Shale oil refers to the oil resources in organic-rich shale, which occur in pores of matrix and micro-fractures in shale and thin interlayers of non-hydrocarbon source rocks, in the forms of free, mutual dissolution with kerogen, or adsorption^[1,2,3]. The United States took the lead in the commercial exploitation of shale oil based on advances in horizontal wells, hydraulic fracturing, and other engineering technologies, changing the global energy picture^[4,5,6,7]. Good resource potential is the foundation of the successful shale oil revolution in the United States: (1) The reservoirs are mainly distributed in marine cratons or foreland basins, with large depositional area, good strata continuity, and relatively stable lithology. (2) The TOC values are generally high (the average value is mostly 3%-5%) and the reservoirs usually have abnor-mally high pressure (the pressure coefficient is 1.3-1.5). (3) Thermal evolutions are moderate, with R_o value of 1.0%-1.7%, result in generation of a large number of hydrocarbons from organic rich shale. Shale oil is mainly preserved in interlayers of tight reservoirs between shale after migration of a short distance. The heavy hydrocarbon components in the crude oil are filtered during the migration, causing a high gas/oil ratio (100-500 m³/t) and good liquidity^{[1, 8-11]}.

Only a dozen of shale formations, such as in the Eagle Ford, Bakken, and Permian basins, have been industrially exploited among more than 80 sedimentary basins and nearly 1000 shale formations in the United States, although the United States has remarkable advantages of geological and engineering conditions in marine shale oil^[4]. It shows that investment in shale oil exploration and development is extremely uncertain^[12]. In this situation, the research direction of shale oil in the United States has gradually shifted from engineering technology to technology innovation of enhancing oil recovery since 2016. Especially, evaluation of economic exploitation value of reservoir based on fine evaluation in multi-scale and research of matching design of extraction technology have become focus^[13,14,15].

China's continental shale oil resources are relatively rich, thus are the most realistic substitute resources at present. Compared with the marine shale oil in the United States, the continental shale oil in China is on a relatively small scale and mainly distributed in more than 30 belts or depressions covering less than 100 km² in 10 basins, with tens of millions of tons of resources^[16]. How to evaluate the potential of development and industrial value of shale oil, design the development plan, and estimate the engineering cost is the key scientific problem in the development of shale oil with a scale of economies. The availability of oil and gas resources, different from the mobility of oil and gas resources, is an important proxy to evaluate the difficulty of oil and gas reservoirs to be economically and effectively exploited under current technical conditions. It has been widely used in the evaluation of various types of unconventional oil and gas reservoirs, such as tight oil, tight gas, and coal-bed methane^{[17,18,19,20,21]}. In this background, this paper introduces the concept of resource availability as an important reference index to evaluate the investment in shale oil business on the basis of briefly summarizing the status of development and challenges on China's continental shale oil. An integrated innovation of the evaluation method and process is proposed according to the characteristics of shale oil resources. In summary, this article provides a comprehensive and comparative study of the availability of the major continental shale oil reservoirs in China from the micro perspective and on the same platform.

China has two types of shale oil resources in medium-low and medium-high maturity. The latter is currently the main object of development and has certain similarities with American shale oil in terms of exploitation methods and key technologies. However, it is more difficult to develop with benefits^[1], which is mainly shown in the following aspects: (1) The main layers producing shale oil are generally distributed in continental depositions in depressions and rift basins, with limited distribution range and strong heterogeneity. (2) The TOC values of source rocks are mostly low (2%-3%) and the reservoir pressure coefficient is generally low (averaging 1.0-1.2). (3) The thermal maturity is overall low (R_o value is 0.75%-1.00%). A few liquid hydrocarbons are migrated in a short distance to thin interlayer with concentration diffusion, while a large amount of crude oil is retained in the pores of the shale matrix as the main body of resources^[22,23,24]. In addition, the oil is heavy, the gas-oil ratio is low (less than 100 m³/t for the main body), and the fluidity is poor, resulting in a great difficulty for development.

The development mode of horizontal well and volume fracturing in North America is widely applied in China's continental shale oil^{[25,26,27,28,29,30,31,32]}, but the difference in geological characteristics determines that the technology system is not universally applicable. The Jimsar Sag of Junggar Basin has been built as China's first national demonstration zone of shale oil, with 178 shale oil wells drilled, basically reaching the stage of large-scale construction and production. By the end of 2019, 117 wells with an annual output of 26.3×10⁴ t oil has been put into operation in submembers 1 and 2 in the 7^th member of Yanchang Formation of Triassic in Ordos Basin, demonstrating a good and stable production result. However, no breakthrough has been made in the pure shale of submembers 3 of 7^th member of Yanchang Formation in the center of the lake basin. In addition, 13 of the 29 testing wells have currently obtained industrial oil flow with unstable production. The Dagang Oilfield has drilled 38 wells and fractured 17 wells in the 2^nd member of Kongdian Formation of Paleogene in Bohai Bay Basin, producing 2.9×10⁴ t of oil in total. A transformation from exploration breakthrough to large-scale development has been primarily made. Jilin Oilfield has drilled 18 exploratory wells in the Qingshankou Formation of Cretaceous in Songliao Basin from 2018 to 2019, with only 10 of them obtained industrial oil flow. The development of shale oil with benefit is of great difficulty.

It can be seen that remarkable differences exist in the development effects of shale oil resources between different basins and even between different strata in the same basin in China^{[16, 33-34]}. It indicates that the difficulties of limited understanding of complex geological conditions, resource availability, and mismatched exploitation technologies have seriously impeded the development of shale oil resources with benefit. It is difficult to obtain accurate evaluation and systematic understanding of the differences in availability of shale oil in multiple basins, due to different experimental conditions and evaluation methods adopted in different basins in previous researches.

The geological resources in Junggar, Ordos, Bohai Bay, and Songliao are 25.1×10⁸ t, 60.5×10⁸ t, 27.4×10⁸ t, and 54.6×10⁸ t, respectively, accounting for about 60% of the total oil resources^[16]. These basins are the key areas for shale oil exploration and development in China. As a result, we select the key area in development at present as a research object, including Lucaogou Formation (P₂l) of Permian in Jimsar Sag in Junggar Basin, submember 3 of the 7^th member of Yanchang Formation (T₃y) in Longdong area in Ordos Basin, the 2^nd member of Kongdian Formation (E₂k) of Paleogene in Cangdong Sag in Bohai Bay Basin, and the 1^st member of Qingshankou Formation (K₂qn) of Cretaceous in Changling Sag in Songliao basin. A total of 483 core samples were analyzed 1385 times in order to conduct a comparative study of evaluation methods and applications of the availability of different shale oil resources under the same technical system of evaluation and the same experimental conditions (Table 1).

In particular, it is pointed out that the seepage conditions of shale oil and fluidity of crude oil in the thin and tight interlayers are relatively good and these shale oils are the main object of development in China at present. However, the proportion of high-quality reserves declines as exploration and development gradually step into a large scale. As a result, a great number of retained crude oil in the pores of the shale matrix, as the main resource, is bound to gradually become the main battlefield. The research on resource availability in this paper focuses on organic-rich shale.

Shale oil reservoirs are characterized by strong heterogeneity, small pores and throat structures, complex pore space distribution, complicated organic matter structure, intricate fluid phase, and unclear oil-gas possibility. Thus, many traditional analytical methods are not applicable. The availability of shale oil is generally controlled by the main factors, such as availability of reservoir space, saturation of reservoir oil, mobility of crude oil, and plasticity of the reservoir^{[17,18,19,20,21]}. Characteristics of the reservoir are not well expressed based on the unilateral evaluation of reservoir.

Reservoir availability is the ability of a reservoir to provide oil storage space and transport channels, which is dependent on the main factors such as development of pore-fracture and effective porosity and connectivity. Crude oil movability is the ability of crude oil to flow effectively in the pore-throat systems of reservoir, which is mainly controlled by the driving force of temperature and pressure of strata, physical property of crude oil, distribution of crude oil in effective pores, and other controlling factors. Plasticity of reservoir represents the degree of difficulty for oil shale to be effectively fractured, which is mainly influenced by crustal stress, mineral composition, distribution of weak surfaces, and other factors.

Digital rock technology was originated in the 1990s. It uses characterizing methods of multiple scales to obtain digital information, such as the internal structure of rocks, and to conduct numerical simulation research on reconstruction of digital core through various algorithms, in order to achieve digital characterization of reservoir^{[35,36,37,38,39,40]}. In terms of effectiveness of shale oil reservoir, saturation and mobility of crude oil, and plasticity of reservoir, this paper proposes an available evaluation process and technical systems of shale oil through integrated innovation of evaluation methods. These methods include analysis of the configuration of pores and fractures using field emission scanning electron microscopy with high resolution and large scanning area, characterization of reservoir space distribution in three-dimension, computation of effective connectivity, analysis of mineral composition and quantitative distribution, recognition of charging effect of movable oil, digital simulation of rock fracture, and effective combination of multi-scale digital rock evaluation techniques.

Availability and connectivity of pores should be used as the main describing parameters for micro-nano scale pore space in shale, in regard to the effectiveness of reservoir evaluation. This paper uses double beams of field emission scanning electron microscopy with image panoramic mosaic technology (MAPS) to obtain a growth level of pores and fractures and distribution characteristics of pore size in reservoir of organic-rich shale. This study also uses a three-dimensional image of pore texture and software for computing effective connectivity to calculate the ratio of interconnected pore volume over the total pore volume in shale samples, in order to acquire parameters of pore connectivity, and finally calculate effective porosity of the core samples in different areas^[39].

The quantitative value of the movable hydrocarbon rather than the distribution of crude oil in the sample can be obtained through traditional geochemical analysis, such as pyrolysis and extraction of chloroform asphalt "A", in regard to the evaluation of saturation and mobility of shale oil. Pores in the shale matrix are mainly at a micro-nanometer scale, with pore types varying widely, resulting in differences in connectivity and availability of storage space in the same oil-bearing powder sample. This paper uses electronic beam charging effect to conduct a quantitative evaluation of the distribution of movable oil. The oil distribution area shows the charging effect through fine adjustment of imaging parameters. The movable oil has been proved as the main cause of the charging effect through a series of experiments, such as conductivity test, polar solvent extraction, and heating removal of movable oil. The method in this paper can be used directly to obtain the distribution of the movable oil and to quantitatively calculate saturation of the movable oil through further combining the traditional pyrolysis analysis.

In terms of evaluation on the plasticity of the reservoir, continental shale has strong heterogeneity, a large number of foliate laminae and other weak structural surfaces at the microscopic scale, and relatively complex mineral composition and distribution characteristics. Thus, the existing evaluation methods are not satisfactory due to insufficient analytical factors. This paper simulates the characteristics of initial breakage and expansion mechanism of fractures in shale cores and systematically evaluates plasticity of shale reservoir on the basis of a reconstruction of rock using digital images and quantitative identification of mineral composition, combining with finite element method.

The storage space in continental shale oil reservoirs shows strong heterogeneity at multiple scales. At a meter scale, organic-rich shale can be existed in siltstones, very fine sandstones, and carbonate rocks in a single layer with thickness less than 5 meters, as classified based on geological evaluation standard of shale oil. It indicates that the shale bed has transitions and alternations between mud-shale and other lithologies at the meter scale. Hydrodynamic conditions and variation of paleoenvironments, such as salinity, lead to the growth of foliate laminae in continental shale at the centimeter scale. Heterogeneity of reservoir space and organic matter distribution is caused by the effect of microorganisms, differences of mineral dissolution, and other factors, at the millimeter-micrometer scale. Variations of the contact relationship between organic matter and inorganic minerals, characteristics of pores and fractures, and crude oil adsorption are caused by the differences in organic matter type and maturity at the nanometer scale. Shale samples of the matrix-type from the four representative shale oil basins were selected in this paper to carry out the storage space evaluation at a centimeter-nanometer scale across 7 orders of magnitude.

The shale oil reservoir of Lucaogou Formation in Jimsar Sag of Junggar Basin has widely distributed micritic dolomite, very fine sandstone, and peperite, influenced by structure, climate, waterbody, sediment supply, and other factors^[25,26]. The storage space mainly includes primary pores and secondary pores. The primary pores mainly include intergranular pores and intracrystalline pores. The secondary pores mainly include enlarged intergranular dissolved pores, intergranular dissolved pores, intragranular dissolved pores, intracrystalline dissolved pores, and a few cracks. The sample has a relatively high TOC value and a large number of kerogen bands. The main pores in the sample include intergranular pores, intergranular pores of clay minerals, partially filled intergranular pores of organic matter, and pores in organic matter (Fig. 1). Organic pores are also an important reservoir space for shale oil. Organic pores are only developed in some organic matter bands, suggesting the diversity of hydrocarbon generating organisms and the heterogeneity of distribution of organic pores. Micritic dolomite is often found near organic-rich and argillaceous regions at cm-scale, with a large number of unfilled intergranular pores, providing a good reservoir space for short-distance migration of liquid hydrocarbon. In addition, a large number of secondary dissolved pores supply a major reservoir space for shale oil to accumulate on a large scale.

The shale oil reservoir of submember 3 of the 7^th member of Yanchang Formation in the Longdong area of Ordos Basin is mainly distributed in the depositional area of shale in the deep lake^[27,28]. Continuity of the reservoir is relatively good, and the lithology is mainly thin layers of fine sandstone, silty mudstone, and argillaceous silty sandstone^[27,28]. Typical characteristics of sedimentary bedding and microscopic pores in organic rich shale of submember 3 of the 7^th member of Yanchang Formation are shown in Fig. 2. Visible reservoir space under an electron microscope is not well developed. The main types of pores are intergranular pores, micro-fractures, intergranular pores of clay minerals, and etc., with a few internal pores in organic matter. However, this may be an important reservoir for shale oil, considering the high TOC value of the sample and absorption of crude oil in the connected organic matter bands as sheets and thus with no visible pores.

The sedimentary structure is relatively stable during the depositional period in the 2^nd member of Kongdian Formation in Cangdong Sag of Bohai Bay Basin, forming strata of fine grain deposits with a thickness of 400-600 m.

These deposits have a great potential for developing both high-quality hydrocarbon source rocks and effective reservoirs. The lithology of the high quality shale bed in the 2^nd member of Kongdian Formation is mainly quartzose and feldspathic shale, calcareous or dolomitic shale, carbonate rock and etc.^[29,30] Typical samples of organic-rich shale show pore types including intergranular pores, micro-fractures, organic pores, shrinking pores in organic matter, and etc. An abundance of organic matter is relatively high and nanopores in organic matter are well developed in some areas, forming multilevel storage systems (Fig. 3).

The strata of shale oil in the 1^st member of Qingshankou Formation in Changling Sag, Songliao Basin contain thick-ultra thick dark mudstone and thin interbedded sandstone, forming a typical source-reservoir-cap assemblage of "muddy enclosure of sand"^[31,32]. The organic shale, as a reservoir, has extremely low porosity and permeability. A large number of intergranular pores between clay minerals and microfractures are well developed in the typical shale oil samples. Organic matter is discretized and distributed at the millimeter scale and thus difficult to be concentrated. Organic pores are not developed under electronic microscopic observation. The reservoir space type is mainly microfractures in the matrix (Fig. 4).

Previous studies have shown that pore size plays an important role on the migration and accumulation of shale

oil^[41]. Shale oil is not able to leak out when the pore diameter is less than 20 nm, whereas external driving force is required to exude shale oil when the pore diameter is between 20-200 nm and shale oil can move freely from pore throats when the pore diameter is greater than 200 nm. Therefore, further statistical analysis of the pore diameter distribution of shale samples in the four regions has been done in this study (Table 2). The results show that the distribution of pore diameter mainly ranges in 20-200 nm. Specifically, shale in Lucaogou Formation has the highest proportion of pores with a diameter greater than 200 nm (30%), whereas shale in the 1^st Qingshankou Formation has a relatively high proportion of invalid pores with a diameter less than 20 nm.

This study analyzes the three-dimensional model of pore structure in shale in the four regions using digital rock technology of FIB-SEM (Fig. 5). Matlab script was used to test and analyze the connectivity of shale samples in the four regions. A pore-connected domain is classified into four types ranging from bad to good based on connectivity, including dead connected domain Cr, the 1^st level connected domain Cr₁, the 2^nd level connected domain Cr₂, and the 3^rd level connected domain Cr₃. The results show that the shale pore connectivity is very poor, with the total porosity of shale in the four regions less than 60%. Specifically, shale in Lucaogou Formation and the 2^nd member of Kongdian Formation have relatively good pore connectivity and relatively high effective porosity, whereas shale in the 1^st member of Qingshankou Formation has relatively poor connectivity (Table 3).

Hydrogen index (HI) is generally more than 350 mg/g, with mainly Type II kerogen (Fig. 6a) and relatively high oil saturation index (OSI) (Fig. 6b), in source rocks in Lucaogou Formation in Jimsar of Junggar Basin. The R_o values of source rock are mainly in the range of 0.6%- 1.1%, suggesting a stage of low maturity to maturity. The strata pressure coefficient is high (1.1-1.3), but the ratio of gas over oil is low (10-20 m³/t). The viscosity of crude oil is high (50-120 mPa•s) and the fluidity is poor. The TOC and S₁ values of typical matrix-dominated shale samples of Lucaogou Formation are 3.96% and 2.21 mg/g, respectively. Narrow organic matter particles are discretely distributed in the samples, whereas the distribution of movable oil is associated with kerogen. The movable oil is adsorbed inside the particles in kerogen, with a few filled in the intergranular pores of mineral particles, showing a good potential for exploitation (Fig. 7). The matrix area and reservoir area in the shale of Lucaogou Formation are often closely associated, forming a good integrated system of source and reservoir at the micro level.

Shale oil samples of submember 3 of the 7^th member of Yanchang Formation in Longdong area in Ordos Basin have strong heterogeneity and mainly Type I and Type II organic matter. The TOC values are overall greater than 5% and the OSI values are moderate (Fig. 6b). The R_o value is 0.6%-1.1%, suggesting a stage of low maturely- maturity. Strata energy is insufficient and the strata pressure coefficient is overall only 0.7-1.0, although it has characteristics of light crude oil (gas/oil ratio of 60-120 m³/t, viscosity of 5-20 mPa•s). The average HI value of the samples is 300 mg/g and the S₁ value is greater than 1.5 mg/g (Fig. 6a). The TOC value of typical samples is 5.43% and the S₁ value is 2.79 mg/g. The abundance of organic matter is relatively low and the distribution of shale oil is associated with organic matter. However, microfractures and a large number of intergranular pores between clay minerals are connected to form relatively good reservoir systems with effectively connected pores under ultrahigh resolution electron microscope observation (Fig. 8).

The continental shale of the 2^nd member of Kongdian Formation in Cangdong Sag in Bohai Bay Basin overall is reaching the standard for very good hydrocarbon source rocks. Kerogen is mainly Type Ⅱ₁ and Type Ⅱ₂, the TOC values are 0.13%-12.92%, and the OSI values are relatively low (Fig. 6b). The R_o values are 0.66%-0.91%, in the range of moderate and low maturity. The overall pressure coefficient is high but with variations (1.0-1.8), the gas/oil ratio is 50-130 m³/t, the viscosity of crude oil is 10-100 mPa•s, and fluidity is moderate. Porosity in the typical samples is overall very low and intergranular pores between minerals are basically filled by kerogen. Movable oil is mainly adsorbed on the surface of kerogen particles or exists in the cracks between kerogen and mineral particles. Kerogen is overall in the shape of the web, forming a very good network for hydrocarbon storage and expulsion (Fig. 9).

The TOC values of shale oil samples of the 1^st member of Qingshankou Formation in Changling Sag, Songliao Basin are relatively low, principally 1.4%-2.5%, with an average value of 1.9% (Fig. 6c). The S₁ values are overall high, about 0.86-2.90 mg/g (Fig. 6c). The OSI values are similar to that of the shale oil samples of submember 3 of the 7^th member of the Yanchang Formation (Fig. 6b). The R_o values are 0.70%-1.13% and the maturity is relatively high. The strata pressure coefficient is high (1.0-1.5), the gas/oil ratio is 50-100 m³/t, the viscosity of crude oil is 10-200 mPa•s, and fluidity is relatively poor. According to TOC values, Liu et al.^[31] divided the organic-rich shale in Qingshankou Formation into blocky mudstone facies with abundant organic matter, blocky mudstone facies with moderate abundance of organic matter, and laminated mudstone facies with moderate abundance of organic matter. These mudstone facies have distinct connectivity of matrix pores and oil saturation. The distribution of charged area in the typical samples shows that shale oil is uniformly dispersed in pores and in the shape of stars, reaching a certain scale although not continuous (Fig. 10). In addition, the charged area is usually partially filled in the tiny intergranular pores and some of the pores are visible. This phenomenon shows that the pores in the original sample are filled with a large amount of movable oil and some intergranular pores are exposed after removing from oiling in a vacuum. Most of the organic carbon is in the form of liquid hydrocarbon generated from oil shale, although the TOC value of the Qingshankou sample is relatively low. In addition, the OSI values also show that the sample has high oil saturation (Fig. 6b).

In summary, at the peak of oil production, the movable oil in continental shale samples is mainly concentrated in internal kerogen, intergranular pores between kerogen and minerals, and adjacent pores, in the form of adsorption and swelling. Shale strata in the four regions have strong heterogeneity and display oil accumulation in a sweet spot. Specifically, shale of Lucaogou Formation is a promising stratum of shale oil sweet spot, as indicated by characteristics of origination from peperite, integration of source and reservoir with accumulation adjacent to the source, and a large amount of movable oil filling the reservoir space. The shale oil in the 1^st member of Qingshankou Formation is scattered, and the organic matter in submember 3 of the 7^th member of Yanchang Formation is associated with shale oil. They also have a lot of intergranular pores between connected clay minerals or micro-fractures, forming a relatively good network for hydrocarbon expulsion of shale oil. Shale in the 2^nd member of Kongdian Formation has relatively low maturity, but high values of hydrogen index. They contain a large amount of crude oil enriched in the network of organic matter, with a thick reservoir, possessing a great potential of large scale production. The technology of charge distribution for crude oil provides the associated conditions between movable oil, pores, and organic matter bands, thus better reveal the availability of these crude oils. Further analysis combining with organic geochemical data, such as free hydrocarbon content, shows that the proportions of movable oil in shale samples in the four regions are 5%-30% in Lucaogou Formation, 15%-30% in submember 3 of the 7^th member of Yanchang Formation, 2%-10% in the 2^nd member of Kongdian Formation, and 10%-25% in the 1^st member of Qingshankou Formation.

Continental shale has many thin layers, strong longitudinal heterogeneity, and a large number of weak structural surfaces, such as foliate laminae. Fully and effectively open these surfaces are the key to improving complexity of fractures and increase drainage area of oil. In this paper, a large number of typical shale samples are randomly selected for X-ray fluorescence spectroscopy (XRF) analysis in large area to obtain distribution characteristics of each element on the surface of the sample along the direction of deposition (Fig. 11). The shale in the four regions shows remarkable characteristics of stratification in the longitudinal direction. The statistical analysis of shale image shows that the average numbers of foliate laminae in one meter are 90, 107, 93, and 71 in the shale of Lucaogou Formation, submember 3 of the 7^th member of Yanchang Formation, the 2^nd member of Kongdian Formation, and the 1^st member of Qingshankou Formation, respectively. The results show that shale in submember 3 of the 7^th member of Yanchang Formation has the strongest longitudinal heterogeneity and the most obvious characteristics of randomly interbedded layers.

In order to further characterize the lithological differences in the longitudinal direction of shale samples, areas within each belt are randomly selected for further quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN) based on the division of foliated laminae discussed above. Take the sample No. 1 in submember 3 of the 7^th member of Yanchang Formation as an example, 5 layers (numbered A, B, C, D, E) are divided longitudinally according to element distribution, and samples within each layer are randomly selected for mineral composition analysis. The scanning results show that the major mineral in Layer A (thickness of 4.1 mm) is carbonate minerals (content of 67.2%). Layer B (thickness 13.6 mm) is dominated by clay minerals (content of 58.1%). The principle minerals in Layer C (thickness of 21.5 mm) include brittle minerals (content of 48.3%) and carbonate minerals (content of 35.8%). Layer D (thickness of 6.4 mm) is dominated by brittle minerals (content of 62%). However, E layer has no remarkable dominant minerals, with brittle minerals, carbonate minerals, and clay minerals accounting for 43.6%, 30.7%, and 25.7%, respectively (Fig. 12). This further confirms the longitudinal heterogeneity of continental shale. The mineral composition of the sample is calculated according to thickness of layer to achieve the weighted average. The average mineral compositions of shale are 42% of brittle minerals, 30% of carbonate minerals, and 28% of clay minerals.

The content of different mineral components directly affects the brittleness of rock, which is an important parameter for the evaluation on the plasticity of reservoir. The shale samples in the four areas are analyzed through X-ray diffraction (XRD) and the mineral compositions are further divided into 3 groups. The first group is brittle minerals, including quartz, feldspar, pyrite, mica, and etc. The second group is carbonate minerals, including calcite, dolomite, and etc. The third group is clay minerals, including kaolinite, montmorillonite, illite, chlorite, and etc. Fig. 13 shows remarkable differences in mineral composition of shale samples from different regions. The brittle minerals in shale samples of Lucaogou Formation are mainly in the range of 40%-65%, whereas the content of clay minerals is relatively low (averaging 15.97%). The content of brittle minerals in the shale samples of submember 3 of the 7^th member of Yanchang Formation is high, accounting for 40%-80%, and the content of clay minerals is also high (averaging 30.65%). The content of brittle mineral in shale of the 2^nd member of Kongdian Formation is 45%-60%, whereas content of clay mineral is very low (averaging 13.91%). The distribution of the three types of minerals in the shale samples of the 1^st member of Qingshankou Formation is quite different. Content of brittle minerals is relatively low (averaging 44.89%), whereas content of clay minerals is relatively high (averaging 39.52%). The plasticity of the reservoir is relatively strong.

A numerical model of the Brazil disk is obtained by randomly reconstructing the mineral distribution of each layer based on the laminae division and mineral characterization discussed above. Take the shale sample No.1 in submember 3 of the 7^th member of Yanchang Formation as an example, the diameter and thickness of the Brazil disk sample are 60 mm and 30 mm, respectively, the model is divided into 5 layers according to mineral distribution (numbered A, B, C, D, and E). The loading force is selected as the direction that at an angle of 45° of the horizontal laminae, considering the influence of mineral composition and laminae on breakage of fractures. The generation and expansion processes of fractures are shown in Fig. 14.

The initial fractures occur simultaneously at interfaces of BC, CD, and DE and continue to expand as a result of the weak intensity of laminae (Fig. 14a-d). With a consistent increase of loading, the fractures continue to expand along the interface (Fig. 14e) and generate new branches of fractures (Fig. 14f), resulting in occurrence of three foliated fractures and two fractures in the shape of double "S" in the matrix of the rock (Fig. 14g). The fractures in the matrix of the rock are mainly generated in layer C, D, and E, which contain a high content of brittle minerals. Fractures in clay-rich layer B are relatively short and simple in form, impeding spread of the fractures Layer A. Thus, no fractures are generated in Layer A in the end. The randomly interlaminated characteristics of continental shale have a significant influence on the process of fracture generation. The opening and expansion of weak structural surfaces, such as foliate laminae, and their connection with the main fractures can effectively enhance the complexity of fractures and improve the seepage conditions of reservoirs. However, the opening of the laminae can cause an increasing loss of fracturing fluid filtration nearby the well, resulting in limited extension of fractures and decreased volume of fracturing. Meanwhile, longitudinal extension of fractures is also restricted by the clay-rich layer.

The box-counting dimension is further introduced to characterize the complexity of the fractures and taken as a quantitative value of the index for fracture complexity evaluation^[42]. The box-counting dimension is a fractal dimension method proposed to describe fracture morpho-logy. It reflects the degree of space occupied by rock fractures and can be used to depict the complexity of rock fractures. A large value suggests the fracture is complex. According to the statistics, the average values of the 3D box-counting dimension of the fractures in the Brazilian disk numerical model are 2.601, 2.554, 2.647, and 2.419, respectively in Lucaogou Formation, submember 3 of the 7^th member of Yanchang Formation, the 2^nd member of Kongdian Formation, and the 1^st member of Qingshankou Formation. The plasticity of the 2^nd member of Kongdian Formation is the best in the four shale samples, mainly because of the relatively well developed laminae, the low content of clay minerals, and the relatively complex fracture networks easily generated in fracturing. The content of clay minerals in shale of Lucaogou Formation is slightly higher and the distribution of laminae is slightly more limited than that in the 2^nd member of Kongdian Formation. The laminae of shale in submember 3 of the 7^th member of Yanchang Formation are the most developed in the four regions and opening of the laminae significantly improves the complexity of fracture systems. However, fracture morphology of the clay-rich layer is relatively simple and the longitudinal expansion of fracture is relatively limited, due to the high content of clay minerals. The content of clay minerals in shale of the 1^st member of Qingshankou Formation is the highest, with relatively undeveloped laminae. The complexity of rock fracture is the lowest and the plasticity of reservoir is poor.

This paper proposes a comprehensive evaluation method of the availability of shale oil in the micro scale in four aspects, including the availability of reservoir, oil saturation of reservoir, mobility of crude oil, and plasticity of reservoir. The key parameters include effective porosity, the proportion of the volume of pore more than 20 nm, the proportion of movable oil, and the box-counting dimension. A total of 483 samples from Lucaogou Formation in Jimsar Sag of Junggar Basin, submember 3 of the 7^th member of Yanchang Formation in Longdong area of Ordos Basin, the 2^nd member of Kongdian Formation in Cangdong Sag of Bohai Bay Basin, and the 1^st member of Qingshankou Formation in Changling Sag of Songliao Basin are studied on the basis of the same evaluation method, providing a basic understanding of the availability of continental shale oil (Table 4). It may be difficult to cover all types and characteristics of continental shale, as a result of limited number of wells and samples and strong heterogeneity of continental shale strata. But the main point is to provide a method and technical means of a comprehensive evaluation at the micro level and comparative study.

The Lucaogou Formation in Jimsar Sag of Junggar Basin has characteristics of peperite, integrated source and reservoir, and accumulation nearby source. The pores in Lucaogou shale are the most developed, with good effective connectivity, compared with that of the other three regions. A large number of crude oil is filled in the reservoir space, in which a high proportion of the oil is the movable oil, with complex reservoir fracturing. It is the most realistic object for exploitation at present. Development mode combining with oil recovery technologies, such as volume fracturing and gas injection huff and puff should be the research focus in future to effectively improve the fluidity of crude oil, because of the high viscosity of crude oil.

Shale samples in submember 3 of the 7^th member of Yanchang Formation, the 2^nd member of Kongdian Formation, and the 1^st member of Qingshankou Formation have similar distribution characteristics of storage space and relatively fair availability and connectivity of pores. Shale in submember 3 of the 7^th member of Yanchang Formation has small strata pressure coefficient, a high proportion of the movable oil, a high gas/oil ratio, and good fluidity, with light crude oil as the majority crude oil. They have well developed foliate laminae and good plasticity although the content of clay minerals is relatively high. Attention should be paid in the process of volume fracturing to fully reconstruct and connect the weak surfaces of the shale structure, in order to form a complex network of fractures. In addition, construction scale should be increased appropriately to supply strata energy. Meanwhile, it is suggested to focus on the feasibility and economic evaluation of a large-scale application of technology transformations of the in-situ shale in submember 3 of the 7^th member of Yanchang Formation.

The connectivity of effective pores in shale of the 2^nd member of Kongdian Formation in Cangdong Sag in Bohai Bay Basin is the second best to that of Lucaogou Formation, while the pore size distribution in Kongdian shale is better than that of the other three regions, which is in advantage of oil migration. A large amount of crude oil has been generated and enriched in the network of organic matter in Kongdian shale, although maturity and proportion of movable oil are relatively low. With high strata pressure, moderate viscosity of crude oil, and excellent plasticity of reservoir, it is expected to achieve large scale development with benefit through volume fracturing.

Shale in the 1^st member of Qingshankou Formation in Changling Sag of Songliao Basin has high maturity, high saturation of movable oil, favorable characteristics of strata pressure, and a relatively high potential for resources, with most of the organic matter converted into liquid hydrocarbon. However, the reservoir has poor connectivity of effective pores and overall small pore size. The effectiveness of reservoir space is remarkably worse than that of the other three regions. It is difficult to produce and develop with a benefit under the current conditions of engineering technology, due to the high viscosity of crude oil and the strong plasticity of reservoir. Technology researches of high plastic reservoir stimulation, oil viscosity reduction, and enhanced oil recovery are needed, such as research and development on low-viscosity fracturing fluid system to improve the opening effect on weak surfaces of reservoir structure and exploration of acidification and stimulation technology in a deep reservoir to improve seepage conditions, and etc.

The traditional analytical methods of reservoirs are not suitable for shale oil as availability of reservoir space, saturation of oil, mobility of oil, plasticity of reservoir for shale oil at the nanoscale are more complex. This paper proposes a series of techniques for comprehensive evaluation on availability of shale oil at multiple scales and using multiple parameters. Systematic experimental analysis was carried out on shale oil core samples in the four major basins on the same technical system of evaluation and experimental conditions of analysis. This paper provides a systematic understanding of the availability of shale oil resources in each basin at the microscale and guidance for evaluation of hydrocarbon potential of shale oil resources and engineering design of development at the macro scale. Future studies focus on systematically conducting a collaborative study at multiple scales based on key parameters, with adding more shale oil core samples in different regions. In order to construct a table of comprehensive evaluation using multi parameters and a comparative chart for continental shale oil in China, the understanding of reservoir heterogeneity and accumulation and distribution of shale oil needs to be consistently improved.