Due to the specificity of the geological background, terrestrial strata are widely distributed in the major hydrocarbon-bearing basins in China. In addition, terrestrial shales are generally featured with high thickness, multiple layers, high TOC content, ideal organic matter types, and moderate thermal evolution, laying a solid material foundation for hydrocarbon generation. However, the quantitative characterization study on their pore structure remains inadequate. In this study, core samples were selected from the Middle Jurassic Lianggaoshan Formation in the southeastern Sichuan Basin of the Upper Yangtze Region for analyses on its TOC content and mineral composition. Besides, experiments including oil washing, the adsorption/desorption of CO2 and nitrogen, and high-pressure mercury pressure experiments were carried out. The pore structure of different petrographic types of terrestrial shales can be accurately and quantitatively characterized with these works. The following conclusions were drawn: for organic-rich mixed shales and organic-rich clay shales, the TOC content is the highest; the pore volume, which is primarily provided by macropores and specific surface area, which is provided by mesopores, was the largest, thus providing more space for shale oil and gas reservation. The pores take on a shape either close to a parallel plate slit or close to or of an ink bottle. For organic-matter-bearing shales, both the pore volume and specific surface area are the second-largest and are provided by the same sized pores with organic-rich mixed shales. Its pores take on a shape approximating either a parallel plate slit or an ink bottle. Organic-matter-bearing mixed shales have the lowest pore volume and specific surface area; its pore volume is primarily provided by macropores, and the specific surface area by mesopores and the shape of the pores are close to an ink bottle.
The value of a cementation exponent, usually obtained by rock and electricity experiments, significantly affects the calculation of water saturation, thickness of the hydrocarbon reservoir, and recovery rate. The determination of the cementation exponent for porous-media reservoirs has been a challenge because of the limited core sampling. A new method was proposed to determine the value of cementation exponent for complex triple-porosity media reservoirs in the work. Firstly, the work discussed the effects of fractures and nonconnected vugs on the cementation exponent of the reservoir as well as the calculation method of the cementation exponent of the dual-porosity media reservoir. Then, a new model for calculating the cementation exponent of triple-porosity media reservoirs was derived by combining the Maxwell-Garnett theory and series-parallel theory, which matched with the real physical-experiment data of rocks. The results showed that the fractures decreased the cementation exponent of the reservoir but the vugs increased. The mixture of matrix pores, fractures, and vugs made the value of the cementation exponent of the triple-porosity media reservoir vary around 2.0. The conductivity of the triple-porosity media reservoir was the external macroscopic expression of the microscopic conductive network. The new calculation model of the cementation exponent proposed in the work could reasonably predict the cementation exponent of the strongly inhomogeneous triple-porosity media reservoir.
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