There are various methods for quantitatively evaluating the retained hydrocarbon content in shale strata. For shale gas, its content consists of three components: lost gas, in-situ desorbed gas, and residual adsorbed gas ^[35-36]. The lost gas is that portion of the total gas that escapes from the sample during its collection and retrieval prior to being sealed into an airtight desorption canister. Lost gas volume cannot be measured experimentally, but only be estimated from the loss time and the change rate of desorbed gas ^[37]. The residual gas refers to the gas remaining in the sample after desorption ^[38]. The shale gas content is generally determined using core samples. Once the core drilled using ordinary tools is extracted out of the wellhead, it is sampled immediately using a sealed tank. Then, a desorption canister is used to measure the change of gas content in the sample over time, and thus the desorbed gas content is determined ^[39]. The lost gas volume during the sampling process is calculated based on the time the sample is exposed from extraction to sampling, and then the residual gas content is determined by crushing the sample in the laboratory. For lost gas, the sealed pressure-retained coring method is adopted to avoid gas loss in the wellbore, and the exposure time of the core collected should be minimized to avoid gas loss in the atmosphere. For residual gas, the core sample is desorbed at high temperature above 90 °C to reduce the presence of residual gas, or the sample is crushed to measure the content of residual gas.

For shale oil, there are three mainstream methods for evaluating its retained hydrocarbon content: pyrolysis method, stepwise extraction method, and nuclear magnetic resonance (NMR) method. The pyrolysis method can be divided into two sub-types: conventional pyrolysis and stepwise pyrolysis ^[40-41]. The former uses the free hydrocarbon content (S₁) to reflect the volume of retained hydrocarbons in the shale strata, but the S₁ tested usually suffers light hydrocarbon loss and heavy hydrocarbon loss. By combining hydrocarbon generation kinetics with rock pyrolysis parameters of shale samples before and after extraction, S₁ can be restored for light hydrocarbons and corrected for heavy hydrocarbons, thereby obtaining the retained hydrocarbon content in shale. The stepwise pyrolysis method determines the retained hydrocarbon content through quantitative evaluation on shale oil in different occurrence states in shale strata, under proper heating conditions, considering that such shale oils in different occurrence states are distinct in molecular thermal volatilization capacity, and that temperature ranges correspond to non-polar free compounds, polar free compounds, heavy hydrocarbons, and adsorbed substances (e.g. resin and asphaltene). The stepwise extraction method obtains the contents of hydrocarbons in different occurrence states by collecting extracts with solvents of different volumes or polarities, considering that the molecules with different compositions and polarities are selective in occurrence space and state ^[42]. The NMR method directly calculates the contents of shale oil in different occurrence states by distinguishing free oil and adsorbed oil depending on the differences of free oil, adsorbed oil, and kerogen in relaxation time on 2D NMR spectra ^[43]. In addition, molecular dynamics model, free hydrocarbon difference method, swelling method, material balance method, and pore oil saturation method can also be used to evaluate the contents of shale oil in different occurrence states ^[44].

Here, the source rock in the Upper Cretaceous Qingshankou Formation in northern Songliao Basin, NE China, is taken as an example. The Qingshankou Formation is a set of thick and extensive shale of semi-deep to deep lake facies. It is the hydrocarbon source of the whole petroleum system of the Qingshankou Formation in the Songliao Basin. For this set of shale, the organic matters are mainly Type I and Type II₁. The total organic carbon content (TOC) ranges from 0.6% to 8.1%, with an average of about 2.39%; the (S₁+S₂) value ranges from 0.01 mg/g to 75.52 mg/g, with an average of about 11.17 mg/g. The thermal maturity (R_o) is 0.7%-1.6%, indicating a peak period of oil generation. Based on the geochemical parameters, the Qingshankou Formation shale is believed to have good oil generation capacity and be reliable for extensive hydrocarbon generation and expulsion, laying the foundation for shale oil accumulation through in-situ retention. By using frozen core test data to calibrate the hydrocarbon evolution process of the Qingshankou Formation shale, the chemical kinetic parameters were obtained. The light hydrocarbon restoration coefficient for the Qingshankou Formation shale was fitted to be around 1.00-3.65, which increases and remains stable with increasing maturity. The lost light hydrocarbon in the Qingshankou Formation shale was determined to be 1.00-16.04 mg/g, with an average of about 5.71 mg/g. The difference in retained hydrocarbon content (S₂) of shale samples before and after extraction was compared to obtain the undetected heavy hydrocarbon loss ΔS₂ in pyrolysis testing. The heavy hydrocarbon correction coefficient for the Qingshankou Formation shale was calculated to be about 2, and then the heavy hydrocarbon loss in the Qingshankou Formation shale was determined to be 0.02-13.18 mg/g, with an average of about 3.21 mg/g. Based on conventional rock pyrolysis, together with light hydrocarbon restoration and heavy hydrocarbon correction, the retained hydrocarbon content of the Qingshankou Formation shale is estimated to be 3.00-22.00 mg/g, with an average of about 8.69 mg/g, which is more than 2.5 times the S₁ value measured by pyrolysis (Fig. 7). Clearly, this method is more accurate and reliable than the process that S₁ is directly used as a parameter to evaluate resource quantity.

The precise characterization of pore structure in tight unconventional hydrocarbon reservoirs is fundamental for unconventional hydrocarbon evaluation. This can be realized by image observation and fluid injection methods. The image observation methods include argon-ion polishing field emission-scanning electron microscopy (FE-SEM), large-view splicing, micro/nano CT, and focused ion beam scanning electron microscopy (FIB-SEM). Large-view splicing achieves a larger-scale characterization at high resolution, effectively reducing the impact of sample heterogeneity on observation results. Micro/nano CT images the pore structure non-destructively with high precision through X-ray scanning. FIB-SEM combines high-resolution imaging with ion cutting beam to image the pore structure in a 3D dimension. This high-resolution method may damage to the samples to a certain extent. The fluid injection methods mainly include low- temperature gas adsorption, high-pressure mercury injection, constant-rate mercury injection, and NMR experiment. Low-temperature gas adsorption includes carbon dioxide adsorption and nitrogen adsorption, which can characterize pore sizes ranging 0.35-2.00 nm and 0.35- 400.00 nm, respectively. High-pressure mercury injection enables a full pore size characterization of pore structure of tight reservoirs. Compared to high-pressure mercury injection, constant-rate mercury injection can effectively and separately extract pore parameters and throat parameters of tight reservoirs. NMR experiment can also characterize the pore size distribution of tight reservoirs.

Currently, the combination of low-temperature gas adsorption and high-pressure mercury injection is popular for characterizing the pore structure of tight reservoirs. Taking marine shale in southeastern Chongqing as an example, the Lower Silurian Longmaxi Formation and Cambrian Niutitang Formation shales reflect pore sizes of mainly 0.5-100.0 nm, with mesopores and micropores in dominance (Fig. 8). Given the thermal evolution degree, with the increase of TOC, the proportion of mesopores and micropores increases, and the development degree of shale pores also increases. Compared to the Longmaxi Formation, the Niutitang Formation shale has a higher degree of thermal evolution, and a lower development of shale pores, which are mainly micropores and few mesopores, and exhibit a less increase with the increase of TOC (Fig. 8). It should be noted that for samples with high clay mineral content and presence of microfractures, the accuracy of test results should be especially considered when the combination of low-temperature gas adsorption and high-pressure mercury injection is adopted.

A source-reservoir assemblage is a stratigraphic unit composed of one or more sets of source rocks and a set of reservoir rock, which are explicitly related as petroleum supply and accumulation, and are adjacent or contiguous in space ^[45]. Based on the spatial configurations of source rocks and reservoir rocks in the tight oil basins in central and western China, five types of source-reservoir assemblages are recognized as follows: lower source and upper reservoir, upper source and lower reservoir, “sandwiched” source and reservoir, thin interbedded source and reservoir, and integrated source and reservoir. The first four types are common in tight freshwater lacustrine strata, while the last type is dominant in the tight saline lacustrine strata.

(1) Lower source and upper reservoir.

The source rock is developed below the reservoir rock, and in close contact with the reservoir rock extensively. This type of assemblage is mainly formed in the regressive sequences in the center and periphery of sedimentary depressions. A typical example is the source-reservoir assemblage for the tight oil of the Chang-6₄ sub-member of the Triassic Yanchang Formation in the Ordos Basin, where the Chang 7 Member source rock underlies the Chang-6₄ sub-member reservoir rock.

(2) Upper source and lower reservoir.

The source rock is developed above the reservoir rock, and in close contact with the reservoir rock extensively. This type of assemblage is equivalent to the source-reservoir-caprock assemblage with the source rock at the top for conventional reservoirs. It is mainly formed in the transgressive sequences in the center and periphery of sedimentary depressions. A typical example is the source-reservoir assemblage for the tight oil of the Chang-8₁ sub-member of the Yanchang Formation in the Ordos Basin, where the Chang-7₃ sub-member source rock overlies the Chang-8₁ sub-member reservoir rock. As the overlying source rock also serves as a seal, this assemblage often has better oil-bearing properties.

(3) “Sandwiched” source and reservoir.

The strata overlying and underlying the reservoir are both source rocks, and these sets of source rocks and reservoir rocks are closely and extensively contacted. This type of assemblage is mainly formed in the aggradational (stable transgressive-regressive) sequences in the center and periphery of sedimentary depressions. A typical example is the source-reservoir assemblage for the tight oil of the Chang-7 Member of the Yanchang Formation in the Ordos Basin, where the organic-rich shale in the Chang-7 Member is the source rock, and the tight clastic rock in the Chang-7 Member shales is the reservoir rock. As oil is supplied both upward and downward, this type of assemblage often has good oil-bearing properties.

(4) Thin interbedded source and reservoir.

Thin (thickness smaller than 1 m) source rocks and thin reservoir rocks are alternative and superimposed vertically. This type of assemblage usually appears in the source-reservoir transition zone in the slope of freshwater lake basins, and it is the result of frequent transgressive-regressive cycles. Being far from the depocenter, which results in thin source rocks with poor quality and thin reservoir rocks, this type of assemblage often has poor oil-bearing properties.

(5) Integrated source and reservoir.

Source rocks and reservoir rocks are mixed together and difficult to distinguish. This type of assemblage is usually developed in the center and periphery of saline lake basins, and is composed of fine-grained diamictite formed by the mixing of clastic rocks (e.g. mud shale, argillaceous siltstone, and sandstone) and carbonate rocks (e.g. dolomitic rock and limy rock). This type of assemblage often has good oil-bearing properties, since it is located in the organic-rich depocenter, where both dissolution and fracturing of carbonate rocks are available. A typical example is the upper and lower sweet spots of the Permian Lucaogou Formation in the Jimsar Sag, the Junggar Basin.

The matching between the densification process of tight reservoirs and hydrocarbon charging has always been a key subject in the study of tight oil/gas accumulation. According to the order of formation, tight oil/gas can be divided into two types: pre-formed, and post- formed ^[46]. For the pre-formed tight oil/gas, the densification process of reservoir has completed before the peak hydrocarbon generation and expulsion of the source rocks. The pore structure of such reservoir is complex and poorly connected. The tight oil/gas is accumulated under the driving of the pressurization from hydrocarbon generation of the source rock, following a non-buoyancy mechanism. Ultimately, tight oil/gas reservoirs with large thickness and wide range are formed. For the post-formed tight oil/gas, the reservoirs remain conventional when charged with crude oil, and gradually become tighter under compaction in the later stage. It is mainly accumulated following the buoyancy mechanism. Controlled by early trap, the reservoirs are distributed in a small range, with the maximum petroliferous area not beyond the trap (Fig. 9).

The research on the densification process and hydrocarbon charging of tight reservoirs mainly includes two aspects: quantitative restoration of the densification process of tight reservoirs, and determination of the charging period of tight oil/gas. For quantitative restoration of the densification process of tight reservoirs, the main diagenetic process for tight reservoirs is determined; then, the reservoir-forming effect of diagenesis is calculated; and ultimately the densification process of tight reservoirs under diagenetic evolution constraints is constructed based on the diagenetic evolution sequence. The charging period of tight oil/gas is mainly determined by homogenization temperature of inclusions, dating of authigenic illite, dating of crude oil isotopes, and hydrocarbon generation and expulsion history of source rocks. Based on the above analysis, the hydrocarbon charging process when tight oil/gas reservoirs are densified is determined, and then the matching between them is clarified.

Here, the tight sandstone gas in the second member of the Xujiahe Formation (referred to as Xu-2 Member) of the Upper Triassic in the West Sichuan Sag is taken as an example for discussion. The tight sandstone reservoir in the Xu-2 Member has undergone strong compaction and diagenesis, and stays in the late diagenetic stage B. The initial porosity of the tight sandstone in the Xu-2 Member is about 45%. After the early diagenetic stages A and B, the reservoir porosity evolved to 18%-22% under compaction and cementation. In the late diagenetic stage A, the combined action of compaction, cementation, and dissolution caused the reservoir to be tight. At the end of this stage, the reservoir porosity decreased to 6%-10% (corresponding to the early stage of Late Jurassic). In the late diagenetic stage B, the influence of compaction weakened, and cementation made the reservoir tighter, with porosity mostly of 2%-5% ^[47]. The main source rock of the Xujiahe Formation in the West Sichuan Sag reached the hydrocarbon generation threshold in the early stage of Late Jurassic, and entered the period of peak hydrocarbon generation in the early stage of Early Cretaceous, later than the time when the sandstone reservoir of the Xu-2 Member became tight. In addition, the homogenization temperature detection results of the inclusions indicate that the hydrocarbon charging of the tight reservoir in the Xu-2 Member occurred from the late stage of Late Jurassic to the early stage of Early Cretaceous. Based on the evolution history of tight reservoirs, the hydrocarbon generation history of source rocks, and the homogenization temperature of inclusions, the tight sandstone gas reservoir in the Xu-2 Member of the West Sichuan Sag is believed to be a typical pre-formed tight gas reservoir that became tight before hydrocarbon accumulation ^[48].

The later reworking of unconventional reservoirs can lead to changes in temperature, pressure, and preservation conditions inside the reservoirs, thereby altering the occurrence state of unconventional hydrocarbons, and especially affecting the content of free oil/gas ^[18]. Therefore, the later reworking of unconventional hydrocarbon reservoirs is crucial for the enrichment of unconventional hydrocarbons, especially for gas reservoirs such as marine shale gas and high-rank CBM that have been structurally uplifted and finalized in the later stage.

Amplitude and time of structural uplift control the enrichment degree of marine shale gas and high-rank CBM. Taking high-rank CBM as an example, we investigated the enrichment degree of CBM under different tectonic evolution modes ^[49] (Fig. 10). If the coalbeds rose continuously after regional uplift inversion to the CBM weathering zone, the CBM reservoirs were damaged, resulting in a low gas content. If the coalbeds rose continuously after regional uplift inversion, but stay presently below the CBM weathering zone, the coalbeds would hold a high gas content. However, if the coalbeds subsided continuously after regional uplift inversion, the coalbeds would contain a high gas content, but the coalbed permeability decreased, which is not conducive for development. Marine shale gas was taken as an example to identify the impact of structural uplift time on gas reservoirs. The tectonic uplift of the Ordovician Wufeng Formation-Silurian Longmaxi Formation shales in the Jiaoshiba area of the Sichuan Basin began around 85 Ma, later than the uplift time in the Pengshui area (125 Ma), creating a high-yield shale gas area. The Pengshui area was uplifted early for a long period, and has not obtained industrial discovery, indicating that the late and short-time uplift is conducive to the preservation and enrichment of shale gas ^[50].

For unconventional reservoirs, which are tight and contain pore-throats with diameters mostly of 5-900 nm, buoyancy is insufficient to drive oil/gas to migrate through the pore-throats by overcoming the capillary force. Oil and gas are mainly bound in the reservoir space in free and adsorbed states, exhibiting the characteristics of hydrocarbon accumulation by retention and self-sealing ^[17,51]. Jia Chengzao analyzed the unconventional hydrocarbon accumulation characteristics of typical petroliferous basins in China, and pointed out that the driving force of unconventional hydrocarbon accumulation is intermolecular force, and the self-sealing effect of petroleum is the key to the unconventional hydrocarbon accumulation ^[16]. According to the intermolecular force and corresponding self-sealing effect, unconventional hydrocarbon accumulation mechanisms can be divided into three types: (1) macromolecular viscosity and condensation forces, for heavy oil and asphalt; (2) capillary pressure and molecular adsorption force, for tight oil and gas, shale oil and gas, and CBM; and (3) intermolecular clathration, for gas hydrate.

Here, the shale gas reservoir in the Longmaxi Formation of the Sichuan Basin is taken as an example to explore the self-sealing mechanism of unconventional hydrocarbon. From bottom up, the TOC and porosity of the shale gas reservoir in the Longmaxi Formation show a gradually decreasing trend, while the water saturation gradually increases. Its self-sealing mechanism mainly includes capillary force, physical properties, and adsorption force. The capillary force is the core of the self-sealing effect for the Longmaxi Formation shale gas (Fig. 11). When the hydrostatic pressure, capillary force, and fluid expansion force inside the shale gas reservoir reach an equilibrium, the gas reservoir can form self-sealing. When the hydrostatic pressure and fluid expansion force are constant, the capillary force becomes the key to self-sealing of gas reservoir. When the water saturation inside the reservoir reaches a critical level, capillary water is formed in the connected pores, so that the reservoir can be effectively sealed by capillary force. The water saturation of the shale in the second submember of the first member of the Longmaxi Formation (hereinafter referred to as Long-1²) above the major gas layer of the Longmaxi Formation shale gas reservoir has reached the critical level, forming a good capillary force sealing. The development degree and connectivity of pores in the shale reservoir of Long-1² are inferior to those in Long-1¹, which is conducive to the formation of physical property sealing. Although Long-1¹ has lower water saturation, well-developed pores, and better connectivity, capillary force sealing and physical property sealing can also be formed in areas where irreducible water exists and pore connectivity is poor locally. In addition, shale gas in adsorbed state occupies the effective migration path of free gas and can form a certain self-sealing effect. The self- sealing state of shale gas is relative. When tectonic movements cause strata to rise and fracture, the self-sealing system of shale gas is broken, and the equilibrium state is disrupted. Ultimately, the shale gas reservoir is destroyed and a new self-sealing equilibrium is formed.

Different types of unconventional and conventional oil and gas resources are distributed in an orderly manner within a whole petroleum system ^[17]. In continental basins, from the margin to the interior, the sedimentary facies transits from sand-dominated to mud-dominated. As the burial depth increases, the degree of thermal evolution of the source rock increases. From the oil generation window to the gas generation window, the reservoir becomes tighter under the joint action of compaction and diagenesis. From deep to shallow, the differences in geological conditions and source-reservoir assemblages of various reservoirs lead to changes in petroleum accumulation mechanisms and locations. Conventional oil and gas accumulate by buoyancy at structural highs outside the source rock. Unconventional oil and gas accumulate near or within the source rock under the drive of pressure difference and by self-sealing. As early as 2013, we proposed ^[17] that the oil and gas generated from a set of source rock in a petroliferous basin exhibit an orderly distribution of conventional oil and gas, tight oil and gas, and shale oil and gas, with the increasing burial depth vertically, and an orderly distribution of shale oil and gas, tight oil and gas, and conventional oil and gas, from the center to exterior of the basin, horizontally (Fig. 12).

Jia Chengzao, after putting forward the concept model of the whole petroleum system in 2017, based on the exploration practice of the Permian in the Junggar Basin,revealed the “sequential accumulation law of conventional and unconventional oil and gas in the whole petroleum system” of the Permian in the Junggar Basin ^[12]: tight oil-conventional oil is formed by sequentially charging from the source rock of the Permian Fengcheng Formation upward, and shale oil is formed by the retained petroleum in the Fengcheng Formation; conventional oil, tight oil and shale oil are developed from shallow to deep strata. Through in-depth study on the whole petroleum system of the Qingshankou Formation in the northern part of the Songliao Basin, we found that the shale of the Qingshankou Formation develops sediments of delta plain, delta front, pre-delta, and deep/semi-deep lake facies from the edge to the center of the lake basin. The reservoir type sequence consists of fine sandstone, siltstone, and shale, gradually becoming tighter. Horizontally, conventional oil reservoir, tight oil reservoir and shale oil reservoir are sequentially distributed (Fig. 13). The orderly distribution of conventional-unconventional oil and gas in the whole petroleum system breaks the approach of traditional petroleum exploration that focuses only on a single type of petroleum resources.