Search Results (234)

Tianjin, nestled on the North China Plain, possesses abundant geothermal resources with tremendous potential for development and utilization. This study employs hydrogeochemical and isotopic analysis techniques to thoroughly explore the geochemical characteristics and circulation patterns of geothermal fluids in Tianjin, shedding light on the mechanisms underlying the formation and evolution of deep geothermal fluids. The findings reveal that atmospheric precipitation serves as the primary recharge source for the region’s geothermal fluids, with the calculated recharge heights coinciding with those of the Jixian mountainous area. This precipitation infiltrates through permeable layers and the deep, large faults surrounding the southern plain, entering relatively enclosed or semi-enclosed geothermal reservoirs. As they circulate, the geothermal fluids undergo intricate interactions with the surrounding rocks, including processes such as leaching, adsorption, carbonate reprecipitation, cation exchange, and decarbonation. The fluids circulate at depths ranging from 1.6 to 3.5 km, with temperatures spanning from 67 to 133 °C. Along the flow path, the anionic composition of the geothermal fluids shifts from HCO₃⁻ dominance in the north to a coexistence of Cl⁻ and SO₄²⁻, ultimately dominated by Cl⁻ in the south, accompanied by an increase in total dissolved solids (TDS). The results indicate that Tianjin geothermal fluids are mainly recharged by meteoric water and evolve along their flow paths through dissolution of evaporitic and carbonate minerals, cation exchange, and carbonate precipitation. Hydrochemical and Sr-isotope differences suggest generally limited vertical connectivity among the studied reservoirs, although local hydraulic interaction may occur near conductive faults. These results provide constraints on the hydrogeochemical evolution and management of geothermal resources in the Tianjin sedimentary basin. Full article

Tight gas is a critical unconventional energy resource, yet the geological characteristics and accumulation processes of tight gas in China’s Songliao Basin remain poorly documented. This study aims to investigate the tight gas system in the Songliao Basin as a representative continental basin, with key objectives including evaluating source rock and reservoir properties via mineralogical and geochemical analyses, characterizing lithologies and pore types, determining the gas charging mechanism in tight media, and identifying the main controlling factors for accumulation. Geochemical results indicate that the Shahezi Formation contains medium to good mudstones and excellent coals. Reservoirs consist of tight sandstones and conglomerates deposited in fan delta and braided river delta systems, with pore spaces dominated by dissolution pores and microfractures, resulting in ultra-low porosity and permeability. Conventional buoyancy-driven migration is ineffective; instead, gas charging is driven by hydrocarbon generation expansion force, creating overpressure that expels pore water and forces gas into reservoirs through fault-sand conduits. Accumulation is controlled by continuous gas supply from thick, highly mature source rocks, dissolution-enhanced and fracture-dominated reservoir space, and sufficient source–reservoir pressure difference. This study elucidates tight gas characteristics and accumulation mechanisms in continental basins, providing data applicable to both continental and marine settings. Full article

Deep gas emissions in volcanic and tectonic environments are commonly interpreted as the surface expression of localized deep emitters. This representation is adequate for first-order description, but it is not physically complete. Deep degassing is more appropriately represented as a coupled source–storage–pathway system in which volatile generation, compressible accumulation, phase change, hydraulic communication, and permeability evolution are dynamically linked. Starting from phase-wise mass conservation in deformable porous–fractured media, reduced equations for gas migration, pore-pressure diffusion, and thermo-poro-mechanical coupling are derived, showing how the distinction between gas-mass transport and pressure propagation provides a unified framework for volcanic and tectonic degassing. Deep pressure gradients are shown to arise from the competition between volatile supply and pathway leakance, while episodic discharge can occur when permeability evolves under effective stress, sealing, and failure. A minimal analytical source–storage–pathway model is further derived, yielding explicit criteria for valve onset, source charging and discharge times, and the distinction between pressure-led and mass-led responses. The framework is then applied to the published Campi Flegrei carbon dioxide (${\mathrm{CO}}_2$) diffuse total output record, providing a real-data illustration of slow storage loading and rapid transient discharge. The analysis considers magmatic exsolution, hydrothermal mediation, metamorphic devolatilization, advective–diffusive near-surface filtering, and the inverse problem through which surface fluxes and gas compositions are used to infer deep source properties. The formulation links magmatic degassing, hydrothermal pressurization, tectonic fluid ascent, and fault-valve behavior within a common continuum-physics perspective and identifies the constitutive assumptions that most strongly control interpretation. Full article

Permeability is the key factor controlling coalbed methane (CBM) production, and hydraulic fracturing is an essential technique for permeability enhancement in low-permeability coal reservoirs. In situ stress plays a dominant role in both coal reservoir permeability evolution and hydraulic fracture propagation. By taking the Yangquan Mining Area in the northeastern Qinshui Basin, China, as the study area, this study integrated injection/falloff well testing and microseismic monitoring data to investigate the controlling effect of in situ stress on coal reservoir permeability and hydraulic fracture geometry. The results show that the in situ stress and reservoir pressure generally increase with burial depth. The measured maximum and minimum horizontal principal stresses ranged from 4.04 to 23.41 MPa and 3.72 to 13.24 MPa, with average values of 14.54 MPa and 8.64 MPa, respectively, while the vertical principal stress ranged from 6.50 to 19.87 MPa, averaging 13.31 MPa. The reservoir pressure ranged from 0.55 to 6.09 MPa, with an average value of 2.32 MPa. The lateral stress coefficient (λ) ranged from 0.45 to 1.68 (average of 0.89), exhibiting a pattern of dispersion in shallow strata and convergence in deeper strata. The regional stress regime is dominated by strike-slip faulting, with approximately 60.5% of the deeper measurement points characterized by σ_H > σ_v > σ_h. The coal seam permeability ranged from 0.03 to 15.52 mD, with an average value of 1.62 mD, and decreased exponentially with increasing effective stress. The controlling effect of the coal seam thickness on the permeability exhibited distinct segmented characteristics. The microseismic monitoring results from 23 hydraulic fracturing treatments indicate that approximately 74% of the fractures trended NE5–NE55°, consistent with the regional maximum horizontal principal stress direction. The fracture lengths ranged from 124.9 to 447.7 m, with an average of 344.7 m, while the fracture heights ranged from 12.9 to 79.09 m. All the induced fractures were predominantly vertical. A greater horizontal principal stress difference was associated with a lower permeability and promoted the formation of longer and more planar hydraulic fractures. These results demonstrate that the regional in situ stress field exerts significant control on both the coal reservoir permeability and hydraulic fracture morphology, providing important guidance for stress-based optimization of CBM development and hydraulic fracturing design. Full article

Long horizontal wells in high-permeability fault-block reservoirs may intersect multiple faults, leading to complex pressure-transient responses, strong parameter coupling in conventional well-test interpretation, inefficient manual history matching, and pronounced non-uniqueness in fault-property identification. To address these challenges, this study proposes a physics-regularized neural inversion framework based on a PINN parameterization and low-weight physics regularization for well-test parameter inversion in long horizontal wells intersecting multiple faults. The proposed method takes the multiple-fault pressure response of a long horizontal well as the target problem. Both the pressure–drawdown curve and the pressure–drawdown derivative curve are used as data constraints. At the same time, parameter scaling and stage-wise training are introduced to jointly invert the reservoir permeability, fault transmissibility coefficient, skin factor, and effective producing length of the horizontal well. Considering that the simplified line-source forward model is not fully consistent with the two-dimensional pressure-diffusion equation and the fault-interface residuals, a physics-loss consistency test is performed to determine safe weighting ranges for the PDE residual and the fault-interface residual. These residuals are then incorporated into the training process as low-weight physics regularization terms to improve the physical plausibility of the inversion results. Results from the base case, different fault types, multiple-fault combinations, noise-robustness tests, ablation experiments, and method comparisons show that the proposed method can stably fit pressure–drawdown and pressure–drawdown derivative curves and effectively identify key well-test parameters in single-fault cases and some multiple-fault cases. In single-fault cases, the order of magnitude of the fault transmissibility coefficient can be identified stably. Reliable inversion performance is obtained for medium- to high-transmissibility faults and some multiple-fault combinations. In contrast, ambiguity remains between sealing faults and strong-baffle faults in multiple low-transmissibility fault combinations. The results further indicate that, under multiple random initializations, the physics-regularized neural inversion framework provides improved inversion stability in the tested synthetic low-transmissibility multiple-fault cases compared with the traditional least-squares method. Therefore, the proposed framework can serve as an intelligent auxiliary tool for well-test parameter inversion and fault-connectivity evaluation in complex fault-block reservoirs. Nevertheless, fine discrimination of low-transmissibility faults and interpretation of highly noisy field data still require joint constraints from geological, seismic, and production-dynamic information. A preliminary reduced field PINN fitting test using the well X falloff event further provides an engineering-scale applicability check for real pressure-transient data, with a pressure NRMSE of 2.457% for the extracted shut-in response. Full article

To address core challenges involving severe reservoir heterogeneity, complex fracture systems, and rapid energy depletion encountered in the development of tight oil reservoirs in the G5 block of the Nanpu Sag, this study performs a systematic analysis of geological characteristics and optimizes an integrated geology–engineering development strategy. Through the integration of 3D seismic and well-logging data, the “sandwich-style” superposition architecture of sand bodies in the Es₃⁴ sub-member is quantitatively characterized. It reveals that productivity is co-controlled by high-quality main channel sand bodies (permeability: 0.5–1 mD) and high-density fracture zones (linear density: 3.2 fractures·m⁻¹) along structural ridges. Consequently, a comprehensive technical system is established, incorporating trajectory optimization for high-angle wells, differential stimulated reservoir volume (SRV) fracturing based on the Reservoir Quality Index (RQI), and CO₂ huff-n-puff for energy supplementation. Field applications demonstrate that optimized well placement increased the drilling encounter rate of high-quality reservoirs from 42% to 78%, while CO₂ huff-n-puff technology successfully restored the formation pressure coefficient from 0.65 to 0.82. The implementation of this integrated approach extended the stable production period of typical wells to 18 months, significantly mitigating production decline and increasing the ultimate recovery factor of the block to 14.5%, which provides a favorable recovery level for a complex fault-block tight oil reservoir compared with the generally low primary-recovery performance reported for analogous tight oil systems in rift-basin settings. This study confirms that the coupling zone of fracture systems along structural ridges and high-quality sand bodies represents the optimal target for economic development. The proposed geology–engineering synergy model provides a transferable technical paradigm for the efficient development of similar complex fault-block tight oil reservoirs. Full article

Underground fluid injection is regarded as one of the important factors inducing seismic activity. This study therefore proposes a method to predict the maximum damage area and seismic magnitude induced by fluid injection, in order to quantify the relationship between stress disturbances in faults and induced seismic activity during fluid injection. This method involves analysing a three-dimensional geological model of fault permeability evolution in order to define the seismic rupture zone of faults during fluid injection projects. It also involves calculating the maximum damage area and seismic magnitude induced by injection and verifying the method’s effectiveness using field data. The results show that, during deep injection, continuous injection of fluid reduces the effective stress on the fault and increases the fracture area. Following the sudden cessation of injection, the rupture area and maximum seismic magnitude reach their peak values. During the initial stage of injection, seismic magnitude increases rapidly with the rupture radius of the fault, while the growth rate of seismic magnitude decreases during the stable injection stage. Once injection has ceased, the rupture range and seismic magnitude will gradually stabilise throughout the entire geological self-balancing stage. Periodic injection results in the largest fault rupture area, whereas linear growth injection induces the highest seismicity. Strike-slip faults exhibit the most significant increase in rupture area, whereas normal faults demonstrate more intense seismicity evolution. Low permeability, proximity to injection wells and direct well closure exacerbate instability, whereas linear slow closure is the safest option. These research results can inform seismic risk management in fluid injection engineering. Full article

This paper presents an integrated approach to the mapping and structural-tectonic interpretation of lineaments in the Mangystau region using multispectral Landsat-8 OLI data and the medium-resolution Airbus WorldDEM4Ortho digital elevation model. Automatic extraction of linear structures has enabled the identification of over 35,000 lineaments of varying length and orientation, forming a network of intersecting zones that influence the distribution of sedimentary thicknesses, drainage directions, and the location of karst-suffosion depressions. The most prominent are the north-western and sub-latitudinal systems, closely correlated with zones of fracturing and faults, which confirms their tectonic origin. The spatial concentration of lineaments coincides with areas of increased permeability in carbonate and gypsum-bearing rocks and localizes the pathways of groundwater circulation, contributing to the development of karst-suffosion processes. The obtained results demonstrate the significance of structural influences on the region’s current geomorphological and hydrogeological conditions and also have practical importance for engineering-geological surveys, the assessment of geological risks, and the planning of sustainable land use. Full article

Radon (²²²Rn) and thoron (²²⁰Rn) are widely used to investigate diffuse degassing, fault-zone permeability, hydrothermal circulation, and subsurface unrest, but their signals are not direct proxies for a single process. This manuscript is a critical synthesis and methodological article that develops a reduced inference framework for interpreting radon–thoron observations in volcanic, tectonic, and hydrothermal settings. The framework separates accessible support of the immediate radium parents ²²⁶Ra and ²²⁴Ra, recoil-scale release into the mobile phase, multiphase transport, geological carrier-gas throughput, and observational closure. It also distinguishes total activity flux from activity concentration and chamber throughput from natural carrier-gas dilution. Synthetic illustrative experiments test the internal behavior of the reduced operator; a concise re-reading of the public Upper Rhine Graben dataset illustrates the limits of concentration-only inference; and published volcanic and hydrothermal examples are used as literature-grounded vignettes. The purpose is not to validate a universal inversion model but to define what can be inferred from different observation packages. The paper, therefore, emphasizes three operational levels: anomaly reporting, mechanism discrimination, and local inversion. Full article

The Quemocuo area in the Qiangtang Basin is a key prospect for permafrost gas hydrate exploration in China. This study investigates source-reservoir-caprock characteristics and their control on gas hydrate accumulation based on drilling results from wells QK-8 and QK-9, integrated with multiple analytical methods. Two high-quality marine source rocks with cumulative thickness ~1000 m exhibit TOC values of 0.74–2.5%, Type II₂ kerogen, and vitrinite reflectance (Ro) of 1.37–2.94%, indicating high to over-mature thermal evolution primarily generating dry thermogenic methane. Gas logging shows hydrocarbon anomalies with a maximum desorbed gas content of 90 mL, confirming strong gas generation capacity. Although reservoir matrix properties are poor (porosity mostly <5%, permeability < 0.2 × 10⁻³ μm²), multi-phase tectonics and dissolution formed a secondary fracture-vug system. Permafrost conditions are favorable (thickness 100–120 m; geothermal gradient 4.5–4.7 °C/100 m), with extremely low permeability at high ice saturations, forming an effective multi-level seal together with thick mudstones. A key novel finding is the significant mixing of biogenic and thermogenic gases, with the biogenic component interpreted to originate from overlying Jurassic-Quaternary low-maturity strata, facilitated by late tectonic uplift and fault conduits. NW-trending faults connect deep thermogenic reservoirs and provide pathways for shallow biogenic gas migration. For the first time, this study establishes a region-specific composite accumulation model for the Qiangtang Basin, characterized by “lower generation and upper storage, fault-fracture conduit and permafrost sealing”, which reveals fault-controlled migration, fracture-vug-controlled storage, permafrost-controlled sealing, and mixed gas enrichment under a high geothermal gradient. Full article

The reservoir quality and gas-bearing properties of the Wufeng Formation–Longmaxi Formation shale vary significantly across different structural units in the Luzhou area of the Sichuan Basin. The mechanisms of shale gas enrichment, tectonic controls, and accumulation models are critical determinants of the potential for three-dimensional (3D) development. Integrating data from core analyses, logging interpretation, focused ion beam scanning electron microscopy (FIB-SEM), and high-resolution core scanning, this study investigates the control exerted by fracture development and tectonic activity on shale gas enrichment and preservation. A conceptual model for shale gas enrichment and accumulation is established, and the potential for 3D development of deep shale gas in the Luzhou block is evaluated. The results indicate that: (1) Reservoir heterogeneity in deep shale gas plays is jointly governed by reservoir space characteristics, diagenesis, structural position, tectonic evolution, and fracture-fluid activity. Organic-rich siliceous shales retain favorable reservoir properties, characterized by an organic matter (OM) pore-dominated pore structure, relatively high porosity and permeability, and good gas-bearing potential due to overpressure preservation. (2) Structural style exerts dominant control over the gas-bearing variability. Synclines are significantly more favorable than anticlines, with free gas migration governing the enrichment pattern. The cores and flanks of synclines form zones of high gas content due to structural integrity, whereas the gas content decreases in anticlinal areas near faults. (3) Shale gas enrichment relies on the synergistic configuration of “high organic carbon content + high-quality pore reservoir space + robust structural preservation conditions.” Well L213 in the syncline core, distant from faults, exhibits good structural integrity and preservation conditions. Free gas from structurally lower positions migrates laterally toward the flanking anticlines, with a portion preserved in the syncline flanks. Concurrently, microfractures enhance reservoir storage and permeability, rendering syncline structures more conducive to shale gas preservation. (4) The high-quality shale succession in the study area is thick and laterally continuous, characterized by “vertical stacked pay zones.” This provides an excellent geological foundation for 3D development. By optimizing the well trajectory design and employing efficient fracturing technologies, such as “intensive fracturing” combined with temporary plugging and diversion, full and balanced utilization of vertically stacked sweet spot reservoirs can be achieved, significantly enhancing the single-well productivity and estimated ultimate recovery (EUR). Full article

The delineation of the Area of Review (AoR) is a fundamental requirement for Class VI carbon storage permits in the United States. The regulatory definition of the pressure front relies on the potential for injected fluids or formation brine to migrate into an Underground Source of Drinking Water (USDW). However, in deep sedimentary basins such as the Texas Gulf Coast and offshore regions, targeted saline formations often lack overlying USDWs. In these scenarios, traditional methods for calculating the critical pressure threshold become mathematically undefined or yield infinite AoR boundaries. This paper proposes a practical, geomechanics-based methodology for defining the pressure front in the absence of a USDW, framed as an alternative site-specific approach under the authority of the UIC Program Director (40 CFR 146.84). By leveraging existing regulatory limits on injection pressure, the proposed framework establishes a threshold based on the minimum horizontal stress, caprock fracture pressure, and fault reactivation limits via Mohr–Coulomb failure analysis. The framework further incorporates capillary breakthrough pressure as a third containment threshold, ensuring that the most restrictive condition governs the AoR boundary. A synthetic case study of a deep Gulf Coast saline formation demonstrates that this approach produces a finite, physically meaningful AoR that scales appropriately with injection operations (evaluated at 1.0 and 2.0 Mt/yr) and captures post-injection pressure evolution during the Post-Injection Site Care (PISC) period. Sensitivity analyses on permeability and fracture gradients confirm the robustness of the method. The study also examines model limitations, injection feasibility boundaries, and extensions toward a probabilistic framework. This framework provides operators and regulators with a defensible, regulatory-consistent pathway for advancing carbon storage projects in deep sedimentary basins, complete with a standardized reviewer checklist and an example AoR delineation report template. Full article

The coal resource-rich areas in Guizhou Province are located at the overlapping junction of the southern part of the third fold and subsidence zones of the Neocathaysian structural system and the Nanling latitudinal structural belt. These areas are characterized by well-developed folds and faults, complex coal seam structures, high in situ stress, and poor air permeability, which lead to low-efficiency conventional gas drainage and failure to achieve the expected results. In terms of enhancing coal seam permeability and improving gas drainage and utilization, research is urgently needed on the permeability enhancement mechanism of deep-hole blasting in outburst-prone coal seams under combined multi-stress action. By analyzing the influence law of coal mass fracture evolution before and after blasting, developing an experimental device for blasting permeability enhancement under combined multi-stress action, and conducting research on the pore variation law of coal mass before and after blasting, it is found that in situ stress is negatively correlated with coal mass pores, while blasting and gas stresses are positively correlated with pores. This study provides a theoretical basis and experimental evidence for permeability enhancement via deep-hole blasting in outburst-prone coal seams and further supports the selection of reasonable parameters for field tests to improve the gas drainage efficiency of outburst-prone coal seams. Full article

Fault-controlled reservoirs are characterized by strong heterogeneity and diverse flow types. Existing water-coning calculation methods cannot accurately describe the complex oil–water distribution within reservoirs exhibiting a distinct “core–damage zone” architecture. To address this limitation, the main goal of this study is to develop a zonal water-coning calculation framework tailored to these highly heterogeneous structures. Methodologically, the Forchheimer equation is utilized to describe the entire reservoir system, with region-specific simplifications applied based on dominant flow mechanisms: in the high-velocity core zone, the viscous term is ignored; in the low-velocity damage zone, the inertial term is neglected; and the transition zone employs the complete Forchheimer formulation. The results indicate that the water-coning curves in the core and transition zones are significantly steeper as the radial distance decreases compared to the damage zone. Specifically, in a field application at the Fuman Oilfield, the calculated theoretical critical production rate of the core zone (5.39 × 10⁻² m³/s) is three orders of magnitude higher than that of the damage zone (1.45 × 10⁻⁵ m³/s). In conclusion, this massive zonal disparity demonstrates the severe bottleneck effect of the high-permeability core under a unified wellbore pressure drawdown, theoretically validating the necessity of deploying segmented completions and targeted water-control strategies to prevent premature water breakthrough. Full article

The steady operation of underground gas storage (UGS) is significant for securing national energy. However, long-term cyclic injection-production operation causes the dynamic changes in formation stress, potentially leading to fault reactivation and slippage. This could affect the seal performance of the fault zone and cause disastrous consequences. In this paper, a mechanical analysis model for fault slip is constructed to study the dynamic seal performance in response to long-term injection-production cycles. An intelligent approach is proposed to predicate the fault slip value based on machine learning algorithms. It can realize long-term prediction of fault slip value under a new condition of injection-production operation. The study shows that (1) formation pressure tends to accumulate near the fault zone due to the low permeability, and the interface of the reservoir layer, cap layer, and fault zone is the seal weak position of UGS; (2) the response of fault slip is driven by the injection-production rate and the reservoir pressure. There is a significant coupling relationship between the fault slip value and the accumulated injection gas volume; (3) the intelligent prediction approach can capture the nonlinear dynamic characteristics of slip tendency accurately, and it exhibits good prediction performance and generalization ability under the new operating condition. This study effectively assesses the dynamic risk for fault slip of depleted hydrocarbon reservoir UGS during the long-term injection-production procedure. It provides an effective technical approach for fault slip tendency analysis and injection-production process optimization, which is important for the sustainable operation of UGS reducing the risk of seal failure and supporting gas storage security. Full article