Accurate pore size distribution (PSD) characterization is crucial for shale reservoir evaluation and hydrocarbon development optimization, where surface relaxivity (rho) is the key parameter for converting nuclear magnetic resonance (NMR) T2 distributions to PSDs. Conventional methods for rho determination have two key bottlenecks: rho is usually treated as a uniform constant despite evidence of its pore-size dependence in heterogeneous shales, and technical limitations of low-temperature nitrogen adsorption (LTNA)- or mercury intrusion porosimetry (MIP)-based workflows reduce rho estimation accuracy, constraining the reliability of NMR-based reservoir characterization. In this work, an improved approach is proposed to determine NMR T2 surface relaxivity of pores at different size ranges, with systematic comparison against two conventional methods: surface-to-volume ratio (SVR) and PSD correlation. Twelve shale core samples from the Shahejie Formation in the Dongying Sag, China, were selected for this study, with systematic geochemical and petrophysical tests, as well as MIP, LTNA, and NMR measurements paired with multi-speed centrifugation. The results show that the rho values of larger pores are greater than those of smaller pores, with rho 1 (corresponding to centrifugation at 3000 rpm) being approximately 2-20 times larger than rho 4 (at 10,000 rpm). The rho values determined by two conventional methods significantly underestimate the volume of micrometer-sized pores, which are crucial for evaluating the mobility of hydrocarbons in shale formations. The pore size range determined by the improved approach aligns well with the pore-throat range obtained from MIP, and reveals that a significant volume of pores in these shales is controlled by throats smaller than 10 nm. This approach can be readily extended to evaluate reservoir performance of other shale formations and conventional rocks via appropriate adjustment of centrifugation speeds, enabling more accurate and reliable NMR-based pore structure characterization.

Water sensitivity damage, often induced during hydraulic fracturing, poses a significant threat to the productivity of tight sandstone reservoirs by reducing permeability. While commonly attributed to clay mineral reactions, a comprehensive understanding of its underlying mechanisms and corresponding engineering control strategies remains essential for effective prevention. This study investigates the water sensitivity mechanisms of the tight sandstone gas reservoirs in the Ahe Formation, Kuqa Depression, Tarim Basin, by integrating core flooding experiments with advanced microscopic analyses, including nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), and in-situ micro-CT scanning. Experimental results classify the reservoir's water sensitivity as weak to moderately weak (13-45%). The analysis reveals that damage is not solely controlled by the content of expandable clay minerals (e.g., illite/smectite mixed layer), which cause swelling and migration. Instead, the permeability reduction is dominantly influenced by the blockage of micropores (diameter < 30 μm), where clay swelling and particle migration exert their most significant impact. Furthermore, water blocking due to capillary-trapped irreducible water in small pores contributes substantially to the impaired gas flow. An integrated mechanism framework is established, in which expandable clays act as the initiating factor, the micropore system serves as the core damage carrier, and water blocking provides a superimposed amplification effect on permeability impairment. Consequently, water sensitivity damage in these tight sandstones results from the complex interplay of clay minerals, micropore structure, and fluid distribution. Therefore, effective prevention strategies must extend beyond simple clay content evaluation to establish an integrated evaluation system combining clay mineral properties, micropore structure characterization, and irreducible water saturation analysis, providing targeted guidance for fracturing fluid optimization and salinity control in field operations.

The Ordovician–Silurian transition (OST) was a period marked by pivotal changes in Earth’s paleoenvironments and a large-magnitude positive carbon isotopic excursion, the Hirnantian Isotopic Carbon Excursion (HICE). The OST sediments in the Yangtze region of South China accommodate vast shale gas resources, and tracking the HICE plays an important role in revealing the untapped resources. However, the driving mechanism behind the HICE in shallow Yangtze seawater remains elusive, hindering paleoenvironment reconstruction and energy exploration in this region. An OST limestone section was recently identified in the Wuke region, South China Block, providing an ideal opportunity to investigate the mechanism driving the HICE in the shallow Yangtze Sea. The OST of the Wuke section was classified into four stages, based on coupled C-Mg isotopic analysis. Stages I, II, III, and IV correspond to the P. sinensis, D. mirus–T. typicus, lowermost D. mirus–M. extraordinarius, and M. persculptus graptolite zones, respectively. An ~1.5‰ positive δ26Mg excursion occurs from the lowermost part of Stage II through the end of Stage III. Furthermore, binary mixing analysis of the δ26Mg and Ca/Mg ratios of carbonate fractions shows that the “limestone endmembers” during these two stages are more enriched in 26Mg than those of Stages I and IV. This feature may be attributed to the stabilization of metastable carbonates, as calcites with elevated δ26Mg can form through transformation from metastable species such as aragonite and amorphous calcium carbonate (ACC). Furthermore, the positive δ13C excursion starts at the base of the D. mirus graptolite zone and continues through the end of the M. extraordinarius zone. This suggests that the HICE may have initiated as early as the Late Katian in the shallow Yangtze Sea, and the earlier onset of the carbon isotopic excursion was likely partially caused by the stabilization of metastable carbonates. The results of this study imply that stabilization of metastable carbonates is one potential factor responsible for the HICE in the shallow Yangtze Sea.

The sandy conglomerate reservoir exhibits substantial vertical extent and considerable thickness, which provides significant capacity for CO2 storage. Meanwhile, the shrinkage pores are developed in the tuff-filled material of sand conglomerate reservoir, which is not only the oil/gas storage space, but also the ideal fluid flow channel of CO2. It is particularly important to select a reasonable pore throat cutting factor and accurately describe the structural and physical characteristics of the shrinkage pores for the evaluation of sand conglomerate reservoir. In this paper, the shrinkage pore developed sample is scanned with micro-computed tomography (CT) to obtain the 3D gray image. The shrinkage pore 3D digital rock is segmented, and the corresponding pore network model is extracted. Then, based on the 3D shrinkage pore network model, a different pore-throat cutting factor is selected to construct the shrinkage pore network models with different pore-throat spaces and calculate the physical/structural parameters. It can be found that, with the increase of pore-throat cutting factor, the number of pore-throat and porosity remain unchanged, and the permeability decreases, the pore volume distribution shifts to the left, the throat volume and throat length shifts to the right, and shape factor continuously shifted to the right. The increase of pore-throat cutting factor causes the interface between pore and throat to be more inclined to the pore side; the pore volume thus decreases, and the throat volume increases. Given the close agreement between laboratory-measured permeability (36.3 mD) and Lattice Boltzmann simulation results (38 mD) for the original shrinkage pore digital rock model, a pore-throat truncation factor of 0.3 +/- 0.1 (range: 0.2-0.4) is validated for sandy conglomerate reservoir characterization. When alpha < 0.2, it causes overestimation of pore volumes and underestimation of flow resistance; when alpha > 0.4, it induces excessive throat length and misrepresents real pore-throat morphology. This provides a basic platform for the accurate characterization of the shrinkage pores in sand conglomerate reservoirs.

Laminae are widely developed in shale formations and are the most typical sedimentary structures in shale. Evaluating their impact on pore structure, gas content, and fracability is crucial for the exploration and development of shale gas resources. This paper focused on the marine shale of the Longmaxi Formation located in the central Luzhou area of the Sichuan Basin. It analyzed the characteristics of the laminasets and their impact on pore structure, gas content, and fracability through various methodologies, including microscopic observation, mineral and elemental analysis, geochemical analysis, CO2 and N2 adsorption, mercury intrusion porosimetry (MIP), modular automated processing system (MAPS), isothermal adsorption, triaxial stress testing, and Brazilian disc splitting. The findings reveal that the laminae of the Longmaxi Formation can be divided into two types: plastic and rigid. Based on the thickness and stacking relationships of these two types, three distinct laminaset types were identified: integrated, gradient, and interbedded. Additionally, characteristic parameters relate to texture, structure, and developmental degree were extracted for each laminaset. The composition (minerals and TOC), texture (particle size and number), structure (continuity), and development degree (laminae density and thickness) of the laminaset jointly control the pore structure, gas content and fracability of the reservoir. In this paper, a new method for predicting fracability is proposed by combining the elastic modulus of the sample and the characteristic parameters of the laminae, showed improved correlation with measured fracability.

The gas-water two-phase seepage capacity of shale gas reservoir has an important influence on its productivity, but there is no method to evaluate the shale gas flow capacity directly by geophysical means such as logging. Three-dimensional digital core models of inorganic pores, organic pores and micro-fractures are established by core focused ion beams-scanning electron microscopy (FIB-SEM). The gas flooding water seepage of shale pores and fractures under different wetting conditions is simulated based on volume of fluid (VOF), and the characteristics of endpoint water saturation are obtained. Based on the understanding of the flow capacity of different pore types obtained from the simulation results, the equivalent flow capacity of each core can be obtained by combining the statistics of different pore types extracted from the large-scale mosaic scanning electron microscopy (Modular Automated Processing System, MAPS). Based on the analysis of petrophysical experiment and logging response, the flow capacity calculation equation and a model for evaluating flow capacity based on logging data are established. The actual logging data processing results show that the evaluation model proposed in this paper has high accuracy, and can obtain continuous shale gas flow profile. It can be used to guide shale gas exploration and development.

With the evolution of unconventional oil and gas exploration concepts from source rocks and reservoirs to carrier beds, the inter-layer sandstone carrier bed within marine–continental transitional shale strata has emerged as a significant target for oil and gas exploration. The inter-layer sandstone is closely associated with the source rock and differs from conventional tight sandstone in terms of sedimentary environment, matrix composition, and the characteristics of reservoir microscopic pore development. Preliminary exploration achievements display that the inter-layer sandstone is plentiful in gas content and holds promising prospects for exploration and development. Consequently, it is essential to investigate the gas-rich accumulation theory specific to the inter-layer sandstone reservoir in transitional facies. Pore development characteristics and heterogeneity are crucial aspects of oil and gas accumulation research, as they influence reservoir seepage performance and capacity. This paper employs total organic carbon analysis, X-ray diffraction, rock thin section examination, field emission scanning electron microscopy, physical analysis, high-pressure mercury intrusion analysis, gas adsorption experiments, and fractal theory to explore the reservoir development characteristics of the sandstone samples from the Upper Permian marine–continental transitional facies Longtan Formation in the southern Sichuan Basin. It also attempts to combine high-pressure mercury intrusion analysis and gas adsorption experiments to describe the structural and fractal characteristics of pores at different scales in a segmented manner. The findings reveal that the sandstone type of the Longtan Formation is mainly lithic sandstone. The pore size distribution of the sandstone primarily falls below 30 nm and above 1000 nm, with the main pore types being inter-granular pores and micro-fractures in clay minerals. The pore volume and specific surface area are largely attributed to the micropores and mesopores of clay minerals. The pore morphology is complex, exhibiting strong heterogeneity, predominantly characterized by slit-like and ink bottle-like features. Notably, there are discernible differences in reservoir structural characteristics and homogeneity between muddy sandstone and non-muddy sandstone. The pore morphology is complex, exhibiting strong heterogeneity, predominantly characterized by slit-like and ink bottle-like features. Notably, there are discernible differences in reservoir structural characteristics and homogeneity between muddy sandstone and non-muddy sandstone.

The pattern of connectivity between microfractures and matrix pores is important for in-depth understanding of ultra-deep porous-fractured clastic reservoirs. The evaluation of reservoir microstructure with digital core technology is an effective method. However, the information of fractures and pores cannot be acquired simultaneously from samples by merely using the traditional single-scale digital core analysis method, such that an integrated analysis of pores and fractures is impossible, which seriously restricts the evaluation of porousfractured clastic reservoir. In this study, the 3D grayscale images of fractured samples are obtained through low-resolution micro-CT scanning, and the Otsu algorithm is adopted for binary segmentation of the 3D grayscale images. Then, matrix samples are drilled at the positions with small, moderate and large distances to fractures respectively for high-resolution scanning, and the maximum class spacing algorithm is used for binary segmentation to construct 3D fractured-porous digital core and the maximal ball algorithm is applied to extract the 3D fracture and pore network model. Finally, a fracture-matrix pore multiscale network model is built by the integration method. The results show that the matrix porosity decreases significantly with the increase of distance to the microfracture, that is, the further the distance to the microfracture, the smaller the matrix porosity. Therefore, a single small-scale pore-fracture model cannot reflect the structural characteristics of large-scale samples, which further verifies the necessity of establishing a representative pore-fracture fusion model. Since the fracture-matrix pore multiscale network model contains both fracture and matrix pore characteristics, the corresponding physical properties can be calculated. The fusion model has a total porosity of 13.6% and the porethroat diameter/fracture aperture ranging in 3-2400 mu m. The proposed modeling method provides a basic study platform for investigating the pore-fracture connectivity pattern in ultra-deep clastic reservoirs.

For shrinkable pore-developed sandy conglomerate formation, the identification of the formation lower limit is of great significance in characterizing the physical properties. In this paper, a 3D gray image of a shrinkage pore-developed sandy conglomerate sample is obtained with micro-CT scanning, the maximum class spacing algorithm is used for binarization segmentation to construct the 3D shrinkage pore digital rock, and the corresponding shrinkage pore network model is extracted through the maximum ball algorithm. By applying the shrinkage pore network model, different formation lower limit RT values are set to eliminate the pores and throats below the lower limit value, and the corresponding shrinkage pore network model is built to calculate the physical parameters. With the increase of formation lower limit RT, the number of pore throats decreases, the porosity and permeability decrease, the average pore-throat radius increases, the aspect ratio and coordination number decrease, the connectivity function curve shifts to the right, and the pore network becomes less connected. When the formation lower limit is 20 μm, the pore/throat in the shrinkage pore network model is disconnected. This provides a basic platform for the study of the physical characteristics of shrinkage pores in tight sandy conglomerate reservoirs, which has important academic significance and practical application value.

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Nanopores are in dominant positions in tight reservoirs. Recently, global scholars have focused on the role of imbibition in tight reservoirs on the macroscale, which is insufficient for understanding the process and mechanism of imbibition in tight reservoirs on the microscale. Therefore, it is of great significance to adopt a new microscopic research method to study the imbibition of water in micropore and nanopore spaces in tight reservoirs. In this paper, models of the quartz nanopore imbibition effect and water drive oil reservoirs are established through molecular dynamics simulation. Then, the impacts of different factors on the imbibition effect and the roles of this effect in the water drive process are investigated. The results show that the percolation rate of water in the nanopore is related to the temperature, pore size, and wettability. The permeation strength increases with increasing wettability. Warming accelerates the movement of water molecules in the system, thereby increasing the rate of osmosis, enhancing the strength of osmosis, and shortening the time needed for equilibrium. However, the total amount of osmosis remains unchanged. The smaller the pore size is, the stronger the sorption strength. Imbibition plays a dominant role at lower injection rates, and expulsion plays a dominant role as the injection rate gradually increases.

Shale gas is a prospective cleaner energy resource and the exploration and development of shale gas has made breakthroughs in many countries. Structure deformation is one of the main controlling factors of shale gas accumulation and enrichment in complex tectonic areas in southern China. In order to estimate the shale gas capacity of structurally deformed shale reservoirs, it is necessary to understand the systematic evolution of organic pores in the process of structural deformation. In particular, as the main storage space of high-over-mature marine shale reservoirs, the organic matter pore system directly affects the occurrence and migration of shale gas; however, there is a lack of systematic research on the fractal characteristics and deformation mechanism of organic pores under the background of different tectonic stresses. Therefore, to clarify the above issues, modular automated processing system (MAPS) scanning, low-pressure gas adsorption, quantitative evaluation of minerals by scanning (QEMSCAN), and focused ion beam scanning electron microscopy (FIB-SEM) were performed and interpreted with fractal and morphology analyses to investigate the deformation mechanisms and structure of organic pores from different tectonic units in Silurian Longmaxi shale. Results showed that in stress concentration areas such as around veins or high-angle fractures, the organic pore length-width ratio and the fractal dimension are higher, indicating that the pore is more obviously modified by stress. Under different tectonic backgrounds, the shale reservoir in Weiyuan suffered severe denudation and stronger tectonic compression during burial, which means that the organic pores are dominated by long strip pores and slit-shaped pores with high fractal dimension, while the pressure coefficient in Luzhou is high and the structural compression is weak, resulting in suborbicular pores and ink bottle pores with low fractal dimension. The porosity and permeability of different forms of organic pores are also obviously different; the connectivity of honeycomb pores with the smallest fractal dimension is the worst, that of suborbicular organic pores is medium, and that of long strip organic pores with the highest fractal dimension is the best. This study provides more mechanism discussion and case analysis for the microscopic heterogeneity of organic pores in shale reservoirs and also provides a new analysis perspective for the mechanism of shale gas productivity differences in different stress–strain environments.

Shale oil is stored in nanoscale shale reservoirs. To explore enhanced recovery, it is essential to characterize the flow of hydrocarbons in nanopores. Molecular dynamics simulation is required for high-precision and high-cost experiments related to nanoscale pores. This technology is crucial for studying the kinetic characteristics of substances at the micro- and nanoscale and has become an important research method in the field of micro-mechanism research of shale oil extraction. This paper presents the principles and methods of molecular dynamics simulation technology, summarizes common molecular models and applicable force fields for simulating shale oil flow and enhanced recovery studies, and analyzes relevant physical parameters characterizing the distribution and kinetic properties of shale oil in nanopores. The physical parameters analyzed include interaction energy, density distribution, radial distribution function, mean-square displacement, and diffusion coefficient. This text describes how molecular dynamics simulation explains the mechanism of oil driving in CO2 injection technology and the factors that influence it. It also summarizes the advantages and disadvantages of molecular dynamics simulation in CO2 injection for enhanced recovery of shale oil. Furthermore, it presents the development trend of molecular dynamics simulation in shale reservoirs. The aim is to provide theoretical support for the development of unconventional oil and gas.

Shale oil and gas resources mainly exist in the pore and fracture system. Quantitative characterization of pore development characteristics and gas-bearing properties is crucial for shale reservoir evaluation. The pore development of shale reservoir exhibits strong complexity and heterogeneity, and research on pore development characteristics of coal measure shale lags behind that of marine shale reservoir. Hence, it is urgent to investigate the pore heterogeneity characteristics of coal-bearing shale and its influence on gas bearing properties. Therefore, the coal-bearing Cretaceous Nenjiang shales from the Songyuan area of the Songliao Basin were selected as the research object in this study. Through total organic carbon (TOC) analysis, X-ray diffraction experiments, porosity analysis, nitrogen adsorption–desorption experiments, and methane isothermal adsorption experiments, the characteristics of pore structure, heterogeneity, and gas bearing properties of coal-bearing shale were analyzed. The influence of rock and mineral components on pore structure and heterogeneity characteristics, the relationship between pore structure characteristics and fractal characteristics, and the effects of pore structure and heterogeneity on gas bearing properties were also discussed. The results show that: (1) The organic matter abundance of the shale in the Nenjiang Formation does not change significantly (the average TOC content is 2.38%). Ink bottle-shaped pores are mostly developed, and the Nenjiang shale is rich in clay minerals (average content 55.6%), with slit-shaped pores mostly developed. The pore surface of shale exhibits obvious fractal characteristics, with average fractal dimensions D1 and D2 of 2.54 and 2.74, respectively, indicating that the internal structure is more complex than the surface structure. (2) The enrichment of organic carbon increases the specific surface area by affecting the development of micropores and pores, consequently increasing the fractal dimension of pores. Similarly, the development of clay minerals increases the number of mesopores and macropores, thereby increasing the fractal dimension of pores. (3) Small pores develop larger specific surface areas, which increases the complexity and heterogeneity of the pore structure. This promotes remarkable fractal characteristics, expands the adsorption sites, and improves the adsorption capacity. This work will provide a scientific theoretical basis for the comprehensive evaluation of coal-bearing shale reservoirs and research on shale gas reservoir formation theory.

The microscopic pore-fracture structure and wettability have a significant influence on the two-phase seepage of shale gas and water. Due to the limitation of experimental conditions, the seepage patterns of gas and water in shale pores and slits under different wetting conditions have not been clarified yet. In this study, the three-dimensional digital rock models of shale inorganic pores, organic pores, and microfractures are established by focused ion beam-scanning electron microscopy scanning, and gas-driven water seepage simulation in shale microscopic pore-fracture structure under different wetting conditions is carried out based on volume of fluid method. The simulation results show that the gas–water relative permeability curves of microfractures are up-concave, and the gas–water relative permeability curves of inorganic and organic pores are up-convex; the gas–water two-phase percolation in microfractures is least affected by the change of wettability, the gas–water two-phase percolation in inorganic pores is most affected by the change of wettability, and the organic pores are in between; the gas–water two-phase percolation zone of microfractures is the largest, and the isotonic saturation is the highest; under the water-wet conditions, the critical gas saturation of microfractures, inorganic pores, and organic pores are 0.13, 0.315, and 0.34, respectively, and the critical gas saturation of organic pores under non-water-wet conditions is 0.525, indicating that under water-bearing conditions, the shale gas flow capacity in water-wet microfractures is the strongest, followed by water-wet inorganic pores, water-wet organic pores, and hydrophobic organic pores, respectively.

Marine-continental transitional shale, as an important shale type, gains less attention than marine and continental shale, which restricts the exploration and development process of marine-continental transitional shale gas. In this study, the Upper Permian Longtan Formation shale in the southern Sichuan Basin was taken as the research object, and the organic matter development characteristics, hydrocarbon generation ability, mineral composition, physical properties, and gas bearing characteristics of the Longtan Formation shale were systematically analyzed. In addition, the effects of organic matter abundance, maturity, and mineral components on shale gas adsorption capacity have been discussed in detail. The results show that the abundance of organic matter in the marine continental transitional shale of the Longtan Formation in southern Sichuan varies greatly, with the TOC value of the vast majority of shale being greater than 2.0%, with the carbon shale (TOC>12%) accounting for about 5%. The main type of organic matter is Type III, with part of Type II2. The maturity of organic matter is in the stage of high maturity to over maturity, which is conducive to the generation of dry gas. There is a good positive linear correlation between the reflectance of vitrinite (R-o) and the maximum thermal decomposition peak temperature (T-max) of rock. The higher the abundance of organic matter, the greater the hydrocarbon generation potential of shale, and the carbonaceous shale shows good shale gas generation potential. The shale of the Longtan Formation is rich in clay minerals, with the highest content of the illite/smectite mixed layer. The abundance and maturity of organic matter jointlypromote the enrichment of Longtan shale gas. The enrichment of clay minerals is beneficial to shale gas adsorption, but poses a challenge to production fracturing.

Tuffaceous material of the Lower Triassic Baikouquan Fm., NE Junggar Basin is closely associated with detrital particles and particularly with crenulated quartz grains and kaolinite. The amount tuff is reduced closed to the source area. The main component of the tuffaceous interstitial material is SiO2, followed by K2O, FeO, and MgO. The tuffaceous interstitial material can be further divided into three types: medium (basic) potassium-rich tuffaceous material, ultrabasic iron-magnesium tuffaceous material, and ultrabasic iron-magnesium rich tuffaceous material. Medium (basic) potassium-rich is dominated by fusiform shrinkage pores, often associated with kaolinite, while ultrabasic iron-magnesium rich tuff pores are not developed, and ultrabasic iron-magnesium tuffaceous material is dominated by dissolution pores. The solution pores have large diameters and large volume of pores and throats, but low pores and throats coordination number. The pore size and the pores and throats volume of shrinkage fractures are small, but the pores and throats coordination number are large. Dissolution pores are mainly distributed in Mbr 1, whereas shrinkage pores mainly occur in Mbr 2. However, the interlayer productivity data from a single well show that the Mbr 1 has a higher productivity than Mbr 2. However, the interlayer productivity data from a single well show that Mbr 1 has a higher productivity than Mbr 2. In addition, tuff is not responsible for wind action, but the cause of intermittent water flow transport in volcanic rocks. Distributary channels at the fan delta front comprise the dominant facies for development of tuffaceous interstitial materials. The composition of tuffaceous interstitial material clearly determines reservoir quality. Medium basic potassium-rich tuff has a high SiO2 content and is prone to devitrification, so it is dominated by shrinkage pores, whereas ultrabasic iron-magnesium tuff contains FeO and MgO and is vulnerable to acid corrosion and the formation of corrosion pores. However, acid minerals such as kaolinite reduce reservoir connectivity. Compared with solution pores, shrinkage pores have a small pore volume, but high pores and throats coordination number, indicating that they have a high seepage capacity. Shrinkage pores are an important factor in causing production differences between single layers and should be given more attentions.

选取代表性的砂岩基质样品和裂缝样品,通过微米 CT 扫描方法分别建立相应的基质和裂缝三维数字岩心.然后,基于相同物理尺寸和分辨率的基质样品数字岩心和裂缝数字岩心,通过布尔叠加算法构建基质-裂缝双重介质数字岩心;同时,基于图像开运算算法进行孔隙体素消除,获取不同微孔喉尺寸的基质数字岩心,并叠加构建不同微孔喉尺寸的基质-裂缝双重数字岩心.最后,基于不同微孔喉尺寸下基质样品和基质-裂缝双重介质样品三维数字岩心,分别计算相应的总孔隙度、连通孔隙度和绝对渗透率,可以发现:微孔喉对基质和基质-裂缝样品的总孔隙度整体贡献较小;微孔喉对基质的连通孔隙度有较大贡献,但对双重介质的连通孔隙度贡献较小;微孔喉对基质的渗透率有重要贡献,对基质-裂缝双重介质的渗透率贡献较小.

The tight oil formation develops with microfractures and matrix pores, it is important to study the influence of matrix physical properties on flow characteristics. At first, the representative fracture and matrix samples are selected respectively in the dual media, the fracture and matrix digital rocks are constructed with micro-CT scanning at different resolutions, and the corresponding fracture and matrix pore networks are extracted, respectively. Then, the modified integration method is proposed to build the dual network model containing both fracture and matrix pore-throat elements, while the geometric-topological structure equivalent matrix pores are generated to fill in the skeleton domain of fracture network, the constructed dual network could describe the geometric-topological structure characteristics of fracture and matrix pore-throat simultaneously. At last, by adjusting the matrix pore density and the matrix filling domain factor, a series of dual network models are obtained to analyze the influence of matrix physical properties on flow characteristics in dual-media. It can be seen that the matrix system contributes more to the porosity of the dual media and less to the permeability. With the decrease in matrix pore density, the porosity/permeability contributions of matrix system to dual media keep decreasing, but the decrease is not significant, the oil–water co-flow zone decreases and the irreducible water saturation increases, and the saturation interval dominated by the fluid flow in the fracture keeps increasing. With the decrease in matrix filling domain factor, the porosity/permeability contributions of matrix system to dual media decreases, the oil–water co-flow zone increases and the irreducible water saturation decreases, and the saturation interval dominated by the fluid flow in the fracture keeps increasing. The results can be used to explain the dual-media flow pattern under different matrix types and different fracture control volumes during tight oil production.

Organic matter serves as the hydrocarbon-generating parent material for shale reservoirs, in which organic pores are also important reservoir spaces. Different types of organic matter have wide differences in hydrocarbon generation and pore-forming ability. Based on the occurrence state of organic matter, in the over-mature Marine shale organic matter mainly includes in situ and migrated organic matter. It has been extensively studied on in situ organic matter and organic matter migrating into inorganic pores, while there are few reports of organic matter migrating into microfractures. In this study, the over-mature Marine shale reservoir in the first sub-member of the Silurian Longmaxi Formation in the Luzhou area of the Sichuan Basin is taken as an example. Core observation, optical microscope, high-precision large-view scanning (MAPS, modular automated processing system) and mineral analysis scanning (QEMSCAN, quantitative evaluation of minerals by scanning electron microscopy) were conducted to observe the morphological characteristics of organic matter veins, and then analyze the genesis and pore-forming characteristics of such organic matter. The results show that: ① Organic matter veins (OM veins) are soluble organic matter with fractures as an effective channel, and OM veins in the study section is easy to form under the condition of micro-fractures in the shale sweet segment after organic matter generating oil and before gas generation ② Organic matter in the OM veins are less efficient in pore-forming, with sparse pores and smaller pore sizes. The occurrence of fractures varies greatly, including horizontal fractures, oblique fractures and high-angle fractures, which are mostly developed in the Long111 and Long112 layers. ③ The development of OM veins can indicate better reservoir conditions, that is, the layers have strong hydrocarbon generation intensity (strong pore-forming ability of organic matter) and high brittle mineral content (strong reservoir compressibility). The new findings in this paper reveal that OM veins are instructive for the determination of geological–engineering sweet spots in the Longmaxi Formation in the Sichuan Basin, and also provide guidance for future research on occurrence form and geological significance of different types of organic matter.