Fractured Gas Reservoirs Research Articles

Research Progress of Three-dimensional Geological Modeling and Multi-field Coupling of Fractured Oil and Gas Reservoirs

Fractured oil and gas reservoirs play an important role in oil and gas exploration and development due to their complex fracture network structure. As the main fluid channel in the reservoir, fractures have a significant impact on the migration, accumulation and exploitation efficiency of oil and gas. This paper summarizes the key geological characteristics of fractured reservoirs, including fracture types, distribution rules and main controlling factors of fracture development, and discusses the influence of fractures on reservoir physical properties. Furthermore, the deterministic and stochastic modeling methods of three-dimensional geological modeling of fractured reservoirs and the latest progress of discrete fracture network modeling technology are introduced in detail. In addition, this paper also discusses in detail the application of multi-field coupling model in the numerical simulation of fluid flow in fractured reservoirs, including continuous medium model and discrete medium model, and their advantages and disadvantages in simulating fluid flow in fractured reservoirs. Finally, this paper summarizes the research progress of multi-physics coupling model of fractured reservoirs, and points out the direction and challenges of future research. Through these studies, it can provide theoretical support and technical guidance for oil and gas exploration and development, in order to achieve more effective development and management of fractured reservoirs.

Research on Numerical Simulation Methods for Water Invasion Dynamics in Fractured Gas Reservoirs with Water Content

Abstract Fractured gas reservoirs with water have complex gas-water relationship, large permeability difference between matrix and fracture, complex gas-water percolation mode, rapid production decline, short stable production period and large reduction of recovery factor due to water production of gas wells, which poses great challenges to efficient development of gas fields. The fracture system is the main channel for the edge and bottom water channeling of gas reservoirs. It is the core issue to understand the water invasion dynamic characteristics of such gas reservoirs to accurately depict the fracture geometry occurrence and truly simulate the gas-water two-phase flow mechanism in the fracture-matrix dual media. Taking the Jia-2 gas reservoir in Moxi gas field as an example, a discrete fracture model construction method that explicitly characterizes the fracture system is proposed. Based on the discrete fracture model, a mathematical model of gas-water two-phase flow in the fracture-matrix dual system is constructed and numerically solved. The influence mechanism of fracture opening, length, density and occurrence on the water invasion performance of multi-layer gas reservoirs is discussed, and the main control factors of the water invasion and water channeling law of fractured water gas reservoirs are identified. The application shows that the water invasion dynamics of gas reservoirs based on the discrete fracture model are more consistent with the actual conditions of the mine, providing a theoretical basis for deepening the understanding of water invasion dynamics of this type of gas reservoirs, optimizing the gas well working system, and formulating targeted water control countermeasures..

Analysis of Production Decline Type Curves Considering Water Influx in Naturally Fractured Gas Reservoirs

Abstract In the development of fractured gas reservoirs with edge and bottom water, water invasion is a pervasive issue. However, most production decline analysis models focus on primary depletion with closed boundaries rather than secondary depletion with water influx. Therefore, this paper aims to develop decline type curves for analyzing and interpreting production data from existing natural water influx in fractured gas reservoirs. Firstly, a transient dual porosity flow model is developed considering water influx in naturally fractured gas reservoirs, the functions of Blasingame decline type curves are derived and obtained. Subsequently, the Blasingame production decline type curves of a vertical well in naturally fractured reservoirs experiencing natural water influx are plotted. These new type curves can estimate water invasion and dual medium parameters, offering valuable insights for production decline analysis in fractured reservoirs with water influx. The Blasingame production decline curves are divided into six regimes based on characteristics. Then, the effects of various formation parameters and water invasion cases on the type curves are discussed and analyzed. Compared with Blasingame type curves without water influx at the external boundary, the behaviors of those presented in this paper are quite different at the boundary responses. Finally, through the analysis of a case well, it is found that theoretical type curves considering dual-medium and water invasion are more consistent with actual production data. This suggests that these new type curves provide more accurate estimation for understanding and managing issues related to water invasion in fractured gas reservoirs.

Research on Fracture Parameter Optimization Method Based on Generative Adversarial Network in Small Sample Size

Abstract This study addresses the optimization of fracturing parameters in the fractured gas reservoirs of the Tarim Basin, especially under the challenge of small sample sizes and high data acquisition costs. It proposes an innovative method based on Generative Adversarial Networks (GAN). Traditional fracturing technology parameter optimization often leads to model overfitting and poor generalization due to limited data. This research adopts GAN for data augmentation to generate additional training samples, thereby improving the training effect of machine learning models. The combination of genetic algorithms and model fusion techniques further optimizes production capacity prediction and fracturing parameter adjustment. Application of this method to actual data from the Tarim Basin shows that it effectively enhances the accuracy of parameter optimization and the generalization ability of the model, providing significant guidance for gas reservoir development under similar complex geological conditions.

Numerical Simulation of Non-Darcy Flow in Naturally Fractured Tight Gas Reservoirs for Enhanced Gas Recovery

In this work, we analyze non-Darcy two-component single-phase isothermal flow in naturally fractured tight gas reservoirs. The model is applied in a scenario of enhanced gas recovery (EGR) with the possibility of carbon dioxide storage. The properties of the gases are obtained via the Peng–Robinson equation of state. The finite volume method is used to solve the governing partial differential equations. This process leads to two subsystems of algebraic equations, which, after linearization and use of an operator splitting method, are solved by the conjugate gradient (CG) and biconjugate gradient stabilized (BiCGSTAB) methods for determining the pressure and fraction molar, respectively. We include inertial effects using the Barree and Conway model and gas slippage via a more recent model than Klinkenberg’s, and we use a simplified model for the effects of effective stress. We also utilize a mesh refinement technique to represent the discrete fractures. Finally, several simulations show the influence of inertial, slippage and stress effects on production in fractured tight gas reservoirs.

Mechanism and application of gas phase trapping by spontaneous imbibition

For fractured gas reservoirs with strong water drive, gas phase trapping affects the gas recovery significantly. The recovery may be less than 50% for some reservoirs while it is only 12% for Beaver River gas field. The gas phase trapping mechanism has been revealed by the results of depletion experimental test. The residual pressure of the trapped gas is as high as 11.75 MPa with a 12.8 cm imbibition layer resulting in gas recovery deceased 49.5% compared with that without imbibition layer. A mathematical model is built to calculate the imbibition thickness based on capillary pressure and relative permeability of the matrix. The gas phase trapping are analyzed by two representative wells in Weiyuan gas field, the intermittent production reinforces the imbibition thickness and result in gas trapped in the matrix block with high residual pressure for the low performace gas wells, the extremely low gas recovery can be explained more rationally. That lays a foundation of improving the gas recovery for fractured reservoirs.

An Accurate Calculation Method on Blasingame Production Decline Model of Horizontal Well with Dumbbell-like Hydraulic Fracture in Tight Gas Reservoirs

Blasingame production decline is an effective method to obtain permeability and single-well controlled reserves. The accurate Blasingame production decline curve needs an accurate wellbore pressure approximate solution of the real-time domain. Therefore, the aim of this study is to present a simple and accurate wellbore pressure approximate solution and Blasingame production decline curves calculation method of a multi-stage fractured horizontal well (MFHW) with complex fractures. A semi-analytical model of MFHWs in circle-closed reservoirs is presented. The wellbore pressure and dimensionless pseudo-steady productivity index JDpss (1/bDpss) are verified with a numerical solution. The comparison result reaches a good match. Wellbore pressure and Blasingame production decline curves are used to analyze parameter sensitivity. Results show that when the crossflow from matrix to natural fracture appears after the pseudo-state flow regime, the value of the inter-porosity coefficient has an obvious influence on the pressure approximate solution of the pseudo-steady flow regime in naturally fractured gas reservoirs. The effects of relevant parameters on wellbore pressure and the Blasingame decline curve are also analyzed. The method of pseudo-steady productivity index JDpss can applied to all well and reservoir models.

In-situ CT study on the effect of cyclic gas injection and depletion exploitation on the phase behavior of fractured condensate gas reservoirs

Using subterranean rock cores as samples, the impact of depletion exploitation and cyclic gas injection on the occurrence and dynamic utilization of condensate oil and the damage to reservoirs were studied. Initially, the internal pore structure of the rock core was analysed using computer tomography (CT), followed by depletion and cyclic gas injection experiments, with in-situ CT scanning of the samples. The results indicate that under different fracture apertures, condensate oil exhibits wave flow and slug flow states. The production effectiveness of cyclic gas injection is significantly superior to depletion exploitation production, with condensate oil saturation decreasing by over 30%. During cyclic gas injection, fractures serve as the main flow channels, with condensate oil being extracted first. In cyclic gas injection, the most significant effect is seen during the first injection, with a decrease in oil saturation of around 3%. Subsequent injections show decreases of approximately 1% and 0.5% in oil saturation respectively. As the gas injection volume increases, the extent of cumulative production rate improvement also gradually increases; however, once the injection volume reaches the reservoir pressure, the rate of cumulative production rate improvement will gradually decrease. These findings provide technical support for optimizing the development mode of condensate gas reservoirs, clarifying the seepage law of condensate oil and gas, and providing technical support for the efficient development of fractured condensate gas reservoirs.

Underground hydrogen storage in depleted gas reservoirs with hydraulic fractures: Numerical modeling and simulation

Underground hydrogen storage (UHS) is one of the key technological solutions for balancing energy systems and promoting sustainable energy development. In this study, we propose a novel UHS method, which involves injecting hydrogen generated from electrolyzing formation water into depleted gas reservoirs through hydraulic fractures during off-peak electricity periods, and then efficiently producing hydrogen for power generation during peak electricity periods. We establish a numerical simulation model for UHS in a depleted fractured gas reservoir, covering the entire process from injecting hydrogen gas into the reservoir through wells to shutting them down and subsequently producing hydrogen when required. We then investigate the impact of hydrogen injection rate, injection duration, and shut-in duration on the UHS process and storage efficiency. Our findings reveal that hydrogen production efficiency can exceed 85 % by optimizing hydrogen injection and production strategies. Our study provides an exemplary numerical simulation scheme to evaluate the feasibility of UHS in depleted gas reservoirs with hydraulic fractures.

A Dynamic Reserve Evaluation Method for an Ultra-Deep Fractured Tight Sandstone Gas Reservoir

A Dynamic Reserve Evaluation Method for an Ultra-Deep Fractured Tight Sandstone Gas Reservoir

Mechanism of displacement gas kick in horizontal well drilling into deep fractured gas reservoir

The risk of well control is high when displacement gas kick occurs in the deep fractured reservoir, and improper handling can easily lead to blowout, which will seriously affect the deep well drilling. Using Fluent software, a simulation model was constructed to depict the interaction of a horizontal well with vertical fractures. The displacement gas kick process was simulated in horizontal well under formation temperature and pressure conditions. An analysis was conducted to assess the impact of fracture width, quantity, as well as the viscosity and density of drilling fluid on the process of gas-liquid displacement. It further compared the effectiveness of three measures in counteracting displacement gas kick: applying back pressure at the wellhead, altering the viscosity and density of the drilling fluid. New findings suggest that the gas-liquid interface within the fracture exhibits a funnel-like shape, where the gas and liquid phases are layered in the annulus and manifest in a streak-like pattern. Fracture width, quantity, and drilling fluid density promote displacement, while drilling fluid viscosity inhibits the displacement. Different from vertical wells, in horizontal wells, displacement gas kick mainly appears in the underbalanced interval. The fracture width primarily determines the size of the displacement window, while the density and viscosity of the drilling fluid exert lesser influence. Horizontal wells are highly sensitive to variations in external conditions when it comes to displacement gas kick. Therefore, enhancing the wellhead back pressure is advisable to address the displacement gas kick in horizontal wells.

Study on the Mechanism of Wellbore Blockage and Scaling Trend Prediction of Keshen Block

Located in the Kuqa foreland basin, Tarim Basin, the Xinkeshen gas field is a rare ultra-deep and ultra-high-pressure fractured tight sandstone gas reservoir. During the development process, the fluid in the well migrates from the bottom hole to the ground. Due to the huge temperature drop and pressure drop in the wellbore, salting-out and scale-out occur in the well to destroy the oil and gas flow channel, resulting in a decrease in gas production in the well and seriously affecting the normal production of the oil field. Aiming at the problem of wellbore scaling and blockage in the Keshen gas field, this paper takes the wellbore of the Keshen block as the research object. After analyzing the composition of produced water and scale in the wellbore, the solution of ‘fixing scale, clarifying mechanism, early prediction, and fine treatment’ is formulated, and the analysis and evaluation technology of the scale formation process and the prediction model of the gas well model are formed. The wellbore blockage in Keshen block is composed of iron oxide, calcium carbonate crystal, calcite crystal, and wellbore steel falling off due to electrochemical corrosion. It is indicated that the scale attached to the steel sheet causes electrochemical corrosion of the steel sheet, resulting in ‘hydrogen embrittlement’, resulting in the bubbling and falling off of the wellbore steel. Through simulation, it is found that the amount of fouling increases with the increase in wellbore depth, and the amount of fouling is 1.97 kg/d at 6800 m, which is in good agreement with the actual situation. Based on the temperature and pressure curves in the wellbore, the simulation results show that the corrosion rate reaches the highest value of 6.37 mm/yr at the depth of 3400 m. Because of the above problems, a polyaspartic acid scale inhibitor with a scale inhibition rate of 98.9% for wells in Keshen block was synthesized. It has important guidance and reference significance for the accurate treatment of scaling problems in the Keshen gas well.

Study on the Flow Behavior of Gas and Water in Fractured Tight Gas Reservoirs Considering Matrix Imbibition Using the Digital Core Method

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured tight gas reservoirs encompasses the flow within fractures and the imbibition flow within the matrix. However, conventional methods typically separate these two types of flow for study, failing to accurately reflect the true flow characteristics of water. In this study, micro-CT imaging techniques were utilized to evaluate the impact of matrix absorption and to examine water movement in fractured tight gas deposits. Water flooding experiments were conducted on tight sandstone cores with different fracture morphologies. Micro-CT scanning was performed on the cores after water injection and subsequent static conditions, simulating the process of water displacement gas in fractures and the displacement of gas in matrix pores by water through imbibition under reservoir conditions. Changes in gas–water distribution within fractures were observed, and the impact of fracture morphology on water displacement recovery was analyzed. Additionally, the recovery rates of fractures and matrix imbibition at different displacement stages were studied, along with the depth of water infiltration into the matrix along fracture walls. The insights gained from this investigation enhance our comprehension of the dynamics of fluid movement within tight gas deposits, laying a scientific foundation for crafting targeted development plans and boosting operational efficiency in such environments.

Prediction of fractures by using the stress field in medium to deep shale gas reservoirs: A case study of Late Ordovician–early Silurian shale gas reservoirs in the Nanchuan region, South China

Containing representative shale gas reservoirs, the Wufeng–Longmaxi Formations in the Nanchuan region in South China have been modified by three compressional tectonic movements (in the Late Jurassic to Early Cretaceous, Late Cretaceous, and Cenozoic to present). These movements formed deeply buried reservoirs with complex in situ stresses and rapid directional changes, influencing the state of shale gas reservoirs fractures. Numerical modeling applied to model the stress field in the three periods showed that the maximum compressive horizontal principal stress (σHmax), strain rate, and fault slip rate regimes transformed from a thrust and strike-slip regime to a thrust and strike-slip regime to a thrust regime. The σHmax direction changed from NW–SE and WNW–ESE to WNW–ESE and nearly E–W and then to multiple directions. The magnitude of strain rate changed from -16 ∼ -15 to -17.7 ∼ -15.6 to -18.8 ∼ -15.8. The fault slip rate changed from 0 to 0.029 mm/a to 0–0.0026 mm/a to 0–0.0012 mm/a. These data strongly agree with data from drilled wells and outcrops and show that the present-day stress field is the superposed effect of multistage movements. Semiquantitative research was conducted on shale gas fracture openness and fracture development. Fracture openness is favorable when the angle between the σHmax direction and nearby faults is ≤45° and the distance from the fault is >2 km, and fracture development is favorable when the magnitude of the strain rate is <-17.6 and the fault slip rate is <0.00036 mm/a. Accordingly, we predicted fractured shale gas reservoirs.

Differences in stress sensitivity of natural-artificial fracture networks in tight sandstone gas reservoirs

Abstract The stress sensitivity of fractures has a significant impact on the production characteristics of tight sandstone gas reservoirs. However, there has been a lack of attention to and research on the differences between different types of fracture and their stress sensitivity. Based on the core samples of the Keshen gas reservoir in Xinjiang, China, this paper conducts a comprehensive comparison of the flow capacity, stress sensitivity, and the production characteristics of the structural fracture, diagenetic fracture, and artificial fracture. The findings reveal that the flow capacity of a single structural fracture is higher than that of a diagenetic fracture. Additionally, both structural and diagenetic fractures contribute to increasing the flow capacity of the porous system by 63 and 88%, respectively. The stress sensitivity of fractures varies from strong to weak, structural fractures exhibit a higher sensitivity compared to diagenetic fractures, and artificial fractures demonstrate the weakest stress sensitivity. Based on the fitting formulas of stress-sensitivity curves for different fractures, a new seepage model considering different stress sensitivities was established and numerical simulations were conducted. The numerical simulation results indicate that the gas well with a diagenetic-artificial fracture network yields a higher production, the 10-year production is 35.01% higher than that with a structural-artificial fracture network. This study is of great significance for understanding the production differences of fractured tight sandstone gas reservoirs and provides valuable insights for selecting optimal well locations.

Optimization method of refracturing timing for old shale gas wells

Based on the elastic theory of porous media, embedded discrete fracture model and finite volume method, and considering the micro-seepage mechanism of shale gas, a fully coupled seepage-geomechanical model suitable for fractured shale gas reservoirs is established, the optimization method of refracturing timing is proposed, and the influencing factors of refracturing timing are analyzed based on the data from shale gas well in Fuling of Sichuan Basin. The results show that due to the depletion of formation pressure, the percentage of the maximum horizontal principal stress reversal area in the total area increases and then decreases with time. The closer the area is to the hydraulic fracture, the shorter the time for the peak of the stress reversal area percentage curve to appear, and the shorter the time for the final zero return (to the initial state). The optimum time of refracturing is affected by matrix permeability, initial stress difference and natural fracture approach angle. The larger the matrix permeability and initial stress difference is, the shorter the time for stress reversal area percentage curve to reach peak and return to the initial state, and the earlier the time to take refracturing measures. The larger the natural fracture approach angle is, the more difficult it is for stress reversal to occur near the fracture, and the earlier the optimum refracturing time is. The more likely the stress reversal occurs at the far end of the artificial fracture, the later the optimal time of refracturing is. Reservoirs with low matrix permeability have a rapid decrease in single well productivity. To ensure economic efficiency, measures such as shut-in or gas injection can be taken to restore the stress, and refracturing can be implemented in advance.

Challenges of formation damage control technology for ultra-deep tight gas reservoirs: A case study from Tarim Basin

Formation damage mechanisms and the corresponding control technology for the tight gas reservoirs have been reported, whereas few studies have discussed ultra-deep fractured tight gas reservoirs. Ultra-deep fractured tight gas reservoirs were susceptible to be damaged owing to geological conditions and engineering status. Taking the ultra-deep fractured tight gas reservoirs located in the Tarim Basin as an example, ultra-tight, high-pressure, high temperature (HPHT), and high-salinity formation water, ultra-low water saturation and fracture networks were identified as special geological characteristics. High-density oil-based drill-in fluids and serious lost circulation were the special engineering status. Challenges in laboratory experiments to evaluate formation damage include rigorous experimental conditions and unsuitable experimental methods. In addition, improving the formation protection ability of working fluids and minimizing the formation damage induced by the sequential use of different types of working fluids were the main challenges associated with using working fluids. Challenges in lost circulation control include the failure of plugging zone due to the degradation of lost circulation materials and repeated lost circulation due to the strength reduction of the plugging zone soaked in diesel oil. Recommendations for key technologies to improve targeted formation damage control technology have been proposed. The comprehensive analysis of these issues provides a road-map for researching formation damage control technologies.

Cavitation‐Induced Shear Failure Mechanism of Fractured Plugging Zone and Structure Strengthening Method for Lost Circulation Control in High‐Temperature and High‐Pressure Fractured Gas Reservoirs

Cavitation‐Induced Shear Failure Mechanism of Fractured Plugging Zone and Structure Strengthening Method for Lost Circulation Control in High‐Temperature and High‐Pressure Fractured Gas Reservoirs

Productivity model for multi-fractured horizontal wells accounting for cross-scale flow of gas and total factor characteristics of fractures

Fractured horizontal wells are widely utilized to develop tight gas reservoirs. Accurate productivity prediction of horizontal wells intercepted by complex hydraulically induced fractures is highly challenging due to fracture branching, bending, extending, and reversing in tight rock formations. Accounting for complex tree-shaped fracture geometries in reservoirs, this study proposes a cross-scale model of gas flows from the matrix to fractures. Using the proposed framework, the well productivity can be calculated in fractured gas reservoirs with any pore size and a fracture-controlled unit. The novelty of this study is that the total factor characteristics of fractures (i.e., length ratio a, width ratio b, branching angle θ, and branching level n), pressure drop coupling between the reservoir and fracture, and gas flow regime in different scale channels can be perfectly considered in the proposed model, from which the key contributions to well productivity are derived. Subsequently, the validity of the proposed cross-scale model is evaluated in comparison with the results of Ning et al. model and field well testing. The characteristic length L0,i, fracture effective width wf, stimulated reservoir volume Vf, fracture pressure pf, pressure gradient Gf, effective permeability kf and flow conductivity Cf of tree-shaped fractures are derived using the proposed model. The results show that the well productivity is jointly determined by Gf and Cf. Moreover, the well productivity mostly depends on a and n, and it is little influenced by b. In contrast, it is almost unaffected by θ. Compared to a straight fracture, a tree-shaped fracture with characteristic parameters of a=0.9 and n=3 can dramatically enhance the productivity by 32 % (b=0.5; θ=30°). In contrast, a tree-shaped fracture slightly increases the productivity by only 3 % when b increases from 0.1 to 0.9 (a=0.2; θ=30°; n=3). Furthermore, when θ is increased from 0° to 90°, the productivity of a well with a tree-shaped fracture decreases by 3 % (a=0.2; b=0.6; n=3). Hence, the study findings will contribute to the exploitation of tight gas reservoirs.

Clarify the effect of fracture propagation on force chains evolution of plugging zone in deep fractured tight gas reservoir based on photoelastic experiment

The mesoscale structural stability of plugging zone formed by lost circulation materials (LCMs) frequently dictates the effectiveness of wellbore strengthening operations in deep fractured reservoirs. To address the stability of these mesoscale structures, researchers have conducted extensive investigations encompassing the establishment of photoelastic experimental and coupled computational fluid dynamics with discrete element simulation methods, as well as the influence of LCMs' geometric shape and frictional properties. However, contemporary studies primarily focus on the overall structural evolution of plugging zone under static fracture tip boundaries, lacking a detailed characterization of the pressure-bearing evolution process of force chain structures within plugging zone fracture tip regions under dynamic fracture tip conditions. This study employs the photoelastic experimental technique to explore the development of force chains under shear in a photoelastic granular system with a dynamic fracture confining boundary. Additionally, it utilizes the average intensity gradient method to accurately describe the evolution of average contact force, the proportion of strong force chains, and the strong force chains geometric structure in each segment under a dynamic fracture confining boundary. The test results showed that the presence of a dynamic fracture boundary leads to both a reduction in the abundance of strong force chains proximal to the fracture tip and a simplification of their geometric architecture, subsequently impacting the stability of the plugging zone. Within the low-propagation fracture plugging zone, an escalation in the shear displacement is observed uniformly progressing with an increase in shear pressure, whereas the high-propagation fracture plugging zone demonstrates climactic fluctuations in shear pressure as shear displacement intensifies. The peak shear strength of force chains within the low-propagation fracture reaches 20 MPa, a value 2.2 times higher than that of the high-propagation fracture boundary plugging zone. The ratio of strong force chains within low-propagation fracture exhibits a consistent increment from 10.5% to 13.3% in response to the ascension of shear displacement. On achieving the maximum shear displacement, this ratio in the front-middle-rear segmentations of the plugging zone reaches 14.6%, 14.7%, and 10.5%, respectively. Notably, within the high-propagation fracture, the proportion displays a fluctuating decline from 11.2% to 7.7%. At the pinnacle of shear displacement, the proportion of strong force chains in the front, middle, and rear divisions of the plugging zone are 7.6%, 7.8% and 7.7% respectively. Adjacent to the low-propagation fracture, strong force chains intermittently gather around the shear zone within the plugging area. Here, they gradually configure into staggered arrangements that eventually fuse into a densely packed, high-luminosity network resembling the structure of a fishbone. Conversely, within the high-propagation fracture regions, strong force chains transition from isolated to offset formations, leading to a persistently disrupted sparsely chain-like structure. This study provides theoretical basis for the wellbore strengthening in fracture propagation deep fractured tight gas reservoir.