The technical feasibility of in situ upgrading technology to develop the enormous oil and gas resource potential in low-maturity shale is widely acknowledged. However, because of the large quantities of energy required to heat shale, its economic feasibility is still a matter of debate and has yet to be convincingly demonstrated quantitatively. Based on the energy conservation law, the energy acquisition of oil and gas generation and the energy consumption of organic matter cracking, shale heat-absorption, and surrounding rock heat dissipation during in situ heating were evaluated in this study. The energy consumption ratios for different conditions were determined, and the factors that influence them were analyzed. The results show that the energy consumption ratio increases rapidly with increasing total organic carbon (TOC) content. For oil-prone shales, the TOC content corresponding to an energy consumption ratio of 3 is approximately 4.2%. This indicates that shale with a high TOC content can be expected to reduce the project cost through large-scale operation, making the energy consumption ratio after consideration of the project cost greater than 1. In situ heating and upgrading technology can achieve economic benefits. The main methods for improving the economic feasibility by analyzing factors that influence the energy consumption ratio include the following: (1) exploring technologies that efficiently heat shale but reduce the heat dissipation of surrounding rocks, (2) exploring technologies for efficient transformation of organic matter into oil and gas, i.e., exploring technologies with catalytic effects, or the capability to reduce in situ heating time, and (3) establishing a horizontal well deployment technology that comprehensively considers the energy consumption ratio, time cost, and engineering cost.

The Qingshankou Formation shale oil in the Gulong Sag is an important oil and gas reservoir in the Daqing oilfield, with geological resources of 15.1 billion tons. The fabric of shale can reflect not only its genesis but also the nature of the reservoir space, its physical properties, oil content, and development value. Here, the characteristics of clay minerals in the Gulong shale oil reservoir were studied via electron microscopy, with the primary focus on the microfabrics and reservoir space; thereafter, the in situ accumulation was studied and discussed. Electron backscattering patterns revealed that nanometer pores and fissures were well developed in the Gulong shale oil reservoir. The nano pores were mostly 20-50 nm in diameter (median 20-30 nm), irregularly shaped, mostly, polygonal, and connected with nanofissures. The widths of nanofissures ranged mostly between 10-50 nm (median 20-30 nm); moreover, these fissures were mainly formed by F-F condensation of clay sheets (clay domains). The coagulation of clays was closely related to organic matter, especially algae. The clay colloids were negatively charged due to isocrystalline replacement; hence, metal cations were absorbed around the clay, forming a positive clay group. The positively charged clays subsequently adsorbed negatively charged humic acid (organic matter) and initially degraded algae to form an organic clay flocculant. When the organic clay flocculates reached the threshold for hydrocarbon generation and expulsion, the volume of organic matter decreased by 87%; thereafter, the generated and expelled hydrocarbon filled the nearby pores formed by this contraction. Moreover, the discharged hydrocarbon could not migrate due to capillary resistance (~12 MPa) of the nanopores; hence, the nanopores formed a unique continuous in situ reservoir within the Gulong shale oil. This study demonstrated that the Gulong shale oil reservoir is an actual clay-type shale reservoir with numerous nanopore and fissures. During coagulation, a large amount of organic matter (including layered algae) was absorbed by the clay, forming an organic clay condensate that could have provided the material foundation for hydrocarbon generation at a later stage. Thermal simulation experiments revealed that the volume of organic matter decreased sharply after hydrocarbon generation and expulsion.

Successful breakthroughs have been made in shale oil exploration in several lacustrine basins in China, indicating a promising future for shale oil exploration and production. Current exploration results have revealed the following major conditions of lacustrine shale oil accumulation: (1) stable and widely distributed shale with a high organic abundance and appropriate thermal maturity acts as a fundamental basis for shale oil retention. This shale exhibits several critical parameters, such as total organic carbon content greater than 2%, with optimal values ranging from 3% to 4%, kerogen Ⅰ and Ⅱ₁ as the dominant organic matter types, and vitrinite reflectance (R_o) values greater than 0.9% (0.8% for brackish water environments). (2) Various types of reservoirs exhibiting brittleness and a certain volume of micro-nanoscale pores are critical conditions for shale oil accumulation, and these reservoirs have porosities greater than 3% to 6%. Moreover, when diagenesis is incipient, pure shales are not favorable for medium-to-high maturity shale oil enrichment, whereas tight sandstone and hybrid rocks with clay content less than 20% are favorable; however, for medium-to-late-stage diagenesis, pure shales with a clay content of 40% are favorable. (3) The retention of a large amount of high-quality hydrocarbons is the factor that best guarantees shale oil accumulation with good mobility. Free hydrocarbon content exceeding a threshold value of 2 mg/g is generally required, and the optimum value is 4 mg/g to 6 mg/g. Moreover, a gas-oil ratio exceeding a threshold value of 80 m³/m³ is required, with the optimal value ranging from 150 m³/m³ to 300 m³/m³. (4) High-quality roof and floor sealing conditions are essential for the shale oil enrichment interval to maintain the overpressure and retain a sufficient amount of hydrocarbons with good quality. Lacustrine shale oil distributions exhibit the following characteristics: (1) major enrichment areas of shale oil are located in semi-deep to deep lacustrine depositional areas with external materials, such as volcanic ash fallout, hydrothermal solutions, and radioactive substances with catalytic action, as inputs; (2) intervals with “four high values and one preservation condition” govern the distribution of shale oil enrichment intervals; and (3) favorable assemblages of lithofacies/lithologies determine the distribution of enrichment area. According to preliminary estimates, China has 131×10⁸ to 163×10⁸ t of total shale oil resources with medium-to-high thermal maturity, among which 67×10⁸ to 84×10⁸ t is commercial. These resources are primarily located in the Chang 7¹⁺² interval in the Ordos Basin, Qing 1+2 members in Gulong sag in the Songliao Basin, Kongdian and Shahejie formations of Cangdong sag, Qikou sag and the Jiyang depression in the Bohai Bay Basin, and Lucaogou Formation in the Junggar Basin.

The buried hill in the Jizhong depression contains abundant petroleum reserves and are important production areas. The Ordovician buried hill has restricted the discovery of new oil and gas exploration targets because of its strong reservoir heterogeneity and complex reservoir-controlling factors. Based on a large volume of core, thin section, logging, seismic, and geochemical data and numerous geological analyses, the reservoir-forming conditions and modes were systematically analyzed to guide the exploration and achieve important breakthroughs in the Yangshuiwu and Wen’an slope buried hills. The study revealed that three sets of source rocks of the third and fourth members of the Shahejie Formation from the Paleogene and Carboniferous-Permian were developed in the Jizhong depression, providing sufficient material basis for the formation of buried hill oil and gas reservoirs. The reservoir control mechanism involving the three major factors of “cloud-karst-fault” was clarified, and karst cave, fracture fissure-pore, and cloud pore type reservoir models were established, thereby expanding the exploration potential. Controlled by the superposition of multi-stage tectonic processes during the Indosinian, Yanshanian, and Himalayan, two genetic buried hill trap types of uplift-depression and depression-uplift were formed. Based on the analysis of reservoir-forming factors of the Ordovician buried hill, three buried hill oil and gas reservoir-forming models were identified: low-level tectonic-lithologic composite quasi-layered buried hill, medium-level paleo-storage paleo-block buried hill, and high-level paleo-storage new-block buried hill. Comprehensive evaluations indicate that the reservoir-forming conditions of the low-level tectonic-lithologic composite quasi-layered buried hill in the northern portion of the Jizhong depression are the most favorable and that the Sicundian and Xinzhen buried hills are favorable areas for future exploration.