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Journal ArticleDOI

Mechanisms of shale gas storage: Implications for shale gas exploration in China

01 Aug 2013-AAPG Bulletin (American Association of Petroleum Geologists (AAPG))-Vol. 97, Iss: 8, pp 1325-1346
TL;DR: In this paper, two models were proposed to predict the variation of gas sorption capacity and total gas content over geologic time as a function of burial history, and the results showed that the changes in GSC of organic-rich shales are quite low at an elevated temperature and pressure and with the presence of moisture.
Abstract: This article reviews the mechanisms of shale gas storage and discusses the major risks or uncertainties for shale gas exploration in China. At a given temperature and pressure, the gas sorption capacities of organic-rich shales are primarily controlled by the organic matter richness but may be significantly influenced by the type and maturity of the organic matter, mineral composition (especially clay content), moisture content, pore volume and structure, resulting in different ratios of gas sorption capacity (GSC) to total organic carbon content for different shales. In laboratory experiments, the GSC of organic-rich shales increases with increasing pressure and decreases with increasing temperature. Under geologic conditions (assuming hydrostatic pressure gradient and constant thermal gradient), the GSC increases initially with depth due to the predominating effect of pressure, passes through a maximum, and then decreases because of the influence of increasing temperature at greater depth. This pattern of variation is quite similar to that observed for coals and is of great significance for understanding the changes in GSC of organic-rich shales over geologic time as a function of burial history. At an elevated temperature and pressure and with the presence of moisture, the gas sorption capacities of organic-rich shales are quite low. As a result, adsorption alone cannot protect sufficient gas for high-maturity organic-rich shales to be commercial gas reservoirs. Two models are proposed to predict the variation of GSC and total gas content over geologic time as a function of burial history. High contents of free gas in organic-rich shales can be preserved in relatively closed systems. Loss of free gas during postgeneration uplift and erosion may result in undersaturation (the total gas contents lower than the sorption capacity) and is the major risk for gas exploration in marine organic-rich shales in China.
Citations
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Journal ArticleDOI
TL;DR: In this article, the pore structure and fractal dimension of the pores in O3w-S1l shale formation in the Jiaoshiba area were investigated using field emission scanning electron microscopy (FE-SEM).

404 citations

Journal ArticleDOI
Kun Jiao1, Suping Yao1, Chun Liu1, Yuqiao Gao2, Hao Wu1, Miaochun Li1, Zhongyi Tang1 
TL;DR: In this article, a dual-beam field emission scanning microscope-focused ion beam (FESEM-FIB) device was used to investigate nanopores in a core plug sample of the Longmaxi Shale from Pengye Well #1, Chongqing, China.

243 citations

Journal ArticleDOI
01 Oct 2016-Fuel
TL;DR: In this paper, the complex pore structures of 12 shale samples collected from two marine shale formations in upper Yangtze area (UYA) in China were characterized using field emission scanning electron microscopy (FE-SEM), high pressure mercury intrusion porosimetry (MIP), and low pressure N2/CO2 adsorption.

198 citations

Journal ArticleDOI
TL;DR: In this paper, the authors investigated the mechanisms of shale gas adsorption from the perspective of methane adaption thermodynamics and kinetics, and found that the absolute isosteric heat of methane on shale is 21.06 kJ/mol.

192 citations

Journal ArticleDOI
TL;DR: In this article, high-pressure methane adsorption experiments on a series of Triassic lacustrine shale moisture-equilibrated samples from the southeastern Ordos Basin, China, were conducted at pressure up to 20 MPa.

177 citations

References
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Journal ArticleDOI
TL;DR: In this article, the authors estimate that the Barnett Shale has a total generation potential of about 609 bbl of oil equivalent/ac-ft or the equivalent of 3657 mcf/acft (84.0 m 3 /m 3 ).
Abstract: Shale-gas resource plays can be distinguished by gas type and system characteristics. The Newark East gas field, located in the Fort Worth Basin, Texas, is defined by thermogenic gas production from low-porosity and low-permeability Barnett Shale. The Barnett Shale gas system, a self-contained source-reservoir system, has generated large amounts of gas in the key productive areas because of various characteristics and processes, including (1) excellent original organic richness and generation potential; (2) primary and secondary cracking of kerogen and retained oil, respectively; (3) retention of oil for cracking to gas by adsorption; (4) porosity resulting from organic matter decomposition; and (5) brittle mineralogical composition. The calculated total gas in place (GIP) based on estimated ultimate recovery that is based on production profiles and operator estimates is about 204 bcf/section (5.78 × 10 9 m 3 /1.73 × 10 4 m 3 ). We estimate that the Barnett Shale has a total generation potential of about 609 bbl of oil equivalent/ac-ft or the equivalent of 3657 mcf/ac-ft (84.0 m 3 /m 3 ). Assuming a thickness of 350 ft (107 m) and only sufficient hydrogen for partial cracking of retained oil to gas, a total generation potential of 820 bcf/section is estimated. Of this potential, approximately 60% was expelled, and the balance was retained for secondary cracking of oil to gas, if sufficient thermal maturity was reached. Gas storage capacity of the Barnett Shale at typical reservoir pressure, volume, and temperature conditions and 6% porosity shows a maximum storage capacity of 540 mcf/ac-ft or 159 scf/ton.

2,418 citations

Journal ArticleDOI
TL;DR: In this article, the authors used scanning electron microscopy to characterize the pore system in the Barnett Shale of the Fort Worth Basin, Texas, showing that the pores in these rocks are dominantly nanometer in scale (nanopores).
Abstract: Research on mudrock attributes has increased dramatically since shale-gas systems have become commercial hydrocarbon production targets. One of the most significant research questions now being asked focuses on the nature of the pore system in these mudrocks. Our work on siliceous mudstones from the Mississippian Barnett Shale of the Fort Worth Basin, Texas, shows that the pores in these rocks are dominantly nanometer in scale (nanopores). We used scanning electron microscopy to characterize Barnett pores from a number of cores and have imaged pores as small as 5 nm. Key to our success in imaging these nanopores is the use of Ar-ion-beam milling; this methodology provides flat surfaces that lack topography related to differential hardness and are fundamental for high-magnification imaging. Nanopores are observed in three main modes of occurrence. Most pores are found in grains of organic matter as intraparticle pores; many of these grains contain hundreds of pores. Intraparticle organic nanopores most commonly have irregular, bubblelike, elliptical cross sections and range between 5 and 750 nm with the median nanopore size for all grains being approximately 100 nm. Internal porosities of up to 20.2% have been measured for whole grains of organic matter based on point-count data from scanning electron microscopy analysis. These nanopores in the organic matter are the predominant pore type in the Barnett mudstones and they are related to thermal maturation. Nanopores are also found in bedding-parallel, wispy, organic-rich laminae as intraparticle pores in organic grains and as interparticle pores between organic matter, but this mode is not common. Although less abundant, nanopores are also locally present in fine-grained matrix areas unassociated with organic matter and as nano- to microintercrystalline pores in pyrite framboids. Intraparticle organic nanopores and pyrite-framboid intercrystalline pores contribute to gas storage in Barnett mudstones. We postulate that permeability pathways within the Barnett mudstones are along bedding-parallel layers of organic matter or a mesh network of organic matter flakes because this material contains the most pores.

2,295 citations

Journal ArticleDOI
TL;DR: The first commercial United States natural gas production (1821) came from an organic-rich Devonian shale in the Appalachian basin this article, which is a continuous-type biogenic (predominant), thermogenic, or combined biogenic-thermogenic gas accumulations characterized by widespread gas saturation, subtle trapping mechanisms, seals of variable lithology, and relatively short hydrocarbon migration distances.
Abstract: The first commercial United States natural gas production (1821) came from an organic-rich Devonian shale in the Appalachian basin. Understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have subsequently been the challenge of millions of dollars worth of research since the 1970s. Shale-gas systems essentially are continuous-type biogenic (predominant), thermogenic, or combined biogenic-thermogenic gas accumulations characterized by widespread gas saturation, subtle trapping mechanisms, seals of variable lithology, and relatively short hydrocarbon migration distances. Shale gas may be stored as free gas in natural fractures and intergranular porosity, as gas sorbed onto kerogen and clay-particle surfaces, or as gas dissolved in kerogen and bitumen. Five United States shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters: thermal maturity (expressed as vitrinite reflectance), sorbed-gas fraction, reservoir thickness, total organic carbon content, and volume of gas in place. The degree of natural fracture development in an otherwise low-matrix-permeability shale reservoir is a controlling factor in gas producibility. To date, unstimulated commercial production has been achievable in only a small proportion of shale wells, those that intercept natural fracture networks. In most other cases, a successful shale-gas well requires hydraulic stimulation. Together, the Devonian Antrim Shale of the Michigan basin and Devonian Ohio Shale of the Appalachian basin accounted for about 84% of the total 380 bcf of shale gas produced in 1999. However, annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed: the Devonian New Albany Shale in the Illinois basin, the Mississippian Barnett Shale in the Fort Worth basin, and the Cretaceous Lewis Shale in the San Juan basin. In the basins for which estimates have been made, shale-gas resources are substantial, with in-place volumes of 497‐783 tcf. The estimated technically recoverable resource (exclusive of the Lewis Shale) ranges from 31 to 76 tcf. In both cases, the Ohio Shale accounts for the largest share.

1,885 citations

Journal ArticleDOI
TL;DR: The effect of shale composition and fabric upon pore structure and CH 4 sorption is investigated for potential shale gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) as mentioned in this paper.

1,749 citations