital to the efficiencies of drilling and completion operation. The purpose of this paper is to characterize and model multiscale natural fractures in shale reservoirs. Based on the seismic and log responses, as well as outcrop and core observations, we divide natural fractures into Macro, Meso, and Micro three scales. Macroscale fractures are the faults picked directly in seismic profiles. Also, Mesoscale fractures are the natural fracture corridors analyzed by ant tracking technique in 3D seismic data. Furthermore, Microscale fractures are the fractures observed in imaging logs and cores. The fracture intensity is obtained by the correlation between ant tracking attributes and fracture density in borehole. The fracture aperture, dip, and azimuth are three main parameters, which are recognized by the loggings and cores. Stochastic modelling is applied to factures. We find that faults identified by the ant tracking result are excellent in line with Macroscale faults interpreted directly from seismic data. In addition, Mesoscale fractures are indicated from the ant tracking result, which are in accord with breakpoint in the well and in keeping with tectonic history of the area. Such high consistency indicates the ant tracking result is reliable. Moreover, image logs and cores reveal that it mainly develops high angle natural fractures and the fracture aperture is about 1 mm. The fracture strike includes three sets (NNW-SSE, NE-SW, and NNE-SSW). The distribution of the natural fractures in discrete fracture network (DFN) system is distributed controlled by the ant tracking result. Comparing the histograms of DFN results and fracture characterized by seismic and logging responses, as well as outcrop and core observation, it suggests that the major part of the observed natural fractures is retained into our DFN model.

Numerical simulation of formation water salinity redistribution in fractured shale reservoirs during hydraulic fracturing

Using numerical simulation methods to predict the distribution of salinity in reservoirs during hydraulic fracturing is challenging due to the dynamic propagation of hydraulic fractures (HFs), random distribution of natural fractures (NFs), multiphase heat and mass transfer behavior, and various connotative mechanisms. In this study, to accurately predict changes in matrix salinity during hydraulic fracturing, a multiphase heat and mass transfer model of HFs, the matrix, and NFs was derived based on the principles of material and energy conservation, the electro-chemical potential, and the embedded discrete fracture model (EDFM). The model considers the dynamic propagation of HFs, multiphase flow, chemical osmotic pressure, capillary pressure imbibition, heat conduction, and NFs. The prediction model of solute salinity developed in this study is then verified using previous findings. Finally, the effects on the salinity distribution within the matrix by volume differences of injected fracturing fluid, salinities of the fracturing fluid, number of NFs, temperatures of fracturing fluid, and mechanisms were analyzed. The results show that the injection volume and temperature of the fracturing fluid, and the number of NFs are positively correlated with the decreasing range of salinity in the matrix and damage range of clay swelling, while the salinity of the fracturing fluid is negatively correlated with the decreasing range of salinity in the matrix and the damage range of clay swelling. During fracturing, the random distribution of NFs and local strong heterogeneity hinder prediction and cause strong heterogeneity in the distribution of salinity, pore pressure, and matrix temperature. At the same time, the pressure gradient, chemical osmotic pressure, and imbibition of capillary pressures under mixed wetting decrease salinity within the matrix and aggravate clay swelling damage. Of the three mechanisms affecting the salinity distribution within the matrix, the pressure gradient has the greatest contribution, followed by osmotic pressure and capillary pressure imbibition. The results of this study provide insights into the theoretical prediction of salinity distribution in the matrix after fracturing and hence the design of HFs.