Search Results (2,473)

Turbidite lobe reservoirs represent critical deep-sea hydrocarbon targets, yet preferred seepage channels within them remain poorly characterized. This paper establishes a method for identifying internal preferred seepage channels in turbidite lobe reservoirs using data including seismic, core, thin section, logging, and production performance, combined with neural network technology. A neural network model for predicting reservoir productivity types can be obtained by taking the average logging data of reservoir intervals as input and the reservoir productivity types categorized by meter oil production index calculated by actual production data as the target. By applying the trained neural network model and inputting actual logging attribute model, the reservoir productivity types of single wells are obtained. Using the attribute model of natural gamma ray, acoustic, neutron, density, deep lateral, and shallow lateral logs, which are built by using the actual logging data and Sequential Gaussian Simulation, and supervising with the single well reservoir productivity type, the reservoir productivity type at any position in the reservoir can be predicted. It predicts their spatial distribution characteristics, reveals the genetic mechanism of preferred seepage channels, and discusses the significance of identifying preferred seepage channels for oilfield development. The results show that the reservoir productivity types in the study area can be divided into five categories with progressive improvement in productivity (A, B, C, D, and E) according to the increase in oil production index per meter, among which Type E reservoirs represent typical preferred seepage channels. The attribute model of reservoir productivity types indicates that, horizontally, types E and B are locally developed in the study area, while types D, C, and A are widely distributed. The preferred seepage channels can be divided into two types according to the shape: zonal (length to width > 2:1) and sheet-like (length to width ≤ 2:1). Vertically, types C, D, and E are relatively well-developed in layers III and IV, whereas types A and B are more common in layers I and II. The vertical combination patterns of preferred seepage channels reveal four types, including homogeneous, bottom-dominated, top-dominated, and interbedded patterns. The formation of preferred seepage channels is influenced by both sedimentary and diagenetic processes, and sedimentary is the most important controlling factors. The identification of preferred seepage channels in turbidite lobe reservoirs is of great significance for formulating development policies and tapping remaining oil. Full article

Foredeep basins often host significant natural gas reservoirs within siliciclastic successions, as exemplified by the Po Plain (Northern Italy), one of Europe’s largest foredeep basins. Here, numerous depleted gas reservoirs have been successfully converted into underground gas storage (UGS) facilities. For safe and efficient storage operations, detailed reservoir characterization and continuous monitoring of surface and subsurface effects are crucial. This study investigates the Cornegliano Laudense reservoir during its first 5–7 years as a UGS facility, employing an integrated monitoring approach that combines traditional methods (InSAR for surface deformation, microseismic monitoring) with innovative techniques (Pulsed Neutron Log-PNL). The results clearly illustrate and quantify the significant increase in storage capacity over a relatively short operational period, primarily driven by the progressive displacement of formation water by injected gas. Despite increased stored gas volumes, monitoring revealed no adverse effects on surface stability or subsurface seismicity. This integrated methodology demonstrates substantial potential for refining predictive models, optimizing storage efficiency, and enhancing sustainable management practices for underground gas storage operations. Full article

The biological production of hydrogen offers a renewable and potentially sustainable alternative for clean energy generation. In Northeast Brazil, depleted oil reservoirs (DORs) present a unique opportunity to integrate biotechnology with existing fossil fuel infrastructure. These subsurface formations, rich in residual hydrocarbons (RH) and native H₂ producing microbiota, can be repurposed as bioreactors for hydrogen production. This process, often referred to as “Gold Hydrogen”, involves the in situ microbial conversion of RH into H₂, typically via dark fermentation, and is distinct from green, blue, or grey hydrogen due to its reliance on indigenous subsurface biota and RH. Strategies include nutrient modulation and chemical additives to stimulate native hydrogenogenic genera (Clostridium, Petrotoga, Thermotoga) or the injection of improved inocula. While this approach has potential environmental benefits, such as integrated CO₂ sequestration and minimized surface disturbance, it also presents risks, namely the production of CO₂ and H₂S, and fracturing, which require strict monitoring and mitigation. Although infrastructure reuse reduces capital expenditures, achieving economic viability depends on overcoming significant technical, operational, and biotechnological challenges. If widely applied, this model could help decarbonize the energy sector, repurpose legacy infrastructure, and support the global transition toward low-carbon technologies. Full article

The development of gravity flow sedimentology has improved our understanding of the physical properties of different types of gravity flow deposits, especially the advancement of various gravity flow models. Although studies of gravity flows have developed greatly, the linkage between different sub-facies and their reservoir properties is hindered by a lack of detailed sedimentary records. Here, integrated test data (including thin-section petrology, high-pressure mercury injection experiments, capillary pressure curve analysis, and scanning electron microscopy) are used to evaluate links between different types of gravity flows and their reservoir properties from the Late Triassic–Early Jurassic Anyao Formation, southeastern Paleo-Ordos Basin, China. The petrological and sedimentological data reveal two types of deep-water gravity flow deposits comprising sandy debris flow (SDF) and turbidity current (TC) deposits. Both are fine-grained lithic sandstones and form low-porosity and ultra-low permeability reservoirs. Secondary porosity, formed by the dissolution of framework grains, including feldspars and lithic fragments, dominates the pore types. This secondary porosity is widely developed in the Anyao Formation and formed by reaction with organic acids during burial (early mesodiagenesis). The associated mud rocks have reached the early mature stage of the oil window with Tmax of 442–448 °C. Compared with the turbidites, the sandy debris flows have higher framework grain content (87.9 vs. 84.8%), framework grain size (0.091 vs. 0.008 mm), porosity (6.97 vs. 3.44%), pore throat radius (0.102 vs. 0.025 μm), and permeability (0.025 vs. 0.005 mD) but are relatively poor in the sorting of framework grains and pore throat radii. The most important petrological factors affecting porosity and permeability of the SDF reservoirs are framework grain size and feldspar grain content, respectively, but those of the TC reservoirs are feldspar grain content and the maximum pore throat radius. Diagenetic dissolution of framework grains is the most important porosity-affecting factor for both SDF and TC reservoirs. Our multi-proxy study provides new insights into the links between gravity flow sub-facies and reservoir properties in the lacustrine deep-water environment. Full article

Hydraulic fracturing in shale reservoirs is affected by microscale structural and material heterogeneity. However, studies on fracture responses to the injection rate across different microstructural types remain limited. To examine the coupled effects of microstructure and flow rate on fracture propagation and mineral damage, high-fidelity digital rock models were constructed from SEM images of shale cores, representing quartz grains and ostracod laminae. Coupled hydro-mechanical damage simulations were conducted under varying injection rates. Fracture evolution and complexity were evaluated using three quantitative parameters: stimulated reservoir area, fracture ratio, and fractal dimension. The results show that fracture morphology and mineral failure are strongly dependent on both the structure and injection rate. All three parameters increase with the flow rate, with the ostracod model showing abrupt complexity jumps at higher rates. In quartz-dominated models, fractures tend to deflect and bypass weak cement, forming branches. In ostracod-lamina models, higher injection rates promote direct penetration and multi-point propagation, resulting in a radial–branched–nested fracture structure. Mineral analysis shows that quartz exhibits brittle failure under high stress, while organic matter fails more readily in tension. These findings provide mechanistic insights into the coupled influence of microstructure and flow rate on hydraulic fracture complexity, with implications for optimizing hydraulic fracturing strategies in heterogeneous shale formations. Full article

Clarifying the phase evolution history of hydrocarbon fluids helps formulate exploration and development strategies. The discovery of the Xinguang Gas Field marks a significant breakthrough in the Western Junggar Basin. However, the phase evolution history of this gas field remains unclear, which hinders the formulation of subsequent exploration strategies. This study employs a comprehensive approach, combining organic geochemistry, fluid inclusions, basin modeling, and PVT testing and simulation, to investigate the characteristics and phase behavior of deep-seated hydrocarbon fluids in this gas field. It also examines the charging history, compositional evolution, and temperature and pressure histories of the reservoir, thereby clarifying the phase transition process of hydrocarbon fluids in the Xinguang Gas Field. This study finds that the deep-seated reservoir fluids in the Jiamuhe Formation (Fm.) of the Xinguang Gas Field exhibit low densities of 0.77 to 0.83 g/cm³, high gas-to-oil ratios (GORs) of 1014.41 to 13,054.77 m³/m³, high methane contents of 91.16% to 92.74%, and retrograde condensation characteristics. Additionally, the reservoir temperature and pressure exceed the critical point and the saturation pressure at reservoir temperature, indicating a supercritical condensate gas phase. The present condensate gas in the Xinguang Gas Field is a mixed hydrocarbon from two charging events. Initially, during the Middle–Late Triassic period, both Block 1 and the Xinguang Gas Field were charged with mature oil. Later, from the Late Cretaceous to Early Neogene periods, a secondary charging of highly mature oil and gas occurred in the Xinguang Gas Field, while the reservoir in Block 1 remained largely unchanged. In the co-evolution of reservoir fluid composition, temperature, and pressure, the phase transitions of the hydrocarbon fluids in the Xinguang Gas Field passed through several stages, including liquid black oil (231.9–80.3 Ma), liquid volatile oil (80.3–79.1 Ma), vapor–liquid two-phase volatile oil (79.1–78.3 Ma), vapor–liquid two-phase condensate gas (78.3–69.1 Ma), and supercritical condensate gas (69.1 Ma–present). Full article

Low-permeability oil reservoirs, due to their weak seepage capacity and high start-up pressure, have limited yield-increasing effects through conventional water injection development methods. High-pressure water injection can significantly change the seepage environment around the well and within the reservoir, expand the effective swept volume of injected water, and thereby greatly enhance the oil recovery rate of water flooding. However, there is still a relative lack of research on the mechanism of high-pressure water injection stimulation and its influencing factors. This paper systematically analyzes the effectiveness mechanism of high-pressure water injection technology in the exploitation of low-permeability reservoirs. The internal mechanism of high-pressure water injection for effective fluid drive and production increase is explained from the aspects of low-permeability reservoir seepage characteristics, capacity expansion and permeability enhancement by high-pressure water injection, and the dynamic induction of micro-fractures. Based on geological and engineering factors, the main factors affecting the efficiency enhancement of high-pressure water injection are studied, including formation deficit, reservoir heterogeneity, dominant channel development and fracturing stimulation measures, injection displacement and micro-fractures, etc. The results of numerical simulation showed the following: (1) formation depletion, reservoir heterogeneity, and the formation of dominant channels significantly affected the effect of water flooding development and (2) engineering factors such as the fracture direction of hydraulic fracturing, water injection rate, and the development of micro-fractures under high-pressure water injection directly determined the propagation path of reservoir pressure, the breakthrough speed of the water drive front, and the ultimate recovery factor. Therefore, during the actual development process, the construction design parameters of high-pressure water injection should be reasonably determined based on the geological reservoir conditions to maximize the oil production increase effect of high-pressure water injection. This study can successfully provide theoretical guidance and practical support for the development of low-permeability oil reservoirs. Full article

To enhance the development efficiency of medium–deep geothermal resources in cold regions, this study focuses on a coaxial borehole heat exchanger (CBHE) located in Dapuzi Town, Xining City, Qinghai Province. Based on field-scale heat exchange experiments, a three-dimensional numerical model of the CBHE was developed using COMSOL Multiphysics 6.2, incorporating both conductive heat transfer in the surrounding geological formation and convective heat transfer within the wellbore. The model was calibrated and validated against measured data. On this basis, the effects of wellhead injection flow rate, injection temperature, and the thermal conductivity of the inner pipe on heat exchange performance were systematically analyzed. The results show that in cold regions with high altitudes (2000–3000 m) and medium–deep low-temperature geothermal reservoirs (68.8 °C), using a coaxial heat exchange system for space heating delivers good heat extraction performance, with a maximum average power output of 282.37 kW. Among the parameters, the injection flow rate has the most significant impact on heat extraction. When the flow rate increases from 10 m³/h to 30 m³/h, the heat extraction power increases by 57.58%. An increase in injection temperature helps suppress thermal short-circuiting and improves the effluent temperature, but excessively high temperatures lead to a decline in heat extraction. Additionally, increasing the thermal conductivity of the inner pipe significantly intensifies thermal short-circuiting and reduces overall heat exchange capacity. Under constant reservoir conditions, the thermal influence radius expands with both depth and operating time, reaching a maximum of 10.04 m by the end of the heating period. For the CBHE system in Dapuzi, maintaining an injection flow rate of 20–25 m³/h and an injection temperature of approximately 20 °C can achieve an optimal balance between effluent temperature and heat extraction. Full article

To reduce CO₂ emissions, CO₂ geological storage is recognized as an effective approach to decrease atmospheric carbon concentration. Sequestration in deep saline aquifers has become a research focus. However, the physicochemical property changes in saline formations induced by CO₂ injection remain unclear, making it difficult to assess their CO₂ storage potential. This study focuses on saline aquifers within the Jurassic Badaowan formation (J₁b), Sangonghe formation (J₁s), and Cretaceous Tugulu Group (K₁tg) of the Baijiahai Uplift in the Junggar Basin. An integrated methodology combining laboratory experiments—including CO₂ static immersion tests, dynamic displacement tests, X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR) measurements, and mechanical testing—with CMG-based numerical modeling was employed to analyze CO₂ storage mechanisms and evaluate storage potential. The results show that after CO₂ immersion, extensive dissolution of calcite in J₁s, clay swelling/cementation in J₁b, and extensive dissolution of calcite in K₁tg all lead to increased porosity and permeability, with the J₁b formation exhibiting superior CO₂ storage capacity, the highest MICP-derived porosity, and the greatest NMR-measured porosity among the three formations. Numerical simulations further confirmed J₁b’s leading sequestration volume. Based on integrated experimental and simulation results, the J₁b formation is identified as the optimal reservoir for CO₂ storage. However, to manage potential mechanical instability during real-world injection scenarios, injection pressures and rates should be carefully controlled and continuously monitored to avoid formation fracturing and ensure long-term storage security. This study provides a reference for implementing saline aquifer CCUS projects. Full article

In the process of the exploration and development of shale oil, the influence of hydration on shale reservoirs is complex, as it can not only improve porosity and permeability, but also lead to reservoir instability. At present, there is a lack of systematic understanding of the influence of hydration on the physical and chemical properties of shale oil reservoirs. Therefore, in this study, taking the Gulong shale oil reservoir in Songliao Basin as the research object, X-ray diffraction mineral composition analysis, electron microscope scanning, and micro-CT scanning were used to study the micro–macro-changes in shale caused by hydration, and the effects of different fracturing fluids on hydration were evaluated. The results show the following: (1) Hydration increases the porosity and permeability of Gulong shale through clay dispersion and dissolution pore formation, though these transient effects may compromise long-term reservoir stability due to pore-throat clogging. (2) Prolonged hydration significantly enhanced pore structure complexity, with tortuosity increasing by 64.7% (from 2.19 to 3.60) and the fractal dimension rising by 7.5% (from 1.99 to 2.14) with hydration time, and the proportion of larger pores (50–100 μm) increased significantly. (3) Hydration leads to crack propagation and new cracks, and the intersection of cracks reduces the core strength, which may eventually lead to macroscopic damage. (4) The influence of different fracturing fluids on the hydration reaction is obviously different. The higher the concentration, the stronger the hydration effect. Distilled water helps to increase porosity and permeability, but long-term effects may affect reservoir stability. The results of this paper reveal the changes in micro- and macro-characteristics of shale oil reservoirs under hydration, which is of great significance for analyzing the mechanism of hydration and provides theoretical support for improving shale oil recovery. Full article

Scale deposition during waterflooding, driven by the incompatibility between injected seawater and formation of water, poses significant challenges to reservoir performance. This study examines the mechanisms of inorganic scale formation and assesses its impact on productivity index, permeability, and pressure dynamics using the ECLIPSE simulator. A five-layered reservoir model with one injector and one producer (spaced 700 feet apart) was simulated under varying seawater injection rates of 1000, 3000, and 5000 stock tank barrels per day (stb/day). The results revealed rapid water breakthrough and escalating water cuts (34–38%) across scenarios, with scale deposition concentrated in layers 3 and 4, reducing permeability by up to 47% and productivity index by 50%. Layer 3 exhibited a threefold higher scaling due to the intense mixing of seawater and the formation of water. The study highlights the necessity of sulfate removal, alternative water sources, well repositioning, and preemptive scale inhibition to minimize reservoir damage caused by scale-induced permeability impairment. Full article

The tight sandstone gas reservoirs of the Xujiahe Formation are critical targets for tight gas exploration and development in the Sichuan Basin. While Class I reservoirs have been successfully developed using staged volume fracturing technology, efforts are being increasingly directed toward Class II and III matrix-type blocks. These reservoirs are characterized by a low permeability, high geo-stress differentials, strong heterogeneity, and limited fracture development. These properties result in several challenges, including ambiguous gas production sources, low reservoir utilization rates, significant variability in horizontal well performance, and rapid early-stage production decline—all of which hinder the effective development of matrix-type reservoirs. This study examines two representative fractured wells, Xin 8-5H and Xinsheng 204-1H, located in Class II and III blocks of the Xujiahe Formation gas reservoir. To identify gas production sources, we establish full-fracturing-section productivity models. Furthermore, accounting for variations in geological characteristics, we develop distinct productivity models for three key zones, the matrix area, fracture area, and fault area, to evaluate the productivity controls. The findings reveal that well Xin 8-5H primarily produces gas from the matrix and fault zones, whereas well Xinsheng 204-1H derives most of its production from the matrix and natural fractures. In matrix-dominated zones, generating complex fracture networks enhances productivity. An optimal cluster spacing of approximately 14 m ensures broad pressure sweep coverage while maintaining effective inter-cluster fracture connectivity. Additionally, natural fractures in the Xu-2 matrix reservoirs play a vital role in fluid communication. To maximize reservoir contact, well trajectories should be designed such that natural fractures are oriented either parallel or perpendicular to the wellbore, thereby improving lateral and vertical development. Near fault zones, adjusting cluster spacing to 14–25 m—while keeping the distance between faults and fracturing stages below 50 m—effectively connects faults and substantially increases production. This study introduces a systematic methodology for identifying gas sources in matrix reservoirs and optimizes key productivity-influencing parameters. The results provide both theoretical insights and practical strategies for the efficient development of Xu-2 matrix reservoirs. Full article

Machine learning-guided predictive models are attractive in rock modeling for different scholars to obtain continuous profiles of rock compressive strength in rock engineering. The major objectives of the study are to assess the implications of machine learning (ML)-based connectionist models to obtain the unconfined compressive strength (UCS) of rock, to perform parametric sensitivity analysis on petrophysical parameters, and to develop an improved correlation for UCS prediction. The least-squares support vector machine (LSSVM) is applied to develop data-driven models for the prediction of UCS. Additionally, the random forest (RF) algorithm is applied to verify the effectiveness of predictive models. A database containing well-logging data is processed and utilized to construct connectionist models to obtain UCS. For the efficacy of predictive models, statistical performance indicators such as the coefficient of determination (CC), average percentage relative error, and maximum average percentage error are utilized in the study. It is revealed that the RF- and LSSVM-based models for predicting UCS perform excellently with high precision. Considering the parametric sensitivity analysis in the predictive models for UCS, the formation compressional wave velocity and formation gamma-ray are the most strongly contributing predictor variables rather than other input variables such as the modulus of elasticity, acoustic shear wave velocity, and rock bulk density. The improved correlation for predicting UCS shows high precision, achieving a CC of 96% and root mean squared error of 0.54 MPa. This systematic research workflow is significant and can be utilized for connectionist robust model development and variable selections in the petroleum and mining fields, such as predicting reservoir properties, the drilling rate of penetration, sanding potentiality of hydrocarbon reservoir rocks, and for the practical implications of boring and geotechnical engineering projects. Full article

Waterflooding, a key method for secondary hydrocarbon recovery, has been employed since the early 20th century. Over time, the role of water chemistry and ions in recovery has been studied extensively. Low-salinity water (LSW) injection, a common technique since the 1930s, improves oil recovery by altering the wettability of reservoir rocks and reducing residual oil saturation. Recent developments emphasize the integration of LSW with various recovery methods such as CO₂ injections, surfactants, alkali, polymers, and nanoparticles (NPs). This article offers a comprehensive perspective on how LSW injection is combined with these enhanced oil recovery (EOR) techniques, with a focus on improving oil displacement and recovery efficiency. Surfactants enhance the effectiveness of LSW by lowering interfacial tension (IFT) and improving wettability, while ASP flooding helps reduce surfactant loss and promotes in situ soap formation. Polymer injections boost oil recovery by increasing fluid viscosity and improving sweep efficiency. Nevertheless, challenges such as fine migration and unstable flow persist, requiring additional optimization. The combination of LSW with nanoparticles has shown potential in modifying wettability, adjusting viscosity, and stabilizing emulsions through careful concentration management to prevent or reduce formation damage. Finally, building on discussions around the underlying mechanisms involved in improved oil recovery and the challenges associated with each approach, this article highlights their prospects for future research and field implementation. By combining LSW with advanced EOR techniques, the oil industry can improve recovery efficiency while addressing both environmental and operational challenges. Full article

Deep coalbed methane (CBM) is challenging to develop due to considerable burial depth, high ground stress, and complex geological structures. However, modeling deep CBM in complex formations and setting reasonable simulation parameters to obtain reasonable results still needs exploration. This study presents a comprehensive equivalent finite element modeling method for deep CBM. The method is based on the cohesive element with pore pressure of the zero-thickness (CEPPZ) model to simulate hydraulic fracture propagation and characterize the effects of bedding interfaces and natural fractures. Taking Ordo’s deep CBM in China as an example, a comprehensive equivalent model for hydraulic fracturing was developed for the limestone layer–coal seam–mudstone layer. Then, the filtration parameters of the CEPPZ model and the permeability parameters of the deep CBM reservoir matrix were inverted and calibrated using on-site data from fracturing tests. Finally, the propagation path of hydraulic fractures was simulated under varying ground stress, construction parameters, and perforation positions. The results show that the hydraulic fractures are more likely to expand into layers with low minimum horizontal stress; the effect of a sizable fluid injection rate on the increase in hydraulic fracture length is noticeable; the improvement effect on fracture length and area gradually weakens with the increased fracturing fluid volume and viscosity; and when directional roof limestone/floor mudstone layer perforation is used, and the appropriate perforation location is selected, hydraulic fractures can communicate the coal seam to form a roof limestone/floor mudstone layer indirect fracturing. The results can guide the efficient development of deep CBM, improving the human society’s energy structure. Full article