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Study of the characteristics of marine-terrigenous facies shale from the Permo-Carboniferous system in the Guxian Block, southwest Qinshui Basin Miao Zhang, and Xuehai Fu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b02556 • Publication Date (Web): 05 Jan 2018 Downloaded from http://pubs.acs.org on January 5, 2018
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Energy & Fuels
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Study of the characteristics of marine-terrigenous facies shale from the
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Permo-Carboniferous system in the Guxian Block, southwest Qinshui Basin Miao Zhanga,b, Xuehai Fu a, b
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Key Laboratory of Coalbed Methane Resources and Reservoir Formation Process, Ministry of Education,
China University of Mining and Technology, Xuzhou, Jiangsu 221008, China b
School of Resources and Geoscience, China University of Mining and Technology, Xuzhou, Jiangsu 221008,
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China
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Abstract: This paper analyzes the characteristics of coal measure shale using samples from the
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Guxian Block of the southwest Qinshui Basin. Several methods, including X-ray diffraction
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(XRD), Rock-Eval pyrolysis, high-pressure mercury intrusion porosimetry (MIP), low-pressure
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nitrogen adsorption/desorption and isothermal adsorption experiments, were used to investigate
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the organic geochemical characteristics, mineral composition, pore structure and methane
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adsorption characteristics of the shales. Furthermore, the effect of the total organic carbon (TOC),
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thermal maturity and mineral composition on the pore structure and methane adsorption capacity
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of shale was also investigated. The results showed that the TOC of the shale samples ranged from
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0.19% to 31.66%, and the shale samples with TOC higher than 2% account for 31.17% of the total
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samples. The shale samples were in the high-over mature stage with high hydrocarbon conversion
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rates. The mineral composition of the shale samples are mainly clay minerals and quartz, the
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brittleness index calculated on the basis of mineral component is distributed primarily in the range
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from 40% to 50%, suggesting that the shale reservoirs have better fracturing properties. The
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mesopores were the major provider of pore volume, followed by macropores, and the micropores
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provided the least pore volume. The pores are open in style and mainly consist of cylindrical pores,
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parallel-plate slit pores and bottle-neck pores. TOC was the main controlling factor for the
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development of pores, followed by clay minerals; the pore-specific volume created by organic
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matter was far greater than that of the clay minerals; quartz arrested the development of pores, and
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the increase in quartz content reduced the porosity by approximately 0.57% to 1.42%. As Ro
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increased, the porosity first increased at the high-maturity stage and then decreased at the
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over-mature stage; the maximum value appeared when Ro=2.0%. The TOC-normalized methane
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adsorption capacity decreased as Ro increased. There was no obvious correlation between the clay
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mineral content and the TOC-normalized methane adsorption capacity, which may be attributed to
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the shale water content. Vertically, as the sedimentary facies transited from carbonate tidal flat
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facies to delta facies, the porosity, BET specific surface area, BJH pore volume and Langmuir
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volume generally decreased and the physical reservoir properties of the shale reservoir became
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weaker.
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Keywords: Shale gas; Organic geochemistry; Pore types; adsorption capacity; Influencing factors
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Introduction
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The U.S. Energy Information Administration (EIA) evaluated the technically recoverable
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shale gas resources of China at 36 × 1012 m3 (approximately 20%) in 20111. The official research
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on shale gas in China is considered to have begun in 2009. The development of shale gas
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resources from marine shale in China has achieved a commercial breakthrough, and the shale gas
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production from continental shale in eastern Ordos Basin was also experiencing a breakthrough2.
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However, the development of shale gas from marine-continental facies shale is slow.
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The studies of the controlling factors in the shale pore characteristics mainly focused on the
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TOC, vitrinite reflectance (Ro), mineral composition, and other factors. Jarvie et al.3 proposed that
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the porosity of organic matter increases monotonously with the increased of hydrocarbon
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generation of organic matter. However, Gasparik et al.4 found that the evolutionary path of organic
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porosity of the shales do not follow a monotonous trend, but instead follow a nonlinear,
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trough-shaped path as the maturity increased. Mastalerz et al.5 observed that as VRo increased
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from 0.35% to 1.41%, the porosity and the total pore volume of shales exhibit a significant decline
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with a reduction of more than 80%, and regain their higher values in the over mature. Work by
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Curtis et al.6 showed that the evolutionary path of porosity is a complex trend of first an increase,
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then a decrease, and finally an increase when the thermal evolution of organic matter is of the
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low-maturation
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(1.30%
