The main point for oil and gas exploration is to first determine the distribution of hydrocarbon source kitchens, and then the exploration which focuses on hydrocarbon source kitchens would have the greatest chance to find oil and gas reservoirs filled by the kitchens. Classical petroleum geology proposes that when oil and gas migrate away from the source rocks, a process from a deep position to a shallower one and from dispersion to enrichment occurs under the action of buoyancy, which is the key part in hydrocarbon accumulation. Therefore, conventional reservoirs are generally distributed “out-of- source”. According to oil-source correlation analysis, the minimum threshold of TOC for effective source rocks in conventional reservoirs is 0.5%^[1-2]. With the increasing difficulty in exploring for conventional oil and gas reservoirs, the exploration of unconventional oil and gas resources has become the focus of oil and gas exploration for China and overseas. Unconventional oil and gas is mostly distributed in the source area and lack the large-scale migration and enrichment or concentration of oil and gas, so the requirements for the quality and extent of source rocks are quite different from those of conventional reservoirs. Timely summarizing the characteristics of lacustrine conventional and unconventional oil and gas, especially the differences in the quality and scale of source rocks in lacustrine shale oil, and establishing the corresponding evaluation standard in advance, provides very important theoretical guiding for upcoming large-scale shale oil exploration. This will aid the selection of the sweet-spot areas and sweet-spot sections, and avoid drilling inefficient wells, ineffective wells and even dry wells. It should be pointed out that the thermal maturity of most lacustrine source rocks in China is within the “liquid window” of hydrocarbon generation, which is not favorable to the economic accumulation of lacustrine shale gas. There is no successful exploration case of lacustrine shale gas at present. We will not discuss the source focus of lacustrine shale gas, but instead will focus on the hydrocarbon source kitchen differences between lacustrine shale oil and conventional oil and gas accumulations.

Traditional oil and gas geochemical studies have systematically evaluated the main source rocks worldwide^{[3⇓⇓⇓-7]}, and clearly propose the abundance index of source rocks required for the formation of commercial hydrocarbon accumulation. Peters^[3] first proposed the source rock standard for oil and gas exploration on the basis of oilfield exploration practices, and pointed out that source rocks with TOC>0.5% are effective source rocks, and those with TOC>1.0% are high-quality source rocks. Katz^[4] counted the lacustrine source rocks worldwide, and pointed out that the average TOC value of effective source rocks was greater than 1.0%, and the hydrocarbon generation potential (S₁+S₂) value was greater than 2.5 mg/g. Huang et al.^[5] established the evaluation standard of lacustrine source rocks in China, and pointed out that the lower limit value of TOC in dark mudstone was 0.4%, and when the TOC value was greater than 1.0%, it was a good source rock. The source rock evaluation standard applied in oil and gas industry was established on this basis. Zhang et al.^[7] studied the lower limit of organic matter abundance of marine source rocks, and pointed out that the effective source rocks need not be very thick, but must reach a certain organic matter abundance (TOC>0.5%), and must have a certain distribution area. As exploration moves further into the source range, some discovery wells show significant differences in both daily production per well and estimated ultimate recovery (EUR) per well, which indicates that not all exploration wells and evaluation wells have ideal exploration results during the self-sourced system exploration. The final production performance is closely related to the quality and extent of the source rock. Therefore, how to establish the source rock standard that can guide the evaluation of shale oil enrichment areas and enrichment sections as soon as possible has become a top priority. Some scholars believe that the lower limit of TOC value in shale oil-rich areas should be 1%^[8-9], but few shale oil exploration wells that have been found meet the above standard recently, which makes the authors doubt the existing evaluation standard, and deeply feel that the hydrocarbon source kitchen standard of shale oil economic accumulation is very different from that of conventional reservoirs. By comparing the similarities and differences of source rock quality, fabric and scale between conventional reservoirs and shale reservoirs, this paper proposes source rock standard, especially TOC value standard, which is suitable for evaluation of shale oil sweet-spot areas and sweet-spot sections, in order to provide guidance for subsequent large-scale shale oil exploration. Considering that China still has different understandings of the concept of shale oil at this stage, the lacustrine shale oil referred to in this paper is the liquid petroleum hydrocarbons and multiple organic compounds in lacustrine organic-rich shale with burial depth greater than 300 m and R_o value greater than 0.5%, including petroleum hydrocarbons formed underground, various bitumen and solid organic matter that has not yet been thermally degraded. Shale oil can be further divided into two categories: medium-high mature shale oil and mid-low mature shale oil based on the maturity stage. The thermal maturity boundary between the two is R_o=1.0%^[10⇓-12]. This paper focuses on the characteristics of source rocks enriched in medium-high maturity shale oil.

Conventional oil and gas reservoirs initiated the start, rise and development of China's oil industry. As mentioned above, for conventional reservoirs, effective source rocks refer to organic-rich mudstones, shales or carbonate rocks that can generate and produce commercial scale oil and gas. Most conventional hydrocarbon reservoirs have experienced the process of hydrocarbon accumulation from dispersion in source rocks to accumulation in reservoirs, so the source rock does not necessarily contain a high abundance of organic matter, but they must have a high hydrocarbon expulsion efficiency to provide sufficient hydrocarbon for migration. Most oil fields that have been developed in China are conventional oil and gas field, and clear oil-source correlations have been established^{[13⇓⇓⇓⇓⇓-19]}. The geochemical characteristics and mineral composition of organic-rich source rocks from different basins in China are listed in Table 1.

This paper takes typical freshwater - slightly saline lacustrine basin and saline lacustrine basin as examples to discuss the corresponding relationship between conventional hydrocarbon accumulation and source rock abundance in order to compare them with the selection and evaluation of shale oil-rich areas. Among them, the freshwater-brackish lacustrine basins include the 1^st member of the Cretaceous Qingshankou Formation in the Songliao Basin (referred to as ‘Qing-1 Member’), the 3^rd member of the Paleogene Shahejie Formation in the Bohai Bay Basin (referred to as ‘Sha-3 Member’), and saline lacustrine basin examples include the upper member of the Paleogene Xiaganchaigou Formation in the Qaidam Basin and the 4^th member of the Paleogene Shahejie Formation in the Bohai Bay Basin (referred to as ‘Sha-4 Member’).

The Songliao Basin is a typical fresh - slightly saline lacustrine basin with two sets of source rocks. Oil-source correlation supports that the Qingshankou Formation (mainly the Qing-1 Member) are the most important source rocks which contributes to the discovered conventional oil accumulations^[6]. Organic geochemical test data from Well Songke-1 revealed^[14] that TOC values of the the Qing-1 Member were all over 0.5%, with the main TOC ranging from 0.9% to 5.0%, with an average value of 3.21%. (S₁+S₂) values ranged from 5 mg/g-26 mg/g, and the mean value was 18.16 mg/g. The average value of chloroform asphalt "A" is 0.52%, and the HI value is relatively concentrated, with an average value of 487 mg/g (Fig. 1a). Although Nenjiang Formation has higher organic matter abundance, it is not the main oil source of conventional reservoirs due to its low maturity.

The Qaidam Basin is a typical saline lacustrine basin. The main source rock is the upper member of Paleogene Lower Ganchaigou Formation (E₃²). A large number of previous studies have shown that the abundance of organic matter in saline lacustrine source rocks is not high, and oil and gas mainly come from “soluble organic matter”^[6,15]. The authors analyzed the newly drilled Well Yuehui-106x, and found that the organic matter abundance of the Lower Ganchaigou Formation was relatively low, and the higher abundance section was also developed^[16]. TOC values range from 0.5% to 3.0%, the maximum value is 4.69%, and the average value is 0.99%. (S₁+S₂) value is generally less than 25 mg/g, with an average value of 7.32 mg/g; The average "A" value of chloroform asphalt is 0.52%, and the maximum value is 2.35%. The maximum HI value is 925 mg/g (Fig. 1b).

The organic matter abundance of source rocks corresponding to other conventional oil reservoirs is generally similar. For example, TOC of the Sha-3 Member in the Jiyang Depression of the Bohai Bay Basin is between 0.5% and 3.5%, and that of the Sha-4 Member is between 1.5% and 4.5%^[17]. The TOC value of source rocks of Fengcheng Formation in the Junggar Basin is 0.6%-3.0%, with an average of 1.63%^[18]. The main TOC value of Cretaceous source rocks in Jiuquan Basin is 0.5%-3.0%^[19].

The above statistics show that the TOC threshold of effective source rocks corresponding to conventional reservoirs is 0.5%, and the main source rocks range from 1.0% to 3.0%. (S₁+S₂) values are in the range of 4-20 mg/g.

Conventional oil and gas abroad mainly come from marine source rocks. In the immature stage, the HI value is generally about 600 mg/g, and the H/C atomic ratio is generally less than 1.2, belonging to type II organic matter^[8-9]. Conventional oil reservoirs in China mainly comes from lacustrine source rocks, and the organic matter is mainly lacustrine aquatic algae, mixed with a small amount of terrigenous organisms. The source rocks in the Qing-1 Member of the Songliao Basin and E₃² of the Qaidam Basin are rich in sapropelic components. Laminated algae can be found in low maturity samples, and even clear organic matter-mineral intercalated algal laminae can be found in local organic-rich layers (Fig. 2). Most samples are dominated by amorphous sludge, and the content generally exceeds 60%. Rock pyrolysis and kerogen element analysis showed that the HI value was up to 1000 mg/g at the immature stage, and the atomic ratio of H and C was up to 1.6, which was much higher than that of marine source rocks, showing extremely high oil-generation potential.

There is a good positive correlation between the kerogen type and the abundance of immature-low maturity source rocks. When TOC<0.5%, theHI value of fresh water - brackish water lacustrine source rocks is mostly lower than 100 mg/g, showing type III kerogen. When the TOC value is 0.5%-1.0%, type II₂ kerogen is dominant. When the TOC value is 1%-3%, it is mainly type II₁ kerogen. When TOC > 3%, the HI value is more than 600 mg/g, mainly type I kerogen (Fig. 3a, 3b). For saline lacustrine source rocks, organic matter is generally rich in hydrogen due to better preservation conditions, and HI values are generally high. Source rocks with TOC>1% are dominated by type I and II₁ kerogen (Fig. 3c, 3d). In this paper, some samples of mid-low maturity source rocks (T_max value of 430-440 °C) are selected, and the analysis results are presented on a source rock type chart. It can be seen that the source rocks in the Cretaceous of the Songliao Basin, Paleogene of Qaidam Basin and Bohai Bay Basin are dominated by type I and II₁ (Fig. 4a, 4c, 4d), while the source rock in the Sha-3 Member of the Bohai Bay Basin is dominated by type II₁ and II₂ (Fig. 4b).

The thermal maturity of organic matter is an important aspect of source rock evaluation, and also an important guarantee for the success of out-of-source conventional oil and gas exploration. Maturity not only determines the amount of generated and produced oil and gas from source rocks, but also determines the density, viscosity and phase state of oil and gas. If the maturity is higher, the oil will be lighter and easier to flow. However, if the maturity is too high, liquid hydrocarbon can be cracked to natural gas, and eventually carbonization.

The lacustrine source rocks in China are generally in the relatively low maturity stage, and a few source rocks can reach the medium-high maturity or over-mature stage. Large-scale source rocks with moderate maturity are generally developed in the vicinity of discovered reservoirs^[6]. The differences between basin types and tectonic evolution can lead to great differences in burial depth and geothermal history of source rocks, so the maturity of organic matter will be significantly different. The R_o value of source rock in the 7^th member of the Yanchang Formation (referred to as “Chang-7 Member”) in the Ordos Basin is 0.7%-1.1%, and the maximum R_o value in the center of the lacustrine basin is 1.3%^[13]. The R_o value of source rocks near the Changyuan in the Songliao Basin is about 0.7%-1.3%, and the highest value in the center of the lacustrine basin is 1.5% or even higher^[14]. The R_o value of hydrocarbon source rocks in the Bohai Bay Basin is generally 0.5%-1.3%, which can reach 1.6% in some areas^[15]. The R_o value of the source rocks in the western Qaidam Basin is mainly 0.6%-1.0%, and the R_o value in the eastern section of the Yingxiongling structural belt can reach 1.2%^[17].

Based on the above results, it can be concluded that the effective source rock abundance threshold for conventional oil and gas accumulation is TOC of 0.5%, and the favorable interval TOCvalue is 1%-3%. The organic matter type is oil-rich kerogen, mainly type I and type II₁ kerogen. The maturity of organic matter is moderate, and the R_o value is mostly 0.7%-1.2%, which is within the range of oil generation window and has a certain scale.

Unlike marine shale oil, which is mainly distributed in marine organic-rich tight clastic rocks and carbonate rocks, shale oil in China is mainly spread through lacustrine organic-rich shale system, which is generally characterized by a high abundance of organic matter, low-mid thermal maturity and large variation in clay content. At present, China's lacustrine shale oil exploration is still in the initial stage. Although it has been observed in the early shale oil exploration of multiple basins, the corresponding evaluation standard of shale oil sweet-spot areas and sweet-spot sections, especially the source rock evaluation standard of shale oil with economies of scale, have not been determined. This will undoubtedly cause explorationists to spend more time and costs in selecting the correct target area and the main target interval. Up to now, the regions and strata systems where terrestrial medium-high maturity shale oil is being tested include the Triassic Chang-7 Member in the Ordos Basin, the Cretaceous Qingshankou Formation in the Songliao Basin, the Permian Lucaogou and Fengcheng Formations in the Junggar Basin, and the Paleogene Shahejie and Kongdian Formation in the Bohai Bay Basin^{[20⇓⇓-23]}. In general, the quality and distribution of source rocks determine the hydrocarbon generation capacity of source rocks and the content of in-source hydrocarbon retention^[24⇓-26]. The relevant evaluation is of great significance for clarifying the potential, mobility and sweet-spot area of shale oil resources. This paper focuses on the high-maturity shale oil in the Chang-7 Member of the Ordos Basin, the Lucaogou Formation of the Junggar Basin and the Kongdian Formation of the Bohai Bay Basin, and discusses the quality requirements of the source rocks for in-source shale oil enrichment.

The TOC value of mudstone in the Chang-7 Member of the Ordos Basin ranges from 2%-6%, with an average value of 3.74%. TOC values in organic-rich shale segments of 6%-32%, with an average of 13.81% (Fig. 5a). The HI value is generally 400-600 mg/g, and the highest value of some samples is 800 mg/g. R_o value of 0.5%-1.2%, and the distribution range of R_o value greater than 1.0% is relatively small, which is mainly dominated by mid-low maturity shale oil. Although the total amount of medium-high maturity shale oil is not low, the resource amount is relatively small compared with the mid-low maturity shale oil. The TOC value of organic-rich shale in the Permian Lucaogou Formation in the Junggar Basin is 2%-14%, up to 22%; R_o value was 0.7%-1.2%; The maximum HI value was 1000 mg/g (Fig. 5b). The TOC value of the 2^nd member of the Kongdian Formation (referred to as the ‘Kong-2 Member’) in the Bohai Bay Basin ranges is 3%-10% and reaches up to 13%. R_ovalue was 0.6%-1.1%. The HIvalue reached a maximum of 850 mg/g (Fig. 5c). The TOC value of the Qing-1 Member shale in the Songliao Basin is mainly 1%-5%, and an individual sample is as high as 10%; the R_ovalue is 0.7%-1.3%, and the highest is more than 1.5%. The HIvalue reached a maximum of 900 mg/g (Fig. 5d).

The TOC of source rocks corresponding to the above four shale oil formations is significantly different from that of HI. When the TOC value of the Chang 7 Member shale is 1%-5%, HI is positively correlated with TOC. When TOC>5%,HI remains relatively stable, and no longer increases with increasing TOC value. The HIvalue of the high TOC value section is maintained at 400-600 mg/g (Fig. 5a). The HI value of the Lucaogou Formation shale shows a higher hydrocarbon generation potential when the TOC value is low. As the TOC value increases, especially when the TOC value is greater than 5%, the TOC and HI gradually show a positive correlation (Fig. 5b). The positive correlation between HIand TOC in the Kong-2 Member of the well is the most significant, with a linear relationship, and the highest HI value is 800 mg/g (Fig. 5c). HIincreased linearly with the increase of TOC, when TOC > 6%, HI value remained at about 800 mg/g and no longer increased (Fig. 5d). For lacustrine shale oil exploration in China, the evaluation of sweet-spot areas and sweet-spot sections should approve lower TOC limits to ensure sufficient hydrocarbon retention and higher formation energy. According to the classification standard of high quality source rock, the minimum TOC value of the Chang-7 Member should be greater than 5%, the minimum TOC value of the Lucaogou Formation should be greater than 3%, the minimum TOC value of the Qing-1 Member should be greater than 3%, and the minimum TOC value of the Kong-2 Member should be greater than 8% (Fig. 5). Therefore, the lowest limit of TOC value in the sweet-spot area and sweet-spot section of medium-high mature shale oil in lacustrine facies should be 2%, and the optimal interval should be 3%-5%. For mid-low maturity shale oil, the lower limit of TOC is higher, preferably greater than 6%-8%, and the higher the TOC is, the better it is^[10].

Good organic matter type is also important for shale oil enrichment. If the HIvalue of low maturity source rock is higher, the organic type is better, and the effective carbon ratio of oil generation is higher. It can be seen from Fig. 6 that the lacustrine shale in China is mainly type I—II₁kerogen, with HI values of 150-800 mg/g and OI values less than 20 mg/g. Microscopic observation also showed that the kerogen was dominated by amorphous forms, accounting for 85%-99%, with a small amount of morphological components (derived from coccodia) and sporophytes, and the content of terrestrial organic components such as vitrinite was low, indicating that the organic parent material was mainly lacustrine small organisms (algae), which were conducive to oil generation^[27⇓-29]. It should be noted that the relationship between HIand TOC of the low-maturity source rocks in the Chang-7 Member of the Ordos Basin is not completely positive. The high-quality source rocks with TOC>5% haveHI values of 400-600 mg/g, which is typical of type II₁ kerogen, and may be related to the preservation conditions of the organic matter. The biomarkers of crude oil generated by the source rocks of the Chang-7 Member are rich in rearranged steranes and hopanes, indicating that the organic matter experienced acidic catalysis of clay minerals, resulting in a large number of deoxidation and dehydrogenation reactions within the organic matter during diagenesis, which is related to the acidic environment of the source rocks and their rich clay content^[13,30]. The oil and gas generated by these type II kerogen source rocks have lower relative molecular mass, lower density and viscosity, and producing fluids that are easier to flow, which is beneficial to obtain higher single well production rates.

Thermal maturity has an important impact on shale oil accumulation, enrichment, and the amount and composition of hydrocarbons. The hydrocarbon evolution of lacustrine source rocks is similar to that of marine source rocks, which conforms to the Tissot model and can be divided into immature (R_o<0.5%), low-mature (0.5%≤ R_o<0.7%), mature (i.e. liquid window, 0.7%≤R_o<1.3%), high-mature (condensate-wet gas, 1.3%≤R_o<2.0%) and over-mature (dry gas, R_o≥2.0%) stages. Zhao et al.^[10] proposed the differences in the types and quantities of in-source retained hydrocarbons at different evolutionary stages, which can be divided into four stages: (i) R_o<0.5% is the solid distribution section of organic matter, which is also the main distribution section of oil shale oil; (ii) When the R_o value is 0.5%-1.0%, it is the coexistence section of retained liquid hydrocarbon, multi-asphaltenes and unconverted organic matter, that is, the distribution section of middle and low maturity shale oil. In this stage, the amount of liquid hydrocarbons in shale varies greatly due to the thickness of the shale and the interlayering relationship with surrounding rock reservoir (transport) layers. The maximum content of retained hydrocarbons is 40%-60%, and the unconverted and polymer semisolid organic matter content is 40%-80%. (iii) R_o value of 1.0%-1.6% is the main stage of high molecular weight liquid hydrocarbon cracking to form low molecular weight compounds (including natural gas), which is the distribution section of medium-high mature shale oil. The general oil is light, and the gas-oil ratio is relatively high. (iv) R_o>1.6% is the stage where large amounts of liquid hydrocarbon cracking and large amounts of natural gas generation occur, which is the main distribution member of shale gas. In general, the thermal maturity of lacustrine shale oil in China is generally low, which may be one of the main reasons why the exploration and development of shale oil has not yet reached large-scale achievement. The thermal maturity of the Chang-7 Member shale in the Ordos Basin varies widely, with R_o value of 0.5%-1.3%, in which the R_o<1.0% occupies a large area, accounting for about 90% of the total distribution area of the shale. The R_o value of source rocks of the Permian Lucaogou Formation in the Junggar Basin and the Paleogene Kong-2 Member in the Bohai Bay Basin is 0.7%-1.0% and 0.8%-1.1%, respectively. According to statistics, those exploratory wells that match the higher maturity window show good mobility. For example, the thermal maturity of the Permian Fengcheng Formation in the Junggar Basin is higher than that of the Lucaogou Formation, and the main R_o value is 0.9%-1.4%, the density of crude oil is 0.85-0.87 cm³/g, which is lower than the 0.90-0.92 cm³/g of the Lucaogou Formation. With the decreased viscosity, the fluid mobility is greatly promoted. Therefore, higher thermal maturity can effectively improve the oil quality, increase the gas-oil ratio, and improve the underground mobility of crude oil. Thus, the development of medium-high mature shale oil mainly depends on horizontal wells and volume fracturing technology, which requires higher maturity to maintain light oil quality and a more highly movable oil ratio. Therefore, the R_o value should be greater than 1.0%, and 1.0%-1.4% is optimum.

The in-source oil and gas accumulations are characterized by “in-source generation, in-situ retention and enrichment”, and the evaluation of the quantity of the retained shale hydrocarbons has become the focus of the economic viability of shale oil^[10⇓-12]. The amount of retained hydrocarbon in source rocks is closely related to the abundance of organic matter, thermal maturity and hydrocarbon expulsion efficiency. Many scholars have discussed hydrocarbon expulsion efficiency from the perspective of comprehensive geochemical and geological evaluation^{[24⇓-26,31⇓ -33]}. Obviously, the amount of retained hydrocarbon will be higher with the thicker source rock, less interaction between the source rock and the transport layers, the less fractures, the lower hydrocarbon expulsion efficiency, and vice versa. It is necessary to make a comprehensive analysis of the thickness, lithological combination and tectonic conditions of the source rocks in order to correctly evaluate the amount of retained hydrocarbon in the source rocks. The amount of retained hydrocarbons obtained without accurately evaluating the sampling points and the surrounding geological conditions of the source rock may not represent the actual underground retained hydrocarbons. Therefore, the economic evaluation of shale oil will inevitably fall into a misunderstanding. Through simulation experiments and theoretical calculations, it is found that under the effect of hydrocarbon generation pressurization, the proportion of hydrocarbon expulsion from source rocks in total hydrocarbon generation is positively correlated with the abundance of organic matter, the original hydrocarbon generation potential of organic matter (mainly controlled by the type of organic matter), and the maturity of organic matter^[34]. It should be noted that despite the relatively low proportion of retained hydrocarbons in high TOC source rocks, the amount of retained hydrocarbons is much higher than that of low TOC source rocks due to the large amount of total hydrocarbon generation. A large number of worldwide exploration practices and studies have confirmed that the retained hydrocarbon of source rocks in the “liquid window” is generally 40%-60%, with an average of about 50%. If the source rock thickness is larger, and there are no good connectivity between source layers and transport layers, the amount of retained hydrocarbon in the source rock will be larger. In-source liquid hydrocarbon retention is not only the main contributor to shale oil, but also the main parent material of light oil and natural gas formed by thermal decomposition of polymer organic compounds under in-situ heating conditions. For deep oil and gas, retained hydrocarbons are also a high-quality gas source for conventional gas and shale gas accumulation in the high/over-mature stage^[24⇓-26].

The lithological combinations of source rocks are different in freshwater lacustrine basins and saline lacustrine basins. The source rocks in the freshwater lacustrine basins are mainly organic-rich shales, with high clay content, and local silty and fine sandstone interlayers, accounting for less than 30% of the formation thickness. The saline lacustrine basin is dominated by mixed sedimentary rocks, with interbedded organic-rich shale and carbonate rocks, which are characterized by frequent interbedded shale, silty mudstone, sandy dolomite, dolomite and limestone. The source rocks in freshwater lacustrine basins are rich in clay minerals and have strong plasticity, which limit fracture formation. The interlayer of fine-grained sandstone and siltstone is the main channel for oil and gas expulsion. With the increase of organic matter abundance, the adsorption on clay minerals and organic matter in source rocks on hydrocarbon generation increases, resulting in a significant increase in retained hydrocarbon content. Since the high TOC source rocks are mostly formed in the quiet environment of the water body, there are few interlayers of fine sandstone and siltstone, and the oil and gas are not expelled smoothly, resulting in a high proportion of retained hydrocarbon in the total hydrocarbon generation potential. For example, the Chang-7³ sub-member of Well L85 in the Longdong area of the Ordos Basin is the major member of shale oil, which is dominated by thick organic-rich shale. The upper part contains about 10 m thick mudstone, and 2-3 fine sandstone and siltstone interlayers are developed between them. The thickness of a single sandstone layer is less than 2 m, with a proportion of about 10%. According to the analysis data, the amount of retained hydrocarbon in this shale is about 15-30 mg/g (Fig. 7).

As mentioned above, with different organic matter abundance, the amount of retained hydrocarbons in the source rock is necessarily variable. The higher the abundance and type of organic matter, the more contents of oil and gas can be produced per unit of organic carbon. The hydrocarbon expulsion ratio and retained hydrocarbon amount of the source rocks are related to TOC, and there is an optimal range of TOC value. Taking the Chang-7 Member of the Ordos Basin as an example, when TOC value increases from 2% to 8%, expelled hydrocarbons increase from 1.5 mg/g to 12 mg/g. However, when TOC >8%, the expelled hydrocarbons did not increase significantly (Fig. 8). It can be seen that as the TOC value increases, the proportion of retained hydrocarbons in the organic-rich shale first decreases and then increases, and the hydrocarbon expulsion will be harder with the higher TOC value, resulting in more hydrocarbons remaining in the shale. The R_o value of the Chang-7 Member in Well L85 and Well C30, which are coring wells recently completed in the Ordos Basin, is 0.8%. The field measurement shows that the free gas volume is high, with the maximum value of 1.7 m³/t, and the average is 1.0 m³/t. The shale oil content is 8.80-26.77 mg/g with an average of 18.70 mg/g. The average content of the C_16- light component is 5.54 mg/g, accounting for 31.4% of the total oil content. The overall retained hydrocarbon generation potential is high, and the retained hydrocarbon generation potential of shale with TOC>6% is 27.53-132.23 mg/g, with an average of 63.88 mg/g.

Under the same thermal maturity condition, if the content of heavy components in the retained hydrocarbons of the source rock is higher, the viscosity will be greater, the adsorption of hydrocarbons will be stronger, and the mobility will be worse. In addition, the content of petroleum hydrocarbon waxes generated by terrestrial source rocks is generally high, which is also an important factor to increase the crude oil viscosity. Therefore, while paying attention to the abundance of organic matter in source rocks, we should also pay attention to the composition of retained hydrocarbons, which have a direct impact on the daily production of a single well and for the cumulative recovery of lacustrine shale oil. The obvious fractionation effect occurs in the process of hydrocarbon expulsion in source rocks, which leads to the obvious difference in the group composition of the retained hydrocarbons and the expelled hydrocarbons. Among them, the proportion of saturated hydrocarbons and aromatic hydrocarbons expelled from a source rock is higher and easier to flow, while the soluble organic matter retained in source rock is rich in non-hydrocarbons and asphaltenes, with high viscosity and poor mobility. Taking Well Yuehui-106x of the E₃² in the Qaidam Basin as an example, the resin and asphaltene in retained hydrocarbons are significantly higher than those in crude oil, and the content of heavy components is also significantly higher than that of crude oil (Fig. 9). The abundance of naphthenic hydrocarbons heavier than C₂₇ is also higher than that of crude oil, indicating that the former may have higher wax content and viscosity. Among them, the ratio of (C₂₁+C₂₂) to (C₂₈+C₂₉) of crude oil is 1.18, and the ratio of retained hydrocarbons is 0.89, indicating that more light components are expelled from hydrocarbons (Fig. 10).

The mineral composition not only has an effect on the fracturing potential of the shale, but also has an important influence on the amount of retained hydrocarbons in the shale. The successful exploitation experience of marine shale oil and gas in North America shows that shale with a high content of brittle minerals such as quartz and carbonate has good fracturing properties, which is of great significance to the exploitation of medium-high mature shale oil. Core observation and rough grinding of rock samples show that the organic-rich shale in the saline lacustrine basin of the Junggar Basin is harder and more brittle than the organic-rich shale in the Chang-7 Member of the Ordos Basin^[28-29]. The main difference between the two shale systems is the difference in carbonate and clay mineral content, and different TOC values also have a certain influence on the mineral distribution. X-ray diffraction mineral analysis shows that the content of brittle minerals, such as quartz, feldspar, carbonate, and pyrite, in the layer with TOC values greater than 6% in the Chang-7 Member of the Ordos Basin, account for 43.9%-85.3% of the total mineral content, while the clay mineral content is low, accounting for less than 40%, with an average of 30%. When the TOC value is less than 6%, the clay mineral content of shale is 30.9%-56.1%, with an average of 42.8%. The Lucaogou Formation in the Junggar Basin has a high carbonate mineral content and a very low clay mineral content. The brittle minerals such as carbonate minerals, feldspar and quartz account for 80%-90% of the total mineral content, and the clay mineral content is 10%-20%. The samples with clay mineral content less than 10% account for 30%.

The statistical data show that the mineral composition of lacustrine shale in China plays an important role in controlling the retained hydrocarbon content and hydrocarbon generation potential of shale. Overall, (S₁+S₂) values are negatively correlated with clay minerals and carbonate mineral content (Fig. 11). In the Chang-7 Member of the Ordos Basin, the value of (S₁+S₂) decreases from 45 mg/g to less than 5 mg/g as the clay mineral content increases from 35% to 60%. In the Lucaogou Formation of the Junggar Basin, the value of (S₁+S₂) decreases from 70 mg/g to less than 20 mg/g with the increase of carbonate mineral content from 10% to 60%. It should be noted that compared with the Lucaogou Formation and Chang-7 Member, high clay mineral content has a greater influence on the decrease of retained hydrocarbons and hydrocarbon potential, while carbonate minerals have a relatively weak correlation with the decrease of retained hydrocarbons and hydrocarbon potential.

In terms of pore structure, the pores in lacustrine shales are mainly clay mineral in-granular pores, feldspar and carbonate dissolution pores, and dolomite intergranular pores. There is few organic pore^[35⇓-37]. Therefore, if the content of non-clay minerals is high in the shale with high TOC value, the adsorption of clay minerals and their in-grain pores on retained hydrocarbon is reduced to a certain extent. However, the retained hydrocarbons generally occur in an adsorbed state within organic matter and pyrite surfaces, or in a free state in inter-granular and intra-granular pores of larger non-clay minerals (Fig. 12).

The current production of lacustrine medium-high mature shale oil is not stable enough, and the decline rate also varies greatly. The existing exploration practice shows that the factors affecting shale oil production include internal and external factors. External factors include drilling methods, production stimulation measures and development techniques, such as horizontal section length, fracturing scale, external energy supplement (such as additives added with fracturing). Internal factors refer to the geological conditions of shale oil, including the development and detachability of shale, thermal maturity level, fluid mobility and shale transformability, including the composition of retained hydrocarbons, shale porosity, reservoir brittleness, formation pressure and fluid properties, etc. Considering that there are great differences in drilling and completion methods and development technology of shale oil in different regions, this paper focuses on the influence of internal factors on single well production of shale oil, especially the influence of source rock quality on shale oil production. The quality of source rock controls the content, composition and gas-oil ratio of retained hydrocarbons in shale formations, and affects the effective storage space and formation pressure. The above factors will directly influence the effect of volume stimulation of shale reservoirs and the selection of development technology, and then have an important impact on single well production of shale oil.

The TOC value of organic-rich shale is significantly different from that of mudstone due to the different original sedimentary environment^[12]. Therefore, the amount of retained hydrocarbon, the content of brittle minerals, the formation pressure and the gas-oil ratio are generally higher than that of mudstone, which is the reason why the sweet-spot areas and sweet-spot sections of shale oil are mainly distributed in shale sections with high TOC values. In the relatively pure shale section of the Chang-7 Member in the Ordos Basin, 29 test wells and 13 industrial oil flow wells were transformed by vertical well volume fracturing. From the perspective of plane distribution, 70% of industrial oil flow wells are located in the distribution area of organic-rich shale with TOC value greater than 6%. Among them, Well N148 has the highest oil test yield, reaching 24.23 t/d, and the thickness of the organic-rich shale is more than 20 m. In the Kong-2 Member of the Cangdong Sag, the test production rate is closely related to the thermal maturity and the gas-oil ratio. For example, the longest production time of the Well G1702H has been since May 28, 2018. The production time of this well is more than 2 years, and the cumulative oil production is 1.2×10⁴ t and the cumulative gas production is 61.6×10⁴ m³. The well is shut in temporarily, and it is expected that the accumulative oil production of the well will reach 2.65×10⁴ t. The thermal maturity of organic-rich shale in this well is relatively high, with R_o greater than 0.9% in total, and the corresponding oil viscosity is 10.4 mPa·s (50 °C), which is less than 22 mPa·s (50 °C) of the adjacent well. Meanwhile, the gas-oil ratio is greater than 100 m³/m³, indicating that the higher thermal maturity is conducive to the improvement of fluid mobility and higher cumulative recovery. Economy is the key to determine the scale of shale oil exploration and production. However, due to the short history of shale oil production, the economic development of shale oil is still in the initial evaluation stage, and a longer period of trial production is needed to analyze and summarize. Considering the differences of geological conditions in different regions, economic evaluation of shale oil should be carried out according to specific geological conditions and oil prices, the focus should include three indicators: (i) The daily production of a single well must be economical; (ii) The cumulative output of a single well should also achieve economic efficiency; (iii) The shale oil sweet-spot area should have a certain scale to ensure the minimum economic production and stable production for a long enough time (8-10 years is appropriate). Therefore, in order to ensure the economic efficiency of the cumulative production of a single well, the evaluation of effective in-source rock includes at least the following factors: (i) the abundance of source rock, parent material type and thermal maturity. 2% is the lowest limit of TOC, and 3%-5% is the best. The main organic parent material was type I—II₁, which is in the thermal maturity window of R_o>1.0%. (ii) Lithologic combination and rock-forming mineral composition. The favorable lithologic combination of shale oil is shale, and mudstone is not the favorable lithologic section for economic mineralization of shale oil. The rock-forming minerals contain high contents of quartz and carbonate, and the proportion is greater than 50%-60%; (iii) The development of lamination, multi-genesis microfractures and matrix pores in the hydrocarbon source kitchen area.

The quality requirements of source rocks are different due to the different process of hydrocarbon retention and accumulation in the out-of-source conventional reservoirs and in-source shale reservoirs. The conventional hydrocarbon reservoir is the product of the sweet-spot and accumulation process of the oil and gas expelled from the source rock. The TOC value of the source rock is not necessarily high, but must have high hydrocarbon expulsion efficiency and sufficient hydrocarbon expulsion amount. Shale oil is mainly the retention of in source formed oil and gas. The quantity and quality of shale oil determine the economic output and cumulative recovery of shale oil. It is required that the abundance of organic matter in the source rock must reach a certain threshold and the parent material type must be good. For medium-high mature shale oil, the lower limit of TOC value should be 2%, the best window is 3%-5%, and the R_o value is greater than 1.0%; For medium-low mature shale oil, the lower limit of TOC value should be 6%, and it will be better if the value is higher, the R_o value is less than 1.0%. At the same time, the distribution range of organic-rich shales should be large enough to ensure minimum economic output and stable production of 8-10 years.

The evaluation of source rocks in out-of-source conventional reservoirs should pay attention to hydrocarbon generation and accumulation, especially accumulation. The evaluation of in-source shale oil should focuse on the quality of source rocks, and the amount of hydrocarbon generation and retention, especially the amount of retained hydrocarbons. In addition, the quality of in source retained hydrocarbons have an important influence on single well production rates and the cumulative production of shale oil, which is not only related to the type of organic matter, but also closely related to the thermal maturity and preservation conditions. Therefore, sufficient attention should be paid to the lithology, thickness and preservation conditions of source rocks in the evaluation of lacustrine shale oil. Those organic-rich shales with well-developed shale intervals and thickness greater than 8-10 m and well-preserved top and bottom are essential for the economic mineralization of medium-high mature shale oil and mid-low mature shale oil. Mudstone is neither a middle-high-mature shale oil nor a favorable lithological section for economic mineralization of middle-low-mature shale oil, so it is necessary to avoid dealing with it from the beginning of exploration.

In order to reach the economic exploitation threshold of lacustrine shale oil, it is necessary to meet three indexes: (i) The daily production of single well must reach the economic threshold; (ii) The cumulative oil output of single well must be economical, that is, the total costs of the whole well must be recovered after the sale of the produced oil, and there is a certain return on the internal income index; (iii) The distribution range of shale oil sweet-spot section should have a certain scale to ensure the minimum economic output of construction and stable production of 8-10 years.

HI—hydrogen index, mg/g;

OI—oxygen index, mg/g;

S₁—free hydrocarbon content in the rocks, mg/g;

S₂—pyrolysis hydrocarbon amount in the rock, mg/g;

T_max—the peak temperature of rock pyrolysis, °C.