Hydrothermal mineral assemblages and related hydrothermally enhanced fracturing are common in the Precambrian Dengying Formation of Central Sichuan Basin. Petrographic and geochemical analyses of core samples show that the hydrothermal dolomite reservoirs of Dengying Formation consist of four main types of pores in the reservoir facies. These include: 1) hydrothermal dissolution vug (or pore), 2) intercrystalline pore, 3) residual inter-breccia vug (or pore), and 4) enlarged dissolved-fracture. There are three different fabrics dolomite in hydrothermal dolomite reservoirs, namely, saddle dolomite, fine-medium dolomite and micritic dolomite. Micritic dolomite is the original lithology of host rock. Saddle dolomite with curved or irregular crystal faces was directly crystallized from hydrothermal fluids (average temperature 192°C). Fine-medium dolomites are the products of recrystallization of micritic dolomite, resulting in abnormal geochemical characteristics, such as slight depletion of δ 18 O, significant enrichment of Mn-Fe and 87 Sr/ 86 Sr, and positive Eu anomaly. A model for the distribution of various hydrothermal dolomite reservoir facies is proposed here, which incorporates three fundamental geological controls: 1) extensional tectonics and tectono-hydrothermal events (i.e., the Xingkai Taphrogenesis of Late Sinian-Early Cambrian, and Emei Taphrogenesis of Late Permian), 2) hydrothermal fluid storage in clastic rocks with large thickness (e.g., Nanhua System of Chengjiang Formation and part of Doushantuo Formation), and 3) confining bed for hydrothermal fluids (such as, the shale in Qiongzhusi Formation). The supply of hydrothermal fluid is critical. Large basement-rooted faults and associated grid-like fracture system may function as the channels for upward migration of hydrothermal fluid flow. The intersection of the above-mentioned faults (including the conversion fault), especially transtensional sags above negative flower structures on wrench faults can serve as a key target for future hydrocarbon exploration.

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The Lower Permian Shanxi Formation in the Eastern Ordos Basin is a set of transitional facies shale, and it is also a key target for shale gas exploration in China. Based on lithofacies classification by X-ray diffraction and kerogen type identification, nanoscale reservoir space, pore volume, pore size distribution, surface area, and fractal characterization were studied using comprehensive methods including N2 and CO2 adsorption, mercury injection capillary pressure, field emission-scanning electron microscopy (FE-SEM), and nuclear magnetic resonance. The results indicate that Shanxi Formation shale can be subdivided into five types of lithofacies: clayey shale (lithofacies I), siliceous clayey shale (lithofacies II), siliceous shale (lithofacies IV), calcareous siliceous shale (lithofacies V), and siliceous calcareous shale (lithofacies VI). Lithofacies V and lithofacies VI are the best lithofacies in terms of organic pore morphology, connectivity, and development degree, followed by lithofacies II. Inorganic pores and microfractures are well developed in all lithofacies. The majority of pores in lithofacies I comprise organic mesopores, but pore volume is contributed by a few inorganic macropores. The pore types and pore volume contributors of lithofacies II are organic macropores. The pore size distribution of lithofacies IV is very similar to that of lithofacies I. The pore size distribution of lithofacies V shows typical bimodal characteristics. It is suggested that the inorganic pores of lithofacies V are mainly macropores, which have the greatest contribution to pore volume, followed by organic mesopores. Total organic carbon (TOC) and thermal maturity do not present obvious controls on pore structure. Vitrinite is the main kerogen type in lithofacies II and IV, and this is associated with disfavored morphology, low connectivity, and poor development degree of organic pores. In contrast, sapropelinite is observed in other shale lithofacies, and it is suggested to be an effective kerogen type that contributes to better development of organic pores.

The decrease in fracturing fluid flowback rate in the process of hydraulic fracturing and the improvement of initial gas production rate after well shut-in for a period of time were investigated using weight and nuclear magnetic resonance (NMR) T2 spectra of dried shale cores and shale cores in the "as received" state after spontaneous oil and water imbibition. Experimental results indicated that the rate and weight during spontaneous water imbibition were much higher than those of spontaneous oil imbibition, contrary to capillary-driven imbibition models. Therefore, spontaneous water imbibition was related to both capillary pressure and additional hydration stress generated by clay swelling. NMR T2 spectra of different imbibition fluids (oil and water) demonstrated that signals between 0.01 ms and 1 ms were total responses of pore fluids and irreducible water, and excess imbibed water was mainly present as irreducible water in shale. Excess imbibed water flowed into the matrix and reacted with minerals to generate many micro-fractures which may connect isolated organic pores to mitigate water blocking.

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