Search Results (450)

Characterizing multiscale fracture networks in shale gas reservoirs remains challenging, while the limited applicability of conventional continuum-based models and insufficient multi-objective coordination often lead to low efficiency in development optimization. To address these issues, this study proposes a production history matching and multi-objective collaborative optimization framework for shale gas horizontal wells based on an equivalent fractal fracture (EFF) model. By integrating fractal theory with intelligent optimization techniques, a multiscale equivalent fractal permeability tensor is constructed, forming a hybrid machine-learning framework that combines physics-based fractal constraints with data-driven learning for efficient representation of complex fracture networks. Microseismic event clouds were converted into continuous fracture-density and fractal-geometry descriptors through denoising, temporal alignment, and spatial interpolation, and these descriptors were mapped to the equivalent fractal fracture model to dynamically update key flow parameters for history matching and parameter inversion. On this basis, a multi-objective collaborative optimization strategy is developed to achieve simultaneous time-varying fracture characterization and dynamic regulation of development parameters. Comparative results indicate that the EFF-based approach yields a production prediction error of 6.8%, slightly higher than the 4.2% obtained using discrete fracture network (DFN) models, while requiring only one-eighteenth of the computational time. Using the net present value (NPV) as the unified objective function, constraints are imposed on bottom-hole flowing pressure, flowback rate and system switching time for optimization. With the optimized pressure drop being more uniform and the gas saturation distribution being more balanced, it is verified that “EFF + NPV” can achieve the coordinated optimization of “production capacity—decline—cost” and enhance the development efficiency. Full article

Defining the near-surface signal reflecting the deep sub-surface leakage is a critical challenge in the risk assessment of geologic carbon storage (GCS) projects, often exacerbated by decoupled deep-to-shallow modeling. This study quantifies the mass distribution and phase evolution of leaked CO₂ through deep reservoir-caprocks, intermediate aquifer, and near-surface soil, thereby showing the sub-surface retention characteristics and the detectability of near-surface signals. A geological model from the deep reservoir to the soil layer was constructed to simulate CO₂ leakage through the caprock and migration into overlying strata in 1000 years. Using the simulator of GPSFLOW, this study evaluates the evolution of fluid phases and the mass distribution during the injection for 100 years and the post-injection periods. The results indicate that (1) at the moment the injection ceases, 87.43–99.06% of the CO₂ remaining within the system is retained within the reservoirs, with less than 8.42% reaching the intermediate aquifer. Remarkably, although the CO₂ ultimately reaching the near-surface soil is less than 0.00073% of the total mass retained within the system, this mass accumulation translates to a concentration anomaly with a signal-to-noise ratio of 368 relative to the background baseline. (2) Sensitivity analysis reveals that the injection rate affects the timing of fluid transport—a tenfold increase in injection rate (from 3.17 to 31.7 kg/s) accelerates the upward movement of CO₂, advancing its arrival at the near-surface by 15 years without changing the overall mass partitioning. The permeability anisotropy ratio affects CO₂ migration and phase distribution—decreasing the vertical to horizontal permeability ratio (1, 0.5, 0.25, 0.125) reduces connectivity, which delays the upward transfer and increases the amount of the aqueous CO₂. However, specifically in the soil layer, the aqueous CO₂ accumulation reveals a non-monotonic trend that peaks at an intermediate ratio of 0.25. (3) CO₂ shows a cascading distribution across formations where reservoirs provide the primary storage, and the intermediate aquifer reduces the mass available for near-surface accumulation. This attenuation effect significantly reduces the CO₂ mass that reaches the soil layer, thereby controlling the strength and duration of near-surface environmental signals. This work offers a theoretical reference for formulating near-surface monitoring strategies for CO₂ leakage in GCS. Full article

Campylobacter jejuni is a major zoonotic pathogen that circulates among birds, livestock, humans, and environmental reservoirs, yet the genomic mechanisms that enable persistence and transmission across divergent hosts remain incompletely understood. Here, we sequenced 61 C. jejuni isolates recovered from multiple host-associated sources in Shenzhen, China, from 2016 to 2023, and analyzed them together with 312 dereplicated publicly available high-quality reference genomes. Phylogenomic analyses resolved three major clades, including one avian-restricted clade and two clades showing frequent cross-host occurrence. Human-associated isolates displayed lower coding density than mammal-associated isolates and significantly higher proteome-level carbon and nitrogen demands than avian-associated isolates. Comparative genomic analyses further revealed strong host-associated divergence in chromosome-encoded, plasmid-encoded, and horizontally acquired gene repertoires. In human-derived isolates, 11 dataset-specific human-unique KEGG genes and 48 human-unique virulence-associated genes were identified, and human-associated strains showed the strongest multidrug-resistance signal across both chromosome-encoded and mobile-gene compartments. Resistance-associated functions enriched in human-associated genomes included antibiotic inactivation, efflux-mediated resistance, target protection/replacement/alteration, reduced permeability, and nutrient-acquisition-associated resistance. By contrast, core host-interaction loci remained under strong purifying selection, indicating that major human-associated traits were linked more closely to mobile gene acquisition than to extensive mutation-driven diversification. Together, these findings support a proposed genome-partition framework of host adaptation in C. jejuni, in which relatively stable chromosomal backgrounds are complemented by rapid plasmid- and horizontal-transfer-mediated acquisition of high-impact accessory genes. Full article

The Jimusar shale reservoir exhibits extremely low permeability, classified as an ultra-low porosity and ultra-low permeability formation. Crude oil mobility is poor, and the reservoir demonstrates significant heterogeneity. Conventional horizontal well fracturing development fails to meet requirements, facing issues such as pronounced energy depletion in the formation, unclear oil–water distribution, and changes in formation stress direction. Based on the reservoir properties of the Jimusar shale oil reservoir, this paper establishes a fracture propagation model for horizontal wellbore hydraulic fracturing and a reservoir numerical model. It simulates the evolution of pressure fields, stress fields, and seepage fields at different time points during the fracturing and production phases of horizontal wells. Results indicate the following: (1) When fracturing fluid is injected into the formation, oil saturation around fractures rapidly decreases. During the initial production phase, oil saturation around fractures increases due to the recovery of some fracturing fluid and the sorption effect between fracturing fluid and crude oil. (2) Formation pressure around horizontal wells significantly increases upon fracturing fluid injection. The dual effects of fracture opening and fluid injection cause stress to rise near fractures. During production, both formation pressure and stress decrease near the wellbore, with greater pressure reduction in the near-wellbore zone than in the far-wellbore zone. However, formation stress decreases less near the wellbore due to stress concentration effects from fracture opening, resulting in a smaller reduction than in the far-wellbore zone. (3) The formation surrounding the fracture undergoes dual influences from fracture opening and fracturing fluid injection, causing deflection in the direction of near-wellbore stress. During the initial production phase, the impact of stress deflection gradually diminishes with ongoing production. However, after prolonged production, the deflection of formation stress intensifies. The conclusion states that this understanding clarifies the multi-field evolution patterns in fracturing production for horizontal well clusters, providing theoretical guidance for subsequent shale development processes. Full article

Granular deposition and grading strongly influence pore-space topology and hence hydraulic conductivity in natural and engineered porous media, yet quantitative links between deposition sequence, particle-scale morphology, pore-network descriptors, and permeability anisotropy remain incomplete. Here, we develop a process-based digital porous-media framework that couples discrete element method (DEM) deposition with pore-network characterization and Darcy-scale permeability evaluation. Two deposition sequences—normal grading (coarse-to-fine) and reverse grading (fine-to-coarse)—are simulated using bi-disperse particle sets with controlled size ratios. To further isolate the role of particle morphology, particle irregularity is parameterized by a Perlin-noise-based shape perturbation factor and incorporated into the DEM-generated packings. For each packing, pore networks are extracted and quantified in terms of pore/throat size distributions and connectivity, while pore-space complexity is measured via box-counting fractal dimension. Single-phase flow is solved under imposed pressure gradient, and intrinsic permeability is computed along three orthogonal directions to evaluate anisotropy. Results show that increasing size contrast reduces porosity, shifts pore and throat distributions toward smaller characteristic radii, increases pore-space fractal dimension, and yields a monotonic permeability reduction. For identical size ratios, reverse grading consistently yields higher permeability than normal grading, suggesting that deposition sequence exerts a strong control on the continuity and efficiency of effective flow pathways at the sample scale. Increasing particle irregularity decreases permeability and systematically modifies permeability anisotropy, transitioning from weak horizontal anisotropy toward near-isotropy and, at strong irregularity, toward preferential vertical permeability. The proposed framework provides a reproducible route to relate depositional history and particle morphology to pore-network structure and directional permeability, offering implications for filtration, packed-bed design, and sedimentary reservoir characterization. Full article

The Tianfu Gas Field in the Sichuan Basin is a core block for the large-scale, economic development of Jurassic tight gas in China. The first sub-member of the first member of the Shaximiao Formation in the Zhongjiang Block hosts typical low-porosity and low-permeability tight sandstone reservoirs. Based on detailed field geological surveys and core observations, this study employed multiple technical methods, including cast thin sections, scanning electron microscopy, computed tomography (CT) scanning, and nuclear magnetic resonance (NMR) to investigate sedimentary microfacies’ characteristics, analyze key reservoir properties (e.g., reservoir space types and pore structure), and clarify the main controlling factors of reservoir development. The results indicate the following: (1) The sedimentary period of the first sub-member of the first member of the Shaximiao formation (Es₁¹) was controlled by a subtropical humid climate, with widespread gray mudstones and bedding-parallel plant fossil fragments. The main sedimentary environment was a shallow-water delta front, where the underwater distributary channel microfacies was the dominant facies belt. (2) Reservoir lithology is dominated by lithic arkose and feldspathic litharenite, with low compositional and structural maturity. Residual primary intergranular pores are the dominant reservoir space type, followed by intragranular dissolved pores in feldspar and lithic fragments. (3) The pore structure is characterized by a small pore-throat radius, poor sorting, and strong heterogeneity. Reservoirs can be subdivided into three categories, with Types II and III being the main types developed in this block. (4) Underwater distributary channels of the shallow-water delta are the main occurrence of reservoir sand bodies. During the burial diagenetic stage, calcite and laumontite cementation and filling led to reservoir densification. Meanwhile, early-formed chlorite rim cement effectively protected primary pores by inhibiting grain compaction and quartz overgrowth. Superimposed with the dissolution and alteration of feldspar, lithic fragments, and other components by late acidic fluids, effective pores were further expanded. The synergistic coupling of these sand-controlling factors and the “densification–protection–alteration” diagenetic process jointly constitutes the formation mechanism of high-quality reservoirs. This mechanism can provide a reliable theoretical basis for the accurate prediction of reservoir “sweet spots” and the optimal selection of horizontal well targets in the Zhongjiang Block of the Tianfu Gas Field. Full article

Efficient development of tight reservoirs in shallow-water delta-front environments is often constrained by misaligned horizontal well design and the underlying geological architecture. To address this, a quantitative optimization workflow is proposed, integrating 3D architectural characterization of single sandbodies with reservoir simulation. Using the Chang 7 Member of the Ordos Basin as a case study, three dominant sandbody types—isolated channels, vertically stacked channels, and mouth bars—were characterized in terms of geometry, stacking pattern, and internal permeability anisotropy. High-resolution geological models incorporating stratigraphic cyclicity and heterogeneity were constructed. Local grid refinement around wellbores and fracture networks was implemented to improve simulation fidelity. Sensitivity analyses identified optimal values for horizontal section length, fracture stage, and fracture half-length for each sandbody architecture. The results indicate that production response is highly sensitive to sandbody geometry and heterogeneity, with diminishing returns observed beyond critical design thresholds. Field validation with three horizontal wells confirmed that optimized parameter sets aligned with geological architecture resulted in significantly improved and more stable oil production. To support application in similar reservoirs, a dimensionless design chart was developed using ratios of horizontal well length to sandbody length (L_h/L_s) and fracture length to sandbody width (L_f/W_s). This empirical tool enables rapid pre-drill assessments and informs well planning strategies aligned with sandbody architecture. By emphasizing the integration of geological and engineering disciplines, the approach offers a scalable framework for optimizing horizontal well design in geologically complex tight formations. Full article

Shale oil reservoirs are characterized by ultra-low matrix permeability. After large-scale hydraulic fracturing is applied to horizontal wells, fluid transport becomes highly complex, posing major challenges for accurately predicting production performance. In this study, a coupled multi-mechanism numerical model is developed for shale oil reservoirs with complex fracture networks. Using the Embedded Discrete Fracture Model (EDFM), the mass transport between the fracture and matrix and within the hydraulic fracture network can be accurately quantified. Based on core analysis and fluid experimental data, the dynamic evolution of rock and fluid properties is characterized by incorporating nanopore confinement effects, stress sensitivity, and threshold pressure gradient behavior. Numerical simulations are then conducted to investigate the impacts of multiple mechanisms, including nanopore confinement effects, stress sensitivity, and threshold pressure gradient, as well as their coupling effects on shale oil production. A field application is carried out using Well H1 in the Qingcheng shale oil reservoir. Simulation results indicate that nanopore confinement reduces bubble-point pressure, leading to a 3.60% increase in cumulative oil production and a noticeable reduction in the producing gas–oil ratio. Stress sensitivity causes a 2.68% decrease in cumulative oil production and suppresses gas production. The threshold pressure gradient exerts the strongest negative impact, resulting in an 8.01% reduction in cumulative oil production and a slight decrease in gas–oil ratio. When all mechanisms are simultaneously considered, strong nonlinear interactions emerge, yielding a 7.09% reduction in cumulative oil production—significantly different from the linear superposition of individual effects. These results demonstrate the necessity of accounting for multi-mechanism coupling to achieve reliable production forecasting in fractured shale oil reservoirs. Full article

Carbon dioxide (CO₂) emissions resulting from natural gas flaring are significant contributors to atmospheric greenhouse gases, posing a substantial risk to the Earth’s climate by exacerbating global warming. As a response, both the oil industry and government authorities are actively exploring cost-effective strategies to address this issue through carbon capture, utilization, and storage (CCUS), as well as reducing natural gas flaring and CO₂ leaks in the oil fields to mitigate the adverse consequences of greenhouse gas emissions. This study presents a numerical investigation of CO₂ utilization for enhanced oil recovery (EOR) and associated CO₂ retention in unconventional reservoirs, using the Bakken Formation as a representative case. A compositional reservoir model is developed to simulate CO₂ Huff-n-Puff (HnP) processes in a fractured horizontal well. The model incorporates dual-porosity and dual-permeability formulations, fluid–rock interactions, and an equation-of-state-based compositional framework to capture multiphase flow behavior. Key operational parameters, including reservoir pressure, injection rate, injection duration, and CO₂ molecular diffusion, are systematically evaluated to assess their impact on oil recovery and CO₂ retention. The results show that lower bottom-hole pressures enhance oil recovery through increased drawdown, while operating pressures near the minimum miscibility pressure (MMP) improve CO₂ solubility and overall retention. Extended injection durations and higher diffusion coefficients increase CO₂ dissolution in the oil phase but exhibit diminishing marginal benefits beyond an optimal injection time. The study quantifies residual and solubility trapping mechanisms during the operational timeframe of CO₂-EOR and provides mechanistic insights into optimizing CO₂-HnP performance in tight formations. The proposed framework establishes a technical basis for integrating CO₂-EOR with emission mitigation strategies in unconventional reservoirs. Full article

To address the challenges of designing geologically compatible, large-scale gas drainage strategies in gassy coal mines, this study introduces an integrated workflow combining detailed gas-geological unit subdivision with the Analytic Hierarchy Process (AHP) for the Baode Coal Mine. This approach aims to transform gas drainage technology selection from empirical judgment to a systematic, quantitative decision-making process, thereby enhancing control precision and mine safety. First, the No. 8 coal seam was refined into ten distinct gas-geological units (II-i to II-x), forming the foundation for a targeted management strategy. For these units, a quantitative evaluation index system was constructed, integrating key factors such as permeability, structural characteristics, and unit area. The AHP was then employed to assess the adaptability of four primary drainage technologies: ULB-uni/bi (underground long borehole unidirectional/bidirectional drainage), UULB (underground ultra-long directional borehole drainage), UDLB-SHF (underground directional long borehole drainage with staged hydraulic fracturing), and FHWS (fractured horizontal wells drilled from the surface). The decision analysis reveals significant regional differentiation in technical suitability. FHWS ranks highest in structurally complex and water-rich zones. UDLB-SHF and UULB serve as viable, cost-effective alternatives to FHWS in various scenarios, with UULB being particularly advantageous for “large-area pre-drainage” in extensive panels with relatively simple geology. ULB-uni/bi is confirmed as the most economical option but is suitable only for minor blocks with simple conditions. Consequently, the study proposes a hierarchical, zone-specific strategy: prioritizing surface-based FHWS for high-risk zones, employing UDLB-SHF for active permeability enhancement in low-permeability resource-rich areas, utilizing UULB for efficient large-area drainage, and restricting ULB-uni/bi to small, geologically normal blocks. Ultimately, this research establishes a robust technical selection system that integrates fine geological subdivision, AHP-based multi-criteria evaluation, and targeted technology matching. It provides a scientific basis for balancing risk control and cost optimization in gas drainage design for the Baode Coal Mine. In summary, the methodological framework proposed in this study provides a systematic approach for coal mine gas control under complex geological conditions. Its core value lies in achieving the unity of scientificity and practicality in gas control technology decisions through standardized analysis logic and differentiated adaptation mechanisms, thereby providing support for the precise and efficient development of coal mine gas control. Full article

Investigations into the production of gas hydrates from marine sediments have demonstrated that commercial viability necessitates a daily gas production rate of 130,000 to 200,000 m³. However, the second-round trial production in the South China Sea yielded only 28,700 m³/day, falling short of the rule-of-thumb for economic feasibility. Given the coexistence of natural gas hydrates (NGHs) and shallow gas in the subsurface reservoirs of the South China Sea, a co-production strategy (simultaneously exploiting NGHs and shallow gas) was proposed to reduce costs and enhance production efficiency. In this study, a large-scale, three-dimensional, multi-phase, and multi-component model was established based on the NGHs–shallow gas symbiotic system in the Qiongdongnan Basin. A dual horizontal well configuration was designed to extract NGHs from the hydrate-bearing layer and natural gas from the underlying shallow gas layer. Co-production via dual horizontal wells expanded the hydrate dissociation zone from the near-wellbore region to deeper strata, particularly enhanced the dissociation of NGHs in the region between the two horizontal wells. By the 10th year of simulation, the peak and cumulative volume rate of CH₄ released from hydrate dissociation increased to 3.52 and 1.45 times under the co-production scenario, resulting in a 2.4-fold improvement in NGH recovery efficiency. Sensitivity analyses of bottom hole pressure and length of the horizontal intervals revealed that reducing bottom hole pressure significantly improved the daily and accumulative gas production from hydrate-bearing reservoirs. The length of horizontal intervals emerged as a critical factor influencing the dissociation of NGHs, whereas it had negligible impact on gas production from shallow gas reservoir with satisfied permeability. This study provides insights into optimizing the development of marine hydrate resources via integrated exploitation strategies. Full article

CO₂-assisted steam huff and puff is an effective method to improve oil recovery and store CO₂ in heavy oil reservoirs. However, few studies focused on complex geological formations, such as bottom water. The bottom water condition not only complicates the process of oil production and CO₂ sequestration, but also makes migration and distribution of oil, water and CO₂ unclear. In this paper, a numerical geological model of an offshore heavy oil reservoir with bottom water is established to analyze the influence of bottom water on injection and production parameters, oil recovery and CO₂ storage capability under vertical and horizontal well layouts. The results show that the bottom water could maintain the formation pressure, but reduce the steam chamber radius and heavy oil utilization area, increase water production and decrease the oil–water ratio. CO₂ could enhance oil recovery in the bottom water reservoir. Oil development indicators of the horizontal well are higher than the vertical well. Meanwhile, CO₂-assisted steam huff and puff use in the bottom water reservoir can create a high-pressure and -temperature environment to make CO₂ supercritical, as it has better CO₂ storage capability and efficiency. The CO₂ storage efficiency of the horizontal well is 63% larger than the vertical well. Thus, the horizontal well layout should be used as a priority if bottom water presents. Conducted analysis of bottom water formation sensitivity parameters shows that the advantageous formation conditions are high oil saturation, porosity of 0.2–0.4 and permeability of 2000–3000 mD. The influence degrees of each formation parameter were evaluated as well. Full article

Due to reservoir heterogeneity and drilling/completion damage, the gas production distribution along the wellbore in low-permeability gas reservoirs generally exhibits significant unevenness, restricting the full utilization of single-well productivity. To address this issue, this paper constructs a novel multi-segment horizontal-well flow model considering the permeability differences along the wellbore. Our methodology developed the skin factor calculation method to quantitatively predict production after acid stimulation. Studies have shown that the heterogeneity of permeability along the wellbore significantly controls the gas production contribution and early production response of each well section, and the traditional homogeneity assumption is prone to leading to biases in production capacity evaluation. Compared with general acidizing, targeted acidizing combined with flow constraints can effectively reconstruct the gas production distribution, significantly enhance the contribution of low-yield sections, and improve overall production performance. Taking the P002-H3 well in the Sichuan Basin as an example, based on gas production profile identification and skin coefficient decomposition, drilling fluid invasion was identified as the dominant damage mechanism, and the acidizing scheme was optimized accordingly, verifying the engineering applicability of the proposed method in horizontal-well production capacity evaluation and stimulation optimization. Full article

An improved depleting sand fracture model was derived in this work using Finite Element Methods, taking into consideration the effect of pore pressure and production on in situ stresses. Sets of governing equations from the commercial finite element simulator COMSOL Multiphysics were used to obtain a model that compares well with the existing fracture model, mainly based on the Mohr–Coulomb failure criterion. The model uniquely couples reservoir depletion-induced stress evolution with fracture initiation and propagation within a unified finite element framework. A constant overburden load was used since its value majorly depends on depth, and the formation is assumed to be fixed at the bottom. The reservoir is assumed to be depleting at a constant rate with no water injection to assist pressure, with an average porosity of 25% and an average permeability of 251 mD at the beginning of production. The reservoir compacted during production, and in turn, porosity and permeability were reduced over the years of observation. Fracturing was observed to be much easier for the depleted reservoir, since horizontal stresses, which might have created friction, are reduced during reservoir production, signifying that for depleted reservoirs, a small fracture pressure is required. Created fractures are observed to propagate in the direction of the maximum horizontal stress and perpendicular to the direction of the minimum horizontal stress. Full article

The non-uniform production contribution caused by insufficient reservoir stimulation during initial fracturing significantly constrains the lifecycle and estimated ultimate recovery (EUR) of horizontal wells. Refracturing is therefore urgently required to reconstruct fracture networks and activate undeveloped reserves. In this study, a coupled geomechanics-matrix-fracture-seepage model is developed based on the Unconventional Fracturing Model (UFM) to characterize formation energy evolution and residual oil distribution. Simulation results indicate that initial fracturing creates a limited pressure diffusion radius (5–30 m), resulting in a “strong near-well, weak far-field” pressure distribution and inefficient residual oil utilization. To address this, a synergistic strategy is proposed, integrating “re-pressurization of existing fractures” for energy replenishment with “infill fracturing” for activating bypassed reserves. This strategy significantly outperforms conventional refracturing, increasing the predicted cumulative oil production by 55.86%. Parameter optimization indicates that maintaining a pumping rate of 10–12 m³/min and a fluid intensity of 1700–1900 m³/stage, while optimizing proppant ratios for conductivity, maximizes recovery. This work provides theoretical guidance for sweet spot evaluation and refracturing design in ultra-low permeability reservoirs. Full article