Shale oil refers to the oil occurring in shale-dominated strata (shale and thin non-source rock interbeds). Shale oil occurs widely in the Daqing, Jilin, Shengli, Liaohe, Jianghan and Nanyang oilfields in central and eastern China^{[1,2,3,4,5,6,7,8]}. Shale oil is the most challenging resource in terms of science and technology, and may be a revolutionary among unconventional oils and the first to succeed in China^[9]. However, the horizontal well and large-scale fracturing copied from shale gas development don’t work so well in shale oil development. For example, Well BYP1, a well drilled specially for shale oil development in the Shengli Oilfield, had an initial oil production of only 8.22 m³/d after two times of fracturing, which quickly dropped to 1.6 m³/d. The well has a cumulative oil production of only more than 100 m³. The wells BY-HF1 and BY-2HF known as the wells with the best performance and the first major breakthrough to continental shale oil in China witnessed fast drop of production to about 1 m³/d, although they delivered high oil flows of 23.6 m³/d and 32.0 m³/d, respectively, after being fractured from the shale layers in Biyang sag of Nanyang Oilfield. Because of high drilling/operating cost, the current shale oil production is far short of commercial development value^[7,10-11]. The root cause is that strong adsorption between shale oil and mineral/organic matter, and its higher viscosity than shale gas, restrict its mobility in shale, thus affecting its recovery. Mobility of shale oil is also related to the molecular composition, occurrence state and occurrence space of shale oil, therefore, evaluation of the occurrence mechanism (amount, state and pore size) and mobility of shale oil is of great significance for selecting favorable target areas and making development plan.

Previously, researchers mainly tried to reveal the factors controlling the enrichment of shale oil in the Jiyang depression from macroscopic analysis of well location and production, lithofacies, overpressure, fracture development, interlayer, porosity, permeability and movability (S₁/TOC) of shale oil^{[12,13,14,15,16,17]}, and found that lamellar shale was favorable for shale oil and gas development; high pressure, interlayer, fracture development and mobility were factors controlling local high production of shale oil. In terms of the occurrence mechanism of shale oil, molecular simulation was used to reveal the adsorption mechanism of shale oil/alkanes at micro-scale^[18,19], and it was found that there were four adsorption layers of crude oil (n-decane) in nano-fractures in quartz. The methods studying occurrence state of shale oil include direct and indirect methods. Direct methods, like scanning electron microscopy (SEM), environmental scanning electron microscopy (E-SEM), CT scanning, electron beam charge effect, energy spectrum and other technologies, can observe and simulate oil directly to find out the occurrence states and pore types of oil^[20]. Indirect methods, like nuclear magnetic resonance (combined with centrifugal/displacement), Rock-Eval pyrolysis experiment, extraction experiments with different polar solvents and molecular dynamics simulation, characterize the pore diameter, occurrence state and content of oil^{[19, 21-27]}. It is recognized that shale oil exists in adsorbed, free and soluble (dissolved) states.

In this work, the occurrence mechanism of shale oil in the Paleogene Shahejie Formation of the Jiyang depression is investigated, the relationship between the ratio of adsorbed state to free state shale oil and depth established, and the factors influencing shale oil mobility are sorted through experiments of shale organic geochemistry, thin sections, low temperature nitrogen adsorption, high pressure mercury intrusion and field emission scanning electron microscopy, in the hope to provide reference for selecting shale oil “sweet spot” intervals. In addition, the ratio of adsorbed oil to free oil established is expected to provide parameters in evaluating the potential of shale oil resources in different occurrence states.

Located in the southeastern part of the Bohai Bay Basin, the Jiyang depression consists of the Chezhen, Zhanhua, Huimin and Dongying sags and uplifts between them, with an area of about 2.5×10⁴ km². The Dongying sag is the largest (about 6 000 km²). On the plane, it is a NE complex half- graben with fault in the north and overlap in the south, deeper in the north and shallower in the south. The nearly EW and NE tensional and torsional large faults in the north control its sedimentary structure. Its tectonic evolution experienced rifting stage, faulting stage and depression stage^{[5, 28-29]} (Fig. 1a). The upper sub-member of the fourth member of the Shahejie Formation (hereinafter referred to as Es₄) and the lower sub- member of the third member of the Shahejie Formation (hereinafter referred to as Es₃) of Paleogene in the Dongying sag have good shale oil and gas shows. Es₄¹ (Shahejie Formation upper sub-member) is saltwater- brackish lacustrine deposit, and composed of grayish-brown calcareous laminar and stratified mudstone interbedded with marl and dolomite etc.^[30] During early Es₃, the lake basin enlarged, the basin faulting strengthened and the accommodation space became larger, so Es₃¹ (Shahejie Formation lower sub-member) is freshwater-brackish lacustrine deposit. In this study, samples were taken from six wells, including Well LY1, Well NY1 and Well FY1 in the Dongying sag (Fig. 1b-1d), Well Wang31, and Well XYS9 and Well Luo67 in the Bonan sub-sag of the Zhanhua sag. Detailed information on the sedimentary environment, lithology and structure of the Shahejie Formation in the Bonan sub-sag were discussed in references [4, 31-32].

In this study, totally 68 samples were collected from six wells (Fig. 1) to conduct experiments of TOC, conventional pyrolysis, stepwise pyrolysis, X-ray diffraction (XRD) and thin section observation. Based on the above experimental results, the shale lithofacies was divided according to organic matter abundance, rock composition and sedimentary structure. Afterwards, 35 samples were selected according to lithofacies to conduct experiments of nuclear magnetic resonance, field emission-scanning electron microscopy (FE-SEM), low-temperature nitrogen adsorption and high-pressure mercury intrusion. Conventional pyrolysis, TOC, chloroform extraction and XRD experiments are all common analysis items, please see relevant literatures [4, 33-34] for the experimental procedures.

(1) Stepwise pyrolysis. The sample was crushed to 124-150 μm (100-120 mesh) and 100 mg powdered sample was taken for pyrolysis analysis with a Rock-Eval 6 instrument. The product S_1-1 was tested after the sample was heated to and kept at 200 °C for 1 min; and then the sample was heated to 350 °C at the temperature rise rate of 25 °C/min and kept at 350 °C for 1 min, then the product S_1-2 was tested. After 350 °C, the sample was heated to 450℃ at the temperature rise rate of 25 °C/min and kept at the temperature for 1 min, and then the product S_2-1 was tested. After exceeding 450 °C, the sample was heated to 600 °C at the temperature rise rate of 25 °C/min and then the product S_2-2 was measured. S_1-1 stands for movable oil, (S_1-1+S_1-2) for free oil (i.e. the maximum movable oil), S_2-1 for adsorbed oil, and S_2-2 for kerogen cracking oil^[25]. It should be noted that, strictly, the product, such as free oil, obtained by the hydrogen flame ionization detector in the Rock-Eval is actually free hydrocarbon, while the product obtained by other means, such as oil washing/extraction, is oil (hydrocarbon + non-hydrocarbon), referred as movable oil, free oil and adsorbed oil in this paper.

(2) Low-temperature nitrogen adsorption. The experiment process is as follows: the sample was crushed to 150-178 μm (80-100 mesh)→dehydrated in an oven (110 °C, 3-4 hours) →vacuumed at high temperature →nitrogen adsorption experiment → washed oil for one week (volume ratio of dichloromethane/acetone=3:1) →dehydrated in an oven (110 °C, 3-4 hours)→vacuumed at high temperature → nitrogen adsorption experiment. See reference [34] for detailed procedure of low- temperature nitrogen adsorption experiment and data processing.

(3) High-pressure mercury injection experiment. Unlike conventional high-pressure mercury intrusion experiment using crushed samples, in this study, this experiment was done on core plugs (1.5 cm in diameter) cut with the SK5625A corundum (grain size of 0.38 mm) NC wire-cutting machine tool in the direction vertical to the sample bedding. Two small core plugs with smooth surface and without cracks, 1.5 cm in diameter and 1.5 cm in length, were made from one sample. One core plug was used for high-pressure mercury injection experiment after washing oil using the same method with the low-temperature nitrogen adsorption experiment; the other core plug was used for high-pressure mercury injection experiment without washing oil. The smooth surface of the core can eliminate Pockmark effect during the experiment. See reference [5] for detailed procedure of the experiment and data processing method.

In this study, the lithofacies of the samples were divided according to organic matter abundance, sedimentary structure and rock composition^[13,17,35]. According to organic matter abundance, the samples are divided into organic-rich shale (TOC>2%), organic-bearing shale (TOC=1%-2%), and organic-lean shale (TOC<1%). Through observation of 68 shale core samples and thin sections, it is found that the samples can be divided into laminar (less than 1 mm thick per layer), bedded (more than 1 mm thick per layer) and massive (with no lamina) shale. According to rock mineral composition, the samples are mainly divided into argillaceous limestone, limy mudstone and mudstone. Previous statistics show that 73% of the shale oil producing intervals in Jiyang depression are lamellar argillaceous limestone and lamellar limy mudstone^[14], so the samples used in this study were dominated by organic-rich lamellar argillaceous limestone, followed by organic-rich lamellar limy mudstone and organic-bearing lamellar argillaceous limestone, organic-rich lamellar limy mudstone and organic-bearing massive mudstone.

The Shahejie Formation shale in the Jiyang depression has higher organic matter abundance. TOC values of some samples exceed 5%, and TOC shows different features in different lithofacies. The lamellar and bedded shales are similar in organic matter abundance, while the massive shale is slightly lower in organic matter abundance, and the cracked hydrocarbon content (S₂) also shows the same characteristics (Fig. 2a and 2b). According to the classification of organic matter types by I_H-T_max (I_H is hydrogen index, T_max is the maximum pyrolysis temperature for kerogen) relationship, the laminar samples have types I and II₁ organic matter, the bedded samples have mainly type II₁ and a small amount of type II₂ organic matter, and the massive samples have type II₁ and type II₂ organic matter. This means that the organic matter in lamellar and bedded samples have higher oil generation capacity (Fig. 2c). According to T_max value, the samples taken are chiefly at mature stage (Fig. 2d). The Shahejie Formation in the Dongying sag has similar TOC with the Shahejie Formation in the Bonan sub-sag, but slight difference in organic matter type. The Shahejie Formation in the Bonan sub-sag has mainly type I organic matter^[4].

The shale in the Shahejie Formation of the Jiyang depression is mainly composed of clay minerals (25%-42%), calcite, dolomite and quartz (15%-17%), with a feldspar content of less than 5%. The laminar and bedded shales have higher carbonate mineral content (calcite + dolomite of more than 40%), and the massive shale has higher clay mineral content (Fig. 3a). The clay minerals are mainly illite-montmorillonite mixed layers, followed by illite, with a small amount of kaolinite (Fig. 3b). The shale intervals with high brittle mineral content are “sweet spot” intervals for effective fracturing. One of the evaluation methods of shale brittleness is based on mineral content, but the distribution pattern of brittle minerals, the maximum/minimum horizontal principal stress difference (or difference coefficient) have strong control on the fracturing effect.

Researchers have studied shale oil resources in the Shahejie Formation in the Jiyang depression, and recognized that the potential of shale oil resources was huge^[36], and many researchers have described shale oil reservoir characteristics, and found that the shale pores in the study area were smaller, mainly nano-pores and a small number of micro-pores^[5,37]. But the amount and occurrence state (adsorbed, free) of shale oil in different grades (scales) of pores directly affect the mobility or the amount of movable shale oil, that is, the movability of shale oil is closely related to its occurrence mechanism, and the research in this field is weak.

The results of low-temperature nitrogen adsorption and high-pressure mercury intrusion experiments of washed and unwashed shale samples were compared to find out the sizes of pores in which shale oil exists (Fig. 4). It can be seen from Fig. 4a that the low-temperature nitrogen adsorption and desorption values of the washed samples are much higher than those of the samples not washed, which indicates that shale oil released during washing, and the hysteresis rings changed after washing, from wedge-shaped pores to ink bottle-shaped pores. From the change of pore diameters before and after oil washing, shale oil mainly occurs in pores of 3-80 nm (Fig. 4b). The experimental results of high-pressure mercury injection before and after oil washing (Fig. 4c) show that the volume of mercury entering after oil washing increased obviously, and shale oil exists in the pores of several nanometers to more than ten microns (Fig. 4d). It should be noted that the mercury injection pressure is high (up to 200 MPa). For unwashed samples, higher injection pressure may cause residual free oil to move and squeeze into smaller pores. In addition, organic matter/asphalt/clay minerals with relatively strong plasticity may shrink at higher pressure, making the smaller pore volume higher at high pressure. Wang et al. found through study that^[38], when the pressure was higher than 25 MPa, the small shale samples with injected mercury would deform. Li Zhuo et al.^[39] adopted 80 nm pore diameter to splice the shale pore diameter characterize by low-temperature nitrogen adsorption and high-pressure mercury injection. In this study, through comprehensive consideration, 65 nm pore diameter was taken as the splicing point of the results of the two kinds of experiments.

The pore size distribution of residual shale oil in different lithofacies of shale was evaluated by the methods mentioned above (Fig. 5). It can be seen that the residual oil at normal temperature and pressure mainly occurs in pores less than 100 nm, and the content of shale oil in organic-rich shale is higher than that in organic-bearing shale (Fig. 5); from lamellar to bedded to massive shales, the occurrence of shale oil in larger pores (more than 100 nm) becomes less and less obvious.

Besides adsorbed on pore surface, shale oil also exists in free state in pores. With the increase of pore size, the mobility of shale oil increases gradually, that is, free oil/movable oil increases gradually. According to the pore size distribution curve (Fig. 5), the oil-bearing pore volume was gradually accumulated from large to small pores, and the accumulative oil-bearing pore volume curve of each type of shale was plotted (i.e. the oil-bearing volume of a pore size and pores larger than the pore size). Combining with the density of the oil produced (0.83 g/cm³) in the study area, the shale oil quantity in the pores larger than a given pore size was calculated. Taking the free oil content obtained from stepwise pyrolysis as the longitudinal axis, and the oil content in the pores with a given size and larger sizes than the given size as the horizontal axis, a crossplot was made (Fig. 6a). The crossplot shows the linear correlation and slope coefficient at different pore sizes (Fig. 6b). See references [40-41] for detailed description. When the slope coefficient is close to 1 and the correlation is the maximum, the pore size is the lower limit for free oil, and the pore size evaluation method for movable oil distribution is similar to this method. It can be seen that with the pore sizes turning from small to large, the correlation coefficient of free oil obtained by stepwise pyrolysis and shale oil obtained before and after washing increases first and then decreases, and is 0.7071 at maximum (Fig. 6a), and the corresponding slope of fitting equation at this point is about 1 (Fig. 6b), which indicates that the lower pore size limit of free oil may be 5 nm, i.e. the oil in the pores less than 5 nm is in adsorbed state. This conclusion is basically consistent with the result of molecular dynamics simulation that “the oil in pores <4 nm is all in adsorbed state”^[40]. The lower pore size limit of movable oil obtained by this method is about 30 nm (Fig. 6c, 6d).

FE-SEM observation of the Shahejie Formation shale samples shows that the pores and fractures in many samples contain precipitated shale oil (Fig. 7). The precipitated oil often occurs in organic matter pores, clay mineral-organic matter intergranular pores, micro-fractures, and pyrite intercrystal pore margin, etc. Statistical results show that the minimum pore size with precipitated shale oil is about 50 nm, and that is the lower pore size limit for movable oil under FE-SEM (vacuum) (about 50 nm). It is higher than the previous lower limit of movable oil (30 nm). The cause may be that oil precipitation from smaller pores is not obvious and difficult to be observed by naked eyes.

The occurrence state of shale oil (adsorbed and free) is related to depth, rock composition (mineral and solid organic matter), oil properties (group composition, oil density, and viscosity) and pore size.

Fig. 8 shows the relationship between the percentage of adsorbed oil and depth obtained from stepwise pyrolysis experiment. It can be seen that the percentage of adsorbed oil decreases gradually with the increase of burial depth, so the percentage of free oil increases gradually. The reason lies in that on the one hand, with the increase of depth, the viscosity/density of shale oil decreases, the content of saturated hydrocarbons increases (oil becomes lighter), and the ability of shale oil to adhere to the surface of pore wall decreases; on the other hand, with the increase of thermal maturity, the fat chain, carboxyl group, hydroxyl group and carbonyl group in kerogen gradually disappear, and the oxygen-carbon ratio gradually decreases, resulting in the decrease of the interactive force between kerogen and shale oil and the weakening of the adsorption capacity. At the same depth, the percentage of oil adsorbed by lamellar/bedded limy mudstone is higher than by argillaceous limestone, and the oil adsorbed by organic-rich lamellar argillaceous limestone is higher than that by organic-bearing argillaceous limestone.

It can be seen from Fig. 9 that the percentage of adsorbed oil decreases with the increase of saturated hydrocarbon content, and increases with the rise of aromatic hydrocarbon, asphaltene and non-hydrocarbon contents, that is, the heavier the oil components (low saturated hydrocarbon content, high gum and asphaltene contents), the higher the percentage of adsorbed oil will be. With the increase of the percentage of free oil, shale oil mobility increases gradually; therefore, we should look for the intervals with higher content of light components (those with deep burial depth, high gas-oil ratio, high percentage of alkanes/more light components) in exploration.

The crude oil viscosity and density of the Shahejie Formation decrease with the increase of depth, while the saturated hydrocarbon content goes up gradually with the increase of depth^[42]. From Fig. 9, it can be seen that the decrease of the percentage of adsorbed oil with the increase of depth is mainly due to the increase of thermal evolution degree, the increase of the percentage of light components (alkanes) in shale oil, the increasing difference of the structure between the remaining hydrocarbon components and the hydrocarbon-generating parent materials, and the gradual decrease of the adsorption and mutual solubility between them.

The amount of adsorbed oil is related not only to the composition of shale oil, but also to the abundance of organic matter and mineral composition of shale. It can be seen from Fig. 10 that there is a good linear positive correlation between the amount of adsorbed oil and TOC: the higher the TOC value, the higher the adsorbed oil amount will be (Fig. 10a). Therefore, for the shales with the same oil content, the lower the TOC, the less the adsorbed oil amount and the higher the movable oil ratio will be. The adsorbed oil obtained from stepwise pyrolysis is mainly from dissolved kerogen. In addition, the pores associated with organic matter are oil-wet, so their surface can adsorb a certain amount of oil. It can be seen from Fig. 10a that the retained oil (dissolved + adsorbed) is about 179 mg/g per unit of TOC. It is noteworthy that the fitting equation in Fig. 10a doesn’t cross the origin, indicating that the residual oil includes not only the oil dissolving organic matter and adsorbed to organic pore surface, but also some oil adsorbed by some inorganic pore surface. The amount of adsorbed oil in inorganic minerals is about 0.2162 mg/g per unit of rock (the intersection with the Y axis). The amount of adsorbed/dissolved oil is related not only to the type of kerogen, the degree of thermal evolution of kerogen and the development of organic pores associated with kerogen, but also to the composition of oil. It can be seen that a consensus hasn’t been reached on the understanding of organic matter adsorption/dissolved oil. Pepper et al. used S₁/TOC of 0.1 or “A”/TOC of 0.2 as the boundary of adsorption saturation of marine source rock^[43,44]. According to theoretical calculation, Tian Shansi et al.^[45] believed that the oil content related to type I and type II₁ kerogen (adsorbed + swelled) is 130-150 mg/g organic carbon per unit mass. Wei et al.^[46] found through experiments that the amount of adsorbed oil related to kerogen in the Dongying depression was 40-120 mg/g per unit of TOC. Through swelling experiments, Zhang Linye et al.^[27] considered that the retained oil amount in Es₃ and Es₄ was 123.07 mg/g per unit mass of kerogen and 142.29 mg/g kerogen respectively. The oil composition (43.49% of saturated hydrocarbons, 17.78% of aromatic hydrocarbons, 17.46% of non-hydrocarbons and 6.98% of asphaltene) used in Zhang Linye's experiment is similar to that of the sample extracts (49.52% of saturated hydrocarbons, 17.13% of aromatic hydrocarbons, 25.59% of non-hydrocarbons and 7.05% of asphaltene) in this study. Assuming that the conversion coefficient between kerogen and TOC is 0.8, then the conclusion reached by Zhang Linye et al. is consistent with the statistical result of this study. Compared with the conclusion from this study, the adsorption capacity of pure minerals in previous studies is generally higher. The main cause is that the adsorption occurs only on the pore surface related to minerals, not on all surface of pure minerals in the experiment, and the existence of bound water on the surface of some minerals under geologic conditions reduces the adsorption capacity. It can be seen that it is more appropriate to work out the adsorption/dissolution amount of shale oil and the adsorption capacity of minerals by statistical analysis in specific areas.

In order to eliminate the influence of organic matter content, the relationship between mineral content and oil content per unit organic matter was obtained by dividing the content of adsorbed oil by TOC of the sample (Fig. 10b-d). It can be found that there is no correlation between the content of clay minerals, siliceous minerals and calcareous minerals and the content of adsorbed oil. Although some inorganic pore surface also show oil wettability, and can adsorb shale oil, but the on one hand pore/specific surface is not completely controlled by mineral content, and on the other hand, the specific surface of the sample with shale oil adsorption capacity follow no rules, especially, the pores of clay minerals which control the specific surface area are not all oil-wet, so there is no obvious correlation between the amount of adsorbed oil and mineral content. Results of previous studies by mass and concentration methods show that clay minerals have higher oil adsorption capacity, while calcite and quartz minerals have lower oil adsorption capacity^[22,47]. But this conclusion is based on dried samples, rather than wettability/adsorption of water-bearing samples. According to the results of molecular dynamics simulation, clay, calcite, and dolomite etc. all show hydrophilic characteristics under the coexistence of oil, water and rock three phases^[48,49], and the content of adsorbed hydrocarbons in shale decreases sharply under water-bearing condition^[50,51]. In this study, the adsorption capacity was tested under water-bearing condition, and the results show the adsorptive capacity is mainly controlled by kerogen (especially TOC) and has no obvious relationship with mineral contents.

The amounts of adsorbed oil and free oil are also related to the pore volume of shale. The larger the pore volume, the higher the amounts of adsorbed oil and free oil will be, but the proportion of adsorbed oil will decrease. On the contrary, with the increase of porosity, the proportion of free oil (Fig. 11) and the movable proportion of shale oil go up. Unlike shale gas, adsorbed oil content has no obvious correlation with pore specific surface area (Fig. 12). The main cause is that the adsorbed oil obtained from stepwise pyrolysis contains more hydrocarbons dissolved in kerogen (this can be proved by the relationship with TOC, Fig. 10a), besides a small amount of adsorbed oil on pore surface. In addition, the pores of lacustrine shale show mixed wettability, that is, hydrocarbon adsorption does not occur on the surface of some water-wet pores, for example, the surface of most clay minerals is water- wet, which makes the relationship between specific surface area and oil content more complex. Fig. 12 shows that some samples have higher specific surface area but lower adsorbed oil content. The main reasons are that these samples have lower TOC content and lower dissolved hydrocarbon content.

Unlike shale gas, no experimental study on the effect of temperature and pressure on the adsorption performance of shale oil has been reported. But with the increase of temperature, the oil will decrease significantly in viscosity and increase in mobility, so the amount of adsorbed oil is deemed to decrease. In fact, molecular dynamics simulation has confirmed that temperature has an important effect on shale oil adsorption^[47]. With the increase of temperature, the adsorption between shale oil and pore surface weakens, so the amount of adsorbed oil decreases gradually. Although it has been found from molecular dynamics that pressure has no significant effect on shale oil adsorption^[47], pressure, as a driving force, has a significant effect on shale oil mobility or recoverability. The amount of oil-soluble gas has a significant effect on the adsorption of shale oil. With the increase of gas content, the adsorption capacity of shale oil decreases, resulting in the decrease of adsorption amount. Molecular dynamics simulation also confirmed that with the increase of small molecular hydrocarbon components, the adsorption amount gradually drops^[47]. The increase of pressure under geological conditions can increase the amount of dissolved gas, decrease the adsorptive capacity and the viscosity of shale oil and enhance the mobility of shale oil. Therefore, many researchers considered pressure or overpressure in shale oil evaluation^[12,14,29].

Based on the above analysis, it can be seen that the shale oil in Shahejie Formation occurs in free state, adsorbed state and dissolved state. The shale oil of adsorbed state and dissolved state cannot be distinguished in stepwise pyrolysis experiment, so they were not discussed individually in quantitative analysis. Based on the characteristics of pore, fracture and shale oil in FE-SEM photos (399) of 35 shale samples, the occurrence models of shale oil have been preliminarily established (Fig. 13). In the statistics, it was found that shale oil signs could be found in all types of pores in shale at oil generation stage in Jiyang depression, but not all pores contain shale oil (such as dissolution pores, calcite intercrystal pores, interlayer pores in clay minerals and intergranular pores). It can be seen that some pores are filled with oil, and other pores have no oil trace. It was also found during the statistics that shale oil would enrich in the aggregate of spherical pyrite when the pyrite has a good communication channel with the outside setting.

Fig. 13 shows the occurrence models of shale oil in different pores in the original formation state. As pressure is released during core drilling, and a large amount of movable oil/light hydrocarbons would lose in subsequent static storage and experiments, the data obtained by FE-SEM and other methods is about residual shale oil. Free shale oil mainly exists in all kinds of pores larger than 5 nm. Adsorbed shale oil mainly occurs on the surface of organic pores, and dissolved shale oil exists in organic matter/asphalt. Adsorbed formation water mainly exists on the surface of clay minerals and some inorganic pores, while free water mainly in larger interlayer pores, fractures and some inorganic pores. During the long geological period, when the pores are filled with oil, the pore surface wettability may be reversed from hydrophilic to lipophilic. For example, some clay mineral interlayer pores and calcite intercrystal pores which should have hydrophilic surfaces show lipophilic characteristic.

Fig. 14 shows the organic geochemical parameters and porosity profile of Well FY1. Free oil content was measured by two experimental methods: stepwise pyrolysis, and nuclear magnetic resonance experiment. In the second method, the test was done on vacuumed mudstone samples saturated with oil, and then the dividing schemes of NMR relaxation time of H signals was established, and finally free oil content was quantitatively estimated based on the relationship between free oil signal and oil content. See references [21, 52] for the detailed procedure.

After analyzing the controlling factors above, it can be seen that the interval with high saturated hydrocarbon content and free oil content and large pore volume is the place with high movable oil content (or movable proportion). The perforated section of Well FY1 is 3 199-3 210 m. It can be seen from Fig. 14 that the saturated hydrocarbon content in this section is not high (generally less than 40%), while OSI index (100 S₁/TOC) is relatively low (no more than 120 mg/g), free oil content (less than 5 mg/g) and porosity are not high (less than 8%), which may be the main reasons behind the failure of this section in Well FY1. In contrast, the 3 300-3 410 m section has high porosity, high free oil content after recovery, and OSI index generally over 120 mg/g, so we recommend to perforate this section.

The organic-rich shale has higher shale oil content than organic-bearing shale. The laminar and bedded shales have higher oil content and brittle mineral content (carbonate + quartz) than massive shale. Shale oil mainly occurs in pores less than 100 nm of different lithofacies shales. From laminar, to bedded to massive shale facies, the content of shale oil and the proportion of macro-pores for shale oil occurrence go down gradually.

With the increase of burial depth, the proportion of adsorbed oil decreases and the proportion of free oil increases. At normal temperature and pressure, the lower pore size limit of free oil is about 5 nm and that of movable oil is about 30 nm. The heavier the oil components (low saturated hydrocarbon content, high gum and asphaltene contents), the higher the adsorbed hydrocarbon content will be. The amount of adsorbed hydrocarbon is mainly controlled by TOC, and there is no obvious correlation between mineral content and adsorbed oil content. The larger the pore volume, the higher the amount of adsorbed oil and free oil will be, but the proportion of adsorbed oil will decrease, while the proportion of free oil will increase.

The occurrence models of shale oil in different types of pores have been established. Residual shale oil exists in all types of pores, but not in all pores, for example, some dissolution pores, calcite intercrystal pores, clay mineral interlayer pores and intergranular pores contain shale oil, and when having a good communication channel with the outside setting, the aggregate of spherical pyrite is rich in shale oil. The connectivity and wettability of various types of pores in shale during oil generation stage determine their degree and state of oil enrichment. Adsorbed oil mainly exists on the surface of organic matter pores, while free oil mainly exists in larger pores with better connectivity.

In order to avoid using the residual shale oil data with deviation of the results from the actual situation. We suggest studying organic geochemistry of shale oil and the ratio of adsorbed oil to free oil under original underground conditions.