Search Results (558)

Deep coalbed methane (CBM) is a core exploration and development domain for increasing the reserves and production of unconventional natural gas in China. A systematic understanding has been established on the enrichment and accumulation mechanism of high-rank deep CBM in the southern section of the eastern margin of the Ordos Basin. However, the medium-rank deep CBM in the Mugua Area of the Shenfu Gas Field in the northern section of the eastern margin has essential differences from that in the southern section in terms of coal rank and hydrocarbon generation–occurrence mechanism, and its accumulation and enrichment regularity remain unclear. The core innovations of this study are as follows: aiming at the unclear accumulation regularity of medium-rank deep CBM in the northern section of the eastern margin of the Ordos Basin, we first reveal the spatiotemporal synergistic coupling reservoir-controlling mechanism of five factors (sedimentation–thermal evolution–temperature–pressure–preservation), determine the 1750 m critical transition zone of the deep CBM occurrence state, and establish two types of accumulation models adapted to the geological characteristics of medium-rank coal. Taking the No.8+9 coal seams of the Taiyuan Formation in the Mugua Area as the research object, based on the theoretical foundation of the dual properties of coal seams as the “source rock–reservoir”, this paper comprehensively adopted technical means such as core observation, drilling and logging data, and high-pressure isothermal adsorption experiments to carry out systematic multi-dimensional studies on sedimentary microfacies, coal reservoir characteristics, thermal evolution degree, and gas-bearing property; identified the main controlling factors of CBM accumulation; and constructed the accumulation model. The results show the following: ① The main burial depth of the coal seams is more than 1700 m, with a thickness ranging from 7.0 to 21.3 m and an average of 15.1 m, and the coal structure is dominated by the primary structure; maximum vitrinite reflectance (R_o,max) is generally distributed from 0.90% to 1.39% with an average of 1.08%, belonging to typical medium-rank coal; and the organic matter type is mainly Type III, with an average gas content of 10.01 m³/t, where the average proportion of desorbed gas in the total gas content is 83.91%, featuring superior source and reservoir conditions and a good foundation for CBM enrichment. ② The CBM accumulation in this area is jointly controlled by the coupling of four factors: sedimentation, thermal evolution degree, temperature–pressure effect, and preservation conditions. The tidal flat–lagoon facies control the development of high-quality coal seams; regional metamorphism dominates the hydrocarbon generation capacity and gas quality of coal seams; the temperature–pressure coupling forms a critical adsorption zone at 1750 m, defining the differentiation boundary of the occurrence state of deep CBM; and high-quality mudstone cap rocks, a stable structural environment, and closed hydrodynamic conditions constitute the three key guarantees for gas enrichment. ③ Two types of accumulation models are divided: “source–reservoir integration + multi-factor synergistic enrichment type” and “source–reservoir limited + insufficient accumulation condition type”. Among them, the four reservoir-controlling factors of the synergistic enrichment type are highly coupled, with excellent gas-bearing property and strong recoverability. This study systematically clarifies the enrichment and accumulation regularity of medium-rank deep CBM in the Mugua Area and improves the accumulation theory of medium-rank deep CBM in the northern section of the eastern margin of the Ordos Basin. Full article

Conventional Diagnostic Fracture Injection Tests (DFITs) are widely used for formation pressure estimation, but in practice, they frequently require days, weeks, or even months of extended shut-in periods, a challenge particularly pronounced when large injection volumes are coupled with ultra-low formation permeability. While recent studies have proposed various modified DFIT approaches to reduce testing time, direct physical validation confirming the reliability of the derived formation pressure estimates remains scarce in the literature. This study applies a low-rate/volume injection mini-frac approach that integrates flow regime identification and Horner analysis. Two complementary field cases are presented: a standard DFIT in a shale reservoir to validate the baseline methodology, and a low-volume mini-frac in a tight granite formation to demonstrate rapid estimation. Results show that low-volume injections exhibit a flow regime evolution identical to standard DFITs, yet this approach is expected to accelerate the transition to the pseudo-radial flow regime. To verify the reliability of formation pressure estimates derived from such methods, the formation pressure estimated in the low-rate/volume injection mini-frac case was benchmarked against a decade of continuous downhole fluid pressure monitoring data from the same well, yielding a relative error of less than 5%. The findings suggest that employing a lower injection rate and volume can improve formation pressure testing efficiency, with potential applications in unconventional hydrocarbon development and deep geo-energy engineering. Full article

Unconventional oil and gas reservoirs naturally have low porosity and low permeability, which necessitate reservoir stimulation during production to achieve commercial exploitation. Therefore, to improve reservoir stimulation effectiveness, this study established a thermal–hydraulic–mechanical coupled numerical model suitable for hydraulic fracturing experiment scales based on rock mechanics, elasticity mechanics, damage mechanics, and flow mechanics theories, combined with maximum principal stress and Mohr–Coulomb damage criteria. The model was numerically solved within a finite element framework and used to simulate the reservoir hydraulic fracturing process. The results indicate that the propagation behavior of hydraulic fractures is controlled by reservoir rock mechanical properties, geostresses, reservoir temperatures, fracturing fluid viscosities, and injection rates. Among these, the increase in principal stress difference, reservoir temperature, fracturing fluid viscosity and injection rate promotes the propagation of hydraulic fractures along the direction of the maximum horizontal principal stress, whereas an increase in the rock’s elastic modulus reduces the propagation length of the hydraulic fractures. During fracturing, the fracturing fluid fractures the reservoir rock, significantly improving its porosity and permeability. This not only enhances the mobilization of unconventional oil and gas resources but also provides effective flow pathways for their migration, thereby ensuring the commercial viability of unconventional oil and gas resource extraction. Additionally, selecting a fracturing process that matches the geological characteristics of the study area during fracturing design is a prerequisite for improving the reservoir stimulation effect. The results of this study provide a reference for fracturing design and optimization. Full article

Supercritical carbon dioxide (SC-CO₂) fracturing has been recognized as an effective technology for developing unconventional oil and gas resources. The extent to which natural fractures can be activated is a critical factor controlling overall reservoir stimulation. A thorough understanding of the activation and propagation mechanisms of natural fractures during SC-CO₂ fracturing is therefore essential for elucidating fracture network evolution and optimizing stimulation strategies. In this work, a multiphysics-coupled numerical model for intersecting fracture propagation was developed using the phase-field method, incorporating formation pressure evolution and variations in CO₂ properties (density and viscosity). Based on this model, the influences of fracture approach angle, horizontal stress difference, injection temperature, and injection rate on fracture propagation patterns and pressure diffusion were systematically investigated. To quantitatively describe the stimulated reservoir volume, a “diffuse interface” was defined to represent the region affected by SC-CO₂ injection. The simulation results demonstrate that larger approach angles enhance the activation of natural fractures, with a 60° angle producing the maximum diffuse interface ratio of 72.5%. Although higher horizontal stress differences tend to suppress fracture activation, they promote plastic deformation at fracture tips, enlarging the diffuse interface to 86.72% at 15 MPa. Elevated injection temperatures further facilitate fracture propagation; as the temperature rises from 313.15 K to 403.15 K, the lateral fracture length increases from 2.8 cm to 3.7 cm, accompanied by continuous expansion of the diffuse interface. Under constant injection rate, a greater injection volume also enhances natural fracture activation and drives fractures to extend farther. These results provide theoretical insights for the design and optimization of SC-CO₂ fracturing in naturally fractured reservoirs. Full article

The Fengcheng Formation in the Mahu Sag of the Junggar Basin represents one of the oldest and most significant alkaline lacustrine systems, hosting abundant dolomite that serves as a key unconventional reservoir. However, the formation mechanism of dolomite remains unclear. This study integrates detailed petrography, geochemistry and cyclostratigraphy to elucidate the origin and distribution of dolomite. Petrographic characteristics indicate a penecontemporaneous origin for the dolomite, with no apparent hydrothermal influence. Mineralogical features exhibit a multi-zonation structure of dolomite, aligning with in situ Fe content, jointly indicating that a multi-stage formation process of dolomite from core to rim. Microbial methanogenesis likely played an important role in the dolomite formation. Spatially, dolomite is enriched in the transition zone but scarce in the depocenter zone, where sodium carbonate prevails. This distribution is primarily controlled by pH differentiation between the transition zone and the depocenter zone of the Mahu Sag. In the transition zone, orbitally driven wet–dry cycles regulated the lake-level change, which, in turn, controlled pH fluctuation, as revealed by the silica precipitation during humid phases and dissolution during arid intervals. In the depocenter zone, lake water remained at a high-pH state, which was unfavorable for dolomite formation. These findings highlight that pH dynamics, linked to orbital climate cycles, played a critical role in governing dolomite formation and distribution in this ancient alkaline lake, providing new insights for the formation of dolomite in alkaline lacustrine environments. Full article

Rhyolites serve as unconventional hydrocarbon-water reservoirs and also as high-quality volcanic reservoirs. Well BZ8-3S-B exhibits maximum productivity in vertical wells. Drilling results reveal significant mega-scale heterogeneity among different wells within the same rhyolitic volcanic edifice, as well as between different intervals within single wells. To clarify the mega-scale heterogeneity characteristics of rhyolitic reservoirs, this study investigates Block BZ8-3S in the Bozhong Depression, Bohai Bay Basin, China. Based on sidewall cores, logging data and seismic datasets, comprehensive research methods including petrographic/mineralogical analysis, image processing, porosity–permeability testing, mercury capillary pressure measurements, logging facies interpretation and seismic facies analyses were employed. The study establishes correlations between volcanic edifice architecture, stratigraphic boundaries, depositional units and their relationships with reservoir space composition/permeability characteristics, aiming to identify principal controlling factors of mega-scale heterogeneity through systematic stratigraphic architecture analysis. The key findings are summarized as follows: (i) The volcanic edifices in Block BZ8-3S exhibit massive-pseudostratified structural characteristics. (ii) Wells A and B belong to the same volcanic edifice system but occupy distinct facies belts. Well A is located in the crater-near crater belt, while Well B lies in the proximal belt. (iii) Eruptive interval unconformity boundaries (EIUBs) are identified at 1 and 4 depths in Wells A and B, respectively. The EIUBs control the vertical heterogeneity of depositional-unit reservoirs. Reservoir porosity exhibits inverse correlation with burial depth below EIUBs, indicating stratigraphic boundary control on reservoir development. Mega-scale heterogeneity of rhyolitic reservoirs is primarily controlled by the number of stratigraphic boundaries and depositional unit types. From an exploration perspective, lava dome deposited units within crater-near crater belt should be avoided, while priority should be given to proximal belt targets featuring thick sequences with high proportions of lava flow units. This study provides critical insights for optimizing exploration strategies and enhancing development efficiency of rhyolite volcanic edifices. Full article

Helium-rich unconventional natural gas resources have attracted increasing attention from both academia and industry. A pronounced local enrichment of helium has recently been identified in coal-derived unconventional natural gas in the Sanjiaobei block on the eastern margin of the Ordos Basin. To clarify the main controls on helium enrichment in unconventional natural gas in this area and to guide the exploration of helium-rich resources, this study systematically examines the source of helium, its transport carrier, multiphase fractionation processes, and enrichment and accumulation pattern in natural gas. The analysis is based on conventional gas composition, helium volumetric content, carbon isotopes, and noble gas isotopes (He, Ne, and Ar) measured from wellhead gas samples collected from 11 production wells in the block, together with the regional deep structural evolution and hydrogeological conditions. The results show that: (1) the helium volumetric content of natural gas in the study area ranges from 0.0175% to 0.214%, with an average of 0.108%, and most wells fall within the high-helium grade category; (2) the helium isotope ratios ³He/⁴He (R/Ra) of the samples range from 0.0148 to 0.0824, indicating a typical crustal helium source; the good positive correlation between helium and nitrogen volumetric contents suggests that the two components share a highly consistent source affinity or common migration and accumulation behavior during fluid evolution; and the extremely high He/Ne ratios, on the order of 10⁴, together with excess Ar isotopes, indicate that the gases experienced little dilution by shallow atmospheric water or modern atmospheric fluids during migration and accumulation. The formation of helium-rich unconventional gas reservoirs on the eastern margin of the Ordos Basin is interpreted to be characterized by basement-derived helium supply, activation by tectonothermal events, groundwater transport, efficient fault-controlled migration, reservoir capture along migration pathways, and sealing by stagnant groundwater and lithologic barriers. On this basis, a helium enrichment model is established. This model depicts the geochemical evolution pathway of trace noble gases in a natural gas system and may provide a useful reference for helium resource evaluation in analogous areas. Full article

The efficient development of low-permeability reservoirs is critically constrained by severe geological heterogeneity, marginal permeability (<10 mD), and the consequent prevalence of low-productivity wells. Conventional intermittent production management, reliant on empirical fixed-cycle schedules, fails to adapt to dynamic reservoir behavior and wellbore conditions, leading to suboptimal energy efficiency and recovery. This study presents a physics-constrained, data-driven framework for adaptive intermittent production optimization, specifically designed to address the coupled geological-engineering complexities of such reservoirs. The methodology integrates three core innovations: (1) a hybrid flowing bottomhole pressure (FBHP) decline model coupling a “Three-Segment” wellbore pressure calculation with inflow performance relationship (IPR) curves, enabling dynamic characterization of pressure depletion; (2) a shut-in pressure buildup prediction framework combining a physically interpretable dual-exponential recovery mechanism—representing near-wellbore elastic expansion and far-field formation recharge—with a Random Forest Regression algorithm to capture the influence of geological and operational heterogeneity; and (3) a “Dual-Curve Intersection Method” that autonomously determines optimal pumping and shut-in durations by intersecting predicted pressure decline and recovery curves under geological constraints. Field implementation on 15 low-production wells in the Jiyuan Oilfield—a representative low-permeability asset—demonstrated robust performance: average pump efficiency improved from 14.3% to 14.49%, and average single-well electricity savings reached 15.61%. This work establishes a closed-loop intelligent control framework that bridges reservoir geology, wellbore hydraulics, and machine learning, offering a scalable solution for enhancing energy efficiency and production sustainability in low-permeability and unconventional resources. Full article

The Gulong shale oil reservoir is characterized by high clay content and strong heterogeneity, with substantial variations in mineral composition among different intervals. However, existing fracability evaluation methods for such continental shales remain inconsistent and often rely on oversimplified two-dimensional fracture descriptors, lacking a multi-parameter quantitative framework derived from three-dimensional fracture characterization. In this study, the Q1 and Q9 members of the Gulong shale oil were selected, and laboratory-scale hydraulic fracturing simulation experiments were conducted using supercritical carbon dioxide (SC-CO₂), liquid CO₂, and water as the fracturing media. Within a fractal-theory framework based on CT-derived three-dimensional reconstructions, a multi-scale evaluation index system was established by integrating fractal dimension, fracture density, and spatial connectivity. The experimental results demonstrate that fluid properties exert a decisive influence on rock failure behavior. Owing to its ultra-low viscosity and strong diffusivity, SC-CO₂ can significantly reduce formation breakdown pressure while effectively activating natural weak planes to generate a more complex fracture network. For the Q9 shale, the breakdown pressure under SC-CO₂ is reduced by 11.91% and 8.33% relative to water and liquid CO₂, respectively. Moreover, the fracture fractal dimension reaches 2.41 under SC-CO₂, which is markedly higher than the values obtained under liquid CO₂ (2.18) and water (2.12). Mineral composition and densely developed bedding are the key factors inducing fracture branching and deflection, whereas injection rate and an asymmetric stress field regulate the internal energy-release rate and stress path, thereby influencing fracture crossing capability and aperture evolution. Based on the experimental dataset, a fracture complexity index (FCI) evaluation model was developed: under SC-CO₂ fracturing, the FCI values are 8.92 for the Q9 member and 4.43 for the Q1 member, and the model predictions are in good agreement with physical observations. This work elucidates the failure mechanism of the Gulong shale under multi-field coupling and provides a theoretical basis for optimizing hydraulic fracturing and evaluating fracability in unconventional reservoirs through the proposed FCI-based assessment framework. Full article

Hydraulic fracture geometry is of great importance for evaluating stimulation effectiveness and supporting the efficient development of unconventional oil and gas reservoirs, and it can be estimated from field shut-in water hammer signals. However, field signals are commonly characterized by strong noise, pronounced non-stationarity, strong dependence on manual extraction of effective response segments, and limited automation in inversion analysis. To address these issues, this study develops an integrated automated interpretation framework for shut-in water hammer analysis, which combines an adaptive shape-preserving Kalman filter for non-stationary signal denoising, an automatic response segment identification method, and a particle swarm optimization-based inversion strategy for fracture geometry estimation. The framework is validated using field high-frequency pressure data from hydraulically fractured wells. The results show that the proposed denoising method improves the signal-to-noise ratio from 11.99 dB to 25.05 dB while preserving key transient features. The response segments can be extracted efficiently, with runtimes of 0.84–1.22 s and onset errors within 0–5 s. For a representative fracturing stage, the relative errors of the inverted fracture half-length and fracture height are 6.21% and 3.04%, respectively. The proposed framework provides a low-cost and field-applicable tool for fracture evaluation and engineering decision-making. Full article

The development of tight heavy-oil reservoirs is severely hampered by the high viscosity and poor mobility of crude oil caused by strong intermolecular stacking interactions among asphaltenes, coupled with the substantial adsorption loss and inadequate deep transport capacity of conventional displacement agents. By targeted penetrant delivery, a novel nanoemulsion system with a well-defined “core–shell” architecture was synthesized to address these critical challenges. The physicochemical properties, stability and oil displacement performance were evaluated. The prepared nanoemulsion exhibited an ultrasmall and uniform particle size distribution between 10 nm and 20 nm. It also demonstrated exceptional dispersibility in aqueous media and remarkable thermal and salinity stability under reservoir conditions. Furthermore, an ultralow critical micelle concentration of approximately 0.01% could be achieved and the oil–water interfacial tension was reduced to 7.3 × 10⁻² mN/m, significantly outperforming the conventional surfactant AES. Core flooding tests revealed that the proposed nanoemulsion enhanced oil recovery by 37.1% and attained a displacement efficiency of 68.9% in oil-wet capillary models. Molecular dynamics simulations further elucidated the underlying synergistic mechanism. The hydrophilic shell minimized adsorption on rock surfaces, facilitating deep migration within nanoporous channels. The hydrophobic core, containing terpinene as a penetrant, effectively disrupted the π-π stacking of asphaltenes due to its nonplanar molecular configuration. This disruption transformed the asphaltene aggregates from a tightly packed state to a dispersed state, resulting in substantial viscosity reduction. This work elucidated the mechanism of asphaltene aggregate disruption by nanoemulsions at the molecular level, offering a promising and theoretically grounded strategy for the efficient exploitation of tight heavy-oil reservoirs. Full article

Hydraulic fracturing of unconventional reservoirs requires accurate fracture monitoring for treatment optimization. Low-frequency distributed acoustic sensing (LF-DAS) in neighbor wells provides dense strain-rate observations, but gauge-length averaging limits spatial resolution and merges closely spaced fracture features. This study formulates gauge-length averaging as an explicit convolution operator and develops a regularized inversion method combining Tikhonov smoothing, a recursive prior, and L-curve parameter selection, supported by a semi-analytical multi-fracture forward model. On a synthetic benchmark, the method advances the effective resolution from the 10 m gauge-length scale to the 1 m sample-spacing scale, recovering fracture count in all hit-window time slices (versus 32% for raw data), achieving Pearson correlation of 0.80 versus 0.29, with peak-position error reduced by 47%. Noise-sensitivity analysis indicates a practical SNR floor near 20 dB, and Wiener-filter comparison confirms 1.5–2.7× correlation and 1.5–2.3× peak-count advantages across tested noise levels. Field application to HFTS-2 B1H stages 22 and 23 reveals previously hidden tensile features consistent with higher local fracture density. With per-stage processing in seconds and no extra sensing hardware, the method is well suited for near-real-time deployment. Full article

Shale gas, as an unconventional resource, requires hydraulic fracturing to create complex fracture networks due to its low porosity and permeability. However, the presence of interlayers significantly affects fracture propagation, leading to highly complex fracture morphologies. This study focuses on the interbedded shale of the WJP Formation in southern China. A three-dimensional block discrete element method (BDEM) was employed to establish a hydraulic fracture propagation model, systematically investigating the effects of geological parameters (stress difference, interlayer thickness), engineering parameters pumping rate, fluid volume, viscosity), and perforation parameters (cluster number, cluster spacing, perforation location) on fracture network morphology. The results indicate that: (1) Among geological parameters, interlayer thickness is the key factor inhibiting vertical fracture propagation. Due to the influence of interlayers, an increase in stress difference promotes fracture length but suppresses fracture height and stimulated reservoir volume (SRV); (2) For engineering parameters, there exists a “threshold effect” for pumping rate and fluid volume, with 16 m³/min and 2000 m³ identified as the critical thresholds for interlayer breakthrough. Low viscosity (1 mPa·s) is conducive to forming complex fracture networks, while high viscosity extends fracture length but reduces SRV; (3) Regarding perforation parameters, the optimal stimulation effect is achieved with 6–7 clusters, a cluster spacing of 10 m, and perforation locations in the center of the main shale layer (19.85–21.6 m); (4) By introducing grey relational analysis, the degree of correlation between various influencing factors and the response to interlayer breakthrough is systematically evaluated based on the breakthrough conditions under different factors. Thin interlayers or low stress differences can reduce the critical pumping rate, whereas thick interlayers (≥3 m) become the primary constraint, making breakthrough difficult even at high pumping rates. Reliable interlayer breakthrough requires the simultaneous satisfaction of Δσ ≤ 16 MPa, h < 1 m, and Q ≥ 16 m³/min. The reliability of the model was verified by comparing numerical simulation results with field microseismic data. This study reveals the extension laws of complex fracture networks in interbedded shale, providing a theoretical basis for fracturing design and development optimization. Full article

Liquid nitrogen (LN₂) fracturing is a highly promising stimulation technology for unconventional reservoirs. Understanding its in situ fracture network formation mechanism is essential for engineering practice. This study investigates coal rock fracturing driven by the synergistic effect of thermal stress and fluid pressure during LN₂ injection. A coupled thermal–hydraulic–mechanical–damage (THMD) numerical model is developed, incorporating in situ stress conditions and LN₂ phase change behavior. Through true triaxial LN₂ fracturing simulations validated against physical experiments, the multi-field dynamic coupling behavior is systematically analyzed, revealing the synergistic mechanism of fracture propagation and permeability enhancement under cryogenic conditions. The results show the following: (1) The proposed model effectively reproduces the true triaxial LN₂ fracturing process, with simulation results in good agreement with physical experiments. (2) LN₂ fracturing exhibits distinct stage-wise characteristics: cryogenic temperatures induce thermal stress that triggers micro-crack initiation; the self-enhancing effects of damage and permeability significantly promote fracture propagation; fluid pressure then becomes the dominant driving force. (3) Coal rock damage follows a four-stage evolution—wellbore crack initiation, stable propagation, unstable propagation, and through-going failure—ultimately forming a complex spatial fracture network. (4) The horizontal stress ratio is a key factor controlling fracture morphology: a single dominant fracture forms under a high stress difference, whereas a multi-directional complex network develops under equal confining pressure. Fractal analysis reveals significant anisotropy and a non-monotonic stress response in the fracture complexity, reflecting structural evolution from multi-directional propagation to main channel connection. This study provides theoretical support for understanding LN₂ fracturing mechanisms and optimizing field treatment parameters. Full article

Neutron logging-while-drilling is a nuclear logging technique within the logging-while-drilling (LWD) system, characterized by high sensitivity to hydrogen formation. With the increasing complexity of well trajectories and the development of unconventional oil and gas, it has evolved from a traditional porosity measurement tool into a critical source of real-time information for geosteering and engineering decision-making. From a systems engineering perspective, this paper reviews the physical basis, tool system configuration, data processing methods, and typical engineering applications of LWD neutron logging. It discusses key technical bottlenecks and development trends. The results indicate that multiple interacting factors, including the neutron source, detector configuration, measurement geometry, environmental suppression capability, and interpretation strategy, constrain its performance. The transition from chemical neutron sources to pulsed neutron generators (PNG) represents a critical turning point, improving measurement safety and expanding the range of measurable parameters while simultaneously introducing new engineering challenges such as target material lifetime and long-term stability. Field practice further demonstrates that the main value of LWD neutron logging lies in providing real-time porosity and related information that overcomes physical limitations during drilling, supporting geosteering and real-time reservoir evaluation decisions. Based on current progress, future work will focus on enhancing the reliability of PNG-based neutron sources and developing data processing and intelligent interpretation workflows that integrate physical models with data-driven methods. Full article