Abstract
The evolution of shale reservoirs is mainly related to two functions: mechanical compaction controlled by ground stress and chemical compaction controlled by thermal effect. Thermal simulation experiments were conducted to simulate the chemical compaction of marine-continental transitional shale, and X-ray diffraction (XRD), CO2 adsorption, N2 adsorption and high-pressure mercury injection (MIP) were then used to characterize shale diagenesis and porosity. Moreover, simulations of mechanical compaction adhering to mathematical models were performed, and a shale compaction model was proposed considering clay content and kaolinite proportions. The advantage of this model is that the change in shale compressibility, which is caused by the transformation of clay minerals during thermal evolution, may be considered. The combination of the thermal simulation and compaction model may depict the interactions between chemical and mechanical compaction. Such interactions may then express the pore evolution of shale in actual conditions of formation. Accordingly, the obtained results demonstrated that shales having low kaolinite possess higher porosity at the same burial depth and clay mineral content, proving that other clay minerals such as illite–smectite mixed layers (I/S) and illite are conducive to the development of pores. Shales possessing a high clay mineral content have a higher porosity in shallow layers (< 3500 m) and a lower porosity in deep layers (> 3500 m). Both the amount and location of the increase in porosity differ at different geothermal gradients. High geothermal gradients favor the preservation of high porosity in shale at an appropriate Ro. The pore evolution of the marine-continental transitional shale is divided into five stages. Stage 2 possesses an Ro of 1.0%–1.6% and has high porosity along with a high specific surface area. Stage 3 has an Ro of 1.6%–2.0% and contains a higher porosity with a low specific surface area. Finally, Stage 4 has an Ro of 2.0%–2.9% with a low porosity and high specific surface area.
Highlights
Shale oil and gas have proven to be a type of unconventional oil and gas resource with abundant reserves (Curtis 2002; Jarvie et al 2007; Zhang et al 2018)
The red dotted line is the porosity evolution path of the thermal simulation experiment, which does not take into account the mechanical compaction caused by increasing burial depth
Diagenetic models, and porosity evolution models, the evolution of marinecontinental transitional shale can be divided into five stages under a simple burial process and a specific geothermal gradient (26 °C/km) (Fig. 11)
Summary
Shale oil and gas have proven to be a type of unconventional oil and gas resource with abundant reserves (Curtis 2002; Jarvie et al 2007; Zhang et al 2018). Key Laboratory of Marine Reservoir Evolution and Hydrocarbon Enrichment Mechanism, Ministry of Education, Beijing 100083, China gas exploration, such as the Barnett Shale in the Fort Worth Basin (Bernard et al 2012), the Horn River Group shale in the Western Canada Sedimentary Basin (Ross and Bustin 2009; Dong et al 2015), the Posidonia Shale in Europe (Gasparik et al 2014), the Devonian Woodford Shale in Oklahoma and Texas, and the Longmaxi Formation in the Sichuan Basin (Tian et al 2013; Yang et al 2016) These examples are marine shales rich in Type I and II kerogen, while marine-continental transitional shales rich in Type III kerogen have not yet been found for large-scale commercial exploitation. In this paper, based on thermal simulation experiments of marine-continental transitional shale samples (Ro from 0.96% to 3.38%), characterizing the diagenesis and pore characteristics of the shale via N 2 adsorption, CO2 adsorption, MIP, X-ray diffraction and SEM.
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