For the petrophysics model of tight sandstones, the elastic modulus of their sandstone and mudstone components are often substituted with those of quartz and clay, which affects model accuracy. To solve this problem, we innovate an adaptive approach for model the rock physics characteristics of tight sandstone. First, based on the relationship between P- and S-wave velocities from well logs and the elastic modulus of the rocks, the equivalent elastic modulus of tight sandstone under saturated conditions is calculated. Next, The Lee model and the Gassmann equation were jointly used to determine the equivalent elasticity modulus of tight sandstone matrix. The upper and lower limits of the equivalent elasticity modulus for mudstone and sandstone are established using the mudstone content curve, the least-squares method and the Voigt-Reuss-Hill (VRH) model. We used the random-walk algorithm to accurately calculate the equivalent elastic modulus of the sandstone and mudstone components. Finally, using the accurately obtained elastic modulus of sandstone and mudstone, the equivalent elastic modulus of the matrix is calculated. The Kuster-Toks & ouml;z model is subsequently applied to compute the dry-frame bulk modulus and shear modulus of the rock. Following this, the Brie model is used to calculate the elastic modulus of the mixed fluid, thereby completing the construction of the rock physics model for the study area. The results demonstrate that our improved petrophysics model can predict the S-wave velocity curve with <= 15% errors relative to the true curve. When sweet spot prediction was performed using reservoir-sensitive parameter (Vp/Vs) derived from the petrophysics template, the agreement between the predictions and well-log data was 80%. Thus, our petrophysics model method can be used to predict tight gas reservoirs effectively and will aid efforts to improve petroleum exploration works in the study area.

Shale oil reserves are abundant worldwide and are a primary focus for future oil and gas development. Shale reservoirs are dense, highly heterogeneous, and have a low oil recovery degree. CO2 flooding can achieve the efficient development of shale oil, but the development of micro- and nano-pores in shale oil reservoirs and the complexity of fluid occurrence make it difficult to analyze the micro-mechanisms governing the enhanced recovery of shale oil through macroscopic CO2 flooding by conventional methods. This seriously limits the widespread application of CO2 flooding in shale oil development. Molecular dynamics offers a microscopic perspective to analyze the interaction between CO2 molecules and crude oil molecules in various states of occurrence, including their interaction with shale pore walls. This approach has become a crucial method for studying reservoir development. In this paper, first, the molecular dynamics simulation methods are summarized, including details on basic principles, force fields, ensemble theory, boundary conditions, simulation process, and molecular simulation software. Second, the characteristics of shale oil reservoirs are elucidated from the perspectives of shale reservoir properties, kerogen type, and occurrence status. The micro-mechanisms (swelling, diffusion, viscosity reduction, extraction, mixing, adsorption, and competitive adsorption) of the displacement of shale oil through CO2 flooding are analyzed in detail, and the main factors (temperature, pressure, crude oil composition, CO2 injection amount, etc.) affecting the mechanism of shale oil displacement through CO2 flooding are summarized. Finally, this paper elucidates the current challenges in molecular simulation technology regarding the micro-mechanisms of CO2-enhanced oil recovery. It also discusses the potential applications and future development directions for CO2-enhanced shale oil recovery. Regarding CO2 shale oil recovery, important future directions for molecular simulation include CO2 composite oil recovery research, constructing composite mineral models, enhancing adsorption and dissolved shale oil recovery, and integrating quantum mechanics research methods. Molecular dynamics can accurately simulate the micro-displacement process of CO2 in shale pores, build a bridge between macro- and micro-displacement dynamics, and provide guidance for the widespread application of CO2-enhanced shale oil recovery. This study provides a reference for the development and application of molecular simulation technology in unconventional oil and gas development.

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12-8.39 x 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

The improvement of resolution and efficiency of seismic inversion is one of the key problems in seismic reservoir characterization. We first express the PP-wave (incident P wave, reflected, or scattered P wave) reflection coefficient of transversely isotropic media with a horizontal symmetry axis (HTI) in the form of Fourier coefficients. Then, we analyze the sensitivity of Fourier coefficients to elastic parameters and fracture weaknesses. The results demonstrate that the zeroth-order Fourier coefficient is sensitive to elastic parameters but insensitive to normal and shear fracture weakness, and the second-order Fourier coefficient is more sensitive to fracture weaknesses. To reliably estimate isotropic and fracture parameters, we next construct the seismic forward solver characterized by elastic parameters and fracture weaknesses by Fourier coefficient decomposition, and the objective function is constructed via Bayesian framework. Based on the automatic decoupling of multifrequency components for seismic signals in frequency domain, the optimal solution of inverse problem is searched by the iterative solution method using seismic multifrequency components. Finally, we use the synthetic data and real data to verify the effectiveness and stability of the proposed method. The experimental examples show that the proposed method can realize the inversion of elastic parameters and fracture parameters simultaneously using the fractional expansion of Fourier coefficients, and improve the accuracy of seismic inversion using the multifrequency component iteration method in the frequency domain.

In this study, an integrated approach for diagenetic facies classification, reservoir quality analysis and quantitative wireline log prediction of tight gas sandstones (TGSs) is introduced utilizing a combination of fit-for-purpose complementary testing and machine learning techniques. The integrated approach is specialized for the middle Permian Shihezi Formation TGSs in the northeastern Ordos Basin, where operators often face significant drilling uncertainty and increased exploration risks due to low porosities and micro-Darcy range permeabilities. In this study, detrital compositions and diagenetic minerals and their pore type assemblages were analyzed using optical light microscopy, cathodoluminescence, standard scanning electron microscopy, and X-ray diffraction. Different types of diagenetic facies were delineated on this basis to capture the characteristic rock properties of the TGSs in the target formation. A combination of He porosity and permeability measurements, mercury intrusion capillary pressure and nuclear magnetic resonance data was used to analyze the mechanism of heterogeneous TGS reservoirs. We found that the type, size and proportion of pores considerably varied between diagenetic facies due to differences in the initial depositional attributes and subsequent diagenetic alterations; these differences affected the size, distribution and connectivity of the pore network and varied the reservoir quality. Five types of diagenetic facies were classified: (ⅰ) grain-coating facies, which have minimal ductile grains, chlorite coatings that inhibit quartz overgrowths, large intergranular pores that dominate the pore network, the best pore structure and the greatest reservoir quality; (ⅱ) quartz-cemented facies, which exhibit strong quartz overgrowths, intergranular porosity and a pore size decrease, resulting in the deterioration of the pore structure and reservoir quality; (ⅲ) mixed-cemented facies, in which the cementation of various authigenic minerals increases the micropores, resulting in a poor pore structure and reservoir quality; (ⅳ) carbonate-cemented facies and (ⅴ) tightly compacted facies, in which the intergranular pores are filled with carbonate cement and ductile grains; thus, the pore network mainly consists of micropores with small pore throat sizes, and the pore structure and reservoir quality are the worst. The grain-coating facies with the best reservoir properties are more likely to have high gas productivity and are the primary targets for exploration and development. The diagenetic facies were then translated into wireline log expressions (conventional and NMR logging). Finally, a wireline log quantitative prediction model of TGSs using convolutional neural network machine learning algorithms was established to successfully classify the different diagenetic facies.

The upper Carboniferous tight sandstone strata are considered the most promising targets for gas exploration in the northeastern Ordos Basin. Reservoir quality is critical for the successful commercial exploration and development of tight sandstone gas. Reservoir quality of deeply buried tight sandstones is controlled by diagenesis, yet there is sparse systematic documentation on upper Carboniferous tight sandstone reservoir quality and its diagenetic link. In this study, we utilized core analysis and wireline log data, and core samples were studied using X-ray diffraction, optical light microscopy, scanning electron microscopy, porosity–permeability, mercury intrusion capillary pressure and nuclear magnetic resonance measurements. Dolomite, siderite, quartz, kaolinite, and illite are the main diagenetic cements. The upper Carboniferous sandstones pore system consists of residual intergranular pores, intragranular dissolution pores associated with feldspar grains and micropores mainly related to diagenetic minerals. Due to differences in diagenetic alterations, sandstones have significant differences in pore types and pore-filling components, ultimately leading to differences in reservoir quality. The residual intergranular porosity is closely related to the reservoir quality. Quartz cement and authigenic clay minerals lead to reduced residual intergranular porosity, but their impact on reservoir quality is relatively limited due to their relatively low content. The most significant factors contributing to reservoir quality deterioration are ductile (clay-rich) grain-influenced compaction and pervasive pore-filling carbonate cement. When sandstone contains large numbers of ductile grains, it loses a large amount of intergranular porosity due to compaction, and the pore space contains only a small number of dissolution pores and micropores, resulting in reservoir quality deterioration. Similarly, when a large amount of carbonate cement is developed in sandstone, it leads to intergranular porosity loss. The best reservoir quality sandstones preserve a percentage of intergranular porosity because they (i) have few ductile grains, resulting in low compaction, and (ii) do not have significant amounts of carbonate cements. Finally, the diagenetic variations were successfully correlated with wireline logs to evaluate the reservoir quality of subsurface upper Carboniferous sandstones. The data sets provided in this research offer insights to better evaluate and predict reservoir quality in the northeastern Ordos Basin.

New Middle-Lower Triassic gas reservoirs werefound in theeastern margin of the Ordos Basin, which provides new possibilitiesfor gas exploration in the Ordos Basin. However, there are few relevantstudies on these gas reservoirs. In this study, we use porosity-permeabilitymeasurements, optical light microscopy, scanning electron microscopy,mercury intrusion capillary pressure experiments, core-scale low-fieldnuclear magnetic resonance experiments, fluid inclusion analysis,burial history reconstruction, organic geochemistry data, and wirelinelog data to systematically investigate the reservoir quality and accumulationpattern of Middle-Lower Triassic gas reservoirs. The Middle-LowerTriassic sandstones are mostly lithic arkose, with a small amountof feldspathic litharenite. In comparison to the upper Paleozoic tightsandstone, the Middle-Lower Triassic sandstones exhibit a superiorpore structure and increased porosity and permeability. A significantportion of the Middle-Lower Triassic sandstones can be referredto as "conventional sandstones" (porosities >12%andpermeabilities >1 mD). The source rocks of the Middle-LowerTriassic gas reservoirs are most likely the upper Paleozoic coal andorganic-rich mudstone, and the accumulation of natural gas occurredin the Early Jurassic to Late Cretaceous. The gas accumulation inthe sandstones of the Middle-Lower Triassic reservoirs wasmainly driven by buoyancy. The initiation and extension of verticalfaults with small displacement in the northeast margin of the OrdosBasin enabled gas to move through the faults from the deep upper Paleozoicsource rocks to the Middle-Lower Triassic reservoirs. Sincegas accumulation relies on buoyancy, conventional sandstone layerswith good reservoir properties are more likely to reach high gas saturationand are the primary targets for exploration and development.

Tight sandstone gas in the Upper Paleozoic strata of the northeastern margin of the Ordos Basin exhibits remarkable exploration potential. The objective of this study is to characterize the generation, accumulation, and distribution of Upper Paleozoic tight sandstone gas in the Linxing-Shenfu gas fields located on the northeastern margin of the Ordos Basin. This study uses the following approaches: (1) porosimetry and permeability testing; (2) stable carbon isotope analysis; (3) organic geochemical examination; (4) gold tube pyrolysis experiments; (5) basin modeling; (6) fluid inclusion analysis; and (7) drilling and seismic data analysis. Reservoirs are classified based on the distance between the sandstone traps and source rocks: in Type I reservoirs, the sandstone traps are interbedded with the source rocks; in Type II reservoirs, the sandstone traps immediately overlie the source rocks; and in Type III reservoirs, the sandstone traps are located far from the source rocks. The three types of gas bearing reservoirs in the Linxing-Shenfu gas fields formed between 190 Ma and 96 Ma (Early Jurassic to Late Cretaceous), and gas accumulation in the three types of reservoirs occurred during the same period. A pressure differential was created between the source rocks and neighboring sandstones as a response to gas generation, and this was the primary mechanism of gas migration and accumulation in the Type I and Type II reservoirs. The initiation and growth of the vertical faults enabled the gas to migrate from the deep source rocks along faults, eventually accumulating in the Type III reservoirs; additionally, the gas migration and accumulation were primarily driven by buoyancy. Type I reservoirs with high gas saturation was mainly distributed in regions with gas expulsion intensities greater than 7 x 108 m3/km2 and located away from the faults. Type II reservoirs with high gas saturation were predominantly distributed in regions with gas expulsion intensities greater than 10 x 108 m3/km2. Type III reservoirs with gas production capacity primarily distributed in conventional sandstone units with high reservoir quality near the faults.

The lower Permian tight gas sandstones (TGSs) in the northeastern Ordos Basin have developed a complex pore network composed mainly of secondary pores with strong reservoir heterogeneity, which affects evaluation and exploitation of gas resources. In this study, lower Permian TGSs were analyzed through the thin sections, scanning electron microscopy, X-ray diffraction, He porosimetry, high-pressure mercury injection capillary pressure, X-ray computed tomography, and nuclear magnetic resonance experiments to elucidate the differential developmental characteristics of secondary pores and their effects on the pore structures and movable fluid distribution. Secondary pores in the lower Permian TGSs include dissolution pores associated with feldspar dissolution and micropores related to authigenic clay minerals. Based on fractal results, we designated the firstorder dissolution pores as those with pore throat diameters greater than 1.98 & mu;m, the second-order dissolution pores as those with pore throat diameters between 0.05 and 1.98 & mu;m, and the pore throats diameters of micropores are mainly smaller than 0.05 & mu;m. Both volumetric feldspar leaching calculations and petrographic statistics suggest that the secondary porosity observed in the lower Permian TGSs may not represent a net increase in porosity and more likely represents a redistribution of the original porosity. Dissolution requires sandstones with nonnegligible initial porosity and permeability: coarse-grained, quartz-rich, low proportion of ductile grains sandstones are more likely to maintain high porosity during burial, and dissolution of coarsegrained feldspar facilitates the development of first-order dissolution pores, thus generating the highest redistributed secondary porosity. The first-order dissolution pores have wide pore throat diameters, which enable seepage of movable fluids; the second-order dissolution pores have intermediate pore throat diameters, which allow moderate movable fluid seepage; and the micropores have small pore throat diameters, which are not conducive to seepage of movable fluids. Combinations of different types of secondary pores lead to differences in pore structures and distributions of movable fluids in the lower Permian TGSs. Specifically, TGSs with high firstorder dissolution porosity have better pore structures, corresponding to the highest movable fluid saturation (MFS) and movable fluid porosity (MFP). When micropores dominate the pore system, the pore structure and pore network connectivity are poor, and the MFS and MFP decrease.

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing-Huangfu area of the Ordos Basin.