Abstract This study addresses limitations of traditional temporary plugging models that neglect combined in-fracture and mouth-plugging effects. A USDFLD subroutine in ABAQUS simulates multi-stage plugging based on injection timing. Using the maximum circumferential stress criterion and cohesive zone model (CZM), a mechanical model for fracture propagation in tight reservoirs was established. Numerical simulations analyzed ground stress, fracture initiation, propagation, and morphology across plugging stages. Results show that temporary plugging significantly alters in-situ stress magnitude and direction, creating a weak stress point near the plugging location. The study clarifies formation conditions of main and branch fractures under real reservoir conditions. However, multi-stage plugging struggles to achieve effective results under high sHmax (7–8 MPa). By unraveling the mechanisms of complex fracture propagation, this work delivers actionable insights that directly inform the design and optimization of fracturing strategies in tight oil reservoirs.

Temporary plugging agents (TPAs) are essential for diverting fractures to enhance heat extraction from deep geothermal resources. While TPA transport and accumulation in fractures directly control plugging performance and fracture network development, most existing studies examine TPA bridging and stacking only under ambient conditions, overlooking thermal degradation effects at reservoir temperatures. This study addresses this gap by integrating high-temperature degradation experiments with numerical modeling. We developed a particle-scale thermal degradation model and incorporated it into a CFD-DEM framework to simulate coupled TPA transport, heat transfer, and degradation in artificial fractures. Our analysis reveals significant differences in degradation behavior based on injection timing, formation temperature, and particle-to-fracture-width ratio (D). Earlyinjected particles experience degradation rates 3-4 times higher than those injected later at the target location. Formation temperature strongly influences degradation kinetics: increasing temperature from 428.15 K to 478.15 K accelerates early-stage particle degradation from 7.83% to 31.28%, exhibiting nonlinear behavior. Notably, we identified a "one-third degradation criterion" where D =1/3 minimizes degradation rate, attributed to the interplay between particle packing density and heat transfer efficiency. Based on these insights, we developed a semi-empirical model using the Stefan number and D ratio to predict early-stage particle degradation rates. The model achieves an average prediction error of 3.62%, providing a practical tool for optimizing TPA selection and operational parameters in enhanced geothermal systems. This work advances understanding of TPA behavior under reservoir conditions and offers quantitative guidance for improving temporary plugging and diverting fracturing operations.

Non-conforming grids provide an efficient framework for simulating complex fracture networks in hot dry rock (HDR) reservoirs. However, their application to thermal-hydraulic-mechanical-chemical (THMC) coupling remains limited by the difficulty of representing multi-field interactions within reduced-dimensional fractures and by the loose coupling among physical fields. To address these issues, a fully coupled THMC model based on a non-conforming grid framework is developed, integrating the embedded discrete fracture model (EDFM) and the extended finite element method (XFEM). The model enables multi-mineral water-rock reactions and accounts for THMC interactions through both property-parameter coupling and differential-term coupling. In particular, a novel method is presented to characterize the multi-field coupling inside the reduced-dimensional fractures within the non-conforming grid framework. Through explicitly incorporating fracture aperture evolution and fracture-wall contact forces in reduced-dimensional fractures, this method accurately captures the combined effects of contact stress, shear dilation, and mineral dissolution/precipitation on fracture permeability. After verification, the proposed model is applied to a typical HDR reservoir to simulate heat extraction over a period of 25 years. The spatiotemporal evolution of physical fields, variations in fracture properties, and wellhead response characteristics are analyzed. The results demonstrate that the proposed model can effectively capture fracture-dominated THMC coupling processes and long-term performance in HDR reservoirs.

China holds abundant deep reservoirs, where temporary plugging and diversion fracturing (TPDF) is a key technology for efficient development. Effective transport and plugging of agents (TPAs) within fractures to boost net pressure are key to the success of this technology. Moreover, optimising the transport parameters can provide practical data support for field operations. While numerical simulation is an important optimization tool, it often yields single-point parameter solutions and requires lengthy computation, limiting its real-time applicability. In contrast, surrogate modelling enables fast target prediction and enhances optimization efficiency. Among various multi-objective optimization algorithms, the non-dominated sorting genetic algorithm II (NSGA-II) demonstrates strong performance in both speed and convergence. In this study, a temporal convolutional network (TCN) was ultimately selected to construct the surrogate model for rapid prediction, which was coupled with NSGA-II for optimization. The main findings are: (1) The TCN model achieved prediction errors below 5%, with transport pattern predictions showing over 80% agreement with simulations; (2) Cost was highly sensitive to the mass concentration of TPAs and injection velocity, minimising cost reduced their optimal ranges; (3) The mass concentration had little influence on most objectives except cost, resulting in minimal variation in its optimal range across different criteria; (4) Injection velocity strongly influenced the dimensionless average velocity of TPAs, minimising it required lower injection velocity; (5) Carrying liquid viscosity significantly impacted dimensionless inlet pressure, leading to higher optimal ranges when high dimensionless inlet pressure was desired.

China possesses abundant deep oil and gas resources; however, their exploitation is constrained by high-temperature, high-pressure conditions and the limitations of conventional hydraulic fracturing in creating complex fracture networks. Temporary Plugging and Diverting Fracturing (TPDF), which induces fracture diversion and generates multiple new fractures, represents a promising technology for the development of deep reservoirs. In TPDF, the migration of temporary plugging agents into fractures to form effective blockages and elevate fracture net pressure is critical. Understanding their migration behavior in deep, high-temperature rock fractures is therefore essential. Numerical simulation provides a valuable means for investigating this migration process. However, fracture models are often simplified as rectangles, and most numerical approaches rely on Discrete Element Models (DEM), which are computationally complex and time-intensive. In this study, a multiphase flow mathematical model for temporary plugging agent migration in deep wedge-shaped rock fractures is developed based on the Dense Discrete Phase Model (DDPM). The model is employed to numerically examine the effects of key parameters—including mass concentration of plugging agents, injection rate, carrying liquid viscosity, and wall temperature—on migration behavior under high-temperature conditions. The results show that the sensitivity of these parameters to migration behavior, from highest to lowest, follows the order: injection rate > carrying liquid viscosity > mass concentration > wall temperature. Increases in mass concentration and wall temperature maintain a triangular migration pattern, whereas increases in injection rate and carrying liquid viscosity alter the pattern from triangular to quadrilateral. Raising injection rate or carrying liquid viscosity individually shifts the dominant mechanism from sedimentation to collision and migration. A critical mass concentration of 6% is identified, beyond which further increases exert minimal influence on subsequent fracture sealing. For TPDF operations in deep reservoirs, factors such as reservoir rock properties and pumping procedures should guide the selection of carrying liquid viscosity and injection rate. As formation temperature increases, the likelihood of plugging agent sedimentation rises due to reduced carrying liquid viscosity. Moreover, the agents experience lower heat exchange than the carrying liquid, resulting in a slower temperature rise for the agents compared with the fluid.

Due to the strong heterogeneity commonly observed in carbonate geothermal reservoirs, conventional matrix acidizing techniques often yield suboptimal stimulation results. To address this issue, this study proposes an alternating thermal loading synergistic acidizing technique to enhance the matrix acidizing performance of carbonate reservoirs. To elucidate the improvement mechanism under this technique, spontaneous imbibition and conductivity monitoring experiments were conducted to quantitatively characterize the evolution of pore structure and fluid migration behavior in rock samples. The results indicate that alternating thermal loading significantly enhances the acidizing effect, increasing the unit-area imbibition mass of the core by 16 %, while porosity and permeability are improved by 3.7 and 2.3 times, respectively. Conductivity monitoring of the imbibition solution further reveals that thermal cycling markedly accelerates the diffusion rate of mineral ions from the rock matrix into the solution. This study confirms the synergistic enhancement mechanism between cyclic thermal stress and acid dissolution, providing a new approach and technical pathway for the efficient stimulation of highly heterogeneous geothermal reservoirs.

Hydraulic fracturing is a critical technique for the efficient development of hot dry rock (HDR) geothermal resources. However, HDR formations are typically deeply buried and exhibit low permeability and pronounced elastoplastic behavior. As a result, conventional hydraulic fracturing often produces relatively simple artificial fracture networks, which limit heat extraction efficiency. To overcome this constraint, this study introduced alternating temperature loading to the rock matrix by combining high-temperature heating with rapid liquid nitrogen cooling. This process generates cyclic thermal stresses that promote microcrack initiation and facilitate the development of more complex fracture networks. To investigate fracture propagation mechanisms in HDR under alternating temperature loading, a series of physical simulation experiments of hydraulic fracturing was conducted. The results show that alternating temperature loading substantially reduced both the breakdown pressure and fracture propagation pressure of HDR specimens. The most pronounced reductions occurred at 600 °C, where breakdown and fracture propagation pressures decreased by 53.4% and 23.3%, respectively, relative to the values measured at 25 °C. In addition, alternating temperature loading significantly shortened the wellbore pressurization period, allowing fractures to initiate earlier. The extent of plastic damage also increased markedly with temperature. Furthermore, alternating temperature loading accelerated the early development of microfractures within the rock. This process led to earlier abrupt changes in axial and radial strains and caused premature failure, accompanied by the formation of a larger number of fractures. These fractures were predominantly shear-driven and displayed greater geometric complexity. Microstructural observations further indicated that thermal stress weakened the bonding strength between minerals such as quartz and feldspar, producing thermally induced microcracks that enhanced fracture network complexity. Overall, this study provides both theoretical insight and practical guidance for increasing fracture network complexity in HDR reservoirs and improving geothermal heat extraction efficiency.

It is difficult to form an effective fracture network in deep shale fracturing. Explosive-hydraulic composite fracturing combines explosive fractures with hydraulic secondary fracturing. In this paper, a large-scale true triaxial hydraulic fracturing physical simulation experiment using artificial specimens simulating deep shale was carried out. The size of the rock sample is 40 cm × 40 cm × 40 cm. During the experiments, the pump pressure curve and acoustic emission signal were synchronously monitored to investigate the influence of bedding-plane dip angle, number of initial explosive fractures, and in situ stress difference on the fracture propagation behavior in explosion–hydraulic composite fracturing. The experimental results demonstrate that the integrated acoustic emission and pump pressure monitoring data can effectively capture the initiation and propagation processes of explosion–hydraulic fractures. A bedding-plane dip angle of 30° facilitates enhanced connectivity between the explosive and hydraulic fractures. An increase in the number of initial explosive fractures positively contributes to the activation of bedding planes; however, the associated stress interference among competing fractures is concomitantly amplified. As the number of initial explosive fractures increases from three to five, the total fracture length is reduced by 27.15

In deep hot dry rock formations, the widespread occurrence of natural fractures significantly affects the deformation and failure behaviors of the rock mass. While previous research has primarily focused on the mechanical behavior of intact rock under high-temperature and high-pressure conditions, the underlying mechanisms of elastic–plastic deformation and failure in hot dry rock containing preexisting fractures remain insufficiently investigated. This study provides an in-depth analysis of the elastic–plastic deformation and failure characteristics of hot dry rock with prefabricated fractures under high-temperature and high-pressure environments. The research employs advanced experimental techniques, including pore-permeability analysis, thermal conductivity measurement, spontaneous imbibition, and high-temperature, high-pressure triaxial compression testing, complemented by methods such as computed tomography scanning, ultrasonic velocity monitoring, and nuclear magnetic resonance. The results indicate that the presence of preexisting fractures reduces the overall strength of the rock, but compressive strength increases as the fracture inclination angle increases. The rock's elastic–plastic deformation capacity also increases with the dip angle. Energy analysis reveals that, although the total energy, elastic strain energy, and dissipated energy of fractured rocks are lower than those of intact rocks, all three parameters show an increasing trend with higher fracture inclination. In terms of damage factors, the weakening effect of prefabricated fractures on the rock diminishes as the fracture dip angle increases. Regarding failure modes, rocks with prefabricated fractures predominantly exhibit splitting failure. These findings enhance the theoretical understanding of the elastic–plastic deformation and failure behaviors of hot dry rock with preexisting fractures under high-temperature and high-pressure conditions.

As a sustainable and renewable energy source, geothermal energy holds significant potential for addressing global energy demands and mitigating climate change. However, the development of geothermal resources involves complex interactions among temperature, fluid flow, stress, and chemistry, collectively known as thermal-hydraulic-mechanical-chemical multiphysics coupling. This work aims to provide a comprehensive overview of such a coupling simulation in geothermal energy development, encompassing theoretical frameworks, numerical models, and practical applications. By integrating insights from various disciplines, this perspective contributes to advancing the understanding and optimization of geothermal energy extraction processes.

Hydraulic fracturing technology is key to achieving efficient heat extraction from hot dry rock (HDR). During the fracturing process, the injection of large volumes of cold fluids induces thermal stresses, significantly affecting the physical properties of the rock, as well as its deformation and failure mechanisms. In this study, based on the principle of "thermal expansion and contraction," we simulate the alternating thermal load environment induced by high-temperature steam and low-temperature liquid nitrogen injection. Our aim is to enhance internal damage in HDR through cyclic thermal stresses, thereby increasing the complexity of fracture networks. However, research on the elastoplastic deformation and failure mechanisms of HDR under alternating thermal loading remains insufficient. In this study, we use a high-temperature, high-pressure triaxial compression system combined with permeability and porosity measurements, along with advanced techniques such as ultrasonic velocity monitoring, computed tomography (CT) scanning, and nuclear magnetic resonance (NMR) imaging, to systematically investigate the elastoplastic deformation behavior and damage mechanisms of deep reservoir rocks under alternating thermal loading. By comparing these results with those from single thermal treatment experiments, we comprehensively analyze the changes in permeability, porosity, and rock mechanical parameters under alternating thermal loading. The experimental results show that the temperature differences induced by alternating thermal loading promote the formation of numerous thermally induced cracks in HDR, thereby weakening its mechanical strength and stiffness. According to the Mohr-Coulomb criterion, alternating thermal loading reduces the cohesion of the rock while increasing the internal friction angle, which enhances its elastoplastic deformation characteristics. By comparing rock failure patterns, CT scan images, and incorporating the Hoek-Brown and Griffith criteria, we reveal the nonlinear elastoplastic deformation and failure characteristics of rocks under alternating thermal loading. Under alternating thermal loading, the fracture network becomes more complex, with shear-type plastic failure being predominant. Furthermore, we validated mechanical testing results using ultrasonic velocity and NMR techniques. Energy dissipation analysis and damage factor calculations indicate that the level of damage and failure under alternating thermal loading is more than twice that of a single thermal treatment. In conclusion, this study provides valuable experimental data and theoretical guidance for understanding the thermomechanical behavior of HDR under alternating thermal loading. The findings are of significant importance for the field application of high-temperature steam and low-temperature liquid nitrogen cyclic injection, especially in the efficient development and usage of HDR geothermal energy.

Temporary plugging and diversion fracturing technology plays a critical role in improving the efficiency of deep geothermal resource extraction, particularly in hot dry rock formations, which are predominantly composed of granite. However, due to the deep burial, high temperatures, and high-stress conditions of hot dry rock, existing research has largely overlooked the mechanics of artificial fracture propagation during temporary plugging and diverting fracturing under high-temperature conditions. This study addresses this gap by using a true triaxial hydraulic fracturing physical simulation test system to investigate the impacts of temperature and stress on the temporary plugging and diverting fracturing of granite. The experiments revealed the variation patterns of two-stage breakdown pressure and the mechanisms of fracture diversion and propagation in granite under high-temperature conditions. Key findings indicate the existence of a critical stress difference for fracture diversion, where artificial fractures in granite will redirect and propagate if the local stress difference falls below this threshold. Additionally, the breakdown pressure decreases as temperature rises but increases with greater horizontal stress differences. The frequency of pressure fluctuations during injection also rises with temperature, suggesting that higher temperatures prolong the sealing effect of the temporary plugging agent. The data show that when the horizontal stress difference increases by 10 MPa at 25 degrees C, the injection pressures during the first-stage water fracturing and second-stage temporary plugging fracturing increase by 56.9% and 90.2%, respectively. At a 2.5-MPa horizontal stress difference, the angle between the fractures created in the first and second stages is largest, approaching 90 deg. Under constant stress, higher temperatures lead to larger diversion angles, indicating that higher temperatures promote the development of more complex fracture networks in hot dry rock. These findings offer valuable theoretical insights and practical guidance for optimizing hydraulic fracturing techniques and enhancing the efficient development of deep geothermal resources.

Supercritical CO2 (SC-CO2) fracturing technology is a key approach for enhancing production and achieving carbon neutralization in tight oil reservoirs. Current SC-CO2 fracturing models primarily focus on the effect of CO2 fracturing fluids on fracture propagation, often overlooking the mechanisms by which CO2 impacts tight oil recovery during shut-in, production, and storage stages. To address this gap, this study develops an integrated model for SC-CO2 fracturing, shut-in, and storage in tight oil reservoirs based on a stress-seepage fluid-solid coupling finite element method. The model systematically determines the mechanisms underlying CO2 fracturing stimulation and storage, as well as their contributions to production, quantified through weight coefficients. This forms the basis of an integrated technology for CO2 fracturing and enhanced oil recovery in tight oil reservoirs. Key factors such as horizontal stress difference, natural fracture distribution, CO(2 )injection volume and rate, and shut-in duration were evaluated through numerical simulation to analyze their effects on crude oil production and CO2 storage. The results are as follows: (1) During CO2 fracturing, horizontal stress difference is the primary factor influencing the complexity and geometry of the fracture network. A smaller horizontal stress difference promotes the formation of a complex fracture network. Additionally, a critical reservoir Young's modulus exists, which optimizes the fracture network morphology for CO2 fracturing. (2) During shut-in, higher permeability and porosity enhance CO(2 )imbibition into the formation. Shut-in also allows sufficient time for ion exchange between the reservoir and CO2, which expands the CO2 huff-and-puff area. As crude oil comes into contact with CO2, it undergoes partial expansion and extraction, facilitating production with free CO2. (3) In the production phase, CO2 stimulates recovery through two key processes. First, CO2 dissolves into crude oil, causing expansion and extraction, which enhances recovery as crude oil is produced alongside free CO2. Second, dissolved CO2 separates from crude oil as pressure decreases during production, forming a dissolved gas drive mechanism. (4) Reservoir permeability, porosity, CO2 injection volume, and injection rate are positively correlated with both crude oil production and CO2 storage. Moreover, there exists an optimal shut-in duration that maximizes crude oil recovery and CO2 storage. The findings of this study provide critical technical and theoretical support for significantly improving recovery rates in tight oil reservoirs in China.

Hydraulic fracturing is a crucial technique for the extraction of geothermal energy from hot dry rock reservoirs. However, the development of such reservoirs faces significant challenges due to the high in-situ stress and strong elastic-plastic behavior of these rocks, which often result in simplified fracture geometries and subsequent low heat extraction efficiency. To address this issue, a novel reservoir treatment method based on thermal expansion and contraction principles is proposed. By applying alternating heating-cooling treatments to the reservoir, cyclic thermal stress is generated within the rock to enhance the complexity of post-fracturing fracture networks. To investigate the resultant hydraulic fracture propagation under alternate-temperature loading, a custom- developed thick-walled cylinder expansion fracturing device was employed to study the fracture propagation mechanisms in hot dry rock samples under cyclic thermal loading. The fracture network complexity was characterized by the fractal dimension method. Experimental results demonstrated that alternate thermal load cycling significantly enhances the fracture network complexity compared to conventional single-phase heat treatment. The maximum improvement in fractal dimension (3.86% increase) was observed at 500 degrees C. Under alternating temperature loads, the upper surface fractures predominantly exhibited bilateral symmetric structures. At 600 degrees C, a substantial increase in branched fractures and rock debris near boreholes occurred, indicating that alternating temperature loads significantly enhance the complexity of engineered fracture networks in hot dry rock. These findings suggest that incorporating thermal cycling into hydraulic fracturing processes can significantly improve the fracture network complexity, thereby enhancing the efficiency of heat extraction from hot dry rock reservoirs.

The heterogeneity of the pore size distribution and predominance of nanopores in shale reservoirs are one of the primary reasons for reduced storage and flow after hydraulic fracturing. Underground hydrogen storage capacity is influenced by the availability of micropores and mesopores, which are not sufficiently interconnected to facilitate effective flow. Besides, shale reservoirs experience changes in their properties at different scales which affects storage, flow and production of gas. A model with multiscale domains is crucial to gain an in-depth understanding of the sorption behavior and the interconnection between the matrix and fracture. Using finite element method, an improved storage and flow model is conducted to simulate the storage, flow, and recovery mechanism of hydrogen across various scales of the shale reservoir based on field data from Chang 7 shale member, Ordos Basin. Multiple layers increase overall storage capacity by providing additional sorption sites in the inter-layer spaces and tree-like hydraulic fractures break the complexity of network pathways by connecting the matrix network to the production well. Specifically, as temperature increases, dissolved gas transforms into adsorbed gas which later becomes free gas with further increase in temperature. This reduces the storage capacity but improves the flowability of gas which then migrates through the interconnected inorganic matrix, natural crack, tree-like hydraulic fracture, and production well. Tree-like fractures enhance permeability by increasing the contact area, which ultimately improves gas flow and production efficiency. Increasing the width of the fracture, stress sensitivity coefficient, and fracture compressibility drastically reduces the production capacity of the gas reservoir due to the likelihood of fracture closure. This research provides a theoretical framework and reference for storage and production evaluation of hydrogen in depleted shale reservoirs.

Hot dry rock (HDR) is a resource-rich, renewable, and clean energy source characterized by its great depth, high temperature, and high geostress. In underground environments, rocks are prone to significant elastoplastic deformation. However, research on the elastoplastic deformation, failure, and fracture mechanisms of HDR under high-temperature conditions remains limited. This study employs Acoustic Emission (AE) and Digital Image Correlation (DIC) as combined monitoring methods to conduct fracture toughness experiments on granite semicircular bend (SCB) specimens under high-temperature conditions. We obtained load-displacement curves, AE parameters, and strain fields near crack tips at various temperatures to reveal the mechanical mechanisms of elastic-plastic failure evolution in HDR. Experimental results indicate that both the peak load and fracture toughness of granite specimens decrease gradually with increasing temperature, with the peak load at 600 degrees C being 69.1 % lower than at 25 degrees C. DIC results show that the fracture process zone at the crack tip enlarges with rising temperature, while strain and crack width values decrease. Additionally, the attenuation of AE b-values at peak load relative to the initial loading phase increases, and the proportion of shear failure increases, with a maximum increase of up to 42.3 %. As temperature rises, the failure mechanism of artificial fractures transitions from brittle macroscopic fractures to plastic fine fractures. When the temperature exceeds 400 degrees C, plastic failure becomes more pronounced, with numerous microcracks forming and further coalescing into complex main cracks. This study provides important theoretical support for the efficient development of deep geothermal resources.

CO2 miscible flooding provides dual advantages in enhancing oil recovery and facilitating geological sequestration, and has become a key technical approach for developing low-permeability oil reservoirs and carbon emission reduction. The pore-scale flow mechanisms governing CO2 behavior during miscible flooding are crucial for achieving efficient oil recovery and secure geological storage of CO2. In this study, pore-scale two-phase flow simulations of CO2 miscible flooding in porous media are performed using a coupled laminar-flow and diluted-species-transport framework. The model captures the effects of diffusion, concentration distribution, and pore structure on the behavior of CO2 miscible displacement. The results indicate that: (1) during miscible flooding, CO2 preferentially displaces oil in larger pore throats and subsequently invades smaller throats, significantly improving the mobilization of oil trapped in small pores; (2) increasing the injection velocity accelerates the displacement front and improves oil utilization in dead-end and trailing regions, but a “velocity saturation effect” is observed—when the inject velocity exceeds 0.02 m/s, the displacement pattern stabilizes and further gains in ultimate recovery become limited; (3) higher injected CO2 concentration accelerates CO2 accumulation within the pores, enlarges the miscible sweep area, promotes a more uniform concentration field, leads to a smoother displacement front, and reduces high-gradient regions, thereby suppressing local instabilities, and improves displacement efficiency, although its effect on overall recovery remains modest; (4) CO2 dynamic viscosity strongly influences flow stability: low-viscosity conditions promote viscous fingering and severe local bypassing, whereas higher viscosity stabilizes flow but increases injection pressure drop and energy consumption, indicating a necessary trade-off between flow stability and operational efficiency.

In hydraulic fracturing in fractured reservoirs, the internal properties (orientation, spacing, length, and persistence of pre-existing crossed natural fractures) of natural fractures and fluid injection rate may induce the intersections of hydraulic fracture network and further affect the gas production. The purpose of this study focuses on the intersections of hydraulic fracture network under varying small-scale crossed natural fractures and fluid injection rate, and detect the relationship between fracture morphology and gas production. Using the discrete fracture network model, the numerical analysis for center- and edge-type intersections of hydraulic fracture network under varying crossed natural fractures and fluid injection rate is implemented. By varying the level of sensitivity factors, the combined finite element-discrete element method is used, and some typical cases are established to investigate the effects of above sensitivity factor (orientation, spacing, length, and persistence of pre-existing crossed natural fractures and fluid injection rate) on the hydraulic fracture propagation. There are center- and edge-type intersections of fracture network morphologies under varying crossed natural fractures and fluid injection rate. The hydraulic fracture can intersect with the edge of the natural fracture and lead to edge-type propagation, which is conducive for the fracture propagating toward the area farther away from the perforation; in edge-type propagation, when the approach angle between hydraulic fractures and natural fractures is small enough, the hydraulic fractures will be reoriented and activate the natural fractures. The center-type propagation is the result of the intersection of hydraulic fractures and crossed clusters of natural fractures, and the hydraulic fracture may intersect with the natural fracture cluster to form a center-type propagation. Compared with large-scale natural fractures, the small-scale and aggregated center- and edge-type intersections of fracture network morphologies are formed in this study; small-scale natural fractures are more sensitive to the propagation behavior and final propagation morphology of hydraulic fractures, and are more sensitive to the change of fluid injection rate. The length of fractures during the fracturing process is positively correlated with gas production, to quantitatively obtain the relationship, the fitting curve is derived. For the sensitivity factors (orientation, spacing, length, and persistence) of natural fractures and fluid injection rate, the formed center-type intersections of hydraulic fracture network may generate long fracture length, which is prone to improving gas production; when the hydraulic fracturing scheme is designed, it is crucial to actively promote the center-type intersections of hydraulic fracture network based on the morphology of natural fractures. When small-scale natural fractures form small-scale and aggregated center- and edge-type intersections of fracture network, the increased fractures gather together to form the clustered low-pressure area and will not continue to increase gas production; the small-scale and aggregated fractures that may play a redundant or even negative role in improving gas production are formed. The provided results of center- and edge-type intersections of hydraulic fracture network under varying crossed natural fractures and fluid injection rate can provide reference for the optimized design of hydraulic fracturing scheme for unconventional gas production in fractured reservoirs.

The existing reservoir in the Yongjin block exhibits an extremely low matrix permeability, posing challenges in precisely evaluating the damage caused by fracturing fluid using traditional core flow experimental methods. Currently, there is no established quantitative method for characterizing the degree of damage. In this study, we integrated online nuclear magnetic resonance, microscopic computed tomography, and core displacement experimental techniques, pioneering a novel approach to evaluate damage in deep tight oil reservoirs subjected to hydraulic fracturing. We analyzed the influence patterns of key factors such as backflow pressure differential, shut-in time, invasion volume, and residual retention on rock matrix damage in the operational area. The study unveiled the mechanisms behind water sensitivity, water block, and fracturing fluid retention damage among oil, water, and rock. The results indicate that water sensitivity damage is less than 20%, primarily occurring within large pores. Water block damage can significantly reduce the residual oil permeability. Experimental findings suggest that optimizing liquid backflow with a pressure differential and well shut-in time set at 5 MPa and 9 days can markedly reduce the intrusion volume of gel-breaking fluid, restoring the residual oil permeability. Under high-pressure differential conditions, residual fracturing fluid can infiltrate the rock matrix, resulting in pore damage. Additionally, it can accumulate on the fracture surfaces, thereby reducing the permeability of microfractures.