Search Results (65)

The Muji Fault Zone (MJF) in the northeastern Pamir Plateau hosts a well-developed non-volcanic geothermal system, characterized by widespread hot springs and mud volcanoes—where core processes of geothermal fluids, including atmospheric precipitation recharge, shallow crustal circulation, carbonate-driven water–rock interactions, and CO₂-rich fluid discharge, are tightly coupled with regional intense crustal deformation and frequent seismic activity. We collected and analyzed 22 geothermal water samples and 8 bubbling gas samples from the MJF periphery, finding that the geothermal waters are predominantly of the HCO₃-Ca·Mg hydrochemical type, with hydrogen (δD: −103.82‰ to −70.21‰) and oxygen (δ¹⁸O: −14.89‰ to −10.10‰) isotopes indicating atmospheric precipitation as the main recharge source. The Na-K-Mg ternary diagram classified the waters as immature, reflecting low-temperature water–rock interactions in the shallow crust (<3 km), while noble gas isotopes (³He/⁴He: 0.03–0.09 Ra, Ra = 1.43 × 10⁻⁶) and carbon isotopes (δ¹³C-CO₂) confirmed fluid origin from crustal carbonate dissolution; SiO₂ geothermometry estimated thermal reservoir temperatures at 67–155 °C. Long-term monitoring (May 2019–April 2024) of Tahman (THM) and Bulake (BLK) springs revealed significant pre-seismic anomalies: before the 2023 Tajikistan Ms7.2 and 2024 Wushi Ms7.1 earthquakes, Na⁺, Cl⁻, and SO₄²⁻ concentrations showed notable negative anomalies (exceeding 2σ of background values) with synchronous trends between the two springs. Integrating these findings, a “Fault-Spring-Mud Volcano-Earthquake” fluid response model was established, providing direct evidence of deep-shallow fluid coupling in mud volcano–geothermal fluid interactions. This study enhances understanding of the dynamic evolution of non-volcanic geothermal systems under tectonic stress and clarifies the mechanisms of hydrogeochemical variations in fault-controlled geothermal systems, offering a robust scientific basis for advancing research on tectonic–fluid interactions in active fault zones of the northeastern Pamir Plateau. Full article

Carbon dioxide (CO₂), a major greenhouse gas, contributes significantly to global warming and environmental degradation. Carbon Capture, Utilization, and Storage (CCUS) is a promising strategy to mitigate atmospheric CO₂ levels. One widely applied utilization approach involves injecting captured CO₂ into depleted oil reservoirs to enhance oil recovery—a technique known as CO₂-Enhanced Oil Recovery (CO₂-EOR). The effectiveness of CO₂-EOR largely depends on complex rock–fluid interactions, including mass transfer, wettability alteration, capillary pressure, and interfacial tension (IFT). Various factors, such as the presence of asphaltenes, salinity, pressure, temperature, and rock type, influence these interactions. This review explores the impact of these parameters on the IFT between CO₂ and oil/water systems, drawing on findings from both experimental studies and molecular dynamics (MD) simulations. The literature indicates that increased temperature, reduced pressure, lower salinity, and the presence of asphaltenes tend to reduce IFT at the oil–water interface. Similarly, elevated temperature and pressure, along with asphaltene content, also lower the surface tension between CO₂ and oil. Most MD simulations employ synthetic oil mixtures of various alkanes and use tools such as LAMMPS and GROMACS. Experimentally, the pendant drop method is most commonly used with crude oil and brine samples. Future research employing actual reservoir fluids and alternative measurement techniques may yield more accurate and representative IFT data, further advancing the application of CO₂-EOR. Full article

Shale gas wastewater from hydraulic fracturing poses significant environmental risks due to its high salinity and complex inorganic composition. This study investigates the behavior of major and trace inorganic constituents across a full-scale treatment train in the Sichuan Basin, China. Despite multi-stage processes including equalization, flocculation, flotation, biological reactors, membrane filtration, and clarification, key inorganic species such as Cl, Na, Br, Sr, Li, and B remained largely persistent in the final effluent with values of 13,760, 8811, 70, 95.9, 26.6, and 60.2 mg/L, respectively. Geochemical tracers including Br/Cl (average: 0.0022 mM/mM), Na/Br (average: 125 mg/mg), and Sr/Ca (average: 0.15 mM/mM) ratios, combined with halide endmember mixing models, revealed that salinity primarily originated from highly evaporated formation brines, with limited evidence for halite dissolution or external contamination. Elevated Sr (average: 89.3 mg/L) and Ca (average: 274 mg/L) levels relative to Mg (average: 32 mg/L) suggest significant water–rock interaction. Environmental risk assessments showed that concentrations of several elements in treated effluent greatly exceeded national and international discharge or reuse standards. These findings underscore the limitations of conventional treatment technologies and highlight the urgent need for advanced processes and regulatory frameworks that address the unique challenges of high-TDS (total dissolved solids) unconventional wastewater. Full article

Supercritical CO₂ (ScCO₂) injection has emerged as a promising method to enhance shale gas recovery while simultaneously achieving CO₂ sequestration. This research investigates how ScCO₂ interacts with water and shale rock, altering the pore structure characteristics of shale reservoirs. The study examines shale samples from three marine shale formations in southern China under varying thermal and pressure regimes simulating burial conditions at 1000 m (45 °C and 10 MPa) and 2000 m (80 °C and 20 MPa). The research employs multiple analytical techniques including XRD for mineral composition analysis, MICP, N₂GA, and CO₂GA for comprehensive pore characterization, FE–SEM for visual observation of mineral and pore changes, and multifractal theory to analyze pore structure heterogeneity and connectivity. Key findings indicate that ScCO₂–water–shale interactions lead to dissolution of minerals such as kaolinite, calcite, dolomite, and chlorite, and as the reaction proceeds, substantial secondary mineral precipitation occurs, with these changes being more pronounced under 2000 m simulation conditions. Mineral dissolution and precipitation cause changes in pore structure parameters of different pore sizes, with macropores showing increased PV and decreased SSA, mesopores showing decreased PV and SSA, and micropores showing insignificant changes. Moreover, mineral precipitation effects are stronger than dissolution effects. These changes in pore structure parameters lead to alterations in multifractal parameters, with mineral precipitation reducing pore connectivity and consequently enhancing pore heterogeneity. Correlation analysis further revealed that H and D₋₁₀–D₁₀ exhibit a significant negative correlation, confirming that reduced connectivity corresponds to stronger heterogeneity, while mineral composition strongly controls the multifractal responses of macropores and mesopores, with micropores mainly undergoing morphological changes. However, these changes in micropores are mainly manifested as modifications of internal space. Siliceous shale samples exhibit stronger structural stability compared to argillaceous shale, which is attributed to the mechanical strength of the quartz framework. By integrating multifractal theory with multi–scale pore characterization, this study achieves a unified quantification of shale pore heterogeneity and connectivity under ScCO₂–water interactions at reservoir–representative pressure–temperature conditions. This novelty not only advances the methodological framework but also provides critical support for understanding CO₂–enhanced shale gas recovery mechanisms and CO₂ geological sequestration in depleted shale gas reservoirs, highlighting the complex coupling between geochemical reactions and pore structure evolution. Full article

This study investigates geothermal clusters in the middle reaches of the Dawen River Basin, focusing on the developmental characteristics and genetic mechanisms of typical geothermal water exposures at key sites, including Daidaoan (Taishan), Qiaogou (Culai Town), and Anjiazhuang (Feicheng). Utilizing hydrogeochemical and environmental isotope analyses, we identify a dual groundwater recharge mechanism: (1) rapid infiltration via preferential flow through fissure media and (2) slow seepage with evaporative loss along gas-bearing zones. Ion sources are influenced by water–rock interactions and positive cation exchange. The hydrochemical types of surface water and geothermal water can be divided into five categories, with little difference within the same geothermal area. The thermal reservoir temperatures range from 53.54 to 101.49 °C, with the Anjiazhuang and Qiaogou geothermal areas displaying higher temperatures than the Daidaoan area. Isotope calculations indicate that the recharge elevation ranges from 2865.76 to 4126.69 m. The proportion of cold water mixed in the shallow part is relatively large. A comparative analysis of the genetic models of the three geothermal water groups shows that they share the common feature of being controlled by fault zones. However, they differ in that the Daidao’an geothermal area in Mount Tai is of the karst spring type with a relatively low geothermal water temperature, whereas the Qiaogou geothermal area in Culai Town and the Anjiazhuang geothermal area in Feicheng are of the gravel or sandy shale spring types with a relatively high geothermal water temperature. Full article

The dynamic process of water depletion plays a critical role in both surface coalbed methane (CBM) development and underground gas extraction, reshaping water–rock interactions and inducing complex permeability responses. Addressing the limited understanding of the coupling mechanism between heterogeneous pore water evolution and permeability during dynamic processes, this study simulates reservoir transitions across four zones (prospective planning, production preparation, active production, and mining-affected zones) via centrifugal experiments. The results reveal a pronounced scale dependence in pore water distribution. During low-pressure stages (0–0.54 MPa), rapid drainage from fractures and seepage pores leads to a ~12% reduction in total water content. In contrast, high-pressure stages (0.54–3.83 MPa) promote water retention in adsorption pores, with their relative contribution rising to 95.8%, forming a dual-structure of macropore drainage and micropore retention. Multifractal analysis indicates a dual-mode evolution of movable pore space. Under low centrifugal pressure, D₋₁₀ and Δα decrease by approximately 34% and 36%, respectively, reflecting improved connectivity within large-pore networks. At high centrifugal pressure, an ~8% increase in D₀−D₂ suggests that pore-scale heterogeneity in adsorption pores inhibits further seepage. A quantitative coupling model establishes a quadratic relationship between fractal parameters and permeability, illustrating that permeability enhancement results from the combined effects of pore volume expansion and structural homogenization. As water saturation decreases from 1.0 to 0.64, permeability increases by more than 3.5 times. These findings offer theoretical insights into optimizing seepage pathways and improving gas recovery efficiency in dynamically evolving reservoirs. Full article

The methane flux in the Dongsha area in the northern South China Sea is relatively high. The results indicate the presence of both shallow and deep gas hydrate reservoirs at the Site DS-W08. The gas hydrate reservoir in this area is mainly composed of fine-grained sediments, and high-saturation gas hydrates are present. The shallow-GHR (8–24 mbsf) exhibits a maximum hydrate saturation of 14% (pore volume). The deep-GHR (below 65 mbsf) shows a maximum hydrate saturation of 33% The suspended sedimentation process on the banks of turbidity currents and the deep-water traction current sedimentation process play potentially important roles in the enrichment of gas hydrates. To investigate the influence of sedimentary processes on gas hydrate accumulation, this study analyzed gas hydrate saturation, sediment grain size, grain compositions, biological components, and geochemical characteristics of hydrate-bearing and adjacent layers at Site DS-W08. Sediment grain size analysis suggests that the studied layer was formed through the interaction of turbidity current-induced overbank suspended deposition and traction current deposition. By comprehensively analyzing the comparison of sediment Sr/Ba ratios and the data of foraminifera and calcareous nannofossils, it is found that the bank deposits and traction current deposits triggered by turbidity currents correspond to glacial periods and interglacial periods, respectively. Analysis of biological components shows that layers with high foraminifera content and traction current-modified sediments are more favorable for gas hydrate accumulation. Hydrate reservoirs are all composed of traction current deposits, and the cap rock rich in foraminifera fossils at the top promotes hydrate formation; while the fine-grained turbidites formed during the turbidite deposition process inhibit hydrate accumulation. This study aims to deepen the understanding of the enrichment mechanism of natural gas hydrates and support the commercial development of fine-grained sediments in the northern South China Sea. Full article

The gas–water relative-permeability relationship in tight gas is complex due to interactions between the gas and water phases within the porous media in the reservoir. To clarify the fluid occurrence and the gas–water relative-permeability behavior in such reservoirs, the Dongsheng tight water-bearing reservoir from the Ordos Basin of China is taken as the research object. A non-steady state method is employed to explore the co-permeability of gas and water phases under dynamic conditions. The irreducible water saturation of different core samples is analyzed using nuclear magnetic resonance (NMR) centrifugation. The Simplified Stone equation is applied for phase permeability normalization. The results indicate that with the decrease in core permeability, the irreducible water saturation increases, and the gas and water permeability decreases. When the displacement pressure difference increases, the gas phase permeability decreases, and the water phase permeability increases. The centrifugal method is effective in reducing the saturation of bound water in rock cores. The displacement method forms channels using gas, which effectively removes free water, particularly in larger or smaller pores. In contrast, centrifugation further displaces water from smaller or capillary pores, where flow is more restricted. Based on these experimental findings, a relationship between displacement pressure difference, critical irreducible water saturation, and residual gas saturation is established. The Stone equation is further refined, and a phase permeability normalization curve is proposed, accounting for the true irreducible water saturation of rock. This provides a more accurate theoretical framework for understanding and managing the gas–water interaction in tight gas reservoirs with a high water content, ultimately aiding in the optimization of reservoir development strategies. Full article

On 23 January 2024, a M_S7.1 earthquake struck Wushi County, Xinjiang Uygur Autonomous Region, marking the largest seismic event in the Southern Tianshan (STS) region in the past century. This study investigates the relationship between hydrothermal fluid circulation and seismic activity by analyzing the chemical composition and origin of fluids in natural hot springs along the Maidan Fracture (MDF). Results reveal two distinct hydrochemical water types (Ca-HCO₃ and Ca-Mg-Cl). The δD and δ¹⁸O values indicating spring water are influenced by atmospheric precipitation input and altitude. Circulation depths (621–3492 m) and thermal reservoir temperatures (18–90 °C) were estimated. Notably, the high ³He/⁴He ratios (3.71 Ra) and mantle-derived ³He content reached 46.48%, confirming that complex gas–water–rock interactions occur at fracture intersections. Continuous monitoring at site S13 (144 km from the epicenter of the Wushi M_S7.1 earthquake) captured pre-and post-seismic hydrogeochemical fingerprints linked to the Wushi MS7.1 earthquake. Stress accumulation along the MDF induced permeability changes, perturbing hydrogeochemical equilibrium. At 42 days pre-Wushi M_S7.1 earthquake, δ¹³C DIC exceeded +2σ thresholds (−2.12‰), signaling deep fracture expansion and CO₂ release. By 38 days pre-Wushi M_S7.1 earthquake, Na⁺, SO₄²⁻, and δ¹⁸O surpassed 2σ levels, reflecting hydraulic connection between deep-seated and shallow fracture networks. Ion concentrations and isotope values showed dynamic shifts during the earthquake, which revealed episodic stress transfer along fault asperities. Post-Wushi M_S7.1 earthquake, fracture closure reduced deep fluid input, causing δ¹³C DIC to drop to −4.89‰, with ion concentrations returning to baseline within 34 days. Trace elements such as Be and Sr exhibited anomalies 12 days before the Wushi M_S7.1 earthquake, while elements like Li, B, and Rb showed anomalies 24 days after the Wushi M_S7.1 earthquake. Hydrochemical monitoring of hot springs captures such critical stress-induced signals, offering vital insights for earthquake forecasting in tectonically active regions. Full article

This study investigates the microscopic structural changes and the evolution of physical properties in typical shale samples from three wells in southwestern China during water–rock interactions. Using scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and other techniques, we analyzed the changes in pore structure, mineral dissolution behavior, and fracture propagation in shale samples of different types (organic-rich, mixed, and inorganic) during water immersion. The results show that water–rock interaction significantly affects the porosity, fracture width, and physical properties of shale. As the reaction time increases, the pore volume and number of pores generally increase in all shale types, with significant fracture propagation. Furthermore, fracture width changes exhibit varying trends depending on the reaction depth. NMR T2 spectrum analysis indicates that water–rock interaction not only influences the expansion of microfractures but also shows different responses in organic and inorganic pores. SEM images further reveal the impact of water–rock interaction on mineral dissolution, particularly during the early stages, where the dissolution of minerals significantly alters the pore structure. Overall, water–rock interaction plays a crucial role in the development of shale gas reservoirs, providing valuable data and theoretical support for future shale gas extraction. Full article

Investigations carried out on 72 fluid samples from 59 sites spread over the area surrounding the Sea of Marmara show that their geochemical and isotopic features are related to different segment settings of the North Anatolian Fault Zone (NAFZ). We collected fluids from thermal and mineral waters including bubbling and dissolved gases. The outlet temperatures of the collected waters ranged from 14 to 97 °C with no temperature-related geochemical features. The free and dissolved gases are a mixture of shallow and mantle-derived components. The large variety of geochemical features comes from intense gas–water (GWI) and water–rock (WRI) interactions besides other processes occurring at relatively shallow depths. CO₂ contents ranging from 0 to 98.1% and helium isotopic ratios from 0.11 to 4.43 Ra indicate contributions, variable from site to site, of mantle-derived volatiles in full agreement with former studies on the NAFZ. We propose that the widespread presence of mantle-derived volatiles cannot be related only to the lithospheric character of the NAFZ branches and magma intrusions have to be considered. Changes in the vertical permeability induced by fault movements and stress accumulation during seismogenesis, however, modify the shallow/deep ratio of the released fluids accordingly, laying the foundations for future monitoring activities. Full article

Research on the multi-field coupling effects in rocks has been ongoing for several decades, encompassing studies on single physical fields as well as two-field (TH, TM, HM) and three-field (THM) couplings. However, the environmental conditions of rock masses in deep resource extraction and underground space development are highly complex. In such settings, rocks are put through thermal-hydrological-mechanical-chemical (THMC) coupling effects under peak temperatures, strong osmotic pressures, extreme stress, and chemically reactive environments. The interaction between these fields is not a simple additive process but rather a dynamic interplay where each field influences the others. This paper provides a comprehensive analysis of fragmentation evolution, deformation mechanics, mechanical constitutive models, and the construction of coupling models under multi-field interactions. Based on rock strength theory, the constitutive models for both multi-field coupling and creep behavior in rocks are developed. The research focus on multi-field coupling varies across industries, reflecting the diverse needs of sectors such as mineral resource extraction, oil and gas production, geothermal energy, water conservancy, hydropower engineering, permafrost engineering, subsurface construction, nuclear waste disposal, and deep energy storage. The coupling of intense stress, fluid flow, temperature, and chemical factors not only triggers interactions between these fields but also alters the physical and mechanical properties of the rocks themselves. Investigating the mechanical behavior of rocks under these conditions is essential for averting accidents and assuring the soundness of engineering projects. Eventually, we discuss vital challenges and future directions in multi-field coupling research, providing valuable insights for engineering applications and addressing allied issues. Full article

This study employs logging, petrology, and geochemistry to investigate the characteristics, origin, and hydrocarbon significance of fractures and (ferro) dolomite veins in a buried hill in the Qiongdongnan (QDN) Basin, South China Sea. We show that the study area is mainly characterized by three stages of fracturing with medium-high dipping angles. The orientation of the fractures is mainly NNW–SSE, consistent with the fault system strike formed by the Mesozoic–Cenozoic tectonic activity in the basin. (Ferro) dolomite veins in the fractures can be classified into three stages, all of which can be even observed in individual fractures. The first stage is the powdery crystal dolomite veins grown mainly on the fracture surface, which have the highest strontium isotope values, as well as high contents of the Mg element and extremely low contents of the Fe and Mn elements. The first-stage veins were formed in a relatively open oxidized environment, and the vein-forming fluids exhibit characteristics of mixing formation water and atmospheric freshwater within the fractures. The second stage, involving fine-crystal dolomite veins, was formed in a buried diagenetic environment where groundwater mixed with deep hydrothermal fluids, and contained the highest carbon isotope values, more Fe and Mn elements, and less Mg element than the first stage. The third stage of medium-crystal ankerite veins was formed in the latest stage, with the lowest strontium and oxygen isotope values. This was mainly a result of deep hydrothermal formation in which the rock-forming material formed from the interaction between the hydrothermal fluid and the iron-rich and aluminosilicate minerals in the surrounding granite of the fractures. We conclude that the multi-phase tectonic movements form a massive scale reticulated fracture inside the granite buried hill, which effectively improves the physical condition of the gas reservoirs. The gas reservoirs remain of high quality, despite the filling of the three stages of (ferro) dolomite veins. Full article

CO₂–water–rock interactions have an important impact on the stability and integrity of the caprock in CO₂ geological storage projects. The injected CO₂ in the reservoir enters the caprock via different mechanisms, leading to either the dissolution or precipitation of minerals. The mineral alterations change the porosity, permeability, and mechanical properties of the caprock, affecting its sealing capability. To evaluate the sealing effectiveness of overlying caprock and identify the influencing factors, numerical simulations and experiments were carried out on the mudstone Dongying Formation in Dezhou, China. Based on high-temperature and high-pressure autoclave experiments, batch reaction simulations were performed to obtain some key kinetic parameters for mineral dissolution/precipitation. Then, they were applied to the following simulation. The simulation results indicate that gaseous CO₂ has migrated 7 m in the caprock, while dissolved CO₂ migrated to the top of the caprock. Calcite is the dominant mineral within 1 m of the bottom of the caprock. The dissolution of calcite increases the porosity from 0.0625 to 0.4, but the overall porosity of the caprock decreases, with a minimum of 0.054, mainly due to the precipitation of montmorillonite and K-feldspar. A sensitivity analysis of the factors affecting the sealing performance of the caprock considered the changes in sealing performance under different reservoir sealing conditions. Sensitivity analysis of the factors affecting the sealing performance of the caprock indicates that the difference in pressure between reservoir and caprock affects the range of CO₂ transport and the degree of mineral reaction, and the sealing of the caprock increases with the difference in pressure. Increasing the initial reservoir gas saturation can weaken the caprock’s self-sealing behavior but shorten the migration distance of CO₂ within the caprock. When the content is lower than 2%, the presence of chlorite improves the sealing performance of the caprock and does not increase with further chlorite content. This study elucidates the factors that affect the sealing ability of the caprock, providing a theoretical basis for the selection and safety evaluation of CO₂ geological storage sites. Full article

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods. Full article