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The Lower Cretaceous Shahezi Formation glutenite reservoirs in the Xujiaweizi Fault Depression are important tight gas reservoirs in the deep strata of the Songliao Basin. Their complex porosity and permeability relationships pose challenges to determining reservoir boundaries and evaluating reservoir grades. For the Shahezi Formation glutenite reservoirs, the water film thickness method, charge dynamics method, gas testing productivity method, and buoyancy balance method were used to determine theoretical lower limits, gas accumulation lower limits, effective flow lower limits, and reservoir-forming upper limits. The petrophysical values of the reservoir boundaries were determined based on the porosity and permeability relationships under different diagenetic controlling factors. On this basis, reservoir types were classified according to differences in microscopic pore structures, and a grading evaluation standard for tight reservoirs was established. This standard was then applied using logging data to provide a basis for selecting sweet spots in the tight gas exploration areas. The Shahezi Formation glutenite was divided into conventional reservoirs, Class Ⅰ-Ⅳ tight glutenite reservoirs, and non-reservoirs. The reservoir boundaries and classification evaluation results were well matched. Conventional reservoirs had porosity greater than 9% and permeability greater than 0.05×10-3 μm2. Class Ⅰ tight reservoirs had porosity of 8%-9% and permeability of (0.01-0.05)×10-3 μm2. Class Ⅱ tight reservoirs had porosity of 5%-8% and permeability of (0.001-0.01)×10-3 μm2. Class Ⅲ tight reservoirs had porosity of 3.5%-5% and permeability of (0.2-1)×10-3 μm2. Class Ⅳ tight reservoirs had porosity of 2%-3.5% and permeability of (0.05-0.2)×10-6 μm2. Non-reservoirs had porosity less than 2% and permeability less than 0.05×10-6 μm2. The gas production of tight glutenite was controlled by the reservoir type. Class Ⅰ and Class Ⅱ tight reservoirs were favorable high-yield layers. The thickness of favorable reservoirs in the Anda-Songzhan area of the northern Xujiaweizi Fault Depression was large, making it a sweet spot for tight gas exploration and development.

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.

To study the impact of faults on the enrichment and mobility of shale oil in the Gulong area, representative rock samples were selected in this paper. Based on geochemical data and chemical kinetics methods, coupled with shale oil enrichment and mobility analysis techniques, the shale oil generation quantity and in situ oil content were evaluated from the perspectives of shale oil generation and micro migration, and the mobility of shale oil was revealed. At the same time, the hydrocarbon expulsion efficiency (HEE) of shale was qualitatively and quantitatively characterized, combined with the development of faults. The research results indicate that the study area mainly develops organic-rich felsic (ORF)/organic-containing felsic (OCF) shale, their proportion in both wells exceeds 65%, and the resource amount is the largest in this type of lithofacies. The development of a fault controls the enrichment of shale oil, and the in situ oil content and oil saturation index (OSI) of the shale in well Y58, which is close to the fault, are significantly worse than those in well S2. Well Y58 has 9.52 mg/g and 424.83 mg/g TOC respectively, while well S2 has 11.34 mg/g and 488.73 mg/g TOC respectively. The fault enhanced the migration of shale oil, increasing the efficiency of oil expulsion. As a result, the components with weak polarity or small molecules, such as saturated hydrocarbons and low carbon number n-alkanes, are prone to migration, reducing the mobility of shale oil.

A quantitative evaluation model that integrates kerogen adsorption and clay pore adsorption of shale oil was proposed, and the evaluation charts of adsorption-swelling capacity of kerogen (Mk) and adsorbed oil capacity of clay minerals (Mc) were established, taking the 1st member of Cretaceous Qingshankou Formation in the northern Songliao Basin as an example. The model and charts were derived from swelling oil experiments performed on naturally evolved kerogens and adsorbed oil experiments on clays (separated from shale core samples). They were constructed on the basis of clarifying the control law of kerogen maturity evolution on its adsorption-swelling capacity, and considering the effect of both the clay pore surface area that occupied by adsorbed oil and formation temperature. The results are obtained in four aspects: (1) For the Qing 1 Member shale, with the increase of maturity, Mk decreases. Given Ro of 0.83%–1.65%, Mk is about 50–250 mg/g. (2) The clay in shale adsorbs asphaltene. Mc is 0.63 mg/m2, and about 15% of the clay pore surface is occupied by adsorbed oil. (3) In the low to medium maturity stages, the shale oil adsorption is controlled by organic matter. When Ro>1.3%, the shale oil adsorption capacity is contributed by clay pores. (4) The oil adsorption capacity evaluated on the surface at room temperature is 8%–22% (avg. 15%) higher than that is held in the formations. The proposed evaluation model reveals the occurrence mechanisms of shale oils with different maturities, and provides a new insight for estimating the reserves of shale oil under formation temperature conditions.

Based on the typical dissection of various onshore tight oil fields in China, the tight oil migration and accumulation mechanism and enrichment-controlling factors in continental lake basins are analyzed through nuclear magnetic resonance (NMR) displacement physical simulation and Lattice Boltzmann numerical simulation by using the samples of source rock, reservoir rock and crude oil. In continental lake basins, the dynamic forces driving hydrocarbon generation and expulsion of high-quality source rocks are the foundational power that determines the charging efficiency and accumulation effect of tight oil, the oil migration resistance is a key element that influences the charging efficiency and accumulation effect of tight oil, and the coupling of charging force with pore-throat resistance in tight reservoir controls the tight oil accumulation and sweet spot enrichment. The degree of tight oil enrichment in continental lake basins is controlled by four factors: source rock, reservoir pore-throat size, anisotropy of reservoir structure, and fractures. The high-quality source rocks control the near-source distribution of tight oil, reservoir physical properties and pore-throat size are positively correlated with the degree of tight oil enrichment, the anisotropy of reservoir structure reveals that the parallel migration rate is the highest, and intralayer fractures can improve the migration and accumulation efficiency and the oil saturation.

The research progress of isotopic fractionation in the process of shale gas/coalbed methane migration has been reviewed from three aspects: characteristics and influencing factors, mechanism and quantitative characterization model, and geological application. It is found that the isotopic fractionation during the complete production of shale gas/coalbed methane shows a four-stage characteristic of “stable-lighter-heavier-lighter again”, which is related to the complex gas migration modes in the pores of shale/coal. The gas migration mechanisms in shale/coal include seepage, diffusion, and adsorption/desorption. Among them, seepage driven by pressure difference does not induce isotopic fractionation, while diffusion and adsorption/desorption lead to significant isotope fractionation. The existing characterization models of isotopic fractionation include diffusion fractionation model, diffusion-adsorption/desorption coupled model, and multi-scale and multi-mechanism coupled model. Results of model calculations show that the isotopic fractionation during natural gas migration is mainly controlled by pore structure, adsorption capacity, and initial/boundary conditions of the reservoir rock. So far, the isotope fractionation model has been successfully used to evaluate critical parameters, such as gas-in-place content and ratio of adsorbed/free gas in shale/coal etc. Furthermore, it has shown promising application potential in production status identification and decline trend prediction of gas well. Future research should focus on: (1) the co-evolution of carbon and hydrogen isotopes of different components during natural gas migration, (2) the characterization of isotopic fractionation during the whole process of gas generation-expulsion-migration-accumulation-dispersion, and (3) quantitative characterization of isotopic fractionation during natural gas migration in complex pore-fracture systems and its application.

Oil and gas exploration professionals have begun to focus more on unconventional oil and gas reserves in recent years as a result of their increased efforts. Fractures have a significant impact on the permeability and connectivity of reservoirs as a crucial component of rock mechanics and hydraulics, which directly affects the production of oil and gas. The identification of fracture development zones or micro faults, as well as how to adequately define the fracturing model, have thus become crucial and pressing issues in the forecast of oil and gas reservoirs. In this study, we decompose the three-dimensional seismic data volume in a site in order to obtain the single frequency data volume that can be calculated using the ant tracking technique. We do this by taking advantage of the synchronous extrusion improvement of short time Fourier transform in time-frequency focusing. Coupled with the advanced DFN model, the extracted data are calibrated in various rock attributes to restore the morphology and characteristics of fractures. The findings demonstrate that this method is capable of providing not only a precise outline of micro fractures but also a reflection of the characteristics of fractures at various scales, including structure and associated properties. The precision and applicability of this method are confirmed in this paper, which is significant as a reference for the oil and gas exploration industry.

Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China, such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin, NE China sandy conglomerate of Baikouquan Formation in Mahu area and hybrid rock of Lucaogou Formation in Jimusaer sag of Junggar Basin, NE China the theoretical lower limit, oil accumulation lower limit, effective flow lower limit and the upper limit of tight oil reservoirs were defined by water film thickness method, oil bearing occurrence method, oil testing productivity method and mechanical balance method, respectively. Cluster analysis method was used to compare the differences in pore-throat structure of different tight reservoirs, determine the grading criterion of tight reservoirs, and analyze its correlation with the limit of reservoir formation. The results show that the boundary between tight reservoir and conventional reservoir corresponds to the upper limit of physical properties, the boundary of class II and class III tight reservoirs corresponds to the lower limit of effective flow, the boundary of class III and class IV tight reservoirs corresponds to the lower limit of reservoir forming, and the theoretical lower limit of tight reservoir corresponds to the boundary between tight reservoir and non-reservoir. Finally, the application results of the grading evaluation criterion show that the tight oil productivity is highly controlled by the type of tight reservoir, and class I and class II tight reservoirs are the favorable sections for high production of tight oil.

The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area.

Aiming at the complicated problem of the genesis of high-quality hybrid sedimentary rocks, the pore-throat systems, controlling factors and fluid mobility of hybrid sedimentary rocks in the Permian Lucaogou Formation in Jimusar Sag were examined. The results show that the hybrid sedimentary rocks contain 5 types of pore-throat system, intergranular (Type A), mixed intergranular-dissolved-intercrystalline (Type B), dissolved (Type C), mixed dissolved-intercrystalline (Type D) and intercrystalline (Type E) ones. The pore-throat systems are controlled by 3 major factors, the component content and arrangement (CCA) of hybrid sedimentary rocks, sedimentary environment and diagenesis. CCA controls the matrix support mode of hybrid sedimentary rocks, and therefore controls the types and changes of pore-throat system. The sedimentary environment mainly controls the macroscopic distribution of pore-throat system, i.e., hybrid sedimentary rocks deposited in the near source and high-energy environment are characterized by high content of coarse-grained component, granular/interbedded-support mode, and development of Type A and Type B pore-throat systems. Hybrid sedimentary rocks deposited in the medium-energy environment far from source are characterized by dolomitic/mud support mode and Type C and Type D pore-throat systems. Hybrid sedimentary rocks deposited in low-energy environment far from source have mainly Type E and Type D pore-throat systems. Diagenetic processes such as compaction and calcite cementation make the proportions of Type A and Type C pore-throat systems decrease further. In the hybrid sedimentary process of sandy-mud, pore-throat system types show a change of “A→B→C→D”, in that of dolomite-sand, pore-throat system types show a change of “A→C→D→E” or “B→D→E”, and in that of dolomite-mud, pore-throat system types show a change of “D→E”, which are affected in details by the contents of coarse-grain component, feldspar and dolomite. The reservoir with Type A pore-throats has the best physical properties and fluid mobility, and the reservoirs with Type D and Type E pore-throats have the poorest. The movable fluid distribution is related to the matrix support mode, and the larger pores in hybrid sedimentary rocks of dolomite/mud support mode have no obvious advantage in fluid mobility. The findings of this study provide a geological basis for evaluating and building reasonable interpretation model of hybrid sedimentary rocks sweet spot.

Abstract Geological processes alter pore spaces over time, and their analysis can shed light on the dynamic fractal structure and fluid flow of rocks over time. This study presents experimental evidence to illustrate that the pore fractal structure evolves with sedimentation, carbonate cementation, clay growth, and dissolution. It examines, describes and characterizes a suite of core samples from the Gaotaizi oil layer of the second and third members of the Qingshankou Formation, Songliao Basin, China. The effects of mechanical compaction and other diagenesis effects on fractal pore structure on sedimentary rocks are discussed. A schematic diagram is proposed that describes the impacts of these diagenetic processes on fractal pore structure at the microscopic scale in sedimentary rocks. This work links the state of diagenetic alteration and fractal pore structure, which can guide practical applications such as predicting the permeability of sedimentary rocks.

A total of nine immature–low maturity oil shale samples from Fushun and Maoming, the main oil shale producing areas in China, and three mature shale samples from the Jiyang Depression, China, were selected for use in hydrocarbon generation thermal simulation experiments in an open system and a closed system. The parallel first–order reaction kinetic model and the overall nth–order reaction kinetic model were used to calibrate the pyrolysis kinetic parameters of the samples. This comparative study revealed following conclusion. The generation period of the gaseous hydrocarbons (C1–5) was the longest, and the generation period of the heavy hydrocarbon (C14+) was the shortest. The activation energy of the hydrocarbon generation reaction was closely related to the maturity of the organic matter, i.e., the higher the maturity of the sample, the higher the activation energy of the reaction, which indicates that oil shale/shale oil conversion requires higher temperature conditions. The parallel first–order reaction model regards the hydrocarbon generation reaction as a series of first–order reactions, and it has a better fitting effect for the longer hydrocarbon generation period reactions, such as generating gaseous hydrocarbons (C1–5) and light components (C6–14) from organic matter. The overall nth–order reaction treats the reaction as a nth–order reaction, and the nth–order reaction has a better fitting effect for reactions with a narrow hydrocarbon generation window, such as generating heavy components from organic matter. In the process of generating hydrocarbons from organic matter, the order of the reaction is the sum of the orders of the sub–reactions. The more hydrocarbon–generating parent material, the higher order of hydrocarbon–generating reaction. The reaction order sequence of the generation of different hydrocarbons from organic matter is as follows: generation of gaseous hydrocarbons > generation of light hydrocarbons > generation of heavy hydrocarbons.

Tight sandstone gas reservoirs have poorer porosity–permeability relationships, so conventional reservoir classification schemes can hardly satisfy the classification and evaluation demand of this type of reservoirs. To solve this problem, this paper took the Permian tight sandstone gas reservoir in the Linxing Block along the eastern margin of the Ordos Basin as an example to describe the micro-structures of the tight sandstone reservoirs by means of high-pressure mercury injection, nuclear magnetic resonance (NMR), scanning electron microscope (SEM) and so on. Then, the control effect of micro-structure parameters on the macrophysical properties was studied. Finally, classification and evaluation of tight sandstone reservoirs were carried out on this basis. And the following research results were obtained. First, NMR can identify the distribution of pores of different sizes, and high-pressure mercury injection can reflect the pore–throat configuration and percolation capacity of a reservoir. Second, both methods are better coincident in the description results. With an increase of the right peak of T2 spectra, the mercury intrusion curve presents a concave shape and the pore throat radius increases while the pore type gradually changes from intragranular dissolution pores and intercrystalline pores to intergranular pores and intergranular dissolution pores and the reservoir quality gets better. Third, micro-pore structure controls reservoir physical properties and fluid mobility. And the porosity of large pores is best correlated with the effective porosity, so it can be used to evaluate the reservoir capacity of tight sandstone. Fourth, the throat radius R15 obtained by high pressure mercury injection is in the best correlation with porosity and permeability, so it can be used to evaluate the percolation capacity of tight sandstone. Fifth, by combining the porosity of large pores with the R15, the tight sandstone reservoirs in the Linxing Block are classified into 4 categories, and the classification results are in a good agreement with the on-site well test data. It is concluded that the combination of high-pressure mercury injection and NMR can effectively identify the key parameters which reflect the reservoir capacity and percolation capacity of tight sandstone, and improve the reliability and integrity of reservoir classification. And by selecting the key parameters that reflect reservoir capacity and percolation capacity, it can provide guidance for the classification and evaluation of tight sandstone reservoirs.

Abstract To improve the precision of predicting sweet spots in tight oil reservoirs, the classification of tight oil reservoir storage space is necessary. The tight oil reservoir in the lower submember of the first member of Shahejie Formation (Es1L) of the Raoyang Sag of the Jizhong Depression in the Bohai Bay Basin was selected as a case study for testing a new method of classifying tight oil reservoir storage space based on the results of porosity, permeability, and mercury intrusion porosimetry measurements. The pore‐throat size ranges were classified according to pore‐throat fractal characteristics and were divided into three groups: 1000 nm. The oil‐bearing property of tight oil reservoir samples is closely related to the median and maximum pore‐throat radii. The inflection and intersection points in the trend lines of the pore volume percentages connected by different pore‐throat widths (1000 nm) vs the porosity and permeability values (which represent the relationship between the pore volume connectivity characteristics and porosity/permeability) were used as the basis for classifying the tight oil reservoir storage space. The tight oil reservoir storage space in the Es1L formation of the Raoyang Sag was divided into three categories, namely classes of III, II, and I. The porosity ranges of the three tight reservoir storage space classes are

Overmature continental shales are widely distributed in China, while few investigations have been conducted. The pore structure is a critical parameter controlling the resource potential of shale gas. However, the pore structure and heterogeneity of continental shales from the Shahezi Formation, Xujiaweizi Fault, Songliao Basin are not well revealed. In this study, helium porosity and permeability, low-temperature N2 adsorption (NGA), mercury intrusion capillary pressure (MICP), and nuclear magnetic resonance (NMR) were applied and characterized to the pore structures of continental shales. Moreover, the heterogeneity and complexity of the pore structure were revealed by the multifractal based on the NMR T2 spectrum. The results showed that clay minerals, quartz, and feldspar are the dominant minerals in the continental shales, and the most content of the clay minerals is the illite-smectite. The studied shales are the low porosity (mean 1.73%) and the ultralow permeability (mean 0.0707 mD) tight reservoirs. The hysteresis loops of ten shales belong to Types H2 and H3, characterized by high special surface area (mean 5.28 m2/g) and pore volume (mean 14.15×10−3 cm3/g). The pore size distributions are unimodal, and Type H3 shales have more larger pores than Type H2 shales. MICP results indicate that the pore-throats are almost less than 20 nm. NMR T2 spectra commonly show three peeks, i.e., p1 (20 ms) with the small T2,gm values, ranging from 0.18 ms to 1.36 ms (0.69 ms), which suggests that more nanopores are in the continental shales. Moreover, the average movable fluid percentage is low, ranging from 1.22% to 15.08% (mean 6.84%). The singularity strength range (Δα) shows that pore structures are heterogeneous. And the heterogeneity and complexity can be better revealed by the multifractal spectra rather than a monofractal model.

Polygonal faults (PFs) have been widely found in over 100 sedimentary basins worldwide, mainly in marine setting on continental margins and intracratonic sedimentary basins. PFs are characterized by layer-bound minor normal faults arranged in polygonal patterns and multi-direction strikes, most of which were developed in fine-grained sediments rich in claystone. The genesis mechanisms of PFs have been recognized as non-tectonic, mainly including shear failure, syneresis, density inversion, low coefficients of friction and gravity sliding theory. Previous studies often regarded PFs as conduits playing a role in favouring fluid migration, which were also regarded as fluid source expelled during PF generation. However, some researchers proposed that the PF-bearing layer is generally impermeable and may act as a seal. To better understand the role of PFs in fluid migration and their contrition to the shallower hydrocarbon accumulation, a geophysical review of global PFs case studies is conducted in this paper. A comprehensive analysis is carried out based on abundant case studies, with key parameters analyzed including the PFs characteristics (e.g., buried depth, lithology, size, etc.), formation mechanisms of PFs, tectonic-sedimentary setting, and the spatial relationship of PFs, nearby major fluid migration pathways and high amplitude anomalies. The compilation of global PF case studies of shows that hydrocarbon fluids from the deep is more likely to migrate upward through normal big faults, gas chimneys or unconformities surface around PFs. In most cases, PFs play limited roles in fluid migration, such as in South China Sea where hydrocarbon accumulations have been observed under the PFs and the PF-bearing layer may act as a seal trapping the free gas underneath. Generally, the role of PFs in fluid migration should be determined through a comprehensive analysis of the characteristics of PFs, surrounding amplitude anomalies, hydrocarbon distribution, and even the sealing ability of PFs which needs further study. It is more likely that the PFs play a limited role in vertical fluid migration and related shallower hydrocarbon accumulation and distribution.

Estuaries are important sediment facies in the fluvial-to-marine transition zone, are strongly controlled by dynamic interactions of tides, waves, and fluvial flows, and show various changes in depositional processes and sediment distribution. Deep investigations on the sediment dynamic processes of the sand component of estuaries have been conducted; however, the understanding of how mud supply affects estuaries’ sedimentary characteristics and morphology is still in vague. Herein, the effects of mud concentration, mud transport properties, fluvial discharge, and tidal amplitude on the sedimentary characteristics of an estuary were systematically analyzed using sedimentary dynamic numerical simulation. The results show that the mud concentration has significant effects on the morphology of tidal channels in estuaries, which become more braided with a lower mud concentration, and straighter, with reduced channel migration, with a higher mud concentration. The mud transport properties, namely, setting velocity, critical bed shear stress for sedimentation, and erosion, mostly affect the ratio between the length and width (RLW) of the sand bar; a sheet-like sand bar with a lower RLW value develops in the lower settling velocity, while there are obvious strip shaped bars with a high RLW value in the higher settling velocity case. Moreover, the effects of hydrodynamic conditions on sedimentary distribution were analyzed by changing the tidal amplitudes and fluvial discharges. The results show that a higher tidal amplitude is often accompanied by a stronger tidal energy, which induces a more obvious seaward progradation, while a higher fluvial discharge usually yields a higher deposition rate and yields a greater deposition thickness. From the above numerical simulations, the statistical characteristics of tidal bars and mud interlayers were further obtained, which show good agreement with modern sedimentary characteristics. This study suggests that sedimentary dynamic numerical simulation can provide insights into an efficient quantitative method for analyzing the effects of mud components on the sediment processes of estuaries.

AbstractDue to diverse mineral composition and complex lithology, mixed shale oil reservoir wettability features and the associated controlling factors remain unclear, limiting the evaluation of the oil-bearing property and sweet spot distribution. This paper examined mixed shale oil samples from the Jimusar Sag in the Lucaogou Formation. Casting thin sections, X-ray diffraction, geochemical characteristics, argon ion polishing scanning electron microscope, and high pressure mercury injection were used to analyze lithologic characteristics, mineral compositions, and pore-throat structures within the mixed shale oil reservoir. Using spontaneous imbibition and nuclear magnetic resonance, the wettability characteristics were analyzed. Impacts of organic matter abundance, mineral composition, pore-throat structure, and source-reservoir combination on wettability were discussed. The Lucaogou mixed shale oil reservoir primarily contains intergranular dissolved pores, intragranular dissolved pores, and intercrystalline pores. Three types of mercury intrusion cures were observed, including a weak platform shape (type I), gentle straight line shape (type II), and upward convex shape (type III), corresponding to intergranular, dissolved, and dissolved-intercrystalline dominant pore-throat systems, respectively. Mixed shale oil reservoirs show dual wet properties, containing both oil-wet and water-wet pores. Oil-wet pores (large pores with T2>1 ms) are more common and have better connectivity than water-wet pores (small pores with T2

Wettability is a significant factor in the exploration and development of shale oil. Currently, shale wettability has yet to reach a unified understanding. The contact angle is widely used in the study of shale wettability. However, the pre-treatment of the shale profoundly affects the contact angle. In this paper, the contact angle errors introduced by the pre-treatment of samples are discussed. Shale wettability is influenced by many factors, and there is not yet a systematic study of its influencing factors. Based on the above issues, the shale of the northern Songliao Basin was taken as the subject. The wettability of the different lithofacies is characterized by an improved contact angle method. The compositional characteristics of the shales and oil in the study area were analyzed. Fresh minerals, a single component of oil, and different temperature/pressure conditions were set up to investigate the influencing factors of shale wettability. The studies show that Organic matter abundance and thermal maturity have a positive correlation with oil-wet. Siliceous minerals are positively correlated with water-wet. Carbonate and clay minerals are negatively correlated with water-wet. The mineralogical composition of the shale, the composition of the oil, the characteristics of the aqueous media, the asphaltene deposits on the surface, temperature, and pressure all impact wettability. The affinity of minerals for hydrocarbons is iron minerals > carbonate minerals > clay minerals > siliceous minerals. Minerals are more hydrophilic at low salinity conditions. The deposition of non-hydrocarbons and asphaltenes renders the surface oleophilic. Increasing temperatures will reduce the hydrophilicity of the “oil-water-rock”.

The characteristics of paleosedimentary environments are of great significance for the enrichment of organic matter (OM) and hydrocarbons in lacustrine shale. This study analyzed mineralogy, well logging data, organic geochemical parameters (total organic carbon and pyrolyzed hydrocarbon), inorganic geochemical parameters (major and trace elements), and multiple geochemical proxies based on inorganic geochemical parameters. These were used to reconstruct the paleosedimentary environment of the lower 1st Member of the Shahejie Formation (Es1L) to reveal OM and shale oil enrichment mechanisms and establish a shale oil enrichment model. The (Fe2O3+Al2O3)/(CaO + MgO), Sr/Ba, Rb/Sr, Cu/Al, and Th/U parameters indicate that the Es1L in Raoyang Sag was deposited in a paleoenvironment dominated by arid paleoclimate, reducing conditions, and saltwater. Paleoclimate, clastic influx intensity, preservation conditions, paleoproductivity, and paleosalinity all affect OM abundance. The OM accumulation in the shale of Es1L was mainly controlled by the high primary productivity of surface water due to algal blooms and moderate salinities, which was achieved using stratified water columns with low oxygen conditions in bottom water. As the main valuable sites for shale oil storage, carbonate mineral depositions are of great significance for oil enrichment. As the dominant lithofacies for oil enrichment, carbonate-rich shale and calcareous shale lithofacies were deposited under a drier paleoclimate, low clastic influx intensity, strong reducing conditions, high paleoproductivity, and moderate salinity paleoenvironment. Additionally, the profile of the shale oil sweet spot was determined through the combination of lithofacies, logging, and paleosedimentary environment data.

Shale gas production prediction and horizontal well parameter optimization are significant for shale gas development. However, conventional reservoir numerical simulation requires extensive resources in terms of labor, time, and computations, and so the optimization problem still remains a challenge. Therefore, we propose, for the first time, a new gas production prediction methodology based on Gaussian Process Regression (GPR) and Convolution Neural Network (CNN) to complement the numerical simulation model and achieve rapid optimization. Specifically, through sensitivity analysis, porosity, permeability, fracture half-length, and horizontal well length were selected as influencing factors. Second, the n-factorial experimental design was applied to design the initial experiment and the dataset was constructed by combining the simulation results with the case parameters. Subsequently, the gas production model was built by GPR, CNN, and SVM based on the dataset. Finally, the optimal model was combined with the optimization algorithm to maximize the Net Present Value (NPV) and obtain the optimal fracture half-length and horizontal well length. Experimental results demonstrated the GPR model had prominent modeling capabilities compared with CNN and Support Vector Machine (SVM) and achieved the satisfactory prediction performance. The fracture half-length and well length optimized by the GPR model and reservoir numerical simulation model converged to almost the same values. Compared with the field reference case, the optimized NPV increased by US$ 7.43 million. Additionally, the time required to optimize the GPR model was 1/720 of that of numerical simulation. This work enriches the knowledge of shale gas development technology and lays the foundation for realizing the scale-benefit development for shale gas, so as to realize the integration of geological engineering.

To determine the occurrence mechanism and mobility of shale oil in the Shahejie Formation in the Jiyang Depression, organic geochemistry analysis, thin-section petrological observation, low-temperature nitrogen adsorption, high-pressure mercury intrusion porosimetry, field emission scanning electron microscopy experiments were conducted on shale samples to reveal its storage mechanism, including pore size, ratio of adsorbed oil to free oil, mobility and its influencing factors, and mode of storage. Residual shale oil is mainly present in pores less than 100 nm in diameter under the atmospheric temperature and pressure. The lower limit of pore size for free oil is 5 nm, and the lower limit of pore size for movable oil occurrence is about 30 nm. The light components, low TOC and high porosity are the main factors contributing to the high proportion of movable oil. Each type of pore can contain residual shale oil, but not all pores have shale oil. Pore connectivity and surface wettability are the determinants of shale oil enrichment degree and enrichment state. Key words: shale oil, absorbed oil, free oil, occurrence mechanism, Paleogene Shahejie Formation, Jiyang Depression, Bohai Bay Basin

The southeastern Sichuan Basin and its basin-margin transition zone (hereinafter referred to as “the basin-margin transition zone of SE Chongqing”) is the focus of normal-pressure shale gas exploration in China. In order to summarize the geological characteristics and enrichment laws of shale gas in the basin-margin transition zone of SE Chongqing, we analyzed the geological characteristics of shale gas reservoirs in the Nanchuan–Wulong area of this transition zone from the aspects of sedimentary formation, tectonic reworking and production characteristics by using geophysical, drilling, logging and testing data, and then we compared it with the overpressure shale gas reservoirs in the Jiaoshiba Block. Finally, we explored the main factors controlling the enrichment & high yields of normal-pressure shale gas in this transition zone and their hydrocarbon accumulation patterns. And the following research results were obtained. (1) Different from the over-pressure shale gas reservoirs in Jiaoshiba Block, the normal-pressure shale gas reservoirs in this transition zone are characterized by lower organic porosities, more developed micro-fractures, higher ratios of adsorbed gas, greater differences of stresses in two directions, lower geothermal gradients, lower formation pressure coefficients, higher initial fluid production rates and higher fluid flowback rates. (2) The enrichment & high yields of normal-pressure shale gas in this area is mainly controlled by three factors, i.e., carbon-rich, silicate-rich and graptolite-rich shale, organic pores, and tectonic stress field, among which, the first factor controlled by deepwater continental shelf facies is the basis of shale gas enrichment, the second is the main controlling factor of shale gas enrichment, and the third is the key factor of high-yield shale gas. (3) The hydrocarbon accumulation patterns of normal-pressure shale gas reservoirs in the transition zone can be divided into four types, including the anticline type, the syncline type, the slope type and the reverse fault type. And the enrichment & high-yield characteristics of shale gas in different hydrocarbon accumulation patterns are also clarified. In conclusion, the research results enrich the geological theory of enrichment & high-yield laws of normal-pressure shale gas and provide a support for the exploration and development of normal-pressure shale gas in complex structures. Keywords: SE Sichuan basin, Transition zone at the basin margin, Late ordovician–early silurian, Normal-pressure shale gas, Main factors controlling high yield, Tectonic stress field, Gas accumulation

The spatial-temporal relationship between high-quality source rocks and reservoirs is a key factor when evaluating the formation, occurrence, and prospectivity of tight oil and gas reservoirs. In this study, we analyze the fundamental oil and gas accumulation processes occurring in the Songliao Basin, contrasting tight oil sand reservoirs in the south with tight gas sand reservoirs in the north. This is done using geochemical data, constant-rate and conventional mercury injection experiments, and fluid inclusion analyses. Our results demonstrate that as far as fluid mobility is concerned, the expulsion center coincides with the overpressure zone, and its boundary limits the occurrence of tight oil and gas accumulations. In addition, the lower permeability limit of high-quality reservoirs, controlled by pore-throat structures, is 0.1 × 10−3 μm2 in the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, and 0.05 × 10−3 μm2 in the Lower Cretaceous Shahezi Formation (K1sh) in the northern Songliao Basin. Furthermore, the results indicate that the formation of tight oil and gas reservoirs requires the densification of reservoirs prior to the main phase of hydrocarbon expulsion from the source rocks. Reservoir “sweet spots” develop at the intersection of high-quality source rocks (with high pore pressure) and reservoirs (with high permeability). Keywords: Spatial-temporal coupling, High-quality source rock, High-quality sandstone, Tight sandstone reservoir, Songliao Basin

The mechanical properties such as Young's modulus, hardness and fracture toughness of Lower Silurian Longmaxi shale samples from Youyang area in southeast Chongqing, China were investigated using dot matrix nanoindentation measurements. With the help of field emission scanning electron microscope (FESEM) and energy dispersive X-ray fluorescence spectroscopy (EDS), the indentation morphology and mineral composition in indentation area were quantitatively analyzed. According to mechanical strength classification, a micromechanical model with three components was introduced and the Mori-Tanaka model was used to upscale mechanical parameters from nano-scale to centimeter-size scale, which were further compared with uniaxial compression results. The experimental results show that there is a positive linear correlation between Young's modulus and hardness and between the Young's modulus and the fracture toughness under nano-scale; the Young's modulus, hardness and fracture toughness perpendicular to the bedding are slightly lower than those parallel with the bedding. According to data statistics, the mechanical properties at the nano-scale follow Weibull distribution feature and the dispersion degree of hardness results is the highest, which is mainly due to shale anisotropy and nanoindentation projection uncertainty. Comparing the results from nanoindentation test, with those from upscaling model and uniaxial compression test shows that the mechanical parameters at the nano-scale are higher than those from upscaling model and uniaxial compression test, which proves mechanical parameters at different scales have differences. It's because the larger the core, the more pores and internal weakness it contains, the less accurate the interpreted results of mechanical parameters will be. Key words: nanoindentation, rock mechanics, Longmaxi Formation shale, Weibull distribution, Mori-Tanaka model

Seabed methane seepage has gained attention from all over the world in recent years as an important source of greenhouse gas emission, and gas hydrates are also regarded as a key factor affecting climate change or even global warming due to their shallow burial and poor stability. However, the relationship between seabed methane seepage and gas hydrate systems is not clear although they often coexist in continental margins. It is of significance to clarify their relationship and better understand the contribution of gas hydrate systems or the deeper hydrocarbon reservoirs for methane flux leaking to the seawater or even the atmosphere by natural seepages at the seabed. In this paper, a geophysical examination of the global seabed methane seepage events has been conducted, and nearby gas hydrate stability zone and relevant fluid migration pathways have been interpreted or modelled using seismic data, multibeam data, or underwater photos. Results show that seabed methane seepage sites are often manifested as methane flares, pockmarks, deep-water corals, authigenic carbonates, and gas hydrate pingoes at the seabed, most of which are closely related to vertical fluid migration structures like faults, gas chimneys, mud volcanoes, and unconformity surfaces or are located in the landward limit of gas hydrate stability zone (LLGHSZ) where hydrate dissociation may have released a great volume of methane. Based on a comprehensive analysis of these features, three major types of seabed methane seepage are classified according to their spatial relationship with the location of LLGHSZ, deeper than the LLGHSZ (A), around the LLGHSZ (B), and shallower than LLGHSZ (C). These three seabed methane seepage types can be further divided into five subtypes considering whether the gas source of seabed methane seepage is from the gas hydrate systems or not. We propose subtype B2 represents the most important seabed methane seepage type due to the high density of seepage sites and large volume of released methane from massive focused vigorous methane seepage sites around the LLGHSZ. Based on the classification result of this research, more measures should be taken for subtype B2 seabed methane seepage to predict or even prevent ocean warming or climate change.

To better understand the pore structure and fractal character of lacustrine shales and their influence on liquid hydrocarbon occurrences, in this study, a total of 29 lacustrine oil-bearing shale samples collected from the Shahejie Formation in the Dongying Sag, Bohai Bay Basin, were investigated based on nitrogen adsorption (NGA) analysis combined with TOC, Rock-Eval pyrolysis, X-ray diffraction (XRD), and field emission-scanning electron microscopy (FE-SEM) experiments. The relationships among the compositions (TOC, minerals, and oil content), pore structures, and fractal dimensions of the lacustrine shale samples were discussed. The results showed that the adsorption and fractal characteristics of lacustrine oil-bearing shales differ at relative pressures of 0-0.1 and 0.5-1. Two corresponding fractal dimensions D1 and D2 were determined by the FHH model according to the nitrogen adsorption branches. Specifically, D1 varies from 2.4292 to 2.6109 (mean 2.5245), and D2 varies between 2.4680 and 2.8535 (mean 2.6889). The specific surface area (SSA) ranges from 1.512 m2/g to 34.002 m2/g, with an average of 13.656 m2/g, the total pore volume is between 6.0 × 10-3 cm3/g and 48.4 × 10-3 cm3/g (mean 24.5 × 10-3 cm3/g), and the average pore diameter is in the range of 4.22 nm to 19.57 nm (mean 9.35 nm). Both D1 and D2 increase with increasing SSA and increase with decreasing average pore diameters but have no correlation with pore volume. Moreover, D1 and D2 exhibit positive relationships with clay minerals and negative correlations with carbonate minerals (calcite and dolomite). The relationship between fractal dimensions (D1 and D2) and TOC contents is expressed as a U-shaped curve, characterized by the minimum D values at approximately 3% TOC. The shale oil content is controlled by the pore structures and fractal dimensions, and lacustrine shales with lower SSAs and smaller fractal dimensions would have more free oil. Therefore, lacustrine shales in the oil window with TOC contents ranging from 2% to 4% are probably the preferred shale oil exploration target in the Shahejie Formation, Dongying Sag, Bohai Bay Basin. The results indicate that fractal analysis can provide insight into the pore structure characteristics and oil storage capacity of lacustrine shales.

Pore structure and its heterogeneity are critical factors controlling the storage capacity and transportation properties of hydrocarbons. Broad ion-beam-milling scanning-electron microscopy allows for the study of a larger planar at high resolution than other methods and can provide insight into shale microstructures. In this study, we investigate the microscopic pore structure of a shale oil reservoir sample from Paleogene Shahejie Formation in Dongying Sag, Bohai Bay Basin, based on the broad ion-beam cross-section, and discuss the heterogeneity of the major pores using multifractal theory. The representative elementary area of the sample was first inferred to be ∼100 × 100 µm 2 (25 single images) for the broad ion-beam cross-section with an area of 1.054 × 0.915 mm 2 . Five pore types (interparticle, intraparticle clay, dissolution, inter-crystalline, and organic) were subsequently identified and analyzed in the selected typical representative elementary area. The results showed that interparticle, intraparticle clay, and dissolution pores were the major pore types and made a significant contribution to the total visible surface porosity (98.34%), whereas inter-crystalline and organic pores were not of great importance. Interparticle pores exhibited the most complex pore morphologies, the largest average pore diameter, and the simplest pore structure. Moreover, interparticle pores that were sub-parallel to the bedding plane showed the best connectivity. Intraparticle clay pores, on the other hand, had the smallest average pore diameter, the most complex pore structure, and their distribution in a two-dimensional plane was the most homogeneous. Dissolution pores were characterized by the least complex pore morphologies but more heterogeneous pore distribution. Both intraparticle clay and dissolution pores were abundant but possessed poor connectivity. We conclude that for shale oil storage and transportation in the Dongying Sag, interparticle pores play an important role in shale oil seepage, whereas intraparticle clay and dissolution pores provide the main space for the occurrence of shale oil.

Abstract: On the basis of the characterization of microscopic pore-throats in shale oil reservoirs by high-pressure mercury intrusion technique, a grading evaluation standard of shale oil reservoirs and a lower limit for reservoir formation were established. Simultaneously, a new method for the classification of shale oil flow units based on logging data was established. A new classification scheme for shale oil reservoirs was proposed according to the inflection points and fractal features of mercury injection curves: microscopic pore-throats (less than 25 nm), small pore-throats (25−100 nm), medium pore-throats (100−1 000 nm) and big pore-throats (greater than 1 000 nm). Correspondingly, the shale reservoirs are divided into four classes, I, II, III and IV according to the number of microscopic pores they contain, and the average pore-throat radii corresponding to the dividing points are 150 nm, 70 nm and 10 nm respectively. By using the correlation between permeability and pore-throat radius, the permeability thresholds for the reservoir classification are determined at 1.00× 10−3 μm2, 0.40×10−3 μm2 and 0.05×10−3 μm2 respectively. By using the exponential relationship between porosity and permeability of the same hydrodynamic flow unit, a new method was set up to evaluate the reservoir flow belt index and to identify shale oil flow units with logging data. The application in the Dongying sag shows that the standard proposed is suitable for grading evaluation of shale oil reservoirs. Key words: shale oil, microscopic pore-throat, high pressure mercury injection, lower limit of reservoir formation, grading evaluation, Bohai Bay Basin, Dongying sag

With the development of imaging technology, tools to quantitatively describe pore structure, morphology, and connectivity have been widely applied on low permeable rocks; however, it is still questionable to what extent this information can be used to predict permeability. Applicability and comparability of different techniques are discussed here for the Middle Ordovician Cobourg limestone (Canada), a rock dominated by calcite grains of variable sizes (µm–cm) and heterogeneously distributed quartz, dolomite, pyrite, and meshy clay minerals. Absolute porosities determined by helium pycnometry (HP) in literature are approximately 1.6% (±0.9%), and gas permeabilities range from 10−20 to 10−19 m2. Porosities obtained from BIB-SEM are much smaller compared to those from HP (16–69% of HP). Pores found in clays are smaller, slit-shaped, and more densely spaced when compared to those in calcite minerals. Connectivity between pores could not be resolved with 3D micro-CT or FIB-SEM reconstructions, which have a resolution limit of 8 µm and 10 nm, respectively. However, assuming the pores to be connected, laboratory-derived permeability data could be fitted using a simple capillary bundle model, including information about the visible pore size distributions obtained from BIB-SEM images and a tortuosity range of 8 to 15.

Taking the southern Songliao Basin as the target area, the hydrocarbon expulsion volume from source rocks has been quantitatively evaluated in this paper, based on the material balance method. Employing the “Overpressure” module of PetroMod software, the overpressure history of the source rocks was evaluated. According to the relationships between hydrocarbon expulsion rate, residual organic carbon content and overpressure within the source rocks, the lower limits of expulsion from tight oil source rocks were determined: a hydrocarbon expulsion amount of 2 mg/g, residual hydrocarbon content of 0.8%, and overpressure of 1 MPa. The source rocks with hydrocarbon expulsion amounts > 8 mg/g, a residual organic carbon content > 2.0%, and overpressure > 7 MPa were defined as excellent source rocks. As a result, tight oil source rocks can be divided into three types, excellent source rocks (type I), inefficient source rocks (type II) and non-productive source rocks (type III). The actual application in the southern Songliao Basin shows that the excellent source rocks have an obvious control on the planar and vertical distribution of tight oil discoveries, areas with excellent source rocks and nearby formations are favorable for the accumulation of tight oil. Key words: tight oil, source rocks, grading evaluation, hydrocarbon expulsion, overpressure, southern Songliao Basin

Abstract In this work, we investigate the dynamics mechanism of oil transportation in nanochannel using molecular dynamics simulations. It is demonstrated that the interaction between oil molecules and nanochannel has a great effect on the transportation properties of oil in nanochannel. Because of different interactions between oil molecules and channel, the center of mass (COM) displacement of oil in a 6-nm channel is over 30 times larger than that in a 2-nm channel, and the diffusion coefficient of oil molecules at the center of a 6-nm channel is almost two times more than that near the channel surface. Besides, it is found that polarity of oil molecules has the effect on impeding oil transportation, because the electrostatic interaction between polar oil molecules and channel is far larger than that between nonpolar oil molecules and channel. In addition, channel component is found to play an important role in oil transportation in nanochannel, for example, the COM displacement of oil in gold channel is very few due to great interaction between oil and gold substrate. It is also found that nano-sized roughness of channel surface greatly influences the speed and flow pattern of oil. Our findings would contribute to revealing the mechanism of oil transportation in nanochannels and therefore are very important for design of oil extraction in nanochannels.

Rate-controlled porosimetry (RCP), nuclear magnetic resonance (NMR) and micro CT tests were conducted on five tight sandstone samples, the results were compared to reveal the limitations of RCP in determining the pore size distribution (PSD) and pore to throat ratio (PTR), and then an effective method to test the pore-throat structure of tight sandstone by combining NMR and RCP was proposed. The quasi-PSD derived by RCP was bimodal, the left peak of which corresponding to throats was in good agreement with that of NMR, while the right peak corresponding to pore bodies had similar volume content and different distribution range with that of NMR. RCP reflected an equivalent spherical radius of pore body, and the calculation was significantly larger than the maximum inscribed radius (MIR) of the actual pore body with the same volume; whereas in NMR, the ratio of pore volume to surface area was used to estimate pore radius, and the pore radius calculated was close to MIR. The full-range pore body size distribution was determined by subtracting the RCP-derived throat size distribution from NMR-derived PSD, and then the pore throat connectivity was evaluated comprehensively. The mean value of PTR calculated by RCP was larger than 100.0 due to the differences in the calculation method between pore body size and throat size in RCP, while the mean value of PTR calculated by combining NMR and RCP ranged from 7.5 to 64.0. It is concluded that the combination of RCP and NMR experiment is an effective way to comprehensively reveal the size distribution of pore body and throat in tight sandstone. Key words: tight sandstone, pore throat structure, pore to throat ratio, pore size distribution, rate-controlled porosimetry, nuclear magnetic resonance

Molecular dynamics simulation was used to study the occurrence state of liquid alkane in pores and slits of shale organic matter. On the basis of OPLS (Optimized Potentials for Liquid Simulation) force field, the alkane densities under different pressures and temperatures were calculated; the comparison with experimental results validated the effectiveness of this approach. With n-heptane as an example, the basic occurrence behaviors of alkanes in the pores and slits of organic matter were analyzed under formation conditions, and the effects of slit aperture, thermal maturity of organic matter, carbon chain length and isomers were also discussed. Results show that: (1) The density distribution of the alkanes across the pores and slits is not uniform, but presents a periodic fluctuation; (2) A “solid-like” alkane layer will form in the vicinity of the solid surface, and its density approximates to 1.9−2.7 times as large as that of the bulk-fluid; (3) Multiple adsorption layers are always shown for liquid alkanes and the thickness of each layer is 0.48 nm; the total number of adsorbed layers is influenced by the slit aperture and fluid composition. Finally, using this approach, the proportion of adsorbed-phase (18.2%) is determined for oil in an organic matter slit. Key words: shale oil, organic matter, liquid hydrocarbon, occurrence state, alkane density, adsorption layer

As significant components of tight gas reservoirs, clay minerals with ultrafine dimensions play a crucial role in controlling pore structures and permeability. XRD (X-ray diffraction), SEM (scanning electron microscopy), N2GA (nitrogen gas adsorption), and RMIP (rate-controlled mercury injection porosimetry) experiments were executed to uncover the effects of clay minerals on pore structures and the permeability of tight gas reservoirs, taking tight rock samples collected from the Lower Cretaceous Dengloukou and Shahezi Formations in the Xujiaweizi Rift of the northern Songliao Basin as an example. The results show that the pore space of tight gas reservoirs primarily comprises intragranular-dominant pore networks and intergranular-dominant pore networks according to fractal theory and mercury intrusion features. The former is interpreted as a conventional pore-throat structure where large pores are connected by wide throats, mainly consisting of intergranular pores and dissolution pores, and the latter corresponds to a tree-like pore structure in which the narrower throats are connected to the upper-level wider throats like tree branches, primarily constituting intercrystalline pores within clay minerals. Intragranular-dominant pore networks contribute more to total pore space, with a proportion of 57.79%–90.56%, averaging 72.55%. However, intergranular-dominant pores make more contribution to permeability of tight gas reservoirs, with a percentage of 62.73%–93.40%. The intragranular-dominant pore networks gradually evolve from intergranular-dominant pore networks as rising clay mineral content, especially authigenic chlorite, and this process has limited effect on the total pore space but can evidently lower permeability. The specific surface area (SSA) of tight gas reservoirs is primarily derived from clay minerals, in the order of I/S (mixed-layer illite/smectite) > chlorite > illite > framework minerals. The impact of clay minerals on pore structures of tight gas reservoirs is correlated to their types, owing to different dispersed models and morphologies, and chlorite has more strict control on the reduction of throat radius of tight rocks.

The Lower Silurian Longmaxi Shale in Southeast Chongqing of Sichuan Basin in China is considered to be a potential shale gas reservoir by many scholars in recent years. The special shale gas well, namely, Pengye-1 well, was selected as a case study to evaluate the characteristics of the shale gas reservoir. A series of experiments were performed to analyze the geochemical, mineralogical, and petrophysical features and gas content using samples of the Longmaxi Shale from Pengye-1 well. The results show that the organic and inorganic porosities of these samples are range of 0.08-2.73% and 0.06-2.65%, with the average of 1.10% and 1.76%, respectively. The inorganic pores primarily contribute to the porosity until the TOC content is more than 3%. Organic matter plays an important role in adsorbed gas content. The adsorbed gas is dominant in the Longmaxi Shale of Pengye-1 well, which ranges from 0.46 to 2.24 cm3/g, with an average of 1.38 cm3/g. The free gas content ranges from 0.45 to 0.84 cm3/g with an average of 0.68 cm3/g, and is 24.4-49.7 percent of total gas with an average of 37.5%. The bottom part of the Longmaxi Shale is the most favorable for shale gas exploring, which is higher of brittleness mineral content, porosity and gas content. Compare with the other five shales in America, the Lower Silurian Longmaxi Shale is derived from older sedimentary periods with significantly higher thermal maturity and has experienced several periods of intense tectonic, which are unfavorable for the shale gas enrichment.

A grading system from a pore structure perspective for assessing the quality of tight gas reservoirs in China is proposed based on an analysis of wettability, adsorption and pore throat size distribution and experiments including X-ray diffraction, contact angle measurement and static nitrogen adsorption, upon tight sand samples, from wells in Turpan-Hami Basin, western China. The hydrophilicity of tight sand has nothing to do with the overall clay content; instead, it is linked to the content of illite. Higher illite content means stronger hydrophilicity of the rocks. Indonesia's formula is proven to be more suitable for the interpretation of gas saturation measurement in tight reservoirs with higher content of illite. The microscopic pore structure of tight reservoir is clearly related to the porosity. The tight sandstone reservoir with low porosity is characterized by high proportion of small pores and high drainage pressure, while the tight sandstone reservoir with high porosity is characterized by high proportion of large pores, low drainage pressure and large average pore size. In view of endowment and flowing of tight sand gas, a new reservoir potential assessment parameter is established by porosity, permeability and gas saturation. The parameter relates to the porosity in a clear manner of trichotomy. Given the porosity of 6% and 4% as threshold, the tight sand gas can be divided into three types: I (Good), II (Potential) and III (Challenging). The trichotomy corresponds to a consistent porosity limit with the pore size change. Key words: tight sand gas, reservoir microscopic pore structure, specific surface area, pore size distribution, reservoir potential assessment parameter, resource grading, Turpan-Hami Basin

X-ray computed tomography is an efficient method for quantitatively estimating the characteristics and heterogeneity of shales in three dimensions. A threshold is commonly used to separate pore-fractures from the background image. However, few studies have focused on the multi-component segmentation of computed tomography images. To obtain the distribution characteristics of different components in three dimensions, a segmentation method was proposed that combines a multi-Otsu thresholding algorithm with scanning electron microscopy. The gray value distributions of different components were first determined using this method. Then, the shale components were divided into several groups based on these gray values. The threshold of each component group was determined using the multi-Otsu thresholding algorithm. The computed tomography image stacks of two shale samples were processed using this segmentation method, and another computed tomography image stack was used to verify the method. The results showed that (1) the multi-component segmentation method can successfully segment computed tomography image stacks using the calculated values determined by computed tomography, which agree well with the measured values obtained from X-ray diffraction, total organic carbon, and porosity tests in the laboratory; (2) samples with similar provenances and mineral compositions have the same gray value distribution in the back scattering scanning electron microscopy and computed tomography images; (3) this method is superior in both the effectiveness and efficiency of the computed tomography image stack segmentation of samples according to the gray value distribution, as determined by samples with similar provenances and mineral compositions.

In this study, data obtained from the Lower Cretaceous McMurray Formation in the central Athabasca Oil Sands, northeastern Alberta, Canada, are examined and used to establish the architecture of stacked fluvial and estuarine tidal bar deposits. A total of 13 distinguishable facies (F1−F7, F8a−F8b, and F9−F13) corresponding to stacked fluvial and estuarine deposits are recognized. These facies are then reassembled into four facies associations: fluvial deposits, tidal flat, tidal bar complex, and tidal bar cap. Of these, the lower fluvial deposits show a highly eroded channel lag and tidal influences in the cross-stratified sand and wavy interbeds. The fluvial deposits pass upwards into upper tidal-dominated tidal flats and a massive homogeneous tidal sand bar complex. Very thick tidal-influenced facies (F8a−F8b, up to 22 m) caused by semi-diurnal and semi-lunar cycles are also observed in tidal flats. Based on studies of the facies and facies associations, a three-dimensional (3-D) architecture model is finally established and used to analyze the internal distribution of the stacked fluvial and estuarine deposits. This is the first time that a 3-D model of the paleo-estuary tidal bar has been constructed. The results of this study will assist future research analyzing the architecture of stacked fluvial and estuarine deposits.

Measuring total porosity in shale gas reservoir samples remains a challenge because of the fine-grained texture, low porosity, ultra-low permeability, and high content of organic matter (OM) and clay mineral. The composition content porosimetry method, which is a new method for the evaluation of the porosity of shale samples, was used in this study to measure the total porosity of shale gas reservoir samples from the Lower Silurian Longmaxi Formation in Southeast Chongqing, China, based on the bulk and grain density values. The results from the composition content porosimetry method were compared with those of the Gas Research Institute method. The results showed that the composition content porosimetry porosity values of shale gas reservoir samples range between 2.05% and 5.87% with an average value of 4.04%. The composition content porosimetry porosity generally increases with increasing OM and clay content, and decreases with increasing quartz and feldspar content. The composition content porosimetry results are similar to the gas research institute results, and the differences between the two methods range from 0.05% to 1.52% with an average value of 0.85%.

Research on the evaluation criteria of shale oil and gas is conducted to accurately assess the resource potential of shale oil and gas. Statistic analysis of the geochemical index of hydrocarbon source rocks in five areas such as Songliao, Hailaer, Jiyang, based on the characteristic of triple-division between the oil content and TOC of source rock, suggests that shale oil and gas can be categorized into three levels of resource enrichment: scattered (ineffective) resources, low efficient resources and enriched resources. The mature stage, at which organic matter generates oil and gas in large amounts, corresponds to the shale oil and gas enrichment window. Furthermore, recoverable index is defined and its computation formula is proposed to provide a quantitative index for recoverability evaluation, considering the brittle mineral content, thickness and depth of shale, etc. In practice, TOC variable values in well profile obtained by TOC-logging correspondence can be used to draw TOC isopach maps and calculate the amount of resources at different levels. Then combined with the evaluation criteria, TOC and Ro isopach maps are superimposed to identify the favorable shale oil and gasareas. Key words: shale oil, shale gas, resource evaluation, resource classification, scattered resources, low efficient resources, enriched resources

In shale, liquid hydrocarbons are accumulated mainly in nanometer-scale pores or fractures, so the pore types and PSDs (pore size distributions) play a major role in the shale oil occurrence (free or absorbed state), amount of oil, and flow features. The pore types and PSDs of marine shale have been well studied; however, research on lacustrine shale is rare, especially for shale in the oil generation window, although lacustrine shale is deposited widely around the world. To investigate the relationship between nanometer-scale pores and oil occurrence in the lacustrine shale, 10 lacustrine shale core samples from Songliao Basin, NE China were analyzed. Analyses of these samples included geochemical measurements, SEM (scanning electron microscope) observations, low pressure CO2 and N2 adsorption, and high-pressure mercury injection experiments. Analysis results indicate that: (1) Pore types in the lacustrine shale include inter-matrix pores, intergranular pores, organic matter pores, and dissolution pores, and these pores are dominated by mesopores and micropores; (2) There is no apparent correlation between pore volumes and clay content, however, a weak negative correlation is present between total pore volume and carbonate content; (3) Pores in lacustrine shale are well developed when the organic matter maturity (Ro) is >1.0% and the pore volume is positively correlated with the TOC (total organic carbon) content. The statistical results suggest that oil in lacustrine shale mainly occurs in pores with diameters larger than 40 nm. However, more research is needed to determine whether this minimum pore diameter for oil occurrence in lacustrine shale is widely applicable.

Adsorption of hydrocarbons may significantly affect hydrocarbon migration in unconventional reservoirs. Clay minerals form the primary adsorbent surfaces for hydrocarbons adsorbed in mudstone/shale. To study the adsorption properties of hydrocarbons (n-decane (C10H22), methyl cyclohexane (C7H14) and toluene (C7H8)) on clay minerals (i.e., cookeite, ripidolite, kaolinite, illite, illite/smectite mixed-layer, Na-montmorillonite and Ca-montmorillonite), hydrocarbon vapor adsorption (HVA) tests were conducted at 298.15 K. The results showed that (i) the adsorption amounts of C10H22, C7H14 and C7H8 ranged from 0.45–1.03 mg/m2, 0.28–0.90 mg/m2 and 0.16–0.53 mg/m2, respectively; (ii) for cookeite, ripidolite and kaolinite, the adsorption capacity of C10H22 was less than C7H14, which was less than C7H8; (iii) for illite, Na-montmorillonite and Ca-montmorillonite, the adsorption capacity of C10H22 was greater than that of C7H8, and the adsorption capacity of C7H14 was the lowest; (iv) for an illite/smectite mixed-layer, C7H14 had the highest adsorption capacity, followed by C10H22, and C7H8 had the lowest capacity. Adsorption properties were correlated with the microscopic parameters of pores in clay minerals and with experimental pressure. Finally, the weighted average method was applied to evaluate the adsorption properties of C10H22, C7H14 and C7H8 on clay minerals in oil-bearing shale from the Shahejie Formation of Dongying Sag in the Bohai Bay Basin, China. For these samples, the adsorbed amounts of C7H14 ranged from 18.03–28.02 mg/g (mean 23.33 mg/g), which is larger than that of C10H22, which ranges from 15.40–21.72 mg/g (mean 18.82 mg/g). The adsorption capacity of C7H8 was slightly low, ranging from 10.51–14.60 mg/g (mean 12.78 mg/g).

A modified model for predicting the friction force between drill-string and borehole wall under in-plane vibrations was developed. It was found that the frictional coefficient in sliding direction decreased significantly after applying in-plane vibration on the bottom specimen. The friction reduction is due to the direction change of friction force, elastic deformation of surface asperities and the change of frictional coefficient. Normal load, surface topography, vibration direction, velocity ratio and interfacial shear factor are the main influence factors of friction force in sliding direction. Lower driving force can be realized for a pair of determinate rubbing surfaces under constant normal load by setting the driving direction along the minimum arithmetic average attack angle direction, and applying intense longitudinal vibration on the rubbing pair. The modified model can significantly improve the accuracy in predicting frictional coefficient under vibrating conditions, especially under the condition of lower velocity ratio. The results provide a theoretical gist for friction reduction technology by vibrating drill-string, and provide a reference for determination of frictional coefficient during petroleum drilling process, which has great significance for realizing digitized and intelligent drilling.

The main factors of the developmental environment of marine source rocks in continental margin basins have their specificality. This realization, in return, has led to the recognition that the developmental environment and pattern of marine source rocks, especially for the source rocks in continental margin basins, are still controversial or poorly understood. Through the analysis of the trace elements and maceral data, the developmental environment of Miocene marine source rocks in the Qiongdongnan Basin is reconstructed, and the developmental patterns of the Miocene marine source rocks are established. This paper attempts to reveal the hydrocarbon potential of the Miocene marine source rocks in different environment and speculate the quality of source rocks in bathyal region of the continental slope without exploratory well. Our results highlight the palaeoenvironment and its control on the formation of Miocene marine source rocks in the Qiongdongnan Basin of the northern South China Sea and speculate the hydrocarbon potential of the source rocks in the bathyal region. This study provides a window for better understanding the main factors influencing the marine source rocks in the continental margin basins, including productivity, preservation conditions, and the input of terrestrial organic matter.

The organopores play an important role in determining total volume of hydrocarbons in shale gas reservoir. The Lower Silurian Longmaxi Shale in southeast Chongqing was selected as a case to confirm the contribution of organopores (microscale and nanoscale pores within organic matters in shale) formed by hydrocarbon generation to total volume of hydrocarbons in shale gas reservoir. Using the material balance principle combined with chemical kinetics methods, an evaluation model of organoporosity for shale gas reservoirs was established. The results indicate that there are four important model parameters to consider when evaluating organoporosity in shale: the original organic carbon (w(TOC0)), the original hydrogen index (IH0), the transformation ratio of generated hydrocarbon (F(Ro)), and the organopore correction coefficient (C). The organoporosity of the Lower Silurian Longmaxi Shale in the Py1 well is from 0.20 to 2.76%, and the average value is 1.25%. The organoporosity variation trends and the residual organic carbon of Longmaxi Shale are consistent in section. The residual organic carbon is indicative of the relative levels of organoporosity, while the samples are in the same shale reservoirs with similar buried depths.