Search Results (42)

Fractured–vuggy carbonate reservoirs are characterized by highly discrete storage structures, and the number, spatial distribution, and volume of cavities strongly affect well-test responses and reservoir development decisions. This study develops a PEBI-grid finite-volume implementation of a wave–seepage-coupled model for pressure-transient interpretation in reservoirs containing irregular cavities. The objective is not to introduce a new general-purpose finite-volume method but to embed irregular cavities as special control volumes into a locally orthogonal PEBI grid so that the cavity volume, geometry, and well–cavity distance can be represented explicitly in bottom-hole pressure calculations. The model is formulated as a thickness-averaged two-dimensional system in which the fracture–matrix region is treated as an equivalent seepage continuum, and each cavity is assigned a spatially uniform pressure governed by a wave–seepage exchange relation. For the limiting case of zero cavity volume, the numerical bottom-hole pressure agrees closely with the analytical solution and the material-balance estimate. A further cylindrical-cavity benchmark against an analytical wave–seepage solution gives a pressure-drawdown relative L2 error of 4.38%, where the relative L2 error denotes the Euclidean norm of the pressure error vector normalized by that of the reference solution, providing additional validation of the cavity-coupled formulation. Sensitivity analysis shows that increasing the cavity volume delays the characteristic extrema of the pressure derivative and strengthens the contrast between the minimum and maximum, whereas increasing the well–cavity distance mainly shifts the onset of the cavity-dominated response and weakens its amplitude. A field pressure-buildup case from the Fuyuan oilfield is interpreted using the proposed workflow. The matched model indicates a pentagonal cavity with a volume of 169,770 m³, a well–cavity distance of 158.4 m, a permeability of 5.535 md, and an initial reservoir pressure of 86.66 MPa. The results demonstrate that the proposed PEBI-FVM wave–seepage-coupled model can support practical well-test interpretation of irregular cavities, while its reliability depends on the validity of the equivalent-continuum and uniform-cavity-pressure assumptions. Full article

Microbial dolostones of the Sinian Qigebulake Formation in the Kepin area, northwestern Tarim Basin, represent an important target for deep to ultra-deep hydrocarbon exploration. Based on integrated analyses of outcrop sections, drilling cores, thin sections, scanning electron microscopy (SEM), and petrophysical data, this study systematically investigates the lithofacies characteristics, reservoir space types, and controlling factors of microbial dolostone reservoirs. (1) Five major lithofacies types were identified, including stromatolitic dolostone, clotted dolostone, foamy laminated dolostone, granular dolostone, and crystalline dolostone. These lithofacies mainly developed in an inner-ramp depositional setting and vertically formed a shallowing-upward sedimentary succession from tidal flat to microbial mound and shoal facies. Reservoir spaces are dominated by secondary dissolution pores, including framework dissolution pores, intergranular and intragranular dissolution pores, vugs, fractures, and karst cavities. The reservoirs are characterized by medium porosity, low permeability, and strong heterogeneity. (2) Sedimentary facies, microbial dolomitization, and karstification jointly controlled the development of relatively favorable reservoir intervals. Early microbial-induced dolomitization enhanced the rigidity of microbial frameworks and facilitated the preservation of primary pores, whereas meteoric karstification associated with the terminal Sinian Keping Movement significantly improved reservoir quality through large-scale dissolution enlargement and fracture-cavity development. SEM observations reveal abundant microbial mineralization textures, including cauliflower-shaped, dumbbell-shaped, and spheroidal dolomite morphologies associated with EPS remnants, providing direct evidence for microbial mediation during dolomite precipitation. (3) Reservoir intervals with relatively favorable physical properties are mainly distributed in the middle-upper microbial mound intervals and upper karst-modified zones of the Qigebulake Formation, forming a favorable source–reservoir–seal assemblage with the overlying Yuertusi Formation black shales. This study provides new insights into the formation and preservation mechanisms of deep microbial dolostone reservoirs and offers important implications for ultra-deep hydrocarbon exploration in the Tarim Basin. Full article

Ultra-deep carbonate reservoirs are increasingly critical to the global energy supply, representing a major frontier in hydrocarbon exploration. While these reservoirs are predominantly controlled by strike-slip faults, hydrocarbon enrichment exhibits considerable spatial variability along these faults, resulting in persistently high exploration risks in the Tarim Basin, China. This paper proposes a quantitative evaluation framework integrating source connectivity, transport capacity, and reservoir quality of strike-slip faults. This multi-parameter quantitative evaluation of the main controlling factors aims to provide a geological basis and an objective reference for hydrocarbon exploration in ultra-deep carbonate reservoirs within the Shunbei area. Utilizing high-precision 3D seismic data and drilling data from 15 exploration wells along the F4 strike-slip fault in the Shunbei area, we identified five distinct kinematic segment types of the strike-slip fault. Subsequently, a comprehensive characterization of source connectivity, transport capacity, and reservoir quality was achieved based on a series of geological parameters, including stratal deformation intensity, gypsum–salt layer thickness, the average value of gradient structure tensor attributes, and the cross-sectional area of fracture–cavity bodies. Principal component analysis was then employed to integrate these geological parameters into a hydrocarbon enrichment index F, quantifying the synergistic coupling effects of multiple geological factors. The results demonstrate a good positive correlation (R² = 0.78) between the F index and the normalized daily oil equivalent production of each well. To assess predictive performance, a randomized cross-validation with 10 independent trials was conducted. The blind test sets yielded an average predictive coefficient of determination (Q²) of 0.76 and a mean relative error (MRE) of 9.65%, indicating stable predictive performance without major deviations. The spatial configuration of the fundamental parameters for source connectivity, transport capacity, and reservoir quality ultimately determines the enrichment degree of ultra-deep carbonate reservoirs, which is specifically manifested as differential hydrocarbon enrichment models associated with distinct kinematic segment types. Specifically, the high-enrichment model correlates primarily with offset and flexural pull-apart segments; the medium-enrichment model is associated with the flexural pull-apart, transpressional uplift, and weakly transpressive strike-slip segments; whereas the low-enrichment model is confined to the weakly transpressive strike-slip and pure strike-slip segments. This study elucidates fault-controlled hydrocarbon accumulation mechanisms within ultra-deep carbonate reservoirs, providing novel insights for the predictive exploration and quantitative evaluation of ultra-deep energy resources in the Shunbei area. Full article

The Dengying Formation gas reservoir in the Penglai gas field, located in the central Sichuan Basin, exhibits substantial resource potential and promising development prospects. This reservoir is characterized by well-developed fractures and dissolution cavities, strong heterogeneity, complex gas–water relationships, and widespread edge–bottom water. During production, edge–bottom water is prone to channeling and intrusion through high-permeability pathways, which severely constrains well productivity and overall gas recovery. To address these challenges, this study takes a fractured-vuggy carbonate edge–bottom water gas reservoir as an example. By integrating large-scale physical simulation with cross-scale numerical simulation, a rational production allocation method suitable for strongly heterogeneous gas reservoirs has been developed. The research results indicate that: (1) Large-scale physical simulation experiments demonstrate that for fractured-vuggy bottom water gas reservoirs, implementing rate reduction and pressure control after water breakthrough can effectively suppress water invasion and coning, extend the stable production period, and increase the recovery factor by approximately 16%; (2) Based on the dynamic characteristics of water invasion, key similarity criteria including the Bond number, capillary number, gravity–viscous force ratio, and geometric–temporal similarity ratio were selected to establish a scientific parameter design method for cross-scale numerical simulation; (3) By considering factors such as reservoir type and aquifer energy, single-well mechanistic models were used to determine appropriate production rates for individual wells, enabling rapid optimization of production allocation plans. This provides crucial guidance for efficient gas well development and surface facility planning. Full article

Deep coalbed methane (CBM) reservoirs are characterized by high in situ stress, and the effective stress during CBM production is significant, leading to substantial damage to reservoir permeability. Studying the variation patterns of coal permeability during stress unloading is crucial for revealing the mechanisms by which CBM stimulation through slotting and cavity creation modifies in situ stress. To understand the permeability variations in fractured coal under stress changes, gas seepage experiments were conducted using seven deep coal samples obtained from the Linxing–Shenfu mining area in the Ordos Basin of North China. Through these experiments, permeability variations in coal under different confining, axial, and gas pressures were investigated, and their implications for permeability enhancement through hydraulic slotting in deep coal seams were analyzed. The results show that during loading, permeability decreases with increasing effective stress, and the rate of permeability damage increases. During unloading, the changes in coal permeability transition from slow to rapid, with the stress sensitivity coefficient increasing and the stress sensitivity becoming more pronounced. Regardless of the loading or unloading process, lower axial pressure leads to higher permeability, greater permeability recovery and damage rate, a larger stress sensitivity coefficient, and stronger stress sensitivity of the coal. For every 4 MPa decrease in the axial pressure, the permeability increases by approximately 0–10%, and the permeability recovery rate increases by about 6%. This is because the lower axial pressure reduces the effective stress acting on the coal matrix and fractures, thereby widening the flow channels and enhancing both the permeability and its recovery capacity. In addition, for every 0.3 MPa increase in the gas pressure, the permeability increases by approximately 10–50%, and the permeability recovery rate increases by about 20%. This indicates that elevating pore pressure effectively counteracts effective stress, expands fracture apertures, and promotes fracture connectivity. This work demonstrates that fractured coal is highly sensitive to stress and that stress relief plays a crucial role in enhancing the permeability of deep coal seams. Full article

Carbonate reservoirs, characterized by extensive fractures and cavities, are prone to gravity displacement during drilling when the bottom-hole pressure approaches equilibrium. This phenomenon, driven by density differences between drilling and formation fluids, can result in simultaneous overflow and leakage, posing significant well control risks such as kicks or blowouts. The occurrence of gravity displacement downhole makes its timely detection through conventional annular flow monitoring techniques challenging. This study investigates the triggering conditions and safe density window for gravity displacement in fractured and cavernous formations. Through theoretical analysis and experimental simulation, we examined the displacement mechanisms in both fractured and cavernous conditions. Computational fluid dynamics (CFDs) simulations were used to validate critical fluid column heights for fractured formations and the proposed safe density window. Based on these findings, practical methods to mitigate the hazards associated with gravity displacement overflow are proposed. The results offer valuable guidance for the field identification and mitigation of such incidents, contributing to managed pressure drilling and enhancing drilling safety in complex carbonate reservoirs. Full article

Ultra-deep fault-controlled carbonate reservoirs exhibit strong heterogeneity, multi-scale fracture–cavity systems, and complex geological controls, which render conventional analytical well testing methods inadequate. This study proposes a geological model-based numerical well testing framework incorporating adaptive meshing, noise reduction, and machine-learning-assisted inversion. A multi-step workflow was established, including (i) single-well geological model extraction with localized grid refinement to capture near-wellbore flow behavior, (ii) pressure data denoising and preprocessing using low-pass filtering, and (iii) surrogate-assisted parameter inversion and sensitivity analysis using particle swarm optimization (PSO) to construct diagnostic type curves for different fracture–cavity control modes. The methodology was applied to different wells, yielding inverted fracture permeabilities ranging from approximately 140 to 480 mD and cavity permeabilities between about 110 and 220 mD. Results show that the numerical well testing method achieved an 85.7% interpretation accuracy, outperforming conventional approaches. Distinct parameter sensitivities were identified for single-, double-, and multi-cavity systems, providing a systematic basis for production allocation strategies. This integrated approach enhances the reliability of reservoir characterization and offers practical guidance for efficient development of ultra-deep carbonate reservoirs. Full article

Carbonate fracture–cavity reservoirs are significant oil and gas reservoirs globally, and their efficient development is influenced by the connectivity between fracture–cavity units within the reservoir. These reservoirs primarily consist of large caves, dissolution holes, and natural fractures, which serve as the primary storage and flow spaces. The S91 unit of the Tarim Oilfield is a karstic fracture–cavity reservoir with shallow coverage. It exhibits significant heterogeneity in the fracture–cavity reservoirs and presents complex connectivity between the fracture–cavity bodies. The integration of static and dynamic data, including geology, well logging, seismic, and production dynamics, resulted in the development of a set of static and dynamic connectivity evaluation processes designed for highly heterogeneous fracture–cavity reservoirs. Methods include using structural gradient tensors and stratigraphic continuity attributes to delineate the boundaries of caves and holes; performing RGB fusion analysis of coherence, curvature, and variance attributes to characterize large-scale fault development features; applying ant-tracking algorithms and fracture simulation techniques to identify the distribution and density characteristics of fracture zones; utilizing 3D visualization technology to describe the spatial relationship between fracture–cavity units and large-scale faults and fracture development zones; and combining dynamic data to verify interwell connectivity. This process will provide a key geological basis for optimizing well network deployment, improving water and gas injection efficiency, predicting residual oil distribution, and formulating adjustment measures, thereby improving the development efficiency of such complex reservoirs. Full article

The deep carbonate reservoirs in the Tarim Basin, Xinjiang, China, are widely developed with multi-scale complex reservoir spaces such as fractures, pores, and karst caves under the coupling of abnormal high pressure, diagenesis, karst, and tectonics and have strong heterogeneity. Among them, fracture–cavity carbonate reservoirs are one of the main reservoir types. Revealing the petrophysical characteristics of fracture–cavity carbonate reservoirs can provide a theoretical basis for the log interpretation and geophysical prediction of deep reservoirs, which holds significant implications for deep hydrocarbon exploration and production. In this study, based on the mineral composition and complex pore structure of carbonate rocks in the Tarim Basin, we comprehensively applied classical petrophysical models, including Voigt–Reuss–Hill, DEM (Differential Effective Medium), Hudson, Wood, and Gassmann, to establish a fracture–cavity petrophysical model tailored to the target block. This model effectively characterizes the complex pore structure of deep carbonate rocks and addresses the applicability limitations of conventional models in heterogeneous reservoirs. The discrepancies between the model-predicted elastic moduli, longitudinal and shear wave velocities (Vp and Vs), and laboratory measurements are within 4%, validating the model’s reliability. Petrophysical template analysis demonstrates that P-wave impedance (Ip) and the Vp/Vs ratio increase with water saturation but decrease with fracture density. A higher fracture density amplifies the fluid effect on the elastic properties of reservoir samples. The Vp/Vs ratio is more sensitive to pore fluids than to fractures, whereas Ip is more sensitive to fracture density. Regions with higher fracture and pore development exhibit greater hydrocarbon storage potential. Therefore, this petrophysical model and its quantitative templates can provide theoretical and technical support for predicting geological sweet spots in deep carbonate reservoirs. Full article

China holds substantial coalbed methane resources, yet low single-well productivity persists. While horizontal well cavity completion offers a permeability-enhancing solution through stress release, its effectiveness remains limited by the incomplete knowledge of stress redistribution and permeability evolution during stress release. To bridge this gap, a fully coupled hydromechanical 3D discrete element model (FLC3D) was developed to investigate stress redistribution and permeability evolution in deep coalbed methane reservoirs under varying cavity spacings and fluid pressures, and a novel sequential cavity completion technique integrated with hydraulic fracturing was proposed to amplify stress release zones and mitigate stress concentration effects. Key findings reveal that cavity-induced stress release zones predominantly develop proximal to the working face, exhibiting radial attenuation with increasing distance. Vertical stress concentrations at cavity termini reach peak intensities of 2.54 times initial stress levels, forming localized permeability barriers with 50–70% reduction. Stress release zones demonstrate permeability enhancement directly proportional to stress reduction magnitude, achieving a maximum permeability of 5.8 mD (483% increase from baseline). Prolonged drainage operations reduce stress release zone volumes by 17% while expanding stress concentration zones by 31%. The developed sequential cavity hydraulic fracturing technology demonstrates, through simulation, that strategically induced hydraulic fractures elevate fluid pressures in stress-concentrated regions, effectively neutralizing compressive stresses and restoring reservoir permeability. These findings provide actionable insights for optimizing stress release stimulation strategies in deep coalbed methane reservoirs, offering a viable pathway toward sustainable and efficient resource development. Full article

Accurate characterization of subsurface geological structures, particularly those obscured by strong coal-seam reflections, is essential for hydrocarbon exploration in subtle reservoirs. Enhancing seismic resolution remains a pivotal technical challenge in addressing this demand. Here, we present a multitrace reflectivity inversion method guided by geological sparsity principles. This method establishes quantitative relationships between sparse inversion operators and the spatial positions of stratigraphic boundaries. Specifically, by integrating prior geological knowledge, such as stratigraphic boundaries and stable sedimentary structures, as constraint operators within the sparsity matrix, this method results in a geologically interpretable and robust inversion framework. Subsequently, we validated this method through synthetic data and field applications in a carbonate fracture–cavity reservoir in the Ordos Basin of western China. The enhanced seismic resolution demonstrates that our method effectively restores shielded reservoir reflections beneath coal seams. Clearer than conventional sparse inversion techniques, the coherence attribute of the enhanced seismic resolution reveals distinct fracture–cavity geometries. Moreover, integrated analyses of well logs, fracture–cavity characterization, and drilling production data further confirm the accuracy and reliability of the inversion results. In conclusion, this method effectively leverages accurate geological structural information to enhance localized seismic resolution, thereby providing robust support for the exploration of subtle hydrocarbon reservoirs. Full article

Due to the fracture caverns in fractured-vuggy reservoirs, channeling frequently occurs during water injection or gas injection. The stability of the oil–water/oil–gas interface during water injection or gas injection in fractured-vuggy reservoirs significantly affects the displacement efficiency. However, there is a lack of in-depth understanding of the stability of the gas–water interface migration during water injection or gas injection in such reservoirs. In order to deal with this problem, this study combines indoor 3D visualization physical simulation experiment and fracture-cavity reservoir flow simulation. The law of interface transport and oil recovery in the process of injection of gas/water considering the degree of filling of fracture holes was studied and the influence of formation on crude oil viscosity, gas injection speed, inclination angle and other factors on the stability of the interface was compared. Results show that, under the influence of gravity differentiation, the oil–water interface of high-viscosity crude oil fluctuates obviously after water breakthrough, and the oil–water interface tends to be unstable, forming uneven oil cones. By reducing the gas drive speed, water invasion can be effectively inhibited to achieve a stable interface which accordingly improves the oil recovery. Full article

This paper describes an innovatively designed experimental method for fracturing fluid energy storage to explore the energy storage mechanism during the well shut-in process of fractured shale reservoirs. By improving the existing core clamp and adding fracturing fluid cavities and large volume intermediate containers to simulate artificial fractures and remote shale reservoirs, the pressure changes in the core during the well shut-in process were monitored under the conditions of a real oil–water ratio and real pressure distribution to explore the energy storage law of the shut-in fluid in fractured shale reservoirs. Compared to the 0.62 MPa energy storage obtained from traditional energy storage experiments (without artificial fractures or remote shale reservoirs), the experimental scheme proposed in this paper achieved a 2.45 MPa energy storage, consistent with the field’s monitoring results. The energy storage effects of four fracturing fluids were compared, namely pure CO₂, CO₂ pre-fracturing fluid, slickwater pre-fracturing fluid, and pure slickwater fracturing fluid. Due to the characteristics of a high expansion coefficient and low interfacial tension of pure CO₂, the energy storage effect was the best, and the pressure equilibrium time was the shortest. Considering factors such as comprehensive economy and energy storage efficiency, the optimal range for CO₂ pre-injection is between 20% and 30%. Based on the optimization criterion of energy storage pressure balance, it is recommended that the optimal CO₂ shut-in time be 5 h and the slickwater be 12.8 h. Considering the economic, sand carrying, and energy storage effects, and other factors, CO₂ pre-storage has the best imbibition effect, and the optimal CO₂ pre-storage range is 20~30%. The research results provide theoretical support for energy storage fracturing construction in other shale oil reservoirs of the same type. Full article

The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively because of small water flood sweep and large injection pressure. Pressure flooding is a new water injection technique that can change the reservoir pore space. Combined with an oil displacement agent, pressure flooding is expected to improve the recovery rate of carbonate reservoirs. In this paper, the influence factors of pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed. The results show that only an appropriate injection flow can produce microfractures. Only an appropriate displacement rate can optimize the effects of pressure flooding. With an increase in crude oil viscosity, the recovery rate after pressure flooding decreases gradually. A complex fracture network is formed in reservoirs after pressure flooding. The new surfactant system has good interfacial tension reduction properties and excellent stability. Pressure flooding experiments with the addition of a surfactant showed that the system can help to improve the recovery of pressure flooding. Full article

Dolomitization is a critical diagenetic alteration that impacts the formation of carbonate hydrocarbon reservoirs. In the offshore Bohai Bay Basin, the Lower Paleozoic carbonate reservoirs in buried hill traps, and the basement highs unconformably overlain by younger rock units, are emerging as a prospective target and predominantly occur in dolomite layers. Meanwhile, the formation mechanisms of the dolomite are not clear, which affects the understanding of the occurrence of deep dolomite reservoirs and hinders oil and gas exploration. Based on comprehensive observations of the thin sections of the carbonate samples, the dolomite types were meticulously categorized into micritic dolostone, fine-crystalline dolostone, and saddle dolomite. Then, carbon, oxygen, and strontium isotope and trace elements were examined to elucidate the dolomitization fluids and propose diagenetic models for the three kinds of dolomite formation. The mineralogical and geochemical evidence reveals that there were two kinds of dolomitization fluids, including penecontemporaneous seawater, and hydrothermal fluid. The diagenetic fluid of the micritic dolostone and fine-crystalline dolostone both involved penecontemporaneous seawater, but fine-crystalline dolostone is also affected by later burial dolomitization processes. The saddle dolomite, filling in pre-existing fractures or dissolution pore cavities, is attributed to a hydrothermal fluid associated with magmatic activities. Notably, the extensive layered fine-crystalline dolostone was the predominant reservoir rock. The initial mechanism for its formation involves penecontemporaneous seepage reflux dolomitization, which is superimposed by later burial dolomitization. The burial dolomitization enhanced porosity, subsequently facilitating the formation of a fracture-related dissolution pore cavity system, and partly filled by saddle dolomite during the Cenozoic hydrothermal events. The findings highlight that the layered fine-crystalline dolostone that underwent multiphase dolomitization is the most potential target for hydrocarbon exploration. Full article