To reveal the energy transfer mechanism of water injection and the dynamic response characteristics of pore pressure in tight sandstone reservoirs, and to clarify the influence of lithology, injection pressure, and injection method on the energy enhancement effect of water injection, a high-pressure energy injection and response testing system and nuclear magnetic resonance (NMR) testing technology were used to conduct systematic water injection energy enhancement experiments on three rock types: mudstone, sandstone, and naturally fractured sandstone. Combined with pressure dynamic monitoring and pore structure evolution analysis, the pressure response characteristics and energy enhancement mechanism of rock samples under different experimental conditions were explored. The experimental results showed that the NMR T2 distribution of the three rock samples exhibited bimodal characteristics, corresponding to small pores (pore size < 1000 nm) and large pores/microcracks (pore size > 1000 nm), respectively. There were significant lithological differences in the evolution of pore structure during water injection, with a cumulative decrease of 7.2% in the proportion of large pores in mudstone and an increase of 9.3% in the proportion of large pores in sandstone with natural fracture development. There is a positive correlation between injection pressure and the energy enhancement effect. Under an injection pressure of 40 MPa, the pressure increment at the outlet end of sandstone with natural fracture development reaches 8.06 MPa, and the energy enhancement effect is 24% higher than that under the 30 MPa working condition, while the mudstone only increases by 15%. The energy enhancement effect of intermittent water injection is significantly better than that of depleted water injection, and the energy enhancement effects of the three rock samples are increased by 18.6%, 12.0%, and 6.9%, respectively. Overall, sandstone with natural fractures has the best energy enhancement effect, followed by sandstone, and mudstone has the worst. The connectivity of pores and the degree of fracture development are the core factors that dominate the water injection energy enhancement effect and pressure transmission efficiency. The research results can provide reliable experimental basis and theoretical support for optimizing water injection development plans, improving energy efficiency, and dynamically regulating stress fields in tight sandstone reservoirs.

Tight reservoirs commonly exhibit low permeability and pronounced lithological heterogeneity, resulting in complex interactions among far-field stress, local structural weakness, and fluid-driven fracture propagation. In this study, four non-replicated 2 m × 2 m × 1 m physical-model specimens representing tight glutenite, tight sandstone, and No. 3 coal rock from the Huabei Oilfield were investigated using an ultra-large true-triaxial hydraulic-fracturing system. Surface-fracture observations, microseismic monitoring, and high-frequency wellhead-pressure measurements were integrated to compare fracture responses under lithology-specific combinations of injection rate, fluid viscosity, perforation configuration, and stress state. The tested glutenite cases exhibited branched or localized fracture patterns depending on the combined treatment configuration; the sandstone case was dominated by a throughgoing main fracture approximately aligned with the principal-stress direction; and the coal-rock case showed extensive participation of bedding and cleat systems. These morphological differences were accompanied by distinct pressure and microseismic signatures, indicating different pathways of hydraulic-energy redistribution and fracture activation. For the two glutenite cases, the combined change from a single-perforation configuration at 0.5 m3/min to three helical perforations at 120° and 0.7 m3/min was associated with a 42.2% larger microseismic-derived stimulated reservoir volume (SRV). Taken together, these responses indicate a shift from stronger far-field-stress-controlled localization in the comparatively uniform sandstone to progressively greater local structural control by heterogeneous interfaces in glutenite and by bedding/cleat discontinuities in coal rock. Because each configuration was represented by a single specimen and several experimental variables changed simultaneously among cases, the observed differences are interpreted as case-specific mechanistic trends rather than statistically established universal relationships. The results show the value of combining fracture morphology, microseismic spatial evolution, and pressure dynamics for interpreting lithology-dependent fracture propagation in ultra-large physical models and for developing qualitative, lithology-adapted hydraulic-fracturing concepts.

During the energy storage fracturing process of tight sandstone reservoirs, the pre-injection of fracturing fluid is used to supplement the formation energy, and the physical properties of rocks change under hydration. To reveal the damage mechanism of hydration on tight sandstone, the tight sandstone surrounding the Daqing Changyuan in the northern part of the Songliao Basin was taken as the research object. Through indoor static hydration experiments, combined with scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), Nano-indentation experiments, and other methods, the evolution laws of rock micro-pore morphology, microfracture parameters, Young's modulus, hardness, and other mechanical indicators under different hydration durations and soaking pressures were systematically explored. The research results show that the water-rock interaction of acidic slick water fracturing fluid significantly changes the mineral composition and microstructure of mudstone and sandstone, controls the development of induced fractures, and degrades the micro-mechanical properties of rocks, with significant lithological differences. In terms of mineral evolution, the soaking time causes the clay minerals in mudstone to increase by up to 12.0%, while pressure causes the carbonate minerals in sandstone to decrease by up to 23.3%. In terms of induced fracture development, the induced fracture widths of sandstone and mudstone under 30 MPa of pressure increase by 122.4% and 85.7%, respectively. The fracture width of mudstone shows a trend of "increasing first and then decreasing" with time, while that of sandstone decreases monotonically. In terms of micro-mechanical properties, after soaking for 168 h, the Young's modulus of mudstone decreases by up to 66.9%, much higher than that of sandstone (29.5%), while the decrease in hardness of both is similar (58.3% and 59.8%); the mechanical parameters at the induced fractures are only 53.0% to 73.6% of those in the matrix area, confirming the influence of microstructural heterogeneity. This research provides a theoretical basis and data support for optimizing hydraulic fracturing parameters, evaluating wellbore stability, and predicting the long-term development performance in tight sandstone reservoirs.

The Jimusar shale reservoir exhibits extremely low permeability, classified as an ultra-low porosity and ultra-low permeability formation. Crude oil mobility is poor, and the reservoir demonstrates significant heterogeneity. Conventional horizontal well fracturing development fails to meet requirements, facing issues such as pronounced energy depletion in the formation, unclear oil-water distribution, and changes in formation stress direction. Based on the reservoir properties of the Jimusar shale oil reservoir, this paper establishes a fracture propagation model for horizontal wellbore hydraulic fracturing and a reservoir numerical model. It simulates the evolution of pressure fields, stress fields, and seepage fields at different time points during the fracturing and production phases of horizontal wells. Results indicate the following: (1) When fracturing fluid is injected into the formation, oil saturation around fractures rapidly decreases. During the initial production phase, oil saturation around fractures increases due to the recovery of some fracturing fluid and the sorption effect between fracturing fluid and crude oil. (2) Formation pressure around horizontal wells significantly increases upon fracturing fluid injection. The dual effects of fracture opening and fluid injection cause stress to rise near fractures. During production, both formation pressure and stress decrease near the wellbore, with greater pressure reduction in the near-wellbore zone than in the far-wellbore zone. However, formation stress decreases less near the wellbore due to stress concentration effects from fracture opening, resulting in a smaller reduction than in the far-wellbore zone. (3) The formation surrounding the fracture undergoes dual influences from fracture opening and fracturing fluid injection, causing deflection in the direction of near-wellbore stress. During the initial production phase, the impact of stress deflection gradually diminishes with ongoing production. However, after prolonged production, the deflection of formation stress intensifies. The conclusion states that this understanding clarifies the multi-field evolution patterns in fracturing production for horizontal well clusters, providing theoretical guidance for subsequent shale development processes.

This study aims to enhance the development effectiveness of infill wells in the strongly heterogeneous conglomerate reservoir of the Baikouquan Formation in the Bai 21 well area of the Junggar Basin. By optimizing the synergy between fracturing and waterflooding development, it provides a basis for improving the recovery rate of such reservoirs. Integrating geomechanical modeling, fracturing numerical simulation, and reservoir dynamic analysis, the influence mechanisms of fracturing parameters—including pumping rate, pad fluid ratio, and proppant intensity—on fracture propagation, waterflooding response, and stress field evolution were systematically investigated. The results indicate that an optimal parameter combination of a pumping rate of 3.5–4.0 m3/min, a pad fluid ratio of 40–50%, and a proppant intensity of 3.0–4.0 m3/m can create short, wide fractures with half-lengths of 40–45 m, effectively delaying water breakthrough and reducing inter-well interference. Stress field simulations further reveal non-uniform evolution during injection and production: the stress near injection wells initially increases and then decreases, dropping by 9.3% compared to the initial value, while the stress around production wells continuously decreases, with a reduction of up to 37.3%. These findings provide valuable guidance for the synergistic development of fracturing and waterflooding in infill wells in similar strongly heterogeneous conglomerate reservoirs.

Studies at hydraulic fracturing test sites (HFTSs) in North America and the Changqing oilfield, China, show that hydraulic fractures (HFs) commonly occur as closely spaced groups, or fracture swarms, with fracture numbers greatly exceeding perforation clusters. To investigate the formation mechanism and evolution of fracture swarms, continuous scratch testing and nanoindentation were used to characterize the mechanical heterogeneity associated with different lithologies, lithologic interfaces (LIs), and bedding planes (BPs). Hydraulic fracturing experiments were conducted on representative specimens from the Changqing HFTS using an improved small-scale true-triaxial system integrated with high-resolution CT scanning, high-frequency pressure monitoring, and acoustic emission (AE) monitoring. The results show that mechanical heterogeneity associated with LIs and BPs destabilizes cross-layer propagation of the main fracture and promotes fracture deflection, arrest, stepwise propagation, and secondary fracture re-initiation near weak planes, thereby favoring swarm development, whereas the homogeneous sandstone control specimen failed to generate such fracture patterns. When the interface contrast index Hi of a BP exceeds 0.1, the HF is more likely to be captured by the weak plane, which suppresses swarm development; when the Hi of an LI exceeds 0.1, local fracture deflection and secondary fracture re-initiation are more likely, whereas lower Hi favors direct crossing. Mechanistically, when weak planes satisfy the activation condition (Iact,i ≥ 1) but not the re-initiation condition (Ire,i < 1), fracture propagation is limited to local slip or minor deflection; when both conditions are satisfied (Iact,i ≥ 1 and Ire,i ≥ 1), secondary fractures are more likely to form and evolve into swarms. Main fractures exhibit larger apertures than secondary fractures, accompanied by alternating pressure peaks and troughs and AE signatures marked by increased event numbers, shear-event enrichment near weak planes, and sustained multipeak energy release. These findings provide new experimental insights into fracture swarm formation in shale reservoirs.

The bottom water of the Shizhouji Formation tight sandstone reservoir in the Tazhong Shun 9 well area is developed. General fracturing faces the problem of excessive extension of hydraulic fractures and easy communication with water layers. A true triaxial fracturing physical simulation experiment was conducted on the sandstone and mudstone outcrops of the same layer to explore the expansion laws of hydraulic fractures in the tight sandstone reservoir and consider the influence of mudstone interlayers, horizontal stress difference, fracturing fluid flow rate, and viscosity. The mechanism of multi-cluster fractures/artificial fractures penetrating through the layers was revealed. The research results show that the existence of mudstone interlayers greatly increases the complexity of fractures, from 1.88 to 2.96, an increase of 57%. When there is a mudstone interlayer in the rock, the fracturing process is prone to open weak planes, hindering the expansion of hydraulic fractures. The hydraulic fractures of Sample No. 4 were cut off four times and penetrated through the layers once. The larger the flow rate, the greater the complexity of hydraulic fractures, and the easier the fractures penetrate through the layers. The fractures with a large flow rate (200 mL/min) were cut off three times, and the stress difference was larger, the hydraulic fractures tended to be simple, and the penetration through the layers was zero times at a high-level stress difference (18 MPa); the greater the viscosity, the greater the fracture pressure, and the complexity of fractures first increased and then decreased; the greater the viscosity, the more easily the hydraulic fractures penetrate through the layers, with low viscosity cutting off three times, medium viscosity cutting off four times, and high viscosity cutting off five times. Therefore, considering the limitation requirements of the on-site fracturing on the extension of fracture height, it is recommended that the on-site fracturing construction flow rate be 6 m3/min, and the fracturing fluid viscosity be 10 mPa & centerdot;s.

A critical strategy for shale reservoir development is the comprehensive reservoir evaluation and the fine division of fracturing grades. However, the diversity of evaluation parameters limits hydraulic fracturing optimization. Therefore, we propose an adaptive-category-gaussian-mixture-model (AC-GMM) based on a geology engineering framework, combining reservoir quality (RQ) and completion quality (CQ) to classify the composite quality index (CQI). The classification serves as the basis for an intelligent algorithm developed for fracturing design. Taking three typical wells from the Lucaogou Formation in the Junggar Basin in China as examples the following research results are summarized. First, the AC-GMM model can finely identify the fracturing grades, achieving a conformity rate of over 90 % with the field production data. Second, the paper obtains three types of fracturing grades (I, II, III) and further refines them into four grades (I, II1, II2, III), the grade I considers both high RQ and CQ, while grade II only regards the better of the double quality, and prioritizes the better CQ. Third, the intelligent algorithm groups similar qualities into the same stage, achieving up to 96 % intra-stage homogeneity, significantly enhancing hydraulic fracturing efficiency for long horizontal wells. Our work provides a data-driven framework for optimizing multi-stage fracturing designs in shale reservoirs.

During heavy oil thermal recovery processes, hydraulic fracturing is an effective method for optimizing steam injection efficiency. However, the fractures created by the fracturing operation may connect with high-water saturation zones, forming high-temperature fracture-induced water channeling pathways. This not only increases water production in the wells but also significantly reduces oil and gas production, negatively affecting development efficiency. Gel-based plugging agents are commonly employed to effectively block these water channeling pathways. However, traditional polymer gels exhibit instability under high-temperature conditions, resulting in leakage and diminished plugging performance. In this study, a high-temperature-resistant copolymer gel suitable for 150°C environments was developed, and its gelation performance, thermal stability, and plugging effectiveness were systematically evaluated. The experimental results indicate that the gelation time of the copolymer gel at 150°C is 10 hours, with the post-gelation viscosity reaching 3483 mPa·s. After 30 days of aging at 150°C, the gel maintained a high viscosity, and its micro-network structure remained stable at approximately 100 μm. In core fracture plugging experiments, the plugging efficiency reached 96.2%. Furthermore, numerical simulations of heavy oil thermal recovery fracture plugging, based on laboratory experimental data, further validated the excellent plugging performance of the copolymer gel under high-temperature conditions. The gel effectively plugs fracture-induced water channeling pathways, reduces the water cut at the production well, and increases oil and gas production, providing strong technical support for the efficient development of heavy oil thermal recovery.

This study proposes a novel method to investigate the effects of friction reducers on the microstructure and permeability of gas shale, using the Longmaxi formation as a case study. By combining high-pressure mercury injection (HPMI) data, the pore size distributions (PSDs) and permeability of gas shale sample were derived from low-field nuclear magnetic resonance (NMR) T2 spectra under various immersion time conditions. The results demonstrate that this method effectively illustrates the impact of friction reducer on gas shale microstructure across different immersion durations. The proportions of both micro- and macro-pores increase initially, then decrease, and eventually stabilize, peaking at 1 day. Meso-pores follow a different trend, with the maximum occurring at 5 days. Permeability trends correspond with micro- and macro- pore changes, and the permeability ratio remains above 1.0, confirming enhanced permeability. These findings provide insight into optimizing friction reducer formulations and improving shale gas extraction efficiency.

Aiming at unclear imbibition replacement mechanisms and flowback/production strategies in unconventional reservoirs of the Erlian Block, this study proposes a systematic approach integrating “imbibition-flowback-productivity synergy” to optimize post-fracturing shut-in and production regimes. By developing numerical models incorporating geological and engineering factors, we analyzed fluid dynamics during both the shut-in and production phases. Concurrently, crude oil displacement-fracturing fluid imbibition replacement experiments were conducted to guide parameter optimization. The results indicate that optimized shut-in time and production rates substantially increase recovery efficiency while mitigating reservoir damage and proppant flowback. The well shut-in time of the Erlian Block can achieve the optimal shut-in replacement effect in about 20–25 days. The optimized flowback rate of the unconventional reservoir in the Erlian Block is 25–30 m3/d. The findings offer theoretical insights and practical recommendations for the efficient development of unconventional resources.

An integrated non-planar three-dimensional (3D) fracture propagation and proppant transport model is developed, capable of simulating key physical behaviors in heterogeneous in situ stress fields, including fracture propagation, deflection, intersection, coalescence, and proppant transport, settling, and bridging. After validating the model reliability with true triaxial hydraulic fracturing laboratory experiments and numerical simulations of non-planar fracture propagation, the proposed model is employed to analyze the impact of in situ stress field heterogeneity on fracture initiation and propagation pressures, non-planar propagation paths, fracture width, and proppant concentration distribution. The simulation results indicate that the principal stress orientation determines the final propagation direction of hydraulic fractures, while the horizontal stress difference affects the curving length required for non-planar fracture reorientation. Stress interactions induced by multi-fracture propagations not only lead to uneven growth but also non-planar geometries, as hydraulic fractures preferentially propagate along the paths of minimal energy dissipation. Proppant distribution is primarily governed by fracture geometry and width, with proppant concentrated near the wellbore where fracture width is greater. Deflected in situ stress fields promote non-planar fracture propagation, as well as intersection and merging, with larger stress deviation angles accelerating fracture deflection and coalescence. The sudden width variations and slurry convergence at fracture intersecting points significantly raise proppant concentration, potentially leading to premature proppant screen-out. Inter-cluster stress heterogeneity affects the simultaneous initiation and propagation of multiple fractures, while inter-well stress heterogeneity induces asymmetric fracture geometries and proppant concentration distribution. In multi-well pad fracturing, the evolution of 3D pressure and stress fields caused by production or injection from parent wells can strongly influence the preferential growth paths of fractures in new wells.

Discontinuities such as lithology interfaces (LIs) and bedding planes (BPs) significantly complicate the mechanisms of hydraulic fracture (HF) propagation in multi-lithology and multi-layered shale reservoirs (MLSR). To investigate how these discontinuities influence HF growth, an improved small-scale true triaxial fracturing simulation system and CT scanning technique were employed to conduct fracturing experiments. Subsequently, a 3D numerical model based on the continuum-discontinuum element method (CDEM) was developed to explore the influence mechanisms of LIs, BPs, minimum horizontal principal stress (σh), and Young’s modulus (E) differences between lithologies, and combined factors on the evolution of HF parameters. The physical experiment results indicate that HF propagates through LIs and BPs in a “step-like” pattern. The HF morphology takes the shape of a “╫” or “╪”, penetrating, offsetting, or terminating at LIs or BPs with a narrow aperture. The numerical simulation shows that when HFs intersect with LIs and BPs, shear failure is dominant. The shear sliding along interfaces causes stress release at the fracture tip, resulting in discontinuities at the fracture front. The effect of σh on HF growth is more significant than that of E. Lithologies with high σh form a pressure barrier, while E indirectly slows the rate of HF growth by influencing the rock stiffness and aperture. HF length extension is more favorable in lithologies with low σh. HFs are more prone to elastic deformation in soft formations, resulting in an uneven and slower extension rate. The tensile-induced stress increases in high E, leading to stress concentration at the LIs, which promotes HF to penetrate the LIs. Furthermore, the elastic deformation of low E contributes to less significant stress concentration, which restricts HF growth. BPs with low σh are less likely to capture HFs, merely delaying the propagation of stress. The findings are expected to provide theoretical support for controlling HF growth during hydraulic fracturing.

The technique of temporary plugging is extensively applied in areas like large-scale multi-cluster fracturing and repeated fracturing in unconventional horizontal wells. However, the current efficiency of temporary plugging is difficult to achieve 100

The Dagang Oilfield has developed a multi-layered 3-D technology for terrestrial shale oil, but challenges such as multiple faults, vertical bedding, superim?posed oil-bearing layers, and limited vertical modification lead to inconsistent effectiveness. To address this, this study establishes a 3-D geological model of the Guandong shale oil (GY) block, integrating fracture parameter inversion from construction pressure and logging data, calibrated through historical matching. It examines fracture morphology, well spacing, horizontal section length, and fracture parameters, optimizing well patterns and fracturing parameters using an or?thogonal experimental method. Additionally, an evaluation system combining the analytic hierarchy process and fuzzy comprehensive evaluation provides guidance for efficient shale oil reservoir development.

The deep carbonate reservoirs in the Yingzhong Block of the Qaidam Basin exhibit strong vertical heterogeneity and complex natural fracture development. Conventional fracability evaluation methods struggle to accurately characterize formation features, thereby affecting the stimulation effectiveness. To enhance the evaluation accuracy of fracturing sweet spot intervals, automatic mineral scanning equipment is employed to obtain formation micro-physical property parameters at continuous depths. Considering the temperature-pressure coupling effect under deep conditions, a rock mechanics computational model based on mineral composition was established to derive macroscopic mechanical parameters such as brittleness index and in situ stress. Based on a combined algorithm of the improved Technique for Order Preference by Similarity to Ideal Solution (TOPSIS) and Analytic Hierarchy Process (AHP), a fracturing sweet spot prediction model integrating micro- and macro-multi-factors is established, and sweet spot index levels are classified. The research results indicate that the rock mechanics computational model demonstrates high accuracy, the calculated macroscopic parameters are reliable, and the fracturing sweet spot index model can fracability and meticulously evaluate the characteristics of deep carbonate formations. The fracturing sweet spots can be classified into three levels: Level I with an index higher than 0.50, Level II with an index between 0.35 and 0.50, and Level III with an index lower than 0.35. After using this method for layer selection, the fracture pressure decreases by 11.6%, and the sand addition success rate increases by 24%. Applying this method to guide the optimization of fracturing intervals demonstrates good on-site practical value, providing an important reference for identifying fracturing sweet spots in deep carbonate reservoirs.

Based on the Low Frequency Distributed Acoustic Sensing(LF-DAS)fiber optic monitoring and downhole hawk-eye imaging,the fluid and sand distribution and perforation erosion of all clusters during hydraulic fracturing were evaluated,and then a fully coupled wellbore-perforation-fracture numerical model was established to simulate the whole process of sand-carrying fluid migration and analyze key influencing factors.The proppant and fracturing fluid exhibit divergent flow pathways during multi-staged,multi-cluster fracturing in horizontal wells,resulting in significant heterogeneity in the fluid-proppant distribution among clusters.Perforation erosion is prevalent,and perforation erosion and sand inflow ratio have phase bias.The trajectory of proppant transport is controlled by the combined effects of inertia of particle migration and gravity settlement.The inertial effect is dominant at the wellbore heel,where the fluid flow rate is high,hindering particles turning into perforations and causing uneven sand distribution among clusters.The gravity settlement is more pronounced toward the wellbore toe,where the fluid flow rate is low,leading to enhanced phase-bias of slurry distribution and perforation erosion.Increasing the pumping rate reduces the influence of gravity settlement,mitigating the phase bias of sand inflow and perforation erosion.However,the large pumping rate limits the sand inflow efficiency near the heel clusters,and more proppants accumulate towards the toe clusters.High-viscosity fluids improve particle suspension,achieving more uniform proppant placement within wellbore and fractures.Larger particle sizes exacerbate sand inflow differences among clusters and perforations,limiting the proppant placement range within fractures.

Compressed Air Energy Storage (CAES) is a method of storing energy in the form of compressed air. Low-permeability formations with excellent sealing properties serve as ideal storage spaces for this purpose. While lower permeability reduces gas diffusion to distant areas, thereby enhancing energy preservation, it also diminishes the formation’s ability to inject and produce gas efficiently. Consequently, hydraulic fracturing of low-permeability formations becomes necessary to improve injection and production efficiency. This study focuses on a target reservoir, employing numerical simulation models based on CAES characteristics to analyze and optimize fracture and injection-production parameters that affect storage efficiency. The simulation results indicate optimal fracture parameters of 120 m length and 30 D·cm conductivity, with optimal injection-production parameters of 3000 m3/h injection rate, 6000 m3/h production rate, 15 MPa injection pressure, and 10 MPa production pressure. These findings provide valuable insights for enhancing multi-cycle injection and production efficiency in CAES systems.

In order to study the influence of multi-cycle stress sensitivity on the injection–production effect, it is necessary to conduct multi-cycle stress sensitivity experiments on reservoir permeability and fracture conductivity first and then calculate the impact on the injection–production effect after the occurrence of the stress sensitivity effect by using the CMG software. After stress sensitivity occurs and the production rate decreases, the constraints of the well should be adjusted. The results showed that the conductivity of the 30–50 mesh ceramsite decreased by 15.94% after 100 cycles, while the conductivity of the 20–40 mesh quartz sand decreased by 51.17%. Under alternating stress, the reservoir permeability decreased significantly during the first 50 cycles, with an average decrease of 20.8%, but remained relatively stable in the later stages. When stress sensitivity was disregarded, the gas production rate of the ceramic and quartz sand stabilized at approximately 3700 m3/h and 2600 m3/h, respectively. When stress sensitivity was considered, the secondary gas cushion for ceramsite had to reach at least 500,000 m3 to maintain a gas production rate of over 3700 m3/h within 40 cycles after the gas cushion. When stress sensitivity was considered, the secondary gas cushion for quartz sand had to exceed 800,000 cubic meters to maintain the gas production rate of over 2600 m3/h within the first 30 cycles after the gas cushion. To sustain the gas production rate over the long term, it was necessary to increase the injection pressure per cycle. The gas injection pressure for ceramsite should be adjusted to more than 17 MPa, and the gas injection pressure for quartz sand should be adjusted to more than 19.3 MPa.

In the Kelameili volcanic gas reservoir, primary hydraulic fracturing treatments in some wells take place on a limited scale, resulting in a rapid decline in production post stimulation and necessitating re-fracturing operations. However, prolonged production has led to a significant evolution in the in situ stress field, which complicates the design of re-fracturing parameters. To address this, this study adopts an integrated geology–engineering approach to develop a formation-specific geomechanical model, using rock mechanical test results and well-log inversion to reconstruct the reservoir’s initial stress field. The dynamic stress field simulations and re-fracturing parameter optimization were performed for Block Dixi-14. The results show that stress superposition effects induced by multiple fracturing stages and injection–production cycles have significantly altered the current in situ stress distribution. For Well K6, the optimized re-fracturing parameters comprised a pump rate of 12 m3/min, total fluid volume of 1200 m3, prepad fluid ratio of 50–60%, and proppant volume of 75 m3, and the daily gas production increased by 56% correspondingly, demonstrating the effectiveness of the optimized re-fracturing design. This study not only provides a more realistic simulation framework for fracturing volcanic rock gas reservoirs but also offers a scientific basis for fracture design optimization and enhanced gas recovery. The geology–engineering integrated methodology enables the accurate prediction and assessment of dynamic stress field evolution during fracturing, thereby guiding field operations.