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The deep coalbed methane (CBM) resources (buried deeper than 1500 m) in North China exceed 30 trillion cubic meters, with significant breakthroughs in exploration, making it a new frontier for natural gas production growth. However, it faces key issues, including complex preservation conditions, unclear controls on enrichment and high productivity, and large production variations. In order to clarify the control factors of preservation conditions of deep CBM, the coal quality, lithology combination, and structural preservation characteristics of typical deep CBM exploration wells in North China are systematically analyzed with multidisciplinary analysis methods of geology, geochemistry, and geophysics. This study reveals that the differential preservation of deep CBM is controlled by the dynamic coupling mechanism of adsorption self-sealing, physical property sealing, and structural preservation system: (1) Favorable coal quality is the basis of strong adsorption. Coal with low ash content and a high evolution degree is characterized by a large Langmuir volume, a great critical depth, and strong self-sealing ability. (2) Tightly lithology combination is a barrier to deep free gas dissipation. Limestone and mudstone exhibit low porosity, a small throat radius, and high breakthrough pressure, resulting in good physical sealing conditions and a high total retained gas content. (3) Continuous and stable structural preservation is the key to free gas enrichment. Late-stage uplift with low amplitude and weak tectonic activity is conducive to free gas accumulation, resulting in a high-pressure coefficient. In summary, areas characterized by deep burial, low-ash coal, limestone/mudstone roof rocks, and structural stability are favorable for deep CBM preservation. The study of differential preservation of deep CBM deepens the understanding of enrichment and high productivity, and provides a theoretical basis for optimizing favorable exploration and development targets.
The Qionghai Uplift and the surrounding buried hills in the Zhu III depression, Pearl River Mouth Basin, are a key oil and gas exploration target in the northern South China Sea. The volcanic rock reservoirs in this area are significantly modified by fracture development. To clarify the formation mechanisms, this study combines high-resolution 3D seismic data, well data, and thin-section observations for analysis. The results indicate that the faults in the study area developed in two stages: (1) NW-SE compression during the Early-Middle Yanshanian formed NE-trending imbricate thrust faults, which were reactivated in the Early Himalayan; (2) left-lateral strike-slip during the Late Yanshanian formed a NNE-trending fault system comprising pure strike-slip, transtensional, and transpressional segments, which were reactivated in the Middle Himalayan. Fractures developed synchronously in two stages, with the densest fracture networks occurring in the hanging-wall regions near thrust faults (e.g., WC13-I well), transpressional segments of strike-slip zones (e.g., WC19-A well), and transtensional segments (e.g., WC13-M well). Specifically, the thrust faults caused shear fracturing of the hanging-wall strata through compression, while differential stresses along various strike-slip fault segments produced distinct fracture networks. Himalayan period stress field rotation further reactivated pre-existing fractures. The resultant fracture network provides effective pathways for oil and gas migration, thereby supporting exploration strategies in this area.
The enrichment patterns of natural gas in the tight sandstone reservoirs of the Xujiahe Formation in the northeastern Sichuan Basin are complex, and the fault system exerts a crucial control on hydrocarbon accumulation. To clarify the structural characteristics of the faults and their impact on natural gas enrichment in this area. Based on three-dimensional seismic data and drilling data, integrated with artificial intelligence fault identification technology and structural analysis, this study identifies a NE-SW trending en echelon strike-slip fault zone in the Xujiahe Formation of the Wubaochang Area, northeastern Sichuan Basin. The structural deformation characteristics, evolutionary history, and reservoir-controlling and accumulation-controlling effects of this fault zone are investigated. The results indicate that the fault zone exhibits vertically layered deformation characteristics: it manifests as thrust faults in the strata from the Upper Ordovician to the Lower Triassic Jialingjiang Formation, while in the Upper Triassic Xujiahe Formation, it appears as a strike-slip fault zone composed of a series of small NNW-SSE trending thrust faults arranged in a right-stepping en echelon pattern. The fault zone underwent two stages of tectonic evolution. During the Indosinian-Yanshanian period, under continuous SE-NW oriented tectonic compression, it exhibited thrust fault activity. In the Himalayan period, the regional tectonic stress field shifted, and under a NE-SW oriented horizontal compressional stress field, the pre-existing major faults underwent sinistral strike-slip movement, forming a series of right-stepping en echelon strike-slip faults in the Xujiahe Formation. The faults in the Xujiahe Formation are interconnected with the deep-seated major faults, linking the Xujiahe Formation reservoir, the Longtan Formation source rocks, and deep fluids. This connection establishes a “strong below and weak above” transport system and a “dual-source hydrocarbon supply” model. Simultaneously, it exerts a dual effect on the tight sandstone reservoirs of the Xujiahe Formation, namely “dissolution and porosity enhancement” and “cementation and destruction,” providing favorable dynamic conditions for the differential evolution of tight reservoirs and the development of sweet spot reservoirs. Consequently, the fault zone serves as a favorable site for natural gas enrichment and preservation in the tight sandstone reservoirs of the Xujiahe Formation. The research demonstrate that strike-slip fault zones are advantageous enrichment belts for natural gas in Triassic tight sandstone reservoirs in the northeastern Sichuan Basin, and greater emphasis should be placed on the evaluation and exploration of such target areas.
To address the challenges of poor sorting, strong heterogeneity, and unclear overburden pressure-dependent variations in porosity and permeability in glutenite reservoirs, where existing conventional sandstone correction methods are inadequate, this study investigates the Paleogene Kongdian Formation glutenite reservoirs (burial depth: 3800~4100 m) in the BZ area. Using overburden pressure porosity-permeability experiments and rock mechanics test data from 13 core plugs covering the main porosity-permeability range, we reveal the unique variation patterns and establish a targeted correction model. The results show that this is a low-porosity, ultra-low-permeability reservoir, with matrix porosity of 5%~15% and permeability of 0.1~6 mD under ambient conditions. The pore space is dominated by intergranular and intragranular dissolution pores, with occasional microfractures, indicating significant heterogeneity. Unlike conventional sandstone reservoirs, the porosity and permeability of these glutenite reservoirs decrease following a power-law function with increasing overburden pressure. The decline gradient varies with the initial porosity and permeability at ambient pressure. Thus, the overburden pressure-dependent porosity/permeability is a bivariate function of the overburden pressure and its initial value at ambient conditions. By fitting the experimental data, we derived the quantitative relationship between the power-law coefficients and the ambient-pressure porosity/permeability, constructing a triaxial overburden pressure correction model. Incorporating rock mechanics data, a uniaxial overburden pressure bivariate correction model for in-situ conditions was also established. Accuracy verification shows that the triaxial model achieves an MSE of 0.369% for porosity and 0.281 mD for permeability. Compared to the traditional univariate model, accuracy improves by 67% and 43%, respectively, providing reliable characterization across both high and low porosity-permeability ranges. The proposed bivariate correction method fills a gap in overburden pressure porosity-permeability correction for glutenite reservoirs and solves the problem that traditional methods cannot adequately account for their strong heterogeneity. This method provides an essential correction tool for accurate reserve evaluation and productivity prediction, and offers a theoretical basis for designing efficient development strategies.
Reflection waveform inversion (RWI) exploits reflected-wave information in seismic data to update the deep background velocity model. By alternately inverting for the migration and tomographic components, RWI not only improves the accuracy of deep velocity model updates but also alleviates the cycle-skipping problem to a certain degree. However, RWI generally requires seismic data with a high signal-to-noise ratio (SNR) and has so far achieved its most successful applications in marine environments. In contrast, land seismic data are often degraded by poor receiver coupling, rugged topography, environmental noise, and strong surface-wave interference, making it difficult to acquire continuous and high-SNR reflection waveforms, which severely limits the applicability of RWI to land data. To address these challenges, this study employs Kirchhoff pre-stack time migration to identify characteristic reflection layer and extract their corresponding common-image gathers (CIGs). The extracted events are then reverse migrated to reconstruct reflected-wave data with enhanced SNR. The reconstructed data are subsequently incorporated into RWI and validated using both synthetic and field data examples. The results demonstrate that the proposed method significantly improves the accuracy of deep background velocity model updates. Furthermore, the strong consistency between the migrated images and the corresponding CIGs confirms the reliability and effectiveness of the reconstructed reflection data for RWI applications. Overall, this method offers a new feasible solution for applying RWI to land seismic data.
Crystalline rock formations are commonly encountered in the deep stages of ultra-deep geothermal drilling. The degradation of their mechanical properties under the coupled effects of thermal, hydraulic, chemical, and stress fields exerts a significant impact on wellbore stability, operational safety, and efficiency. This paper elaborates on the current status of ultra-deep drilling and its downhole environmental conditions, while analyzing the mechanical characteristics of crystalline rocks. On this basis, the paper further clarifies the action mechanisms of single-field factors (including thermal field, seepage field, chemical field and stress field) during ultra-deep drilling, as well as the influence pathways of more complex multi-field coupling effects on the mechanical properties of crystalline rocks. Focusing on typical crystalline rocks (granite and gneiss), this study summarizes the microstructural evolution laws and macroscopic mechanical response behaviors under thermal shock, seepage intrusion, chemical corrosion, and stress disturbance. It also generalizes the degradation characteristics of key mechanical parameters such as strength, fracture toughness, and elastic modulus, and compares the degradation mechanisms between granite and gneiss. It is explicitly clarified that in ultra-deep drilling, high temperatures can induce the initiation of microcracks inside crystalline rocks and further promote their propagation; fluid intrusion not only exacerbates the dissolution of primary minerals but also facilitates the precipitation of secondary minerals; stress redistribution resulting from drilling-induced perturbations further promotes fracture connectivity and the formation of macroscopic failure surfaces; and multi-field synergy drives the transition of rocks from a brittle to a ductile deformation mode.Existing theories have limitations in terms of multi-field coupling mechanisms, coverage of crystalline rock types, and the long-term effects of actual drilling fluids. Future research urgently needs to strengthen fully coupled thermal-hydraulic-mechanical-chemical experiments and simulations, develop a “fully coupled thermal-hydraulic-mechanical-chemical numerical model” capable of accurately describing cross-scale damage processes and a “digital twin wellbore model” integrated with real-time drilling data, and propose an “active wellbore stability control strategy” focusing on multi-field coupling mechanisms. Ultimately, within a multi-scale and multi-field coupling framework, this study aims to establish a crystalline rock wellbore stability evaluation and degradation control method suitable for deep underground environments, providing solid theoretical support for in-depth understanding of the mechanical behaviors of crystalline rocks under multi-field coupling conditions and the safe and efficient implementation of ultra-deep drilling.
Gravel packing is an effective completion technique to meet sand-control and productivity-enhancement needs of natural gas hydrate reservoirs. Friction at gravel-gravel interfaces and their bonding with hydrates directly affect the packing process and the mechanical properties of the gravel-pack structure. However, particle-scale studies that systematically clarify the mechanisms of friction and bonding between hydrates and packing gravel are still lacking, and quantitative characterization of inter-particle micro-forces under the coupled effects of “wetting-temperature-contact type” remains insufficient. In this study, a customized high-precision micro-force testing apparatus, combined with in-situ high-resolution microscopic observation, was employed to investigate inter-particle interactions at the single-particle contact scale. Three wetting states-dry, partially wetted, and fully wetted-and multiple contact configurations, including bare contact, ice-coated contact, and hydrate-coated contact, were clearly distinguished. The friction coefficients and bond strengths among tetrahydrofuran (THF) hydrate, ice, and gravel particles were systematically measured. The results show that: (1) THF-hydrate particles exhibit overall higher friction coefficients than ice, primarily due to their roher surfaces and the higher propensity for brittle micro-fracture during sliding; (2) interfacial friction varies nonlinearly with water content: compared to dry particle contacts, a modest amount of liquid water reduces the friction coefficient due to thin-film lubrication, whereas excess water increases the friction coefficient again through viscosity and capillary-bridge effects; when gravel is coated by ice or hydrate, the friction coefficient decreases markedly; (3) at low temperatures, pronounced bonding occurs at both hydrate-gravel and ice-gravel interfaces, with failure dominated by interfacial brittle fracture, indicating that rupture preferentially occurs at the particle-hydrate interface rather than within the hydrate itself. These particle-scale findings elucidate how wetting, temperature, and contact configuration govern friction coefficient and bond strength among hydrates, ice, and gravel, and they provide a basis for parameterized modeling of gravel-packing operations and for reliability assessment in sand control and productivity enhancement.
Natural fractures in middle-deep shale reservoirs experience continuous stress evolution under the combined influence of hydraulic stimulation and long-term production. Their stability evolution critically affects wellbore integrity, stimulation effectiveness, and the safety of infill-well deployment. Focusing exclusively on natural fractures, this study develops a stability evaluation framework by coupling a 3D geomechanical model with a discrete fracture network (DFN). The approach maps the strike and dip of natural fractures onto the 3D grid and constructs a spatially continuous fracture-orientation volume through geostatistical interpolation. This enables the unified coupling of natural fracture geometry with the regional 3D stress field and rock mechanical attributes, providing a continuous 3D quantification of natural-fracture stability. Results show that natural-fracture slip risk is governed by the combined effects of fracture orientation and tectonic stress regime, with distinct high-risk orientations under normal-faulting, strike-slip, and reverse-faulting conditions. Fluid injection may trigger natural-fracture instability through reduced effective normal stress and lowered frictional strength, whereas long-term production enhances effective stress and generally improves natural-fracture stability. In the YS108 block, the stress regime evolves toward a typical normal-faulting state after nearly ten years of production, leading to significantly reduced slip risk of natural fractures. The proposed 3D evaluation framework provides a practical basis for post-production stability assessment, well-trajectory optimization, and stimulation-risk management in middle-deep shale reservoirs.
China possesses vast and widely distributed oil and gas resources, characterized by significant development potential and rapid growth in their exploitation. However, the exploration and development of unconventional resources such as shale gas and tight oil remain at an early stage. As domestic demand for oil and gas continues to rise, the extraction of deep unconventional resources has consequently become a major focus in national energy engineering. A common practice in unconventional oil and gas production involves large-scale fluid injection into deep geological formations. Such injection disturbs the in-situ stress field and alters the stress state of subsurface faults, which may lead to fault instability, slip, and subsequently induced seismicity. Therefore, evaluating and mitigating such anthropogenic seismic risks has become a critically important issue for achieving safe and sustainable resource development. In recent years, seismic events have been monitored during the production phases of multiple deep energy projects worldwide. Post-earthquake analyses indicate a clear spatiotemporal correlation between these events and fault activation or instability triggered directly by fluid injection. Notable examples include geothermal projects in Pohang, South Korea, and Basel, Switzerland, which were suspended due to significant induced earthquakes. In fact, geological conditions in China’s oil and gas fields are often more complex, making it difficult to accurately predict fault slip conditions, specific slip patterns, and displacement, or to determine optimal operational parameters near fault-developed zones. To balance benefits and risks in unconventional resource development, predicting and preventing the associated environmental geological issues and seismic hazards caused by deep energy extraction has become an urgent challenge. This study reviews typical cases of induced seismicity in energy projects globally, with a focus on analyzing the underlying stress conditions and the detailed triggering mechanisms of fault instability and slip at development sites. It systematically summarizes fault slip instability modes, established criteria for induced seismicity, estimated affected ranges, and current magnitude prediction models. The influence of both anthropogenic engineering factors and inherent environmental geological conditions on induced seismic events during development is also thoroughly discussed. Finally, this study summarizes the major unresolved issues and key technical challenges that need to be addressed in current research, and outlines potential future research directions through three primary approaches: numerical simulation, experimental methods, and enhanced field monitoring. The work contributes to a deeper fundamental understanding of human induced seismicity from oil and gas operations, and holds practical implications and considerable engineering value for mitigating or preventing potential seismic hazards.
In-situ stress is a fundamental parameter for seismic research, deep resource development, and underground engineering. However, in soft rock formations with strong rheological behavior, the hydraulic fracturing(HF) method cannot directly determine the maximum horizontal principal stress(σH), and the anelastic strain recovery(ASR) method often suffers from large uncertainties due to the difficulty of accurately determining the anelastic strain recovery compliance. To address these limitations, this study proposes a novel approach for in-situ 3D stress in soft rock formations that integrates the hydraulic fracturing method with the anelastic strain recovery method. The minimum horizontal principal stress(σh) is obtained through hydraulic fracturing tests, while the anelastic strain recovery compliance is back-calculated from ASR data on recovered core samples, enabling the complete in-situ 3D stress tensor to be reconstructed. This combined method has been successfully applied in the Ningjin salt cavern gas storage project, confirming its reliability and applicability in deep soft rock formations. The proposed approach provides a new technical solution for acquiring in-situ stress in soft rock formations and offers valuable support for salt cavern gas storage construction, unconventional hydrocarbon development, and wellbore stability evaluation.
To systematically review the research progress of intelligent fracturing technology in unconventional oil and gas reservoirs, by integrating machine learning algorithms (e.g., random forest and gradient boosting), the embedded discrete fracture model (EDFM), fiber-optic/microseismic monitoring technologies, and smart equipment, this study analyzes technological breakthroughs and application cases in key aspects such as reservoir parameter prediction, fracture propagation simulation, and real-time control. Results demonstrate that the random forest and gradient boosting models demonstrated optimal performance in permeability prediction (R²>0.92). The EDFM-AI workflow reduces fracture parameter calibration errors to 6.8%. Fiber-optic monitoring technology achieves sub-millimeter resolution in fracture detection. The intelligent early-warning system predicts sand plugging risks 30 seconds in advance (accuracy above 85%). Intelligent fracturing technology significantly enhances reservoir modification efficiency and production, but challenges such as small-sample generalization, multi-source data fusion, and equipment autonomy require further resolution. Establishing a closed-loop technical system encompassing “reservoir evaluation, optimized design, fracture monitoring, anomaly prediction, and equipment control”, and promote the development of intelligent and precise fracturing processes.
The ongoing Fourth Industrial Revolution, characterized by artificial intelligence (AI), is driving a wave of intelligent transformation across the oil and gas industry. International oilfield service and operating companies in regions such as the United States, Norway, and the Middle East are investing heavily in digital and intelligent transformation to secure a competitive advantage in the future landscape. As a cutting-edge technology in oil and gas engineering, intelligent drilling and completion is poised to yield disruptive and leapfrog innovations, empowering the development of new quality productive forces. This paper elaborates on the conceptual framework of intelligent drilling and completion technologies and provides a comprehensive review of the current domestic and international development status and technical disparities across five key areas: surface equipment, measurement-transmission-conduction tools, drilling fluids, cementing, and software. It further identifies four major existing problems and four key challenges. Furthermore, it proposes the “1244” development direction: focusing on one goal—empowering technological innovation and industrial upgrading through “Drilling and Completion + AI”; concentrating on two major fields—intelligent drilling and intelligent cementing; tackling four key technological directions—equipment, tools, fluids, and software; and realizing four typical application scenarios—fully automated wellsite operations, autonomous drilling control, intelligent drilling fluid regulation, and intelligent cementing operations. Simultaneously, the article advocates building a technical system with the geology-engineering knowledge base as the foundation, large/small AI models as the backend support, and “Drilling and Completion + AI” as the front-end application carrier. This aims to accelerate the transition of intelligent drilling and completion technology from unit-level closed-loop to global closed-loop and remote-controlled operations.
Drilling digital twin technology, as a core method for virtually mapping actual drilling processes and enabling visual monitoring and intelligent decision-making, has become one of the inevitable trends in the future development of intelligent drilling. Drilling digital twins primarily involve two aspects: surface drilling rigs and subsurface wellbores. While surface rigs have entered systematic research phases globally due to their relatively stable nature and abundant mature experience, subsurface wellbores present significant challenges. These include invisibility, tangibility issues, high uncertainty, complex operating conditions, and the involvement of multi-medium and multi-physics coupling phenomena. This paper systematically elaborates on the core theories, key technologies, and development trends of constructing and applying digital wellbore models for drilling operations. It aims to provide a reference for subsequent research and engineering practice in this field.
This paper systematically reviews the current technical framework and implementation approaches for drilling digital twin modeling, focusing on key challenges such as multi-source heterogeneous data fusion during wellbore drilling operations, the coupling of physics-based and data-driven models, and intelligent decision feedback mechanisms. First, targeting the objects and levels of drilling data fusion, the fusion mechanisms for multi-temporal and multi-spatial scale data and conflict resolution methods were explored. Second, a comprehensive digital twin architecture suitable for drilling operating conditions was established, and methods for implementing joint physics-based and data-driven modeling were summarized. Then, diagnostic methods for drilling anomaly data features were proposed, enabling the establishment of multi-perspective decision feedback mechanisms between the physical and digital entities. Finally, the application potential of wellbore digital twin technology was prospected in the areas of high spatiotemporal resolution cognition, edge deployment, and model credibility assurance. The research results can provide theoretical support and methodological guidance for achieving drilling state recognition and efficient control under complex operating conditions.
Accurate prediction of collapse and fracture pressures is crucial for well trajectory design, wellbore stability control, and efficient drilling operations. Traditional numerical and analytical methods are often computationally complex and inefficient, while purely data-driven models, although faster, suffer from pronounced black-box characteristics and lack interpretability, which limits their engineering applicability. To overcome these challenges, this study proposes a hybrid-driven prediction method that integrates wellbore stability mechanistic models with a multi-task learning framework (MW-MMoE). In this approach, stress coordinate transformation is embedded as physical prior knowledge at the input stage, while the output targets are reconstructed by first predicting key stress components and then converting them into equivalent densities of collapse and fracture pressures through physical formulations. The Mohr-Coulomb criterion is further incorporated into the loss function as a physical constraint. The model architecture leverages a multi-gated mixture-of-experts network combined with the GradNorm algorithm to dynamically adjust task weights and balance gradients during training. Ablation experiments demonstrate that the proposed MW-MMoE achieves mean absolute errors as low as 0.0019 g/cm³ and 0.0033 g/cm³ for collapse and fracture pressure equivalent densities, respectively, significantly outperforming both single-task and conventional multi-task models, while achieving over a hundredfold improvement in computational efficiency compared with analytical methods. Case studies further validate its engineering applicability: the model can rapidly generate collapse and fracture pressure equivalent density curves for individual wells, produce high-resolution contour maps under arbitrary well inclinations, azimuths, and stress conditions, and perform large-scale three-dimensional predictions across the entire study area. These results highlight that the MW-MMoE model combines high accuracy, efficiency, and interpretability, providing a novel and practical solution for intelligent wellbore stability prediction with broad application prospects.
To regulate the hydration heat of deep-water well cementing slurry, phase change microcapsules (m-PCMs) with organic (PMMA) and inorganic (SiO₂) shells were prepared in this study to investigate the influence mechanism of shell properties on the cement matrix performance. The results indicated that both types of m-PCMs exhibited excellent shear stability and similar peak phase change temperatures (25.6 °C), effectively reducing hydration exotherms. The critical difference lay in their wettability: PMMA@m-PCM was hydrophobic (116.5°), whereas SiO₂@m-PCM was strongly hydrophilic (27.3°). Micro-CT confirmed that m-PCMs at a 6 wt% dosage effectively reduced the proportion of large pores, optimizing the pore structure. Mechanical tests revealed that SiO₂@m-PCM demonstrated a significant strength enhancement effect at 3 and 7 days, while PMMA@m-PCM severely weakened the matrix strength. SEM analysis revealed that the core of this performance disparity was interfacial compatibility: the hydrophilic SiO₂ shell formed a dense interfacial transition zone (ITZ) with the matrix, whereas the hydrophobic PMMA shell caused severe interfacial debonding, creating mechanical weak points. This study demonstrates that using hydrophilic inorganic shells is key to achieving the unification of m-PCM hydration heat regulation and mechanical performance enhancement. These findings provide a new methodology for designing low-heat cement slurries, offering theoretical and technical insights for safe and sustainable deep-sea oil and gas exploitation and reducing ecological impact.
The Lucaogou formation of the Permian System in the Jimsar Sag, Junggar Basin, represents a typical example of mixed siliciclastic-carbonate continental shale oil in China. After more than a decade of exploration and pilot development, remarkable technological and production breakthroughs have been achieved, confirming its substantial resource potential. Nevertheless, the current depletion-based development mode continues to face critical challenges such as rapid formation energy loss, sharp production decline rates, and persistently low recovery factors. The key technical direction for improving oil recovery at the later stage of development therefore remains unclear and urgently requires systematic investigation. To address these issues, a coupled numerical model of hydraulic fractures and the shale matrix was established based on the actual geological model of a well platform located in the lower sweet-spot interval of the Jimsar Sag. The model was validated through history matching by optimizing key reservoir and fracture parameters. On this basis, an inter-well gas injection displacement scheme involving three horizontal wells was designed, in which gas is injected through the central well and oil is produced from the two adjacent wells following an initial depletion phase. Simulation results show that, for Jimsar shale oil characterized by an ultra-tight matrix and poorly developed natural fractures, the degree of communication between horizontal wells through hydraulic fractures is the key factor determining the effectiveness of gas injection development. Comparative analyses of different injected gases (CO2 and CH4), injection timing, and injection pressure were performed to clarify their influence on the displacement process. Based on these results, an optimized operation strategy was proposed, involving cyclic reinjection of produced gas after the initial breakthrough of the injected gas at the production wells. Compared with depletion development, the designed inter-well gas injection scheme increases the cumulative oil production by approximately 45%, while the oil utilization ratio-an indicator of carbon and energy efficiency-nearly doubles. The proposed cyclic reinjection of produced gas further enhances carbon utilization efficiency and reduces the external CO2 supply demand, thereby achieving a dual objective of improving oil recovery and promoting effective carbon recycling. Overall, the developed coupled model and the derived optimization strategy provide a technically feasible and scientifically grounded approach for enhancing oil recovery in continental shale oil reservoirs. The findings clarify the mechanisms and governing parameters of inter-well gas displacement under ultra-tight conditions, and the proposed cyclic reinjection mode offers a practical pathway for synergistic oil production enhancement and CO2 geological utilization. This study provides important theoretical support and engineering reference for large-scale application of gas injection displacement and CO2 sequestration in the late-stage development of continental shale oil fields in China.
The goal of “carbon peak and neutrality” is driving China’s energy system to accelerate transition to clean, low-carbon development. As an important new clean energy source, natural gas hydrate (NGH) exhibits high energy density, wide distribution, and substantial resource potential. Therefore, accelerating its industrial production is key to achieving a reduction in pollution and carbon emission. NGH production involves Thermal-Hydrological-Mechanical-Chemical (THMC) multi-physical field coupling. Traditional experiments and production tests fail to fully reveal underlying mechanisms, making numerical simulation—with high functionality, flexible methods, and low cost—an essential research tool. This study systematically reviews theories, technologies, and applications of numerical simulation for natural gas hydrate production to provide theoretical support for safe, efficient extraction and advance the translation of simulation technologies to engineering practice. Specifically, it clarifies evolution laws of seepage parameters (e.g., porosity, permeability) during hydrate dissociation; identifies evolution of mechanical parameters (e.g., shear strength, cohesion) with hydrate saturation, revealing the core mechanism by which hydrates dominate reservoir mechanical property evolution via decomposition behaviour; outlines approaches to constructing THMC multi-physical field coupling models; summarizes functions and advantages of major global simulators (e.g., TOUGH+Hydrate, SuGaR-TCHM), and validates applications at typical pilot sites. Current numerical simulation research has limitations: multi-phase flow models insufficiently account for continuous pore structure evolution and impacts of hydrate saturation on relative permeability; characterization of mechanical properties and sand production risk responses in unconsolidated clayey silt sediments is inadequate; and capacity to predict long-term mechanical stability risks (e.g., land subsidence, submarine landslides) induced by production is limited. Future work should establish “micro-macro” cross-scale parameter models, refine elastoplastic constitutive models for clayey silt sediments, and develop integrated geological engineering simulation tools to advance simulation technologies from mechanistic interpretation to engineering decision support.
Under the “dual-carbon” target, geothermal energy has become an important direction for energy transition due to its characteristics of being clean and efficient, having abundant reserves, and being low-carbon and environmentally friendly. Aiming at the seepage-heat transfer evolution characteristics and well-pattern optimization of geothermal fields under multi-well production and reinjection conditions, this study takes the geothermal field in the Xiong’an high-speed railway area as the research object. A three-dimensional coupled seepage-heat transfer numerical model was constructed based on COMSOL Multiphysics, and parameter calibration was carried out by combining field monitoring data of production-well water temperature and groundwater level to ensure consistency between numerical results and actual operation conditions. On this basis, twenty additional geothermal wells were designed, including ten production wells and ten reinjection wells. By simulating three well-pattern schemes—linear, staggered, and triangular—the variations in production-well water level, temperature, and dynamic recoverable geothermal resources under different schemes were analyzed, and the influences of different schemes on reservoir stability and heat-exchange efficiency were systematically compared. The results show that the linear well pattern has a simple structure and is easy to implement; however, its thermal mobilization range is limited, the overall recoverable geothermal resources are the lowest, and boundary production wells are prone to forming localized groundwater drawdown cones. The staggered well pattern exhibits a more uniform distribution of production and reinjection, which can effectively suppress localized overexploitation, delay cold-water breakthrough, and maintain relatively high reservoir thermal stability, resulting in the most stable evolution of dynamic recoverable geothermal energy. The triangular well pattern shows the strongest thermal mobilization capacity and the highest recoverable geothermal resources during the early stage of operation, but the risk of cold-water intrusion increases in areas with high production-well density, leading to a tendency of localized thermal attenuation in the later stage of operation. On a 50-year timescale, the total recoverable geothermal resources of both the staggered and triangular well patterns are more than 1% higher than those of the linear well pattern. Among them, the staggered well pattern achieves the best balance between resource utilization efficiency and system stability and is recommended as the preferred well-pattern scheme for the efficient and sustainable development of the geothermal field in the study area. The research results can provide theoretical references for well-pattern optimization, development performance evaluation, and sustainable operation of multi-well production and reinjection systems in mid- to deep-depth hydrothermal geothermal fields under similar geological settings and operating conditions.
Geological carbon storage (GCS) is one of the key technologies to achieve Carbon peak and carbon neutrality goals. Since industrial-source CO2 usually contains various impurity gases, and its purification is costly and technically challenging, these impurities are often injected into the subsurface together with CO2 in practical engineering applications. Based on the geological characteristics of the Shiqianfeng Formation in a CCS demonstration project area, a two-dimensional geological model was established, and reactive transport simulations of impure CO2 were conducted using the CMG-GEM compositional simulator. N2 and H2S were selected as representative impurity components to investigate the migration pathways, occurrence forms, and spatial distribution characteristics of impure CO2 in the saline aquifer. The study systematically analyzed the dominant trapping mechanisms, including structural trapping, residual gas trapping, and solubility trapping, at different storage stages, and explored the role of capillary pressure in the geological storage process of impure CO2. The simulation results indicate that during the early injection stage, CO2 predominantly accumulates in the supercritical state at the top of the reservoir. Over time, the capillary trapping effect gradually emerges, more CO2 is retained in the reservoir pores, promoting the continuous conversion of supercritical CO2 into bound and dissolved forms, thereby significantly enhancing the overall storage stability and safety. CO2 migration exhibits pronounced spatiotemporal heterogeneity: the injected gas rapidly rises under buoyancy and accumulates beneath the caprock, then gradually migrates downward under density and concentration gradients, promoting dissolution. After injection ceases, the gas spreads laterally along the base of the caprock, forming a tongue-shaped migration front with a maximum diffusion distance of approximately 650 m. The transport behaviors of the impurity components differ significantly. Due to its low solubility, N2 tends to accumulate at the leading edge of the gas-liquid displacement front, whereas CO2 and H2S, with higher solubility, form dissolution-enriched zones near the injection well, reaching peak solubilities of 1.4 mol/kg-H2O and 0.53 mol/kg-H2O, respectively. Capillary pressure plays a crucial role by suppressing the rate of gas-phase migration, enhancing dissolution trapping efficiency, and inducing reverse imbibition of formation water during the post-injection stage, thereby promoting greater retention of CO2 in pore spaces in the form of residual gas and effectively increasing the proportion of residual trapping. Comprehensive analysis demonstrates that the storage behavior of impure CO2 in saline aquifers is jointly governed by impurity properties, trapping mechanisms, and capillary pressure effects. The findings provide scientific support for optimizing injection strategies in impure CO2 geological storage projects and offer important guidance for ensuring long-term storage security and improving storage efficiency.
Oil-based foams hold significant potential for enhancing oil recovery and regulating subsurface fluid flow, yet their stability under high-temperature reservoir conditions and their transport mechanisms within pore-throat structures remain insufficiently understood. To address this gap, this study systematically investigates the behaviour of an oil-based foam system through temperature-dependent stability experiments, complemented by pore-scale numerical simulations that characterize bubble deformation and breakthrough within porous media. Experimental results show that increasing temperature accelerates liquid drainage and gas diffusion within the foam films, leading to a reduction in the number of bubbles, enlargement of average bubble size, and a pronounced decline in overall foam stability. Simulation results further demonstrate that pore-throat diameter and injection pressure jointly govern bubble morphology evolution and breakthrough behaviour, with the competition between capillary forces and external driving pressure emerging as the key mechanism influencing oil-based foam mobility. By integrating these findings, this work establishes a unified mechanical framework linking temperature effects and pore-throat confinement, thereby providing theoretical support for the application and optimization of oil-based foams in high-temperature reservoirs.
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