Thermal simulation experiment of organic matter-rich shale and implication for organic pore formation and evolution

Ma, Zhongliang; Zheng, Lunju; Xu, Xuhui; Bao, Fang; Yu, Xiaolu

doi:10.1016/j.ptlrs.2017.04.005

Cited by 20 publications

(13 citation statements)

References 9 publications

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“…Minerals such as clay mixed with organic matter exhibit oil-wetting characteristics under the infiltration of organic hydrocarbons. Ma et al (2017) found that the amount of retained oil in the hot simulated samples has good correspondence with the pores of organic matter, confirming, to some extent, the binding effect of pores related to organic matter on shale oil due to its lipophilicity. The interstitial pores/cracks of organic matter developed, and the intercrystalline pores of clay minerals mixed with organic matter are relatively developed in the Es 3 l of the Shahejie Formation in the Zhanhua sag , which may be the primary type of oil-wetting pores.…”

Section: Effect Of Pore Size On Shale Oil Movabilitysupporting

confidence: 62%

Effect of Shale Reservoir Characteristics on Shale Oil Movability in the Lower Third Member of the Shahejie Formation, Zhanhua Sag

Ning

Jiang

et al. 2020

Acta Geologica Sinica (Eng)

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To reveal the effect of shale reservoir characteristics on the movability of shale oil and its action mechanism in the lower third member of the Shahejie Formation (Es3l), samples with different features were selected and analyzed using N2 adsorption, high‐pressure mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), high‐speed centrifugation, and displacement image techniques. The results show that shale pore structure characteristics control shale oil movability directly. Movable oil saturation has a positive relationship with pore volume for radius > 2 μm, as larger pores often have higher movable oil saturation, indicating that movable oil is present in relatively larger pores. The main reasons for this are as follows. The relatively smaller pores often have oil‐wetting properties because of organic matter, which has an unfavorable effect on the flow of oil, while the relatively larger pores are often wetted by water, which is helpful to shale oil movability. The rich surface provided by the relatively smaller pores is beneficial to the adsorption of immovable oil. Meanwhile, the relatively larger pores create significant pore volume for movable oil. Moreover, the larger pores often have good pore connectivity. Pores and fractures are interconnected to form a complex fracture network, which provides a good permeability channel for shale oil flow. The smaller pores are mostly distributed separately; thus, they are not conducive to the flow of shale oil. The mineral composition and fabric macroscopically affect the movability of shale oil. Calcite plays an active role in shale oil movability by increasing the brittleness of shale and is more likely to form micro‐cracks under the same stress background. Clay does not utilize shale oil flow because of its large specific surface area and its block effect. The bedding structure increases the large‐scale storage space and improves the connectivity of pores at different scales, which is conducive to the movability of shale oil.

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Section: Effect Of Pore Size On Shale Oil Movabilitysupporting

confidence: 62%

Effect of Shale Reservoir Characteristics on Shale Oil Movability in the Lower Third Member of the Shahejie Formation, Zhanhua Sag

Ning

Jiang

et al. 2020

Acta Geologica Sinica (Eng)

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“…Shale gas generation model and stages of shales in the Sichuan Basin, , showing that the hydrocarbon generation and organic matter occurrence are different at the five evolution stages.…”

Section: Gas Generation Mechanismmentioning

confidence: 99%

“…Shale samples with different burial depths were collected to analyze the characteristics of the natural pore evolution of shale and to summarize the factors affecting pore evolution. Mastalerz et al used a series of New Albany shale samples with different thermal maturities and found that the total pore volume of the shale decreased significantly with increasing thermal maturity. − The change in pore volume was affected mainly by the thermal maturity, mineral composition, and organic matter content. − However, shale at different buried depths and evolutionary stages underwent different diagenesis. The differences in sedimentary environment and diagenesis determine the heterogeneity of organic matter and minerals.…”

Section: Spatial Evolution Of Gas Storagementioning

confidence: 99%

Advances on the Mechanism of Reservoir Forming and Gas Accumulation of the Longmaxi Formation Shale in Sichuan Basin, China

et al. 2021

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Shale gas has become one of the most important natural gas resources. The Sichuan Basin in China is one of the main shale gas production areas and has entered large-scale commercial development. The mechanism of shale gas accumulation is an important scientific problem in shale gas exploration. This work systematically summarizes the understanding of shale gas accumulation in terms of shale gas generation mechanisms, pore evolution mechanisms, gas migration mechanisms, and gas accumulation models. This work reviews the formation process of methane in shale and clarifies that the causes of methane formation vary according to the evolutionary stage. The formation and evolution of organic pores and mineral pores in shale are analyzed using a thermal simulation; the organic pore content is found to vary significantly with evolutionary stage. In addition, this work focuses on an analysis of the migration mechanism of shale gas, discussing the impacts of shale anisotropy, self-sealing, porosity and permeability, various forces, and pathway availability on shale gas migration. In addition to the actual gas content of the shale gas reservoir, shale gas accumulation is analyzed using mathematical and evolutionary models, and the accumulation process is revealed. This work provides important guidelines for shale gas exploration in the Sichuan Basin, which has undergone complex tectonic evolution.

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“…The simulation experiment was conducted on the DK-II type (third-generation) formation porosity thermocompression simulation experiment instrument from the Wuxi Research Institute of Petroleum Geology, Sinopec. Through a series of simulation experiments under different conditions or pyrolysis systems, our predecessors found that the instrument has the advantages of simulated experimental conditions approaching the actual geological conditions, retaining the original columnar and pore space, and obtaining accurate experimental data [45][46][47][48]. At the same time, to ensure sample uniformity, the columnar core used in the simulation experiment was a cylindrical core column formed by further pressing after crushing the samples to 40-60 mesh.…”

Section: Simulation Experimentsmentioning

confidence: 99%

“…(3) Acquisition and quantification of the pyrolysis products: The gaseous hydrocarbons were collected first, followed by separation and quantification of the expelled oil and residual water. Finally, Ma et al conducted a thermal simulation experiment of diagenesis, hydrocarbon generation, and the evolution of the organic matter-rich shale and pointed out that the solid residues were extracted using chloroform to obtain the content of chloroform asphalt "A," which was defined as residual bitumen [48].…”

Section: Simulation Experimentsmentioning

confidence: 99%

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

Cao

et al. 2021

Energies

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Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R2) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen0(original) + bitumen0(original)→kerogenr (residual kerogen) + expelled oil (generated) + bitumenn+r (generated + residual) + C2+(generated + residual) + CH4(generated). Among these, bitumen, expelled oil, and C2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ13C1 < 13C2-5 < δ13Cexpelled oil < δ13Cbitumen < δ13Ckerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

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Thermal simulation experiment of organic matter-rich shale and implication for organic pore formation and evolution

Cited by 20 publications

References 9 publications

Effect of Shale Reservoir Characteristics on Shale Oil Movability in the Lower Third Member of the Shahejie Formation, Zhanhua Sag

Effect of Shale Reservoir Characteristics on Shale Oil Movability in the Lower Third Member of the Shahejie Formation, Zhanhua Sag

Advances on the Mechanism of Reservoir Forming and Gas Accumulation of the Longmaxi Formation Shale in Sichuan Basin, China

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

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