Shale oil in the United States is mainly formed in marine strata. Over the past decade, the average growth rate of shale oil production in the United States has exceeded 25%. In 2018, the production of shale oil in the United States was 3.29×10⁸ t, accounting for 59% of the total crude oil production, boosting the crude oil production in the country to its second highest peak in the history^[1]. The "shale oil revolution" in the United States has successfully initiated the large-scale and continuous growth of shale oil production from marine shale with medium-high maturity, which brings us two inspirations. First, the revolution of exploration thought has promoted the oil and gas exploration shifting from outside to inside the source rock area, which has brought about profound changes in oil/gas exploration field, accumulation theory and exploration technology, and confirmed that “exploring oil inside source areas” is an important direction of sustainable development of petroleum industry. Second, the revolution of technology and cost strongly supports the breakthrough in “exploring oil inside source areas” and its large-scale development. The combination of favorable area optimization & “sweet spot” evaluation technology, ultra-long horizontal well & volume fracturing technology, and factory-like operation effectively reduce the cost and increase efficiency, greatly lowering the economic thresholds of shale oil and gas development^{[2,3,4,5,6,7]}.

In China, shale oil is mainly developed in continental strata. Compared with North American marine shale oil, there are great difference in geological conditions, resource quality, development technology and economic threshold. Overall, the continental sediments have a relatively rapid change of facies, strong heterogeneity, diverse mineral compositions, and complex pore structures and types. Moreover, the continental sediments exhibit lower thermal maturity of organic matter (OM), higher fluid viscosity, poorer mobility, and larger residual quantity of shale oil. Although the medium to high maturity shale oil resources have a certain scale, but the total economic recoverable amount is small. A considerable amount of continental shale oil is in medium and low maturity, which requires in-situ conversion technology for effective development. According to the evaluation result, this part of resources has great potential, and may indicate a new opportunities for shale oil revolution^{[2-3, 5]}.

The ability to develop shale oil on a large scale depends on three prerequisites. First, the daily production of a single well reaches the economic threshold. Second, the estimated ultimate recovery (EUR) of a single well at a certain oil price is economical. Third, the shale oil “sweet spot” should be large enough to support the minimum economic production and maintain stable production for a period of time. In addition, the development of shale oil also requires a favorable match of several geological conditions. First, source kitchen with high OM abundance and good OM quality (Type I-II₁) ensures a large number of hydrocarbons occluded in shale and determines enough OMs (liquid hydrocarbon, bitumen, and solid OM) retained for underground in-situ conversion development. Second, shale laminations should be developed and a certain amount of matrix pores should be preserved. Third, a high proportion of brittle minerals can ensure the effectiveness of fracturing. Fourth, good preservation conditions, i.e., cap rocks with good sealing properties are developed both above and below the section of shale oil “sweet spot” ^{[3, 5, 7]}. The above conditions are significantly different in shale and mudstone.

China's continental shale oil exploration is still in the initial stage, and there is no uniform standard for the selection of “sweet spot”. During the exploration and exploitation practice, the fracturing effect on different lithologic combinations is found to be different, and the test production varies greatly^[8,9]. In particular, when exploring and developing the pure shale reservoir (defined as Class III shale oil^[10] by oilfield), whether the shale section or mudstone section is preferable is controversially discussed. For example, there are two different opinions on shale oil exploration in the 7th member of Triassic Yanchang Formation (Chang-7 Member or Chang-7) in the Ordos Basin. One view is that the dark massive mudstone of Chang-7 Member is the most favorable shale oil exploration and development target under current technological conditions ^[11,12]. The other view is that the black shale (including silty laminar black shale) has better hydrocarbon generation conditions and hydrocarbon-bearing capacity and is more brittle than massive mudstone^{[13,14,15,16,17]}. In the Upper Cretaceous Qingshankou Formation of the Songliao Basin, laminar felsic shale facies with medium organic carbon content (TOC of 2%-3% in the sweet-spot section) has good hydrocarbon generation potential and well-developed reservoir storage space, which is a dominant lithofacies of shale oil^[18]. As for the shale oil which is formed in a saline environment of the eastern faulted depression lacustrine basins in China, the combination of laminar argillaceous limestone and black shale is the "sweet spot" for shale oil exploration and development^{[8, 19]}, and the felsic shale and mixed shale with laminations are conducive to shale oil enrichment, high yield and fracturing^[9].

According to the petrology, organic geochemistry, reservoir property and brittleness index of fine-grained sediments in typical lacustrine basins, this paper concludes that there are differences between shale and mudstone in the sedimentary environment, texture characteristics, organic matter abundance, amount and efficiency of hydrocarbon generation and expulsion, and storage capacity, and these differences determine their different roles during the formation of conventional and shale reservoirs. Therefore, it is of great significance to study the difference of hydrocarbon accumulation between continental organic-rich shale and mudstone for accurately selecting shale oil sweet-spot area/section, objectively evaluating the shale oil/gas resource and its economy, and reducing inefficient and ineffective wells.

Continental organic-rich shales are widely distributed in China. In terms of strata, they are mainly distributed in the Permian, Upper Triassic, Lower Cretaceous, Paleogene, and Neogene. In terms of areas, they are mainly distributed in the Ordos, Songliao, Junggar, and Bohai Bay Basins. The organic matter abundance of continental mudstones and shales varies greatly. In terms of the effectiveness of source rocks, the lower limit of TOC value is 0.5%-0.8%, and the upper limit is 8%-10% or even higher. As the effective source rocks for the formation of conventional reservoirs, the TOC values are mainly in the range of 0.5%-0.8% and 2%-3%. Although source rocks with higher TOC values are also the main hydrocarbon source of conventional oil and gas reservoirs, their contribution is limited to two conditions. First, the concentrated section of high TOC shale has poor hydrocarbon expulsion and low expulsion efficiency, and high expulsion efficiency only occurs when the shale has a moderate thickness and is interbedded with the reservoirs^[20,21]. Second, the organic-rich shales are mainly distributed in semi-deep to deep lacustrine areas, and geographically located in the lower part of the syncline of the present basin. The source rock, reservoir and cap rock assemblage and hydrocarbon accumulation dynamics are not conducive to the formation of conventional oil and gas reservoirs. The shale with medium and high TOC value should be the main source rock for the formation of shale oil and gas reservoirs. Taking shale and mudstone as end members and carrying out the study of reservoir forming differences, are of great significance to guide the upcoming "sweet spot" selection and layer selection evaluation of shale oil exploration.

The types of rock associations of continental shale are complex and diverse, including shale, mudstone, siltstone, carbonate, migmatite, and tuff. Among them, shale and mudstone are widely recognized as source rocks. At present, there is no systematic data to conclude whether tuff and carbonate intercalated in shale/mudstone also participate in the process of hydrocarbon supply, so this paper will not discuss them. In general, the organic matter content of shale is relatively high. The black shale which has the highest TOC value is the main section of shale oil and gas reservoir formation. The gray shale has low TOC value, so that it is difficult to become an effective source rock due to the lack of solid material foundation, in spite of its developed laminations. Mudstone also has high organic matter content, which, however, is lower than that of shale. In addition, the massive structure and poorer brittleness also determine that the mudstone is not the main section of shale oil and gas reservoirs. When mudstone is in moderate thickness and interbedded with reservoirs, it is more likely to act as main source rock of conventional oil and gas reservoirs.

Continental source rocks are mainly developed in freshwater and saline lacustrine basins in China. The study results show that shale and mudstone with high TOC values can form in both types of lacustrine basins. Shale and mudstone are significantly different in organic matter abundance and contribution to hydrocarbon generation and expulsion, even they were deposited in the same environment.

The source rocks in the Chang-7 Member in the Ordos Basin are organic-rich shales deposited in freshwater lacustrine basin, with an average thickness of 105 m. Among them, shale accounts for 30%-50%. The Chang-7₁₊₂ sub-member is mainly composed of mudstone, and the Chang-7₃ sub-member is concentrated with shale. According to the measured data, the average TOC value of shale is 13.81%^[11], 18.50%^[17] and 16.40%^[22], and the average TOC value of mudstone is 3.75%^[11], 3.74%^[17] and 1.20%^[22]. That is, the average TOC value of shale is 3-14 times that of mudstone. From the perspective of hydrocarbon generation kinetic energy, shale’s activation energy distribution is more concentrated than that of mudstone. The R_o value (0.70%-0.87%) corresponding to the main hydrocarbon generation period of shale is lower than that of mudstone (1.06%-1.72%). When the R_o value is 0.9%-1.3%, the total hydrocarbon yield and oil production of shale are higher than that of mudstone^[23]. According to laboratory simulation and calculation of hydrocarbon generation and expulsion, the average hydrocarbon generation intensity of shale and mudstone are 249×10⁴ t/km² and 48×10⁴ t/km², respectively, and their average hydrocarbon expulsion intensities are 193×10⁴ t/km² and 20×10⁴ t/km², respectively. Clearly, shale’s hydrocarbon generation and expulsion intensities are 5-9 times that of mudstone.

The source rocks of Lucaogou Formation of Middle Permian in the Junggar Basin were formed in a saline lacustrine basin, with an average thickness of 200-300 m. Specially, shale accounts for 30%-50%, with the TOC value of 5.0%- 16.1% (average 6.1%), and the TOC value of mudstone is 1%-5% (average 3.2%). In the second member of Kongdian Formation of Paleogene in the Cangdong Sag of the Bohai Bay Basin, the shale and mudstone have the TOC value of 2.32%-9.23% (average 4.87%) and 0.14%-8.41% (average 3.07%), respectively, suggesting that the TOC of shale is nearly twice as much as mudstone.

Shale and mudstone are obviously different in the sedimentary mechanism, texture, chemical composition and other aspects. Shale is in lamina structure and is easy to delaminate along the layer. Due to the source input and seasonal climate fluctuations, algae and other organic matters, carbonate, clay, silty feldspar, quartz, and volcanic ash are in layered sedimentation and form continuous laminations. Mudstone is in massive structure. It is mostly developed in the shallow- shoreside lacustrine environment with a disturbed water body and a large injection of fine-grained sediments, showing the characteristics of density flow in most cases, so it is not easy to form laminations.

According to the systematic study on typical continental shale and mudstone in the Chang-7 Member of the Ordos Basin, the Qingshankou Formation of the Songliao Basin, the Lucaogou Formation of the Junggar Basin and the Paleogene of the Bohai Bay Basin, it is concluded that there are obvious differences in structure, texture, mineral composition, type and content of organic matter, and sedimentary mechanism between shale and mudstone (Table 1). Understanding these differences is of guiding significance to objectively select favorable drilling target areas and target layers in the early exploration stage.

The formation of organic-rich shale and mudstone is controlled jointly by the original productivity of organic materials and the preservation conditions in the syn-sedimentary period and later stage. Based on the petrological and TOC analysis on organic-rich shale and mudstone in the Chang-7 Member of the Ordos Basin, the Qingshankou Formation of the Songliao Basin and the Lucaogou Formation of the Junggar Basin, it is found that the organic matter in shale is enriched along lamina, and the organic matter in mudstone is mainly dispersed and bioclastic^[17]. Four mechanisms contribute to organic matter enrichment. First, volcanic ash deposition and deep hydrothermal fluid injection cause "fertility effect". Second, radioactive substances promote the excessive and over-speed growth of organisms and improve the hydrocarbon generation capacity. Third, salinization and stratification of water body are conducive to efficient capture and preservation of organic matter. Fourth, deep anaerobic water environment and low deposition rate ensure that organic matter accumulated is not diluted.

1.3.1. "Fertility effect" caused by volcanic ash deposition and deep hydrothermal fluid injection

Lee et al. ^[24] believed that submarine volcanic eruption will lead to seawater temperature rise, ocean acidification, and a large amount of CO₂ emitted, which will cause death or even extinction of livings because of suffocation. Afterwards, algae will flourish and form organic-rich shale after burial. The outcrop and core observation of the Chang-7 Member in the Ordos Basin show that there are many layers of tuff in the organic-rich shale section, with the thickness ranging from millimeter to centimeter. Statistics show that the more sedimentary tuff, the greater the thickness and TOC value of source rocks ^[25,26]. For example, 156 layers of tuff have been identified in the Chang-7₃ sub-member of the Yishicun section in the Tongchuan area, Shaanxi Province, and in a certain range, the content of tuff is positively correlated with TOC value. When the content of tuff is between 5% and 7%, the TOC value of shale is the highest (more than 20%), which indicates that appropriate amount of volcanic material input can promote the biological growth and bloom. Hydrothermal minerals such as authigenic albite, reddingite, layered pyrite and typical white marcasite are also found in the organic-rich shale of the Chang-7 Member. Trace elements including Cu, Pb, and Zn are enriched, indicating that deep hydrothermal fluid intrusion occurred during the deposition of Chang-7 Member. It is believed that hydrothermal activities provide sufficient nutrients for biological flourishment, leading to the "fertility effect". The organic matter of the Lucaogou Formation in the Junggar Basin is mainly composed of bacteria and algae, and micron-sized algal lamina that is interbedded with intermediate-basic volcanic ashes is also commonly observed in organic-rich shale. The analysis shows that the rapid hydrolysis of salt coating on the surface of volcanic ash promotes the enrichment of phosphorus and other nutrients in water, and then improves the growth of algae. The above cases confirm that frequent and large-scale volcanic ash deposition and lake-bottom hydrothermal fluid intrusion are the triggers of biological bloom, and are constructive and favorable factors for the formation of high-quality source rocks.

1.3.2. Radioactive substances promote the excessive growth of organisms and improve hydrocarbon generation capacity

Almost all organic-rich shales are rich in uranium, and show high GR values on logging curves ^{[11, 25, 27]}. The particles and energy released by uranium during radioactive decay can promote biological growth and organic matter converting into hydrocarbon ^[27]. In the uranium-rich source rocks of the Chang-7 Member in the Ordos Basin, more than 50% of uranium exists in collophanite, and more than 20% of uranium occurs in organic matter by adsorption. Frequent volcanic activities provided rich uranium source input for the Chang-7 source rocks ^[28]. The tuff layer of the Chang-7 Member is also rich in blue-green algae and supermicrobial fossils, and the content of algae in the associated shale is extremely high (Fig. 1). These fossils mostly appear at the bottom of the Chang-7₃ sub-member and often near the tuffaceous lamina, showing the characteristics of short-term microbial "boom and death" ^[26]. Nutrients and radioactive materials with appropriate high concentrations of nitrogen and phosphorus can promote the growth of blue-green algae and improve paleo-productivity ^[29]. Uranium’s radioactivity can provide energy for the survival and reproduction of organisms ^[30]. A thermal simulation experiment of hydrocarbon generation was carried out by adding uranyl carbonate solution into low-mature source rocks containing Type I, II, and III kerogens. It was found that the participation of uranium could improve the productivity of source rocks, and increase the total hydrocarbon quantity, and reduce the threshold temperature of hydrocarbon generation of source rocks, leading to the generation of liquid hydrocarbons at relatively low temperature ^[31,32,33]. Analysis of the products of shale and kerogen after neutron irradiation operation showed that radioactivity could change the structure of kerogen and improve the hydrocarbon generation potential of source rocks^[27].

1.3.3. Salinization and stratification of water body are conducive to efficient capture and preservation of organic matter

Salty water can promote organic matter flocculation, and then improve the efficiency of organic matter being captured. The physical simulation results showed that the efficiency of organic matter being captured increased by 300% when the salinity increased from 1% to 3%, and the efficiency increased by 100% when the sediment concentration increased from 2% to 4%. In addition, water stratification could easily occur in salty lacustrine basins, which could maintain a relatively good anoxic reduction environment, and that was conducive to the accumulation and preservation of organic matter. Taking the sweet-spot section of Well Ji 32 in the Junggar Basin as an example, in high-TOC sections, the ratio of V to Cr, Mo content, and ratio of Cu & Mo to Zn are 2-4, 0.010‰-0.018‰ and 0.6-0.8, respectively; in low-TOC sections, these values are 1-2, 0.003‰-0.008‰ and 0.3-0.5, respectively. The comparison results showed that the water in the high-TOC sections had higher anoxic levels, and the preservation condition was better than that in the low-TOC sections.

1.3.4. Deep anaerobic water environment and low deposition rate ensure that organic matter accumulated is not diluted

Low oxygen level and anaerobic environment of a lacustrine basin are essential for the preservation and enrichment of organic matter. The content of pyrite in the mudstone and shale of the Chang-7 Member in the Ordos Basin is generally high. The content of pyrite in Zhidan in the east, Huanxian in the west, and Tongchuan in the south are all higher than 20%. There is an obvious positive correlation between organic matter abundance and pyrite content. The grain size of pyrite can be used to semi-quantitatively evaluation of the oxygen content in the sedimentary environment. For example, in the Yishicun section, the grain size of 1258 pyrite framboids (Fig. 2) was counted by using the scanning electron microscope imaging technology. The results showed that in the sections with the TOC of 15%-20%, the grain size of pyrite was generally smaller than 8 μm, and the average grain size was smaller than 6.5 μm, indicating a sulfide and anoxic environment. In the sections with the TOC of 2%-10%, the grain size of pyrite was generally larger than 8 μm, and the average grain size was larger than 10 μm, which indicated an oxygen-depleted or weakly oxic environment. With the increase of pyrite grain size, the oxygen content of sedimentary water increased correspondingly.

Low deposition rate and low compensation rate of terrigenous debris are beneficial to the preservation and enrichment of organic matter. According to the ID-TIMS dating data of three Chang-7 tuff samples from the Yishicun section and Well Yaoye 1 (Fig. 3)^[34], the deposition rate of Chang-7₃ shale is 5 cm/1000 a, which is far lower than that of the Cretaceous (13.5 cm/1000 a)^[35] and that of the Triassic continental strata (24 cm/1000 a)^[36] in the Songliao Basin. According to the Milankovitch cycle analysis, the Chang-7₃ shale can be divided into five astronomical cycles. Through statistical analysis, it was found that, for each cycle, the deposition rate and TOC value in the ascending half-cycle were significantly negatively correlated with those in the descending half-cycle (Figs. 3 and 4). This indicated that the deposition rate of the Chang-7 Member was relatively low, and the low terrigenous debris compensation rate had reduced its dilution effect on organic matter, which was favorable for the formation of organic-rich mudstone and shale.

The development of continental shale is dependent on two processes: terrigenous input, and endogenous deposition. Due to the joint influences of climate, hydrodynamic conditions, modes of source input and organic matter flocculation, laminar structure is widely developed in shale, which is one of the important conditions for the extensive formation and enrichment of shale oil. Microscopic observation showed that many kinds of shale with laminar structure had good reservoir capacity. The pore sizes distribution curve was bimodal, and the micron-sized pores were developed. Generally, shale is the section of high-quality reservoir lithofacies ^{[9, 15-16]}.

With the Permian Lucaogou Formation in the Junggar Basin as an example, the differences in reservoir capacity between mudstone and shale were identified using the optical microscope, scanning electron microscope, nitrogen adsorption, and other technical methods. Since the Lucaogou Formation was formed in a saline lacustrine basin, the shale generally has a laminar structure. The combination of carbonate, albite, and organic matter is the most popular type (Fig. 5a-5c), and organic matter is mostly distributed in parallel and laminar form (Fig. 5b). Intergranular pores in dolomite and intragranular pores of clay minerals are the main pore types. The former takes a high proportion, and exhibits larger pore diameter than the latter (Fig. 5d). There is no laminar structure in the mudstone. Matrix minerals of carbonate and albite are dominant, and the organic matter is dispersed in the matrix minerals (Fig. 5e-5g). Intragranular pores of chlorite are dominant, and the percentage of intergranular pores of dolomite is low (Fig. 5h). In general, mudstone is less porous than shale. The specific pore volume (pore volume per gram of rock) of shale is generally higher than 0.04340 cm³/g, which is much higher than that of the mudstone (0.00691 cm³/g). The BET specific surface area of shale is 8.07 m²/g, which is more than five times that of the mudstone (1.68 m²/g). Shale has larger pores than mudstone. The space of pores larger than 38 nm in shale volume accounts for 80%, and that value in massive mudstone is only 65%. Similar characteristics are found in the specific surface area (Fig. 6). Therefore, it can be concluded that the reservoir capacity of shale is better than that of massive mudstone.

Most of the existing shale oil wells in the Jiyang depression of the Bohai Bay Basin are drilled in organic-rich laminar argillaceous limestone lithofacies, limy mudstone lithofacies, and their thin intercalations, which have good reservoir capacity ^{[16, 37]}. In the Qingshankou Formation of the Songliao basin, organic-laminated felsic lithofacies is found to have good hydrocarbon generation potential and developed reservoir capacity, which also suggests that the shale section is the predominant lithofacies of shale oil ^[15].

Statistical results show that different types of shales and mudstones in the Junggar and Ordos basins are obviously different in rock-forming mineral and element compositions. In the Lucaogou Formation of the Junggar Basin, the difference of mineral composition between shale and mudstone is mainly in dolomite, albite, and quartz contents. Shale has higher dolomite content which can exceed 30% at most, leading to carbonate lamina, which is interlayered with organic matter to form laminar shale. Moreover, the content of quartz and albite in shale is also high, about 30%. Mudstone has lower dolomite content, generally less than 10%, which is mainly dispersed between organic matter, quartz, albite, and clay minerals. It contains the quartz content of about 30%, and the maximum content of albite as much as 50%. In the Chang-7 Member of the Ordos Basin, shale contains the content of clastic minerals of generally 20%-30%, lower than that of mudstone, and also contains the content of feldspar less than 5% and K-feldspar of 1% on average. The carbonate content is generally high, and the average dolomite content is 5.6%. The authigenic iron-bearing mineral in shale is mainly pyrite, with an average content of 10%, which is 10 times of that of mudstone. The clastic minerals in the mudstone are as much as 35%-45%, among which feldspar can reach 5%-15%, and others are quartz. The dolomite content is low, with an average of 3.7%. Siderite is the main iron-bearing mineral in mudstone, with an average of 3.2%. In terms of clay minerals, both mudstone and shale are mainly composed of illite/smectite (I/S) - 68.4% in shale and 60% in mudstone. Mudstone has more illite, kaolinite, and chlorite than shale, but its smectite content is relatively lower. Generally, the content of brittle minerals in mudstone is relatively lower, which affects the creation of induced fractures and the fracturability of reservoirs, making it difficult to maintain a stable production.

Mudstone and shale are also very different in element composition. Major elements reflect the differences in source input, sedimentary environment, and biological action. For example, the mudstone in the Chang-7 Member of the Ordos Basin has the average CaO content of 53.82%, higher than shale, indicating more sufficient supply of terrigenous debris when the mudstone was deposited. The average content of MgO is 1.64% in shale, and 3.46% in mudstone, suggesting that shale was formed in a more stable water environment. The average content of P₂O₅ in shale is 0.61%, which is three times of that in mudstone, indicating that the original productivity of organic matters during the deposition of shale is higher than the mudstone of the same period. The differentiation of B, U, Ni, Sr, Cu, Mo, Mn, Mg, S, and other elements in mudstone and shale of the Chang-7 Member is very obvious. For example, the average contents of Cu and U in shale are 0.060‰ and 0.012‰, which are three times higher than that of mudstone, indicating that shale was deposited in a more anoxic sedimentary environment. In addition, the average content of Mo in shale is 0.02‰, which is 10 times that of mudstone, indicating that water salinity was lower when shale was deposited.

The above results show that there are obvious differences between shale and mudstone in the sedimentary environment, content and distribution of organic matter, reservoir property, and mineral compositions. In respect of the shale oil exploration and development practices, shales have high TOC value, developed lamination, relatively good reservoir property, and relatively high brittle mineral content, and are the most favorable lithofacies type for shale oil exploration and development. However, there are still some problems in current research and production practice, such as undefined concept and unclear facies. These key factors restrict the selection and evaluation of shale oil field, optimization of "sweet-spot area/section", fracturing and drilling design, and optimization of development scheme. Therefore, to promote the exploration and development process of continental shale oil, it is necessary to separate shale and mudstone to determine the resources distribution, the evaluation parameters and evaluation standards of "sweet spot", the selection of favorable blocks, and the effective development technology.

For the exploration of shale oil with medium-high maturity, it is suggested that the key evaluation elements should be determined and the selection criteria should be established as soon as possible. As mentioned above, the abundance and type of organic matter are the material basis for determining whether shale oil can be economically developed. Obviously, the higher the TOC content, the better. At present, the lower limit of the TOC value in several key onshore shale oil exploration areas is set to be 1%-2%, and it is believed that this value is rather lower. For example, the lower limit of TOC in the shale oil enrichment area of the Jiyang depression^[37] is 2%, the Permian Lucaogou Formation shale oil enrichment area of the Santanghu Basin^[38] is 4%, the shale oil core area of the Biyang sag^[39] is 1.7%, the sweet spot of the Lucaogou Formation in the Jimusa'er sag^[40] is 1%, the shale oil target area under drilling in the Ordos Basin^[12] is 2%-6%, the selected shale oil area of Jurassic Daanzhai Formation in the Sichuan Basin is 1%, and the thickness of black shale is more than 20 m^[4]. This paper suggests that the shale oil area should meet the following criteria. First, the lower limit of TOC content is adjusted to 2%-3%. It is better to be greater than 3%. As for the type of organic matter, Type I kerogen is preferred, and Type II₁ can also be considered. Type II₂-III organic matters are not the parent materials that can support the economic development of shale oil; hence, they should be excluded from the selection and evaluation of shale oil area. Second, in addition to high content of brittle minerals, shale should contain low content of clay minerals, which would be better to be lower than 25%-30%. Third, in addition to a certain matrix porosity, the shale roof/floor should have good sealing capacity to ensure the movable liquid hydrocarbon would not lost.

2.1.1. Shale oil of Chang-7 Member in the Ordos Basin

Two types of shale oil exist in Chang-7 Member in the Ordos Basin: transition from tight oil to shale oil, and shale oil. The former refers to the shale oil layer intercalated with a certain proportion of tight sandstone, which largely involves the production of shale oil. The latter is produced from pure shale without sandstone layers interbedded. In the Chang-7 shale, the organic matter belongs to Type I-II. The shale is concentrated in the Chang-7₃ sub-member, where the organic matter is mainly Type I-II₁, and the maximum TOC is 32%, with an average value of 13.8%; the brittle mineral content is less than 35%, and the clay mineral content is larger than 60%. Mudstone is mainly in the Chang-7₁₊₂ sub-member, where the main organic matter is Type II, especially Type II₂. The maximum TOC content is 6%, with an average value of 3.8%. In the Chang-7₃ sub-member, there are 13 wells with the testing oil production exceeding 5 t/d. Three wells have demonstrated a testing production of being more than 20 t/d. Among these wells, Well Ning 148 has achieved 24.23 t/d from Chang-7₃. However, in the case of a relatively low proportion of sandstone interlayer (the sandstone to strata ratio is less than 5%), the oil production is not stable. When the TOC content is greater than 4.5%, the production is negatively correlated with TOC content. This result is related to the increase of liquid hydrocarbon adsorption capacity when the organic matter content exceeds a certain value. Until now, the shale oil wells with high initial production and stable production in Chang-7 are mostly located in the areas with sand to strata ratio being greater than 15%. Obviously, tight sandstone has a contribution to the production. Therefore, this reservoir is actually a transitional type between shale oil and tight oil. Due to the high clay content of shale in Chang-7₃ of the Ordos Basin, the combination of horizontal well and fracturing technique is not suitable for the development of shale oil. Instead, the in-situ conversion technology is recommended, and its effect will be better than the existing technology.

2.1.2. Shale oil of Kong-2 Member of Cangdong sag in Bohai Bay Basin

By the end of 2019, 12 horizontal wells had been put into trial production, of which 7 wells have achieved good results, 2 wells were shut down due to high hydrogen sulfide content, and 3 wells have not yet been transferred to trial production. At present, Well Guandong 1701H and Well Guandong 1702H have cumulatively produced 7663 t and 10353 t, respectively, showing satisfactory results of test production. According to the analysis of available data, the organic matter is mainly Type I-II₁. When the organic matter TOC content is 2%-3%, the retained hydrocarbon content increases obviously, and an inflection point appears at 3% (Fig. 7). Therefore, the minimum lower limit of TOC for the "sweet-spot section" of shale oil is as 2%, and 3% is recommended. The brittle felsic mineral content is 18%-42%, with an average of 34%. The carbonate mineral content is 12%-62%, with an average of 34%. The clay mineral content is greater than 30%, with an average of 16%^{[9, 41]}. The source rock of the third member of Shahejie Formation (Es3) in the Qikou sag is 100-500 m thick, with TOC of 1.09%-2.37% and R_o of 0.7%-1.2%. It is mainly composed of mixed shale and felsic shale. The average content of felsic mineral is 30%, the average content of carbonate mineral is 26%, and the average content of clay mineral is 23%. Good results were obtained in re-testing of 20 old wells, but it still needs confirmation by trial production that whether the expected cumulative recovery can be obtained. The main constraint is that the relatively lower organic matter content of the Es3 shale may result in the lack of formation energy.

2.1.3. Shale oil of Lucaogou Formation in Jimusa'er sag and of Fengcheng Formation in Mahu sag, Jungar Basin

There are two shale oil sweet-spot sections in the Lucaogou Formation, i.e. the upper section and the lower section. At present, 89 shale oil wells have been drilled, including 37 horizontal wells. Among which 28 wells have been put into production, with a daily oil output of 370 t^{[40, 42]}. Typically, Well Ji 172 has been in continual production for nearly 1800 days, with the cumulative oil production of nearly 1.9×10⁴ t, and the daily oil production of about 4 t/d. There are three factors related to the economically recoverable shale oil. First, a good material base is necessary. The TOC should be 2%-3%, the organic matter type should be mainly Type I-II₁, and the R_o should be 0.8%-0.9%. Second, the abundance of recoverable oil reserves should be high, being (25-30) ×10⁴ t/km². Third, the capping layer should be developed both above and below the shale concentration section (for instance, whether the mudstone is developed in the Wutong Formation at the top of the upper sweet-spot section). In the upper and lower sweet-spot sections, the clay mineral content is lower than 15%, and the brittle mineral content is between 80% and 85%. Generally, preferable reservoir forming elements will determine the economic recoverability and total amount of shale oil in this area.

2.2.1. The resources potential of shale oil with low-medium maturity

Continental shale oil resources in China have huge potential, and most of them are shale oil with low-maturity. According to the preliminary evaluation, the prospective resources of shale oil with low-medium maturity is (700-900) × 10⁸ t, and natural gas in these shales is about 65×10¹² m³, which is roughly equivalent to conventional petroleum geological resources. The technically recoverable resources are (200- 250) ×10⁸ t, which is equivalent to the recoverable resources of conventional oil ^[3]. The continental shale oil resources are mainly distributed in three basins, namely the Ordos Basin, Songliao Basin, and Junggar Basin. At these basins, the prospective resources of shale oil are about (620-650)×10⁸ t (Table 2) and the technically recoverable resources are (170- 200) ×10⁸ t, both accounting for more than 80%.

2.2.2. Evaluation criteria of sweet-spot areas/sections for in-situ conversion of shale oil with low-medium maturity

Shale sections which are suitable for underground in-situ conversion should meet five conditions. First, the shale concentration section has high organic matter abundance generally with TOC of 6%-8% (the more the better) and Type I-II₁ kerogens. Second, the thickness of shale concentration section is generally greater than 15 m and the net shale/stratum ratio is greater than 0.8. Third, the thermal maturity is moderate, with R_o of 0.5%-1.0%. Fourth, the burial depth is less than 3000 m, and the continuous distribution area is larger than 50 km². Fifth, the shale section has good roof and floor preservation conditions and the thickness of shielding layers is greater than 2 m; faults are not developed, the formation water content is less than 5%, and there is no active water.

2.2.3. An example of selection of sweet-spot section for in-situ conversion in the Chang-7 Member of the Ordos Basin

In the Chang-7 shale of the Ordos Basin, Chang-7₃ has the best condition for in-situ conversion. In Chang-7, the sections with TOC greater than 6% are 16 m thick on average, or up to 60 m thick, with the distribution area of about 3×10⁴ km². The area with a thickness greater than 20 m accounts for 50%, about 1.8×10⁴ km². The hydrogen index (HI) is high, up to 750 mg/g, with an average of 450 mg/g. The occluded hydrocarbon content (S₁) in shale is large. According to the field measurement of Well Le 85, the oil content is 8.80-26.77 mg/g (with an average of 18.7 mg/g), of which the average content of components lighter than C_16- is 5.538 mg/g, accounting for 31.4% of the total oil content. In addition, the residual hydrocarbon generation potential (S₂) of shale is large. The residual hydrocarbon generation potential of shale sections with TOC content being higher than 6% is 27.53-132.23 mg/g, with an average of 63.88 mg/g. Shale has low water saturation and water content, with no active water. The maturity of shales in Chang-7 is moderate, with R_o ranging from 0.6% to 1.2%. The area of shales with R_o<1.0% in Chang-7 is relatively large, accounting for about 90% of the total shale distribution area. This is the considerable potential for in-situ conversion ^[3]. According to the evaluation criteria for shale oil sweet spots for in-situ conversion, it is estimated that the favorable area for shale oil in-situ conversion in Chang-7₃ in the Ordos Basin is larger than 1.5×10⁴ km², and the technically recoverable resources are greater than 150×10⁸ tons.

Shale and mudstone are different in sedimentary environment and dynamics, organic matter accumulation and preservation conditions, lamellation and reservoir properties, mineral composition and fracturability, etc., which determine their different roles in shale oil economic mineralization. Shale has become the best interval and main “sweet spot” area for economic mineralization of shale oil own to its high organic matter abundance, well-developed lamellation, developed matrix pores, low clay mineral content, high brittleness, large continuous distribution range of concentrated intervals, and good preservation conditions. Mudstone is not the main interval and target due to its low organic matter abundance, underdeveloped lamellation, high clay mineral content, poor brittleness, and poorly developed matrix pores.

Currently, to prevent the emergence of too many low efficient and ineffective wells, the selection criteria of "sweet spots" should be strictly controlled for the economic mineralization of shale oil with medium-high maturity. The following parameters are recommended as the lower limit criteria for the selection of shale oil "sweet spot" areas/sections. First, the TOC value is 2%-3% (˃3% is recommended) and the organic matter is mainly Type I-II₁. Second, the R_o value is greater than 0.9% or 1.0% if possible. Third, the clay mineral content is less than 30%. Fourthly, the free hydrocarbon content is 4-6 mg/g. Fifthly, the preservation conditions are favorable, namely the roof and floor of the shale concentration section should be tight layers with good continuity and sealing capacity.

The exploitation techniques of shale oil with low-medium maturity are obviously different from those of shale oil with medium-high maturity. Furthermore, the selection criteria of "sweet spot area/section" are also different. First, the thickness of the shale concentration section is greater than 15 m. Second, TOC is generally 6%-8%, and the kerogen is Type I-II₁. Third, the value of R_o is 0.5%-1.0%. Fourthly, the continuous distribution area is greater than 50 km², and a larger area is better. Fifthly, the shale section has good preservation conditions, with the thickness of roof and floor shielding layers being greater than 2 m, and the formation water content being less than 5%.