The exploration and development potential of tight oil is huge in China. By the end of 2018, the geological resources were 178.2×10⁸ t, and the technically recoverable resources were 12.34×10⁸ t^[1]. Although different organizations and scholars have different definitions of tight oil^[2,3], tight oil has the following standard characteristics: accumulation nearby sources or “self-source and self-reservoir”; poor reservoir physical properties, and the tight oil occurs mostly in micro-nano scale pores; and no natural production capacity, and commercial oil flow can only be obtained after technological stimulation. In contrast to conventional oil, which relies on buoyancy to accumulate, tight oil mainly relies on the source-reservoir pressure difference to migrate and accumulate. Tight oil accumulation not only depends on source rock conditions but also is controlled by reservoir conditions and their match and distribution in time and space^[4]. Lu et al.^[4] established the source rock grading evaluation criteria when studying tight oil in the southern Songliao Basin, NE China. As another important part of tight oil evaluation, reservoir evaluation results affect directly the selection of tight oil “sweet spot” targets. The establishment of reservoir formation limit and grading evaluation criteria for tight reservoirs is of great significance for tight oil exploration and development.

The upper limit of tight reservoir can be determined using the mechanical equilibrium method^[5]. The methods for determining the lower limit of tight reservoirs can be divided into three categories: (1) Statistical methods that rely on empirical laws^{[6,7,8,9,10,11]}, including empirical statistics, distribution function methods, and pore-permeability intersection diagrams. These methods are limited by the amount of data in the study area. In addition, the boundaries are controlled by statistical laws, which lack strict scientific basis. (2) Boundary determination, which depends on the relationship between the physical properties of oil, water, and the reservoir, including the oil-bearing grade method and oil test productivity method^{[8,9,10,11,12,13]}. (3) Determination of the lower limit of physical properties by using the law of fluid flow, including the minimum flow pore throat radius method, the lower limit method of filling pore throat, and bound water film thickness method^{[14,15,16,17]}. Different methods have different principles, applicability, and means of determining boundaries. It is unscientific to synthesize the boundaries determined by different methods into a fixed boundary, while ignoring the difference in geological significance of the boundaries determined through different methods.

Reservoir grading evaluation methods can also be divided into three categories: (1) Classify the petrophysical facies by the superposition of tectonic, sedimentary, and diagenetic facies^{[18,19,20,21]}. This method provides a qualitative evaluation of reservoir quality from the perspective of genesis, but has difficulty in providing quantitative standards. (2) Establish grading evaluation criteria by selecting the main parameters to construct coefficients that have a great influence on reservoir quality^[22]. This method can evaluate reservoir difference in a target area very well, but has difficulty in making a horizontal comparison since the main control parameters selected for different target areas are quite different. (3) Establish reservoir grading evaluation criteria based on the microscopic pore structure characterization^[23,24].

In China, the tight oil reservoirs are very complex in lithology, with diverse source-reservoir accumulation types. It is necessary to select unified parameters for grading evaluation to conduct comparative studies on different tight oil blocks. Furthermore, it is necessary to clarify the relationship between reservoir formation limit and grading evaluation standard to understand the geological significance of tight oil reservoirs of different grades. In view of this, in this study, the water film thickness method was used to obtain the theoretical lower limit, the oil-bearing grade method was used to obtain the lower limit of accumulation, the oil test productivity method was used to obtain the lower limit of effective seepage, and the mechanical balance method was used to obtain the upper limit of tight reservoirs based on tight reservoir physical properties, pore throat structure, oil and gas display, productivity, and other data. Combined with the difference in pore throat structure of the reservoir, we have determined the grading boundary of tight reservoirs and established research methods and grading evaluation criteria for reservoir boundaries of tight reservoirs.

In China, the tight oil is widely distributed in the basins of Ordos, Songliao, Junggar, Sichuan, Bohai Bay, Qaidam, Jianghan and Subei^[25]. The main producing beds are the Triassic Yanchang Formation in the Ordos Basin, the Lower Cretaceous Quantou Formation and Upper Cretaceous Qingshankou Formation in the Songliao Basin, the Permian Lucaogou Formation in the Jimsar sag of the Junggar Basin, and the Lower Triassic Baikouquan Formation in the Mahu area. Tight oil reservoirs have complex lithology and diverse types of source-reservoir-accumulation combination. Based on the spatial matching relationship between source rocks and reservoirs, tight oil accumulation combination can be divided into “self-source and self-reservoir”, “nearby source”, and “distant source”. The “self-source and self-reservoir” type is typically represented by tight oil in the mixed rocks of the Lucaogou Formation in the Jimsar sag, Junggar Basin^[26]. The “nearby source” type is widely distributed in the Yanchang Formation in the Ordos Basin, the Quantou Formation and Qingshankou Formation in the Songliao Basin, the Paleogene Kongdian-Shahejie Formation in the Jinxian sag of the Bohai Bay Basin, and the Paleogene Funing Formation in the North Jiangsu Basin. Among them, the Yanchang Formation in the Ordos Basin^[27] and the Quantou Formation^[28,29] and Qingshankou Formation^[29,30] in the Songliao Basin are the typical examples of this type. The “distant source” type is represented by the Baikouquan Formation in the Mahu area in the Junggar Basin^[31].

The reservoir formation limits of tight rock include upper and lower limits. The upper limit refers to the boundary between conventional oil reservoirs and tight oil reservoirs, and the lower limit refers to whether the rock can be used as an effective reservoir boundary for oil. The lower limit of the reservoir can be further divided into the theoretical lower limit, the lower limit of accumulation, and the lower limit of effective seepage. The theoretical lower limit refers to the lower limit at which oil molecules can theoretically (when the charging power is infinite) enter the rock pore throat. The lower limit of accumulation refers to the corresponding reservoir bed in which oil is charged into the tight rock under the action of a source-reservoir pressure difference. The lower limit of effective seepage refers to the lower limit corresponding to the effective oil and gas flow in which oil can seep out of the rock pores under the existing industrial technology. Some scholars also refer to this as the lower limit of the effective reservoir bed or the industrial lower limit^[32].

Regardless of how high the charging pressure was when tight oil was accumulated, the rock surface was covered with a water film, as the original bed contained with water. When the sum of the water film thickness and the oil molecular radius is equal to the pore throat radius, the corresponding theoretical critical pore throat radius is the theoretical lower limit of the reservoir^[17]. Using the tight reservoir of the Qingshankou Formation in the Songliao Basin as an example, a diagram of water film thickness (Fig. 1a) was used to calculate the water film thickness at 20 MPa formation pressure as 18 nm (Fig. 1b). Combined with the oil molecular radius (1.3 nm), the critical pore throat radius was found to be 19 nm. Then, the lower limit of theoretical permeability was determined to be 0.012×10^-3 μm² (Fig. 1c) and the lower limit of theoretical porosity was 3% (Fig. 1d). Using the water film thickness method, the theoretical lower limit of porosity of tight oil reservoirs in typical continental basins in China is 1%-4%, and the theoretical lower limit of permeability is 1.2×10^-7 μm²-0.2×10^-4 μm² (Table 1). Among them, the formation pressure of the Yanchang Formation of Ordos Basin is low, the water film thickness is large, and the corresponding theoretical lower limit is high. Although the formation pressure of the Lucaogou Formation of Junggar Basin is high, the water film thickness is small, and the corresponding theoretical lower limit is small.

The oil content of the core can provide direct evidence for whether the reservoir contains oil. No matter what kind of oil-bearing grades of cores, including oil-saturated, oil-rich, oil-immersion, oil-spot, oil-trace, and fluorescence, means that oil has charged into the reservoir and formed accumulation. Therefore, the lower limit of accumulation can be determined using the lower limits of the core physical properties of different oil-bearing grades.

The oil-bearing grade method has been used to determine the lower limit of tight reservoir accumulation in typical continental basins in China (Fig. 2). The results showed that the lower limit of accumulation porosity is 1.0% and the lower limit of permeability is 1.2×10^-7 μm² for the Lucaogou Formation in the Jimsar sag, Junggar Basin. The lower limit of accumulation porosity of tight oil reservoirs in all other areas is about 5.0%, and the lower limit of permeability is about 0.03×10^-3 μm². The Lucaogou Formation reservoir consists of “self-source and self-reservoir” mixed rock. The accumulated oil can be stored without migration or with a short-distance migration. The pressure decays slowly and the charging power is strong, so the lower limit of accumulation is very low, which is close to the theoretical lower limit. Conversely, “nearby source” and “distant source” tight oil need to migrate and charge into the reservoir over a certain distance. The accumulation charging power is less than the internal hydrocarbon expulsion power of the source rock. Therefore, the lower limit of accumulation is higher than that of the “self-source and self-reservoir” type.

The lower limit of accumulation can address the issue of the lower limit of oil charging to tight reservoirs, but it cannot solve the problem of the lower limit of production. The oil test productivity method can be used to determine the effective seepage limit based on the relationship between production and reservoir physical properties and the difference in physical properties between the oil-water layer and dry layer. The results showed that tight oil reservoir beds in the Qingshankou Formation and Quantou Formation in the Songliao Basin and the Funing Formation in the North Jiangsu Basin have lower limit of effective seepage porosity of 8%, 9%, and 8% respectively (Fig. 3a-c). The lower limit of effective seepage permeability for all three is approximately 0.1×10^-3 μm² (Fig. 3d-f).

The lower limit of effective seepage depends on the seep capacity of the oil in the rock matrix. The pore structure (pore size, connectivity) of “self-source and self-reservoir” type tight/shale oil reservoirs is typically worse than that of “distant source” or “nearby source” tight oil reservoirs. The oil flows less easily. Therefore, the lower limit of effective seepage is relatively high. However, this type of reservoir is more likely to be overpressure formation, increasing oil mobility, and reducing the lower limit of effective seepage. Corresponding stimulation measures to increase production will also reduce the lower limit of effective seepage. Compared with the lower limit of effective seepage, the industrial lower limit emphasizes the lower limit of the physical properties of the reservoir bed corresponding to the commercial oil flow produced under the existing technology^[35]. The economic factors such as input cost and market conditions should be taken into consideration. Therefore, the value is generally higher than that of the lower limit of effective seepage.

Due to the difference in accumulation dynamics, the methods for exploration of tight oil and conventional oil are different. In conventional oil reservoirs, there is a uniform oil-water interface. The exploration method is used to find structural high of traps. Conversely, in tight oil reservoirs, there is no uniform oil-water interface. The exploration method is used to select sweet spots. Determining the upper limit of accumulation of tight rock is a prerequisite for distinguishing reservoir types and determining the exploration methods.

During the process of oil migration and accumulation in the reservoirs, there is buoyancy caused by the density difference between formation water and oil and the capillary resistance formed in the throat. When they are equal, the corresponding throat radius are the upper limit of the critical throat radius of the tight reservoir^[36]. Using the mechanical balance method, the upper limit of the critical throat radius of the Quantou Formation reservoir in the Songliao Basin was determined to be 0.8 μm (Fig. 4a). This value was then used to determine the upper limit of permeability, being 1×10^-3 μm² (Fig. 4b) and the upper limit of porosity, being 12% (Fig. 4c). This method was also used to determine the upper limit of porosity, ranging from 11% to 12%, and the upper limit of permeability (1.0-1.3) ×10^-3 μm² for tight reservoirs of typical continental basins in China (Table 2).

The oil enrichment degree and the fluid seepage capacity in the tight rock matrix are the key factors affecting the effective development of tight oil^[4]. The oil enrichment degree depends on the charging power and the pore throat structure of the rock during accumulation. Both of them determines the critical pore throat radius of tight oil accumulation or the lower limit of accumulation, which represents the oil content in the rock in the macroscopic view. The seepage capacity of the oil in a tight rock matrix depends on the pore structure of the rock and the overpressure formation. In the microscopic view, this is expressed as the pore throat radius of effective oil seepage in the tight rock, or the lower limit of effective seepage. In the macroscopic view, it is expressed as the rock permeability. The two factors are related to the pore structure of the tight rock. A set of tight reservoir grading evaluation criterias have been established based on the difference in the pore structure of tight rock.

Based on the inflection point of the high-pressure mercury injection curve and its fractal characteristics, and referring to the classification method of shale oil reservoirs by Lu, et al.^[24], the pore system in tight oil reservoir are divided into II-micro-pore throats, I-micro pore, mesopore and macropore. Furthermore, the tight reservoirs are divided into 4 types in typical continental basins in China (Fig. 5): Type I, II, III and IV tight oil reservoirs according to the various proportion of pore type. There are obvious differences in the micro pore throat structure among regions and types. The main peak of pore-throat radius of glutenite reservoir from Baikouquan formation in Mahu area of Junggar basin is the largest where the peaks are 0.4-7.0 μm in type I - type IV tight reservoir; followed by the pore-throat radius of sandstone reservoir in Quantou Formation in the south and Qingshankou Formation in the north of Songliao basin, with 0.1-1.0 μm and 0.03-1.00 μm of type I - type III tight reservoir and less than 0.1 μm and 0.01 μm of type IV tight reservoir, respectively. The main peak of pore throat radius of hybrid reservoir of Lucaogou Formation in Jimusar sag is the smallest, and type I - type III tight oil reservoir is 0.015-0.800 μm, the main peaks of pore throat radius of type IV tight oil reservoir are less than 0.01 μm. However, in practical application, it is difficult to use the reservoir grading method based on the difference of microscopic pore throat structure (pore throat radius). Therefore, it is necessary to use macroscopic predictable physical property parameters (porosity, permeability, etc.) for standard conversion. For different types of reservoirs, the porosity and permeability have significant difference according to pore throat structure (Fig. 6), and they provide a basis for the establishment of physical property-based reservoir grading criteria. As the establishment of reservoir physical property classification evaluation standard of Qingshankou Formation in the north of Songliao Basin an example, the pore-throat structure is classified as type IV tight reservoir whose porosity is generally less than 5%, and the permeability is less than 0.03×10^-3 μm²; while the pore throat structure is classified as type III tight reservoir whose porosity generally ranges from 5% to 8%, and the permeability ranges from 0.03×10^-3 μm² to 0.2×10^-3 μm². Based on this, the porosity and permeability classification boundaries of type III and IV tight reservoirs are 5% and 0.03×10^-3 μm². Using the same way, the physical property classification boundary between other types of reservoirs are determined. The physical property grading evaluation results of the tight reservoirs in typical continental basins in China showed that (Table 3), the sandstone grading boundaries are the same for the Quantou Formation in the South Songliao Basin, the Qingshankou Formation in the North Songliao Basin, as well as the Member 1 of Kongdian Formation - Member 4 of Shahejie Formation in the Jinxian sag, Bohai Bay Basin and the Funing Formation in the North Jiangsu Basin (Table 3). These results are significantly different from the grading results of the tight glutenite of the Baikouquan Formation in the Mahu area, and those of the mixed rock of the Lucaogou Formation in the Jimsar sag of the Junggar Basin. The permeability grading limit of the glutenite in the Baikouquan Formation in the Mahu area is higher than that of the other areas. This is because numerous grain source fractures formed in glutenite reservoirs due to the release of stress after the glutenite reservoir was taken out, resulting in a higher test permeability. The permeability grading limit of the mixed rock in the Lucaogou Formation, Jimsar sag is lower than that of the other areas due to its smaller sedimentary particles. The permeability is lower than that of sandstone reservoirs. In addition, the results of grading were well matched with the reservoir limit. The grading boundary between tight reservoirs and conventional reservoirs corresponds to the upper limit of physical properties. The grading boundary between type II and III tight reservoirs corresponds to the lower limit of effective seepage. The boundary between type III and IV tight reservoirs corresponds to the lower limit of accumulation, and the theoretical lower limit corresponds to the boundary between tight reservoirs and non-reservoirs.

The aforementioned grading evaluation criteria of tight reservoir physical properties needs to be combined with logging data to improve their applicability in practice. Conversely, the reservoir physical properties can be predicted through logging data. Furthermore, the logging data grading evaluation criteria can be established through the relationship between the logging data and the established grading evaluation criteria.

According to the statistical analysis, we found that a crossplot of the acoustic wave and acoustic wave/density of the Qingshankou Formation in the North Songliao Basin can appropriately classify tight reservoirs and determine the boundary values of logging response parameters for different grades of reservoirs, allowing for identification and grading of different types of tight reservoirs (Fig. 7).

Using the key tight oil exploration Well Ta 234 as an example, the reservoirs were graded using the logging grading criteria. The results showed that at the depth of 1760.0-1769.6 m, the siltstone reservoirs are poor oil layers, being a type II tight reservoir. At the depth of 1770.6-1774.0 m, siltstone reservoir is a type I tight reservoir, with oil layers. After combined fracturing for these two layers, the daily oil production was 7 t/d (Fig. 8a).

The porosity grading model was established using a single logging response for the tight glutenite reservoir in Well Block Fengnan 4, in the Lower Triassic Baikouquan Formation, Mahu area, Junggar Basin, and the results were not satisfactory. A multi-log response regression was adopted to establish an evaluation model to improve the precision of the porosity logging evaluation^[37]. Using the Well Fengnan 401 as an example, the reservoirs were graded by a single well. The results showed that the main body of the Baikouquan Formation conglomerate reservoir is type II, with thin layers of type I, III, and IV. The upper (2516-2520 m), middle (2528-2532 m), and lower (2537.0-2545.5 m) parts of Member 3 of the Baikouquan Formation are all Type II tight reservoirs, being oil layers, which have been confirmed by production test. The obtained oil productivity was 4 t/d after combined fracturing. The upper part (2561-2563 m) of the Member 2 of Baikouquan Formation is mainly type I tight reservoirs, with thin layers of type III tight reservoirs. The lower part (2566-2671 m) consists of type II tight reservoirs, being oil layers. The obtained oil productivity was 9.95 t/d after combined fracturing. The 2611-2620 m layer of the Baikouquan Formation is dominated by type II tight reservoirs, with a thin layer of type III tight reservoirs. The obtained oil productivity was 1.77 t/d after combined fracturing. It is an oil-bearing water layer, which has been confirmed by oil production test. The comparison results of the oil test productivity in the different layers showed that the oil test productivity is higher in high-quality reservoirs (Fig. 8b).

The mixed rock reservoir in the Lucaogou Formation in the Jimsar sag, Junggar Basin is complex in lithology. The relationship between the logging curve and porosity is not obvious. However, the density logging curve of reservoirs with different lithology have a good corresponding relationship with porosity. During the grading and evaluation of reservoirs, different lithologies should be distinguished firstly, and then the physical properties of reservoirs with different lithologies can be predicted. The grading evaluation identification results of the reservoirs showed that the upper part (2840-2845 m; 5 m in thickness) in the Well J302 is dominated by type I tight reservoirs, followed by types II and III. In contrast, the lower part (2853-2870 m; 17 m in thickness) is dominated by type III and IV reservoirs. Although the reservoir is different in thickness, the fracturing productivity from the upper part (3.25 t/d) is similar to the fracturing productivity from the lower part (3.34 t/d), and both oil test conclusions are oil layers. This shows that the better the reservoir grade, the higher the productivity per unit thickness (Fig. 8c).

The relationship between the grading evaluation results of tight oil reservoirs with different lithologies and the oil test productivity shows that the reservoir grading evaluation can guide appropriately the exploration of tight oil. However, it should be noted that a reservoir layer graded as high-quality does not always correspond to a high productivity layer. The productivity of tight oil is also controlled by the oil saturation of the reservoir and engineering conditions. However, during the development of tight oil reservoirs, determination of reservoir boundaries and grading criteria of reservoirs and the selection of a high-quality reservoir are the prerequisites for successful development.

The theoretical lower limit of porosity ranges from 1% to 4%, and the lower limit of permeability ranges from 1.2×10^-7 to 0.2×10^-4 μm² for tight reservoirs in typical continental basins in China. The lower limit of porosity for hydrocarbon accumulation ranges from 1% to 5%, the lower limit of permeability ranges from 1.2×10^-7 to 0.3× 10^-4 μm², the lower limit of porosity of effective seepage ranges from 8% to 9%, and lower limit of permeability is approximately 0.1×10^-3 μm². The upper limit of porosity of tight rock is 11% to 12% and the upper limit of permeability is (1.0-1.3) ×10^-3 μm². The theoretical lower limit of tight oil for the “self-source and self-reservoir” type is close to the lower limit for hydrocarbon accumulation, while the theoretical lower limit of tight oil for the “nearby source” and “distant source” types are both lower than the lower limit of hydrocarbon accumulation.

Based on the difference in reservoir pore structure, tight reservoirs in typical continental basins in China have been graded and evaluated, and the connotation of the reservoir boundaries and their relationship with the grading evaluation criteria have been clarified. The grading boundary between tight reservoirs and conventional reservoirs corresponds to the upper limit of physical properties. The grading boundary between type II and III tight reservoirs corresponds to the lower limit of effective seepage. The boundary of type III and IV tight reservoirs corresponds to the lower limit of accumulation, and the theoretical lower limit corresponds to the boundary between tight reservoirs and non-reservoirs.

The actual application results for the tight siltstone reservoir in the Qingshankou Formation, Songliao Basin, the tight glutenite in the Baikouquan Formation in the Mahu area, and the mixed rock in the Lucaogou Formation in the Jimsar sag, Junggar Basin showed that type I and II tight reservoirs are favorable layers with a high productivity of tight oil.

The authors are grateful for the help from Hu Suyun, Tao Shizhen, and Bai Bin from the China Petroleum Exploration and Development Research Institute, Zhang Wei and Pan Jian from the Daqing Oilfield, Shao Mingli from the Jilin Oilfield, Gao Yang from the Xinjiang Oilfield, and other experts for their assistance with the study.