Search Results (58)

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

In carbonate reservoirs, nanoparticles can adhere to rock surfaces, potentially altering the rock wettability and modifying the absolute permeability. In the water-alternating-gas (WAG) process, the introduction of nanoparticles into the water phase, termed nano-water-alternating gas (NWAG), is a promising approach for enhancing oil recovery and CO₂ storage. The NWAG process can alter rock wettability and absolute permeability through the adsorption of nanoparticles on the rock surface. This study investigated the efficiency of the NWAG method, which utilizes nanofluids in CO₂-enhanced oil recovery (EOR) processes to simultaneously recover oil and store CO₂ using 1D core and 3D heterogeneous reservoir models. The simulation results of the 1D core model showed that applying the NWAG method enhanced both oil recovery and CO₂ storage efficiency by increasing to 3%. In a 3D reservoir model, a Dykstra–Parsons coefficient of 0.4 was selected to represent reservoir heterogeneity. Additionally, the capillary trapping of CO₂ during WAG injection was computed using Larsen and Skauge’s three-phase relative permeability hysteresis model. A sensitivity analysis was performed using the NWAG ratio, slug size, injection period, injection cycle, and nanofluid concentration. The results confirmed an increase of 0.8% in oil recovery and 15.2% in CO₂ storage compared with the conventional WAG process. This mechanism suggests that nanofluids can enhance oil recovery and expand CO₂ storage, improving the efficiency of both the oil production rate and CO₂ storage compared to conventional WAG methods. Full article

The geochemical properties of fracturing flowback fluids indirectly indicate the fracturing efficiency of the reservoir, the interaction between the reservoir and injected water, and the preservation of oil and gas, thereby offering robust data support for identifying fracturing flowback fluid sources, assessing fracturing effects, and proposing stimulation strategies. In this study, the ion characteristics, total salinity, and stable isotope ratio of fracturing flowback fluids of the Z202H1 and Z203 wells in Western Chongqing were measured. The findings suggest that with the extension of flowback time, the geochemical properties of fracturing flowback fluids evolve toward higher salinity and heavier stable isotope ratios, ultimately stabilizing. Upon comparing the water–rock reaction intensity and the rate of total salinity increase in the fracturing flowback fluids, it is concluded that fracturing flowback fluids contain a mixture of formation water. Because water–rock reactions elevate the total salinity of fracturing flowback fluids, we introduce the Water–Rock Reaction Intensity Coefficient (I_R) to denote the intensity of these reactions. Based on the I_R value, the binary mixture model for fracturing fluids in fracturing flowback fluids was adjusted. With the increase in flowback time, the content of fracturing fluids in fracturing flowback fluids of Z202H1 and Z203 stabilized at about 55% and 40% respectively. During the same flowback period, the fracturing flowback fluids of the Z203 well exhibit a higher total salinity, a heavier stable isotope ratio, a greater I_R, and a lower fracturing fluid content in fracturing flowback fluids. This suggests that the fracturing effect of the Z203 well is superior to that of the Z202H1 well, leading to a higher production capacity of the Z203 well. Full article

Using geochemical and pumping test data from 80 groundwater wells, the chemical, hydrologic, and hydraulic properties of the fractured Eocene carbonate aquifer located west of the Al-Minya district, the Western Desert, Egypt, have been characterized and determined to guarantee sustainable management of groundwater resources under large-scale desert reclamation projects. The hydrochemical data show that groundwater from the fractured Eocene carbonate aquifer has a high concentration of Na⁺ and Cl⁻ and varies in salinity from 2176 to 2912 mg/L (brackish water). Water–rock interaction and ion exchange processes are the most dominant processes controlling groundwater composition. The carbonate aquifer exists under confined to semi-confined conditions, and the depth to groundwater increases eastward. From the potentiometric head data, deep-seated faults are the suggested pathways for gas-rich water ascending from the deep Nubian aquifer system into the overlying shallow carbonate aquifer. This mechanism enhances the dissolution and karstification of carbonate rocks, especially in the vicinity of faulted sites, and is supported by the significant loss of mud circulation during well drilling operations. The average estimated hydraulic parameters, based on the analysis of step-drawdown, long-duration pumping and recovery tests, indicate that the Eocene carbonate aquifer has a wide range of transmissivity (T) that is between 336.39 and 389,309.28 m²/d (average: 18,405.21 m²/d), hydraulic conductivity (K) between 1.31 and 1420.84 m/d (average: 70.29 m/d), and specific capacity (Sc) between 44.4 and 17,376.24 m²/d (average: 45.24 m²/d). On the other hand, the performance characteristics of drilled wells show that well efficiency ranges between 0.47 and 97.08%, and well losses range between 2.92 and 99.53%. In addition to variations in carbonate aquifer thickness and clay/shale content, the existence of strong karstification features, i.e., fissures, fractures or caverns, and solution cavities, in the Eocene carbonate aquifer are responsible for variability in the K and T values. The observed high well losses might be related to turbulent flow within and adjacent to the wells drilled in conductive fracture zones. The current approach can be further used to enhance local aquifer models and improve strategies for identifying the most productive zones in similar aquifer systems. Full article

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II₂, with TOC content greater than 1%. The maturity of shale samples is relatively higher (R_o,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m²/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm³/g, with an average of 2.1 cm³/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential. Full article

This paper presents a comprehensive analysis of water injection management practices for complex and impactful onshore and offshore carbonate reservoirs. It delves into the fundamental aspects of waterflooding design, surveillance techniques, and monitoring methods tailored for the unique challenges posed by carbonate formations. Two case studies from the Permian Basin in Texas and two from Lula Field offshore Brazil and Agbami Field offshore Nigeria are examined considering scientific principles into practice to provide insights into best practices, lessons learned, and strategies to maximize the benefits derived from real noteworthy waterflood operations. The paper underscores the significance of rigorous reservoir characterization, including understanding reservoir architecture, heterogeneities, fracture networks, fluid communication pathways, and rock–fluid interactions. It emphasizes the crucial role of integrated multidisciplinary teams involving geologists, reservoir engineers, production engineers, and field operators in ensuring successful waterflood design, implementation, and optimization. Through the case studies, the paper highlights the importance of designing pattern configurations, well placements, and injection/production strategies to the specific reservoir characteristics, continually optimizing these elements based on surveillance data. It also stresses the necessity of comprehensive data acquisition, advanced analytics, numerical simulations, and frequent model updates for effective reservoir management and decision-making. The paper is impactful in terms of the lessons learned from the actual case studies, and how can these be implemented in actual field projects. Different case studies documented in the paper provide the challenges facing them and how different authors have addressed their problems in unique ways. The paper distills the information and important findings from a variety of case studies and provides succinct information that is of immense value as a reference. Important findings of these case studies are connected using creativity and are innovative as they introduce unique techniques and establish successful ideas to create new value in terms of maximizing oil recovery. Most importantly, this paper explores the application of innovative technologies, such as intelligent completions, 4D seismic monitoring, and water–alternating gas (WAG) injection, which can significantly improve waterflood performance in complex carbonate reservoirs. In summary, the paper provides a thorough understanding of the factors contributing to the success and failure of waterfloods in carbonate reservoirs through case studies based on factually and technically sound operations. It documents guidelines for optimizing waterflood performance and reducing or eliminating the potential for failures, reinforcing positive results in these challenging yet invaluable hydrocarbon resources. Full article

Carbon neutrality has become a global common goal. CCUS, as one of the technologies to achieve carbon neutrality, has received widespread attention from academia and industry. After CO₂ enters the formation, under the conditions of formation temperature and pressure, supercritical CO₂, formation water, and rock components interact, which directly affects the oil and gas recovery and carbon sequestration efficiency. In this paper, the recent progress on CO₂ water–rock interaction was reviewed from three aspects, including (i) the investigation methods of CO₂ water–rock interaction; (ii) the variable changes of key minerals, pore structure, and physical properties; and (iii) the nomination of suitable reservoirs for CO₂ geological sequestration. The review obtains the following three understandings: (1) Physical simulation and cross-time scale numerical simulation based on formation temperature and pressure conditions are important research methods for CO₂ water–rock interaction. High-precision mineral-pore in situ comparison and physical property evolution evaluation are important development directions. (2) Sensitive minerals in CO₂ water–rock interaction mainly include dolomite, calcite, anhydrite, feldspar, kaolinite, and chlorite. Due to the differences in simulated formation conditions or geological backgrounds, these minerals generally show the pattern of dissolution or precipitation or dissolution before precipitation. This differential evolution leads to complex changes in pore structure and physical properties. (3) To select the suitable reservoir for sequestration, it is necessary to confirm the sequestration potential of the reservoir and the later sequestration capacity, and then select the appropriate layer and well location to start CO₂ injection. At the same time, these processes can be optimized by CO₂ water–rock interaction research. This review aims to provide scientific guidance and technical support for shale oil recovery and carbon sequestration by introducing the mechanism of CO₂ water–rock interaction, expounding the changes of key minerals, pore structure, and physical properties, and summarizing the sequestration scheme. Full article

Shale gas reservoirs generally exhibit characteristics such as low porosity, permeability, and pore throat radius, with high airflow resistance. Currently, hydraulic fracturing is a commonly used method for commercial shale gas extraction; however, the hydraulic fracturing method has exhibited a series of issues, including water sensitivity and reservoir pollution in shale reservoirs. Therefore, the development of anhydrous fracturing technology suitable for shale gas reservoirs has become an urgent requirement. The supercritical carbon dioxide fracturing technique has the merits of reducing reservoir damage, improving recovery and backflow rates, and saving water resources. Moreover, this technique has broad application prospects and can achieve the effective extraction of shale gas. To enhance the understanding of the supercritical carbon dioxide fracturing technique, this review summarizes the progress of current research on this technique. Furthermore, this study analyzes the stage control technology of supercritical carbon dioxide during the fracturing process, the interaction characteristics between supercritical carbon dioxide and rocks, and the laws of rock initiation and crack growth in supercritical carbon dioxide fracturing. The outcomes indicate that after SC-CO₂ enters the reservoir, CO₂ water–rock interaction occurs, which alters the mineral composition and pore throat framework, weakens the mechanical characteristics of shale, reduces the rock fracturing pressure, and increases the complexity of the fracturing network. This article provides a reference for research related to supercritical carbon dioxide fracturing technology and is greatly significant for the development of shale gas reservoirs. Full article