Search Results (173)

Tight reservoirs commonly exhibit low permeability and pronounced lithological heterogeneity, resulting in complex interactions among far-field stress, local structural weakness, and fluid-driven fracture propagation. In this study, four non-replicated 2 m × 2 m × 1 m physical-model specimens representing tight glutenite, tight sandstone, and No. 3 coal rock from the Huabei Oilfield were investigated using an ultra-large true-triaxial hydraulic-fracturing system. Surface-fracture observations, microseismic monitoring, and high-frequency wellhead-pressure measurements were integrated to compare fracture responses under lithology-specific combinations of injection rate, fluid viscosity, perforation configuration, and stress state. The tested glutenite cases exhibited branched or localized fracture patterns depending on the combined treatment configuration; the sandstone case was dominated by a throughgoing main fracture approximately aligned with the principal-stress direction; and the coal-rock case showed extensive participation of bedding and cleat systems. These morphological differences were accompanied by distinct pressure and microseismic signatures, indicating different pathways of hydraulic-energy redistribution and fracture activation. For the two glutenite cases, the combined change from a single-perforation configuration at 0.5 m³/min to three helical perforations at 120° and 0.7 m³/min was associated with a 42.2% larger microseismic-derived stimulated reservoir volume (SRV). Taken together, these responses indicate a shift from stronger far-field-stress-controlled localization in the comparatively uniform sandstone to progressively greater local structural control by heterogeneous interfaces in glutenite and by bedding/cleat discontinuities in coal rock. Because each configuration was represented by a single specimen and several experimental variables changed simultaneously among cases, the observed differences are interpreted as case-specific mechanistic trends rather than statistically established universal relationships. The results show the value of combining fracture morphology, microseismic spatial evolution, and pressure dynamics for interpreting lithology-dependent fracture propagation in ultra-large physical models and for developing qualitative, lithology-adapted hydraulic-fracturing concepts. Full article

Ultra-deep lattice-like fractured carbonate reservoirs, formed by multi-period tectonic movements, feature strong heterogeneity, multi-scale fracture nesting, and anisotropic in situ stress. However, hydraulic fracture (HF) propagation behaviors within these complex formations remain poorly understood. In this study, using an unstructured fracture network approach, we simulated HF propagation in two typical fault-controlled lattice-like structures: compressive-torsion and pull-apart overlap zones. The performance of commingled, staged, and temporary plugging fracturing was evaluated, alongside sensitivity analyses of wellbore orientation, plugging timing, pump rate, and fluid viscosity. Results indicate that HFs in compressive-torsion zones exhibit long, straight geometries with local tensile activation points. Conversely, pull-apart overlap zones promote step-shaped, multi-branched fractures with superior lateral connectivity. The optimal timing for temporary plugging exhibits a delayed trend with increasing natural fracture density, ranging from 50% to 70% of the fracturing process in compressive-torsion zones, whereas an earlier implementation is preferred in pull-apart overlap zones, occurring at 33–65% of the fracturing process. Furthermore, HFs in compressive-torsion zones are less sensitive to viscosity and pump rate. To optimize stimulated volume, a moderate viscosity of 50–60 mPa·s is universally recommended. Regarding pump rates, 8–10 m³/min is ideal for balanced connectivity in pull-apart overlap zones, whereas >12 m³/min is required for compressive-torsion zones. These findings provide critical theoretical and engineering guidelines for differentiated fracturing strategies in ultra-deep reservoirs. Full article

Reservoir stimulation through fracturing is essential for the commercial development of unconventional oil and gas resources. Supercritical CO₂ (scCO₂) combines liquid-like density with gas-like viscosity and compressibility, enabling efficient conversion of stored energy into shock waves and jet impacts. This study introduces an innovative scCO₂ shock fracturing technique, in which a downhole pressure-control valve rapidly releases compressed scCO₂ to generate transient shock pressures that induce rock fracture initiation and propagation. A series of scCO₂ shock fracturing experiments were conducted on sandstone and shale to evaluate the influence of different impact loads on both macroscopic and microscopic damage. Rock damage evolution was characterized using computed tomography (CT), nuclear magnetic resonance (NMR), mercury intrusion porosimetry (MIP), and quantitative analysis of fracture surface morphology. The results showed that increasing shock pressure enhanced fracture surface roughness, shear slip, and particle spalling in sandstone, producing rough tensile–shear fracture surfaces with a potential self-supporting tendency. NMR results indicated that sandstone mainly exhibited a single-peak T₂ response, and scCO₂ shock loading primarily affected pores and pore-fracture spaces larger than 0.08 µm. In contrast, shale showed a broader and more heterogeneous pore-fracture response, with preferential enlargement and connection of large pore-fracture spaces. The NMR-MIP-calibrated equivalent pore-fracture diameter distribution showed that scCO₂ shock fracturing mainly promoted pore-fracture spaces larger than 0.2 μm in shale; at 40 MPa, the volume of this pore-fracture range increased by approximately 6.75 times. However, the characteristic equivalent pore-fracture diameter decreased at 45 MPa, which is attributed to severe specimen fragmentation, fragment displacement, scCO₂ escape, and energy dissipation. These findings suggest that scCO₂ shock fracturing is a promising stimulation approach for enhancing macroscopic fracturing and microscopic pore-fracture reconstruction in unconventional reservoirs. Full article

Child-well stimulation design has become a central challenge in mature unconventional reservoirs, where infill wells are commonly completed in reservoirs that have already been modified by parent-well production. Prior depletion changes pore pressure, stress distribution, and fracture-propagation pathways, causing child-well treatments to behave differently from parent-well completions. As a result, increasing fluid volume, proppant loading, stage density, or pump rate does not necessarily produce proportional gains in recovery. This review synthesizes the comprehensive literature on child-well stimulation intensity with emphasis on well performance, fracture-driven interactions, pad-scale economics, diagnostics, and resource-use considerations. The analysis shows that the production response is highly conditional: larger treatments can enhance reservoir contact when fractures access underdrained rock; however they may lose effectiveness when depletion-induced stress changes redirect fracture growth toward parent-well drainage areas or pre-existing fracture networks. In such cases, higher nominal intensity can increase interwell communication, reduce completion efficiency, impair parent-well performance, and weaken pad-level economic value. A key outcome of this review is the distinction between nominal stimulation intensity, represented by the treatment pumped, and effective stimulation intensity, represented by the fraction of that treatment that creates incremental productive fracture area. This distinction reframes child-well optimization from a treatment-size problem to a depletion-aware fracture-placement problem. Diagnostics, coupled modeling, production analysis, and mitigation strategies are therefore necessary to determine whether added stimulation intensity improves recovery or primarily redistributes production within the pad. From an economic perspective, the pad rather than the individual child well is the correct unit for evaluating stimulation-intensity decisions, since pad-level net present value integrates incremental child-well recovery, parent-well degradation, protection costs, spacing effects, and completion capital. Produced-water reuse and lifecycle emission benchmarking represent practical tools for reducing the environmental footprint of child-well development programs while simultaneously lowering freshwater demand and disposal volumes. These economic and environmental dimensions are inseparable from the technical optimization of stimulation intensity and are addressed explicitly in this review. This review concludes that child-well stimulation intensity should be optimized within a pad-scale framework that integrates depletion state, spacing, landing-zone selection, parent-well management, and long-term value rather than being uniformly maximized. Full article

Direct core-scale evidence remains insufficient for evaluating hydraulic fracture–natural fracture coupling and stimulation effectiveness in tight sandstone oil reservoirs. In this study, post-fracturing full-diameter cores from the Chang 8₁ tight oil reservoir in the Xi 119 well block, Xifeng Oilfield, Ordos Basin, were investigated using core observation, computed tomography (CT) scanning, fracture-source evidence and three-dimensional fracture-network reconstruction. A total of 87.56 m of core from 11 core runs was scanned at a voxel size of 50.62 μm. Natural fractures, hydraulic fractures and engineering-induced fractures were identified and distinguished based on fracture-surface features, CT expression, spatial continuity, proppant/tracer evidence and their relationship with bedding and lithological boundaries. The results show that lithological structure exerts a first-order control on hydraulic-fracture surface morphology. Massive sandstone tends to generate straight and continuous high-conductivity main fractures, argillaceous laminated sandstone promotes bedding-controlled discontinuous fractures with limited connectivity, and cross-bedded sandstone favors fracture diversion, branching and natural-fracture activation. Based on fracture assemblage, spatial connectivity and seepage behavior, three hydraulic fracture–natural fracture coupling types were classified: single hydraulic-fracture type, single main fracture–diverted fracture–natural fracture type, and dual main fractures–diverted fractures–natural fractures type. Their equivalent permeability increases stepwise from 155 mD to 345 mD and 586 mD, respectively, indicating a positive relationship between fracture-network complexity and seepage capacity. A CT-derived stimulation-effect evaluation framework was further established by integrating pore–fracture structural modification, fracture volume increase, aperture improvement and seepage-capacity enhancement. The dual main fractures–diverted fractures–natural fractures type shows the strongest stimulation response, with the largest reduction in small-aperture pore/fracture proportion, the greatest lamina-fracture aperture enlargement and the most significant permeability improvement. These results provide direct core-scale evidence for understanding fracture-network formation in continental tight sandstone reservoirs and support more targeted hydraulic-fracturing design and stimulation-effect evaluation. Full article

Deep low-rank coal from the Daqiang Mine in the Tiefa Basin was investigated using micro-CT imaging with a voxel size of 1 μm. The CT-resolved connected macropore structures of 12 representative elementary volumes (REVs) were reconstructed, and corresponding equivalent pore network models were established. Steady-state, isothermal, single-phase continuum methane flow was simulated under prescribed inlet and outlet pressures with no-flow lateral boundaries, which primarily represent the flow capacity of CT-resolved connected macropores under unstressed conditions. The results showed that: (1) the S1 group exhibited a relatively compact pore structure, smaller throats, stronger spatial heterogeneity, and poorer connectivity, whereas the S2 and S3 groups contained better-developed and more highly connected pore–throat networks; (2) the simulated mean absolute permeabilities of the S1, S2, and S3 groups were 0.781, 0.969, and 0.910 mD, respectively. These values were generally close to, but slightly higher than, the experimental measurements, mainly because the digital models retained only CT-resolved connected pores and did not account for stress-induced compression or the flow-limiting effects of unresolved fine throats; (3) permeability was positively correlated with pore radius, throat radius, and coordination number, but negatively correlated with throat length, pore-to-throat ratio, tortuosity, and fractal dimension. Among these parameters, throat radius showed the strongest correlation with permeability; and (4) an empirical regression model was further established: $K=-4.809+0.672 r_t+3.950 \tau .$ The model exhibited a high goodness of fit ($R^2=0.952$, $p<0.001$); however, its applicability is limited to the investigated coal samples from the Daqiang Mine. Overall, effective throat size and pore–throat connectivity provide more direct indicators of gas-transport capacity than total porosity alone, offering a pore-scale basis for identifying favorable CBM flow zones and optimizing reservoir stimulation strategies in the study area. Full article

The fracturing design of horizontal wells in low-permeability reservoirs mostly relies on static data such as logging data, and insufficient utilization of while-drilling information from drilling and mud logging leads to an unreliable basis for staged fracturing and cluster design, making it difficult to achieve efficient reservoir stimulation. To address this issue, this paper takes mechanical specific energy (MSE) as the core engineering parameter. Based on the drilling and mud logging data from the horizontal section of an example well, a mechanical specific energy model is established after data preprocessing. The K-medoids unsupervised clustering algorithm is adopted to realize the fine division of fracturing stages, and the optimal number of stages is determined using the elbow method. A fracturing sweet spot index (FSI) is constructed using the random forest algorithm. This index integrates four key parameters: oil saturation, porosity, permeability, and mechanical specific energy to optimize perforation cluster placement. The proposed method is validated through finite element numerical simulation and field data comparison. The research results show that the optimal division of the example well is determined as 11 stages with six clusters per stage, and the matching degree between stage-cluster division and reservoir heterogeneity is significantly improved. Compared with the original scheme, the stimulated reservoir volume (SRV) of the optimized construction scheme is increased by 19.6%, and the treatment pressure exhibits an obvious overall reduction trend, as demonstrated by the construction pressure curves. The research indicates that this method can make full use of drilling while-drilling data to realize integrated geological and engineering evaluations of fracturing and optimization of staged fracturing and cluster designs, and can provide effective technical support for the fracturing optimization design of horizontal wells in low-permeability reservoirs lacking complete logging data. Full article

Fracturing is the dominant stimulation technique for low-porosity, low-permeability dolomite gas reservoirs, yet the lack of systematic laboratory research on multistage alternating acid etching mechanisms restricts field construction parameter optimization. Targeting the low-permeability Xixiangchi Formation dolomite reservoir in the eastern Sichuan Basin, this work develops a high-temperature, high-pressure core acid etching system coupled with 3D surface scanning. A reliable lab-to-field parameter conversion is established based on the Reynolds and Froude similarity criteria. Four-factor three-level orthogonal tests are conducted to quantify the impacts of pad fluid-to-acid viscosity ratio, total acid volume, pumping rate, and alternating injection stages on JRC-characterized wall roughness and fracture conductivity. The results show an identical factor dominance ranking for both indicators: viscosity ratio > pumping rate > injection stages > total acid volume. The optimal stimulation scheme is determined as a 50:1 viscosity ratio, 120 mL total acid volume, 12.54 mL/min laboratory pumping rate (equivalent to 8 m³/min in field operations), and 3 alternating injection stages. An elevated viscosity ratio intensifies viscous fingering, induces heterogeneous dolomite dissolution, and forms abundant irregular asperities on fracture surfaces. These self-supporting rough structures sustain stable seepage channels and markedly improve conductivity, verifying the positive roughness-conductivity correlation and revealing the core mechanism of heterogeneous etching-driven conductivity enhancement. The findings provide direct experimental support and parameter guidance for multistage alternating acid fracturing design in the Xixiangchi Formation and analogous tight dolomite reservoirs. Full article

This study addresses the poorly understood fracture propagation mechanisms in continental shale oil reservoirs with multi-lithologic combinations, specifically those in the lower third member of the Shahejie Formation, Bonan Sag, which exhibit complex lithology, coexistence of bedding planes and natural fractures, and pronounced mechanical anisotropy. We conduct small scale true triaxial hydraulic fracturing physical simulation experiments using limestone mudstone, felsic–lime mixed shale, and their combined rock samples. We innovatively introduce the hydraulic fracture complexity coefficient (F_h), the bedding plane fracture complexity coefficient (F_l), and the comprehensive fracture complexity coefficient (F_T) to enable quantitative evaluation of fracture complexity. The results show that high-viscosity fracturing fluid promotes vertical propagation and improves proppant placement, but yields relatively simple fracture geometry. Low-viscosity fracturing fluid readily activates bedding plane fractures, yet limits fracture height; a combined viscosity strategy can synergistically optimize the overall fracturing performance. The “high–low–high” viscosity sequence achieves the highest comprehensive fracture complexity coefficient (F_T), simultaneously providing large fracture height, high complexity, and effective proppant transport. Although increasing the injection rate significantly reduces the breakdown pressure and increases fracture width, it contributes marginally to vertical fracture growth. For fracturing multi-lithologic shale oil reservoirs, the recommended technical strategy is a “high-low-high” viscosity sequence combined with a moderately increased injection rate” to maximize the stimulated reservoir volume and overall fracturing effectiveness. Full article

Stacked coalbed methane (CBM) reservoirs can increase the drainage thickness of a single well, but commingled production is influenced by stress-sensitive permeability, gas desorption, water drainage, and interlayer heterogeneity. This study presents a three-segment reservoir model for well GP-2 in the Tucheng block. Pore-fracture compressibility was estimated from overburden low-field nuclear magnetic resonance measurements and compared with stress-dependent permeability obtained by the pulse-decay method. The resulting coefficient was used in the dynamic permeability relationship and held fixed during history matching. The model was calibrated against gas- and water-production data from the first 240 d. One-factor simulations were then run over a common 3000 d calculation window to compare the relative responses to geological, adsorption, and stimulation parameters. In the GP-2 base model, average gas rate increased with equivalent coal thickness, gas content, Langmuir pressure, stimulated area, and stimulated-region permeability; inverse responses were obtained for cleat-fracture porosity, proportional three-layer initial permeability, initial reservoir pressure, and Langmuir volume. Adsorption time and interlayer spacing had comparatively small effects. These trends are specific to the selected model and parameter ranges and should not be interpreted as validated long-term forecasts or established causal relationships. This study demonstrates a practical way to carry a laboratory-derived stress-sensitivity parameter into a multilayer field model. Full article

Mature thin oil reservoirs remain pivotal to maintaining reserves, sustaining production, and enhancing profitability due to their substantial annual output and untapped recovery potential. However, prolonged development leads to compromised fracturing efficacy, manifesting as severe formation-energy depletion, rapid production decline, and short effective periods of stimulation measures. Energy-storage fracturing technology addresses these challenges through fluid-injection energization and imbibition displacement, thereby replenishing formation energy and mobilizing residual oil. Leveraging a geo-engineering integrated platform, this study establishes an inverted seven-spot well-pattern energization model to systematically investigate pore pressure–stress field evolution and dynamic responses under varying energization parameters, including energy-storage injection rate, energy-storage volume, and energy-storage sequence. Key findings include: (1) increasing the energy-storage injection rate from 1.5 m³/min to 3.5 m³/min elevates average pore pressure by 7.8 MPa, with minimum and maximum horizontal principal stresses increasing by 1.4 MPa and 1.7 MPa, respectively; (2) raising the energy-storage volume from 2800 m³ to 4200 m³ enhances pore pressure by 5.5 MPa, accompanied by 2.5 MPa and 2.6 MPa increments in minimum and maximum horizontal principal stresses; (3) simultaneous energizing of all injection wells (1–6) is identified as the optimal injection sequence, yielding the highest average pore pressure of 40.3 MPa at equivalent monitoring positions within the well group, with corresponding average minimum and maximum horizontal principal stresses of 55.3 MPa and 60.3 MPa, respectively. The results provide theoretical and technical support for optimizing energy-storage fracturing strategies in mature thin oil reservoirs. Full article

The Huainan Mining Area features extensively developed, fragmented-soft and low-permeability coal seams, characterized by low porosity and permeability, complex geological structures, and significant difficulty in coalbed methane (CBM) drainage. Horizontal wells with staged fracturing in the coal seam roof have become a key method for regional gas control. To further enhance the volume fracturing stimulation effect and single-well gas production, this study targets the horizontal well group in the roof of the No. 8 coal seam in the Huainan Mining Area as the research object. A saturated volume fracturing technology for horizontal wells in the coal seam roof, centered on the concept of a high pump rate (18–20 m³/min) and a high proppant volume (>250 m³/stage), is proposed. This study investigates the fracture propagation mechanisms and fracturing parameter optimization of this technology, and conducts engineering application to verify its stimulation effect. Increasing the fracturing pump rate improves the proppant-carrying capacity of the fracturing fluid, successfully enabling high-rate and high-volume proppant placement. Optimization of the perforation parameters—12 holes per m per cluster and a cluster spacing of 15–25 m—utilizes high perforation friction and moderate stress interference to promote balanced initiation and propagation of multiple fractures within a stage. The optimized ‘saturated’ injection mode, with a single-stage fluid volume exceeding 2400 m³, a single-stage proppant volume exceeding 250 m³, and a maximum sand ratio exceeding 20%, combined with a multi-size proppant mixture, enables full propping of both main and branch fractures. Microseismic monitoring shows that the hydraulic fracture extension length increased by approximately 50% compared to conventional wells, significantly enlarging the stimulated reservoir volume (SRV). Saturated fracturing achieved stable gas production of 2000 to 3000 m³/d, with average production ramp-up rates of 21.47–26.40 m³/d (five times higher than the 5.34 m³/d of the conventional well), and the stable plateau period was notably extended from 36 days to over 150 days. The saturated volume fracturing technology proposed in this study provides an important reference for efficient CBM extraction and surface gas control in mining areas with similar geological conditions. Full article

Hydraulic fracturing in naturally fractured shale reservoirs commonly generates complex mesh-like fracture networks governed by hydraulic fracture–natural fracture interactions, which strongly affect stimulated volume, fracture connectivity, and early-time production. Existing simulation and monitoring-based methods often cannot simultaneously capture interaction mechanisms, rapidly generate field-scale fracture networks, and validate production responses. This study proposes a mechanics-constrained recursive propagation framework. A field-constrained stochastic natural-fracture model is first constructed, an explicit hydraulic fracture–natural fracture interaction criterion is incorporated to identify penetration, opening, and shear slipping, and a fully vectorized bidirectional recursive algorithm is developed to efficiently generate complex fracture networks. The method is applied to a 40-stage fractured horizontal well in the Changqing Oilfield, where the target interval has a porosity of 6.1%, a permeability of 0.1 mD, and a horizontal stress contrast of 7.0 MPa. The simulated network reproduces crossing, arrest, unilateral diversion, and bilateral diversion, and agrees well with microseismic observations. EDFM-based fully implicit flow simulation further shows early-time production deviations of 2–10%. These results demonstrate that the proposed framework can efficiently generate physically plausible field-scale fracture networks for fracturing design, post-fracturing evaluation, and short-term production forecasting. Full article

Hydraulic fracturing is the core technology for stimulation and reform of low-permeability and unconventional oil and gas reservoirs. Reservoir fracability directly determines fracture morphology, complexity, and stimulated reservoir volume. To address the shortcomings of existing fracability evaluation models, such as poor applicability, subjective weighting and insufficient accuracy, five key indicators are selected, including brittleness index, brittle mineral index, stress difference coefficient, minimum horizontal principal stress and porosity. First, the three-dimensional discrete lattice method is used to clarify the influence of each parameter on fracture complexity. Then, the Analytic Hierarchy Process (AHP) and Entropy Weight Method (EWM) are combined to determine the indicator weights, a continuous fracability evaluation model is constructed, and a classification standard for fracturing applicability is established. The results show that the brittleness index has the greatest influence on fracture complexity with a weight of 0.3559, followed by brittle mineral index (0.2986), minimum principal stress (0.1994), stress difference coefficient (0.0993) and porosity (0.0467). The reservoir fracability indices of 0.37 and 0.59 are the mutation points of fracture complexity. Based on microseismic evaluation of stimulated reservoir volume (SRV) using an envelope surface method, it is found that reservoirs with low fracability are more suitable for fracturing designs characterized by large cluster spacing, fewer clusters, and smaller stage spacing. In contrast, reservoirs with medium and high fracability can develop more complex fracture networks by reducing cluster spacing, increasing the number of clusters, and adopting higher pumping rates. The research results can provide theoretical basis and technical support for hydraulic fracturing operation design. Full article

Evaluating the productivity contribution of individual fracturing stages in deep coalbed methane (CBM) horizontal wells remains a critical challenge, hindering the optimization of stimulation designs. This study systematically integrates dual-phase (aqueous and gaseous) fracturing tracer monitoring with machine learning algorithms to address this issue. Based on large-scale field applications across ten deep CBM horizontal wells in the Changqing mining area of the Ordos Basin, comprising 132 monitored stages, quantitative production profile data were interpreted. Three distinct gas production archetypes—Homogeneous, Heel-Dominated, and Heterogeneous—were identified, each governed by specific geomechanical and stratigraphic controls. Pearson correlation analysis and Random Forest feature importance ranking were employed to decouple the hierarchical influence of geological parameters (Class I coal intersection length, trajectory position, coal thickness) and engineering parameters (proppant volume, pumping rate, fluid volume). A power-law correlation between Class I coal length and initial gas productivity was quantified (R² = 0.71). For the first time, an economically viable “differentiated fracturing scale window” tailored to coal petrophysical classes and wellbore trajectory positions was defined. Subsequently, a machine learning-assisted geology-engineering closed-loop optimization methodology was established, using tracer data as a dynamic feedback bridge to iteratively refine fracturing designs. This research provides a reliable technical approach and practical template for enhancing single-well productivity and recovery efficiency in deep unconventional gas reservoirs. Full article