The lithology of source rocks in Yanchang Formation of Ordos Basin is black shale and dark mudstone, mainly black shale ( Zhong et al., 2016 ). The hydrocarbon generation center of the basin is located in the southwest of the whole basin, and the hydrocarbon generation potential energy is large. The east of Xiaohe is located in the northeast of the basin, far away from the hydrocarbon generation center, and the hydrocarbon generation potential energy is low. However, after the hydrocarbon generation of the source rock, the oil and gas will migrate from the part with high hydrocarbon generation potential energy to the part with low hydrocarbon generation potential energy. Therefore, it is considered that the oil and gas in the study area come from the source rock of the bottom Yanchang Formation ( Zhang et al., 2020 ).

The distribution area of effective source rocks in Chang 7 is 2.34 × 10⁴ km². The thickness of effective source rocks is more than 160 meters, and the average cumulative thickness is about 60 meters. The vitrinite reflectance R_o is greater than 0.8%. The evolution of source rocks has entered a mature stage. The total hydrocarbon generation of source rocks is 2251.17 × 10⁸ t, and the total hydrocarbon expulsion is 1125.58 × 10⁸ t. It has sufficient oil source and great potential for oil and gas resources ( Liu et al., 2015 ) ( Figure 1 ).

Through the analysis of geochemical test data of Chang 7 source rocks in the study

area, it is found that the main peak distribution range of total organic carbon content (TOC) of Chang 7 shale is between 1% and 3%, with an average content of 2.20%. The main distribution range of hydrocarbon generation potential (S₁ + S₂) is between 5 - 15 mg/g, and the average content is 15.8 mg/g. The content of chloroform asphalt “A” is 0.1% - 0.4%, with an average content of 0.23% ( Figures 2-4 ).

The macerals of organic matter in the Chang 7 shale in the study area are mainly sapropelic group and exinite group, accounting for up to 95%, and the content of vitrinite and inertinite is low. Through the statistics of microscopic macerals, it is found that the Chang 7 shale is mainly composed of I-II₁ kerogen ( Figure 5 ), which has strong oil generation capacity ( Zhao et al., 2007 ).

The highest pyrolysis peak temperature (T_max) is an effective indicator of maturity. The T_max value of Chang 7 shale is distributed at 439˚C - 454˚C, which has reached the peak evolution stage of oil generation. The vitrinite reflectance is 0.56% - 1.41% ( Table 1 ), reflecting that the Chang 7 source rock has reached the high oil generation stage.

Therefore, based on the characteristics of organic matter abundance, type and thermal evolution degree of source rocks, the Chang 7 shale in the study area is a high-quality source rock.

The core porosity and permeability test of Chang 2 reservoir in the study area shows that the porosity of the reservoir is distributed between 1.67% and 19.43%, the average porosity is 12.41%, the main porosity is between 16% and 18%, the maximum permeability is 10.01 × 10⁻³ μm², and the minimum permeability is 0.1 × 10⁻³ μm². The permeability distribution range is between 5 × 10⁻³ - 20 × 10⁻³ μm², and the average permeability is 10.01 × 10⁻³ μm², which is comprehensively evaluated as an ultra-low permeability reservoir ( Figure 6 ).

By analyzing the pore types of Chang 2 reservoir, it is considered that the pore types of Chang 2 reservoir are mainly residual intergranular pores, followed by dissolution pores, and feldspar dissolution pores and debris dissolution pores are the main pore types ( Figure 7 ). The high pressure mercury injection data show that the displacement pressure of Chang 2 reservoir is 1.82 MPa, the saturated median pressure is 41.40 MPa, the maximum throat radius is 0.40 μm, the median throat radius is 0.02 μm, the mercury removal efficiency is 36.05% ( Figure 8 ), and the maximum mercury saturation is 84.24% ( Bai et al., 2010 ; Feng et al., 2020 ; Bai et al., 2013 ; Zhao et al., 2020 ). It is concluded that the displacement pressure of Chang 2 reservoir in the study area is low, which is good-medium, and the mercury removal efficiency is high, which shows that the reservoir storage and seepage are good.

Based on the reservoir pressure, formation temperature test data and regional research results in the study area, the geothermal gradient is determined to be 2.9˚C/100m, the pressure coefficient of Chang 2 reservoir is 0.87, the average density is 0.8678 g/cm³, the average viscosity is 12.1 mPa∙s, and the average freezing point is 16.64˚C, which belongs to light and medium viscosity crude oil ( Lin et al., 2017 ; Wang et al., 2002 ; Zhao et al., 2022 ; Shao et al., 2023 ).

The oil layer is mainly distributed in the channel sand body of the Chang 2₂ oil layer sub-group, which has good plane continuity and is distributed along the distribution direction of the channel sand body. The oil and gas enrichment is mainly controlled by the factors such as the nose-like uplift structure, the distribution of the top cap rock and the lateral lithologic barrier. The reservoir type is mainly a structural-lithologic composite reservoir ( Figure 9 ).

There are mainly two types of liquid brine inclusions and liquid hydrocarbon inclusions in Chang 2 reservoir minerals ( Figure 10 ), which are mainly distributed in quartz microcracks. The size of inclusions is generally 3 - 6 μm, and the gas-liquid ratio is mostly distributed in 5% - 20%. The research shows that the homogenization temperature of the brine inclusions associated with hydrocarbon inclusions ranges from 70˚C to 130˚C, showing a continuous single peak distribution, and the main peak is distributed between 90˚C and 110˚C ( Figure 11 ) ( Sun et al., 2022 ).

Fluid inclusions trapped in mineral-defective caverns are direct evidence of paleofluid filling. On this basis, through the determination of the homogenization temperature of the brine inclusions associated with hydrocarbon inclusions, combined with the burial-thermal evolution history diagram ( Figure 12 ), the specific time of inclusion capture is determined, which is the time of oil and gas accumulation ( Chen et al., 2007 ). Through the PetroMod oil and gas system numerical simulation software, the burial-thermal evolution history of the Chang 2 reservoir was restored. The oil and gas filling of the reservoir was a continuous accumulation period of about 115 Ma, which was in the middle and late Early Cretaceous ( Shi et al., 2014 ).

Reservoir conditions have an important influence on the distribution and enrichment of Chang 2 reservoir. After compaction, pressure solution and cementation, the original pores of Chang 2 reservoir in the study area are significantly reduced. However, due to the deep burial depth of Chang 2 reservoir group, the content of feldspar and debris in sandstone composition is higher than that of Yan’an formation sandstone, and the porosity of reservoir changes significantly after diagenesis. Therefore, the development degree of residual intergranular pores and dissolution pores directly affects the permeability of reservoir ( Xun et al., 2016 ).

The delta plain deposits are developed in the study area of Chang 2, and the channel sand bodies are superimposed in multiple periods. The vertical cumulative thickness can reach 30.63 m, and the average sand-to-ground ratio is 0.63 ( Table 2 ), which provides favorable conditions for the formation of Chang 2 reservoir. The thickness of Chang 2 sandstone in the study area is large, and it is easy to form compaction structure by differential compaction. Nasal uplift is formed in the sand body development zone. The center of the sand body is often the highest part of the uplift. If there is lithologic occlusion in the upward direction, structural-lithologic reservoirs can be formed ( Wang et al., 2019 ).