Search Results (1,417)

The gas reservoir of the Sinian Dengying Formation (Member 4) in Sichuan Basin exhibits extensive development of inter-clast dissolution pores and vugs within its carbonate reservoirs, characterized by low porosity (average 3.21%) and low permeability (average 2.19 mD). With the progressive development of the Moxi (MX)structure, the existing stimulation techniques require further optimization based on the specific geological characteristics of these reservoirs. Through large-scale true tri-axial physical simulation experiments, this study systematically evaluated the performance of three principal acid systems in reservoir stimulation: (1) Self-generating acid systems, which enhance etching through the thermal decomposition of ester precursors to provide sustained reactive capabilities. (2) Gelled acid systems, characterized by high viscosity and effectiveness in reducing breakdown pressure (18%~35% lower than conventional systems), are ideal for generating complex fracture networks. (3) Diverting acid systems, designed to improve fracture branching density by managing fluid flow heterogeneity. This study emphasizes hybrid acid combinations, particularly self-generating acid prepad coupled with gelled acid systems, to leverage their synergistic advantages. Field trials implementing these optimized systems revealed that conventional guar-based fracturing fluids demonstrated 40% higher breakdown pressures compared to acid systems, rendering hydraulic fracturing unsuitable for MX reservoirs. Comparative analysis confirmed gelled acid’s superiority over diverting acid in tensile strength reduction and fracture network complexity. Field implementations using reservoir-quality-adaptive strategies—gelled acid fracturing for main reservoir sections and integrated self-generating acid prepad + gelled acid systems for marginal zones—demonstrated the technical superiority of the hybrid system under MX reservoir conditions. This optimized protocol enhanced fracture length by 28% and stimulated reservoir volume by 36%, achieving a 36% single-well production increase. The technical framework provides an engineered solution for productivity enhancement in deep carbonate gas reservoirs within the G-M structural domain, with particular efficacy for reservoirs featuring dual low-porosity and low-permeability characteristics. Full article

Traditional hydraulic-fracturing models are restricted by low computational efficiency, insufficient field data, and complex physical mechanisms, causing evaluation delays and failing to meet practical engineering needs. To address these challenges, this study innovatively develops a dynamic hydraulic-fracturing monitoring method that integrates machine learning with numerical simulation. Firstly, this study uses GOHFER 9.5.6 software to generate 12,000 sets of fracture geometry data and constructs a big dataset for hydraulic fracturing. In order to improve the efficiency of the simulation, a macro command is used in combination with a Python 3.11 code to achieve the automation of the simulation process, thereby expanding the data samples for the surrogate model. On this basis, a parameter sensitivity analysis is carried out to identify key input parameters, such as reservoir parameters and fracturing fluid properties, that significantly affect fracture geometry. Next, a neural-network surrogate model is established, which takes fracturing geological parameters and pumping parameters as inputs and fracture geometric parameters as outputs. Data are preprocessed using the min–max normalization method. A neural-network structure with two hidden layers is chosen, and the model is trained with the Adam optimizer to improve its predictive accuracy. The experimental results show that the efficiency of automated numerical simulation for hydraulic fracturing is significantly improved. The surrogate model achieved a prediction accuracy of over 90% and a response time of less than 10 s, representing a substantial efficiency improvement compared to traditional fracturing models. Through these technical approaches, this study not only enhances the effectiveness of fracturing but also provides a new, efficient, and accurate solution for oilfield fracturing operations. Full article

Deep carbonate reservoirs have garnered significant attention and demonstrated great potential for oil and gas exploration in recent years. The Majiagou Formation in the Ordos Basin has received much attention for its deep oil and gas deposits recently. However, the issue of fluid evolution within the great depth has been overlooked, and the relationship between fluid flow and the gas accumulation process remains unclear. This paper aims to explore the fluid evolution and its relationship with the gas accumulation, which poses a challenge for further petroleum exploration. To achieve this, petrological studies on dolomite samples were carried out and four types of secondary cements were identified: early gypsum-moldic pore-filling calcite, late gypsum-moldic pore-filling calcite, dissolution pore-filling calcite and fracture-filling calcite. Subsequently, an interdisciplinary approach that integrates petrography observation, microthermometry, laser Raman analysis of fluid inclusions, and carbon and oxygen isotope tests on these types of cements is employed to elucidate the fluid flow evolution. These investigations revealed that four different stages of inorganic fluid activity were coeval with two stages of organic fluid activity. The two stages of organic fluid flows were significantly important for petroleum accumulation. In the late Triassic to early Jurassic, there was small-scale liquid oil accumulation, which was associated with the second stage of fluids. In the early Cretaceous, there was large-scale gas accumulation, which was associated with the fourth stage of fluids. This research is crucial for understanding the fluid flow process and its relationship with hydrocarbon accumulation in deeply buried carbonate formations. Full article

The perforating–fracturing–testing combined technology has emerged as a crucial well completion technique to enhance production efficiency. However, the shock loads generated during perforation in the packed section of an oil and gas well significantly affect the stability of the perforating tubing string system, potentially leading to deformation or even fracture. During the perforating operation, a large amount of blast products is generated, and as these products escape the perforating gun and interact with the perforating fluid, the fluid pressure pulsates. These pressure fluctuations are the primary cause of the dynamic response of the perforating tubing string. The greatest threat to tubing string integrity occurs when pulsating pressure reaches its peak amplitude, potentially leading to tubing failure. To address this, this study employs underwater explosion theory to analyze the pressure variations during the generation and propagation of shock waves in perforation operations. Additionally, quantitative numerical simulation analysis reveals key relationships governing peak perforating fluid pressure: peak pressure remains remarkably stable at 370–371 MPa despite variations in perforating fluid viscosity (0–110 cP) or tubing Young’s modulus (100–260 GPa). However, it responds significantly to other parameters: fluid density (1–3 g/cm³) causes a linear increase from 335 MPa to 598 MPa; total charge mass drives a proportional rise from 162 MPa to 388 MPa; detonation interval (0–50 μs) elevates pressure from 268 MPa to 378 MPa; and formation pressure (0–100 MPa) increases it from 315 MPa to 372 MPa. Crucially, peak pressure decreases from 376 MPa to 243 MPa as the explosion space expands (0–5 m³). Furthermore, a nonlinear regression model is developed to predict peak perforating shock loads. The results indicate that residual perforation energy critically impacts tubing string safety. Validated against two field cases, the model achieves nearly 10% error compared to predictions from Pulsfrac (industry-standard perforating shock software), meeting field requirements while providing actionable insights for wellbore integrity and perforating tubing string stability. Full article

Supercritical carbon dioxide (Sc-CO₂) thermal shock fracturing emerges as an innovative rock fragmentation technology combining environmental sustainability with operational efficiency. This study establishes a thermo-hydro-mechanical coupled model to elucidate how in situ stress magnitude and anisotropy critically govern damage progression and fluid dynamics during Sc-CO₂ thermal shock fracturing. Key novel findings reveal the following: (1) The fracturing mechanism integrates transient hydrodynamic shock with quasi-static pressure loading, generating characteristic bimodal pressure curves where secondary peak amplification specifically indicates inhibited interwell fracture coalescence under anisotropic stress configurations. (2) Fracture paths undergo spatiotemporal reorientation—initial propagation aligns with in situ stress orientation, while subsequent growth follows thermal shock-induced principal stress trajectories. (3) Stress heterogeneity modulates fracture network complexity through confinement effects: elevated normal stresses perpendicular to fracture planes reduce pressure gradients (compared to isotropic conditions) and delay crack initiation, yet sustain higher pressure plateaus by constraining fracture connectivity despite fluid leakage. Numerical simulations systematically demonstrate that stress anisotropy plays a dual role—enhancing peak pressures while limiting fracture network development. This demonstrates the dual roles of the technology in enhancing environmental sustainability through waterless operations and reducing carbon footprint. Full article

During drilling operations, lost circulation frequently occurs, leading to significant loss of drilling fluids which causes environmental damage and increasing drilling costs. To address the problem of fracture plugging, gel materials have emerged as an ideal solution due to stable physicochemical properties and excellent environmental compatibility. However, most existing gels exhibit poor stability and low mechanical strength under high-temperature conditions. To overcome these limitations, high-temperature-resistant phase-conversion stiffened dual-network hydrogel for oil-based drilling fluids was developed. Phase-conversion was realized by immersing synthesized double-network hydrogel in ethylene glycol (EG), polyethylene glycol (PEG), and glycerol (Gly), optimizing and enhancing its mechanical properties, followed by plugging performance evaluations. Experimental results demonstrated that the phase-conversion stiffened gels achieved significantly improved compressive strength and plugging efficiency at elevated temperature. The GC-MS results indicated that dehydration and reagent exchange occurred during immersion, with change in the solid content of the sample. After being treated by white oil at high temperature, the oil phase almost replaced the water phase in the gel. The results of ATR-IR confirmed the formation of hydrogen bonds in the gel. TGA data revealed that PEG enhanced the thermal stability of the gel, EG negatively affected thermal stability, and Gly had negligible influence. The enhancement in gel strength primarily stems from the increase in solid content caused by phase transformation. Dehydration and multiple hydrogen bonds formed between organic reagent molecules and polymer chains in the gel have a synergistic enhancement effect. Full article

Underground hydrogen storage (UHS) in shale and tight reservoirs offers a promising solution for large-scale energy storage, playing a critical role in the transition to a hydrogen-based economy. However, the successful deployment of UHS in these low-permeability formations depends on a thorough understanding of the geomechanical and geochemical factors that affect storage integrity, injectivity, and long-term stability. This review critically examines the geomechanical aspects, including stress distribution, rock deformation, fracture propagation, and caprock integrity, which govern hydrogen containment under subsurface conditions. Additionally, it explores key geochemical challenges such as hydrogen-induced mineral alterations, adsorption effects, microbial activity, and potential reactivity with formation fluids, to evaluate their impact on storage feasibility. A comprehensive analysis of experimental studies, numerical modeling approaches, and field applications is presented to identify knowledge gaps and future research directions. Full article

Lost circulation, a prevalent challenge in drilling engineering, poses significant risks including drilling fluid loss, wellbore instability, and environmental contamination. Conventional plugging materials often exhibit an inadequate performance under high-temperature, high-pressure (HTHP), and complex formation conditions. To address that, this study developed a high-performance gel–resin composite plugging material resistant to HTHP environments. By optimizing the formulation of bisphenol-A epoxy resin (20%), hexamethylenetetramine (3%), and hydroxyethyl cellulose (1%), and incorporating fillers such as nano-silica and walnut shell particles, a controllable high-strength plugging system was constructed. Fourier-transform infrared spectroscopy (FTIR) and thermogravimetric analysis (TGA) confirmed the structural stability of the resin, with an initial decomposition temperature of 220 °C and a compressive strength retention of 14.4 MPa after 45 days of aging at 140 °C. Rheological tests revealed shear-thinning behavior (initial viscosity: 300–350 mPa·s), with viscosity increasing marginally to 51 mPa·s after 10 h of stirring at ambient temperature, demonstrating superior pumpability. Experimental results indicated excellent adaptability of the system to drilling fluid contamination (compressive strength: 5.04 MPa at 20% dosage), high salinity (formation water salinity: 166.5 g/L), and elevated temperatures (140 °C). In pressure-bearing plugging tests, the resin achieved a breakthrough pressure of 15.19 MPa in wedge-shaped fractures (inlet: 7 mm/outlet: 5 mm) and a sand-packed tube sealing pressure of 11.25 MPa. Acid solubility tests further demonstrated outstanding degradability, with a 97.69% degradation rate after 24 h in 15% hydrochloric acid at 140 °C. This study provides an efficient, stable, and environmentally friendly solution for mitigating drilling fluid loss in complex formations, exhibiting significant potential for engineering applications. Full article

The persistent challenge of fracture-driven interference (FDI) during large-scale hydraulic fracturing in the southern Sichuan Basin has severely compromised shale gas productivity, while the existing research has inadequately addressed both FDI risk reductions and the optimization of reservoir stimulation. To bridge this gap, this study developed a mechanistic model of the competitive multi-cluster fracture propagation under non-uniform perforation conditions and established a perforation-based design methodology for the mitigation of horizontal well interference. The results demonstrate that spindle-shaped perforations enhance the uniformity of fracture propagation by 20.3% and 35.1% compared to that under uniform and trapezoidal perforations, respectively, with the perforation quantity (48) and diameter (10 mm) identified as the dominant control parameters for balancing multi-cluster growth. Through a systematic evaluation of the fracture communication mechanisms, three distinct inter-well types of FDI were identified: Type I (natural fracture–stress anisotropy synergy), Type II (natural-fracture-dominated), and Type III (stress-anisotropy-dominated). To mitigate these, customized perforation schemes coupled with geometry-optimized fracture layouts were developed. The surveillance data for the offset well show that the pressure interference decreased from 14.95 MPa and 6.23 MPa before its application to 0.7 MPa and 0 MPa, achieving an approximately 95.3% reduction in the pressure interference in the application wells. The expansion morphology of the inter-well fractures confirmed effective fluid redistribution across clusters and containment of the overextension of planar fractures, demonstrating this methodology’s dual capability to enhance the effectiveness of stimulation while resolving FDI challenges in deep shale reservoirs, thereby advancing both productivity and operational sustainability in complex fracturing operations. Full article

Natural hydrogen is generated by fairly deep processes and/or in low-permeability rocks. In such contexts, fluids circulate mainly through the network of faults and fractures. However, hydrogen flows from these hydrogen-generating layers can reach sedimentary rocks with more typical permeability and porosity, allowing H₂ flows to spread out rather than be concentrated in fractures. In that case, three different H₂ transport modes exist: advection (displacement of water carrying dissolved gas), diffusion, and free gas Darcy flow. Numerical models have been run to compare the efficiency of these different modes and the pathway they imply for the H₂ in a sedimentary basin with active aquifers. The results show the key roles of these aquifers but also the competition between free gas flow and the dissolved gas displacement which can go in opposite directions. Even with a conservative hypothesis on the H₂ charge, a gaseous phase exists at few kilometers deep as well as free gas accumulation. Gaseous phase displacement could be the faster and diffusion is neglectable. The modeling also allows us to predict where H₂ is expected in the soil: in fault zones, eventually above accumulations, and, more likely, due to exsolution, above shallow aquifers. Full article

Deep coalbed methane (CBM) reservoirs are characterized by high hydrocarbon content and are considered an important strategic resource. Due to their inherently low permeability and porosity, horizontal well drilling is commonly employed to enhance production, with the length of the horizontal section playing a critical role in determining CBM output. However, during extended horizontal drilling, wellbore instability frequently occurs as a result of drilling fluid invasion into the coal formation, posing significant safety challenges. This instability is primarily caused by the physical intrusion of drilling fluids and their interactions with the coal seam, which alter the mechanical integrity of the formation. To address these challenges, interpenetrating and semi-interpenetrating network (IPN/s-IPN) hydrogels have gained attention due to their superior physicochemical properties. This material offers enhanced sealing and support performance across fracture widths ranging from micrometers to millimeters, making it especially suited for plugging applications in deep CBM reservoirs. A self-degradable interpenetrating double-network hydrogel particle plugging agent (SSG) was developed in this study, using polyacrylamide (PAM) as the primary network and an ionic polymer as the secondary network. The SSG demonstrated excellent thermal stability, remaining intact for at least 40 h in simulated formation water at 120 °C with a degradation rate as high as 90.8%, thereby minimizing potential damage to the reservoir. After thermal aging at 120 °C, the SSG maintained strong plugging performance and favorable viscoelastic properties. A drilling fluid containing 2% SSG achieved an invasion depth of only 2.85 cm in an 80–100 mesh sand bed. The linear viscoelastic region (LVR) ranged from 0.1% to 0.98%, and the elastic modulus reached 2100 Pa, indicating robust mechanical support and deformation resistance. Full article

Recovering oil by fracturing fluid imbibition has demonstrated significant potential for enhanced oil recovery (EOR) in tight oil reservoirs. White mineral oil (WMO), kerosene, or saturated alkanes with matched apparent viscosity have been widely used as “crude oil” to investigate imbibition mechanisms in light shale oil or tight oil. However, the representativeness of these simulated oils for low-maturity crude oils with higher viscosity and greater content of resins and asphaltenes requires further research. In this study, imbibition experiments were conducted and T₂ and T₁–T₂ nuclear magnetic resonance (NMR) spectra were adopted to investigate the oil recovery characteristics among resin–asphaltene-rich Jimusar shale oil and two WMOs. The overall imbibition recovery rates, pore scale recovery characteristics, mobility variations among oils with different occurrence states, as well as key factors influencing imbibition efficiency were analyzed. The results show the following: (1) WMO, kerosene, or alkanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes, their influence on pore wettability alteration, and may consequently overestimate the intrinsic imbibition displacement efficiency in reservoir formations. (2) Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension in governing displacement dynamics. (3) Imbibition displacement exhibits selective mobilization characteristics for oil phases in pores. Specifically, when the oil phase contains complex hydrocarbon components, lighter fractions in larger pores are preferentially mobilized; when the oil composition is homogeneous, oil in smaller pores is mobilized first. Full article

This study developed a copper mineral prospectivity map for the Koldar massif, Kazakhstan, using an integrated approach combining geophysical and satellite methods. A strong spatialgenetic link was identified between faults and hydrothermal mineralization, with faults acting as key conduits for ore-bearing fluids. Lineament analysis and density mapping confirmed the high permeability of the Koldar massif, indicating its structural prospectivity. Hyperspectral and multispectral data (ASTER, PRISMA, WorldView-3) were applied for detailed mapping of hydrothermal alteration (phyllic, propylitic, argillic zones), which are critical for discovering porphyry copper deposits. In particular, WorldView-3 imagery facilitated the identification of new prospective zones. The transformation of magnetic and gravity data successfully delineated geological features and structural boundaries, confirming the fractured nature of the massif, a key structural factor for mineralization. The resulting map of prospective zones, created by normalizing and integrating four evidential layers (lineament density, PRISMA-derived hydrothermal alteration, magnetic, and gravity anomalies), is thoroughly validated, successfully outlining the known Aktogay, Aidarly, and Kyzylkiya deposits. Furthermore, new, previously underestimated prospective areas were identified. This work fills a significant knowledge gap concerning the Koldar massif, which had not been extensively studied using satellite methods previously. The key advantage of this research lies in its comprehensive approach and the successful application of high-quality hyperspectral imagery for mapping new prospective zones, offering a cost-effective and efficient alternative to traditional ground-based investigations. Full article

To address critical technical challenges in coalbed methane fracturing, including the uncontrollable release rate of conventional breaker agents and incomplete gel breaking, this study designs and fabricates an intelligent controlled-release breaker system based on paraffin-coated mesoporous silica nanoparticle carriers. Three types of mesoporous silica (MSN) carriers with distinct pore sizes are synthesized via the sol-gel method using CTAB, P123, and F127 as structure-directing agents, respectively. Following hydrophobic modification with octyltriethoxysilane, n-butanol breaker agents are loaded into the carriers, and a temperature-responsive controlled-release system is constructed via paraffin coating technology. The pore size distribution was analyzed by the BJH model, confirming that the average pore diameters of CTAB-MSNs, P123-MSNs, and F127-MSNs were 5.18 nm, 6.36 nm, and 6.40 nm, respectively. The BET specific surface areas were 686.08, 853.17, and 946.89 m²/g, exhibiting an increasing trend with the increase in pore size. Drug-loading performance studies reveal that at the optimal loading concentration of 30 mg/mL, the loading efficiencies of n-butanol on the three carriers reach 28.6%, 35.2%, and 38.9%, respectively. The release behavior study under simulated reservoir temperature conditions (85 °C) reveals that the paraffin-coated system exhibits a distinct three-stage release pattern: a lag phase (0–1 h) caused by paraffin encapsulation, a rapid release phase (1–8 h) induced by high-temperature concentration diffusion, and a sustained release phase (8–30 h) attributed to nano-mesoporous characteristics. This intelligent controlled-release breaker demonstrates excellent temporal compatibility with coalbed methane fracturing processes, providing a novel technical solution for the efficient and clean development of coalbed methane. Full article

Horizontal well fracturing is vital for low-permeability tight oil reservoirs, but multi-fracture effectiveness is hampered by stress shadowing and fluid-rock interactions, particuarly in optimizing fracture geometry and conductivity under different sequencing strategies. While previous studies have addressed aspects of pore pressure and stress effects, a comprehensive comparison of sequencing strategies using fully coupled models capturing the intricate seepage–stress–damage interactions remains limited. This study employs a novel 2D fully coupled XFEM model to quantitatively evaluate three fracturing approaches: simultaneous, sequential, and alternating. Numerical results demonstrate that sequential and alternating strategies alleviate stress interference, increasing cumulative fracture length by 20.6% and 26.1%, respectively, versus conventional simultaneous fracturing. Based on the research findings, fracture width reductions are 30.44% (simultaneous), 18.78% (sequential), and 7.21% (alternating). As fracture width directly governs conductivity—the critical parameter determining hydrocarbon flow efficiency—the alternating strategy’s superior width preservation (92.79% retention) enables optimal conductivity design. These findings provide critical insights for designing fracture networks with targeted dimensions and conductivity in tight reservoirs and offer a practical basis to optimize fracture sequencing design. Full article