Search Results (34)

Low-resistivity reservoirs characterized by weak log contrasts are highly concealed and therefore difficult to detect using conventional oil–water discrimination methods. Recent exploration and development indicate that low-resistivity reservoirs are widely developed in the Triassic Chang 3 Member of the Zhenbei area, Ordos Basin. However, contrasting tectonic evolution associated with the Tianhuan Depression and complex lithologic assemblages in the western and eastern sectors have resulted in complicated hydrocarbon migration and accumulation processes. In this study, integrated well-log and geochemical data were used to systematically investigate the genesis of low-resistivity reservoirs in the Chang 3 Member and to establish oil–water discrimination charts. Three-dimensional seismic flattening was applied to restore the Late Jurassic paleostructure of the western Chang 3 Member and to analyze its tectonic evolution. Reservoir petrology and pore–throat architecture in the western and eastern areas were comparatively examined using thin-section petrography, field-emission scanning electron microscopy (FESEM), and high-pressure mercury intrusion. Results indicate that the development of low-resistivity reservoirs in the Chang 3 Member is primarily controlled by highly saline formation water and elevated bound-water saturation. Based on these controls, the invasion factor–acoustic transit time cross-plot and the apparent spontaneous potential difference (ΔSP) method effectively discriminate oil- and water-bearing intervals in a total of 25 wells within the study area. Paleostructural restoration reveals that the western Chang 3 Member has undergone a tectonic inversion from a west-high–east-low configuration since the Late Jurassic to the present-day east-high–west-low geometry. Oil–source correlation indicates that hydrocarbons in the Chang 3 reservoirs were mainly derived from the underlying Chang 7 source rocks, whereas the bimodal distribution of fluid-inclusion homogenization temperatures suggests that the reservoirs experienced two distinct charging episodes. Integrated analysis suggests that tectonic inversion during the Yanshanian movement, combined with multistage hydrocarbon charging, led to secondary migration and partial destruction of early-formed reservoirs in the western area, resulting in predominantly scattered accumulations. In contrast, the eastern area experienced relatively limited tectonic modification, and laterally extensive accumulations are controlled by Type I–III lithologic–structural traps formed by the Chang 3 reservoir interval and its overlying strata. These findings provide an important geological basis for the identification of low-contrast reservoirs and for the exploration and development of hydrocarbon accumulations that are jointly controlled by tectonic evolution and lithologic heterogeneity. Full article

The pore architecture of the Nahr Umr Formation sandstone reservoirs is highly complex and heterogeneous, severely limiting efficient oilfield development. Conventional methods often fail to adequately characterize such intricate pore systems, necessitating the application of fractal theory. Focusing on sandstone samples from the Nahr Umr-B Member, this study integrates thin section identification, XRD, HPMI, and NMR to characterize the fractal features of the reservoir pore structure and evaluate fluid mobility. The results indicate that from Type I to Type III reservoirs, displacement pressure and median pressure gradually increase, whereas the average and median pore-throat radius gradually decrease, and the pore-throat sorting coefficient decreases. For instance, Type I reservoirs exhibit an average displacement pressure of 0.15 MPa, a median pressure of 0.81 MPa, an average pore-throat radius of 1.96 μm, and a median pore-throat radius of 2.85 μm; in contrast, Type III reservoirs show averages of 14.43 MPa, 45.32 MPa, 0.02 μm, and 0.03 μm, respectively. These trends reflect a gradual deterioration in pore connectivity, increased resistance to fluid flow, and a reduction in the development of larger pore throats. From Type I to Type III reservoirs, both the total fractal dimension (D_H) and the movable fluid pore fractal dimension (D_N2) show a gradual increasing trend. This indicates that the pore structure becomes increasingly complex and heterogeneous, the complexity of the movable fluid pore space increases, and fluid mobility progressively weakens. Furthermore, higher quartz content and lower cement and clay mineral contents correspond to smaller reservoir pore fractal dimensions and stronger fluid mobility. For example, Sample No. 3 (Type I) has a quartz content of 91.97%, a cement content of 1.64%, and a clay mineral content of 6.4%, with a D_H of 2.4385 and D_N2 of 2.9323. Conversely, Sample No. 4 (Type III) has a quartz content of 49.72%, a cement content of 11.21%, and a clay mineral content of 39.07%, with a D_H of 3.9099 and D_N2 of 2.9762. Compared to D_H, D_N2 reduces the prediction error for dynamic quality by over 70% on average, offering a more reliable prediction of fluid mobility and providing a more precise scale for evaluating reservoir development potential. Full article

Shallow gas reservoirs exhibit low formation pressure and gas injection levels, leading to low-resistivity contrast between gas-bearing reservoirs and fully water-saturated layers. Gas-bearing formation identification and water saturation estimation face great challenges. To improve the accuracy of shallow gas reservoir identification and logging evaluation, it is essential to analyze the genesis mechanisms underlying the low-resistivity contrast. This study used the HJ Formation, a typical shallow gas reservoir located in the BY Sag of the eastern South China Sea Basin as an example. Combining the results of nuclear magnetic resonance (NMR), full rock mineral analysis and X-ray diffraction of clay minerals in the laboratory, it was determined that the genesis mechanism for the low-resistivity contrast in the gas-bearing reservoir was due to the high irreducible water saturation (S_wi) and the cation-induced supplementary conductivity. Afterwards, we integrated three methods, density–neutron correlation, calculation of the apparent formation water resistivity, and cross-plots of conventional and gas-logging curves, to identify shallow gas reservoirs. In addition, we also established a Waxman–Smits-based model to estimate water saturation. Compared with the typical Archie’s equation, the predicted water saturation curve using the Waxman–Smits-based model was more reasonable. The established methods and models can be used in target shallow gas reservoir evaluations, and it also has reference value for other types of oilfields with similar physical characteristics. Full article

The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article

This study addresses the limitations of conventional evaluation methods caused by low porosity, strong heterogeneity, and complex pore structures in tight sandstone reservoirs. Through integrated rock physics experiments and multi-physical field modeling, the research systematically investigates the coupled response mechanisms between electrical and elastic parameters. The experimental approach includes pore structure characterization, quantitative mineral composition analysis, resistivity and polarizability measurements under various saturation conditions, P- and S-wave velocity testing, and scanning electron microscopy (SEM) imaging. The key findings show that increasing porosity leads to significant reductions in resistivity and elastic wave velocities, while also increasing surface conductivity. Specifically, clay minerals enhance surface conductivity through interfacial polarization effects and decrease rock stiffness, which exacerbates wave velocity attenuation. Furthermore, resistivity exhibits a nonlinear negative correlation with water saturation, with sharp increases at low saturation levels due to the disruption of conductive pathways. By integrating the Modified Generalized Effective Medium Theory of Induced Polarization (MGEMTIP) and Kuster–Toksöz models, this study establishes quantitative relationships between porosity, saturation, and electrical/elastic parameters, and constructs cross-plot templates that correlate elastic wave velocities with resistivity and surface conductivity. These analyses reveal that high-porosity, high-saturation zones are characterized by lower resistivity and wave velocities, coupled with significantly higher surface conductivity. The proposed methodology significantly improves the accuracy of reservoir evaluation and enhances fluid identification capabilities, providing a solid theoretical foundation for the efficient exploration and development of tight sandstone reservoirs. Full article

As an important unconventional oil and gas resource, tight oil exploration and development is of great significance to ensure energy supply under the background of continuous growth of global energy demand. Low-porosity and low-permeability reservoirs are characterized by tight rock properties, poor physical properties, and complex pore structure, and as a result the fine calculation of logging reservoir parameters faces great challenges. In addition, the crude oil in this area has high viscosity, the formation water salinity is low, and the oil reservoir resistivity shows significant spatial variability in the horizontal direction, which further increases the difficulty of oil and water reservoir identification and affects the accuracy of oil saturation calculation. Targeting the above problems, the Nutcracker Optimization Algorithm (NOA) was used to optimize the hyperparameters of the random forest classification model, and then the optimal hyperparameters were input into the random forest model, and the conventional logging curve and oil test data were combined to identify and classify the reservoir fluids, with the final accuracy reaching 94.92%. Compared with the traditional Hingle map intersection method, the accuracy of this method is improved by 14.92%, which verifies the reliability of the model for fluid identification of low-porosity and low-permeability reservoirs in the research block and provides reference significance for the next oil test and production test layer in this block. Full article

The bottom-simulating reflector (BSR) serves as an important seismic indicator for identifying gas hydrate-bearing sediments. This review synthesizes global BSR observations and demonstrates that spatial relationships among BSRs, free gas, and gas hydrates frequently deviate from one-to-one correspondence. Moreover, our analysis reveals that more than 35% of global BSRs occur shallower than the bases of gas hydrate stability zones, especially in deepwater regions, suggesting that the BSRs more accurately represent the interface between the gas hydrate occurrence zone and the underlying free gas zone. BSR morphology is influenced by geological settings, sediment properties, and seismic acquisition parameters. We find that ~70–80% of BSRs occur in fine-grained, grain-displacive sediments with hydrate lenses/nodules, while coarse-grained pore-filling sediments host <20%. BSR interpretation remains challenging due to limitations in traditional P-wave seismic profiles and conventional amplitude versus offset (AVO) analysis, which hinder accurate fluid identification. To address these gaps, future research should focus on frequency-dependent AVO inversion based on viscoelastic theory, multicomponent full-waveform inversion, improved anisotropy assessment, and quantitative links between rock microstructure and elastic properties. These innovations will shift BSR research from static feature mapping to dynamic process analysis, enhancing hydrate detection and our understanding of hydrate–environment interactions. Full article

This study focuses on a low-permeability sandstone reservoir in the Changqing Oilfield, aiming to elucidate the formation mechanism and occurrence state of residual oil during late-stage waterflooding development, thereby providing theoretical guidance for refined residual oil recovery. By integrating scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and digital core analysis, the oil–water occurrence state and dynamic characteristics during waterflooding were systematically investigated. NMR was employed to determine fluid distribution within core pores, while CT scanning was utilized to construct a 3D digital core model, enabling the identification of microscopic residual oil displacement and occurrence states at different flooding stages. The oil displacement efficiency was further analyzed based on variations in oil–water distribution and occurrence states within the core. The results demonstrate that pore and throat size and connectivity are the primary factors governing reservoir permeability. After high-pore-volume (PV) waterflooding, microscopic residual oil predominantly exists as dispersed droplets, films, and small-scale clusters or columns. Although prolonged high-PV waterflooding effectively expands the sweep volume, localized displacement efficiency declines, and reservoir heterogeneity adversely affects sweep volume maintenance. The post-flooding residual oil characteristics are collectively determined by the core’s local connectivity, wettability, and pore–throat morphology. This research systematically analyzes the occurrence patterns and evolutionary trends of residual oil in low-permeability reservoirs during long-term waterflooding, providing critical theoretical insights and technical support for enhanced oil recovery and residual oil exploitation. Full article

This investigation focuses on the prevalent continental oil shale within the Triassic Chang 7, a member of the Yanchang Formation in the Ordos Basin and the Permian Lucaogou Formation in the Junggar Basin of western China, and delves into the impacts of hydrocarbon generation and the derived organic acids on the physical attributes of oil shale reservoirs. Water-soluble organic acids (WSOAs) were extracted via Soxhlet extraction and analyzed by a 940 ion chromatograph (Metrohm AG), supplemented with core observations, thin-section analyses, pyrolysis, and trace element assays, as well as the qualitative observation of pore structures via FIB-SEM scanning electron microscopy. The study discloses substantial disparities in the types and abundances of organic acids within the oil shale strata of the two regions, with mono-acids being conspicuously more prevalent than dicarboxylic acids. The spatial distribution of organic acids within the oil shale strata in the two regions is non-uniform, and their generation is inextricably correlated with the type of organic matter, thermal maturity, and depth at which they are buried. During diverse stages of diagenesis, the hydrocarbons and organic acids produced from the pyrolysis of organic matter not only exert an impact on the properties of pore fluids but also interact with diagenetic processes such as compaction, dissolution, and metasomatism to enhance the reservoir quality of oil shale. The synergy between chemical interactions and physical alterations collectively governs the migration and distribution patterns of organic acids as well as the characteristics of oil shale reservoirs. Furthermore, the sources of organic acids within the oil shale series in the two regions demonstrate pronounced dissimilarities, which are intimately associated with the peculiarities of their sedimentary milieu. The oil shale of the Yanchang Formation was formed in a warm and humid freshwater lacustrine basin environment, while the oil shale of the Lucaogou Formation was deposited in a brackish to saline lacustrine setting under an arid to semi-arid climatic regime. These variances not only illuminate the intricacy and multiplicity of the sedimentary attributes of oil shale but also accentuate the impact of the sedimentary environment on the genesis and distribution of organic acids, especially the transformation and optimization of reservoir dissolution by organic acids generated during hydrocarbon generation—a factor of paramount significance for the precise identification and effective development of the “sweet spot” area of shale oil. These areas, characterized by an abundance of organic matter, their maturity, and superior reservoir properties, are the foci of the efficient exploration and development of continental shale oil. Full article

Permeability is a fundamental property of porous media. It quantifies the ease with which a fluid can flow under the effect of a pressure gradient in a network of connected pores. Porous materials can be natural, such as soil and rocks, or synthetic, such as a densified network of fibres or open-cell foams. The measurement of permeability is difficult and time-consuming in heterogeneous and anisotropic porous media; thus, a numerical approach based on the calculation of the tensor components on a 3D image of the material can be very advantageous. For this type of microstructure, it is important to perform calculations on large samples using boundary conditions that do not suppress the transverse flows that occur when flow is forced out of the principal directions. Since these are not necessarily known in complex media, the permeability determination method must not introduce bias by generating non-physical flows. A new finite element-based method proposed in this study allows us to solve very high-dimensional flow problems while limiting the biases associated with boundary conditions and the small size of the numerical samples addressed. This method includes a new boundary condition, full permeability tensor identification based on the multiscale homogenization approach, and an optimized solver to handle flow problems with a large number of degrees of freedom. The method is first validated against academic test cases and against the results of a recent permeability benchmark exercise. The results underline the suitability of the proposed approach for heterogeneous and anisotropic microstructures. Full article

The complex pore structure of unconventional oil and gas reservoirs is one of the reasons for the difficulties in resource evaluation and development. Therefore, it is crucial to comprehensively characterize the pore structure, understand reservoir heterogeneity from multiple perspectives, and gain an in-depth understanding of fluid migration and accumulation mechanisms. This review outlines the methods and basic principles for characterizing microporous systems in unconventional reservoirs, summarizes the fractal analysis corresponding to the different methods, sorts out the relationship between the fractals and reservoir macroscopic physical properties (porosity, permeability, etc.) with the reservoir microscopic pore structures (pore structure parameters, pore connectivity, etc.). The research focuses on cutting-edge applications of characterization techniques, such as improved characterization accuracy, calibration of PSD ranges, and identification of different hydrogen compositions in pore systems for dynamic assessment of unconventional reservoirs. Fractal dimension analysis can effectively identify the quality level of the reservoir; complex pore-throat structures reduce permeability and destroy free fluid storage space, and the saturation of removable fluids is negatively correlated with D_f. As for the mineral composition, the fractal dimension is positively correlated with quartz, negatively correlated with feldspar, and weakly correlated with clay mineral content. In future qualitative characterization studies, the application and combination of contrast agents, molecular dynamics simulations, artificial intelligence techniques, and 4D imaging techniques can effectively improve the spatial resolution of the images and explore the adsorption/desorption of gases within the pores, and also help to reduce the computational cost of these processes; these could also attempt to link reservoir characterization to research on supercritical carbon dioxide-enhanced integrated shale gas recovery, carbon geological sequestration, and advanced underground hydrogen storage. Full article

Reservoir sensitivity is a parameter that is used to evaluate the degree of change in reservoir permeability under the influence of external fluids. Accurate evaluation of reservoir sensitivity is conducive to the optimization of fluid parameters during exploration and development. Taking the Wenchang Formation and Enping Formation of the Paleogene in the Huilu area of the Pearl River Mouth Basin as the research object, reservoir sensitivity experiments were carried out. Combined with the corresponding experimental results obtained using methods such as thin section identification, scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury intrusion porosimetry (MIP), and screening analysis, based on mineral sensitization and pore structure sensitization, qualitative and quantitative evaluations of reservoir sensitivity were carried out, and factors affecting sensitivity and sensitization mechanisms were analyzed. This work shows the following: (1) The sandstone reservoirs in the two areas have the same clay type, but the total clay content of the Wenchang Formation is greater than that of the Enping Formation. The porosity of the Wenchang Formation is less developed than the Enping Formation. (2) The Wenchang Formation has weak or moderately weak water sensitivity and moderately weak or moderately strong flow velocity sensitivity. The water sensitivity of the Enping Group samples is moderately weak or moderately strong, the flow rate sensitivity is moderately weak, the alkali sensitivity is weak, the acid sensitivity is moderately weak, and the salinity sensitivity is moderately weak or moderately strong. (3) The sensitivity of the Wenchang Formation is mainly affected by the content of clay minerals. The sensitivity of the Enping Formation is also affected by the clay content and type. Although the clay content is not high, the permeability is more susceptible to sensitivity due to the pore structure and debris particle distribution characteristics. These conclusions are beneficial for the selection of fluid parameters and efficient reservoir development. Full article

The Ordovician thick dolostone in Shuntogol area of the Tarim Basin has the potential to form a large-scale reservoir, but its genesis and reservoir development model are still unclear. Starting from a sedimentary sequence, this study takes a batch of dolostone samples obtained from new drilling cores in recent years as the research object. On the basis of core observation and thin section identification, trace elements, cathodoluminescence, carbon and oxygen isotopes, rare earth elements, and X-ray diffraction order degree tests were carried out to discuss the origin of the dolomite and summarize the development model of the dolostone reservoir. The analysis results show that the Ordovician dolomite in the study area had a good crystalline shape, large thickness, high Fe and Mn values, and mostly showed bright red light or bright orange–red light under cathode rays. The ratio of δ¹⁸O values to seawater values at the same time showed a negative bias; the δCe values were negative anomalies, the δEu values were positive anomalies, and the order degree was high. This indicates that the dolomitization process occurred in a relatively closed diagenetic environment. The Ordovician carbonate rocks in the study area were low-lying during the sedimentary period, and with the rise of sea level, the open platform facies continued to develop. When the Middle and Lower Ordovician series entered the burial stage, the main hydrocarbon source rocks of the lower Cambrian Series entered the oil generation peak, and the resulting formation overpressure provided the dynamic source for the upward migration of the lower magnesium-rich fluid, and the dolomitization fluid entered the karst pore system in the target layer to produce all the dolomitization. This set of dolostone reservoirs is large in scale and can be used as a favorable substitute area for deep carbonate exploration for continuous study. Full article

This paper covers the design of binder formulations and technology for low-energy building materials based on alkaline aluminosilicate binders developed for special uses. The microstructure of the binders was investigated using scanning electron and atomic force microscopy examination techniques. The identification of phase compositions was performed by means of X-ray diffraction. The degree of binding of the alkali metal ions within the binder was determined with the help of chemical analysis of the pore fluid. Structure formation depending upon binder mix design and curing conditions was also studied. Some examples of the manufacture and application of binder-based glues and adhesives, including those developed for heat insulation and fire prevention, are discussed. The advantages of binder-based temperature-insulating composite materials compared with traditionally used materials are highlighted. Full article

In addition to main fractures, a large number of secondary fractures are formed after the volumetric fracturing of shale gas wells. The secondary fracture properties are so complex, that it is difficult to identify and diagnose by direct monitoring methods. In this study, a new approach to model and diagnose secondary fracture properties is presented. First, a new pressure decline model, which is composed of four interconnected domains, i.e., wellbore, main fractures, secondary fractures, and reservoir matrix pores, is built. Then, the fracturing fluid pumping and post-fracturing soaking processes are simulated. The simulated pressure derivatives reflect five fracture-dominated flow regimes, which correspond to multiple alternating positive and negative slopes of the pressure decline derivative. The results of sensitivity simulation show that the density, permeability, and width of secondary fractures are the main controlling factors affecting the size ratio. Finally, based on the simulated pressure decline characteristics, a diagnostic method for the identification and analysis of secondary fracture properties is formed. This method is then applied to three platform wells in the Changning shale gas field in China. This study builds the correlation between the secondary fracture properties and the shut-in pressure decline characteristics, and also provides a theoretical method for comprehensive post-fracturing evaluation of shale gas horizontal wells. Full article